<Page>

                                                                       EXHIBIT 1


                      [CANADIAN SUPERIOR ENERGY INC. LOGO]



                            ANNUAL INFORMATION FORM



                         (EXCEPT AS OTHERWISE NOTED THE
                           INFORMATION HEREIN IS GIVEN
                            AS AT DECEMBER 31, 2004)



                             DATED: MARCH 22, 2005


<Page>

                               TABLE OF CONTENTS

<Table>
<Caption>
                                                                            Page
                                                                            ----
<S>                                                                         <C>
GLOSSARY OF TECHNICAL TERMS ................................................   1
FORWARD LOOKING STATEMENTS .................................................   5
ABBREVIATIONS ..............................................................   6
CONVERSION .................................................................   6
THE CORPORATION ............................................................   7
  Name and Incorporation ...................................................   7
  Intercorporate Relationships .............................................   7
GENERAL DEVELOPMENT OF THE BUSINESS ........................................   7
  History ..................................................................   7
DESCRIPTION OF THE BUSINESS ................................................  11
  General ..................................................................  11
  Oil and Gas Properties and Wells .........................................  12
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION ...............  15
  General ..................................................................  15
  Selected Reserves Information ............................................  15
  Reserves Data - Constant Prices and Costs ................................  16
  Reserves Data - Forecast Prices and Costs ................................  20
  Constant Prices Used in Estimates ........................................  23
  Forecast Prices Used in Estimates ........................................  25
  Reserves Reconciliation ..................................................  27
  Future Net Revenue Reconciliation ........................................  28
  Undeveloped Reserves .....................................................  29
  Significant Factors or Uncertainties Affecting Reserves Data .............  29
  Future Development Costs .................................................  29
  Oil and Gas Properties and Wells .........................................  30
  Properties With No Attributed Reserves ...................................  30
  Expirations and Work Commitments .........................................  31
  Undeveloped Land Due to Expire ...........................................  31
  Forward Contracts and Future Commitments .................................  31
  Additional Information Concerning Abandonment and Reclamation Costs ......  32
  Tax Horizon ..............................................................  33
  Costs Incurred ...........................................................  33
  Exploration and Development Activities ...................................  33
  Production Estimates .....................................................  34
RISK FACTORS ...............................................................  36
  Exploration, Development and Production Risks ............................  36
  Substantial Capital Requirements and Liquidity ...........................  36
  Additional Funding Requirements ..........................................  37
  Issuance of Debt .........................................................  37
  Prices, Markets and Marketing of Crude Oil and Natural Gas ...............  37
  Insurance ................................................................  37
  Legal Proceedings ........................................................  38
  Environmental Risks ......................................................  38
  Competition ..............................................................  38
  Reserve Replacement ......................................................  39
  Reliance on Operators and Key Employees ..................................  39
  Permits and Licenses .....................................................  39
</Table>


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                                     - ii -


<Table>
<S>                                                                         <C>
  Royalties, Incentives and Production Taxes ...............................  39
  Land Tenure ..............................................................  40
  Title to Properties ......................................................  40
  Corporate Matters  .......................................................  40
DIVIDENDS ..................................................................  40
DESCRIPTION OF CAPITAL STRUCTURE ...........................................  40
  Common Shares ............................................................  41
  Preferred Shares .........................................................  41
  Shareholder Rights Plan ..................................................  41
MARKET FOR SECURITIES ......................................................  42
  Trading Price and Volume .................................................  42
DIRECTORS AND OFFICERS .....................................................  42
  Names, Occupations and Security Holders ..................................  42
  Cease Trade Orders, Bankruptcies, Penalties or Sanctions .................  45
  Conflicts of Interest ....................................................  46
LEGAL PROCEEDINGS ..........................................................  46
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS ................  46
TRANSFER AGENT AND REGISTRAR ...............................................  46
INTERESTS OF EXPERTS .......................................................  46
AUDIT COMMITTEE ............................................................  46
  Mandate of the Audit Committee ...........................................  47
  Relevant Education and Experience of Audit Committee Members .............  47
  Audit Committee Oversight ................................................  47
  External Auditor Fees ....................................................  48
ADDITIONAL INFORMATION .....................................................  48
APPENDIX "A" ............................................................... A-1
APPENDIX "B" ............................................................... B-1
APPENDIX "C" ............................................................... C-1
</Table>


<Page>

                           GLOSSARY OF TECHNICAL TERMS

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

     (a)  "CONSTANT PRICES AND COSTS" means prices and costs used in an estimate
          that are:

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

          (ii) if, and only to the extent that, there are fixed or presently
               determinable future prices or costs to which the Corporation is
               legally bound by a contractual or other obligation to supply a
               physical product, including those for an extension period of a
               contract that is likely to be extended, those prices or costs
               rather than the prices and costs referred to in paragraph (i).

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

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

     (c)  "DEVELOPMENT COSTS" means costs incurred to obtain access to reserves
          and to provide facilities for extracting, treating, gathering and
          storing the oil and gas from the reserves. More specifically,
          development costs, including applicable operating costs of support
          equipment and facilities and other costs of development activities,
          are costs incurred to:

          (i)  gain access to and prepare well locations for drilling, including
               surveying well locations for the purpose of determining specific
               development drilling sites, clearing ground, draining, road
               building, and relocating public roads, gas lines and power lines,
               to the extent necessary in developing the reserves;

          (ii) drill and equip development wells, development type stratigraphic
               test wells and service wells, including the costs of platforms
               and of well equipment such as casing, tubing, pumping equipment
               and the wellhead assembly;

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

          (iv) provide improved recovery systems.

     (d)  "DEVELOPMENT WELL" means a well drilled inside the established limits
          of an oil or gas reservoir, or in close proximity to the edge of the
          reservoir, to the depth of a stratigraphic horizon known to be
          productive.

     (e)  "EXPLORATION COSTS" means costs incurred in identifying areas that may
          warrant examination and in examining specific areas that are
          considered to have prospects that may contain oil and gas reserves,
          including costs of drilling exploratory wells and exploratory type
          stratigraphic test wells. Exploration costs may be incurred both
          before acquiring the related property (sometimes referred to in part
          as "prospecting costs") and after acquiring the property. Exploration
          costs,


<Page>
                                     - 2 -


          which include applicable operating costs of support equipment and
          facilities and other costs of exploration activities, are:

          (i)  costs of topographical, geochemical, geological and geophysical
               studies, rights of access to properties to conduct those studies,
               and salaries and other expenses of geologists, geophysical crews
               and others conducting those studies (collectively sometimes
               referred to as "geological and geophysical costs");

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

         (iii) dry hole contributions and bottom hole contributions;

          (iv) costs of drilling and equipping exploratory wells; and

          (v)  costs of drilling exploratory type stratigraphic test wells.

     (f)  "EXPLORATORY WELL" means a well that is not a development well, a
          service well or a stratigraphic test well.

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

     (h)  "FUTURE PRICES AND COSTS" means future prices and costs that are:

          (i)  generally accepted as being a reasonable outlook of the future;

          (ii) if, and only to the extent that, there are fixed or presently
               determinable future prices or costs to which the Corporation is
               legally bound by a contractual or other obligation to supply a
               physical product, including those for an extension period of a
               contract that is likely to be extended, those prices or costs
               rather than the prices and costs referred to in paragraph (i).

     (i)  "FUTURE NET REVENUE" means the estimated net amount to be received
          with respect to the development and production of reserves (including
          synthetic oil, coal bed methane and other non-conventional reserves)
          estimated using constant prices and costs or forecast prices and
          costs.

     (j)  "GROSS" means:

          (i)  in relation to the Corporation's interest in production or
               reserves, its "company gross reserves", which are its working
               interest (operating or non-operating) share before deduction of
               royalties and without including any royalty interests of the
               Corporation;

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

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                                     - 3 -


         (iii) in relation to properties, the total area of properties in which
               the Corporation has an interest.

     (k)  "NATURAL GAS" means the lighter hydrocarbons and associated
          non-hydrocarbon substances occurring naturally in an underground
          reservoir, which under atmospheric conditions are essentially gases
          but which may contain natural gas liquids. Natural gas can exist in a
          reservoir either dissolved in crude oil (solution gas) or in a gaseous
          phase (associated gas or non-associated gas). Non-hydrocarbon
          substances may include hydrogen sulphide, carbon dioxide and nitrogen.

     (l)  "NATURAL GAS LIQUIDS" means those hydrocarbon components that can be
          recovered from natural gas as liquids including, but not limited to,
          ethane, propane, butanes, pentanes plus, condensate and small
          quantities of non-hydrocarbons.

     (m)  "NET" means:

          (i)  in relation to the Corporation's interest in production or
               reserves its working interest (operating or non-operating) share
               after deduction of royalty obligations, plus its royalty
               interests in production or reserves;

          (ii) in relation to the Corporation's interest in wells, the number of
               wells obtained by aggregating the Corporation's working interest
               in each of its gross wells; and

         (iii) in relation to the Corporation's interest in a property, the
               total area in which the Corporation has an interest multiplied by
               the working interest owned by the Corporation.

     (n)  "NON-ASSOCIATED GAS" means an accumulation of natural gas in a
          reservoir where there is no crude oil.

     (o)  "OPERATING COSTS" or "PRODUCTION COSTS" means costs incurred to
          operate and maintain wells and related equipment and facilities,
          including applicable operating costs of support equipment and
          facilities and other costs of operating and maintaining those wells
          and related equipment and facilities.

     (p)  "PRODUCTION" means recovering, gathering, treating, field or plant
          processing (for example, processing gas to extract natural gas
          liquids) and field storage of oil and gas.

     (q)  "PROPERTY" includes:

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

          (ii) royalty interests, production payments payable in oil or gas, and
               other non-operating interests in properties operated by others;
               and

         (iii) an agreement with a foreign government or authority under which
               the Corporation participates in the operation of properties or
               otherwise serves as "producer" of the underlying reserves (in
               contrast to being an independent purchaser, broker, dealer or
               importer).

     A property does not include supply agreements, or contracts that represent
     a right to purchase, rather than extract, oil or gas.

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                                     - 4 -


     (r)  "PROVED PROPERTY" means a property or part of a property to which
          reserves have been specifically attributed.

     (s)  "RESERVOIR" means a porous and permeable underground formation
          containing a natural accumulation of producible oil or gas that is
          confined by impermeable rock or water barriers and is individual and
          separate from other reservoirs.

     (t)  "SERVICE WELL" means a well drilled or completed for the purpose of
          supporting production in an existing field. Wells in this class are
          drilled for the following specific purposes: gas injection (natural
          gas, propane, butane or flue gas), water injection, steam injection,
          air injection, salt-water disposal, water supply for injection,
          observation, or injection for combustion.

     (u)  "UNPROVED PROPERTY" means a property or part of a property to which no
          reserves have been specifically attributed.

     (v)  "WELL ABANDONMENT COSTS" means costs of abandoning a well (net of
          salvage value) and of disconnecting the well from the surface
          gathering system. They do not include costs of abandoning the
          gathering system or reclaiming the wellsite.

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                                     - 5 -


                           FORWARD LOOKING STATEMENTS

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


     o    The future commercial success of the Corporation's oil and natural gas
          exploration, development and production activities;

     o    The stability of world-wide oil and natural gas prices;

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

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

     o    The Corporation's oil and natural gas reserves;

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

     o    The Corporation's ability to successfully defend against pending or
          future litigation.

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

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

The forward looking statements that are contained in this document involve a
number of risks and uncertainties. As a consequence, actual results might differ
materially from results forecast or suggested in these forward looking
statements. Additional information regarding these factors and other important
factors that could cause results to differ materially may be referred to as part
of particular forward looking statements. The forward looking statements are
qualified in their entirety by reference to the important factors discussed in
the section "RISK FACTORS" and elsewhere in this document and to those that may
be discussed as part of particular forward looking statements. We qualify all of
our forward-looking statements by these cautionary statements. The Corporation
assumes no obligation to update these forward-looking statements to reflect
actual results, changes in assumptions or changes in other factors affecting
such statements. Given these uncertainties, you should not place undue reliance
on these forward-looking statements.

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                                     - 6 -


                                  ABBREVIATIONS

<Table>
<Caption>
OIL AND NATURAL GAS LIQUIDS                                     NATURAL GAS
---------------------------                                     -----------
<S>       <C>                                                   <C>          <C>
bbl       barrel                                                mcf          thousand cubic feet
bbls      barrels                                               MMcf         million cubic feet
Mbbls     thousand barrels                                      mcf/d        thousand cubic feet per day
boe/d     barrels of oil equivalent per day                     MMcf/d       million cubic feet per day
bbl/d     barrels of oil per day                                M(3)         cubic metres
Mmbbls    million barrels                                       MMBTU        million British Thermal Units
AOF       absolute open flow                                    gigajoule    trillion joules
API       American Petroleum Institute                          TCF          trillion cubic feet
ARTC      Alberta Royalty Tax Credit                            MMscf        million standard cubic feet
MSTB      thousands of Stock Tank Barrels of oil                NGLS         natural gas liquids
          (oil volume at 60(DEGREES) F and 14.65 PSIA)


OTHER:
------
boe       Barrel of oil equivalent of natural gas and
          crude oil on the basis of 1 Bbl of crude oil
          for 6 Mcf of natural gas (this conversion
          factor is not based on either energy content
          or current prices).
$M        Thousands of dollars
$MM       Millions of dollars
</Table>

                                   CONVERSION

The following table sets forth certain standard conversions from Standard
Imperial units to the International System of units (or metric units).

<Table>
<Caption>
TO CONVERT FROM                            TO                      MULTIPLIED BY
----------------                           --                      -------------
<S>                                        <C>                     <C>
Mcf                                        Cubic metres                28.174
Cubic metres                               Cubic feet                  35.494
Bbls                                       Cubic metres                 0.159
Cubic metres                               Bbls oil                     6.290
Feet                                       Metres                       0.305
Metres                                     Feet                         3.281
Miles                                      Kilometres                   1.609
Kilometres                                 Miles                        0.621
Acres                                      Hectares                     0.405
Hectares                                   Acres                        2.471
Gigajoules                                 MMBTU                        0.950
</Table>

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                                     - 7 -


                                 THE CORPORATION

NAME AND INCORPORATION

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

Canadian Superior is a reporting issuer, or the equivalent, in the provinces of
British Columbia, Alberta, Saskatchewan, Manitoba, Ontario, Quebec, New
Brunswick, Nova Scotia, Prince Edward Island, and Newfoundland. The common
shares of the Corporation are listed and posted for trading on the Toronto Stock
Exchange and the American Stock Exchange under the symbol "SNG".

The Corporation's head office is located at 3300, 400 - 3rd Avenue S.W.,
Calgary, Alberta, T2P 4H2 and its registered office is located at 3300, 421 -
7th Avenue S.W., Calgary, Alberta, T2P 4K9. The Corporation has an east coast
office located at 704, 1959 Upper Water Street, Halifax, Nova Scotia, B3J 3N2.

INTERCORPORATE RELATIONSHIPS

The Corporation has no subsidiaries which individually represent more than 10%,
nor in the aggregate represent more than 20%, of the total consolidated assets
and total consolidated revenues of the Corporation, as at December 31, 2004.

                       GENERAL DEVELOPMENT OF THE BUSINESS

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

HISTORY

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

On February 16, 2005, Canadian Superior announced that the Toronto Stock
Exchange completed its review of Canadian Superior Energy and determined that
Canadian Superior meets the Toronto Stock Exchange's continued listing
requirements.

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

On December 30, 2004, Canadian Superior closed a private placement consisting of
1,377,000 common shares in the capital of the Corporation ("Common Shares")
issued on a "flow-through" basis at a price of $2.50 per share, for gross
proceeds of $3,442,500. Proceeds of the issue were used to fund exploration
drilling in Western Canada including East Ladyfern in Northwestern Alberta.

<Page>
                                     - 8 -


On December 6, 2004, the Corporation announced that the Toronto Stock Exchange
was reviewing the Common Shares of Canadian Superior with respect to meeting the
requirements for continued listing on the Toronto Stock Exchange.

On November 30, 2004, Canadian Superior announced that it and GlobalSantaFe
Corporation ("GlobalSantaFe") entered into an agreement for GlobalSantaFe to
drill Canadian Superior's next Mariner project exploration well, offshore Nova
Scotia, Canada and Canadian Superior's first Intrepid exploration well offshore
Trinidad and Tobago, subject to regulatory and governmental approvals.
GlobalSantaFe's harsh environment jackup drilling rig, the Galaxy II, which had
been working near Canadian Superior's Mariner Block in the Sable Island area,
offshore Nova Scotia, Canada was selected and awarded the contract to drill the
next Mariner well. In addition, GlobalSantaFe's semi-submersible drilling rig,
the Arctic I, which had been working in Venezuelan waters south of Canadian
Superior's Trinidad Intrepid Block 5(c) was selected and awarded the contract to
drill Canadian Superior's first offshore well on its Intrepid Block 5(c) off the
east coast of Trinidad.

On November 12, 2004, Mr. Alex Squires joined the Board of Directors of Canadian
Superior, replacing Mr. Rodney D. Erskine who is no longer a Director of
Canadian Superior.

On November 5, 2004, Mr. Ross A. Jones joined Canadian Superior as Chief
Financial Officer.

On November 1, 2004, the Corporation announced that in addition to the five
wells that were drilled in the second quarter of 2004, nine wells were drilled
in the third quarter, with eight out of the nine being successful. Six were
successful gas wells and two were successful oil wells. One of the producing gas
wells was dually completed for conventional gas and for coal bed methane. Of the
nine wells, eight are 100% working interest wells that are operated by Canadian
Superior.

On October 29, 2004, the Corporation announced that Mr. David Purcell resigned
as Chief Financial Officer of the Corporation, effective October 31, 2004. Mr.
Purcell's duties and responsibilities were re-assigned back to those persons
performing the functions prior to his joining the Corporation. Further, on
October 29, 2004 the Corporation announced that, effective October 18, 2004, Mr.
Harvey Klingensmith was no longer a Director of Canadian Superior. The
Corporation also announced that Mr. Frits Van Dyl joined the Corporation as
Senior Geologist.

On October 12, 2004, Canadian Superior Energy announced that it had determined
to proceed with its Mariner Project offshore Nova Scotia, near Sable Island,
with a second Mariner well planned to commence drilling between December 31,
2004 to April 30, 2005.

On October 6, 2004, Mr. Gregory Noval, President and Chief Executive Officer of
Canadian Superior, reassumed the role of Chief Operating Officer. Mr. Harvey R.
Klingensmith, who previously served as Chief Operating Officer, resigned
effective October 6, 2004.

On September 21, 2004, the Corporation announced that that an independent
petrophysical evaluation of the Canadian Superior El Paso Mariner I-85
exploration well was completed to analyze the well for hydrocarbon potential. In
the independent assessment, 24.6 m (80.7 feet) of net pay had been assigned to
the Canadian Superior El Paso Mariner I-85 well from the well log analysis.
Further, in the independent report, it was stated that 4 zones warranted flow
testing in the well based on the gas indications, calculated saturation and
porosity values, and the pressure potential at the depth of these formations.

On September 15, 2004, the Corporation announced that Canadian Superior acquired
El Paso Corporation's ("El Paso") offshore Nova Scotia exploration and
production assets. The acquisition was undertaken by negotiation between
Canadian Superior and El Paso and was facilitated by El Paso's decision to exit
the exploration and production in Western Canada and Offshore Nova Scotia. The
acquisition includes El Paso's interests in the Marquis Blocks (EL 2401 & 2402),
and in the Mariner Block (EL 2409) offshore Nova Scotia and in the Mariner

<Page>
                                     - 9 -


I-85 well. All of El Paso's seismic data, shared geophysical, geotechnical and
environmental data, Marquis L-35/L-35A well data, Mariner I-85 well data and
related inventory and extensive tax pools were acquired.

On August 30, 2004, the Corporation announced that its offshore wellsite survey
work, initiated earlier in August 2004, was successfully completed at two new
proposed future Mariner Project drilling locations. The field work was completed
on August 29, 2004 on the offshore Mariner Block (EL 2409) located in shallow
water approximately 275 kilometres (170 miles) southeast of Halifax, Nova
Scotia, Canada.

On August 24, 2004, the Corporation announced that it received the necessary
geophysical and geological work authorization approval from the Canada-Nova
Scotia Offshore Petroleum Board ("CNSOPB") to commence additional wellsite
survey activities on its Mariner block (EL 2409) located offshore, approximately
275 kilometres (170 miles) southeast of Halifax, Nova Scotia, Canada.

On June 11, 2004, several senior El Paso Oil and Gas Canada, Inc. management
personnel joined Canadian Superior's management team. More specifically, Mr.
Harvey R. Klingensmith joined Canadian Superior as Chief Operating Officer; Mr.
David Purcell as Chief Financial Officer; Mr. Mel Marshall as Vice President -
Exploration; and Mr. Tony Sartorelli as Senior Geophysicist.

On June 9, 2004, the Corporation announced that it retained the law firms of
Morrison & Foerster LLP of New York, NY and Borden Ladner Gervais LLP of
Calgary, Alberta to represent the Corporation with respect to a number of class
action proceedings against the Corporation.

On May 27, 2004, the Corporation's President & Chief Executive Office, Mr.
Gregory Noval, commenced an action against the National Post, its owners and
certain of its reporters for $75 million for damages relating to alleged
misleading reporting on Canadian Superior's Mariner well and the class action
lawsuits.

On May 11, 2004, the Corporation announced that it had been informed by the
Trinidad and Tobago Ministry of Energy and Energy Industries that its bid for
Block 5(c) in the 2003/2004 Competitive Bid Round was successful. Block 5(c) is
an 80,041 acre Continental Shelf block with water depths in excess of 150 meters
(500 feet).

On March 30, 2004, the Corporation announced that it had extended the expiry
date of its Common Share purchase warrants, issued in December 2003 and January
2004, from March 31, 2004 to December 31, 2004. The extension did not apply to
any warrants held by officers, directors, and security holders holding in excess
of 10% of the issued and outstanding securities of the Corporation or any of
their respective associates or affiliates.

On March 17, 2004, the Corporation announced that it had been made aware of
announcements by a number of United States law firms indicating that they plan
to commence a class action lawsuit against the Corporation and a number of its
senior officers with respect to events surrounding the Canadian Superior El Paso
Mariner I-85 exploration well, offshore Nova Scotia. See "LEGAL PROCEEDINGS".

On March 11, 2004, the Corporation announced that although the Mariner I-85
exploration well had encountered gas pay in multiple zones as targeted, the
Corporation had reluctantly agreed with El Paso, the operator of the test well,
not to proceed with any further testing or completion operations on the test
well at the time, to maintain the well within the original budget.

On March 8, 2004, Mr. Gerald J. Maier was appointed to the Board of Directors of
the Corporation.

On February 25, 2004, Mr. Rodney D. Erskine was appointed to the Board of
Directors of the Corporation.

In December 2003 and January 2004, Canadian Superior closed the private
placement of 7,400,180 special warrants at a price of $3.00 per special warrant
and 142,857 flow-through special warrants at a price of $3.50 per flow-through
special warrant for total gross proceeds of $22,700,540. Each special warrant
(other than a flow-through special warrant) exercisable into one Common Share
and one-third of one Common Share purchase warrant. Each flow through special
warrant exercisable into one Common Share.

<Page>
                                     - 10 -


In November and December 2003, Canadian Superior closed the private placement of
4,998,463 Common Shares issued on a "flow-through" basis at a price of $3.25 per
flow-through Common Share, for total gross proceeds of $16,245,005.

On November 20, 2003, Canadian Superior announced that drilling had commenced on
the Mariner I-85 exploration well and that El Paso Oil & Gas Canada, Inc., an
indirect subsidiary of El Paso Corporation, was participating in the drilling by
paying 2/3 of the costs to earn a 50% interest in the Mariner block.

On November 17, 2003, Canadian Superior announced that the CNSOPB had approved
the drilling program authorization application for the Canadian Superior / El
Paso Mariner I-85 exploration well.

On November 13, 2003, Canadian Superior announced that it had successfully
acquired two major exploration licences from the CNSOPB totalling 370,881 acres
for work expenditure bids totalling $14,107,000.

On April 16, 2003, Canadian Superior announced that a Canadian subsidiary of El
Paso Corporation had formally elected to farm-in and participate in the drilling
and development of the Corporation's Mariner block.

On April 15, 2003, Canadian Superior announced two new natural gas discoveries
located on the Corporation's East Ladyfern natural gas property.

On March 21, 2003, Canadian Superior announced that it had successfully
completed the acquisition of El Paso's Drumheller, Alberta area oil and gas
assets production facilities, gas plants and undeveloped lands located in
central Alberta (the "El Paso Properties"), for approximately $53.5 million, net
of purchase price adjustments.

On March 13, 2003, Canadian Superior closed a best efforts financing and issued
9,040,333 units, each unit consisting of one Common Share and one half of one
Common Share purchase warrant, at $1.50 per unit for total gross proceeds of
$13,560,500.

On February 25, 2003, Canadian Superior closed a bought deal financing and
issued 13,400,000 Common Shares at $1.60 per share for total gross proceeds of
$21,440,000.

On January 22, 2003, Canadian Superior announced that the CNSOPB had completed
its review and had issued its environmental approval of the Corporation's
"Environmental Assessment for Exploration Drilling in License EL 2409". The
Corporation also announced that preparations for drilling in the Mariner block
were underway and that commencement of drilling was targeted for the end of May
2003.

On January 13, 2003, Canada Superior announced it had entered into an agreement
with the Canadian division of El Paso Corporation to acquire their Drumheller
area oil and gas assets, production facilities, gas plants and undeveloped
lands, effective October 1, 2002, for, a then estimated, approximately $59.0
million, net of purchase price adjustments.

On November 18, 2002, Canadian Superior announced that it had completed an
acquisition in northwest Alberta comprising 22 contiguous sections located updip
of the main Ladyfern gas field. In a subsequent announcement March 11, 2003 the
Corporation announced that an initial test well located at 07-02-92-11 W6M had
been successfully drilled by the Corporation, to a total depth of 9,393 feet, to
evaluate the Slave Point formation.

On September 11, 2002, Canadian Superior announced that Canadian Superior's
Marquis L-35/L-35A test well which commenced drilling on July 8, 2002, was being
abandoned after having encountered porosity and the Abenaki reef reservoir.

On September 3, 2002, the Corporation's Common Shares began trading on The
American Stock Exchange under the symbol "SNG".

<Page>
                                     - 11 -


On June 9, 2002, Canadian Superior announced the commencement of the drilling on
its Marquis L-35 exploration well offshore Nova Scotia, Canada.

On April 23, 2002, the Corporation announced it had entered into a joint venture
with El Paso Oil and Gas Canada, Inc., an indirect subsidiary of El Paso, to
develop the Corporation's 100% owned Marquis project and Mariner prospect land
holdings in the shallow waters of the Scotian Shelf.

On February 21, 2002, the Corporation announced it had completed the wellsite
surveying for its initial test well on the Corporation's Marquis Abenaki Reef
prospect, located approximately 160 kilometres (100 miles) offshore Nova Scotia.

On February 8, 2002, the Corporation announced that its winter drilling program
in northern Alberta and northeast British Columbia resulted in 12 natural gas
discoveries and one oil discovery.

                           DESCRIPTION OF THE BUSINESS

GENERAL

COMPETITION

The oil and gas industry in Canada and Trinidad and Tobago is highly competitive
in all aspects, including the exploration for, and the development of, new
sources of supply, the acquisition of oil and gas interests and the marketing
of, crude oil, natural gas and natural gas liquids. The Corporation competes
with other companies in this sector for the exploration and development of oil
and gas reserves.

The Corporation actively competes for reserve acquisitions, exploration leases,
licences and concessions and skilled industry personnel with a substantial
number of other oil and gas companies. The Corporation's competitors include
major integrated oil and natural gas companies and numerous other independent
oil and natural gas companies and individual producers and operators, most of
which possess significantly greater financial resources than the Corporation.

CYCLICAL NATURE OF BUSINESS

The Corporation's business is generally not cyclical, however, its revenue from
the sale of natural gas is highly seasonal, with demand for natural gas rising
during cold winder months and hot summer months.

SPECIALIZED SKILL AND KNOWLEDGE

The Corporation believes its success is largely dependant on the performance of
its management and key employees, many of whom have specialized knowledge and
skills relating to conventional and offshore oil and gas operations. The
Corporation believes that they have adequate personnel with the specialized
skills required to successfully carry out its operations.

FOREIGN OPERATIONS

The Corporation currently has no production or revenue from foreign operations.

ENVIRONMENTAL PROTECTION

All aspects of the oil and gas industry present potential environmental risks
and are, accordingly, subject to a variety of Canadian federal, provincial and
municipal environmental regulations. These regulatory regimes are laws of
general application that apply to Canadian Superior in the same manner as they
apply to other participants in the energy industry.

<Page>
                                     - 12 -


All phases of the oil and natural gas business present environmental risks and
hazards and are subject to environmental regulation pursuant to a variety of
international conventions and provincial and municipal laws and regulations.
Environmental legislation provides for, among other things, restrictions and
prohibitions on spills, releases or emissions of various substances produced in
association with oil and gas operations. The legislation also requires that
wells and facility sites be operated, maintained, abandoned and reclaimed to the
satisfaction of applicable regulatory authorities. Compliance with such
legislation can require significant expenditures and a breach may result in the
imposition of fines and penalties, some of which may be material. Environmental
legislation is evolving in a manner expected to result in stricter standards and
enforcement, larger fines and liability and potentially increased capital
expenditures and operating costs. The discharge of oil, natural gas or other
pollutants into the air, soil or water may give rise to liabilities to third
parties and may require the Corporation to incur costs to remedy such discharge.
No assurance can be given that environmental laws will not result in a
curtailment of production or a material increase in the costs of production,
development or exploration activities or otherwise adversely affect the
Corporation's financial condition, capital expenditures, results of operations,
competitive position or prospects.

The Corporation conducts its operations in Canada in a manner consistent with
environmental regulations as stipulated in provincial and federal legislation.
The Corporation is committed to meeting its responsibilities to protect the
environment wherever it operates and anticipates making expenditures of both a
capital and expense nature to ensure full compliance with laws relating to
protection of the environment. The Corporation anticipates spending sufficient
funds on environmental expenditures in 2005 and in future years in order to
comply in all material respects with all environmental requirements related to
its field operations. The Corporation does not anticipate that such
expenditures, as a percentage of cash flow, will be greater than those expected,
on average, by other industry operators. The Corporation will maintain insurance
coverage where available, and financially desirable, in light of risk versus
cost factors.

HUMAN RESOURCES

The Corporation had a total of 34 full-time staff, including 5 staff members in
the Halifax office and 7 staff members in the Drumheller field office, as at
December 31, 2004.

OIL AND GAS PROPERTIES AND WELLS

Canadian Superior's principal properties can be divided into three distinct
groups:

     1.   Trinidad and Tobago;

     2.   East Coast, Offshore Nova Scotia, Canada; and

     3.   Western Canadian Holdings

TRINIDAD AND TOBAGO

In 2004, the Corporation continued to make steady progress in preparing for
exploration and development on its offshore Trinidad and Tobago holdings. The
Corporation was awarded the right to explore on Block 5(c), which the
Corporation has named "Intrepid", in the Government of Trinidad and Tobago
Ministry of Energy and Energy Industries' 2003/2004 Offshore Competitive Bid
Round in May 2004. The Corporation's Intrepid Block 5(c) covers 80,041 gross
acres. Management of the Corporation believes this block holds natural gas
exploration and development potential. The Corporation has obtained detailed 3D
seismic data of the Intrepid Block from the Government of Trinidad and Tobago
and is interpreting that data to confirm drilling locations. Based on this
seismic, a number of large structural gas prospects have been identified on the
Intrepid Block with multi-tcf potential. The Corporation has entered into a
production sharing contract (the "Production Sharing Contract") with the
Government of Trinidad and Tobago and management anticipates that the Production
Sharing Contract will be executed by the Prime Minister of Trinidad and Tobago
in due course. In anticipation of the finalization of

<Page>
                                     - 13 -


the Production Sharing Contract, the Corporation is completing the front-end
activities required to prepare for drilling on the Intrepid Block 5(c).

In connection with the anticipated commencement of the first phase of operations
in respect of the Corporation's Mayaro/Guayaguayare (M/G) Tradewinds project in
Trinidad and Tobago, the Corporation is planning to begin 3D seismic shooting
and acquisition operations in 2005 through 2006, to be followed by drilling
operations thereafter. Further, the Corporation has embarked on a joint venture
with a national oil company, the Petroleum Company of Trinidad and Tobago
Limited ("Petrotrin"). This joint venture encompasses the two near-shore
Mayaro/Guayaguayare (M/G) Blocks (55,000 gross acres) off the east coast of
Trinidad.

As a result of the Intrepid Block 5(c) acquisition and the Mayaro/Guayaguayare
(M/G) "Tradewinds" Joint Venture, Canadian Superior plans to drill at least five
new offshore wells over the next 12 to 36 months off the east coast of Trinidad.

EAST COAST, OFFSHORE NOVA SCOTIA, CANADA

In 2004, the Corporation and its former joint venture partner, El Paso Oil and
Gas Canada, Inc., drilled the Mariner I-85 exploration well. The well was
drilled, evaluated and the well bore was permanently abandoned. In the third
quarter of 2004, the Corporation released the results of an independent
petrophysical evaluation of the Mariner I-85 exploration well completed by Al
Lye & Associates, Inc. of Calgary, Alberta to analyze the well for hydrocarbon
potential. The independent assessment assigned 24.6 m (80.7 feet) of net pay to
the Mariner I-85 well. Furthermore, the independent report indicated that 4
zones warranted flow testing in the well based on the gas indications,
calculated saturation and porosity values, and the pressure potential at the
depth of these formations.

Further drilling is planned by Canadian Superior in offshore Nova Scotia off the
east coast of Canada. To better position the Corporation in this regard Canadian
Superior acquired El Paso's offshore Nova Scotia assets in the third quarter of
2004. The acquisition included El Paso's interests in the Marquis Blocks (EL
2401 & 2402), and in the Mariner Block (EL 2409) offshore Nova Scotia and in the
Mariner I-85 well, all of El Paso's seismic data, all shared geophysical,
geotechnical and environmental data, all Marquis L-35/L-35A well data, all
Mariner I-85 well data and all related inventory and extensive tax pools.

During the fourth quarter of 2004, the Corporation continued preparations for
further drilling on Mariner. Based on front-end geological and geophysical
analysis completed, two new prospective locations have been identified for
drilling on the Corporation's Mariner block. Drilling, engineering, procurement
and permitting activities to progress this additional drilling are underway. The
Corporation is preparing to undertake further drilling upon finalizing joint
venture partners and once rig availability is fully assessed and integrated into
the overall drilling schedule.

Canadian Superior's holdings offshore Nova Scotia consist of 100% interests in
six exploration licences totalling 1,293,946 acres. Canadian Superior is
involved in the three main play types in the basin.

In addition to Canadian Superior's Mariner exploration project targeting
Cretaceous and Jurassic gas bearing sands, in 2004 the Corporation continued to
work on its Abenaki reef Marquis project and Mayflower deepwater project. The
Marquis project lands encompass two exploration licences with approximately
112,000 contiguous acres located in shallow water depths. The Marquis Project
lands are located approximately 20 kilometres (12 miles) northwest of Sable
Island. During 2002, the first Marquis exploration well, L-35/L-35A, was drilled
and confirmed the presence of a porous Abenaki reef reservoir in three separate
zones within the Abenaki reef complex. Additional seismic data to provide
detailed geophysical data that can be tied to measured well bore data obtained
through the drilling of the Marquis L-35/L-35A exploration well, when obtained,
should allow the Corporation to identify optimal future drilling locations on
the Abenaki reef up-dip from their 2002 Marquis L-35/L-35A well.

<Page>
                                     - 14 -


Canadian Superior's Mariner, Marauder, Marconi and Marquis prospects comprise
approximately 584,000 acres and are located in close proximity to Sable Island.

Canadian Superior's Mayflower deepwater project exploration licence covers
approximately 710,000 acres and is located approximately 460 kilometres (285
miles) east of Boston. Mapping to date indicates the presence of five deepwater
prospects within the Mayflower block. These prospects are structural and are
typically formed by mobile salt tectonics. Prospect sizes range from 50 to 200
square kilometres (19 to 77 square miles) in size and are located in 1,300 to
2,500 metre (4,265 - 8,200 feet) water depths.

The Corporation acquired prospects in November 2003 on its Marauder and Marconi
exploration lands covering 370,881 additional acres offshore Nova Scotia. These
exploration licences were targeted for acquisition based on analysis of
proprietary seismic data and in-house geological evaluations. Marauder,
encompassing 312,037 acres, directly offsets three significant discovery
licences (Uniacke, Citnalta and Arcadia). Marauder has four seismically defined
prospects, two of which lie on trend with and are related to the Uniacke and
Citnalta significant discoveries. Marconi (EL 2416), encompassing 58,844 (100%
owned) acres, has a seismically defined tilted fault/anticlinal prospect similar
to other Sable area fields such as Glenelg and Alma.

WESTERN CANADA HOLDINGS

During 2004, the Corporation has continued to develop Western Canadian cash flow
and production focusing on developing its Drumheller Alberta area and several
high impact drilling opportunities. The Corporation's acreage holdings in
Drumheller continue to increase, and as of December 31, 2004, Canadian Superior
holds 181,995 gross acres in the Drumheller area.

Drumheller is Canadian Superior's core producing area and it generates the
majority of the Corporation's cash flow through the sale of oil and gas. During
2004, Canadian Superior drilled or participated in 38 gross (24.8 net) wells in
the Drumheller area with an overall success rate of over 90%. Of these 38 wells,
22 were operated and 16 were non-operated. The average working interest of the
operated wells was 91.7% and for the non-operated wells, the average working
interest was 28.9%. Canadian Superior's strategy is to maintain control over its
high interest wells and the timing for tie-in. Of the operated wells, 16 were
successful oil or gas wells, 3 were suspended and 3 were drilled and abandoned.

Of the 16 non-operated wells (9 of which are coal bed methane) all were
successful. Three of the wells are tied-in and producing and 13 are waiting
final tie-in. The Corporation participated in 10 coal bed methane wells (1
operated) in 2004. These wells show initial average test rates of 150 mcf/d. The
Corporation intends to use the 2004 program as a staging ground for future
development of the coal bed methane potential that exists over its acreage base
within the Drumheller area. The Corporation holds approximately 108 net sections
(69,120 acres) in the Drumheller area with the potential for coal bed methane
production.

In December of 2004, a 100% operated exploration well that was drilled by the
Corporation which validated 5 sections of land and tested 2 mmcf/d gas from a
Cretaceous exploratory target. The Corporation plans to tie-in this well in
early 2005 and follow up with more delineation drilling.

Another 12 to 14 operated locations are either surveyed or will be submitted for
survey and management of the Corporation expects that drilling of these
locations will commence in late winter or early spring of 2005. The Corporation
also shot or participated in two 2D seismic surveys and three 3D seismic
surveys, the largest of the 3D's seismic surveys being 46 square kilometres
which was completed in the late fall of 2004.

Canadian Superior also holds operated working interests in a number of other
Alberta, British Columbia and Saskatchewan properties that are primarily in
winter access areas. These other areas total an aggregate of 102,623 gross acres
(83,686 net acres) in Alberta and 15,243 gross acres (11,766 net acres) in
British Columbia. The main operated areas in Alberta are Windfall, Boundary Lake
and Bison. In British Columbia, the main operated areas are Altares, Umbach and
Parkland.

<Page>
                                     - 15 -


East Ladyfern
-------------

In March of 2004, Canadian Superior shot a 62 square kilometre 3D seismic
program in the East Ladyfern area to further evaluate the Slave Point potential
demonstrated in the tested 7-2 well. The 3D seismic indicated follow-up
locations to the south. Additional 2D seismic was shot and lands to the south
were tied up under a seismic option. The 1-26-92-11W6 location was surveyed and
prepared in late 2004 after freeze up. The well was spudded in late January of
2005 and it had been cased to the top of the Slave Point, but due to early
break-up the well was not completed. The Corporation plans to go back into the
area in late 2005 and test the well after freeze-up.

Windfall/Pine Creek
-------------------

Additional 2D seismic was shot in the Windfall area early in 2004 to evaluate
several potential zones in the Cretaceous and the Jurassic. Two wells were
planned and have been successfully drilled during the winter of 2004/2005. The
first well, non-operated, was spudded in late December 2004 and was tested in
early January 2005. This well is being tied-in by the operator of the well. The
second well, which is operated by Canadian Superior, was spudded in February of
2005 and awaits a completion that is scheduled before break up in late March or
early April, 2005.

Boundary Lake
-------------

In 2004, the Boundary Lake area was emphasized in Canadian Superior's
exploration effort. Several test seismic lines have been reprocessed which has
initiated a larger reprocessing project and a renewed interest in this area.
Exploration efforts are still in the planning stages and the Corporation is
looking to this area for future potential reserve adds.

British Columbia - Umbach, Altares, Parkland
--------------------------------------------

Although Canadian Superior continues to be active in Altares and the Parkland
area of NEBC, and the Venus, Botha and Chinchaga areas of Northern Alberta,
these areas have been re-evaluated over the last two quarters of 2004 and the
Corporation has at this time shifted its emphasis to the core areas in Alberta,
Offshore Nova Scotia and Offshore Trinidad.

          STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

GENERAL

The reserve disclosure presented below conforms with the requirements of
National Instrument 51-101, STANDARDS OF DISCLOSURE FOR OIL AND GAS ACTIVITIES
("NI 51-101"). Additional information not required by NI 51-101 has been
presented to provide continuity and additional information which management of
the Corporation believes is important to the readers of this information. Boe
may be misleading, particularly if used in isolation. A boe conversion ratio of
6 mcf:1 bbl is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
wellhead.

All of the Corporation's reserves are in Canada, more specifically in the
provinces of British Columbia, Alberta and Saskatchewan.

SELECTED RESERVES INFORMATION

The following tables set forth certain information relating to the oil and
natural gas reserves of the Corporation's properties and the present value of
the estimated future net cash flow associated with such reserves as at December
31, 2004. The information set forth below is derived from the report, with a
preparation date of March 3, 2005, prepared by Gilbert Laustsen Jung Associates
Ltd. ("GLJ") evaluating the Corporation's proved and proved plus probable
reserves (the "GLJ Report"). The effective date of the GLJ Report is December
31, 2004. The GLJ Report has been prepared in accordance with the standards
contained in the COGE Handbook and the

<Page>
                                     - 16 -


reserves definitions contained in National Instrument 51-101 and the COGE
Handbook. ALL EVALUATIONS AND REVIEWS OF FUTURE NET CASH FLOW ARE STATED PRIOR
TO ANY PROVISION FOR INTEREST COSTS OR GENERAL AND ADMINISTRATIVE COSTS AND
AFTER THE DEDUCTION OF ESTIMATED FUTURE CAPITAL EXPENDITURES FOR WELLS TO WHICH
RESERVES HAVE BEEN ASSIGNED. IT SHOULD NOT BE ASSUMED THAT THE ESTIMATED FUTURE
NET CASH FLOW SHOWN BELOW IS REPRESENTATIVE OF THE FAIR MARKET VALUE OF THE
CORPORATION'S PROPERTIES. THERE IS NO ASSURANCE THAT SUCH PRICE AND COST
ASSUMPTIONS WILL BE ATTAINED AND VARIANCES COULD BE MATERIAL. THE RECOVERY AND
RESERVE ESTIMATES OF CRUDE OIL, NGLS AND NATURAL GAS RESERVES PROVIDED HEREIN
ARE ESTIMATES ONLY AND THERE IS NO GUARANTEE THAT THE ESTIMATED RESERVES WILL BE
RECOVERED. ACTUAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES MAY BE GREATER OR
LESS THAN THE ESTIMATES PROVIDED HEREIN.

The Corporation has a Reserves Committee consisting of the entire Board of
Directors which reviews the qualifications and appointment of the independent
qualified reserves evaluators. The Reserves Committee also reviews the
procedures for providing information to the evaluators. All booked reserves are
based upon annual evaluation and review by the independent qualified reserves
evaluators.

In accordance with the requirements of National Instrument 51-101, the REPORT ON
RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR in Form 51-101 F2 and
the REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE in Form 51-101
F3 are attached as Appendices "A" and "B" hereto, respectively.

RESERVES DATA - CONSTANT PRICES AND COSTS

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

<Page>
                                     - 17 -


<Table>
<Caption>
                                                                  SUMMARY OF RESERVES AND VALUES
                                      ---------------------------------------------------------------------------------
                                                                                                                TOTAL
                                                           PROVED                                               PROVED
                                        PROVED            DEVELOPED         PROVED       TOTAL      TOTAL        PLUS
                                      PRODUCING         NON-PRODUCING     UNDEVELOPED    PROVED    PROBABLE    PROBABLE
                                      ---------         -------------     -----------    ------    --------    --------
<S>                                   <C>               <C>               <C>            <C>       <C>         <C>
MARKETABLE RESERVES
 LIGHT/MEDIUM OIL (MBBL)
   Total Company Interest                   805                     0               0       805         769       1,574
   Working Interest                         805                     0               0       805         769       1,574
   Net After Royalty                        741                     0               0       741         658       1,399

 GAS (MMCF)
   Total Company Interest                17,542                 2,344           1,040    20,925       8,553      29,479
   Working Interest                      17,297                 2,344           1,034    20,675       8,528      29,203
   Net After Royalty                     14,380                 1,835             882    17,097       6,796      23,893

 NATURAL GAS LIQUIDS (MBBL)
   Total Company Interest                   175                    18               4       197          92         288
   Working Interest                         170                    18               4       192          91         283
   Net After Royalty                        121                    12               2       136          63         199

 OIL EQUIVALENT (MBBL)
   Total Company Interest                 3,904                   409             177     4,490       2,286       6,776
   Working Interest                       3,858                   409             176     4,443       2,281       6,724
   Net After Royalty                      3,259                   318             149     3,726       1,853       5,579

BEFORE TAX PRESENT VALUE (M$)
   0.0%                                  92,002                 9,276           3,920   105,197      50,114     155,312
   5.0%                                  76,880                 8,191           3,040    88,111      34,651     122,761
   8.0%                                  70,416                 7,654           2,637    80,707      28,683     109,390
   10.0%                                 66,797                 7,334           2,408    76,539      25,546     102,085
   12.0%                                 63,605                 7,040           2,205    72,850      22,910      95,759
   15.0%                                 59,453                 6,642           1,942    68,037      19,676      87,713
   20.0%                                 53,813                 6,074           1,591    61,477      15,655      77,133

AFTER TAX PRESENT VALUE (M$)
   0.0%                                  91,923                     -               -   101,941           -     139,282
   5.0%                                  76,813                     -               -    85,342           -     110,165
   8.0%                                  70,356                     -               -    78,183           -      98,351
   10.0%                                 66,741                     -               -    74,162           -      91,929
   12.0%                                 63,552                     -               -    70,607           -      86,383
   15.0%                                 59,404                     -               -    65,978           -      79,347
   20.0%                                 53,771                     -               -    59,680           -      70,116
</Table>

<Page>
                                     - 18 -


The following table sets forth the total future net revenue of Canadian
Superior, undiscounted:

                     TOTAL FUTURE NET REVENUE (UNDISCOUNTED)

<Table>
<Caption>
                                                                                                   Future Net
                                                                                                     Revenue              Future Net
                                                                     Capital                         Before                 Revenue
                                                     Operating     Development     Abandonment       Income     Income       After
                            Revenue     Royalties      Costs          Costs           Costs           Taxes       Tax       Income
Entity Description           (M$)          (M$)         (M$)           (M$)            (M$)            (M$)       (M$)    Taxes (M$)
------------------          -------     ---------    ---------     -----------     -----------    -----------    ------  -----------
<S>                         <C>         <C>          <C>           <C>             <C>            <C>            <C>     <C>
Proved Producing            157,225        21,632       41,296             390           1,906         92,002        79       91,923

Proved Developed
  Nonproducing               15,955         1,757        2,758           1,985             178          9,276         -            -

Proved Undeveloped            7,365           790        1,290           1,257             108          3,920         -            -

Total Proved                180,545        24,179       45,344           3,633           2,192        105,197     3,256      101,941

Total Probable               92,237        14,660       22,039           5,163             261         50,114         -            -

Total Proved
  Plus Probable             272,782        38,839       67,383           8,795           2,453        155,312    16,030      139,282
</Table>

<Page>
                                     - 19 -


The following table represents a summary of oil and gas reserves and the net
present values of future net revenue:

    SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE

<Table>
<Caption>
                                                            Reserves
                           ---------------------------------------------------------------------------
                             Light and                                     Natural Gas        Oil
                            Medium Oil      Heavy Oil      Natural Gas       Liquids      Equivalent
                           -------------   -----------   ---------------   -----------   -------------
                           W.I.     Net    W.I.   Net     W.I.     Net     W.I.   Net    W.I.     Net
Entity Description         Mbbl    Mbbl    Mbbl   Mbbl    MMcf     MMcf    Mbbl   Mbbl   Mbbl    Mbbl
------------------         -----   -----   ----   ----   ------   ------   ----   ----   -----   -----
<S>                        <C>     <C>     <C>    <C>    <C>      <C>      <C>    <C>    <C>     <C>
PROVED PRODUCING
Light & Medium Oil.......   575     525     0      0      3,836    3,273    63     49    1,277   1,120
Natural Gas..............   231     216     0      0     13,461   11,106   107     72    2,581   2,139
Other Company
  Revenue/Costs..........     0       0     0      0          0        0     0      0       0       0
                           -----   -----    --     --    ------   ------   ---    ---    -----   -----
TOTAL: PROVED
  PRODUCING..............   805     741     0      0     17,297   14,380   170    121    3,858   3,259

TOTAL PROVED
Light & Medium Oil.......   575     525     0      0      3,836    3,273    63     49    1,277   1,120
Natural Gas..............   231     216     0      0     16,839   13,823   129     87    3,166   2,607
Other Company
  Revenue/Costs..........     0       0     0      0          0        0     0      0       0       0
                           -----   -----    --     --    ------   ------   ---    ---    -----   -----
TOTAL: TOTAL PROVED......   805     741     0      0     20,675   17,097   192    136    4,443   3,726

TOTAL PROVED PLUS
  PROBABLE
Light & Medium Oil.......  1,250   1,094    0      0      5,056    4,207    89     68    2,182   1,863
Natural Gas..............   324     304     0      0     24,147   19,686   194    131    4,542   3,716
Other Company
  Revenue/Costs..........     0       0     0      0          0        0     0      0       0       0
                           -----   -----    --     --    ------   ------   ---    ---    -----   -----
TOTAL PROVED PLUS
  PROBABLE...............  1,574   1,399    0      0     29,203   23,893   283    199    6,724   5,579

<Caption>
                              Net Present Value of Future Net Revenue
                           ---------------------------------------------
                                         Before Income Tax
                                    Discounted at Various Rates
                           ---------------------------------------------
                             0%        5%        10%      15%      20%
Entity Description           M$        M$        M$        M$       M$
------------------         -------   -------   -------   ------   ------
<S>                        <C>       <C>       <C>       <C>      <C>
PROVED PRODUCING
Light & Medium Oil.......   30,751    24,712    20,993   18,401   16,468
Natural Gas..............   60,847    51,734    45,352   40,591   36,884
Other Company
  Revenue/Costs..........      404       434       452      460      461
                           -------   -------   -------   ------   ------
TOTAL: PROVED
  PRODUCING..............   92,002    76,880    66,797   59,453   53,813
TOTAL PROVED
Light & Medium Oil.......   30,751    24,712    20,993   18,401   16,468
Natural Gas..............   73,719    62,625    54,749   48,831   44,209
Other Company
  Revenue/Costs..........      727       774       797      804      801
                           -------   -------   -------   ------   ------
TOTAL: TOTAL PROVED......  105,197    88,111    76,539   68,037   61,477
TOTAL PROVED PLUS
  PROBABLE
Light & Medium Oil.......   51,843    37,473    29,311   24,104   20,524
Natural Gas..............  101,285    83,339    71,011   61,996   55,122
Other Company
  Revenue/Costs..........    2,184     1,949     1,764    1,613    1,487
                           -------   -------   -------   ------   ------
TOTAL PROVED PLUS
  PROBABLE...............  155,312   122,761   102,085   87,713   77,133
</Table>

<Page>
                                     - 20 -


RESERVES DATA - FORECAST PRICES AND COSTS

The following table sets forth a summary of reserves and values and the net
present value of future net revenue of the Corporation, forecast based:

<Table>
<Caption>
                                                                  SUMMARY OF RESERVES AND VALUES
                                      ---------------------------------------------------------------------------------
                                                                                                                TOTAL
                                                           PROVED                                               PROVED
                                        PROVED            DEVELOPED         PROVED       TOTAL      TOTAL        PLUS
                                      PRODUCING         NON-PRODUCING     UNDEVELOPED    PROVED    PROBABLE    PROBABLE
                                      ---------         -------------     -----------    ------    --------    --------
<S>                                   <C>               <C>               <C>            <C>       <C>         <C>
MARKETABLE RESERVES
 LIGHT/MEDIUM OIL (MBBL)
   Total Company Interest                   768                     0               0       768         763       1,531
   Working Interest                         768                     0               0       768         763       1,531
   Net After Royalty                        708                     0               0       708         655       1,363

 GAS (MMCF)
   Total Company Interest                17,288                 2,340           1,031    20,659       8,193      28,852
   Working Interest                      17,043                 2,340           1,025    20,408       8,167      28,575
   Net After Royalty                     14,167                 1,831             875    16,873       6,481      23,355

 NATURAL GAS LIQUIDS (MBBL)
   Total Company Interest                   172                    18               4       194          88         282
   Working Interest                         167                    18               3       189          88         277
   Net After Royalty                        120                    12               2       134          61         195

 OIL EQUIVALENT (MBBL)
   Total Company Interest                 3,822                   408             175     4,405       2,217       6,622
   Working Interest                       3,776                   408             174     4,358       2,212       6,570
   Net After Royalty                      3,189                   317             148     3,654       1,797       5,451

BEFORE TAX PRESENT VALUE (M$)
   0%                                    80,547                 8,095           3,065    91,706      39,825     131,532
   5%                                    68,343                 7,199           2,369    77,911      27,770     105,682
   8%                                    63,143                 6,753           2,049    71,945      23,108      95,053
   10%                                   60,219                 6,485           1,867    68,572      20,647      89,219
   12%                                   57,629                 6,240           1,705    65,574      18,573      84,146
   15%                                   54,238                 5,906           1,495    61,639      16,017      77,656
   20%                                   49,583                 5,426           1,214    56,223      12,819      69,042

AFTER TAX PRESENT VALUE (M$)
   0%                                    80,547                     -               -    90,550           -     122,672
   5%                                    68,343                     -               -    76,898           -      98,460
   8%                                    63,143                     -               -    71,005           -      88,608
   10%                                   60,219                     -               -    67,678           -      83,224
   12%                                   57,629                     -               -    64,722           -      78,556
   15%                                   54,238                     -               -    60,846           -      72,599
   20%                                   49,583                     -               -    55,515           -      64,719
</Table>

<Page>
                                     - 21 -


The following table represents the total future net revenue of the Corporation,
undiscounted:

                     TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
<Table>
<Caption>
                                                                                                  Future Net
                                                                                                    Revenue               Future Net
                                                                     Capital                         Before                Revenue
                                                     Operating     Development     Abandonment       Income      Income     After
                            Revenue     Royalties      Costs          Costs           Costs           Taxes        Tax     Income
Entity Description            (M$)         (M$)         (M$)           (M$)            (M$)           (M$)         M$)    Taxes (M$)
------------------          -------     ---------    ---------     -----------     -----------    -----------    ------  -----------
<S>                         <C>         <C>          <C>           <C>             <C>            <C>            <C>     <C>
Proved Producing            146,289        19,835       43,347             360           2,201         80,547         0       80,547

Proved Developed
  Nonproducing               14,792         1,610        2,883           2,004             201          8,095         -            -

Proved Undeveloped            6,563           681        1,401           1,284             132          3,065         -            -

Total Proved                167,644        22,126       47,630           3,647           2,534         91,706     1,156       90,550

Total Probable               83,164        13,005       24,597           5,309             428         39,825         -            -

Total Proved
  Plus Probable             250,808        35,131       72,228           8,957           2,961        131,532     8,859      122,672
</Table>



<Page>
                                     -22 -

    The following table sets forth the discounted future net revenue of the
Corporation's oil and gas reserves by production group:

  SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE
<Table>
<Caption>
                                                                                        RESERVES
                                                             ---------------------------------------------------------------
                                                                  LIGHT AND
                                                                 MEDIUM OIL             HEAVY OIL            NATURAL GAS
                                                             -------------------   -------------------   -------------------
                                                               W.I.       NET        W.I.       NET        W.I.       NET
                    ENTITY DESCRIPTION                         MBBL       MBBL       MBBL       MBBL       MMCF       MMCF
-----------------------------------------------------------  --------   --------   --------   --------   --------   --------
<S>                                                          <C>        <C>        <C>        <C>        <C>        <C>
PROVED PRODUCING
Light & Medium Oil                                              538        492        0          0         3,784      3,236
Natural Gas                                                     230        216        0          0        13,259     10,931
Other Company Revenue/Costs                                       0          0        0          0             0          0
                                                              -----      -----        --         --       ------     ------
TOTAL: PROVED PRODUCING                                         768        708        0          0        17,043     14,167

TOTAL PROVED
Light & Medium Oil                                              538        492        0          0         3,784      3,236
Natural Gas                                                     230        216        0          0        16,624     13,637
Other Company Revenue/Costs                                       0          0        0          0             0          0
                                                              -----      -----        --         --       ------     ------
TOTAL: TOTAL PROVED                                             768        708        0          0        20,408     16,873

TOTAL PROVED PLUS PROBABLE
Light & Medium Oil                                            1,207      1,059        0          0         4,982      4,155
Natural Gas                                                     324        305        0          0        23,593     19,200
Other Company Revenue/Costs                                       0          0        0          0             0          0
                                                              -----      -----        --         --       ------     ------
TOTAL: TOTAL PROVED PLUS PROBABLE                             1,531      1,363        0          0        28,575     23,355

<Caption>
                                                                             RESERVES
                                                             -----------------------------------------
                                                                 NATURAL GAS
                                                                   LIQUIDS           OIL EQUIVALENT
                                                             -------------------   -------------------
                                                               W.I.       NET        W.I.       NET
                    ENTITY DESCRIPTION                         MBBL       MBBL       MBBL       MBBL
-----------------------------------------------------------  --------   --------   --------   --------
<S>                                                          <C>        <C>        <C>        <C>
PROVED PRODUCING
Light & Medium Oil                                              61         48       1,230      1,080
Natural Gas                                                    106         72       2,546      2,109
Other Company Revenue/Costs                                      0          0           0          0
                                                               ---        ---       -----      -----
TOTAL: PROVED PRODUCING                                        167        120       3,776      3,189

TOTAL PROVED
Light & Medium Oil                                              61         48       1,230      1,080
Natural Gas                                                    127         86       3,128      2,574
Other Company Revenue/Costs                                      0          0           0          0
                                                               ---        ---       -----      -----
TOTAL: TOTAL PROVED                                            189        134       4,358      3,654

TOTAL PROVED PLUS PROBABLE
Light & Medium Oil                                              87         67       2,125      1,818
Natural Gas                                                    190        128       4,446      3,633
Other Company Revenue/Costs                                      0          0           0          0
                                                               ---        ---       -----      -----
TOTAL: TOTAL PROVED PLUS PROBABLE                              277        195       6,570      5,451

<Caption>
                                                                   NET PRESENT VALUE OF FUTURE NET REVENUE
                                                             ----------------------------------------------------
                                                                 BEFORE INCOME TAX DISCOUNTED AT VARIOUS RATES
                                                             ----------------------------------------------------
                                                                                     10%        15%        20%
                    ENTITY DESCRIPTION                        0% M$      5% M$        M$         M$         M$
-----------------------------------------------------------  --------   --------   --------   --------   --------
<S>                                                          <C>        <C>        <C>        <C>        <C>
PROVED PRODUCING
Light & Medium Oil                                            26,630     21,625     18,674     16,630     15,092
Natural Gas                                                   53,594     46,350     41,148     37,194     34,070
Other Company Revenue/Costs                                      323        368        397        414        421
                                                             -------    -------     ------     ------     ------
TOTAL: PROVED PRODUCING                                       80,547     68,343     60,219     54,238     49,583

TOTAL PROVED
Light & Medium Oil                                            26,630     21,625     18,674     16,630     15,092
Natural Gas                                                   64,459     55,605     49,178     44,271     40,388
Other Company Revenue/Costs                                      617        682        720        738        743
                                                             -------    -------     ------     ------     ------
TOTAL: TOTAL PROVED                                           91,706     77,911     68,572     61,639     56,223

TOTAL PROVED PLUS PROBABLE
Light & Medium Oil                                            43,090     31,630     25,240     21,153     18,316
Natural Gas                                                   86,539     72,318     62,384     55,024     49,348
Other Company Revenue/Costs                                    1,902      1,733      1,595      1,478      1,378
                                                             -------    -------     ------     ------     ------
TOTAL: TOTAL PROVED PLUS PROBABLE                            131,532    105,682     89,219     77,656     69,042
</Table>

<Page>
                                       - 23 -

CONSTANT PRICES USED IN ESTIMATES

    The following table identifies benchmark reference pricing. The oil, gas,
NGL reference prices, inflation rates and exchange rates used in the forecasted
price evaluation were prepared by GLJ, the Corporation's independent qualified
reserves evaluator and are as follows:

                       DECEMBER 31, 2004 CONSTANT PRICES
                        CRUDE OIL AND NATURAL GAS PRICES
<Table>
<Caption>
                                                                                         BOW
                                                                           LIGHT,       RIVER
                                                WEST TEXAS     BRENT       SWEET       CRUDE OIL                MEDIUM
                                               INTERMEDIATE    BLEND      CRUDE OIL     STREAM        LLB      CRUDE OIL
                                                CRUDE OIL     CRUDE OIL    (40 API,     QUALITY    CRUDE OIL   (29 API,
                                                AT CUSHING      FOB       0.3%S) AT       AT          AT       2.0%S) AT
                                                 OKLAHOMA     NORTH SEA    EDMONTON    HARDISTY    HARDISTY     CROMER
                                   EXCHANGE        THEN         THEN         THEN        THEN        THEN        THEN
                       INFLATION     RATE        CURRENT       CURRENT     CURRENT      CURRENT     CURRENT     CURRENT
YEAR                       %       $US/$CDN      $US/BBL       $US/BBL     $CDN/BBL    $CDN/BBL    $CDN/BBL    $CDN/BBL
----                   ---------   ---------   ------------   ---------   ----------   ---------   ---------   ---------
<S>                    <C>         <C>         <C>            <C>         <C>          <C>         <C>         <C>
1999 Average              1.7       0.6750        19.29         17.81       27.69        23.84       22.14       25.42
2000 Average              2.7       0.6740        30.22         28.35       44.56        35.25       32.61       39.91
2001 Average              2.6       0.6448        25.97         24.37       39.40        27.70       23.48       31.56
2002 Average              2.2       0.6376        26.08         24.99       40.33        31.83       30.60       35.48
2003 Average              2.8       0.7213        31.07         28.93       43.66        32.11       31.18       37.55
2004 Average (e)          1.9       0.7734        41.38         38.20       52.96        36.86       35.64       45.75

DECEMBER 31, 2004         0.0       0.8308(1)     43.45(2)      40.46(3)    46.54(4)     25.92(5)    24.33(6)    32.12(7)
                                                  CONSTANT THEREAFTER

<Caption>

                                 ALBERTA NATURAL GAS LIQUIDS
                       -----------------------------------------------
                                                             EDMONTON
                         SPEC      EDMONTON     EDMONTON     PENTANES
                        ETHANE     PROPANE       BUTANE        PLUS
YEAR                   $CDN/BBL    $CDN/BBL     $CDN/BBL     $CDN/BBL
----                   --------   ----------   ----------   ----------
<S>                    <C>        <C>          <C>          <C>
1999 Average              n/a       15.89        18.70        27.71
2000 Average              n/a       32.18        35.60        46.31
2001 Average              n/a       31.85        31.17        42.48
2002 Average              n/a       21.39        27.08        40.73
2003 Average              n/a       32.14        34.36        44.23
2004 Average (e)          n/a       34.70        39.97        54.07

DECEMBER 31, 2004       22.66       29.79        34.44        48.97(7)
                                     CONSTANT THEREAFTER
</Table>

<Page>
                                     -24 -

                            NATURAL GAS AND SULPHUR
<Table>
<Caption>
                             US GULF COAST
                             GAS PRICE AT     MIDWEST AT                     SPOT PLANT
                               HENRY HUB        CHICAGO       AECO-C SPOT    GATE THEN    ARP PLANT    AGGREGATOR    ALLIANCE
                             THEN CURRENT    THEN CURRENT    THEN CURRENT     CURRENT        GATE      PLANT GATE   PLANT GATE
YEAR                           $US/MMBTU       $US/MMBTU      $CDN/MMBTU      $/MMBTU      $/MMBTU      $/MMBTU      $/MMBTU
----                         -------------   -------------   -------------   ----------   ----------   ----------   ----------
<S>                          <C>             <C>             <C>             <C>          <C>          <C>          <C>
1999 Average                     2.32            2.34            2.92           2.75         2.48          n/a          n/a
2000 Average                     4.33            4.38            5.08           4.92         4.50         4.60          n/a
2001 Average                     4.05            4.17            6.21           6.07         5.41         5.30         5.61
2002 Average                     3.36            3.30            4.04           3.88         3.88         3.83         3.82
2003 Average                     5.50            5.60            6.66           6.49         6.13         5.89         6.69
2004 Average (e)                 6.19            6.13            6.88           6.69         6.33         6.19         6.45

DECEMBER 31, 2004                6.15(8)         6.25            6.79(9)        6.54         6.49         6.39         6.39
                                                     CONSTANT THEREAFTER

<Caption>

                                           SASK. SPOT                                            SULPHUR     ALBERTA
                             SASKENERGY      PLANT         SUMAS       CANWEST     SPOT PLANT      FOB      SULPHUR AT
                             PLANT GATE       GATE         SPOT       PLANT GATE      GATE      VANCOUVER   PLANT GATE
YEAR                           $/MMBTU      $/MMBTU      $US/MMBTU     $/MMBTU      $/MMBTU      $US/LT      $CDN/LT
----                         -----------   ----------   -----------   ----------   ----------   ---------   ----------
<S>                          <C>           <C>          <C>           <C>          <C>          <C>         <C>
1999 Average                    2.83          2.97         2.15          2.51         2.78        33.74         6.93
2000 Average                    4.79          5.16         4.17          5.27         4.88        38.14        13.59
2001 Average                    5.71          6.20         4.56          6.76         6.29        18.29       -14.66
2002 Average                    4.04          4.08         2.68          3.64         3.93        29.38         3.04
2003 Average                    6.40          6.68         4.66          5.71         6.32        59.81        39.83
2004 Average (e)                6.59          6.78         5.26          5.54         6.44        62.99        38.75

DECEMBER 31, 2004               6.64          6.69         5.50          5.44         6.49        63.50(10)    34.00(10)
                                                                CONSTANT THEREAFTER
</Table>

    Unless otherwise stated, the gas price reference point is the receipt point
on the applicable provincial gas transmission system known as the plant gate.
The plant gate price represents the price before raw gas gathering and
processing charges are deducted. Spot refers to weighted average one month
price.

    NOTE: THESE PRICES ARE ACTUAL POSTED PRICES AT THE REFERENCED DATE; OTHER
REFERENCE PRICES ARE DERIVED BASED ON HISTORICAL PRICE DIFFERENTIALS.

(1) This is the December 31, 2004 Noon Rate from the Bank of Canada.

(2) This is the December 31, 2004 settlement price for prompt month delivery
    from NYMEX.

(3) This is the December 31, 2004 price reported by Nickles (Daily Oil
    Bulletin).

(4) This is the December 31, 2004 average price reported by Imperial, Shell and
    Petro-Canada refineries.

(5) This is the December 31, 2004 price reported by Petro-Canada.

(6) This is the December 31, 2004 price reported by Flint Hills.

(7) This is the December 31, 2004 price reported by Shell.

(8) This is the December 31, 2004 settlement price for prompt month delivery
    from NYMEX.

(9) This is the December 31, 2004 same day settlement price from NGX.

(10) Utilized the GLJ January 1, 2005 forecast price for 2005.
<Page>
                                       - 25 -

FORECAST PRICES USED IN ESTIMATES

    The following table represents forecast prices for crude oil and natural gas
liquids used in preparing reserves data by GLJ, the Corporation's independent
qualified reserves evaluator. This standard price forecast of GLJ is effective
January 1, 2005:

                     GILBERT LAUSTSEN JUNG ASSOCIATES LTD.
                       CRUDE OIL AND NATURAL GAS LIQUIDS
                                 PRICE FORECAST
                           EFFECTIVE JANUARY 1, 2005
<Table>
<Caption>
                                              WEST TEXAS
                              BANK OF     INTERMEDIATE CRUDE                           LIGHT, SWEET CRUDE
                              CANADA        OIL AT CUSHING       BRENT BLEND CRUDE     OIL (40 API, 0.3%S)
                              AVERAGE          OKLAHOMA          OIL FOB NORTH SEA     AT EDMONTON
                               NOON      --------------------   --------------------   -------------------
                             EXCHANGE    CONSTANT     THEN      CONSTANT     THEN      CONSTANT     THEN
                 INFLATION     RATE        2005      CURRENT      2005      CURRENT      2005      CURRENT
YEAR                 %       $US/$CDN    $US/BBL     $US/BBL    $US/BBL     $US/BBL    $CDN/BBL   $CDN/BBL
----             ---------   ---------   --------   ---------   --------   ---------   --------   ---------
<S>              <C>         <C>         <C>        <C>         <C>        <C>         <C>        <C>
1994              0.2         0.732      21.01       17.18      19.34       15.82      27.17       22.22
1995              2.2         0.729      22.44       18.39      20.79       17.04      29.57       24.23
1996              1.6         0.733      26.26       21.99      24.40       20.43      35.10       29.39
1997              1.6         0.722      24.23       20.61      22.55       19.18      32.74       27.85
1998              0.9         0.675      16.68       14.42      14.84       12.83      23.56       20.36
1999              1.7         0.673      22.12       19.29      20.42       17.81      31.75       27.69
2000              2.7         0.673      34.07       30.22      31.97       28.35      50.24       44.56
2001              2.6         0.646      28.51       25.97      26.76       24.37      43.26       39.40
2002              2.2         0.637      27.91       26.08      26.74       24.99      43.16       40.33
2003              2.8         0.721      32.53       31.07      30.29       28.93      45.71       43.66
2004 (e)          1.9         0.769      42.15       41.38      38.81       38.10      53.95       52.96

2005 Q1           2.0         0.820      43.25       43.25      41.75       41.75      52.00       52.00
2005 Q2           2.0         0.820      42.25       42.25      40.75       40.75      50.50       50.50
2005 Q3           2.0         0.820      41.50       41.50      40.00       40.00      49.75       49.75
2005 Q4           2.0         0.820      41.00       41.00      39.50       39.50      49.00       49.00

2005 Full
Year              2.0         0.820      42.00       42.00      40.50       40.50      50.25       50.25

2006              2.0         0.820      39.25       40.00      37.75       38.50      46.75       47.75
2007              2.0         0.820      36.50       38.00      35.00       36.50      43.75       45.50
2008              2.0         0.820      34.00       36.00      32.50       34.50      40.75       43.25
2009              2.0         0.820      31.50       34.00      30.00       32.50      37.75       40.75
2010              2.0         0.820      30.00       33.00      28.50       31.50      35.75       39.50
2011              2.0         0.820      29.25       33.00      28.00       31.50      35.00       39.50
2012              2.0         0.820      28.75       33.00      27.50       31.50      34.50       39.50
2013              2.0         0.820      28.50       33.50      27.25       32.00      34.25       40.00
2014              2.0         0.820      28.50       34.00      27.25       32.50      34.00       40.75
2015              2.0         0.820      28.25       34.50      27.00       33.00      33.75       41.25
2016+             2.0         0.820      28.25      +2.0%/yr    27.00      +2.0%/yr    33.75      +2.0%/yr
                  Revised January 6, 2005 11:03 AM

<Caption>
                                           BOW RIVER CRUDE OIL         HEAVY CRUDE
                                            STREAM QUALITY AT           OIL PROXY
                                               HARDISTY           (12 API) AT HARDISTY
                                           -------------------    ---------------------
                                           CONSTANT     THEN      CONSTANT      THEN
                                             2005      CURRENT      2005       CURRENT
YEAR                                       $CDN/BBL   $CDN/BBL    $CDN/BBL    $CDN/BBL
----                                       --------   ---------   ---------   ---------
<S>                                        <C>        <C>         <C>         <C>
1994                                        22.58       18.47       18.36       15.02
1995                                        25.38       20.80       21.09       17.28
1996                                        30.01       25.13       23.96       20.06
1997                                        24.89       21.17       16.94       14.41
1998                                        16.94       14.64       10.93        9.45
1999                                        27.34       23.84       22.56       19.67
2000                                        39.74       35.25       30.83       27.34
2001                                        30.41       27.70       18.60       16.94
2002                                        34.06       31.83       28.43       26.57
2003                                        33.62       32.11       27.49       26.26
2004 (e)                                    37.60       36.91       29.65       29.11

2005 Q1                                     33.25       33.25       24.50       24.50
2005 Q2                                     36.25       36.25       29.00       29.00
2005 Q3                                     35.75       35.75       28.50       28.50
2005 Q4                                     35.25       35.25       28.00       28.00

2005 Full
Year                                        35.00       35.00       27.50       27.50

2006                                        34.50       35.25       28.00       28.50
2007                                        33.75       35.00       27.75       28.75
2008                                        31.25       33.25       25.75       27.25
2009                                        29.00       31.50       23.50       25.50
2010                                        27.50       30.50       22.50       24.75
2011                                        27.00       30.50       22.00       24.75
2012                                        26.50       30.50       21.50       24.75
2013                                        26.25       30.75       21.00       24.75
2014                                        26.25       31.50       21.25       25.50
2015                                        26.00       31.75       21.00       25.75
2016+                                       26.00      +2.0%/yr     21.00      +2.0%/yr
                                                    Revised January 6, 2005 11:03 AM

<Caption>

                                              MEDIUM CRUDE OIL                   ALBERTA NATURAL GAS
                                             (29 API, 2.0%S) AT                 LIQUIDS (THEN CURRENT
                                                   CROMER                             DOLLARS)
                                            ---------------------              -----------------------    EDMONTON
                                            CONSTANT      THEN        SPEC      EDMONTON     EDMONTON     PENTANES
                                              2005       CURRENT     ETHANE     PROPANE       BUTANE        PLUS
YEAR                                        $CDN/BBL    $CDN/BBL    $CDN/BBL    $CDN/BBL     $CDN/BBL     $CDN/BBL
----                                        ---------   ---------   --------   ----------   ----------   ----------
<S>                                         <C>         <C>         <C>        <C>          <C>          <C>
1994                                         23.60       19.30       n/a        12.53        13.45        21.69
1995                                         26.47       21.69       n/a        13.90        13.79        24.11
1996                                         31.17       26.10       n/a        22.31        17.15        30.06
1997                                         27.88       23.72       n/a        18.62        18.73        30.91
1998                                         19.61       16.95       n/a        11.15        12.44        21.83
1999                                         29.15       25.42       n/a        15.89        18.70        27.71
2000                                         45.00       39.91       n/a        32.18        35.60        46.31
2001                                         34.65       31.56       n/a        31.85        31.17        42.48
2002                                         37.97       35.48       n/a        21.39        27.08        40.73
2003                                         39.32       37.55       n/a        32.14        34.36        44.23
2004 (e)                                     46.60       45.75       n/a        35.09        40.49        54.07

2005 Q1                                      45.25       45.25      22.00       33.25        38.50        52.50
2005 Q2                                      44.00       44.00      21.25       32.25        37.25        51.00
2005 Q3                                      43.25       43.25      21.75       31.75        36.75        50.25
2005 Q4                                      42.75       42.75      23.25       31.25        36.25        49.50

2005 Full
Year                                         43.75       43.75      22.00       32.25        37.25        50.75

2006                                         40.75       41.50      21.25       30.50        35.25        48.25
2007                                         38.00       39.50      20.50       29.00        33.75        46.00
2008                                         35.50       37.75      20.00       27.75        32.00        43.75
2009                                         32.75       35.50      20.00       26.00        30.25        41.25
2010                                         31.00       34.25      20.00       25.25        29.25        40.00
2011                                         30.50       34.25      20.00       25.25        29.25        40.00
2012                                         29.75       34.25      20.00       25.25        29.25        40.00
2013                                         29.75       34.75      20.25       25.50        29.50        40.50
2014                                         29.75       35.50      20.75       26.00        30.25        41.25
2015                                         29.50       36.00      21.00       26.50        30.50        41.75
2016+                                        29.50      +2.0%/yr               Escalate at 2.0% per year

</Table>

<Page>
                                    - 26 -

    The following table represents forecast prices for natural gas and sulphur
used in preparing reserves data by GLJ, the Corporation's independent qualified
reserves evaluator. This standard price forecast of GLJ is effective January 1,
2005:

                     GILBERT LAUSTSEN JUNG ASSOCIATES LTD.
                            NATURAL GAS AND SULPHUR
                                 PRICE FORECAST
                           EFFECTIVE JANUARY 1, 2005
<Table>
<Caption>
                                                                                              ALBERTA PLANT GATE
               US GULF COAST GAS PRICE                                     -------------------------------------------------------
                     @ HENRY HUB                                                   SPOT
             --------------------------   MIDWEST PRICE                   --------------------
              CONSTANT                      @ CHICAGO      AECO-C SPOT    CONSTANT     THEN
                2005      THEN CURRENT    THEN CURRENT    THEN CURRENT      2005      CURRENT       ARP      AGGREGATOR   ALLIANCE
YEAR          $US/MMBTU     $US/MMBTU       $US/MMBTU      $CDN/MMBTU     $/MMBTU     $/MMBTU     $/MMBTU     $/MMBTU      $/MMBTU
----         -----------  -------------   -------------   -------------   --------   ---------   ---------   ----------   --------
<S>          <C>          <C>             <C>             <C>             <C>        <C>         <C>         <C>          <C>
1994          2.37           1.94            2.11            1.98          2.27        1.86        1.81        n/a           n/a
1995          2.07           1.70            1.69            1.15          1.24        1.02        1.31        n/a           n/a
1996          3.01           2.52            2.73            1.39          1.50        1.26        1.63        n/a           n/a
1997          2.90           2.47            2.75            1.84          1.99        1.69        1.96        n/a           n/a
1998          2.50           2.16            2.20            2.03          2.18        1.88        1.94        n/a           n/a
1999          2.66           2.32            2.34            2.92          3.15        2.75        2.48        n/a           n/a
2000          4.88           4.33            4.38            5.08          5.55        4.92        4.50       4.60           n/a
2001          4.45           4.05            4.17            6.21          6.66        6.07        5.41       5.30          5.61
2002          3.60           3.36            3.30            4.04          4.15        3.88        3.88       3.83          3.82
2003          5.75           5.50            5.60            6.66          6.80        6.49        6.13       5.89          6.69
2004 (e)      6.30           6.19            6.13            6.88          6.81        6.69        6.33       6.19          6.45

2005 Q1       6.15           6.15            6.25            6.60          6.35        6.35        6.35       6.25          6.15
2005 Q2       6.00           6.00            6.05            6.30          6.10        6.10        6.05       5.95          5.95
2005 Q3       6.15           6.15            6.20            6.50          6.25        6.25        6.25       6.15          6.10
2005 Q4       6.50           6.50            6.60            6.90          6.65        6.65        6.60       6.50          6.60

2005 Full
Year          6.20           6.20            6.30            6.60          6.35        6.35        6.30       6.20          6.20

2006          5.90           6.00            6.10            6.35          6.00        6.10        6.10       6.00          6.00
2007          5.55           5.75            5.90            6.15          5.65        5.90        5.90       5.90          5.80
2008          5.20           5.50            5.65            6.00          5.40        5.75        5.75       5.75          5.50
2009          5.10           5.50            5.65            6.00          5.30        5.75        5.75       5.75          5.50
2010          5.00           5.50            5.65            6.00          5.20        5.75        5.75       5.75          5.50
2011          4.90           5.50            5.65            6.00          5.10        5.75        5.75       5.75          5.50
2012          4.80           5.50            5.65            6.00          5.00        5.75        5.75       5.75          5.50
2013          4.75           5.60            5.75            6.10          5.00        5.85        5.85       5.85          5.60
2014          4.75           5.65            5.95            6.20          4.95        5.95        5.95       5.95          5.80
2015          4.70           5.75            6.00            6.30          4.95        6.05        6.05       6.05          5.90
                                                                                                    Escalate at 2.0% per year
2016+         4.70         +2.0%/yr        +2.0%/yr        +2.0%/yr        4.95      +2.0%/yr

<Caption>
                                         SASKATCHEWAN PLANT GATE           BRITISH COLUMBIA
                                   ------------------------------------   -------------------                 ALBERTA
                                                                          CANWEST      SPOT      SULPHUR      SULPHUR
                                                              SUMAS        PLANT      PLANT        FOB        AT PLANT
                                   SASKENERGY      SPOT        SPOT         GATE      GATE      VANCOUVER       GATE
YEAR                                 $/MMBTU     $/MMBTU     $US/MMBTU    $/MMBTU    $/MMBTU      $US/LT      $CDN/LT
----                               -----------   --------   -----------   --------   --------   ----------   ----------
<S>                                <C>           <C>        <C>           <C>        <C>        <C>          <C>
1994                               1.88          1.88       1.59          1.81       1.87       44.96        16.57
1995                               1.35          0.98       1.03          1.29       1.12       54.99        30.07
1996                               1.52          1.28       1.32          1.50       1.47       36.28        14.44
1997                               1.84          1.75       1.70          1.80       1.98       34.75        11.50
1998                               2.05          2.13       1.60          1.94       2.00       24.59        -6.51
1999                               2.83          2.97       2.15          2.51       2.78       33.74         6.93
2000                               4.79          5.13       4.17          5.27       4.88       38.14        13.59
2001                               5.71          6.13       4.56          6.76       6.29       18.29       -14.66
2002                               4.04          4.08       2.68          3.64       3.93       29.38         3.04
2003                               6.40          6.68       4.66          5.71       6.32       59.81        39.83
2004 (e)                           6.59          6.78       5.26          5.54       6.44       62.99        38.75

2005 Q1                            6.50          6.50       5.50          5.30       6.25       63.50        34.00
2005 Q2                            6.20          6.20       5.30          5.05       6.00       63.50        34.00
2005 Q3                            6.40          6.40       5.45          5.20       6.15       63.50        34.00
2005 Q4                            6.75          6.80       5.95          5.50       6.75       63.50        34.00

2005 Full
Year                               6.45          6.50       5.55          5.25       6.30       63.50        34.00

2006                               6.25          6.25       5.40          5.90       6.10       55.00        23.50
2007                               6.05          6.05       5.25          5.90       5.90       45.00        11.50
2008                               5.90          5.90       5.10          5.75       5.75       45.00        11.50
2009                               5.90          5.90       5.10          5.75       5.75       46.00        12.50
2010                               5.90          5.90       5.10          5.75       5.75       47.00        14.00
2011                               5.90          5.90       5.10          5.75       5.75       48.00        15.00
2012                               5.90          5.90       5.10          5.75       5.75       49.00        16.50
2013                               6.00          6.00       5.15          5.85       5.85       50.00        17.50
2014                                .10          3.10       5.25          5.95       5.95       51.00        19.00
2015                               6.20          6.20       5.35          6.05       6.05       52.00        20.00

2016+                                                           Escalate at 2.0% per year             +2.0%/yr
</Table>

    Unless otherwise stated, the gas price reference point is the receipt point
on the applicable provincial gas transmission system known as the plant gate.
The plant gate price represents the price before raw gas gathering and
processing charges are deducted. Spot refers to weighted average one month
price.
<Page>
                                       - 27 -

RESERVES RECONCILIATION

    The following table provides a reconciliation of the Corporation's net
reserves based on forecast pricing, by principal product type, between this
analysis and the Corporation's prior year-end evaluation:

<Table>
<Caption>
                                               LIGHT AND MEDIUM OIL               UNCONVENTIONAL GAS (CBM)
                                        ----------------------------------   ----------------------------------
                                                                NET PROVED                           NET PROVED
                                                       NET         PLUS                     NET         PLUS
                                        NET PROVED   PROBABLE    PROBABLE    NET PROVED   PROBABLE    PROBABLE
FACTORS                                   (MBBL)      (MBBL)      (MBBL)       (MMCF)      (MMCF)      (MMCF)
-------                                 ----------   --------   ----------   ----------   --------   ----------
<S>                                     <C>          <C>        <C>          <C>          <C>        <C>
December 31, 2003                           925        634         1,559          0           0            0

Extensions                                    0          0             0        831         893        1,724
Improved Recovery                             0         13            13                      0
Technical Revisions                         -90         -8           -98          0           0            0
Discoveries                                  33         13            46                      0
Acquisitions                                  0          0             0                      0
Dispositions                                            -1            -1                      0
Economic Factors                             10          4            14                      0
Production                                 -170                     -170         -7           0           -7

December 31, 2004                           708        655         1,363        824         893        1,717

<Caption>
                                             CONVENTIONAL NATURAL GAS
                                        ----------------------------------
                                                                NET PROVED
                                                       NET         PLUS
                                        NET PROVED   PROBABLE    PROBABLE
FACTORS                                   (MMCF)      (MMCF)      (MMCF)
-------                                 ----------   --------   ----------
<S>                                     <C>          <C>        <C>
December 31, 2003                         13,906       5,611      19,517

Extensions                                   573         183         756
Improved Recovery                            560         120         680
Technical Revisions                        1,835        -802       1,033
Discoveries                                2,707         765       3,472
Acquisitions                                   0           0           0
Dispositions                                -187        -369        -556
Economic Factors                             214          80         294
Production                                -3,558                  -3,558

December 31, 2004                         16,050       5,588      21,638
</Table>

    The Corporation has no unconventional reserves (Bitumen, Synthetic Crude
Oil, Natural Gas from Coal, etc.).
<Page>
                                       - 28 -

FUTURE NET REVENUE RECONCILIATION

    The following table provides a reconciliation of the changes in the net
present values of future net revenue based on constant prices and costs,
calculated using a discount rate of 10 percent:

<Table>
<Caption>
                                                              AFTER TAX 2004   BEFORE TAX 2004
PERIOD AND FACTOR                                                  (M$)             (M$)
-----------------                                             --------------   ---------------
<S>                                                           <C>              <C>
Estimated Net Present Value at December 31, 2004                  60,694            62,417

  Oil and Gas Sales During the Period Net of Production
    Costs and Royalties(1)                                       (28,767)          (28,767)
  Changes due to Prices, Production Costs and Royalties
    Related to Forecast Production(2)                             10,614            10,614
  Development Costs During the Period(3)                           1,848             1,848
  Changes In Forecast Development Costs(4)                          (472)             (472)
  Changes Resulting from Extensions and Improved Recovery(5)      13,027            13,027
  Changes Resulting from Discoveries(5)                            1,080             1,080
  Changes Resulting from Acquisitions of Reserves(5)                  --                --
  Changes Resulting from Dispositions of Reserves(5)                (565)             (565)
  Accretion of Discount(6)                                         6,242             6,242
  Net Change in Income Taxes(7)                                     (654)               --
  Changes Resulting from Technical Reserves Revisions              6,001             6,001
  All Other Changes(8)                                             5,115             5,115

Estimated Net Present Value as at December 31, 2004               74,162            76,539
</Table>

------------

Notes:

(1) Company actual before income taxes, excluding G&A.

(2) The impact of changes in prices and other economic factors on future net
    revenue.

(3) Actual capital expenditures relating to the exploration, development and
    production of oil and gas reserves. (4) The change in forecast development
    costs for the properties evaluated at the beginning of the period. (5) End
    of period net present value of the related reserves. (6) Estimated as 10% of
    the beginning of period net present value.

(4) The change in forecast development costs for the properties evaluated at the
    beginning of the period.

(5) End of period net present value of the related reserves.

(6) Estimated as 10% of the beginning of period net present value.

(7) The difference between forecast income taxes at beginning of period and the
    actual taxes for the period plus forecast income taxes at the end of period.

(8) Includes changes due to revised production profiles, development timing,
    operating costs, rates, actual price received in 2004 versus forecast, etc.
<Page>
                                       - 29 -

UNDEVELOPED RESERVES

    Proved and probable undeveloped reserves have been estimated in accordance
with procedures and standards contained in the COGE Handbook. The significant
majority of the undeveloped reserves are scheduled to be developed within the
next two years of the effective date, that is December 31, 2004.

SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA

    The evaluated oil and gas properties of the Corporation have no material
extraordinary risks or uncertainties beyond those which are inherent of an oil
and gas producing company.

FUTURE DEVELOPMENT COSTS

    The following table summarizes the capital development costs, in thousands
of dollars, related to the recovery of the Corporation's reserves, based on
constant pricing:
<Table>
<Caption>

                           2005       2006       2007       2008       2009       2010       2011       2012       2013
                         --------   --------   --------   --------   --------   --------   --------   --------   --------
<S>                      <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>
Proved Producing            360         30         0          0          0         0          0           0         0
Total Proved              1,415      2,209         0          0          0         0          0           9         0
Total Proved Plus
  Probable                1,893      5,811       368        414        150         0          0         159         0

<Caption>
                                                                                                   10%
                           2014       2015       2016     SUBTOTAL     REMAINDER     TOTAL      DISCOUNTED
                         --------   --------   --------   ---------   -----------   --------   ------------
<S>                      <C>        <C>        <C>        <C>         <C>           <C>        <C>
Proved Producing            0          0          0           390          0           390          369
Total Proved                0          0          0         3,633          0         3,633        3,268
Total Proved Plus
  Probable                  0          0                    8,795          0         8,795        7,604
</Table>

    The following table summarizes the capital development costs, in thousands
of dollars, related to the recovery of the Corporation's reserves, based on
forecast pricing and escalating cost:
<Table>
<Caption>
                           2005       2006       2007       2008       2009       2010       2011       2012       2013
                         --------   --------   --------   --------   --------   --------   --------   --------   --------
<S>                      <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>
Proved Producing            360          0         0          0          0         0          0           0         0
Total Proved              1,415      2,222         0          0          0         0          0          10         0
Total Proved Plus
  Probable                1,893      5,897       383        439        162         0          0         183         0

<Caption>
                                                                                                   10%
                           2014       2015       2016     SUBTOTAL     REMAINDER     TOTAL      DISCOUNTED
                         --------   --------   --------   ---------   -----------   --------   ------------
<S>                      <C>        <C>        <C>        <C>         <C>           <C>        <C>
Proved Producing            0                     0           360          0           360          343
Total Proved                0          0          0         3,647          0         3,647        3,280
Total Proved Plus
  Probable                  0          0          0         8,957          0         8,957        7,728
</Table>

<Page>
                                       - 30 -

OIL AND GAS PROPERTIES AND WELLS

    The following table, as prepared by the Corporation, sets forth Canadian
Superior's gross and net interest in oil and gas wells which are producing as at
December 31, 2004:

<Table>
<Caption>
                                                            PRODUCING                                    SHUT-IN
                                            -----------------------------------------   -----------------------------------------
                                                    OIL                   GAS                   OIL                   GAS
                                            -------------------   -------------------   -------------------   -------------------
                                             GROSS       NET       GROSS       NET       GROSS       NET       GROSS       NET
                                            --------   --------   --------   --------   --------   --------   --------   --------
<S>                                         <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>
Alberta                                        64         44        162         90         22        14.4        39        23.2
Saskatchewan                                    0          0          0          0          0           0         2           2
British Columbia                                0          0          0          0          0           0         0           0
TOTAL                                          64         44        162         90         22        14.4        41        25.2
</Table>

------------

Notes:

(1) "Gross" wells are defined as the total number of wells in which the
    Corporation has an interest.

(2) "Net" wells are defined as the aggregate of the numbers obtained by
    multiplying each gross well by the Corporation's percentage working or
    participating interest therein.

PROPERTIES WITH NO ATTRIBUTED RESERVES

    The following table represents the Corporation's undeveloped land holdings,
as at December 31, 2004:

<Table>
<Caption>
                                                              GROSS ACRES     NET ACRES     AVERAGE WI
                                                              ------------   ------------   ----------
<S>                                                           <C>            <C>            <C>
Alberta                                                         157,403.57     135,488.33       86
British Columbia                                                 13,213.98       9,997.37       76
Saskatchewan                                                        360.02         360.02      100
Offshore Nova Scotia                                             1,293,946      1,293,946      100
TOTAL                                                         1,464,923.57   1,439,791.72       98
</Table>

------------

Notes:

(1) "Gross" refers to the total acres in which the Corporation has or may earn
    an interest.

(2) "Net" refers to the total acres in which the Corporation has an interest or
    may earn an interest, multiplied by the percentage working interest therein
    owned or to be owned by the Corporation.
<Page>
                                       - 31 -

EXPIRATIONS AND WORK COMMITMENTS

    The following table sets forth the expirations and work commitment for the
undeveloped lands of the Corporation, as at December 31, 2004:

WORK COMMITMENTS OFFSHORE NOVA SCOTIA
(MARQUIS, MARINER, MAYFLOWER, MARAUDER, MARCONI)

<Table>
<S>                                                           <C>
Gross Acres                                                   1,293,946
Net Acres                                                     1,293,946
Work Expenditure Commitment                                   $98,567,800 (initial);
                                                              $57,877,403.68 (remaining)
Deposits Tendered                                             $24,641,950 (initial);
                                                              $14,469,350.97,
                                                              and a current receivable of $531,742.82
</Table>

UNDEVELOPED LAND DUE TO EXPIRE

    The following table represents the undeveloped land of the Corporation due
to expire in 2005:

<Table>
<Caption>
                                                              GROSS UNDEVELOPED   NET UNDEVELOPED
                                                              -----------------   ---------------
<S>                                                           <C>                 <C>
Alberta                                                            34,876             29,988
British Columbia                                                    4,083              3,041
Saskatchewan                                                            0                  0
Offshore Nova Scotia                                                    0                  0
TOTAL                                                              38,959             33,029
</Table>

FORWARD CONTRACTS AND FUTURE COMMITMENTS

    The Corporation enters into commodity sales agreements and certain
derivative financial instruments to reduce its exposure to commodity price
volatility. These financial instruments are entered into solely for hedging
purposes and are not used for trading or other speculative purposes.

    At December 31, 2004, the Corporation had the following contracts in place:

<Table>
<Caption>
CONTACT                                                       VOLUME             PRICE                        TERM
-------                                                     ----------   ----------------------   ----------------------------
<S>                                                         <C>          <C>                      <C>
Natural Gas -- Fixed Price                                  1,000 gj/d          $9.37/gj (Aeco)   January 1 - March 31, 2005
Natural Gas -- Costless Collar                              1,000 gj/d   $7.00-$13.50/gj (Aeco)   January 1 - January 31, 2005
Crude Oil -- Fixed Price                                     100 bbl/d       $44.25 $US/bbl WTI   January 1 - January 31, 2005
</Table>

<Page>
                                       - 32 -

ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS

    The following table represents the Corporation's projected abandonment costs
for future drilling, in thousands of dollars, using constant pricing:
<Table>
<Caption>
                                                                          YEAR
                       -----------------------------------------------------------------------------------------------------------
ENTITY DESCRIPTION       2005       2006       2007       2008       2009       2010       2011       2012       2013       2014
------------------     --------   --------   --------   --------   --------   --------   --------   --------   --------   --------
<S>                    <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>
Proved Producing         199        185        196        119        130         94        131        143         78        153
Total Proved             199        185        216        119        176        100        164        182        106        167
Total Proved Plus
  Probable               179         85        134        214        128        163        102        107        156        217

<Caption>
                              YEAR                       TOTALS
                       -------------------   -------------------------------      10%
ENTITY DESCRIPTION       2015       2016     SUBTOTAL   REMAINDER    TOTAL     DISCOUNTED
------------------     --------   --------   --------   ---------   --------   ----------
<S>                    <C>        <C>        <C>        <C>         <C>        <C>
Proved Producing          83         58       1,569        337       1,906        1,081
Total Proved             117         69       1,800        391       2,192        1,217
Total Proved Plus
  Probable                92        175       1,752        701       2,453        1,177
</Table>

    The following table represents the Corporation's projected abandonment costs
for future drilling, in thousands of dollars, using forecast prices:
<Table>
<Caption>

ENTITY DESCRIPTION       2005       2006       2007       2008       2009       2010       2011       2012       2013       2014
------------------     --------   --------   --------   --------   --------   --------   --------   --------   --------   --------
<S>                    <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>
Proved Producing         257        141        212        124        135        109        175        138        120        187
Total Proved             257        141        232        124        184        116        211        206        130        215
Total Proved Plus
  Probable               257        117         33        283         94        229         95        150        275        185

<Caption>
                                                                                  10%
ENTITY DESCRIPTION       2015       2016     SUBTOTAL   REMAINDER    TOTAL     DISCOUNTED
------------------     --------   --------   --------   ---------   --------   ----------
<S>                    <C>        <C>        <C>        <C>         <C>        <C>
Proved Producing          93         39       1,729        472       2,201        1,200
Total Proved             129         46       1,993        541       2,534        1,358
Total Proved Plus
  Probable                83        202       2,003        958       2,961        1,372
</Table>

    The following table, as prepared by the Corporation, represents the
estimated costs with respect to abandonment and reclamation liability of
existing properties of Canadian Superior, in thousands of dollars:
<Table>
<Caption>
                         2005       2006       2007       2008       2009       2010       2011       2012       2013       2014
                       --------   --------   --------   --------   --------   --------   --------   --------   --------   --------
<S>                    <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>
Undiscounted              0          0        1,209       657         0        1,502        0          57         0          59
Discounted at 10%         0          0          867       429         0          815        0          24         0          21

<Caption>
                         2015       2016       2017     SUBTOTAL   REMAINDER    TOTAL
                       --------   --------   --------   --------   ---------   --------
<S>                    <C>        <C>        <C>        <C>        <C>         <C>
Undiscounted              15       8,502      2,195       5,234        0         5,234
Discounted at 10%          5       2,581        492      14,197        0        14,196
</Table>
<Page>

                                       - 33 -

TAX HORIZON

    The Corporation does not expect to be cash taxable in 2005.

COSTS INCURRED

    The following, as prepared by the Corporation, represents the costs
incurred, in thousands of dollars, in Canada by Canadian Superior before
property dispositions and corporate asset additions:

<Table>
<S>                                                           <C>
Property Acquisitions -- Proved Properties                      1,070
Property Acquisitions -- Unproved Properties                    2,573
Exploration Costs                                              25,211
Development Costs                                              13,367
</Table>

EXPLORATION AND DEVELOPMENT ACTIVITIES

    The following table sets forth the gross and net exploration and development
wells in which the Corporation participated during the year ended December 31,
2004:

<Table>
<Caption>
                                                                  DEVELOPMENT           EXPLORATION
                                                                     WELLS                 WELLS              TOTAL WELLS
                                                              -------------------   -------------------   -------------------
                                                               GROSS       NET       GROSS       NET       GROSS       NET
                                                              --------   --------   --------   --------   --------   --------
<S>                                                           <C>        <C>        <C>        <C>        <C>        <C>
Oil Wells                                                        2            2         3        2.23         5        4.23
Natural Gas Wells                                                7         1.75        21       13.91        28       15.66
Service Wells                                                    0            0         2           2         2           2
Dry Holes                                                        0            0         3        2.93         3        2.93
Total                                                            9         3.75        29       21.07        38       24.82
</Table>

    The following operations strategies build on and augment the efforts of the
Corporation in 2004:

1.  Continue to grow Western Canadian cash flow and production, focusing on the
    Drumheller area and high impact Western Canadian plays;

2.  Maintain high interest operational positions and a strong balance sheet;

3.  Continue forward with drilling and development of the Corporation's Offshore
    Nova Scotia and Offshore Trinidad and Tobago assets; and

4.  Continue to focus on increasing the underlying value for shareholders
    through strategic drilling, development and acquisitions.
<Page>
                                       - 34 -

PRODUCTION ESTIMATES

    The following table represents a forecast, using constant pricing, of first
year production by product type:

<Table>
<Caption>
                                                            2005 AVERAGE DAILY PRODUCTION
                                        ----------------------------------------------------------------------
                                         LIGHT AND                                    NATURAL         OIL
                                         MEDIUM OIL    HEAVY OIL     NATURAL GAS    GAS LIQUIDS    EQUIVALENT
                                        ------------  ------------  --------------  ------------  ------------
                                        W.I.    NET   W.I.    NET    W.I.    NET    W.I.    NET   W.I.    NET
ENTITY DESCRIPTION                      BBL/D  BBL/D  BBL/D  BBL/D  MCF/D   MCF/D   BBL/D  BBL/D  BBL/D  BBL/D
------------------                      -----  -----  -----  -----  ------  ------  -----  -----  -----  -----
<S>                                     <C>    <C>    <C>    <C>    <C>     <C>     <C>    <C>    <C>    <C>
PROVED PRODUCING
Craigmyle-Chain                           62     56      0      0    2,832   2,195     5     3      539    425
Drumheller                               299    269      0      0    1,887   1,504    25    18      638    538
Other Properties                          93     84      0      0    6,216   4,855    70    48    1,200    940
ARTC/AGCA Adjustments                      0      0      0      0        0       0     0     0        0      0
                                         ---    ---     --     --   ------  ------   ---    --    -----  -----
TOTAL: PROVED PRODUCING                  454    408      0      0   10,935   8,554   100    69    2,377  1,903

TOTAL PROVED
Craigmyle-Chain                           62     56      0      0    4,127   3,104    33    22      783    595
Drumheller                               299    269      0      0    1,887   1,504    25    18      638    538
Other Properties                          93     84      0      0    6,552   5,131    72    49    1,257    988
ARTC/AGCA Adjustments                      0      0      0      0        0       0     0     0        0      0
                                         ---    ---     --     --   ------  ------   ---    --    -----  -----
TOTAL: TOTAL PROVED                      454    408      0      0   12,565   9,740   130    89    2,678  2,121

TOTAL PROVED PLUS PROBABLE
Craigmyle-Chain                           67     60      0      0    4,361   3,264    36    24      830    628
Drumheller                               301    269      0      0    1,902   1,517    26    18      643    540
Other Properties                         104     93      0      0    7,084   5,525    77    52    1,361  1,066
ARTC/AGCA Adjustments                      0      0      0      0        0       0     0     0        0      0
                                         ---    ---     --     --   ------  ------   ---    --    -----  -----
TOTAL: TOTAL PROVED PLUS PROBABLE        472    422      0      0   13,347  10,305   138    95    2,834  2,234
</Table>

<Table>
<Caption>
                                                                      RESERVES
                                        --------------------------------------------------------------------
                                         LIGHT AND                                NATURAL GAS       OIL
                                         MEDIUM OIL   HEAVY OIL    NATURAL GAS      LIQUIDS      EQUIVALENT
                                        ------------  ----------  --------------  ------------  ------------
                                        W.I.    NET   W.I.  NET    W.I.    NET    W.I.    NET   W.I.    NET
ENTITY DESCRIPTION                      MBBL   MBBL   MBBL  MBBL   MMCF    MMCF   MBBL   MBBL   MBBL   MBBL
------------------                      -----  -----  ----  ----  ------  ------  -----  -----  -----  -----
<S>                                     <C>    <C>    <C>   <C>   <C>     <C>     <C>    <C>    <C>    <C>
PROVED PRODUCING
Craigmyle-Chain                           134    126    0     0    4.848   3,979     8      5     950    795
Drumheller                                575    525    0     0     3836   3,273    63     49   1,277  1,120
Other Properties                           97     90    0     0    8,613   7,128    99     67   1,631  1,345
ARTC/AGCA Adjustments                       0      0    0     0        0       0     0      0       0
                                        -----  -----   --    --   ------  ------   ---    ---   -----  -----
TOTAL: PROVED PRODUCING                   805    741    0     0   17,297  14,380   170    121   3,858  3,259

TOTAL PROVED
Craigmyle-Chain                           134    126    0     0    5,669   4,574    23     15   1,102    904
Drumheller                                575    525    0     0    3,836   3,273    63     49   1,277  1,120
Other Properties                           97     90    0     0   11,170   9,249   106     72   2,064  1,703
ARTC/AGCA Adjustments                       0      0    0     0        0       0     0      0       0      0
                                        -----  -----   --    --   ------  ------   ---    ---   -----  -----
TOTAL: TOTAL PROVED                       805    741    0     0   20,675  17,097   192    136   4,443  3,726

TOTAL PROVED PLUS PROBABLE
Craigmyle-Chain                           179    169    0     0    6,958   5,606    30     20   1,368  1,123
Drumheller                              1,250  1,094    0     0    5,056   4,207    89     68   2,182  1,863
Other Properties                          145    135    0     0   17,189  14,080   164    111   3,174  2,593
ARTC/AGCA Adjustments                       0      0    0     0        0       0     0      0       0      0
                                        -----  -----   --    --   ------  ------   ---    ---   -----  -----
TOTAL: TOTAL PROVED PLUS PROBABLE       1,574  1,399    0     0   29,203  23,893   283    199   6,724  5,579
</Table>

<Page>
                                       - 35 -

    The following table represents a forecast, using forecast pricing, of first
year production by product type:

<Table>
<Caption>
                                                            2005 AVERAGE DAILY PRODUCTION
                                        ----------------------------------------------------------------------
                                         LIGHT AND                                    NATURAL         OIL
                                         MEDIUM OIL    HEAVY OIL     NATURAL GAS    GAS LIQUIDS    EQUIVALENT
                                        ------------  ------------  --------------  ------------  ------------
                                        W.I.    NET   W.I.    NET    W.I.    NET    W.I.    NET   W.I.    NET
ENTITY DESCRIPTION                      BBL/D  BBL/D  BBL/D  BBL/D  MCF/D   MCF/D   BBL/D  BBL/D  BBL/D  BBL/D
------------------                      -----  -----  -----  -----  ------  ------  -----  -----  -----  -----
<S>                                     <C>    <C>    <C>    <C>    <C>     <C>     <C>    <C>    <C>    <C>
PROVED PRODUCING
Craigmyle-Chain                           62     56      0      0    2,832   2,195     5     3      539    425
Drumheller                               299    269      0      0    1,887   1,504    25    18      638    538
Other Properties                          93     84      0      0    6,216   4,855    70    48    1,200    940
ARTC/AGCA Adjustments                      0      0      0      0        0       0     0     0        0      0
                                         ---    ---     --     --   ------  ------   ---    --    -----  -----
TOTAL: PROVED PRODUCING                  454    408      0      0   10,935   8,554   100    69    2,377  1,903

TOTAL PROVED
Craigmyle-Chain                           62     56      0      0    4,127   3,104    33    22      783    595
Drumheller                               299    269      0      0    1,887   1,504    25    18      638    538
Other Properties                          93     84      0      0    6,552   5,131    72    49    1,257    988
ARTC/AGCA Adjustments                      0      0      0      0        0       0     0     0        0      0
                                         ---    ---     --     --   ------  ------   ---    --    -----  -----
TOTAL: TOTAL PROVED                      454    408      0      0   12,565   9,740   130    56    2,678  2,121

TOTAL PROVED PLUS PROBABLE
Craigmyle-Chain                           67     60      0      0    4,361   3,264    36    24      830    628
Drumheller                               301    269      0      0    1,902   1,517    26    18      643    540
Other Properties                         104     93      0      0    7,084   5,525    77    52    1,361  1,066
ARTC/AGCA Adjustments                      0      0      0      0        0       0     0     0        0      0
                                         ---    ---     --     --   ------  ------   ---    --    -----  -----
TOTAL: TOTAL PROVED PLUS PROBABLE        472    422      0      0   13,347  10,305   138    94    2,834  2,234
</Table>

<Table>
<Caption>
                                                                      RESERVES
                                        --------------------------------------------------------------------
                                         LIGHT AND                                NATURAL GAS       OIL
                                         MEDIUM OIL   HEAVY OIL    NATURAL GAS      LIQUIDS      EQUIVALENT
                                        ------------  ----------  --------------  ------------  ------------
                                        W.I.    NET   W.I.  NET    W.I.    NET    W.I.    NET   W.I.    NET
ENTITY DESCRIPTION                      MBBL   MBBL   MBBL  MBBL   MMCF    MMCF   MBBL   MBBL   MBBL   MBBL
------------------                      -----  -----  ----  ----  ------  ------  -----  -----  -----  -----
<S>                                     <C>    <C>    <C>   <C>   <C>     <C>     <C>    <C>    <C>    <C>
PROVED PRODUCING
Craigmyle-Chain                          134     127    0     0    4,759   3,902     8      5     935    782
Drumheller                               538     492    0     0    3,784   3,236    61     48   1,230  1,080
Other Properties                          96      89    0     0    8,501   7,029    98     67   1,611  1,327
ARTC/AGCA Adjustments                      0       0    0     0        0       0     0      0       0      0
                                        -----  -----   --    --   ------  ------   ---    ---   -----  -----
TOTAL: PROVED PRODUCING                  768     708    0     0   17,043  14,167   167    120   3,776  3,189

TOTAL PROVED
Craigmyle-Chain                          134     127    0     0    5,580   4,498    23     15   1,087    891
Drumheller                               538     492    0     0    3,784   3,236    61     48   1,230  1,080
Other Properties                          96      89    0     0   11,044   9,139   104     71   2,041  1,683
ARTC/AGCA Adjustments                      0       0    0     0        0       0     0      0       0      0
                                        -----  -----   --    --   ------  ------   ---    ---   -----  -----
TOTAL: TOTAL PROVED                      768     708    0     0   20,408  16,873   189    134   4,358  3,654

TOTAL PROVED PLUS PROBABLE
Craigmyle-Chain                          179     169    0     0    6,836   5,501    29     19   1,348  1,106
Drumheller                              1,207  1,059    9     9    4,982   4,155    87     67   2,125  1,818
Other Properties                         145     135    0     0   16,757  13,699   160    109   3,098  2,527
ARTC/AGCA Adjustments                      0       0    0     0        0       0     0      0       0      0
                                        -----  -----   --    --   ------  ------   ---    ---   -----  -----
TOTAL: TOTAL PROVED PLUS PROBABLE       1,531  1,363    0     0   28,575  23,355   277    195   6,570  5,451
</Table>
<Page>

                                       36

                                  RISK FACTORS

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

EXPLORATION, DEVELOPMENT AND PRODUCTION RISKS

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

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

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

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

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

SUBSTANTIAL CAPITAL REQUIREMENTS AND LIQUIDITY

The Corporation anticipates that it will make substantial capital expenditures
for the acquisition, exploration, development and production of oil and natural
gas reserves in the future. If the Corporation's revenues or reserves decline,
the Corporation may have limited ability to expend the capital necessary to
undertake or complete future drilling programs. There can be no assurance that
debt or equity financing, or cash generated by operations will be available or
sufficient to meet these requirements or for other corporate purposes or, if
debt or equity financing is available, that it will be on terms acceptable to
the Corporation. Moreover, future activities may require the Corporation to
alter its capitalization significantly. The inability of the Corporation to
access sufficient capital for its operations could have a material adverse
effect on the Corporation's financial condition, results of operations or
prospects.


<Page>


                                       37

ADDITIONAL FUNDING REQUIREMENTS

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

ISSUANCE OF DEBT

From time to time the Corporation may enter into transactions to acquire assets
or the shares of other corporations. These transactions may be financed
partially or wholly with debt, which may increase the Corporation's debt levels
above industry standards. Neither the Corporation's articles nor its by-laws
limit the amount of indebtedness that the Corporation may incur. The level of
the Corporation's indebtedness from time to time could impair the Corporation's
ability to obtain additional financing in the future on a timely basis to take
advantage of business opportunities that may arise.

PRICES, MARKETS AND MARKETING OF CRUDE OIL AND NATURAL GAS

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

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

INSURANCE

The Corporation's involvement in the exploration for and development of oil and
natural gas properties may result in the Corporation becoming subject to
liability for pollution, blow-outs, property damage, personal injury or other
hazards. Although the Corporation has obtained insurance in accordance with
industry standards to address such risks, such insurance has limitations on
liability that may not be sufficient to cover the full extent of such
liabilities. In addition, such risks may not, in all circumstances be insurable
or, in


<Page>


                                       38

certain circumstances, the Corporation may elect not to obtain insurance to deal
with specific risks due to the high premiums associated with such insurance or
other reasons. The payment of such uninsured liabilities would reduce the funds
available to the Corporation. The occurrence of a significant event that the
Corporation is not fully insured against, or the insolvency of the insurer of
such event, could have a material adverse effect on the Corporation's financial
position, results of operations or prospects.

LEGAL PROCEEDINGS

The Corporation, and certain of our directors and officers, have been named as
defendants in various class action lawsuits. In addition certain of our
directors and officers are plaintiffs in litigation actions. Litigation may be
time consuming, expensive, and distracting from the conduct of our business, and
the outcome of litigation may be difficult to predict. The Corporation is unable
to determine the ultimate aggregate amount of monetary liability or financial
impact in these legal matters, which unless otherwise specified, seek damages of
indeterminate amounts. The Corporation cannot determine whether these matters
will, individually or collectively, have a material adverse effect on our
business, results or operations and financial condition. To the extent expenses
incurred in connection with litigation or any potential regulatory proceeding or
action (which may include substantial fees of attorneys and other professional
advisors and potential obligations to indemnify officers and directors who may
be parties to such actions) are not covered by available insurance, such
expenses could adversely affect our cash position. The Corporation, and any of
our named directors or officers, intend to vigorously defend these actions
suits, claims, proceedings and investigations. The Corporation may in the future
be subject to other litigation arising in the normal course of our business.

ENVIRONMENTAL RISKS

All phases of the oil and natural gas business present environmental risks and
hazards and are subject to environmental regulation pursuant to a variety of
international conventions and national, provincial and municipal laws and
regulations. Environmental legislation provides for, among other things,
restrictions and prohibitions on spills, releases or emissions of various
substances produced in association with oil and gas operations. The legislation
also requires that wells and facility sites be operated, maintained, abandoned
and reclaimed to the satisfaction of applicable regulatory authorities.
Compliance with such legislation can require significant expenditures and a
breach may result in the imposition of fines and penalties, some of which may be
material. The Corporation believes that it is in substantial compliance with
existing legislation. Environmental legislation is evolving in a manner expected
to result in stricter standards and enforcement, larger fines and liability and
potentially increased capital expenditures and operating costs. The discharge of
oil, natural gas or other pollutants into the air, soil or water may give rise
to liabilities to governments and third parties and may require the Corporation
to incur costs to remedy such discharge. No assurance can be given that
environmental laws will not result in a curtailment of production or a material
increase in the costs of production, development or exploration activities or
otherwise adversely affect the Corporation's financial condition, results of
operations or prospects.

COMPETITION

The Corporation actively competes for reserve acquisitions, exploration leases,
licences and concessions and skilled industry personnel with a substantial
number of other oil and gas companies, many of which have significantly greater
financial resources than the Corporation. The Corporation's competitors include
major integrated oil and natural gas companies and numerous other independent
oil and natural gas companies and individual producers and operators.

The oil and gas industry is highly competitive. The Corporation's competitors
for the acquisition, exploration, production and development of oil and natural
gas properties, and for capital to finance such activities, include companies
that have greater financial and personnel resources available to them than the
Corporation.


<Page>


                                       39

Certain of the Corporation's customers and potential customers are themselves
exploring for oil and gas, and the results of such exploration efforts could
affect the Corporation's ability to sell or supply oil or gas to these customers
in the future. The Corporation's ability to successfully bid on and acquire
additional property rights, to discover reserves, to participate in drilling
opportunities and to identify and enter into commercial arrangements with
customers will be dependent upon developing and maintaining close working
relationships with its future industry partners and joint operators and its
ability to select and evaluate suitable properties and to consummate
transactions in a highly competitive environment.

RESERVE REPLACEMENT

The Corporation's future oil and natural gas reserves, production, and cash
flows to be derived therefrom are highly dependent on the Corporation
successfully acquiring or discovering new reserves. Without the continual
addition of new reserves, any existing reserves the Corporation may have at any
particular time and the production therefrom will decline over time as such
existing reserves are exploited. A future increase in the Corporation's reserves
will depend not only on the Corporation's ability to develop any properties it
may have from time to time, but also on its ability to select and acquire
suitable producing properties or prospects. There can be no assurance that the
Corporation's future exploration and development efforts will result in the
discovery and development of additional commercial accumulations of oil and
natural gas.

RELIANCE ON OPERATORS AND KEY EMPLOYEES

To the extent the Corporation is not the operator of its oil and natural gas
properties, the Corporation will be dependent on such operators for the timing
of activities related to such properties and will largely be unable to direct or
control the activities of the operators. In addition, the success of the
Corporation will be largely dependent upon the performance of its management and
key employees. The Corporation has no key-man insurance policies, and therefore
there is a risk that the death or departure of any member of management or any
key employee could have a material adverse effect on the Corporation.

PERMITS AND LICENSES

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

ROYALTIES, INCENTIVES AND PRODUCTION TAXES

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

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

Oil and natural gas royalty holidays and reductions for specific wells reduce
the amount of Crown royalties paid by the Corporation to the provincial
governments. In Alberta, the Alberta Royalty Tax Credit program provides a
rebate on Alberta Crown royalties paid in respect of eligible producing
properties. Both of these incentives have the effect of increasing the net
income of the Corporation.


<Page>


                                       40

Producers of oil and natural gas in the Province of British Columbia are also
required to pay annual rental payments in respect of Crown leases and royalties
and freehold production taxes in respect of oil and gas produced from Crown and
freehold lands, respectively. The amount payable as a royalty in respect of oil
depends on the vintage of the oil (whether it was produced from a pool
discovered before or after October 31, 1975), the quantity of oil produced in a
month and the value of the oil. In specific circumstances, oil produced from
newly discovered pools may be exempt from the payment of a royalty for the first
36 months of production.

LAND TENURE

Crude oil and natural gas located in the western provinces is owned
predominantly by the respective provincial governments. Provincial governments
grant rights to explore for and produce oil and natural gas pursuant to leases,
licences and permits for varying terms and on conditions set forth in provincial
legislation including requirements to perform specific work or make payments.
Oil and natural gas located in such provinces can also be privately owned and
rights to explore for and produce such oil and natural gas are granted by lease
on such terms and conditions as may be negotiated.

TITLE TO PROPERTIES

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

Although title reviews were conducted prior to the purchase of the El Paso
Properties and may be conducted prior to the purchase of other oil and natural
gas producing properties or the commencement of drilling wells, such reviews may
not discover unforeseen title defects that could adversely affect the
Corporation's title to or proportionate interest in the property or entitlement
to revenue from the property.

CORPORATE MATTERS

To date, the Corporation has not declared any dividends payable on its
outstanding common shares. The Board of Directors of the Corporation will
consider the Corporation's dividend policy from time to time to assess whether
the declaration of dividends payable on its outstanding common shares is
appropriate. Certain of the directors and officers of the Corporation are also
directors and officers of other oil and gas companies involved in natural
resource exploration and development, and conflicts of interest may arise
between their duties as officers and directors of the Corporation and as
officers and directors of such other companies. Such conflicts must be disclosed
in accordance with, and are subject to such other procedures and remedies as
apply under the BUSINESS CORPORATIONS ACT (Alberta).

                                    DIVIDENDS

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

                        DESCRIPTION OF CAPITAL STRUCTURE

The Corporation's authorized share capital consists of an unlimited number of
common shares (the "Common Shares") and an unlimited number of first preferred
shares, issuable in series (the "Preferred Shares"). As at March 22, 2005,
109,858,183 Common Shares and Preferred Shares were outstanding.


<Page>


                                       41

COMMON SHARES

The Common Shares in the capital of the Corporation are entitled to notice of
and to vote at all meetings of shareholders (except meetings at which only
holders of a specified class or series of shares are entitled to vote) and are
entitled to one vote per share. The holders of common shares in the capital of
the Corporation are entitled to receive such dividends as the Board of Directors
may declare and, upon liquidation, to receive such assets of Canadian Superior
as are distributable to holders of common shares in the capital of the
Corporation.

PREFERRED SHARES

The Preferred Shares may be issued in one or more series with each series to
consist of such number of shares as may, before the issue of the series, be
fixed by the directors of the Corporation. The directors are authorized, before
the issue of the series, to determine the designation, rights, restrictions,
conditions and limitations attaching to the Preferred Shares of each series. The
Preferred Shares of each series rank equally with respect to the payment of
dividends and the distribution of assets in the event of liquidation,
dissolution or winding-up and in priority to the Common Shares and any other
shares of the Corporation ranking junior to the Preferred Shares. In addition,
if any amount of a fixed cumulative dividend or an amount payable on return of
capital in respect of shares of a series of Preferred Shares is not paid in
full, the shares of the series are entitled to participate rateably with the
shares of any other series of the same class in respect of such amounts.

SHAREHOLDER RIGHTS PLAN

The shareholders of the Corporation have adopted a shareholder rights plan (the
"Rights Plan"). The Rights Plan is contained in an agreement dated as of January
22, 2001, as amended and restated as of May 17, 2001, between the Corporation
and Computershare Trust Company of Canada (the "Rights Plan Agreement"). The
effective date of the Rights Plan was January 22, 2001 (the "Effective Date")
and it was amended and restated as of May 17, 2001. The Rights Plan continues in
effect until January 22, 2011, being ten years from its effective date.

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

Eight trading days after a Flip-in Event, each Right will permit the holder
(other than an Acquiring Person) to purchase from the Corporation, on payment of
the $15 exercise price, common shares in the capital of the Corporation with a
market value of $30. The result will be massive dilution of the holdings of the
Acquiring Person. The Corporation anticipates that no Acquiring Person will be
willing to risk such dilution and so will instead either make a take-over bid
that is permitted by the Rights Plan, negotiate with the Board of Directors for
a waiver of the Rights Plan, or apply to regulatory authorities for an order
rendering the Rights Plan ineffective.

A person will not become an Acquiring Person, and will not trigger the
separation and ability to exercise the Rights, by becoming the beneficial owner
of 20% or more of the common shares in the capital of the Corporation pursuant
to a take-over bid specifically permitted by the Rights Plan (a "Permitted Bid")
or in other circumstances provided for under the Rights Plan. Investment
advisors (for fully managed accounts), trust companies (acting in their
capacities as trustees and administrators) and statutory bodies acquiring 20%


<Page>


                                       42

of the common shares in the capital of the Corporation are exempted from
triggering a Flip-In Event, provided that they are not making, and are not part
of a group making, a take-over bid.

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

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

                              MARKET FOR SECURITIES

TRADING PRICE AND VOLUME

The common shares of Canadian Superior are listed and posted for trading on the
Toronto Stock Exchange and the American Stock Exchange under the symbol "SNG".
The following table sets forth the reported high, low and close sale prices and
volume of trading of the Common Shares as reported by the Toronto Stock Exchange
for the periods indicated.
<Table>
<Caption>
                                         HIGH                LOW             CLOSE             VOLUME
                                     ------------        ------------    ------------        ------------
<S>                                      <C>                 <C>             <C>              <C>
January 2004                             3.94                2.30            3.63             12,947,674
February 2004                            4.85                2.30            4.58             21,907,848
March 2004                               4.88                1.50            1.87             44,477,934
April 2004                               1.88                1.32            1.39              5,883,716
May 2004                                 1.96                1.33            1.73              6,063,771
June 2004                                2.37                1.70            2.00              3,710,766
July 2004                                2.20                1.70            1.83              1,272,738
August 2004                              2.09                1.60            1.82              1,989,402
September 2004                           2.50                1.71            2.34              3,636,137
October 2004                             2.85                2.23            2.34              3,145,919
November 2004                            2.77                2.13            2.63              2,527,703
December 2004                            2.69                1.65            1.91              5,581,837
January 2005                             2.25                1.86            1.96              1,762,586
February 2005                            2.83                1.93            2.60              3,059,202
</Table>

                             DIRECTORS AND OFFICERS

NAMES, OCCUPATIONS AND SECURITY HOLDERS

The following sets forth the names and municipalities of residence, offices or
positions with the Corporation, principal occupations of the directors and
executive officers of the Corporation during the past five years and the number
of voting securities held by them, directly or indirectly, beneficially or of
record, or over which each exercises control or direction. The term of the
directors' office expires at the next annual general meeting of the Corporation,
when the shareholders will be asked to elect the directors for the following
year. Officers of the Corporation are appointed by the directors until they
resign or until their successors are appointed.



<Page>

                                       43
<Table>
<Caption>
                                                         PRESENTATION AND PRINCIPAL
NAME AND MUNICIPALITY                                       OCCUPATION DURING THE                          COMMON SHARES
    OF RESIDENCE           OFFICE OR POSITION                  LAST FIVE YEARS                         BENEFICIALLY OWNED(%)
------------------------ -------------------------- ------------------------------------------ ------------------------------------
<S>                      <C>                        <C>                                               <C>
Leigh Bilton             Executive Vice             Manager Field Operations of Canadian                       58,644
Calgary, Alberta         President, Vice            Superior from 2001 to present.                            (0.0534%)
Canada                   President Operations       Vice President, Operations of Canadian
                         and Director.              88 Energy Corporation from prior to 1998
                                                    to 2001. Director of the Corporation
                                                    since 2002.


Charles Dallas           Director                   Rancher and independent businessman.                       64,444
Innisfail, Alberta                                  Director of the Corporation since                         (0.0587%)
Canada                                              2000.

Thomas J. Harp(1)(2)     Director                   From 1979 to present, President of Harp                      Nil
Calgary, Alberta                                    Resources Ltd., a private resources                         (0%)
Canada                                              company from 1979 - June 1, 2004, Mr. Harp
                                                    was the Chief Executive Officer of Coyote
                                                    Oilfield Rentals (Alberta) Ltd. Since
                                                    2001, Mr. Harp has been a director of
                                                    Cheynne Energy Inc. Mr. Harp has been a
                                                    Director of the Corporation since 2000.

Gerald J. Maier(1)       Director                   Chairman of Granmar Investments Ltd., a                    40,000
Calgary, Alberta                                    private company from 1985 to present.                     (0.0364%)
Canada                                              Director of Stream Flo Industries Ltd.,
                                                    from 1998 to present and Vintage
                                                    Petroleum Inc. from 2002 to present.
                                                    Director of the Corporation as of
                                                    March 8, 2004.

Gregory S. Noval         President and Chief        President and Chief Executive Officer of                 3,132,426
Turner Valley, Alberta   Executive Officer, and     Canadian Superior from 1997 to present.                   (2.851%)
Canada                   a Director                 President and Chief Executive Officer,
                                                    Canadian 88 from 1988 to 2000. Director
                                                    of the Corporation since 1996.

</Table>

<Page>


                                       44
<Table>
<Caption>
                                                         PRESENTATION AND PRINCIPAL
NAME AND MUNICIPALITY                                       OCCUPATION DURING THE                          COMMON SHARES
    OF RESIDENCE           OFFICE OR POSITION                  LAST FIVE YEARS                         BENEFICIALLY OWNED(%)
------------------------ -------------------------- ------------------------------------------ ------------------------------------
<S>                      <C>                        <C>                                               <C>
Michael E. Coolen        Vice President, East       Vice President, East Coast Operations                    148,327
Halifax, Nova Scotia     Coast Operations           of the Corporation from March 12, 2004                   (0.135%)
Canada                                              to present. Director of East Coast
                                                    Operations of the Corporation from
                                                    July 1, 2001 to March 12, 2004. For
                                                    the four years prior thereto, Manager
                                                    Health, Safety and Environment, Sable
                                                    Offshore Energy Inc., under secondment
                                                    from ExxonMobil Canada and Mobil
                                                    Oil Canada.

Alexander Squires(1)     Director                   Mr. Squires is a Chartered Financial                      408,000
                                                    Analyst and was the director of the                       (0.371%)
                                                    Toronto Society of Financial Analysts
                                                    from 1984 to 1986. Since 1997 Mr. Squires
                                                    has been a Managing Partner and Director
                                                    of Brant Securities Ltd. an independent
                                                    full service securities firm.

Ross A. Jones            Chief Financial Officer    Chief Financial Officer of Canadian                        2,650
                                                    Superior Energy Inc. from November                        (0.002%)
                                                    2004 to President. From 2002 to 2004
                                                    Mr. Jones was President of Stevlaur
                                                    Resources Ltd. an Oil and Gas financial
                                                    consulting company, and from 1998 to
                                                    2001 Mr. Jones was Vice President of
                                                    Tikal Resources Corp. a junior oil and
                                                    gas company listed on the TSX.
</Table>

NOTES:

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

(2)  Mr. Harp is a Professional Engineer.

(3)  Mr. Alexander Squires was appointed to the Board of Directors effective
     November 12, 2004.

(4)  Mr. Rodney Erskine resigned from the Board of Directors of the Corporation
     effective as of May 4, 2004.

(5)  Mr. J. Ronald Woods resigned from the Board of Directors of the Corporation
     effective as of November 3, 2004.


<Page>


                                       45

As at March 22, 2005, the number of Common Shares beneficially owned directly or
indirectly or controlled by the directors and executive officers of the
Corporation, as a group, was 3,854,491 Common Shares, being 3.5% of the
outstanding Common Shares of the Corporation.

CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS

Other than as described below, to the knowledge of management of the
Corporation, there has been no director or officer, or any shareholder holding a
sufficient number of securities of the Corporation to affect materially the
control of the Corporation that is or, within the 10 years before the date of
this annual information form, has been a director or officer of any issuer that,
while that person was acting in that capacity:

         (a)      was been the subject of a cease trade or similar order, or an
                  order that denied the issuer access to any exemptions under
                  securities legislation, for a period of more than 30
                  consecutive days;

         (b)      was subject to an event that resulted, after the director or
                  executive officer ceased to be a director or executive office,
                  in the company being subject of a cease trade order or similar
                  order or an order that denied the relevant company access to
                  any exemption under securities legislation, for a period of
                  more than 30 consecutive days; or

         (c)      within a year of that person ceasing to act in that capacity
                  or within the 10 years before the date of this annual
                  information form, became bankrupt, made a proposal under any
                  legislation relating to bankruptcy or insolvency or was
                  subject to or instituted any proceedings, arrangement or
                  compromise with creditors or had a receiver, receiver manager
                  or trustee appointed to hold its assets.

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

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

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

On October 15, 1997, the Alberta and Ontario Securities Commissions (the "ASC"
and the "OSC", respectively) issued orders relating to a settlement agreement
entered into by Canadian 88, Mr. Noval and two other parties (the "Respondents")
in respect of their involvement in a take-over bid made in early 1997 by
Canadian 88 for the common shares of Morrison Petroleums Ltd., a corporation
whose common shares were listed on the TSX and the Montreal Exchange. In spite
of the fact that Canadian 88 made in excess of $14 million and donated $1
million to charity, in a joint submission with the ASC and the OSC, the
Respondents agreed that their actions and the public statements of Mr. Noval on
behalf of Canadian 88 were contrary to the public interest. Under the terms of
the settlement agreement, Canadian 88 was required to make a $200,000 payment to
the ASC and was reprimanded by the OSC. Mr. Noval was prohibited from trading
securities and from relying on most exemptions available under the securities
legislation of Alberta and Ontario for a period of 12 months.


<Page>


                                       46

CONFLICTS OF INTEREST

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

                                LEGAL PROCEEDINGS

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

During 2004, a number of class action proceedings were initiated against
Canadian Superior and certain of its directors and officers in the United States
District Court, Southern District of New York, in the Ontario Superior Court of
Justice and the Quebec Superior Court by plaintiffs alleging to have purchased
securities of the Corporation and alleging they suffered damages resulting from
statements by the Company regarding the Company's Mariner I-85 exploration well
drilled offshore Nova Scotia. Canadian Superior and the individuals involved
categorically deny these allegations and have advised the Corporation's insurer
of the same. The amount of damages remains to be quantified. Canadian Superior
views these actions to be without merit and has filed applications to dismiss
these actions which remain outstanding. Further, the Corporation intends to
aggressively deal with these matters.

           INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Pursuant to an executive employment contract with the Corporation, dated July 1,
2000, Gregory Noval, the President and Chief Executive Officer of the
Corporation assigned to Hughes Air Corp., a company controlled by Gregory Noval,
certain obligations to provide services to the Corporation and certain rights to
receive remuneration from the Corporation. In January 2003, Hughes Air Corp. and
the Corporation set off amounts of $1.1 million, and the contract between the
Corporation and Hughes Air Corp. was terminated and all obligations from Hughes
Air Corp. to the Corporation were extinguished.

                          TRANSFER AGENT AND REGISTRAR

Computershare Trust Company of Canada at 600, 530 - 8th Avenue S.W., Calgary,
Alberta, T2P 3S8, is the transfer agent and registrar for the Common Shares.

                              INTERESTS OF EXPERTS

Reserve estimates contained in this annual information form are derived from
reserve reports prepared by Gilbert Laustsen Jung Associates Ltd. As of the date
hereof, Gilbert Laustsen Jung Associates Ltd., as a group, does not beneficially
own, directly or indirectly, any Common Shares of the Corporation.

As at March 22, 2005, KPMG LLP and its partners did not hold any registered or
beneficial ownership interests, directly or indirectly, in the securities of the
Company or its associates or affiliates.

                                 AUDIT COMMITTEE

The Audit Committee of the Corporation consists of Mr. Gerald J. Maier, Mr.
Alexander Squires and Mr. Thomas J. Harp, each of whom is considered
"independent" and "financially literate" within the meaning of Multilateral
Instrument 52-110, AUDIT COMMITTEES.


<Page>


                                       47

MANDATE OF THE AUDIT COMMITTEE

The mandate of the Audit Committee is to assist the Board of Directors of the
Corporation in its oversight of the integrity of the financial and related
information of the Corporation and its subsidiaries and related entities,
including the financial statements, internal controls and procedures for
financial reporting and the processes for monitoring compliance with legal and
regulatory requirements.

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

               (i)   the integrity of the Corporation's financial statements

               (ii)  the integrity of the financial reporting process

               (iii) the system of internal control and management of financial
                     risks

               (iv)  the external auditors' qualifications and independence

               (v)   the external audit process and the Corporation's process
                     for monitoring compliance with laws and regulations.


The Charter of the Audit Committee of the Board of Directors of Canadian
Superior is attached hereto, in its entirety, as Appendix "C".

RELEVANT EDUCATION AND EXPERIENCE OF AUDIT COMMITTEE MEMBERS

The following is a brief summary of the education or experience of each member
of the Audit Committee that is relevant to the performance of his
responsibilities as a member of the Audit Committee, including any education or
experience that has provided the member with an understanding of the accounting
principles used by the Corporation.
<Table>
<Caption>
     NAME OF AUDIT COMMITTEE MEMBER                          RELEVANT EDUCATION AND EXPERIENCE

<S>                                                     <C>
Gerald J. Maier                                         Chairman of Granmar Investments Ltd., a private
                                                        company from 1985 to present. Director of Stream
                                                        Flo Industries Ltd., from 1998 to present and
                                                        Vintage Petroleum Inc. from 2002 to present.
                                                        Director of the Corporation as of March 8, 2004.

Alexander Squires, CFA                                  Mr. Squires is a Chartered Financial Analyst and
                                                        was the director of the Toronto Society of
                                                        Financial Analysts from 1984 to 1986 Since 1997,
                                                        Mr. Squires has been a Managing Partner and
                                                        Director of Brant Securities Ltd. an independent
                                                        full service securities firm.

Thomas J. Harp                                          From 1979 to present, President of Harp Resources
                                                        Ltd., a private resources company From 1979 -
                                                        June 1, 2004, Mr. Harp was the Chief Executive Officer
                                                        of Coyote Oilfield Rentals (Alberta) Ltd.  Since 2001,
                                                        Mr. Harp has been a director of Cheynne Energy
                                                        Inc.  Mr. Harp has been a Director of the
                                                        Corporation since 2000.
</Table>


AUDIT COMMITTEE OVERSIGHT

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


<Page>


                                       48

EXTERNAL AUDITOR FEES

For the year ended December 31, 2003 and 2004, KPMG LLP and its affiliates were
paid approximately $154,700 and $193,600, respectively, as detailed below:
<Table>
<Caption>
                                                                          YEAR ENDED DECEMBER 31
-----------------------------------------------------------------------------------------------------------
                                                                             2004                     2003
<S>                                                                     <C>                      <C>
KPMG LLP
   Audit fees                                                           $ 150,000                $ 148,700
   Audit-related fees                                                         $ 0                      $ 0
   Tax Fees                                                                   $ 0                   $6,000
   All Other Fees                                                         $43,600                      $ 0
-----------------------------------------------------------------------------------------------------------
   TOTAL                                                                $ 193,600                $ 154,700
-----------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
</Table>

                             ADDITIONAL INFORMATION

Additional information relating to the Corporation may be found on through the
internet on the System for Electronic Document Analysis and Retrieval (SEDAR)
which can be accessed at www.sedar.com. Additional information, including
directors' and officers' remuneration and indebtedness, principal holders of the
Corporation's securities and securities authorized for issuance under equity
compensation plans, if applicable, is contained in the Corporation's Management
Information Circular for its most recent annual meeting of security holders that
involved the election of directors. Additional financial information is provided
in the Corporation's financial statements and Management's Discussion & Analysis
for its most recently completed year.

Additional copies of this Annual Information Form and the materials listed in
this section are available upon request by contacting the Corporation at 3300,
400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2 or by phone at (403) 294-1411 or
fax at (403) 216-2374.
<Page>


                                  APPENDIX "A"

                             REPORT ON RESERVES DATA
                                       BY
                         INDEPENDENT QUALIFIED RESERVES
                              EVALUATOR OR AUDITOR

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


1.   We have prepared an evaluation of the Company's reserves data as at
     December 31, 2004. The reserves data consist of the following:

     (a)  (i)  proved and proved plus probable oil and gas reserves estimated as
               at December 31, 2004, using forecast prices and costs; and

          (ii) the related estimated future net revenue; and

     (b)  (i)  proved oil and gas reserves estimated as at December 31, 2004,
               using constant prices and costs; and

          (ii) the related estimated future net revenue.


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

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

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

4.   The following table sets forth the estimated future net revenue (before
     deduction of income taxes) attributed to proved plus probable reserves,
     estimated using forecast prices and costs and calculated using a discount
     rate of 10 percent, included in the reserves data of the Company evaluated
     by us for the year ended December 31, 2004, and identifies the respective
     portions thereof that we have audited, evaluated and reviewed and reported
     on to the Company's Board of Directors:
<Table>
<Caption>




                                                          Net Present Value of Future Net Revenue
                              Location of                 (before income taxes, 10% discount rate)
    Description and        Reserves (Country    ------------------------------------------------------------
  Preparation Date of         or Foreign
   Evaluation/Report        Geographic Area)            Audited           Evaluated      Reviewed     Total
------------------------  --------------------  ---------------------- ------------- ------------- ---------
<S>                        <C>                          <C>               <C>            <C>        <C>
   March 3, 2005               Canada                      0               89,219           0        89,219
</Table>

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

6.   We have no responsibility to update this evaluation for events and
     circumstances occurring after the preparation dates.


<Page>


                                       A-2


7.   Because the reserves data are based on judgements regarding future events,
     actual results will vary and the variations may be material.

Executed as to our report referred to above:

Gilbert Laustsen Jung Associates Ltd., Calgary, Alberta, Canada

Dated March 8, 2005



ORIGINALLY SIGNED BY
---------------------------------
Dana B. Laustsen, P. Eng.
Executive Vice-President

<Page>


                                  APPENDIX "B"

                       REPORT OF MANAGEMENT AND DIRECTORS
                     ON RESERVES DATA AND OTHER INFORMATION

     TERMS TO WHICH A MEANING IS ASCRIBED IN NATIONAL INSTRUMENT 51-101 HAVE
                            THE SAME MEANING HEREIN.

         Management of Canadian Superior Energy Inc. (the "Corporation") are
responsible for the preparation and disclosure of information with respect to
the Corporation's oil and gas activities in accordance with securities
regulatory requirements. This information includes reserves data, which consist
of the following:

     (a)  (i)  proved and proved plus probable oil and gas reserves estimated as
               at December 31, 2004 using forecast prices and costs; and

          (ii) the related estimated future net revenue; and

     (b)  (i)  proved oil and gas reserves estimated as at December 31, 2004
               using constant prices and costs; and

          (ii) the related estimated future net revenue.

         An independent qualified reserves evaluator has evaluated and reviewed
the Corporation's reserves data. The report of the independent qualified
reserves evaluator is presented in Schedule A to the Annual Information Form of
Canadian Superior Energy Inc. effective as at December 31, 2004.

         The Reserves Committee, which is comprised of the Board of Directors of
the Corporation as a whole, has:

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

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

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


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

     (a)  the content and filing with securities regulatory authorities of the
          reserves data and other oil and gas information;

     (b)  the filing of the report of the independent qualified reserves
          evaluator on the reserves data; and

     (c)  the content and filing of this report.


<Page>


                                       B-2

Because the reserves data are based on judgements regarding future events,
actual results will vary and the variations may be material.

DATED March 31, 2005.


    Signed: "GREGORY S. NOVAL"                          Signed: "ROSS A. JONES"
    --------------------------                          -----------------------
         Gregory S. Noval                                    Ross A. Jones
      Chief Executive Officer                           Chief Financial Officer



      Signed: "LEIGH BILTON"                           Signed: "GERALD J. MAIER"
      ----------------------                           -------------------------
           Leigh Bilton                                     Gerald J. Maier
             Director                                          Director


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                                  APPENDIX "C"

                      CHARTER OF THE AUDIT COMMITTEE OF THE

               BOARD OF DIRECTORS OF CANADIAN SUPERIOR ENERGY INC.

PURPOSE/OBJECTIVES

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

         -    the integrity of the Corporation's financial statements

         -    the integrity of the financial reporting process

         -    the system of internal control and management of financial risks

         -    the external auditors' qualifications and independence

         -    the external audit process and the Corporation's process for
              monitoring compliance with laws and regulations

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

AUTHORITY

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

          -    seek any information it requires from any employee of the
               Corporation (whose employees are directed to co-operate with any
               request made by the Committee);

          -    seek any information it requires directly from external parties
               including the external auditors and independent reservoir
               engineering firm; and

          -    obtain outside legal or professional advice without seeking Board
               approval (however providing notice to the Chair of the Board).


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                                       C-2

ORGANIZATION

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

          -    The Committee shall consist of three members of the Board of the
               Corporation;

          -    The members of the Committee shall be independent members of the
               Board as defined in section 1.4 of Multilateral Instrument 52-110
               Audit Committees, as well as Part 1, sec 121(A) of the AMEX
               Company manual;

          -    The Chairman of the Committee shall be determined by the Board;

          -    Two members of the Committee shall constitute a quorum thereof;

          -    No business shall be transacted by the Committee except at a
               meeting of its members at which a quorum is present in person or
               by telephone or by a resolution in writing signed by all members
               of the Committee;

          -    The meetings and proceedings of the Corporation that regulate
               meetings and proceedings of the Board shall apply to the
               Committee;

          -    The Committee may invite such directors, officers or employees of
               the Corporation, the external auditors and the independent
               reservoir engineering firm as it may see fit, to attend its
               meetings and take part in the discussion and consideration of the
               affairs of the Committee; and

          -    Meetings shall be held not less than four times per year,
               generally coinciding with the release of interim or year-end
               financial information including consecutive sessions with
               Management and the External Auditors. Special meetings may be
               convened as required upon the request of the Committee. The
               external auditors and independent reservoir engineering firm may
               convene a meeting if they consider that it is desirable or
               necessary; and the proceedings of all meetings will be minuted.

DUTIES AND RESPONSIBILITIES

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

          CORPORATE INFORMATION AND INTERNAL CONTROL


          -    review and recommend for approval of quarterly and annual
               financial statements, MD&A and annual reports of the Corporation;

          -    review of internal control systems maintained by the Corporation;

          -    review of significant accounting and tax compliance issues where
               there is choice among various alternatives or where application
               of a policy has a significant effect on the financial results of
               the Corporation;

          -    review of significant proposed non-recurring events such as
               mergers, acquisitions or divestitures; and

          -    review of press releases or other publicly circulated documents
               containing financial information.


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                                       C-3

          EXTERNAL AUDITORS

          -    retain and/or terminate the external auditors (subject to
               regulatory and shareholder notification) who, in turn, will
               report directly to the Audit Committee;

          -    review the terms of the external auditors' engagement and the
               appropriateness and reasonableness of the proposed engagement
               fees;

          -    annually, obtain and review a certificate attesting to the
               external auditors' independence, identifying all relationships
               between the external auditors and the Corporation;

          -    annually, evaluate the external auditors' qualifications,
               performance and independence;

          -    annually, to assure continuing auditors' independence, consider
               the rotation of the lead audit partner or the external audit
               firm;

          -    pre-approve engagements for non-audit services provided by the
               external auditors or their affiliates together with estimated
               fees and potential issues of independence; and

          -    review hiring policies for employees or former employees of the
               external auditors.

          AUDIT

          -    review the audit plan for the coming year with the external
               auditors and with management;

          -    review with management and the external auditors any proposed
               changes in major accounting policies, the presentation and impact
               of significant risks and uncertainties, and key estimates and
               judgements of management that may be material to financial
               reporting;

          -    query management and the external auditors regarding significant
               financial reporting issues during the fiscal period and the
               method of resolution;

          -    review any problems experienced by the external auditors in
               performing the audit, including any restrictions imposed by
               management of significant accounting issues in which there was a
               disagreement with management;

          -    review audited annual financial statements and quarterly
               financial statements with management and the external auditors
               (including disclosures under "Management Discussion & Analysis"),
               in conjunction with the report of the external auditors and
               obtain explanation from management of all significant variances
               between comparative reporting periods; and

          -    review the auditors' report to management, containing
               recommendations of the external auditors, and management's
               response and subsequent remedy of any identified weaknesses.


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                                       C-4

OTHER DUTIES AND RESPONSIBILITIES

          -    The responsibilities, practices and duties of the Committee
               outlined herein are not intended to be comprehensive. The Board
               may, from time to time charge the Committee with the
               responsibility of reviewing items of a financial or control, risk
               management or reserves nature;

          -    The Committee shall periodically report to the Board the results
               of reviews undertaken and any associated recommendations;

          -    The Committee shall monitor the receipt, retention and treatment
               of complaints received by the issuer regarding accounting,
               internal accounting controls, or auditing matters; and

          -    The Committee shall monitor the confidential, anonymous
               submissions by employees of concerns regarding questionable
               accounting or auditing matters.