<Page>

                                                                      Exhibit 1



                               CANADIAN SUPERIOR ENERGY INC.





                              RENEWAL ANNUAL INFORMATION FORM





                                (EXCEPT AS OTHERWISE NOTED THE
                                 INFORMATION HEREIN IS GIVEN
                                  AS AT DECEMBER 31, 2003)











                                  DATED AS OF MAY 13, 2004





<Page>


                                     TABLE OF CONTENTS
<Table>
<Caption>
                                                                                                                            Page
<S>                                                                                                                         <C>
FORWARD LOOKING STATEMENTS.....................................................................................................3
ABBREVIATIONS..................................................................................................................4
CONVERSION.....................................................................................................................4
THE CORPORATION................................................................................................................5
   Name and Incorporation......................................................................................................5
   Intercorporate Relationships................................................................................................5
GENERAL DEVELOPMENT OF THE BUSINESS............................................................................................5
   History.....................................................................................................................5
   Significant Acquisition.....................................................................................................7
NARRATIVE DESCRIPTION OF THE BUSINESS..........................................................................................8
   General.....................................................................................................................8
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION..................................................................12
   General....................................................................................................................12
   Selected Reserves Information..............................................................................................13
   Reserves Data - Constant Prices and Costs..................................................................................14
   Reserves Data - Forecast Prices and Costs..................................................................................17
   Constant Prices Used in Estimates..........................................................................................20
   Forecast Prices Used in Estimates..........................................................................................22
   Reserves Reconciliation....................................................................................................24
   Future Net Revenue Reconciliation..........................................................................................25
   Undeveloped Reserves.......................................................................................................25
   Significant Factors or Uncertainties.......................................................................................25
   Future Development Costs...................................................................................................26
   Oil and Gas Properties and Wells...........................................................................................27
   Properties With No Attributed Reserves.....................................................................................27
   Forward Contracts and Future Commitments...................................................................................28
   Additional Information Concerning Abandonment and Reclamation Costs........................................................29
   Tax Horizon................................................................................................................30
   Costs Incurred.............................................................................................................30
   Exploration and Development Activities.....................................................................................30
   Production Estimates.......................................................................................................32
RISK FACTORS..................................................................................................................34
   Exploration, Development and Production Risks..............................................................................34
   Substantial Capital Requirements and Liquidity.............................................................................34
   Additional Funding Requirements............................................................................................35
   Issuance of Debt...........................................................................................................35
   Prices, Markets and Marketing of Crude Oil and Natural Gas.................................................................35
   Insurance..................................................................................................................35
   Legal Proceedings..........................................................................................................36
   Environmental Risks........................................................................................................36
   Competition................................................................................................................36
   Reserve Replacement........................................................................................................37
   Reliance on Operators and Key Employees....................................................................................37
   Permits and Licenses.......................................................................................................37
   Royalties, Incentives and Production Taxes.................................................................................37
   Land Tenure................................................................................................................38
   Title to Properties........................................................................................................38
   Corporate Matters..........................................................................................................38
</Table>

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                                 - 2 -

<Table>
<Caption>
                                                                                                                            Page
<S>                                                                                                                         <C>
DIVIDENDS.....................................................................................................................38
DESCRIPTION OF CAPITAL STRUCTURE..............................................................................................38
   Common Shares..............................................................................................................38
   Preferred Shares...........................................................................................................39
   Warrants...................................................................................................................39
   Shareholder Rights Plan....................................................................................................39
MARKET FOR SECURITIES.........................................................................................................40
   Trading Price and Volume...................................................................................................40
DIRECTORS AND OFFICERS........................................................................................................40
   Names, Occupations and Security Holders....................................................................................40
   Cease Trade Orders, Bankruptcies, Penalties or Sanctions...................................................................42
   Conflicts of Interest......................................................................................................43
LEGAL PROCEEDINGS.............................................................................................................43
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS...................................................................44
TRANSFER AGENT AND REGISTRAR..................................................................................................44
MATERIAL CONTRACTS............................................................................................................44
ADDITIONAL INFORMATION........................................................................................................44
APPENDIX A.....................................................................................................................1
APPENDIX B.....................................................................................................................1
</Table>

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                                 - 3 -
                        FORWARD LOOKING STATEMENTS

The Corporation 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", "targeting", 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.

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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                                  - 4 -

                              ABBREVIATIONS

<Table>
<Caption>

<S>               <C>                                              <C>             <C>
OIL AND NATURAL GAS LIQUIDS                                        NATURAL GAS
------------------------------------------------------------------ ----------------------------------------------------------------
Bbls              barrels                                          Mcf             thousand cubic feet
MBbls             thousand barrels                                 MMcf            million cubic feet
Bcfe              billion cubic feet equivalent                    Bcf             billion cubic feet
Boe/d             barrels of oil equivalent per day                Mcf/d           thousand cubic feet per day
Bopd              barrels of oil per day                           MMcf/d          million cubic feet per day
Bbls/d            barrels of oil per day                           M(3)            cubic metres
MMBbls            million barrels                                  MMBTU           million British Thermal Units
API               American Petroleum Institute                     Gigajoule       trillion joules
MSTB              thousands of Stock Tank Barrels of oil           TCF             trillion cubic feet
                  (oil volume at 60 degrees F and 14.65 PSIA)      MMscf           million standard cubic feet
                                                                   Ngls            natural gas liquids
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>

                            <S>                               <C>                               <C>
                            TO CONVERT FROM                   TO                                MULTIPLIED BY
                            --------------------------------- --------------------------------- ---------------------------------
                            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>


<Page>


                                  - 5 -

                             THE CORPORATION

NAME AND INCORPORATION

Canadian Superior Energy Inc. ("Canadian Superior" or the "Corporation") 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.

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%
and in the aggregate represent more than 20% of the total consolidated assets
and total consolidated revenues of the Corporation, as at December 31, 2003.

                      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 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 the Common Share purchase warrants, issued in December 2003 and January
2004, from March 31, 2004 to December 31, 2004. The extension does not apply to
any warrants held by officers, directors, 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 has 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 (the "Mariner I-85
exploration well"). 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 Corporation ("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.

<Page>


                                  - 6 -

On March 8, 2004, the Corporation announced that Gerald J. Maier had been
appointed to the board of directors (the "Board of Directors") of the
Corporation.

On February 25, 2004, the Corporation announced that Rodney D. Erskine had been
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) is exercisable into one Common Share
and one-third of one Common Share purchase warrant. Each flow through special
warrant is exercisable into one Common Share.

In November and December 2003, Canadian Superior closed the private placement of
4,998,463 flow-through Common Shares 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 16, 2003, Canadian Superior announced that the Canada-Nova Scotia
Offshore Petroleum Board 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 Canada-Nova Scotia Offshore
Petroleum Board totalling 370,881 acres for work expenditure bids totalling
$14,107,000.

On April 16, 2003, Canadian Superior announced that the Canadian subsidiary of
El Paso 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. See "GENERAL DEVELOPMENT OF THE BUSINESS --
SIGNIFICANT ACQUISITION".

On March 13, 2003, Canadian Superior announced that it had 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 announced that it had 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 Canada-Nova Scotia
Offshore Petroleum Board 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 to acquire El Paso's
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. See "GENERAL
DEVELOPMENT OF THE BUSINESS -- SIGNIFICANT ACQUISITION".

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                                  - 7 -

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

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
Corporation, 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.

On November 7, 2001, the Corporation announced that it had selected the drilling
location for its first well on the Corporation's Marquis Abenaki Reef prospect
located approximately 160 kilometres (100 miles) offshore Nova Scotia.

In November 2001, the Corporation was the successful bidder in respect of two
exploration licenses totalling 822,000 acres offshore Nova Scotia at the
Canada-Nova Scotia Offshore Petroleum Board's November 1, 2001 call for bids.
Parcels covered by the two exploration licences were numbers 1 and 4 which call
for work expenditures over the next five years of $41,250,000 and $15,510,000,
respectively. These parcels are known as the Mayflower and Mariner blocks,
respectively.

On August 24, 2001, Canadian Superior announced that it had reached a settlement
with Canadian 88 Energy Corp. ("Canadian 88") in regard to all outstanding
litigation. As a result of the settlement the companies no longer have any
long-term contractual obligations to each other.

On August 2, 2001, the Common Shares of the Corporation were listed on the
Toronto Stock Exchange (the "TSX") and Canadian Superior announced the opening
of a regional office in Halifax, Nova Scotia and the appointment of Michael E.
Coolen as Director east coast operations.

On June 12, 2001, the Corporation announced that, in association with
Geophysical Service Incorporated of Houston, Texas, it had acquired 1,100
kilometres of high-resolution seismic coverage over Canadian Superior's offshore
Nova Scotia Marquis prospects and 700 kilometres of additional high-resolution
seismic data in the immediate area at an aggregate cost of approximately $2.5
million.

Effective May 1, 2001, the Corporation sold its 10% interest in its Waterton
area assets in the foothills of southwest Alberta to Hunt Oil Company of Canada
Inc. for $18 million.

SIGNIFICANT ACQUISITION

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 relating primarily to cash flow from
operations between the effective date of the transaction (October 1, 2002)
and the closing date (March 21, 2003). Additional capitalized transaction
costs of $0.7 million were also incurred. The assets purchased included, at
the time of acquisition of such assets, production of approximately 2,600
boe/d of company operated sweet gas and light crude oil production, extensive
seismic data and key infrastructure consisting of interests in three gas
plants, three oil batteries, 20 production facilities and 130 km of company
operated pipelines.

<Page>


                                  - 8 -

Management of the Corporation believes that the Drumheller asset acquisition
was an important strategic acquisition for Canadian Superior that established
a significant new core western Canadian operating base. The transaction added
significant natural gas (75%) and light sweet oil production (25%),
approximately 4.3 million boe in total proved reserves, underutilized gas
plant capacity, production facilities, seismic data, a large undeveloped land
position comprised of 170,000 gross acres (106,693 net acres), and a
portfolio of identified drilling locations. See "GENERAL DEVELOPMENT OF THE
BUSINESS -HISTORY" and "NARRATIVE DESCRIPTION OF THE BUSINESS - OIL AND GAS
PROPERTIES AND WELLS - DRUMHELLER, ALBERTA AREA ASSETS".


                     NARRATIVE 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's primary competitors include integrated oil and
gas companies and other numerous senior oil and gas companies, most of which may
have greater financial and other resources than Canadian Superior.

SEASONALITY OF MARKETS

The market demands for oil and gas products varies on a seasonal basis, and that
variation is affected by abnormalities in temperature and precipitation in key
market areas.

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.

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. The Corporation anticipates
spending sufficient funds on environmental expenditures in 2003 in order to
comply in all material respects with all environmental requirements related to
its field operations.

HUMAN RESOURCES

The Corporation had a total of 44 full-time staff, including six staff members
in the Halifax office and six staff members in the Drumheller field office, as
at December 31, 2003.

OIL AND GAS PROPERTIES AND WELLS

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

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                                  - 9 -

1.       East coast Canada, offshore Nova Scotia

2.       Offshore Trinidad

3.       Western Canadian holdings

EAST COAST CANADA, OFFSHORE NOVA SCOTIA

Canadian Superior holds interests in six exploration licences totalling
1,293,946 acres in offshore Nova Scotia. During 2002 and 2003, joint venture
agreements were entered into with subsidiaries of the El Paso in relation to the
Marquis and Mariner projects. These joint venture agreements encompassed three
of the six exploration licences. The combined effect of the Canadian Superior -
El Paso joint venture agreements is that Canadian Superior contributed
exploration projects identified on three exploration licences, and Canadian
Superior and El Paso drilled two exploration wells. The first exploration well,
known as Marquis L35/L35A was drilled in 2002 to a depth of 4,552 metres (14,934
feet). The second exploration well, known as Canadian Superior El Paso Mariner
I-85 exploration well, spudded on November 20, 2003 and was a deep exploration
well drilled to a depth of 5,408 metres (17,743 feet).

Pursuant to the terms of the initial joint venture agreements, executed on April
23, 2002, El Paso could earn, upon satisfaction of all conditions, a 50% working
interest in the Marquis project by joining Canadian Superior in the drilling of
the Marquis L-35/L-35A well. On April 16, 2003, El Paso Corporation, through its
Canadian subsidiary El Paso Oil and Gas Canada, Inc., elected to participate in
the drilling of a well on the Mariner project lands. Pursuant to this farm-in
agreement, El Paso elected to participate, on a promoted basis, in the drilling
of an exploration well on Canadian Superior's Mariner project. Under the
proposed farm-out Canadian Superior would retain a 50% working interest in the
Mariner project and contribute only one-third of drilling costs of the first
Mariner exploration well, subsequently designated the Canadian Superior El Paso
Mariner I-85 exploration well.

MARINER PROJECT (EL 2409, 100% WORKING INTEREST; SUBJECT TO EL PASO EARNING A
50% WORKING INTEREST)

Canadian Superior's Mariner project is located approximately nine kilometres
northeast of Sable Island, Offshore Nova Scotia. This project encompasses an
offshore area of 101,800 acres. El Paso Corporation, through its Canadian
subsidiary El Paso Oil and Gas Canada, Inc., farmed-in to participate in the
drilling and development of the Mariner project.

During the third quarter of 2003, Canadian Superior and El Paso selected a
location for the next exploration well, Mariner I-85, approximately nine
kilometres northwest of the Sable Offshore Energy Project's Venture gas field.
Spudding occurred November 20, 2003. This farm-out allows El Paso, upon
satisfaction of all conditions, to obtain a 50% working interest in the 101,800
acre Mariner project lands by committing to pay two-thirds of the cost of the
first Mariner project exploration well.

This first Mariner project exploration well was drilled to a total depth of
approximately 5,408 metres (17,743 feet) to evaluate one of three large
structures identified on the Mariner project licence. The Rowan Gorilla V
jack-up drilling rig was contracted to drill this well.

The Mariner I-85 exploration well encountered gas pay in multiple zones. Gas
levels measured while drilling supported the presence of gas bearing reservoir
sections, subsequently confirmed by the full suite of electric wireline logs
completed and evaluated. Canadian Superior reluctantly agreed with El Paso,
operator of the well, not to proceed with flow testing to surface and/or
completion operations.

On March 25, 2004, an announcement was made that abandonment operations had been
safely completed.

The Mariner I-85 exploration well was drilled on the first of three prospects
identified on the Mariner project lands. The I-85 well was located in shallow
water depths of approximately 55 metres (180 feet) on the southeast side of our
licence.

<Page>


                                  - 10 -

MARQUIS PROJECT (EL 2401 & EL 2402, 50% WORKING INTEREST)

Canadian Superior's Marquis project lands encompass two exploration licences
with approximately 112,000 contiguous acres. The Marquis project lands are
located approximately 20 kilometres 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
massive Abenaki reef complex. El Paso earned a 50% working interest to the depth
drilled in the Marquis project by drilling of the Marquis L-35/L-35A well. A
targeted high-resolution 3-D Seismic survey on the Marquis project lands,
originally scheduled for September of 2003, was postponed due to adverse weather
conditions and is expected to proceed in due course.

MAYFLOWER PROJECT (EL 2406, 100% WORKING INTEREST)

Canadian Superior's Mayflower project exploration licence, covering
approximately 720,000 acres, was acquired in November 2001 for a work
expenditure bid of $41.25 million. This project area is located approximately
460 kilometres east of Boston. Mapping to date indicates the presence of five
sizeable deep-water prospects within the Mayflower block. These large prospects
are structural and are typically formed by mobile salt tectonics. Prospect sizes
range from 50 to 200 square kilometres in size and are located in 1,300 to 2,500
metre water depths. The Corporation plans to proceed with a seismic program over
the Mayflower block to further define target structures for drilling.

Canadian Superior is working to secure joint venture partners for the deep water
Mayflower block. The potential Mayflower joint venture partnership is
anticipated to be structured on terms similar to past joint ventures.

MARAUDER & MARCONI PROSPECTS (EL 2415 & 2416, 100% WORKING INTEREST)

Canadian Superior acquired two new exploration licences offshore Nova Scotia
from the Canada-Nova Scotia Offshore Petroleum Board, covering 370,881 acres.
Land parcels #2 (EL 2415) and #4 (EL 2416) were acquired for work expenditure
bids aggregating to $14.1 million. These licences, named Marauder (EL 2415) and
Marconi (EL 2416), were targeted for acquisition based on analysis of
proprietary seismic data and in-house geological evaluations. Marauder has four
seismically defined prospects. The Marconi licence has a seismically defined
tilted fault / anticlinal prospect similar to other Sable area fields.

OFFSHORE TRINIDAD

TRADEWINDS PROJECT

During 2003, Canadian Superior secured a joint venture position in offshore
Trinidad. The joint venture, known as our Tradewinds project, covers 55,000
acres of near shore acreage in the Mayaro/Guayaguayare area, off the east coast
of Trinidad.

A joint venture agreement with Petroleum Company of Trinidad and Tobago Limited
("Petrotrin") encompasses two Blocks (55,000 acres) in the Mayaro/Guayaguayare
area. Petrotrin, an integrated oil company owned by the Government of the
Republic of Trinidad and Tobago, produces approximately 60,000 barrels of oil
per day and owns a refinery in Trinidad capable of handling 165,000 barrels of
oil per day.

Under the terms of the joint venture agreement with Petrotrin, Canadian Superior
and partners will initially conduct approximately 259 square kilometres (100
square miles) of high resolution offshore 3-D seismic over the
Mayaro/Guayaguayare area and plans to drill two separate seismically defined
structures on the properties.

Efforts to increase our presence in shallow offshore Trinidad opportunities will
continue during 2004. In early 2004, Canadian Superior submitted bids for
production sharing contracts for two blocks located off the east coast of
Trinidad. Canadian Superior has 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

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                                  - 11 -

block, with water depths in excess of 150 meters. Canadian Superior intends
to finalize agreements with respect to its bid for Block 5(c) and initiate
exploration activity.

WESTERN CANADA HOLDINGS

The Corporation's focus in western Canada in 2003 was initiating a development
drilling program with respect to the Drumheller area assets acquired in March,
2003. Production for 2003 averaged 2,285 boe/d. During 2003, production
increased substantially to approximately 2,650 boe/d at year end. Production
reached in excess of 3,000 boe/d at the end of April 2004. Further production
additions are expected from continued drilling in the Drumheller area and from
activities in winter access areas that are expected to be renewed in the fall of
this year.

DRUMHELLER, ALBERTA AREA ASSETS

The Drumheller asset acquisition was an important strategic acquisition for
Canadian Superior that established a significant new core Western Canadian
operating base for the Corporation. The transaction added natural gas (75%) and
light sweet oil production (25%), approximately 5.5 million boe in established
reserves, underutilized gas plant capacity, strategic production facilities,
extensive seismic data, a large undeveloped land position comprised of 170,000
gross acres (106,693 net acres) and a portfolio of identified drilling
locations. Key infrastructure assets include interests in three gas plants,
three oil batteries, 20 production facilities and 130 kilometres of
company-operated pipelines.

The Drumheller area is now Canadian Superior's largest single producing area.
Thirteen successful oil and gas wells were drilled in 2003, with twelve wells
completed, six wells tied-in in 2003, and the remaining six wells tied-in early
in 2004. A total of 23 new exploration and development locations were surveyed
during 2003. Thirteen locations were drilled in 2003, four locations were
drilled in the first quarter of 2004 and six locations remain to be drilled to
complete the first phase of Canadian Superior's Drumheller area drilling
program.

During 2003, the Corporation conducted an in-depth assessment of the potential
for coal bed methane production on our large Drumheller area landholdings. Our
landholdings are situated in the heart of significant thick coal bed
accumulations. Our assessment confirmed the potential for commercial production
and led to the drilling of two test wells in two separate joint ventures. We
currently hold approximately 108 net sections (69,120 acres) of Drumheller area
lands with potential for coal bed methane production.

ALBERTA WINTER AREA OPERATIONS

East Ladyfern Area, Alberta (50%-75% working interest, operated):

During 2003, drilling occurred in winter access areas with a particular focus on
the East Ladyfern area. Canadian Superior holds approximately 15,360 gross acres
in the East Ladyfern area. The Corporation currently holds 24 contiguous
sections of land in this area. During the first quarter of 2003, Canadian
Superior successfully drilled two Slave Point gas wells jointly with its partner
El Paso. During the first quarter of 2004 one well was successfully completed.

Early in 2004, Canadian Superior completed 62 square kilometres (24 square
miles) of 3-D seismic in the East Ladyfern area over our landholdings. Based on
this seismic data, several new locations have been identified for drilling.

Windfall (100% working interest, operated):

Canadian Superior holds approximately 7,840 acres in the Windfall area south of
Edson. Gas gathering and facilities optimization projects were implemented
during 2003 to bring new gas on-stream in this gas production area. Production
from this area averaged 192 boe/d during 2003. Additional lands were acquired
during 2003 and plans for a three well winter drilling program are being
considered for 2004. The primary targets in the Windfall area are Gething,
Nordegg and Notikewan natural gas targets.

<Page>


                                  - 12 -

Twinning (66.7% working interest, operated):

In the Twinning area of Central Alberta, Canadian Superior holds an average
66.7% working interest in 3,840 acres of landholdings and is operator.
Production from this area averaged 37 boe/d during 2003.

OTHER ALBERTA ACTIVITY AREAS

In the Boundary Lake area of Northwest Alberta,  Canadian Superior holds
12,480 gross acres (9,504 net acres).  Production from this area averaged 50
boe/d during 2003.

In the Bison Lake area of North Central Alberta, Canadian Superior continued
with the development of multi-zone targets during 2003. One new sour gas well
was placed on-stream during the year at approximately 0.5 mmcf/d. Total
production from this area averaged 160 boe/d during 2003. Approximately 22,400
acres are held 100% by the Company in this area. The potential exists to drill
Wabamun targets on these lands.

BRITISH COLUMBIA

Canadian Superior holds lands covering 15,243 gross acres (11,506 net acres) in
northeastern British Columbia.

Umbach (62.5%-100% working interest, operated):

The Company's  landholdings total 5,557 gross acres (3,994 net  acres).
Canadian Superior is evaluating these lands for Slave Point potential.

Altares (33%-100% working interest, operated):

In the Altares area of northeast British Columbia, Canadian Superior holds 4,566
gross acreages (2,392 net acres) on a foothills overthrust prospect jointly with
Unocal Canada Limited. The Corporation is targeting the Mississippian formation
for future drilling.

Parkland (100% working interest, operated):

The Company holds 5,120 acres of land in Parkland, south of Fort St. John. An
exploration well was successfully drilled with Mississippian, Permian and
Cretaceous potential. This well is expected to be completed and production
tested. Additional drilling is planned for this area.

         STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

GENERAL

National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities
("NI 51-101"), which was adopted by Canadian securities regulatory authorities
effective September 30, 2003, establishes a new standard of disclosure for all
Canadian reporting issuers in upstream oil and natural gas activities and new
reserve definitions for proved and probable reserve categories. NI 51-101
replaces National Policy 2-B (NP 2-B) "Guide for Engineers and Geologists
Submitting Oil and Gas Reports to Canadian Provincial Securities
Administrators".

The reserve disclosure presented below conforms with the requirements of NI
51-101. Additional information not required by NI 51-101 has been presented to
provide continuity and additional information which management of the
Corporation believes is important to the readers of this information.

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

<Page>


                                  - 13 -

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.

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, 2003. The information set forth below is derived from the report, with a
preparation date of April 21, 2004, 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, 2003. The GLJ Report has been prepared in accordance with the standards
contained in the COGE Handbook and the reserves definitions contained in NI
51-101 and the COGE Handbook. ALL EVALUATIONS AND REVIEWS OF FUTURE NET CASH
FLOW ARE STATED PRIOR TO ANY PROVISION FOR INTEREST COSTS OR GENERAL AND
ADMINISTRATIVE COSTS AND AFTER THE DEDUCTION OF ESTIMATED FUTURE CAPITAL
EXPENDITURES FOR WELLS TO WHICH RESERVES HAVE BEEN ASSIGNED. IT SHOULD NOT BE
ASSUMED THAT THE ESTIMATED FUTURE NET CASH FLOW SHOWN BELOW IS REPRESENTATIVE OF
THE FAIR MARKET VALUE OF THE CORPORATION'S PROPERTIES. THERE IS NO ASSURANCE
THAT SUCH PRICE AND COST ASSUMPTIONS WILL BE ATTAINED AND VARIANCES COULD BE
MATERIAL. THE RECOVERY AND RESERVE ESTIMATES OF CRUDE OIL, NGLS AND NATURAL GAS
RESERVES PROVIDED HEREIN ARE ESTIMATES ONLY AND THERE IS NO GUARANTEE THAT THE
ESTIMATED RESERVES WILL BE RECOVERED. ACTUAL CRUDE OIL, NGLS AND NATURAL GAS
RESERVES MAY BE GREATER OR LESS THAN THE ESTIMATES PROVIDED HEREIN. The
Corporation has a reserves committee consisting of the entire Board of Directors
which reviews the qualifications and appointment of the independent qualified
reserves evaluators. The committee also reviews the procedures for providing
information to the evaluators. All booked reserves are based upon annual
evaluation and review by the independent qualified reserves evaluators

In accordance with the requirements of NI 51-101, the Report on Reserves Data by
Independent Qualified Reserves Evaluator in Form 51-101 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.

<Page>

                                         -14-

RESERVES DATA - CONSTANT PRICES AND COSTS

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

<Table>
<Caption>

                                                                  Proved                                                  Total
                                                                 Developed                                                Proved
                                                     Proved        Non-          Proved           Total        Total       Plus
                                                    Producing    producing     Undeveloped       Proved      Probable    Probable
                                                    ---------    ---------     -----------      -------      --------    --------
<S>                                                 <C>          <C>           <C>              <C>          <C>         <C>
MARKET RESERVES

    LIGHT/MEDIUM OIL - MSTB
 -----------------------------------------

       Total Company Interest                          806          157             75             1039         760         1798
       Working Interest                                806          157             75             1039         760         1798
       Net After Royalty                               729          139             69              938         659         1597

    GAS - MMCF
 -----------------------------------------

       Total Company Interest                        15752         1412            629            17793        7380        25173
       Working Interest                              15519         1412            623            17553        7352        24905
       Net After Royalty                             12596         1108            478            14182        5758        19940

    NATURAL GAS LIQUIDS - MSTB
 -----------------------------------------

       Total Company Interest                          176           10             11              197         101          298
       Working Interest                                171           10             11              192         100          293
       Net After Royalty                               119            7              7              133          69          202

    OIL EQUIVALENT - MBOE
 -----------------------------------------

       Total Company Interest                         3608          402            191             4201        2091         6292
       Working Interest                               3564          402            190             4156        2085         6242
       Net After Royalty                              2948          331            156             3435        1688         5123

BEFORE TAX PRESENT VALUE - $M

       0.0%                                          77497         7040           3555            88092       37561       125653
       8.0%                                          58223         5479           2343            66046       22086        88132
       10.0%                                         55093         5190           2134            62417       19866        82283
       12.0%                                         52360         4931           1950            59241       18005        77246
       15.0%                                         48847         4588           1715            55149       15724        70873
       18.0%                                         45881         4291           1518            51690       13902        65592
       20.0%                                         44144         4115           1404            49664       12882        62545

FIRST 6 YEARS BEFORE TAX CASH FLOW - $M

       2004                                          18680         1548           -302            19926        1476        21402
       2005                                          13359          972            507            14838        1902        16740
       2006                                           9525         1095            632            11253        3689        14942
       2007                                           7219          760            518             8497        3187        11684
       2008                                           5353          743            424             6519        3473         9992
       2009                                           4155          558            344             5057        3554         8611

 Oil Equivalent Factors
 -----------------------------------------

Li/Med oil - 1.0 bb/boe, Propane - 1.0 bbl/boe   Sales Gas - 6.0 mcf/boe     Condensate - 1.0 bbl/boe     Butane - 1.0 bbl.boe
</Table>


<Page>

                                                 -15-


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


<Table>
<Caption>
                                                                                                Future                   Future
                                                                                                 Net                       Net
                                                                    Capital                    Revenue                   Revenue
                                                                    Develop-      Abandon-      Before                    After
                                                        Operating    ment          ment         Income        Income     Income
                                Revenue    Royalties      Costs      Costs         Costs        Taxes          Tax        Taxes
                                 (M$)        (M$)          (M$)      (M$)          (M$)          (M$)          (M$)        (M$)
                                -------    ---------    ---------   --------      --------     -------       -------     -------
<S>                             <C>        <C>          <C>         <C>           <C>          <C>           <C>         <C>

Proved Producing                 130769      20200        32160        711          200          77497         498        76999

Total Proved                     152332      23249        37956        2835         200          88092         2066       86026

Total Proved Plus Probable       227710      35349        60262        6147         300          125653        12943      112710

</Table>



<Page>


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


<Table>
<Caption>
                                                                    Reserves
                                -----------------------------------------------------------------------------------
                                   Light and                                        Natural Gas
                                   Medium Oil       Heavy Oil      Natural Gas        Liquids       Oil Equivalent
                                 --------------    ------------   -------------    --------------   --------------
                                  W.I      Net     W.I.    Net    W.I.     Net      W.I.     Net     W.I.     Net
                                  Mbbl     Mbbl    Mbbl    Mbbl   Mmef     Mbbl     Mbbl     Mbbl    Mbbl     Mbbl
                                  -----    -----    ----    ----  -----    -----     ----     ----   -----    -----
<S>                              <C>      <C>      <C>     <C>   <C>      <C>       <C>      <C>    <C>      <C>

Proved Producing
----------------
Light & Medium Oil Properties       524      477      0       0    3462     2931       58      45     1158     1010
Natural Gas Properties              283      253      0       0   12056     9665      114      74     2405     1938
AGCA Adjustment                       0        0      0       0       0        0        0       0        0        0
ARTC                                  0        0      0       0       0        0        0       0        0        0
                                  -----    -----    ----    ----  -----    -----     ----     ----   -----    -----
Proved Producing                    806      729      0       0   15519    12596      171     119     3564     2948

Total Proved
------------
Light & Medium Oil Properties       756      685      0       0    4020     3327       71      54     1497     1294
Natural Gas Properties              283      253      0       0   13533    10855      121      79     2659     2141
AGCA Adjustment                       0        0      0       0       0        0        0       0        0        0
ARTC                                  0        0      0       0       0        0        0       0        0        0
                                  -----    -----    ----    ----  -----    -----     ----     ----   -----    -----
Total Proved                       1039      938      0       0   17553    14182      192     133     4156     3435

Total Proved Plus Probable
--------------------------

Light & Medium Oil Properties      1441     1277      0       0    5410     4381      101      76     2444     2083
Natural Gas Properties              357      321      0       0   19495    15559      191     126     3797     3040
AGCA Adjustment                       0        0      0       0       0        0        0       0        0        0
ARTC                                  0        0      0       0       0        0        0       0        0        0
                                  -----    -----    ----    ----  -----    -----     ----     ----   -----    -----

Total Proved Plus Probable         1798     1597      0       0   24905    19940      293     202     6242     5123
</Table>




<Table>
<Caption>

                                     Net Present Value of Future Net Revenue
                                   -------------------------------------------
                                                Before Income Taxes
                                             Discounted at Various Rates
                                    ------------------------------------------
                                      0%       5%       10%      15%     20%
                                      M$       M$        M$       M$      M$
                                     -----    -----     -----   ------  -----
<S>                                 <C>      <C>       <C>     <C>     <C>

Proved Producing
----------------
Light & Medium Oil Properties        25973    20210    16798    14520   12882
Natural Gas Properties               51654    43711    38252    34236   31140
AGCA Adjustment                       -498     -366     -273     -207    -158
ARTC                                   368      340      317      298     281
                                     -----    -----     -----   ------  -----
Proved Producing                     77497    63896    55093    48847   44144

Total Proved
------------
Light & Medium Oil Properties        31363    24505    20305    17445   15365
Natural Gas Properties               56489    47781    41767    37333   33913
AGCA Adjustment                       -498     -363     -268     -200    -150
ARTC                                   738      668      614      571     536
                                     -----    -----     -----   ------  -----
Total Proved                         88092    72591    62417    55149   49664

Total Proved Plus Probable
--------------------------

Light & Medium Oil Properties        45760    32650    25195    20463   17234
Natural Gas Properties               78273    64789    55713    49128   44110
AGCA Adjustment                       -343     -217     -132      -74     -34
ARTC                                  1962     1703     1508     1356    1235
                                     -----    -----     -----   ------  -----

Total Proved Plus Probable          125653    98926    82283    70873   62545
</Table>




<Page>


                                                 -17-


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>
                                                                Proved                                                   Total
                                                               Developed                                                 Proved
                                                  Proved         Non-           Proved          Total       Total         Plus
                                                Producing      producing      Undeveloped      Proved      Probable     Probable
                                                ---------      ---------      -----------      -------     --------     --------
<S>                                             <C>            <C>            <C>              <C>         <C>          <C>
MARKETABLE RESERVES

     LIGHT/MEDIUM OIL  - MSTB
     -------------------------------
     Total Company Interest                        795            151              75           1022          728         1750
     Working Interest                              795            151              75           1022          728         1750
     Net After Royalty                             721            134              69            925          634         1559

     GAS  - MMCF
     -------------------------------
     Total Company Interest                      15428           1424             625          17477         7212        24690
     Working Interest                            15195           1424             618          17237         7184        24422
     Net After Royalty                           12314           1118             475          13906         5611        19517

     NATURAL GAS LIQUIDS  - MSTB
     -------------------------------
     Total Company Interest                        175             10              11            196           98          294
     Working Interest                              170             10              11            191           97          289
     Net After Royalty                             119              7               7            133           67          201

     OIL EQUIVALENT  - MBOE
     -------------------------------
     Total Company Interest                       3542            399             190           4131         2028         6159
     Working Interest                             3498            399             189           4086         2023         6108
     Net After Royalty                            2892            328             156           3376         1636         5012

BEFORE TAX PRESENT VALUE - $M

     0.0%                                        66695           5372            2581          74648        26603       101251
     8.0%                                        51797           4407            1741          57945        16299        74243
     10.0%                                       49375           4223            1593          55192        14785        69977
     12.0%                                       47254           4057            1463          52774        13505        66279
     15.0%                                       44515           3834            1295          49644        11921        61564
     18.0%                                       42187           3639            1153          46979        10642        57621
     20.0%                                       40817           3522            1071          45409         9920        55330

FIRST 6 YEARS BEFORE TAX CASH FLOW - $M

     2004                                        21106           1806            -244          22668         1634        24302
     2005                                        11818            792             433          13042         1392        14434
     2006                                         7537            886             519           8943         2990        11932
     2007                                         5167            427             388           5982         2435         8417
     2008                                         3800            422             309           4532         2414         6946
     2009                                         2871            336             245           3452         2483         5935
</Table>




<Page>

                                                           -18-


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


<Table>
<Caption>
                                                                                                   Future                   Future
                                                                                                     Net                      Net
                                                                        Capital                    Revenue                  Revenue
                                                                        Develop-      Abandon-      Before                   After
                                                            Operating    ment          ment         Income       Income     Income
                                    Revenue    Royalties      Costs      Costs         Costs        Taxes         Tax        Taxes
                                     (M$)        (M$)          (M$)      (M$)          (M$)          (M$)         (M$)        (M$)
                                    -------    ---------    ---------   --------      --------     -------      -------     -------
<S>                                 <C>        <C>          <C>         <C>           <C>          <C>          <C>          <C>
     Proved Producing               119136       18707        32797        711           225         66695        186         66510
     Total Proved                   138085       21392        38976       2844           225         74648       1246         73402
     Total Proved Plus Probable     202883       31706        63349       6227           350        101251       5281         95971
</Table>


<Page>

                              - 19 -

The following table sets forth the discounted future net revenue by production
group:

<Table>
<Caption>

                                                                Reserves
                          -------------------------------------------------------------------------------------
                             Light and                                          Natural Gas
                             Medium Oil       Heavy Oil       Natural Gas         Liquids      Oil Equivalent
                          -------------------------------------------------------------------------------------
                            W.I.     Net     W.I.     Net     W.I.      Net     W.I.     Net     W.I.     Net
                           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
  Properties                  522     477        0       0     3458     2927      57       45     1156    1010
Natural Gas Properties        273     244        0       0    11737     9387     113       74     2342    1882
AGCA Adjustment                 0       0        0       0        0        0       0        0        0       0
ARTC                            0       0        0       0        0        0       0        0        0       0
                          -------------------------------------------------------------------------------------
Proved Producing              795     721        0       0    15195    12314     170      119     3498    2892

TOTAL PROVED

Light & Medium Oil
  Properties                  749     681        0       0     4014     3322      71       54     1489    1289
Natural Gas Properties        273     244        0       0    13224    10584     120       79     2597    2087
AGCA Adjustment                 0       0        0       0        0        0       0        0        0       0
ARTC                            0       0        0       0        0        0       0        0        0       0
                          -------------------------------------------------------------------------------------
Total Proved                 1022     925        0       0    17237    13906     191      133     4086    3376

TOTAL PROVED PLUS PROBABLE

Light & Medium Oil
  Properties                 1407    1251        0       0     5360     4345     100       76     2400    2050
Natural Gas Properties        343     308        0       0    19061    15173     188      125     3708    2962
AGCA Adjustment                 0       0        0       0        0        0       0        0        0       0
ARTC                            0       0        0       0        0        0       0        0        0       0
                          -------------------------------------------------------------------------------------
Total Proved Plus
  Probable                   1750    1559        0       0    24422    19517     289      201     6108    5012

</Table>

<Table>
<Caption>


                                   Net Present Value of Future Net Revenue
                          -----------------------------------------------------------
                                             Before Income Taxes
                                        Discounted at Various Rates
                          -----------------------------------------------------------
                              0%          5%         10%         15%         20%
                              M$          M$         M$          M$          M$
                          -----------------------------------------------------------
<S>                           <C>         <C>        <C>         <C>         <C>
PROVED PRODUCING

Light & Medium Oil
  Properties                   21593       17067       14466       12744       11503
Natural Gas Properties         45182       39091       34829       31647       29162
AGCA Adjustment                 -428        -309        -227        -169        -126
ARTC                             349         327         308         292         278
                          -----------------------------------------------------------
Proved Producing               66695       56175       49375       44515       40817

TOTAL PROVED

Light & Medium Oil
  Properties                   25131       19992       16935       14867       13355
Natural Gas Properties         49233       42560       37874       34372       31636
AGCA Adjustment                 -421        -303        -220        -161        -118
ARTC                             706         648         603         566         537
                          -----------------------------------------------------------
Total Proved                   74648       62897       55192       49644       45409

TOTAL PROVED PLUS PROBABLE

Light & Medium Oil
  Properties                   33679       24739       19675       16428       14184
Natural Gas Properties         66178       56012       49072       43976       40046
AGCA Adjustment                 -293        -180        -105         -54         -18
ARTC                            1687        1488        1335        1214        1117
                          -----------------------------------------------------------
Total Proved Plus
  Probable                    101251       82058       69977       61564       55330

</Table>

<Page>


                              - 20 -

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, 2003 CONSTANT PRICES
                                  GILBERT LAUSTSEN JUNG ASSOCIATES LTD.
                                    CRUDE OIL AND NATURAL GAS PRICES

<Table>
<Caption>

                                       West Texas                      Light, Sweet    Bow River        Heavy           Medium
                                      Intermediate     Brent Blend      Crude Oil      Crude Oil      Crude Oil        Crude Oil
                                      Crude Oil at    Crude Oil FOB  (40 API, 0.3%S) Stream Quality  Proxy (12 API) (29 APL, 2.0%S)
                        Exchange   Cushing Oklahoma     North Sea      at Edmonton    at Hardisty     at Hardisty      at Cromer
             Inflation    Rate       Then Current     Then Current     Then Current   Then Current    Then Current    Then 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>
   1993         1.8      0.7750          18.46            17.03           21.94          16.73          13.26            17.59
   1994         0.2      0.7300          17.18            15.82           22.22          18.47          15.02            19.30
   1995         2.2      0.7290          18.39            17.04           24.23          20.80          17.28            21.69
   1996         1.6      0.7334          21.99            20.43           29.39          25.13          20.06            26.10
   1997         1.6      0.7224          20.61            19.18           27.85          21.17          14.41            23.72
   1998         0.9      0.6723          14.42            12.83           20.36          14.64           9.45            16.95
   1999         1.7      0.6750          19.29            17.81           27.69          23.84          19.67            25.42
   2000         2.7      0.6740          30.22            28.35           44.56          35.25          27.34            39.91
   2001         2.6      0.6448          25.97            24.37           39.40          27.70          16.94            31.56
   2002         2.2      0.6376          26.08            24.99           40.33          31.83          26.57            35.48
 2003 (e)       2.8      0.7213          30.96            29.00           43.51          32.01          26.01            37.26

   2004         0.0      0.7738          32.52            31.02           40.81          29.81          23.31            34.81
                                                            Constant Thereafter
</Table>

<Table>
<Caption>

   Year                Alberta Natural Gas Liquids
                          (Then Current Dollars)
------------  -----------------------------------------------
                Spec       Edmonton  Edmonton    Edmonton
               Ethane      Propane    Butane   Pentanes Plus
              $Cdn/bbl     $Cdn/bbl  $Cdn/bbl     $Cdn/bbl
------------  ---------- --------- ---------- ---------------
<S>           <C>          <C>       <C>        <C>
   1993            n/a      14.10      13.64      21.17
   1994            n/a      12.53      13.45      21.69
   1995            n/a      13.90      13.79      24.11
   1996            n/a      22.31      17.15      30.06
   1997            n/a      18.62      18.73      30.91
   1998            n/a      11.15      12.44      21.83
   1999            n/a      15.89      18.70      27.71
   2000            n/a      32.18      35.60      46.31
   2001            n/a      31.85      31.17      42.48
   2002            n/a      21.39      27.08      40.73
 2003 (e)          n/a      32.01      34.01      44.01

   2004           19.50     29.81      31.81      41.31
                     Constant Thereafter

</Table>


                             NATURAL GAS AND SULPHUR

<Table>
<Caption>

                                                                         Alberta Plant Gate            Saskatchewan Plant Gate
                                                        ------------------------------------------ -------------------------------
              US Gulf
              Coast Gas      Midwest
               Price @       Price @                      Spot
              Henry Hub      Chicago      AECO-C Spot     Then                                                            Sumas
            Then Current   Then Current   Then Current   Current     ARP     Aggregator  Alliance  SaskEnergy   Spot       Spot
    Year     $US/mmbtu      $US/mmbtu      $Cdn/mmbtu    $/mmbtu   $/mmbtu    $/mmbtu    $/mmbtu    $/mmbtu    $/mmbtu   $US/mmbtu
----------- ------------- --------------- ------------- ---------- --------- ----------- --------- ----------- --------- ---------
<S>         <C>           <C>             <C>           <C>        <C>       <C>         <C>       <C>         <C>       <C>
    1993        2.11           2.31           2.26        2.16       1.71       n/a        n/a        1.48       2.07       1.89
    1994        1.94           2.11           1.98        1.86       1.81       n/a        n/a        1.88       1.87       1.59
    1995        1.70           1.69           1.15        1.02       1.31       n/a        n/a        1.35       0.98       1.03
    1996        2.52           2.73           1.39        1.26       1.63       n/a        n/a        1.52       1.28       1.32
    1997        2.47           2.75           1.84        1.69       1.96       n/a        n/a        1.84       1.74       1.70
    1998        2.16           2.20           2.03        1.88       1.94       n/a        n/a        2.05       2.13       1.60
    1999        2.32           2.34           2.92        2.75       2.48       n/a        n/a        2.83       2.97       2.15
    2000        4.33           4.38           5.08        4.92       4.50       4.60       n/a        4.79       5.16       4.17
    2001        4.05           4.17           6.21        6.07       5.41       5.30       5.61       5.71       6.20       4.56
    2002        3.36           3.30           4.04        3.88       3.88       3.83       3.82       4.04       4.08       2.68

</Table>

<Table>
<Caption>

                 British Columbia
             ---------------------- ----------- ----------
                                                  Alberta
                                     Sulphur      Sulphur
               CanWest       Spot      FOB        at Plant
             Plant Gate  Plant Gate  Vancouver      Gate
    Year      $/mmbtu     $/mmbtu     $US/LT      $Cdn/LT
-----------  ----------- ---------- ----------- ----------
<S>          <C>         <C>        <C>         <C>
    1993        1.73       2.10       30.22       -9.68
    1994        1.81       1.87       44.96       16.57
    1995        1.29       1.12       54.99       30.07
    1996        1.50       1.47       36.28       14.44
    1997        1.80       1.98       34.75       11.50
    1998        1.94       2.00       24.59       -6.51
    1999        2.51       2.78       33.74        6.93
    2000        5.27       4.88       38.14       13.59
    2001        6.76       6.29       18.29      -14.66
    2002        3.64       3.93       29.38        3.04

</Table>

<Page>


                              - 21 -

                             NATURAL GAS AND SULPHUR

<Table>
<Caption>

                                                                         Alberta Plant Gate            Saskatchewan Plant Gate
                                                        ------------------------------------------ -------------------------------
              US Gulf
              Coast Gas      Midwest
               Price @       Price @                      Spot
              Henry Hub      Chicago      AECO-C Spot     Then                                                            Sumas
            Then Current   Then Current   Then Current   Current     ARP     Aggregator  Alliance  SaskEnergy   Spot       Spot
    Year     $US/mmbtu      $US/mmbtu      $Cdn/mmbtu    $/mmbtu   $/mmbtu    $/mmbtu    $/mmbtu    $/mmbtu    $/mmbtu   $US/mmbtu
----------- ------------- --------------- ------------- ---------- --------- ----------- --------- ----------- --------- ---------
<S>         <C>           <C>             <C>           <C>        <C>       <C>         <C>       <C>         <C>       <C>
  2003 (e)      5.43           5.46           6.66        6.49       6.33       5.85       6.83       6.60       6.68       4.66

    2004        5.77           5.86           6.09        5.83       5.73       5.43       5.83       5.88       5.98       5.49
                                                       Constant Thereafter

</Table>

<Table>
<Caption>

                 British Columbia
             ---------------------- ----------- ----------
                                                  Alberta
                                     Sulphur      Sulphur
               CanWest       Spot      FOB        at Plant
             Plant Gate  Plant Gate  Vancouver      Gate
    Year      $/mmbtu     $/mmbtu     $US/LT      $Cdn/LT
-----------  ----------- ---------- ----------- ----------
<S>          <C>         <C>        <C>         <C>
  2003 (e)      5.69       6.32       59.81       40.01

    2004        5.43       5.78       59.50       35.00
                   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.


<Page>

                                    - 22 -

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
April 1, 2004:



                              GILBERT LAUSTSEN JUNG ASSOCIATES LTD.
                               CRUDE OIL AND NATURAL GAS LIQUIDS
                                        PRICE FORECAST
                                    EFFECTIVE APRIL 1, 2004


<Table>
<Caption>

                     Bank of     West Texas                     Light, Sweet      Bow River         Heavy            Medium
                     Canada     Intermediate    Brent Blend       Crude Oil        Crude Oil       Crude Oil        Crude Oil
                     Average    Crude Oil at     Crude Oil      (40 API, 0.3%S)   Stream Quality  Proxy (12 API)  (29 API, 2.0%S)
                      Noon    Cushing Oklahoma   FOB North Sea    at Edmonton      at Hardisty     at Hardisty       at Cromer
                    Exchange  Constant  Then   Constant  Then   Constant  Then  Constant  Then  Constant  Then  Constant  Then
          Inflation   Rate     2004 $  Current  2004 $ Current  2004 $ Current  2004 $ Current  2004 $ Current  2004 $ Current
  Year       %     $US/$Cdn $US/bbl $US/bbl $US/bbl $US/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl $Cdn/bbl
-----------------------------------------------------------------------------------------------------------------------------------
<S>          <C>    <C>     <C>     <C>     <C>     <C>     <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>
     1993       1.8   0.775  22.56   18.46    20.81   17.03   26.81  21.94    20.44   16.73    16.20  13.26    21.49   17.59
     1994       0.2   0.732  20.62   17.18    18.99   15.82   26.67  22.22    22.17   18.47    18.03  15.02    23.17   19.30
     1995       2.2   0.729  22.03   18.39    20.41   17.04   29.03  24.23    24.92   20.80    20.70  17.28    25.98   21.69
     1996       1.6   0.733  25.78   21.99    23.95   20.43   34.46  29.39    29.47   25.13    23.52  20.06    30.60   26.10
     1997       1.6   0.722  23.79   20.61    22.14   19.18   32.14  27.85    24.43   21.17    16.63  14.41    27.37   23.72
     1998       0.9   0.675  16.38   14.42    14.57   12.83   23.13  20.36    16.63   14.64    10.73   9.45    19.25   16.95
     1999       1.7   0.673  21.72   19.29    20.05   17.81   31.17  27.69    26.84   23.84    22.14  19.67    28.62   25.42
     2000       2.7   0.673  33.45   30.22    31.38   28.35   49.33  44.56    39.02   35.25    30.26  27.34    44.18   39.91
     2001       2.6   0.646  27.99   25.97    26.27   24.37   42.47  39.40    29.86   27.70    18.26  16.94    34.02   31.56
     2002       2.2   0.637  27.40   26.08    26.25   24.99   42.37  40.33    33.44   31.83    27.91  26.57    37.27   35.48
     2003       2.8   0.721  31.93   31.07    29.74   28.93   44.88  43.66    33.01   32.11    26.99  26.26    38.60   37.55
2004 Q1 (e)     1.5   0.757  34.50   34.50    33.00   33.00   44.50  44.50    34.25   34.25    28.00  28.00    40.50   40.50
  2004 Q2       1.5   0.750  36.00   36.00    34.50   34.50   47.25  47.25    37.75   37.75    31.75  31.75    43.75   43.75
  2004 Q3       1.5   0.750  34.00   34.00    32.50   32.50   44.50  44.50    35.25   35.25    29.50  29.50    41.00   41.00
  2004 Q4       1.5   0.750  32.75   32.75    31.25   31.25   43.00  43.00    32.50   32.50    26.25  26.25    39.00   39.00
2004 Full Year  1.5   0.750  34.25   34.25    32.75   32.75   44.75  44.75    35.00   35.00    29.00  29.00    41.00   41.00
 2004 Q2-Q4     0.0   0.750  34.25   34.25    32.75   32.75   44.75  44.75    35.00   35.00    29.00  29.00    41.00   41.00
    2005        1.5   0.750  28.50   29.00    27.00   27.50   37.25  37.75    29.75   30.25    24.75  25.00    33.25   33.75
    2006        1.5   0.750  26.25   27.00    24.75   25.50   34.25  35.25    28.00   28.75    23.00  23.75    30.25   31.25
    2007        1.5   0.750  24.00   25.00    22.50   23.50   31.00  32.50    24.75   26.00    20.00  21.00    27.25   28.50
    2008        1.5   0.750  23.50   25.00    22.25   23.50   30.50  32.50    24.50   26.00    19.75  21.00    26.75   28.50
    2009        1.5   0.750  23.25   25.00    21.75   23.50   30.25  32.50    24.25   26.00    19.50  21.00    26.50   28.50
    2010        1.5   0.750  23.25   25.50    22.00   24.00   30.25  33.00    24.25   26.50    19.75  21.50    26.50   29.00
    2011        1.5   0.750  23.25   25.75    21.75   24.25   30.25  33.50    24.25   27.00    19.75  22.00    26.50   29.50
    2012        1.5   0.750  23.25   26.25    22.00   24.75   30.25  34.00    24.50   27.50    20.00  22.50    26.75   30.00
    2013        1.5   0.750  23.25   26.50    21.75   25.00   30.25  34.50    24.50   28.00    20.00  23.00    26.75   30.50
    2014        1.5   0.750  23.25   27.00    22.00   25.50   30.25  35.00    24.50   28.50    20.25  23.50    26.75   31.00
   2015+        1.5   0.750  23.25   +1.5%/yr 22.00  +1.5%/yr 30.25  +1.5%/yr 24.50   +1.5%/yr 20.25  +1.5%/yr 26.75  +1.5%/yr

</Table>

<Table>
<Caption>


                     Alberta Natural Gas Liquids
                       (Then Current Dollars)
              Spec    Edmonton   Edmonton    Edmonton
            Ethane    Propane     Butane   Propane Plus
   Year   $Cdn/bbl   $Cdn/bbl     $Cdn/bbl   $Cdn/bbl
--------------------------------------------------------
<S>           <C>     <C>        <C>        <C>
     1993       n/a     14.10    13.64      21.17
     1994       n/a     12.53    13.45      21.69
     1995       n/a     13.90    13.79      24.11
     1996       n/a     22.31    17.15      30.06
     1997       n/a     18.62    18.73      30.91
     1998       n/a     11.15    12.44      21.83
     1999       n/a     15.89    18.70      27.71
     2000       n/a     32.18    35.60      46.31
     2001       n/a     31.85    31.17      42.48
     2002       n/a     21.39    27.08      40.73
     2003       n/a     32.14    34.36      44.23
2004 Q1 (e)     n/a     33.50    36.50      45.00
  2004 Q2      22.00    36.25    39.25      47.75
  2004 Q3      22.25    33.50    36.50      45.00
  2004 Q4      23.25    32.00    35.00      43.50
2004 Full Year 22.50    33.75    36.75      45.25
 2004 Q2-Q4    22.50    33.75    36.75      45.25
    2005       18.50    25.75    28.75      38.25
    2006       17.25    23.25    25.25      35.75
    2007       16.50    20.50    22.50      33.00
    2008       16.50    20.50    22.50      33.00
    2009       16.50    20.50    22.50      33.00
    2010       17.00    21.00    23.00      33.50
    2011       17.25    21.50    23.50      34.00
    2012       17.50    21.75    24.00      34.50
    2013       18.00    22.00    24.50      35.00
    2014       18.00    22.50    24.75      35.50
   2015+                Escalate at 1.5% per year

</Table>

<Page>
                                       - 23 -


                             GILBERT LAUSTSEN JUNG ASSOCIATES LTD.
                                    NATURAL GAS AND SULPHUR
                                        PRICE FORECAST
                                    EFFECTIVE APRIL 1, 2004

<Table>
<Caption>


                                                                                          Alberta Plant Gate
                   US Gulf Coast Gas        Midwest                  ----------------------------------------------------------
                   Price @ Henry Hub        Price @      AECO-C            Spot
                                            Chicago       Spot
                  Constant      Then         Then         Then        Constant     Then
                   2004 $      Current      Current      Current       2004 $     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>
     1993         2.58        2.11         2.31         2.26          2.64        2.16        1.71        n/a         n/a
     1994         2.33        1.94         2.11         1.98          2.23        1.86        1.81        n/a         n/a
     1995         2.04        1.70         1.69         1.15          1.22        1.02        1.31        n/a         n/a
     1996         2.95        2.52         2.73         1.39          1.48        1.26        1.63        n/a         n/a
     1997         2.85        2.47         2.75         1.84          1.95        1.69        1.96        n/a         n/a
     1998         2.45        2.16         2.20         2.03          2.14        1.88        1.94        n/a         n/a
     1999         2.61        2.32         2.34         2.92          3.10        2.75        2.48        n/a         n/a
     2000         4.79        4.33         4.38         5.08          5.45        4.92        4.50        4.60        n/a
     2001         4.37        4.05         4.17         6.21          6.54        6.07        5.41        5.30        5.61
     2002         3.53        3.36         3.30         4.04          4.08        3.88        3.88        3.83        3.82
     2003         5.65        5.50         5.60         6.66          6.67        6.49        6.13        5.89        6.69
 2004 Q1 (e)      5.70        5.70         5.85         6.55          6.30        6.30        6.20        5.90        6.30
   2004 Q2        5.60        5.60         5.65         6.55          6.30        6.30        6.20        5.90        6.15
   2004 Q3        5.70        5.70         5.75         6.65          6.40        6.40        6.30        6.00        6.20
   2004 Q4        5.85        5.85         6.00         6.90          6.65        6.65        6.55        6.20        6.55
2004 Full Year    5.70        5.70         5.80         6.65          6.40        6.40        6.30        6.00        6.30
  2004 Q2-Q4      5.70        5.70         5.80         6.70          6.45        6.45        6.35        6.05        6.30
     2005         4.75        4.80         5.00         5.55          5.20        5.30        5.25        5.15        5.30
     2006         4.35        4.50         4.75         5.20          4.80        4.95        4.95        4.95        4.95
     2007         4.15        4.35         4.60         5.00          4.55        4.75        4.75        4.75        4.75
     2008         4.10        4.35         4.60         5.00          4.50        4.75        4.75        4.75        4.75
     2009         4.05        4.35         4.60         5.00          4.45        4.75        4.75        4.75        4.75
     2010         4.05        4.40         4.65         5.10          4.45        4.85        4.85        4.85        4.85
     2011         4.05        4.50         4.75         5.20          4.45        4.95        4.95        4.95        4.95
     2012         4.05        4.55         4.80         5.25          4.45        5.05        5.05        5.05        5.05
     2013         4.05        4.60         4.90         5.35          4.50        5.15        5.15        5.15        5.15
     2014         4.05        4.70         4.95         5.45          4.50        5.20        5.20        5.20        5.20
    2015+         4.05     +1.5%/yr     +1.5%/yr     +1.5%/yr         4.50     +1.5%/yr

</Table>

<Table>
<Caption>

                Saskatchewan Plant Gate                    British Columbia
                ------------------------               ------------------------
                                                                                            Alberta
                                                       CanWest      Spot        Sulphur     Sulphur
                                                        Plant       Plant        FOB        at Plant
                SaskEnergy    Spot      Sumas Spot      Gate        Gate       Vancouver     Gate
     Year        $/mmbtu     $/mmbtu     $US/mmbtu     $/mmbtu     $/mmbtu       $US/LT     $Cdn/LT
-----------------------------------------------------------------------------------------------------
<S>              <C>         <C>         <C>           <C>         <C>           <C>        <C>
     1993        1.48         2.07         1.89         1.73          2.10        30.22       -9.68
     1994        1.88         1.87         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         1.74         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         5.16         4.17         5.27          4.88        38.14       13.59
     2001        5.71         6.20         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 Q1 (e)     6.35         6.45         5.10         5.55          6.25        60.00       35.50
   2004 Q2       6.35         6.45         4.95         5.60          6.15        67.00       46.00
   2004 Q3       6.45         6.55         5.05         5.65          6.25        65.00       43.00
   2004 Q4       6.70         6.80         5.35         5.85          6.65        60.00       36.50
2004 Full Year   6.45         6.55         5.10         5.65          6.35        63.00       40.50
  2004 Q2-Q4     6.50         6.60         5.10         5.70          6.35        64.00       42.00
     2005        5.40         5.45         4.30         5.15          5.30        45.00       16.50
     2006        5.10         5.10         4.05         4.95          4.95        45.00       16.50
     2007        4.90         4.90         3.90         4.75          4.75        45.00       16.50
     2008        4.90         4.90         3.90         4.75          4.75        45.00       16.50
     2009        4.90         4.90         3.90         4.75          4.75        46.00       18.00
     2010        5.00         5.00         3.95         4.85          4.85        47.00       19.00
     2011        5.10         5.10         4.05         4.95          4.95        48.00       20.50
     2012        5.20         5.15         4.10         5.05          5.05        49.00       22.00
     2013        5.30         5.25         4.20         5.15          5.15        50.00       23.50
     2014        5.35         5.35         4.25         5.20          5.20        51.00       25.00
    2015+          Escalate at 1.5 % per year                                          +1.5%/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>
                                    - 24 -

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                               Heavy Oil
-------------------------------- -------------------------------------------- --------------------------------------------
                                                                Net Proved                                    Net Proved
                                  Net Proved    Net Probable   Plus Probable     Net Proved    Net Probable  Plus Probable
           FACTORS                  (Mbbl)        (Mbbl)          (Mbbl)           (Mbbl)        (Mbbl)         (Mbbl)
-------------------------------- -------------- -------------- -------------- -------------- -------------- --------------
<S>                              <C>            <C>            <C>            <C>            <C>            <C>
January 1, 2003                              8             11             19              0            911            911

Extensions                                  86             -4             82                             0
Improved Recovery                                           0                                            0
Technical Revisions                         28         -1,044         -1,016              0           -911           -911
Discoveries                                                 0                                            0
Acquisitions                               949          1,671          2,620                             0
Dispositions                                                0                                            0
Economic Factors                                            0                                            0
Production                                -146                          -146                             0

January 1, 2004                            925            634          1,559              0              0              0
</Table>


<Table>
<Caption>
--------------------------------  --------------------------------------------
                                           Conventional Natural Gas
--------------------------------  --------------------------------------------
                                                                  Net Proved
                                   Net Proved     Net Probable  Plus Probable
          FACTORS                    (Mbbl)          (Mbbl)        (Mbbl)
--------------------------------  -------------- -------------- --------------
<S>                               <C>            <C>            <C>
January 1, 2003                           6,693          5,875         12,568

Extensions                                1,517            794          2,311
Improved Recovery                           105            -14             91
Technical Revisions                      -3,296         -4,370         -7,666
Discoveries                                                  0
Acquisitions                             11,841          3,326         15,167
Dispositions                                                 0
Economic Factors                                             0
Production                               -2,954                        -2,954

January 1, 2004                          13,906          5,611         19,517
</Table>


Note: The previous evaluation was prepared using Canadian National Policy 2-B
reserves definitions. Under those definitions, probable reserves were adjusted
by a factor to account for the risk associated with their recovery. The
Corporation previously applied a risk factor of 50% in reporting its probable
reserves. Under current, NI 51-101, reserves definitions, estimates are prepared
such that the full proved plus probable reserves are estimated to be recoverable
(proved plus probable reserves are effectively a "best estimate"). The above
reconciliation reflects current probable reserves versus previous risk adjusted
(50%) probable reserves reported by the Corporation.

The Corporation has no unconventional reserves (Bitumen, Synthetic Crude Oil,
Natural Gas from Coal, etc.).



<Page>
                                    - 25 -

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        BEFORE TAX
                                                                                                      2003              2003
PERIOD AND FACTOR                                                                                     (M$)              (M$)
------------------------------------------------------------------------------------------------ ----------------- ----------------
<S>                                                                                              <C>               <C>
Estimated Net Present Value at December 31, 2002                                                           25,340           27,368

      Oil and Gas Sales During the Period Net of Production Costs and Royalties (1)                      (19,850)         (19,850)
      Changes due to Prices and Royalties Related to Forecast Production (2)                              (1,419)          (1,419)
      Development Costs During the Period (3)                                                              14,122           14,122
      Changes In Forecast Development Costs (4)                                                          (14,024)         (14,024)
      Changes Resulting from Extensions and Improved Recovery (5)                                           7,928            7,928
      Changes Resulting from Discoveries (5)                                                                    -                -
      Changes Resulting from Acquisitions of Reserves (5)                                                  55,590           55,590
      Changes Resulting from Dispositions of Reserves (5)                                                       -                -
      Accretion of Discount (6)                                                                             2,737            2,737
      Net Change in Income Taxes (7)                                                                          305
      Changes Resulting from Technical Reserves Revisions                                                (12,043)         (12,043)
      All Other Changes (8)                                                                                 2,008            2,008

Estimated Net Present Value as at December 31, 2003                                                        60,694           62,417
</Table>

NOTES:

(1)      Corporation 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.

(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, royalty rates, actual price received in 2003
         versus forecast, etc.


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, 2003.

SIGNIFICANT FACTORS OR UNCERTAINTIES

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.



<Page>
                                    - 26 -

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>
                                 2004    2005    2006    2007    2008     2009    2010    2011    2012    2013    2014     2015
------------------------------- ------- ------- ------- ------- -------- ------- ------- ------- ------- ------- -------- -------
<S>                             <C>     <C>     <C>     <C>     <C>      <C>     <C>     <C>     <C>     <C>     <C>      <C>
PROVED PRODUCING                   711       0       0       0        0       0       0       0       0       0        0       0

TOTAL PROVED                      2315     510       0       0        0       0       0       0       9       0        0       0

TOTAL PROVED PLUS PROBABLE        2660    3057       0       0      270       0       0     150       9       0        0       0
</Table>


<Table>
<Caption>
                                                                    10%
                                 Subtotal   Remainder    Total   Discounted
------------------------------- --------- ------------ -------- ------------
<S>                             <C>       <C>          <C>      <C>
PROVED PRODUCING                       711            0      711          678

TOTAL PROVED                          2835            0     2835         2654

TOTAL PROVED PLUS PROBABLE            6147            0     6147         5440
</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>
                                 2004    2005    2006    2007    2008     2009    2010    2011    2012    2013    2014     2015
------------------------------- ------- ------- ------- ------- -------- ------- ------- ------- ------- ------- -------- -------
<S>                             <C>     <C>     <C>     <C>     <C>      <C>     <C>     <C>     <C>     <C>     <C>      <C>
PROVED PRODUCING                   711       0       0       0        0       0       0       0       0       0        0       0

TOTAL PROVED                      2315     518       0       0        0       0       0       0      10       0        0       0

TOTAL PROVED PLUS PROBABLE        2660    3103       0       0      287       0       0     166      10       0        0       0
</Table>

<Table>
<Caption>
                                                                    10%
                                 Subtotal   Remainder    Total   Discounted
------------------------------- --------- ------------ -------- ------------
<S>                             <C>       <C>          <C>      <C>
PROVED PRODUCING                     711            0      711          678

TOTAL PROVED                        2844            0     2844         2661

TOTAL PROVED PLUS PROBABLE          6227            0     6227         5499
</Table>


<Page>
                                    - 27 -


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, 2003:

<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                      75          50.3           156           87.7           22          14.4          32          17.4
Saskatchewan                  0            0             5              5            0             0            2            2
British Columbia              0            0             0              0            0             0            0            0
TOTAL                        75          50.3           161           92.6           22          14.4          34          19.4
</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, 2003:

<Table>
<Caption>

Location                                    Gross Acres                       Net Acres                       Average WI
---------------------------------- ------------------------------- -------------------------------- -------------------------------
<S>                                <C>                             <C>                              <C>
Alberta                                        157,021                         133,543                               85%
Saskatchewan                                     3,993                           3,993                              100%
British Columbia                                13,214                           9,997                               76%
Offshore Nova Scotia                         1,293,946                       1,187,414                               92%
TOTAL                                        1,468,174                       1,334,947                               91%
</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.

The following table sets forth the expirations and work commitment for the
undeveloped lands of the Corporation, as at December 31, 2003:

<Table>
<Caption>

WORK COMMITMENTS OFFSHORE NOVA SCOTIA                               MAYFLOWER, MARAUDER, MARCONI
------------------------------------------------------------------- ----------------------------
<S>                                                                 <C>
Gross Acres                                                         1,080,881
Net Acres                                                           1,080,881
Work Expenditure Commitment                                         $55,357,000
Deposits Tendered                                                   $13,839,000
</Table>


<Page>
                                    - 28 -

The following table represents the undeveloped land of the Corporation due to
expire in 2004:

<Table>
<Caption>
                                                          Gross Undeveloped                           Net Undeveloped
                                                  ----------------------------------          ------------------------------
<S>                                               <C>                                         <C>
PROVINCE                                                        Acres                                      Acres
--------

Alberta                                                         8,320                                      6,219
British Columbia                                                  0                                          0
Saskatchewan                                                     800                                        800
Nova Scotia Offshore                                              0                                          0
TOTAL                                                           9,120                                      7,019
</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.


Subsequent to December 31, 2003, the Corporation entered into the following
contracts:

<Table>
<Caption>
                 CONTRACT                               VOLUME                 PRICE                         TERM
      ----------------------------------------- --------------------- --------------------------- --------------------------------
      <S>                                       <C>                   <C>                         <C>
      Natural Gas - Fixed Price                       2,000 gj/d             $5.95/gj (Aeco)        March 1 - March 31, 2004
      Natural Gas - Fixed Price                       2,000 gj/d             $6.14/gj (Aeco)        April 1 - October 31, 2004
</Table>


At December 31, 2003, the Corporation had the following contracts in place:

<Table>
<Caption>
                 CONTRACT                               VOLUME                 PRICE                         TERM
      ----------------------------------------- --------------------- --------------------------- --------------------------------
      <S>                                       <C>                   <C>                         <C>
      Natural Gas - Fixed Price                       2,000 gj/d             $6.53/gj (Aeco)        January 1 - March 31, 2004
      Natural Gas - Fixed Price                       1,000 gj/d             $5.68/gj (Aeco)        January 1 - January 31, 2004
      Crude Oil - Fixed Price                         275 bbl/d            $35.75 CAD/bbl WTI       January 1 - May 31, 2004
</Table>


<Page>
                                    - 29 -

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>
                                 2004    2005    2006    2007    2008     2009    2010    2011    2012    2013    2014     2015
                                ------- ------- ------- ------- -------- ------- ------- ------- ------- ------- -------- -------
<S>                             <C>     <C>     <C>     <C>     <C>      <C>     <C>     <C>     <C>     <C>     <C>      <C>
PROVED PRODUCING                     0       0      50       0        0       0       0       0       0      50      100       0

TOTAL PROVED                         0       0      50       0        0       0       0       0       0      50      100       0

TOTAL PROVED PLUS PROBABLE           0       0       0      80        0       0       0       0       0       0       30      30
</Table>

<Table>
<Caption>
                                                                    10%
                                Subtotal   Remainder    Total    Discounted
                                --------- ------------ -------- ------------
<S>                             <C>       <C>          <C>      <C>
PROVED PRODUCING                    200            0      200           96

TOTAL PROVED                        200            0      200           96

TOTAL PROVED PLUS PROBABLE          140          160      300          119
</Table>



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

<Table>
<Caption>
                                 2004    2005    2006    2007    2008     2009    2010    2011    2012    2013    2014     2015
                                ------- ------- ------- ------- -------- ------- ------- ------- ------- ------- -------- -------
<S>                             <C>     <C>     <C>     <C>     <C>      <C>     <C>     <C>     <C>     <C>     <C>      <C>
PROVED PRODUCING                     0       0      52       0        0       0       0       0       0      57      116       0

TOTAL PROVED                         0       0      52       0        0       0       0       0       0      57      116       0

TOTAL PROVED PLUS PROBABLE           0       0       0      84        0       0       0       0      34       0        0      35
</Table>


<Table>
<Caption>
                                                                    10%
                                Subtotal   Remainder    Total    Discounted
                                --------- ------------ -------- ------------
<S>                             <C>       <C>          <C>      <C>
PROVED PRODUCING                     225            0      225          106

TOTAL PROVED                         225            0      225          106

TOTAL PROVED PLUS PROBABLE           153          197      350          137
</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>
                        2004   2005   2006    2007   2008   2009   2010   2011   2012    2013   2014   2015
                       ------ ------ ------ ------- ------ ------ ------ ------ ------ ------- ------ ------
<S>                    <C>    <C>    <C>    <C>     <C>    <C>    <C>    <C>    <C>    <C>     <C>    <C>
Undiscounted             0      0      0    1,172    565     0    1,313    0      0      0       0      0
Discounted at 10%        0      0      0     881     392     0     773     0      0      0       0      0
</Table>

<Table>
<Caption>
                           Subtotal              Remainder                  Total
                       --------------- ----------------------------- -------------------
<S>                    <C>             <C>                           <C>
Undiscounted               3,051                  7,085                    10,136
Discounted at 10%          2,045                  2,554                    4,599
</Table>


<Page>
                                    - 30 -

TAX HORIZON

The Corporation does not expect to be cash taxable in 2004.

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                          $53,400
Property Acquisitions - Unproved Properties                        $2,085
Exploration Costs                                                  $19,311
Development Costs                                                  $9,199
</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,
2003:

<Table>
<Caption>
                                       Development Wells                Exploration Wells                    Total Wells
                                -------------------------------- --------------------------------- --------------------------------
                                    Gross             Net             Gross             Net             Gross            Net
                                --------------- ---------------- ---------------- ---------------- ---------------- ---------------
<S>                             <C>             <C>              <C>              <C>              <C>              <C>
Oil Wells                             6               5.1               1                1                7              6.1
Natural Gas Wells                     3                3                5                4                8               7
Service Wells                         0                0                0                0                0               0
Dry Holes                             0                0                2                2                2               2
Total                                 9               8.1               8                7               17              15.1
</Table>


During 2003, Canadian Superior continued to expand its inventory of undeveloped
lands in western Canada. In addition to increasing its prospect inventory, the
Corporation evaluated a number of production acquisition opportunities with a
view to increasing its exposure in areas of year round accessibility. The result
of this process was the acquisition in early 2003 (effective October 1, 2002) of
a producing property in the Drumheller, Alberta area. See "GENERAL DEVELOPMENT
OF THE BUSINESS -  HISTORY", "SIGNIFICANT ACQUISITION" and "NARRATIVE
DESCRIPTION OF THE BUSINESS - OIL AND GAS PROPERTIES AND WELLS - DRUMHELLER,
ALBERTA AREA ASSETS".

This acquisition, in addition to comprising approximately 2,600 boe/d of
production and adding approximately 4.2 million boe to the Corporation's proved
reserves, includes 74,326 gross acres of undeveloped lands together with
gathering and processing infrastructure covering the properties.

To date, the Corporation has identified approximately 30 drilling prospects on
the Drumheller lands, in addition to the 13 wells drilled in 2003. In 2004, the
Corporation intends to establish a program to develop and increase production in
the Drumheller area which will provide a stable production base and cash flow
which, in addition to funding the Drumheller development, will provide a source
of funding for exploration and development in more high impact areas.

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

1.       Pursue balanced capital programs focused on development of recently
         acquired properties which can be developed at relatively low cost and
         which can utilize existing infrastructure;

2.       Pursue high impact exploration plays that offer maximum returns for
         shareholders;

3.       Allocate capital to projects and activities that provide potential for
         strong rates of return;

<Page>
                                    - 31 -

4.       Leverage the Corporation's reach in high risk, high impact exploration
         plays through industry participation;

5.       Increase efficiencies and reduce operating costs;

6.       Pursue property acquisitions to strengthen existing core areas and
         establish new core growth areas; and

7.       Utilize expertise developed in conjunction with our offshore activities
         to evaluate and pursue other international opportunities.

<Page>
                                    - 32 -

PRODUCTION ESTIMATES

The following tables present a forecast of the Corporation's production by
product type in the first year of forecast. Production for properties which
individually account for 20 percent or more of the Corporation's forecast
production (total proved plus probable reserves, boe basis) in the first year of
forecast has been identified separately in these tables.

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

<Table>
<Caption>
                                                 2004 Average Daily Production
                          ----------------------------------------------------------------------------
                            Light and                                    Natural Gas
                            Medium Oil      Heavy Oil      Natural Gas     Liquids      Oil Equivalent
                          -------------- --------------- -------------- --------------- --------------
                           W.I.    Net    W.I.    Net     W.I.    Net    W.I.    Net     W.I.    Net
                          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               56     50       0       0    1503   1139       0       0     306    240
Drumheller                   265    237       0       0    1782   1396      23      17     585    486

Other Properties             156    125       0       0    7201   5383      91      60    1448   1082
                          ------- ------ ------- ------- ------- ------ ------- ------- ------- ------
Proved Producing             477    413       0       0   10486   7918     114      76    2339   1809

TOTAL PROVED
Craigmyle- Chain              56     50       0       0    2527   1871       0       0     477    362
Drumheller                   325    290       0       0    2024   1564      29      20     691    571

Other Properties             156    125       0       0    7274   5447      91      60    1460   1093
                          ------- ------ ------- ------- ------- ------ ------- ------- ------- ------
Total Proved                 537    466       0       0   11826   8882     120      80    2628   2026

TOTAL PROVED PLUS PROBABLE
Craigmyle-Chain               57     51       0       0    3065   2248       0       0     567    426
Drumheller                   327    291       0       0    2040   1576      29      21     696    574
Other Properties             181    146       0       0    7612   5681      96      63    1545   1156
                          ------- ------ ------- ------- ------- ------ ------- ------- ------- ------

Total Proved Plus Probable   564    489       0       0   12718   9505     125      83    2809   2156
</Table>


<Table>
<Caption>
                                                            Reserves
                          -----------------------------------------------------------------------------
                            Light and                                      Natural Gas
                            Medium Oil       Heavy Oil     Natural Gas       Liquids     Oil Equivalent
                          --------------- -------------- --------------- --------------- --------------
                           W.I.    Net     W.I.    Net    W.I.    Net     W.I.    Net     W.I.   Net
                           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              120     113       0      0    3334    2662       0       0    675     557
Drumheller                   524     477       0      0    3462    2931      58      45   1158    1010

Other Properties             163     140       0      0    8722    7003     114      74   1730    1381
                          ------- ------- ------- ------ ------- ------- ------- ------- ------ -------
Proved Producing             806     729       0      0   15519   12596     171     119   3564    2948

TOTAL PROVED
Craigmyle- Chain             120     113       0      0    3866    3062       0       0    764     623
Drumheller                   756     685       0      0    4020    3327      71      54   1497    1294

Other Properties             163     140       0      0    9667    7793     121      79   1895    1518
                          ------- ------- ------- ------ ------- ------- ------- ------- ------ -------
Total Proved                1039     938       0      0   17553   14182     192     133   4156    3435

TOTAL PROVED PLUS PROBABLE
Craigmyle-Chain              146     138       0      0    4632    3667       0       0    918     749
Drumheller                  1441    1277       0      0    5410    4381     101      76   2444    2083
Other Properties             211     183       0      0   14863   11892     191     126   2879    2291
                          ------- ------- ------- ------ ------- ------- ------- ------- ------ -------

Total Proved Plus Probable  1798    1597       0      0   24905   19940     293     202   6242    5123
</Table>


<Page>
                                    - 33 -

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


<Table>
<Caption>
                                                 2004 Average Daily Production
                          ----------------------------------------------------------------------------
                            Light and                                    Natural Gas
                            Medium Oil      Heavy Oil      Natural Gas     Liquids      Oil Equivalent
                          -------------- --------------- -------------- --------------- --------------
                           W.I.    Net    W.I.    Net     W.I.    Net    W.I.    Net     W.I.    Net
                          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               56     50       0       0    1503   1139       0       0     306    240
Drumheller                   265    237       0       0    1781   1396      23      17     585    486

Other Properties             156    125       0       0    7201   5383      91      60    1448   1082
                          ------- ------ ------- ------- ------- ------ ------- ------- ------- ------
Proved Producing             477    412       0       0   10486   7918     114      76    2339   1808

TOTAL PROVED
Craigmyle-Chain               56     50       0       0    2527   1871       0       0     477    362
Drumheller                   325    289       0       0    2024   1564      29      20     691    571

Other Properties             156    125       0       0    7274   5447      91      60    1460   1093
                          ------- ------ ------- ------- ------- ------ ------- ------- ------- ------
Total Proved                 537    465       0       0   11825   8882     120      80    2628   2025

TOTAL PROVED PLUS PROBABLE
Craigmyle-Chain               57     51       0       0    3065   2248       0       0     567    426
Drumheller                   327    291       0       0    2040   1575      29      21     696    574

Other Properties             181    146       0       0    7612   5681      96      63    1545   1155
                          ------- ------ ------- ------- ------- ------ ------- ------- ------- ------
Total Proved Plus Probable   564    488       0       0   12717   9504     125      83    2808   2155
</Table>


<Table>
<Caption>
                                                            Reserves
                          -----------------------------------------------------------------------------
                            Light and                                      Natural Gas
                            Medium Oil       Heavy Oil     Natural Gas       Liquids     Oil Equivalent
                          --------------- -------------- --------------- --------------- --------------
                           W.I.    Net     W.I.    Net    W.I.    Net     W.I.    Net     W.I.   Net
                           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              117     110       0      0    3318    2649       0       0    670     552
Drumheller                   522     477       0      0    3458    2927      57      45   1156    1010

Other Properties             156     134       0      0    8419    6738     113      74   1672    1331
                          ------- ------- ------- ------ ------- ------- ------- ------- ------ -------
Proved Producing             795     721       0      0   15195   12314     170     119   3498    2892

TOTAL PROVED
Craigmyle-Chain              117     110       0      0    3851    3048       0       0    758     618
Drumheller                   749     681       0      0    4014    3322      71      54   1489    1289

Other Properties             156     134       0      0    9373    7536     120      79   1839    1469
                          ------- ------- ------- ------ ------- ------- ------- ------- ------ -------
Total Proved                1022     925       0      0   17237   13906     191     133   4086    3376

TOTAL PROVED PLUS PROBABLE
Craigmyle-Chain              144     136       0      0    4602    3641       0       0    910     742
Drumheller                  1407    1251       0      0    5360    4345     100      76   2400    2050

Other Properties             199     172       0      0   14460   11532     188     125   2798    2219
                          ------- ------- ------- ------ ------- ------- ------- ------- ------ -------
Total Proved Plus Probable  1750    1559       0      0   24422   19517     289     201   6108    5012
</Table>



<Page>

                                   - 34 -


                                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>

                                   - 35 -


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 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

<Page>

                                   - 36 -


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. 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.

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.

<Page>

                                   - 37 -


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.

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.

<Page>

                                   - 38 -


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 April
30, 2004, 107,872,850 Common Shares and Preferred Shares were outstanding. In
addition, as at April 30, 2004, the number of $3.20 Common Share purchase
warrants outstanding was 1,949,923.

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.

<Page>

                                   - 39 -


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.

WARRANTS

The Corporation has Common Share purchase warrants ("Warrants") outstanding
which were issued under the terms of a warrant indenture (the "Warrant
Indenture") dated December 16, 2003 between the Corporation and Computershare
Trust Company of Canada, as trustee. Pursuant to the Warrant Indenture, each
whole Warrant entitled the holder thereof to purchase one Common Share of the
Corporation from the date of issue of the Warrant until March 31, 2004 at a
price of $3.20 per Common Share. Any right of acquisition of a Warrant Common
Share under any Warrants that had not been exercised at 4:30 pm (Calgary
time) on March 31, 2004 will cease and terminate. On March 30, 2004, the
Corporation announced that it had extended the expiry date of 1,949,923
Warrants from March 31, 2004 to December 31, 2004. The extension does not
apply to any warrants held by officers, directors, security holders holding
in excess of 10% of the issued and outstanding securities of the Corporation
or any of their respective associates or affiliates of the Corporation. The
extension became effective at 4:29 pm (Calgary time) on March 31, 2004.

No fractional Warrant Common Shares or Warrants will be issued. The Warrants
may not be exercised, and the Warrants and Common Shares may not be offered,
sold or otherwise transferred in the United States or by or on behalf of a
U.S. person unless an exemption from the registration requirements in the
UNITED STATES SECURITIES ACT OF 1933 and applicable United States state
securities laws is available to the holder. The foregoing is a summary only
of the terms of the Warrants and is qualified by the more detailed provisions
of the Warrant Indenture.

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.

<Page>

                                   - 34 -


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% 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 TSX 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 TSX for the periods indicated.

<Table>
<Caption>
                           HIGH              LOW              CLOSE              VOLUME
                          -----             -----             -----             ---------
<S>                       <C>               <C>               <C>               <C>
January 2003              $2.05             $1.48             $1.81             7,555,264
February 2003             $1.85             $1.49             $1.54             5,260,634
March 2003                $1.68             $1.28             $1.35             4,054,557
April 2003                $1.64             $1.27             $1.48             3,885,126
May 2003                  $1.55             $1.28             $1.39              3,541651
June 2003                 $1.76             $1.24             $1.59             7,138,654
July 2003                 $0.02             $1.58             $1.88             8,901,113
August 2003               $2.38             $1.87             $1.96             5,582,336
September 2003            $2.35             $1.96             $2.06             5,214,006
October 2003              $2.99             $2.06             $2.76             8,465,447
November 2003             $3.28             $2.55             $3.05             8,050,032
December 2003             $3.48             $2.96             $3.26             7,999,357
</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 are appointed by the directors
until they resign or until their successors are appointed.

<Page>

                                     - 41 -


<Table>
<Caption>
                                                                                                        COMMON SHARES
NAME AND MUNICIPALITY OF                                    PRESENT AND PRINCIPAL OCCUPATION          BENEFICIALLY OWNED
RESIDENCE                       OFFICE OR POSITION             DURING THE LAST FIVE YEARS                     (%)
------------------------        ------------------          --------------------------------          ------------------
<S>                             <C>                         <C>                                       <C>
Leigh Bilton                    Vice President              Manager Field Operations of                      18,789
Calgary, Alberta                Operations and              Canadian Superior from 2001 to                  (0.0174%)
                                a Director                  present. Vice-President, Operations
                                                            of Canadian 88 Energy Corporation
                                                            from prior to 1998 to 2001.
                                                            Director of the Corporation
                                                            since 2002.

Charles Dallas(1)               Director                    Rancher and independent businessman.             64,444
Innisfail, Alberta                                          Director of the Corporation since 2000.         (0.0597%)

Rodney D. Erskine(1)            Director                    Chairmen and co-founder of Erskine                 nil
Calgary, Alberta                                            Energy LLC, a private oil and gas                 (0%)
                                                            exploration and development company
                                                            from April 2004 to present. Prior
                                                            thereto, President of El Paso
                                                            Production Co., a subsidiary of El Paso
                                                            Corporation from 2001 to 2004.  Prior
                                                            thereto, President of Coastal Oil & Gas
                                                            Corp. from 1997 to 2001. Director of
                                                            the Corporation as of February 25, 2004.

Thomas J. Harp(2)               Director                    President of Harp Resources Ltd., a                nil
Calgary, Alberta                                            private resources company.  Chief                 (0%)
                                                            Executive Officer of Coyote Oilfield
                                                            Rentals (Alberta) Ltd.  Director of the
                                                            Corporation since 2000.

Gerald J. Maier                 Director                    Chairman of Granmar Investments Ltd., a          40,000
Calgary, Alberta                                            private company from 1985 to present.           (0.0371%)
                                                            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.
</Table>

<Page>

                                     - 42 -


<Table>
<Caption>
                                                                                                        COMMON SHARES
NAME AND MUNICIPALITY OF                                    PRESENT AND PRINCIPAL OCCUPATION          BENEFICIALLY OWNED
RESIDENCE                       OFFICE OR POSITION             DURING THE LAST FIVE YEARS                     (%)
------------------------        ------------------          --------------------------------          ------------------
<S>                             <C>                         <C>                                       <C>
Gregory S. Noval                President and Chief         President and Chief Executive Officer           1,808,096
Turner Valley, Alberta          Executive Officer, and      of Canadian Superior from 1997 to               (1.676%)
                                a Director                  present. President and Chief Executive
                                                            Officer, Canadian 88 from 1988 to
                                                            2000. Director of the Corporation
                                                            since 1996.

J. Ronald Woods(1)              Director                    President of Rowood Capital Corp., a              6,920
Toronto, Ontario                                            private investment company.  Prior              (0.0064%)
                                                            thereto, Mr. Woods was Vice-President
                                                            of Conwest Exploration. Director of
                                                            the Corporation since 2001.

Michael E. Coolen               Vice President and          Vice President and Director, East Coast          145,000
Halifax, Nova Scotia            Director, East Coast        Operations of the Corporation from              (0.1344%)
                                Operations                  March 12, 2004 to present.  Director of
                                                            East Coast Operations of the
                                                            Corporation from July 1, 2001 to March
                                                            12, 2004.  For the fours years prior
                                                            thereto, Manager Health, Safety and
                                                            Environment, Sable Offshore Energy
                                                            Inc., under secondment from ExxonMobil
                                                            Canada and Mobil Oil Canada.
</Table>

NOTES:

(1)  Member of the audit committee of the Corporation.

(2)  Mr. Harp is a professional engineer.

As at May 13, 2004, the number of Common Shares beneficially owned directly or
indirectly or controlled by the directors and executive officers of the
Corporation, as a group, was 2,083,249 Common Shares, being 1.93% of the
outstanding Common Shares.

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 other
company that, while that person was acting in that capacity:

     (a)  was the subject of a cease trade or similar order, or an order that
          denied the other company access to any exemptions under Canadian
          securities legislation, for a period of more than 30 consecutive days;
          or
<Page>

                                     - 43 -


     (b)  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.

To the knowledge of management of the Corporation, there has been no director or
officer, or any shareholder holding sufficient number of securities of the
Corporation to affect materially the control of the Corporation, or a personal
holding company of any such person that has, within the 10 years before the date
of this annual information form, become 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 the assets of the
director or officer.

Other than described below, to the knowledge of management of the Corporation,
no director or officer, 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 Canadian securities legislation or by a Canadian securities
          regulatory authority or has entered into a settlement agreement with
          the Canadian 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.

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

A number of class action proceedings have been initiated against Canadian
Superior and certain of its directors and officers in the United States District
Court, Southern District of New York. The complainants, all of whom are
purchasers of securities of Canadian Superior, allege violations by the named
defendants of Section 10(b) and Rule 10(b)-5, and Section 20(a) of the UNITED
STATES SECURITIES AND EXCHANGE ACT OF 1934, during varied class periods between
October 22, 2003 and March 11, 2004. Specifically the complainants allege that
the named defendants made materially false and misleading statements to the
public with regard to the cost and results of the company's drilling operations
offshore Nova Scotia causing investors to suffer damages. None of the complaints
have identified the amount of damages being sought. As such, the exposure of
Canadian Superior to potential damages, if any, arising from these U.S. class
action proceedings cannot currently be estimated. Canadian Superior is of the
view that these U.S. class action proceedings are without merit and has
confirmed that it will vigorously defend these U.S. class action proceedings.

<Page>

                                     - 44 -


           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.

                               MATERIAL CONTRACTS

On December 16, 2003 Canadian Superior Energy Inc. entered into the Warrant
Indenture with Computershare Trust Company of Canada whereby the Corporation
proposed to create and issue Special Warrants, each Special Warrant entitling
the holder thereof to acquire, subject to adjustment in certain circumstances
and for no additional consideration, one Unit, each Unit consisting of one
Common Share and one-third of one Warrant. See "DESCRIPTION OF CAPITAL
STRUCTURE - WARRANTS."

                             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>

                                     - 1 -


                                   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, 2003. The reserves data consist of the following:

     (a)  (i)  proved and proved plus probable oil and gas reserves estimated as
               at December 31, 2003, 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,
               2003, 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, 2003, 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>
                                 Location of
                                   Reserves
                                 (Country or                         Net Present Value of Future Net Revenue
  Description and                  Foreign                           (before income taxes, 10% discount rate)
Preparation Date of               Geographic               --------------------------------------------------------------
 Evaluation/Report                   Area)                 Audited          Evaluated          Reviewed           Total
-------------------              -----------               -------          ---------          --------         ---------
<S>                              <C>                       <C>              <C>                <C>              <C>
  April 21, 2004                    Canada                    $0            $69,977 M             $0            $69,977 M
</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>

                                     - 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 May 10, 2004


ORIGINALLY SIGNED BY
--------------------------------------------
Dana B. Laustsen, P. Eng.


<Page>

                                     - 1 -


                                   APPENDIX B

                       REPORT OF MANAGEMENT AND DIRECTORS
                            ON OIL AND GAS DISCLOSURE

     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, or arranging 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, 2003 using forecast prices and costs; and

          (ii) the related estimated future net revenue; and

     (b)       Proved oil and gas reserves estimated as at December 31, 2003
               using constant prices and costs; and

          (i)  the related estimated future net revenue.

     Independent qualified reserves evaluators have evaluated and reviewed the
Corporation's reserves data. The report of the independent qualified reserves
evaluators is presented in Schedule A to the Annual Information Form of Canadian
Superior Energy Inc. effective as at December 31, 2003.

     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 evaluators;

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

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

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

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

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

     (f)  the content and filing of this report.


<Page>

                                     - 2 -


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

     DATED at Calgary, Alberta as of the 13th day of May, 2004.

    SIGNED "Gregory S. Noval"                      SIGNED "Leigh Bilton"
----------------------------------           ----------------------------------
o                                            o
o                                            o

    SIGNED "T.J. (Jake) Harp"                    SIGNED "Michael E. Coolen"
----------------------------------           ----------------------------------
o                                            o
o                                            o