Exhibit 1  CANADIAN
SUPERIOR ENERGY INC.   RENEWAL ANNUAL
INFORMATION FORM   (Except as otherwise noted the 
information herein is given 
as at December 31, 2002)  DATED AS OF April 30, 2003  
   TABLE OF CONTENTS FORWARD LOOKING STATEMENTSABBREVIATIONSCONVERSIONTHE CORPORATIONName and IncorporationIntercorporate
  RelationshipsGENERAL DEVELOPMENT
  OF THE BUSINESSHistoryAcquisitions and DispositionsOil and Gas Industry TrendsNARRATIVE
  DESCRIPTION OF THE BUSINESSGeneralPrincipal Oil and Gas
  PropertiesOil
  and Gas Operations, Excluding the El Paso PropertiesOil and Gas
  Operations, El Paso PropertiesReconciliation of ReservesFuture CommitmentsExploration and DevelopmentSELECTED FINANCIAL
  INFORMATIONCurrent and Annual
  InformationDividendsFINANCIAL
  STATEMENTSMANAGEMENTS
  DISCUSSION AND ANALYSISMARKET
  FOR SECURITIESDIRECTORS
  AND OFFICERSCorporate
  Cease Trade Orders or BankruptciesPenalties or SanctionsPersonal BankruptciesConflicts of InterestADDITIONAL
  INFORMATION   
   FORWARD LOOKING STATEMENTS The
corporation cautions that certain statements in this short form prospectus and
the documents incorporated by reference herein including 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, 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.  The forward-looking statements that are contained in this
document and the documents incorporated by reference herein 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. 
Some of these risks and uncertainties are identified in the managements
discussion and analysis incorporated by reference herein.  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 any documents incorporated by reference and to those that
may be discussed as part of particular forward-looking statements. ABBREVIATIONS Oil and
  Natural Gas Liquids
  
  Natural
  GasBbls
  
  barrels
  
  Mcf
  
  thousand
  cubic feetMBbls
  
  thousand
  barrels
  
  MMcf
  
  million
  cubic feetBcfe
  
  billion
  cubic feet equivalent
  
  Bcf
  
  billion
  cubic feetBoe/d
  
  barrels of
  oil equivalent per day
  
  Mcf/d
  
  thousand
  cubic feet per dayBopd
  
  barrels of
  oil per day
  
  MMcf/d
  
  million
  cubic feet per dayBbls/d
  
  barrels of
  oil per day
  
  M3
  
  cubic metresMMBbls
  
  million
  barrels
  
  MMBTU
  
  million
  British Thermal UnitsAPI
  
  American
  Petroleum Institute
  
  Gigajoule
  
  trillion
  joulesMSTB
  
  thousands of
  Stock Tank Barrels of oil
  
  TCF
  
  trillion
  cubic feet(oil volume
  at 60o F and 14.65 PSIA)
  
  MMscf
  
  million
  standard cubic feetNgls
  
  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 10 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  CONVERSION The
following table sets forth certain standard conversions from Standard Imperial
units to the International System of units (or metric units). To Convert From
  
  To
  
  Multiplied
  ByMcf
  
  Cubic metres
  
  28.174Cubic metres
  
  Cubic feet
  
  35.494Bbls
  
  Cubic metres
  
  0.159Cubic metres
  
  Bbls oil
  
  6.290Feet
  
  Metres
  
  0.305Metres
  
  Feet
  
  3.281Miles
  
  Kilometres
  
  1.609Milometres
  
  Miles
  
  0.621Acres
  
  Hectares
  
  0.405Hectares
  
  Acres
  
  2.471Gigajoules
  
  MMBTU
  
  0.950
   
    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 its issued and outstanding
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 registered office at 3300, 421  7th Avenue S.W.,
Calgary, Alberta, T2P 4K9.  The
Corporation also 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, 2002. 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 and in the Nova Scotia offshore area. 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 April 16,
2003, Canadian Superior announced that the Canadian subsidiary of El Paso
Corporation had formally elected to farm-in and participate in the drilling and
development of the Corporations Mariner natural gas prospect offshore Nova
Scotia On April 15,
2003, Canadian Superior announced two new natural gas discoveries located on
the Corporations East Ladyfern natural gas play. On March 21,
2003, Canadian Superior announced that it had successfully completed the
acquisition of El Paso Corporations Drumheller, Alberta area oil and gas
assets (the El Paso Properties), production facilities, gas plants and
undeveloped lands located in central Alberta for approximately $53.3 million,
net of purchase price adjustments. 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  2 
    for drilling
in the Mariner block (EL 2409) were underway and that commencement of
drilling is targeted for the end of May 2003. On January 13, 2003, Canada Superior announced it
had entered into an agreement with the Canadian division of El Paso Corporation
to acquire El Pasos Drumheller area oil and gas assets, production facilities,
gas plants and undeveloped lands, effective October 1, 2002, for
approximately $59.0 million, net of purchase price adjustments. On
November 18, 2002, Canadian Superior announced that it had completed an
acquisition in northwest Alberta comprising 22 contiguous sections located
updip of the main Ladyfern gas field. 
In a subsequent announcement March 11, 2003 the Corporation
announced that an initial test well located at 07 02 92 11 W6M had been
successfully drilled by the Corporation to a total depth of 9,393 feet to
evaluate the Slave Point formation. On September
3, 2003 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 #s 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 respectively known as the Mayflower and Mariner
blocks. 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 M.E. (Mike)
Coolen as Director of east coast operations. On June 12,
2001, the Corporation announced that, in association with Geophysical Service
Incorporated (GSI) 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.  3 
    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. On
November 2, 2000, the Corporation acquired two exploration licences from
the Canada  Nova Scotia Offshore Petroleum Board.  Land parcels #4 and #5 were acquired for work expenditure bids of
$5,125,800 and $22,575,000, respectively. 
These parcels are known collectively as the Marquis block. Effective
July 1, 2000, a separation agreement between the Corporation and Canadian
88 officially recognized Canadian Superior as an independent entity.  Included in the terms of separation were:
(i) a requirement that Canadian Superior provide its own management,
administrative and operations functions; (ii) the ability for Canadian
Superior to undertake its own product marketing arrangements separate and
distinct from any Canadian 88 contract requirements; and (iii) the
granting of a right of first refusal to Canadian Superior on any farmout of
Canadian 88 lands in western Canada. On
January 4, 2000, Canadian 88 distributed to its shareholders, in the form
of a dividend, its shares of the Corporation. 
As a result of this distribution, Canadian 88 no longer held a
controlling position in the Corporation. Significant Acquisitions On
March 21, 2003, Canadian Superior announced that it had successfully completed
the acquisition of El Paso Corporations Drumheller, Alberta area oil and gas
assets, production facilities, gas plants and undeveloped lands located in
central Alberta for approximately $53.3 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).  The assets purchased include
current 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.  See General Development of the Business - History,
Narrative
Description of the Business  Principal Oil and Gas Properties  Drumheller
Asset Acquisition and Narrative Description of the Business  Oil and Gas
Operations, El Paso Properties. Oil and Gas Industry Trends The
Corporation will conduct its operations in Canada in a manner consistent with
environmental regulations as stipulated in provincial and federal
legislation.  The Corporation is
committed to meeting its responsibilities to protect the environment wherever
it operates and anticipates making increased expenditures of both a capital and
expense nature as a result of the increasingly stringent laws relating to the
protection of the environment.  However,
the Corporation does not anticipate that it will be subject to any increases in
such expenditures which, as a percentage of cash flow, will be greater than
those expected, on average, by other industry operators.  The Corporation will maintain insurance coverage
where available and financially desirable in light of risk versus cost
factors.  Unforeseen significant changes
in such areas as markets, prices, royalties, interest rates and government
regulations would have an impact on the Corporations future operating results
and/or financial condition. The oil and
gas industry has been subject to considerable price volatility over which
companies have little control, and a material decline in the price of oil
and/or natural gas could result in a significant decrease in the Corporations
future anticipated revenues.  The oil
and gas industry has inherent business risks and there is no assurance that
products can continue to be produced at economical rates or that produced
reserves will be replaced.  Fluctuations
in currency and exchange rates and changes in production volumes are daily
risks in the oil and gas industry.  4 
    NARRATIVE DESCRIPTION OF
THE BUSINESS General Competition The oil and
gas industry in Canada 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, some 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. 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 currently has a total of 43 full-time employees, including
six employees in each of the Halifax office and the Drumheller field office. Principal Oil and Gas
Properties Canadian
Superior has been working towards two parallels paths:  establishing secure cash-flow from
conventional Western Canadian oil and gas assets coupled with ongoing
exploration offshore Nova Scotia. East Coast, Offshore Nova Scotia During the
past year, Canadian Superior commenced offshore Nova Scotia exploration
activities with the drilling of the Corporations first offshore exploration
well. Canadian Superior is the fourth largest public company acreage holder in
the offshore Nova Scotia basin, where the Corporation holds four offshore
exploration licenses, totalling approximately 933,800 acres. These four
licenses are now grouped and identified as separate projects: the Marquis
Project (2 licenses); the Mariner Prospect (1 license); and the Mayflower
Prospect (1 license).  The licenses are
located close to existing Sable Island project infrastructure and to planned
infrastructure that is intended to supply gas to northeastern United States
natural gas markets.  5 
    Marquis Project (50% Working Interest, Operated) The Marquis
Project encompasses two license areas with an aggregate of approximately
112,065 contiguous acres located in shallow water depths (180 feet) in close
proximity to the existing Sable Island project producing infrastructure. In the
July to September period in 2002, Canadian Superior operated the drilling of
its first offshore exploration well, the Marquis L-35/L-35A well, with its
partner El Paso Corporation. This well, which was drilled under budget,
encountered natural gas indications in thick reservoir beds, but logging data
did not confirm sufficient commercial hydrocarbons to justify the substantial
costs required for testing and casing. El Pasos
Marquis Project involvement with Canadian Superior was formalized in April 2002
with the signing of joint venture agreements for the Marquis Project. Under the
Joint Venture Agreements Canadian Superior was carried for 50% of the initial
$32 million of expenditures incurred in the drilling of the Marquis L-35/L-35A
well. El Paso has participated in the creation of an joint venture technical
team consisting of four Canadian Superior staff and three El Paso staff, housed
in Canadian Superiors East Coast offices in Halifax, Nova Scotia. Although the
Corporations first offshore exploration well was not a commercial success, the
drilling confirmed the Jurassic, Abenaki Reef style play exists on Canadian
Superiors Marquis Project license acreage and 
provides important data that directly points towards the next drilling
location expected to be drilled in the next year. Canadian
Superior and El Paso Corporation plan to further delineate and define the next
planned Marquis well location through the acquisition of a 3D seismic survey.
The next Marquis well location will be structurally up-dip from the Marquis
L-35/L35-A well in an identified porous reef trap. Mariner Prospect (100% Working Interest, subject to Farm-in, Operated) The Mariner
Prospect was acquired at a Canada-Nova Scotia Offshore Petroleum Board Land
Sale in November, 2001 based on seismic data acquired by Canadian Superior.
This prospect covers 101,835 acres. Canadian Superior and El Paso jointly
acquired a large high-density seismic density set for the purpose of
determining a drillable feature on the Mariner Prospect in late 2002. This
newly acquired data, consisting of 2,200 kilometres of high-resolution seismic,
combined with the existing seismic data was processed and interpreted in detail
to confirm the Mariner Prospect viability. The interpretation yielded three
distinct drilling targets. On April 16,
2003 El Paso formally committed to farm-in and participate in the drilling of
this first Mariner Prospect well location. El Paso is providing Canadian
Superior with a 25% carried working interest in this well.  The estimated well cost is $45 million
(D&A) and $60 million completed. Canadian Superior holds an option to elect
to increase its working interest to 50% by covering one third of expenditures in
the Mariner Prospect well. Permitting,
engineering and procurement activities are well underway following the recently
received approvals of both the Canada-Nova Scotia Benefits Plan and from
Environmental Assessment. Provincial and federal guidelines for obtaining
seismic data and for drilling wells offshore Nova Scotia are stringent and
require long lead times for approval.  6 
    Mayflower Prospect (100% Working Interest, Operated) The Mayflower
Prospect exploration license, 100% owned by Canadian Superior, was acquired at
the Canada-Nova Scotia Offshore Petroleum Board Land Sale in November, 2001
based on detailed geological and seismic data assessments conducted on the
license area by the Corporations technical staff.  The Mayflower Prospect is located in the western portion of the
Scotia Basin approximately 285 miles east of Boston, Massachusetts and in close
proximity to the New England and Northeastern United States energy markets.
This Mayflower Prospect license area covers 720,000 acres. Canadian
Superior has identified, based on reprocessed seismic data, extensive basin
floor fans and turbidites confined in mini-basins by mobile salt diapers.  The Mayflower Prospect is targeting three
large deep-water structures (1,000 to 1,500 meters water depth). Canadian
Superior intends to acquire 2D and 3D seismic on the Mayflower Prospect lands
during 2003 with drilling planned for 2004. Western Canada In 2002,
Canadian Superior continued to develop its western Canada asset base focusing
on core areas in Alberta, British Columbia and Saskatchewan.  The key areas are: (a)Alberta: Ladyfern area of Northwest Alberta
as well as the Venus, Windfall, Boundary Lake and Bison Lake areas; (b)Northeastern British Columbia: Parkland,
Umbach and Altares, all in the Peace River Arch area; and (c)Saskatchewan: Frenchman Butte, Makwa, and
Bronson areas. The western
Canadian properties are concentrated in these core areas of activity in
projects ranging from low risk development to high impact, large reserves based
exploration plays. Western Canadian acreage holdings were increased to 126,020
gross acres (105,269 net acres) in 2002. 
See Oil
and Gas Operations, Excluding the El Paso Properties - Oil and Gas Reserves. During 2002,
the Corporation examined its western Canadian asset mix.  The concentration of assets in winter access
activity areas was identified as a vulnerability. Scheduled winter access
programs had the potential to be deferred significantly if freeze-up conditions
were not present in normally expected time periods. As a direct result of this
examination process, the Corporation focused on evaluating production and land
purchases to establish a new base of assets located in year-round accessible
activity areas. This process resulted in the acquisition of El Pasos
Drumheller area assets early in 2003 See Principal Oil and Gas Properties - Drumheller Asset
Acquisition As at December
31, 2002, the value of the Corporations western Canadian assets including the
Drumheller assets acquired, was approximately $89 million. The Drumheller
acquisition increases the Corporations western Canadian land holdings to
290,430 gross acres (206,325 net acres) with a high average working interest of
over 70%. Canadian Superior currently expects to achieve a 2003 exit rate
production target of 5,000 boe/d.  7 
    Alberta East Ladyfern (75-100% Working Interest, Operated) Canadian
Superior has assembled an acreage position of approximately 14,080 gross acres
of lands in the Ladyfern area. A portion of these lands (6,400 acres) were
acquired at the Government of Albertas November 13, 2002 Alberta Petroleum and
Natural Gas Land Sale for a total purchase price of $1,249,740 ($195 per acre).
The Corporations East Ladyfern play is located in northwest Alberta, 65 miles
east of Fort St. John, British Columbia, up-dip from the main Ladyfern
producing gas field. Detailed proprietary seismic was acquired by Canadian
Superior to evaluate these lands for purchase and to facilitate the choice of
the first four drilling locations. Several major Slave Point amplitude
anomalies analogous to the main Ladyfern gas field have been identified through
seismic on the lands. During 2002,
Canadian Superior initiated the detailed preparations for the drilling of East
Ladyfern area wells. Drilling and casing of two of the four planned East
Ladyfern well locations occurred in the first quarter of 2003. The first two
drilled exploration wells are Slave Point natural gas discoveries.  Planning is proceeding for the drilling of
two additional wells in 2003, followed by a multi-well program to develop this
newly discovered field. Since East Ladyfern is a winter access only area, the
Corporation intends to fully evaluate and test two discovery wells in the next
drilling season.  Pipeline and
facilities applications required to construct the infrastructure necessary to
tie-in the first two gas wells have been submitted. The recently
discovered East Ladyfern reserves have not been included in the Corporations
year-end reserves or in the year-end Net Asset Value calculation. Canadian
Superior holds a 75% operated working interest in the first two wells and El
Paso has farmed-in and participated to earn 25%. Venus (100% Working Interest & Farm-in, Operated) During 2002,
several exploration wells were drilled and completed.  Initial production of up to 10 mmcf/d was tested from one well
and subsequently this well was placed on production at an average rate of 2.0
mmcf/d for a period of 4 months. 
Subsequent to this, production from the well declined with associated
water which has presented challenges from a water disposal standpoint. The
Corporation hopes to address the water disposal problem next winter in this
winter access only area.  Canadian
Superior is evaluating the viability of other wells coming onstream and has
negotiated a farm-in to drill another well up-dip on the Slave Point reef
trend. Canadian Superior has increased its acreage holdings to 14,784 gross
acres of lands in the Venus area of Alberta. Windfall (100% Working Interest, Operated) Canadian
Superior has increased is holdings to approximately 5,920 acres in the Windfall
area south of Edson. During 2002, two additional wells were drilled and placed
on production. Production averaged 2.3 mmcf/d and 48 bbls of ngls in December
2002. Facilities and pipeline balancing, coupled with zone completions in these
wells are underway to maximize production. Following the interpretation of
recently acquired seismic, a three well development program is planned for
2003.  In addition, recent seismic
interpretation has indicated a deeper oil bearing objective that may result in
an exploration well being drilled in 2003. Other Alberta Activity Areas In the
Boundary Lake area of northwestern Alberta, Canadian Superior successfully
drilled and cased three wells (net 50% Working Interest, operated) with a
partner, Husky Oil. Two of these wells were placed  8 
    onstream in
2002, with an average production rate of 1.25 mmcf/d over a 5 month period.
During 2002, Canadian Superior increased its acreage position in this area to a
total of 12,480 gross acres (9,504 net acres). Approximately 6,500 acres of
Boundary Lake acreage is 100% owned by the Corporation. Additional seismic has
been acquired, a deeper oil target has been identified, and additional wells
are planned for 2003. In the Bison
Lake area in north central Alberta (100% Working Interest, operated), Canadian
Superior expanded its land holdings and continued development of multi-zone
shallow targets during 2002 and into the first quarter of 2003. Canadian
Superior now has operated land holdings totalling 26,240 acres. Production from
the Bison Lake area averaged 1.5 mmcf/d over an 8 month period in 2002.
Additional wells may be drilled to examine the Wabamun potential on these
lands. In the
Twinning area in central Alberta (50% Working Interest, operated), the
Corporation continues to produce from two wells at an average of 425 mcf/d plus
14 bbls of ngls (net) during 2002. Drumheller Asset Acquisition On March 20,
2003 Canadian Superior closed the acquisition of assets located in the
Drumheller area of central Alberta.  The
unadjusted purchase price was approximately $65 million. The effective date for
adjustments was October 1, 2002. 
Primarily as a result of high commodity prices during the period between
the October 1, 2002 effective date and the March 20, 2003 closing date, the net
closing price was $53.5 million. The Drumheller
area asset acquisition is a strategic purchase that establishes a year-round
access core area with multiple prospects for oil and natural gas. At
acquisition, the purchase added approximately 2,600 boe/d of sweet gas and
light oil to the Corporations production base, approximately 4.2 million boe
to the Corporations proved reserves and approximately 5.5 million boe to the
Corporations established reserves. In
addition the purchase includes 170,000 gross acres  (106,693 net acres) of land, access to extensive seismic data,
and key infrastructure interests (three gas plants, three oil batteries, 20
production facilities and 130 kilometres of company-operated pipelines). British Columbia In northeast
British Columbia, Canadian Superior has land holdings that cover 13,938 gross
acres (10,745 net acres). Parkland (100% Working Interest, operated) In Parkland,
south of Ft. St John, the Corporation holds 5,120 acres of 100% owned lands. A
successfully drilled well is expected to be completed and production tested in
2003.  Further development drilling is
planned for this area. Umbach  (62.5% Working Interest,
operated) At Umbach,
north of Fort St. John, Canadian Superior operates one well that averaged in
excess of 250  mcf/d of natural gas and
6.5 bbls/d of ngls over an 8 month period. The Corporation has land holdings
totalling 5,557 gross acres (3,994 net acres) and has acquired a large database
of seismic in this area.  Further land
acquisitions and possible drilling are expected in this exploration area in 2003.  9 
    Altares  (50% Working Interest,
operated) The
Corporation holds a 50% working interest in Altares, a land holding located
west of Fort St. John, British Columbia. Canadian Superior has acquired 3,200
gross acres (1,600 net acres) on this foothills over-thrust prospect. A well is
planned for drilling in late 2003 targeting the Mississippian formation on this
prospect. Saskatchewan In
Saskatchewan, Canadian Superior holds interests in 7,137 net acres.  Bronson Lake, Frenchman Butte and Makwa are
Canadian Superiors producing properties. Natural gas production from these
Saskatchewan properties averaged 675 mcf/d in 2002. Drilling opportunities on
new lands acquired during 2003 will be pursued. Oil and Gas Operations,
Excluding the El Paso Properties The following
information pertains to the oil and gas operations of the Corporation, but
excludes information pertaining to the El Paso Properties.  See General Development of the Business  Significant
Acquisitions. Oil and Gas Wells The following
table sets forth the number and status of wells in which the Corporation had a
working or a royalty interest as at December 31, 2002 which were producing
or which the Corporation considered to be capable of production. Location
  
  Producing
  
  Shut-In(1)Oil
  
  Gas
  
  Oil
  
  GasGross(2)
  
  Net(3)
  
  Gross(2)
  
  Net(3)
  
  Gross(2)
  
  Net(3)
  
  Gross(2)
  
  Net(3)Alberta
  
  2
  
  0.4
  
  22
  
  19.4
  
  1
  
  0.8
  
  15
  
  12.1Saskatchewan
  
  
  
  
  
  4
  
  4.0
  
  1
  
  1
  
  2
  
  2.0British Columbia
  
  
  
  
  
  1
  
  0.6
  
  
  
  
  
  2
  
  1.6TOTAL
  
  2
  
  0.4
  
  27
  
  24.0
  
  2
  
  1.8
  
  19
  
  15.7 
 Notes: (1)Shut-in wells means wells which
have encountered and are capable of producing crude oil or natural gas but
which are not producing due to lack of available transportation facilities,
available markets or other reasons. (2)Gross wells are defined as the total
number of wells in which the Corporation has an interest. (3)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.  Undeveloped
Lands The following
table sets out the Corporations undeveloped land holdings as at
December 31, 2002. Location
  
  Gross
  Acres(1)
  
  Net
  Acres(2)
  
  Average
  Working InterestAlberta
  
  82,304
  
  72,250
  
  87.8
  %Saskatchewan
  
  4,032
  
  4,032
  
  100.0
  %British Columbia
  
  11,909
  
  9,236
  
  77.6
  %Nova Scotia Offshore(3)
  
  933,800
  
  877,768
  
  94.0
  %Total
  
  1,032,045
  
  963,286
  
  93.3
  %   10 
   
 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.  Drilling Activity  The following
table sets forth the gross and net wells in which the Corporation participated
during the periods indicated. Year  Ended December 31, 2002
  
  Year
  Ended December 31, 2001
  
  Year
  Ended December 31, 2000Wells
  
  Gross(1)
  
  Net(2)
  
  Gross(1)
  
  Net(2)
  
  Gross(1)
  
  Net(2)Producing Oil
  
  
  
  
  
  
  
  
  
  
  
  Producing Gas
  
  13.0
  
  12.5
  
  15.0
  
  13.4
  
  3.0
  
  2.1Dry Holes
  
  4.0
  
  4.0
  
  3.0
  
  2.7
  
  
  
  TOTAL
  
  17.0
  
  16.5
  
  18.0
  
  16.1
  
  3.0
  
  2.1 
 Notes:  (1)Gross wells means the number of wells in
which the Corporation has an interest. (2)Net wells means the aggregate of the
numbers obtained by multiplying each gross well by the Corporations percentage
working interest therein.  Production History The following
table sets forth the Corporations average daily production volume before
deductions of royalties payable to others, crude oil prices, and net oil and
gas capital expenditures incurred for each of the last eight quarters and the
years then ended.  Also shown are
average annual netbacks received by product category. 2002
  
  
  
  2001Quarter
  Ended
  
  
  
  Quarter
  EndedDec.
  31
  
  Sept.
  30
  
  June
  30
  
  March
  31
  
  2002
  Total
  
  Dec.
  31
  
  Sept.
  30
  
  June
  30
  
  March
  31
  
  2001
  TotalAverage Daily Production VolumesOil and NGLs (bopd)
  
  42
  
  84
  
  54
  
  53
  
  59
  
  26
  
  15
  
  17
  
  16
  
  19Natural Gas (mcf/d)
  
  4,375
  
  6,555
  
  5,219
  
  2,716
  
  4,725
  
  2,802
  
  2,569
  
  2,557
  
  2,029
  
  2,492Total boe/d (6:1)
  
  771
  
  1,177
  
  924
  
  506
  
  846
  
  493
  
  443
  
  443
  
  354
  
  434Per Unit AmountsRealized priceOil & NGLs/bbl
  
  41.75
  
  40.61
  
  35.16
  
  23.38
  
  35.69
  
  25.39
  
  34.29
  
  42.05
  
  48.55
  
  36.03Natural gas/mcf
  
  5.51
  
  3.49
  
  3.65
  
  3.72
  
  4.04
  
  3.30
  
  3.09
  
  5.96
  
  9.78
  
  5.23Royalty/Government Share ($)Oil & NGLs/bbl
  
  15.03
  
  9.97
  
  6.92
  
  4.18
  
  8.89
  
  2.18
  
  6.65
  
  6.88
  
  10.54
  
  5.97Natural gas/mcf
  
  0.94
  
  0.94
  
  0.72
  
  1.07
  
  0.90
  
  0.38
  
  0.83
  
  1.33
  
  2.04
  
  1.07   11 
    2002
  
  
  
  2001Quarter
  Ended
  
  
  
  Quarter
  EndedDec.
  31
  
  Sept.
  30
  
  June
  30
  
  March
  31
  
  2002
  Total
  
  Dec.
  31
  
  Sept.
  30
  
  June
  30
  
  March
  31
  
  2001
  TotalOperating Costs ($)Oil & NGLs/bbl
  
  10.00
  
  8.19
  
  6.65
  
  8.50
  
  8.23
  
  11.69
  
  6.25
  
  10.35
  
  10.49
  
  9.12Natural gas/mcf
  
  1.67
  
  1.37
  
  1.11
  
  1.42
  
  1.37
  
  1.17
  
  0.62
  
  1.04
  
  1.05
  
  0.97Netbacks ($)Oil & NGLs/bbl
  
  16.72
  
  22.45
  
  21.59
  
  10.70
  
  18.57
  
  11.52
  
  21.39
  
  24.82
  
  27.52
  
  20.35Natural gas/mcf
  
  2.90
  
  1.18
  
  1.82
  
  1.23
  
  1.77
  
  1.75
  
  1.64
  
  3.59
  
  6.69
  
  3.18  Capital Expenditures  The following
table summarizes capital expenditures made by the Corporation on acquisitions,
exploration and development drilling and production facilities and other
equipment for the periods indicated.  2002
  
  
  
  2001Quarter
  Ended
  
  
  
  Quarter
  EndedDec
  31
  
  Sept.
  30
  
  June  30
  
  March
  31
  
  2002
  Total
  
  Dec.
  31
  
  Sept.
  30
  
  June
  30
  
  March
  31
  
  2001
  TotalAcquisitions (dispositions)
  
  $
  1,264
  
  1,105
  
  1,870
  
  723
  
  4,962
  
  1,831
  
  2,427
  
  1,981
  
  493
  
  6,732Exploration and Developmentincluding drilling and facilities
  
  $
  5,174
  
  15,979
  
  6,041
  
  19,331
  
  46,525
  
  9,322
  
  3,732
  
  4,381
  
  3,493
  
  20,928Other
  
  1,795
  
  1,355
  
  472
  
  (84
  )
  3,538
  
  
  
  
  
  
  
  
  
  $
  8,233
  
  18,439
  
  8,383
  
  19,970
  
  55,025
  
  11,153
  
  6,159
  
  6,362
  
  3,986
  
  27,660   Oil and Gas Reserves  Chapman
Petroleum Engineering Ltd. (Chapman) an independent petroleum engineering
firm in Calgary, Alberta, prepared a report dated March 18, 2003 which
evaluated as at January 1, 2003 the reserves of Canadian Superior and the
estimated cumulative cash flows from such reserves on a before tax basis
utilizing both escalated and constant prices and cost basis (the Chapman
Report).  These reserves do not include
the El Pas Properties. The reserve
evaluation of Canadian Superiors properties and the estimated cumulative cash
flow to be derived there from on an escalated and constant pricing and cost
basis are summarized in the following table. 
The
Chapman Report presents the estimated cumulative cash flow of Canadian
Superiors properties prior to provision for indirect cost on a before tax
(BIT) basis.  It should not be assumed
that the discounted cumulative cash flows presented below are representative of
the fair market value of the reserves. 
The reserve volumes and the present worth values of probable reserves
have been reduced by 50% by Chapman to reflect the risk associated with
recovery of these reserves.  12 
    Assumptions
and qualifications relating to costs, prices for future production and other
matters are summarized in the notes to the following tables. Canadian Superiors Reserves and Cumulative Cash Flow
Values Based on Escalated Prices and Cost Assumptions
Summary of Reserves and Economics
January 1, 2003
(including ARTC) Net
  to Appraised InterestReserves
  
  Cumulative
  Cash Flow (BIT)  M$Oil
  MSTB
  
  Sales
  Gas
  MMscf
  
  NGL
  MBbls
  
  
  
  Discounted
  at:Description
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Undisc.
  
  10%/year
  
  15%/year
  
  20%/yearProven
  Producing
  
  8
  
  8
  
  6,199
  
  4,776
  
  82
  
  55
  
  19,582
  
  15,764
  
  14,414
  
  13,304
  Non-Producing (Developed)
  
  0
  
  0
  
  2,844
  
  1,917
  
  49
  
  33
  
  7,932
  
  5,328
  
  4,572
  
  4,007Total Proven
  
  8
  
  8
  
  9,043
  
  6,693
  
  131
  
  88
  
  27,514
  
  21,092
  
  18,986
  
  17,311Probable
  
  2,234
  
  1,845
  
  15,747
  
  11,751
  
  313
  
  225
  
  60,633
  
  28,284
  
  21,674
  
  17,368Total Proven Plus Probable
  
  2,242
  
  1,853
  
  24,790
  
  18,444
  
  444
  
  313
  
  88,147
  
  49,376
  
  40,660
  
  34,679Less 50% Probable
  
  1,117
  
  923
  
  7,874
  
  5,876
  
  156
  
  112
  
  30,316
  
  14,142
  
  10,837
  
  8,684Proven Plus 50% Probable
  
  1,125
  
  931
  
  16,915
  
  12,567
  
  287
  
  200
  
  57,831
  
  35,234
  
  29,823
  
  25,995  Canadian Superiors Reserves and Cumulative Cash Flow
Values Based on Unescalated Prices and Cost Assumptions
Summary of Reserves and Economics
January 1, 2003
(including ARTC)  Net
  to Appraised InterestReserves
  
  Cumulative
  Cash Flow (BIT)  M$Oil
  MSTB
  
  Sales
  Gas MMscf
  
  NGL
  MBbls
  
  
  
  Discounted
  at:Description
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Undisc.
  
  10%/year
  
  15%/year
  
  20%/yearProven
  Producing
  
  8
  
  8
  
  6,208
  
  4,781
  
  82
  
  54
  
  25,759
  
  20,420
  
  18,550
  
  17,023
  Non-Producing (Developed)
  
  0
  
  0
  
  2,844
  
  1,915
  
  48
  
  33
  
  10,527
  
  6,948
  
  5,924
  
  5,162Total Proven
  
  8
  
  8
  
  9,052
  
  6,696
  
  131
  
  87
  
  36,286
  
  27,368
  
  24,474
  
  22,185Probable
  
  2,234
  
  1,845
  
  15,746
  
  11,530
  
  314
  
  214
  
  95,523
  
  47,335
  
  38,879
  
  29,885Total Proven Plus Probable
  
  2,242
  
  1,853
  
  24,799
  
  18,226
  
  444
  
  301
  
  131,809
  
  74,703
  
  61,353
  
  52,070Less 50% Probable
  
  1,117
  
  923
  
  7,873
  
  5,765
  
  157
  
  107
  
  47,761
  
  23,668
  
  18,440
  
  14,943Proven Plus 50% Probable
  
  1,125
  
  931
  
  16,924
  
  12,460
  
  288
  
  194
  
  84,048
  
  51,036
  
  42,914
  
  37,127    13 
   
 Notes:  (1)Reserve Definitions as follows are
considered to be materially equivalent to the definitions contained in National
Policy 2-B (proven and probable reserves), and in the SEC Regulation 20-F,
Rule 4-10 (proven reserves) with regard to the intent, interpretation and
application in establishing the classification of reserves in this report.  These reserve classification procedures also
follow the recommendations and guidelines published by the Petroleum Society of
CIM (Canada), the Society of Petroleum Evaluation Engineers (USA & Canada)
and the World Petroleum Congress. (a)Proven Producing Reserves
are those reserves which are estimated to be recoverable under the existing
depletion mechanism and under current economic and operating conditions, which
have been established by existing production. (b)Proven Non-Producing (Developed)
Reserves are those reserves which are estimated to be recoverable
under the most likely depletion mechanism, and under current economic and
operating conditions; which have been established by adequate tests and other
information on zones behind pipe in existing wells; but which are not currently
producing due to lack of facilities and/or markets, or for mechanical reasons. (c)Proven Non-Producing
(Undeveloped) Reserves are those reserves which are estimated to be
recoverable under the most likely depletion mechanism and have been identified
by geological and or geophysical control on lands that are undrilled which are
directly offset by wells having indicated commercial production in the
objective formation and it is reasonably certain the location will be
developed; or from wells that have been drilled and tested but require a
relatively large capital expenditures to place the reserves on production. (d)Probable Reserves are the
potential recoverable reserves estimated for undeveloped tracts or zones behind
pipe or incremental reserves from producing zones where the potential has been
reasonably confirmed by geological and/or geophysical control and engineering
data but where available data has been insufficient to establish proof that
these reserves would be economically recoverable under current technology and
existing market conditions. (2)Crude Oil (Oil) means a mixture
consisting mainly of pentanes and heavier hydrocarbons that may contain sulphur
compounds that is liquid at the conditions under which its volume is measured
or estimated, but excluding such liquids obtained from the processing of
natural gas. (3)Natural Gas (Gas) means the lighter
hydrocarbons and associated non-hydrocarbons substances occurring
naturally in and underground reservoir, which under atmospheric conditions is
essentially a gas, but which may contain liquids.  The natural gas reserve estimates are reported on a marketable
basis, that is the gas which is available to a transmission line after removal
of certain hydrocarbons and non-hydrocarbon compounds present in the raw
natural gas and which meets specifications for use as domestic commercial or
industrial fuel. (4)Natural Gas Liquids (NGL) means those
hydrocarbon components recovered from raw natural gas as a liquid by processing
through extraction plants or recovered from field separators, scrubbers, or
other gathering facilities.  These liquids
include the hydrocarbon components ethane, propane, butanes and pentanes plus a
combination thereof. (5)Gross Reserves are the total of the
Corporations working and/or royalty interest share before deduction of
royalties owned by others. (6)Net Reserves are the total of the Corporations
working and/or royalty interest share after deducting the amounts attributable
to royalties owned by others. (7)The escalating price report of Chapman
contained in the Chapman Report includes certain assumptions regarding future
increases in the prices of oil, natural gas and natural gas liquids as follows: CRUDE OIL PRICE FORECASTS EFFECTIVE JANURY 1, 2003  Alberta
  
  Alberta
  
  Sask.
  
  Sask.
  
  B.C.
  
  ART Credits (g)WTI (a)
  
  Par Price (b)
  
  Heavy (c)
  
  Light (d)
  
  Heavy (e)
  
  Light (f)
  
  Rate
  
  MaxDate
  
  $US/STB
  
  $CDN/STB
  
  $CDN/STB
  
  $CDN/STB
  
  $CDN/STB
  
  $CDN/STB
  
  %
  
  M$HISTORICAL PRICES1994
  
  17.16
  
  22.27
  
  18.19
  
  20.76
  
  19.16
  
  21.12
  
  n/a
  
  n/a1995
  
  18.41
  
  25.11
  
  19.76
  
  22.77
  
  20.57
  
  23.85
  
  n/a
  
  n/a1996
  
  21.98
  
  29.39
  
  25.09
  
  28.41
  
  26.07
  
  27.99
  
  n/a
  
  n/a   14 
    1997
  
  20.59
  
  27.90
  
  21.15
  
  26.52
  
  23.73
  
  26.32
  
  n/a
  
  n/a1998
  
  14.46
  
  20.39
  
  14.68
  
  19.31
  
  17.01
  
  19.38
  
  n/a
  
  n/a1999
  
  19.21
  
  27.88
  
  23.71
  
  27.23
  
  25.65
  
  27.42
  
  n/a
  
  n/a2000
  
  30.39
  
  44.90
  
  34.51
  
  43.37
  
  40.12
  
  n/a
  
  n/a
  
  n/a2001
  
  25.98
  
  39.66
  
  25.41
  
  35.57
  
  31.84
  
  n/a
  
  n/a
  
  n/a2002(e)
  
  26.00
  
  40.52
  
  31.87
  
  37.67
  
  34.57
  
  n/a
  
  n/a
  
  n/aCURRENT YEAR FORECAST2003
  
  25.00
  
  38.06
  
  30.45
  
  35.40
  
  31.86
  
  37.11
  
  25.00
  
  500FUTURE FORECAST2004
  
  24.00
  
  36.52
  
  29.22
  
  33.97
  
  30.57
  
  35.61
  
  25.00
  
  5002005
  
  23.00
  
  34.98
  
  27.99
  
  32.54
  
  29.28
  
  34.11
  
  25.00
  
  5002006
  
  23.00
  
  34.98
  
  27.99
  
  32.54
  
  29.28
  
  34.11
  
  25.00
  
  5002007
  
  23.35
  
  35.51
  
  28.41
  
  33.02
  
  29.72
  
  34.62
  
  25.00
  
  5002008
  
  23.70
  
  36.04
  
  28.83
  
  33.52
  
  30.17
  
  35.14
  
  25.00
  
  5002009
  
  24.05
  
  36.58
  
  29.27
  
  34.02
  
  30.62
  
  35.67
  
  25.00
  
  5002010
  
  24.41
  
  37.13
  
  29.71
  
  34.53
  
  31.08
  
  36.20
  
  25.00
  
  5002011
  
  24.78
  
  37.69
  
  30.15
  
  35.05
  
  31.55
  
  36.75
  
  25.00
  
  5002012
  
  25.15
  
  38.25
  
  30.60
  
  35.58
  
  32.02
  
  37.30
  
  25.00
  
  5002013
  
  25.53
  
  38.83
  
  31.06
  
  36.11
  
  32.50
  
  37.86
  
  25.00
  
  5002014
  
  25.91
  
  39.41
  
  31.53
  
  36.65
  
  32.99
  
  38.42
  
  25.00
  
  5002015
  
  26.30
  
  40.00
  
  32.00
  
  37.20
  
  33.48
  
  39.00
  
  25.00
  
  5002016
  
  26.69
  
  40.60
  
  32.48
  
  37.76
  
  33.98
  
  39.59
  
  25.00
  
  5002017
  
  27.09
  
  41.21
  
  32.97
  
  38.33
  
  34.49
  
  40.18
  
  25.00
  
  5002018
  
  27.50
  
  41.83
  
  33.46
  
  38.90
  
  35.01
  
  40.78
  
  25.00
  
  500Constant thereafter 
 Notes: (a)West Texas Intermediate
quality (D2/S2) crude landed in Cushing, Oklahoma. (b)Equivalent price for Light
Sweet Crude (D2/S2) landed in Edmonton, Alberta after exchange of 0.650
$US/$CDN and transportation charges of $0.50 CDN/STB. (c)Bow River at Hardisty,
Alberta.  (905 kg/m3, 21.0 g sulphur). (d)Light Sweet Blend at Cromer,
Saskatchewan.  (850 kg/m3, 12.0 g
sulphur). (e)Midale at Cromer,
Saskatchewan.  (880 kg/m3, 20.0 g
sulphur). (f)B.C. Light at Taylor, British
Columbia.  (825 kg/m3, 5.0 g sulphur). (g)ARTC rate ranges from 75%
maximum to 25% minimum; Crown royalty shelter, $2,000,000. NATURAL GAS & BY-PRODUCTS
PRICE FORECASTS
EFFECTIVE JANUARY 1, 2003  AECO
  Spot
  
  Sask
  
  B.C.
  
  
  
  
  
  Pentanes
  
  NGLGRP
  (a)
  
  Gas
  (NIT)
  
  Gas
  (b)
  
  Gas
  (c)
  
  Propane
  (d)
  
  Butane
  (d)
  
  Plus
  (d)
  
  Mix
  (e)
  
  SulphurDate
  
  $/MMBTU
  
  $/GJ
  
  $/MMBTU
  
  $/MMBTU
  
  $/MMBTU
  
  $/BBL
  
  $/BBL
  
  $/BBL
  
  $/BBL
  
  $/LTHISTORICAL PRICES1994
  
  1.82
  
  1.73
  
  1.78
  
  1.88
  
  1.81
  
  12.72
  
  13.44
  
  21.67
  
  15.62
  
  16.571995
  
  1.31
  
  1.24
  
  1.08
  
  1.35
  
  1.29
  
  14.38
  
  13.97
  
  24.11
  
  17.18
  
  30.071996
  
  1.63
  
  1.55
  
  1.33
  
  1.52
  
  1.50
  
  22.95
  
  17.19
  
  30.05
  
  23.35
  
  14.441997
  
  1.97
  
  1.87
  
  1.67
  
  1.84
  
  1.80
  
  17.73
  
  19.07
  
  30.90
  
  22.08
  
  11.501998
  
  1.94
  
  1.84
  
  1.94
  
  2.05
  
  1.94
  
  11.13
  
  12.06
  
  21.86
  
  14.63
  
  6.51  15 
   1999
  
  2.48
  
  2.35
  
  2.82
  
  2.83
  
  2.51
  
  15.93
  
  18.01
  
  27.73
  
  20.09
  
  6.932000
  
  4.50
  
  4.27
  
  5.56
  
  4.85
  
  4.00
  
  31.38
  
  35.01
  
  46.35
  
  36.96
  
  15.002001
  
  5.78
  
  5.48
  
  5.44
  
  5.48
  
  6.12
  
  31.27
  
  30.27
  
  44.98
  
  35.08
  
  6.202002(e)
  
  3.89
  
  3.69
  
  4.04
  
  4.07
  
  3.85
  
  19.14
  
  25.11
  
  40.72
  
  27.41
  
  2.02CURRENT YEAR FORECAST2003
  
  5.00
  
  4.74
  
  5.40
  
  5.15
  
  5.00
  
  19.03
  
  22.84
  
  38.44
  
  26.00
  
  10.00FUTURE FORECAST2004
  
  4.75
  
  4.50
  
  5.00
  
  4.85
  
  4.75
  
  18.26
  
  21.91
  
  36.89
  
  24.95
  
  10.002005
  
  4.50
  
  4.27
  
  4.70
  
  4.60
  
  4.50
  
  17.49
  
  20.99
  
  35.33
  
  23.89
  
  10.002006
  
  4.50
  
  4.27
  
  4.70
  
  4.60
  
  4.50
  
  17.49
  
  20.99
  
  35.33
  
  23.89
  
  10.002007
  
  4.50
  
  4.27
  
  4.70
  
  4.60
  
  4.50
  
  17.75
  
  21.31
  
  35.86
  
  24.25
  
  10.002008
  
  4.57
  
  4.33
  
  4.77
  
  4.67
  
  4.57
  
  18.02
  
  21.63
  
  36.40
  
  24.62
  
  10.002009
  
  4.64
  
  4.39
  
  4.84
  
  4.74
  
  4.64
  
  18.29
  
  21.95
  
  36.95
  
  24.99
  
  10.002010
  
  4.71
  
  4.46
  
  4.91
  
  4.81
  
  4.71
  
  18.57
  
  22.28
  
  37.50
  
  25.36
  
  10.002011
  
  4.78
  
  4.53
  
  4.99
  
  4.88
  
  4.78
  
  18.84
  
  22.61
  
  38.07
  
  25.74
  
  10.002012
  
  4.85
  
  4.60
  
  5.06
  
  4.96
  
  4.85
  
  19.13
  
  22.95
  
  38.64
  
  26.13
  
  10.002013
  
  4.92
  
  4.66
  
  5.14
  
  5.03
  
  4.92
  
  19.41
  
  23.30
  
  39.22
  
  26.52
  
  10.002014
  
  4.99
  
  4.73
  
  5.22
  
  5.11
  
  4.99
  
  19.70
  
  23.65
  
  39.80
  
  26.92
  
  10.002015
  
  5.07
  
  4.80
  
  5.29
  
  5.18
  
  5.07
  
  20.00
  
  24.00
  
  40.40
  
  27.32
  
  10.002016
  
  5.15
  
  4.88
  
  5.37
  
  5.26
  
  5.15
  
  20.30
  
  24.36
  
  41.01
  
  27.73
  
  10.002017
  
  5.22
  
  4.95
  
  5.45
  
  5.34
  
  5.22
  
  20.61
  
  24.73
  
  41.62
  
  28.15
  
  10.002018
  
  5.30
  
  5.02
  
  5.54
  
  5.42
  
  5.30
  
  20.91
  
  25.10
  
  42.25
  
  28.57
  
  10.00Constant thereafter 
 Notes:  (a)Gas Reference Price (GRP)
represents the average of all system and direct (spot and firm) sales. (b)Price paid at field delivery
point. (c)Price paid by CanWest Gas
Supply Inc. net of raw gas gathering and processing charges but before
deduction of field gathering and compression charges (d)Reference point is FOB
Edmonton for fractionated product. (e)Natural Gas Liquids blended
mix price assuming typical liquid composition of 40% propane, 30% butane and
30% pentanes plus. (8)Net production revenue is income derived
from the sale of net reserves, less all capital costs, production taxes,
royalties and operating costs and before provision for income taxes and
administrative overhead costs. (9)Alberta Royalty Tax Credits (ARTC)  The forecast Alberta Royalty Tax Credit (ARTC)
rate and maximum reimbursement has been prepared based on the Government of
Alberta Information Letter 95-9, dated February 15, 1995, effective
January 1, 1995.  The ARTC is based
on a formula keyed to the average Par Price for Alberta crude, and the
Alberta Gas Reference Price.  The ARTC
rate refers to the percentage of royalty payments to be reimbursed.  This rate is also utilized in determining
the maximum annual reimbursement to be made to each company as a percentage of
reference maximum. As specified
in Information Letter 95-9, the reference maximum, which applies to a
total corporation or group of associated corporations has been changed from
$2,500,000 to $2,000,000 per year and the maximum percentage changed from 85%
to 75%.  Under the Par Price forecast
utilized in this report the calculated rate and maximum annual reimbursement is
less than the maximum stated in the policy. In accordance
with the policy the Provincial Government announced in 1998 that it was
considering changes to the ARTC to be introduced, at the earliest, at
January 1, 2001.  The Government
staff has recently indicated to Chapman that a number of changes were proposed
but only two passed first reading. 
These proposed changes have been revoked and the policy will be continued
as before still with a three-year rolling term.  It is evident that the Provincial Government is in favor of
continuing the incentive for small explorers. 
Given that there was an opportunity to make changes and no changes were
made, it is Chapmans position that the existing policy will be maintained,
indefinitely. Production
which is acquired from an operator who fully utilizes its ARTC does not qualify
for ARTC for the purchaser.  16 
   These values
include the full effect of the ARTC credit, where applicable, since the
Corporations full rebate does not exceed the maximum allowed, and the most
recent royalty and incentive policies of the applicable provincial, state and
local governments in Canada and the USA, details of which are given in the
scope of this report. (10)Capital expenditures and operating costs
are escalated at 1.5% per year until 2018 then held constant. (11)For the
Unescalated Case we have utilized the December 31, 2002 posted prices for oil
and gas and have held them constant throughout. The posted prices are: Oil:          WTI  US $31.23/STB
(Edmonton Par  CDN $48.93/STB)
Gas:        NYMEX  US $4.60/Mscf (CDN
$5.86/Mscf, AECO Spot @ Plant Gate). Adjustments for crude quality, gas heating value and NGL trucking and
fractionation have still been applied throughout to the average prices to
reflect actual prices being received. (12)The $U.S./$Can. exchange rate is assumed to
be $0.650 throughout the period of the Chapman Report.  Oil and Gas Operations, El Paso Properties The following
information pertains solely to the El Paso Properties.  See General Development of the Business  Significant
Acquisitions and Narrative Description of the Business  Principal
Oil and Gas Properties  Drumheller Asset Acquisition. El Paso Oil and Gas Wells The following
table sets forth the number and status of wells acquired as part of the El Paso
properties in which the Corporation had a working or a royalty interest as at
December 31, 2002 which were producing or which the Corporation considered
to be capable of production. Location
  
  Producing
  
  Shut-In(1)Oil
  
  Gas
  
  Oil
  
  GasGross(2)
  
  Net(3)
  
  Gross(2)
  
  Net(3)
  
  Gross(2)
  
  Net(3)
  
  Gross(2)
  
  Net(3)Alberta
  
  66.0
  
  44.4
  
  134.0
  
  63.8
  
  33.0
  
  21.0
  
  28.0
  
  12.5 
 Notes: (1)Shut-in wells means wells which
have encountered and are capable of producing crude oil or natural gas but
which are not producing due to lack of available transportation facilities,
available markets or other reasons. (2)Gross wells are defined as the total
number of wells in which the Corporation has an interest. (3)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.  El Paso Undeveloped Lands  The following
table sets out the Corporations undeveloped land holdings acquired as part of
the El Paso properties as at December 31, 2002. Gross
  Acres(1)
  
  Net
  Acres(2)
  
  Average
  Working InterestAlberta
  
  80,000
  
  64,000
  
  80
  %   17 
    
 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 value of
the 64,000 net acres (80,000 gross) of undeveloped land holdings is estimated
by the Corporation to be $5 million.  El Paso Production History  The following
table sets forth the Corporations average daily production volume of the El
Paso properties before deductions of royalties payable to others, crude oil
prices, and net oil and gas capital expenditures incurred for each of the last
eight quarters and the years then ended. 
Also shown are average annual netbacks received by product
category. 2002
  
  2001Quarter
  Ended
  
  Quarter
  EndedDec.
  31
  
  Sept.
  30
  
  June  30
  
  March
  31
  
  2002
  Total
  
  Dec.
  31
  
  Sept.
  30
  
  June
  30
  
  March
  31
  
  2001
  TotalAverage Daily Production VolumesOil and NGLs (bopd)
  
  753
  
  810
  
  853
  
  935
  
  837
  
  951
  
  1,071
  
  1,002
  
  653
  
  921Natural Gas (mcf/d)
  
  11,220
  
  8,956
  
  8,778
  
  8,821
  
  9449
  
  10,018
  
  12,147
  
  12,833
  
  10,064
  
  11,266Total Boe/d (6:1)
  
  2,623
  
  2,303
  
  2,316
  
  2,405
  
  2441
  
  2,619
  
  3,096
  
  3,141
  
  2,330
  
  2,799Per Unit AmountsRealized priceOil & NGLs/bbl
  
  37.25
  
  38.07
  
  34.93
  
  27.79
  
  34.26
  
  22.56
  
  33.19
  
  34.79
  
  35.43
  
  31.24Natural gas/mcf
  
  5.68
  
  3.31
  
  4.19
  
  3.49
  
  4.27
  
  3.36
  
  3.29
  
  6.38
  
  9.60
  
  5.57Royalty/Government Share ($)Oil & NGLs/bbl
  
  7.71
  
  6.23
  
  5.74
  
  4.67
  
  6.01
  
  4.52
  
  6.02
  
  6.95
  
  6.41
  
  5.95Natural gas/mcf
  
  1.32
  
  0.83
  
  0.96
  
  0.73
  
  0.98
  
  0.73
  
  0.94
  
  1.66
  
  2.48
  
  1.44Operating Costs ($)Oil & NGLs/bbl
  
  4.95
  
  5.10
  
  6.16
  
  5.26
  
  5.35
  
  4.62
  
  4.73
  
  3.02
  
  4.48
  
  4.17Natural gas/mcf
  
  0.83
  
  0.85
  
  1.03
  
  0.88
  
  0.89
  
  0.77
  
  0.79
  
  0.50
  
  0.75
  
  0.70Netbacks ($)Oil & NGLs/bbl
  
  24.59
  
  26.74
  
  23.03
  
  17.86
  
  22.90
  
  13.42
  
  22.24
  
  24.82
  
  24.54
  
  21.12Natural gas/mcf
  
  3.53
  
  1.63
  
  2.20
  
  1.88
  
  2.40
  
  1.86
  
  1.56
  
  4.22
  
  6.37
  
  3.43  El Paso Oil and Gas Reserves Gilbert
Laustsen Jung Associates Ltd. (GLJ), an independent petroleum engineering
firm in Calgary, Alberta, prepared a report dated January 20, 2003 which
evaluated as at October 1, 2002 the reserves of the El Paso properties and
the estimated cumulative cash flows from such reserves on a before tax basis
utilizing both escalated and constant prices and cost basis (the GLJ Report).  18 
   The reserve
evaluation of the El Paso properties and the estimated cumulative cash flow to
be derived therefrom on an escalated and constant pricing and cost basis are
summarized in the following table. The GLJ Report presents the estimated cumulative cash
flow of the El Paso properties prior to provision for indirect cost on a
before tax (BIT) basis.  It should
not be assumed that the discounted cumulative cash flows presented below are
representative of the fair market value of the reserves. The reserve volumes
and the present worth values of probable reserves have been reduced by 50% by
GLJ to reflect the risk associated with recovery of these reserves. Assumptions
and qualifications relating to costs, prices for future production and other
matters are summarized in the notes to the following tables. El Paso Properties Reserves and Cumulative Cash Flow
Values Based on Escalated Prices and Cost Assumptions
Summary of Reserves and Economics
October 1, 2002 Net
  to Appraised InterestReserves
  
  Cumulative
  Cash Flow (BIT)  M$Oil
  MSTB
  
  Sales
  Gas MMcf
  
  NGL
  MBbls
  
  
  
  Discounted
  at:Description
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Undisc.
  
  10%/year
  
  15%/year
  
  20%/yearProven
  Producing
  
  1083
  
  975
  
  15576
  
  12160
  
  192
  
  131
  
  59657
  
  44701
  
  40257
  
  36839
  Non-Producing
  
  75
  
  69
  
  1334
  
  1054
  
  21
  
  14
  
  4529
  
  2993
  
  2525
  
  2168Total Proven
  
  1157
  
  1043
  
  16910
  
  13214
  
  212
  
  144
  
  64186
  
  47694
  
  42782
  
  39006Probable
  
  1939
  
  1668
  
  4275
  
  3367
  
  62
  
  42
  
  32681
  
  12170
  
  8215
  
  5750Total Proven Plus Probable
  
  3096
  
  2711
  
  21185
  
  16581
  
  274
  
  186
  
  96867
  
  59864
  
  50997
  
  44756Less 50% Probable
  
  969
  
  834
  
  2138
  
  1683
  
  31
  
  27
  
  16340
  
  6085
  
  4108
  
  2875Proven Plus 50% Probable
  
  2127
  
  1877
  
  19047
  
  14898
  
  243
  
  165
  
  80527
  
  53779
  
  46889
  
  41881   19 
    El Paso Properties Reserves and Cumulative Cash Flow
Values Based on Unescalated Prices and Cost Assumptions
Summary of Reserves and Economics
October 1, 2002  Net
  to Appraised InterestReserves
  
  Cumulative
  Cash Flow (BIT)  M$Oil
  MSTB
  
  Sales
  Gas MMcf
  
  NGL
  MBbls
  
  
  
  Discounted
  at:Description
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Gross
  
  Net
  
  Undisc.
  
  10%/year
  
  15%/year
  
  20%/yearProven
  Producing
  
  1134
  
  1020
  
  15814
  
  12353
  
  196
  
  133
  
  72976
  
  52463
  
  46580
  
  42125
  Non-Producing
  
  82
  
  76
  
  1349
  
  1064
  
  21
  
  14
  
  5843
  
  3724
  
  3111
  
  2653Total Proven
  
  1216
  
  1096
  
  17163
  
  13417
  
  217
  
  147
  
  78819
  
  56187
  
  49691
  
  44778Probable
  
  2007
  
  1711
  
  4322
  
  3418
  
  62
  
  42
  
  44269
  
  15908
  
  10825
  
  7699Total Proven Plus Probable
  
  3223
  
  2807
  
  21485
  
  16835
  
  279
  
  189
  
  123088
  
  72095
  
  60516
  
  52477Less 50% Probable
  
  1003
  
  855
  
  2161
  
  1709
  
  31
  
  21
  
  22135
  
  7954
  
  5413
  
  3849Proven Plus 50% Probable
  
  2220
  
  1952
  
  19324
  
  15126
  
  248
  
  168
  
  100953
  
  64141
  
  55103
  
  48628  
 Notes: (1)Reserve Definitionsas evaluated by Gilbert
Laustsen Jung Associates Ltd. (GLJ) are in accordance with the following
definitions, which meet guidelines set out by Canadian securities regulatory
authorities (National Policy 2 B): Proved Reserves:  Those reserves estimated as recoverable
under current technology and existing economic conditions in the case of
constant price and cost analyses and anticipated economic conditions in the
case of escalated price and cost analyses, from that portion of a reservoir
which can be reasonably evaluated as economically productive on the basis of
analysis of drilling, geological, geophysical and engineering data, including
the reserves to be obtained by enhanced recovery processes demonstrated to be
economic and technically successful in the subject reservoir. Probable Reserves:  Those reserves which analysis of drilling,
geological, geophysical and engineering data does not demonstrate to be proved,
but where such analysis suggests the likelihood of their existence and future
recovery under current technology and existing or anticipated economic
conditions. Probable additional reserves to be obtained by the application of
enhanced recovery processes will be the increased recovery over and above that
estimated in the proved category which can be realistically estimated for the
pool on the basis of enhanced recovery processes which can be reasonably
expected to be instituted in the future. Producing Reserves:  Those reserves that are actually on
production or, if not producing, that could be recovered from existing wells
and facilities and where the reasons for the current nonproducing status is the
choice of the owner rather than the lack of markets or some other reasons. An
illustration of such a situation is a well or zone which is capable but is
shut-in because its deliverability is not required to meet contract
commitments. If reserves are currently shut-in, the date of resumption of production
must be known with reasonable certainty. Nonproducing Reserves:  Those reserves that are not currently
producing either due to lack of facilities and/or markets. (2)Crude Oil (Oil) means a
mixture consisting mainly of pentanes and heavier hydrocarbons that may contain
sulphur compounds that is liquid at the conditions under which its volume is
measured or estimated, but excluding such liquids obtained from the processing
of natural gas.  (3)Natural Gas (Gas) means the
lighter hydrocarbons and associated non hydrocarbons substances occurring
naturally in and underground reservoir, which under atmospheric conditions is
essentially a gas, but which may contain liquids.  The natural gas reserve estimates are reported on a marketable
basis, that is the gas which is available to a transmission line after removal
of certain hydrocarbons and non hydrocarbon compounds present in the raw
natural gas and which meets specifications for use as domestic commercial or
industrial fuel.   20 
    (4)Natural Gas Liquids (NGL)
means those hydrocarbon components recovered from raw natural gas as a liquid
by processing through extraction plants or recovered from field separators,
scrubbers, or other gathering facilities. 
These liquids include the hydrocarbon components ethane, propane,
butanes and pentanes plus a combination thereof.  (5)Gross Reserves are the
total of the Corporations working and/or royalty interest share before
deduction of royalties owned by others.  (6)Net Reserves are the total
of the Corporations working and/or royalty interest share after deducting the
amounts attributable to royalties owned by others.  (7)The escalating price report of
GLJ contained in the GLJ Report includes certain assumptions regarding future
increases in the prices of oil, natural gas and natural gas liquids as follows:  PRICE FORECASTS
EFFECTIVE JANUARY 1, 2003 Alberta
  
  Alberta
  
  
  
  
  
  Natural
  Gas & By-Products Price ForecastsDate
  
  WTI(a)
  Crude Oil At Cushing Oklahoma US$/Bbl
  
  Light
  Sweet Oil (40 API, 0.3%S) at Edmonton CDN$/Bbl
  
  Bow
  River Crude Oil Stream Quality at Hardisty CDN$/Bbl
  
  Alberta
  Reference Price CDN$/MMBTU
  
  AECO-C
  Spot Gas (b) CDN$/MMBTU
  
  Propane
  (d) CDN$/Bbl
  
  Butane(d)
  CDN$/Bbl
  
  Pentanes
  Plus (d) CDN$/BblHISTORICAL PRICES1993
  
  18.46
  
  21.94
  
  16.73
  
  1.71
  
  2.26
  
  14.10
  
  13.64
  
  21.171994
  
  17.18
  
  22.22
  
  18.47
  
  1.81
  
  1.98
  
  12.53
  
  13.45
  
  21.691995
  
  18.39
  
  24.23
  
  20.80
  
  1.31
  
  1.15
  
  13.90
  
  13.79
  
  24.111996
  
  21.99
  
  29.39
  
  25.13
  
  1.63
  
  1.39
  
  22.31
  
  17.15
  
  30.061997
  
  20.61
  
  27.85
  
  21.17
  
  1.96
  
  1.84
  
  18.62
  
  18.73
  
  30.911998
  
  14.42
  
  20.36
  
  14.64
  
  1.94
  
  2.03
  
  11.15
  
  12.44
  
  21.831999
  
  19.29
  
  27.69
  
  23.84
  
  2.48
  
  2.92
  
  15.89
  
  18.70
  
  27.712000
  
  30.22
  
  44.56
  
  35.25
  
  4.50
  
  5.08
  
  32.18
  
  35.60
  
  46.312001
  
  25.97
  
  39.40
  
  27.70
  
  5.41
  
  6.21
  
  31.85
  
  31.17
  
  42.48CURRENT YEAR FORECAST2002 Q4
  
  25.50
  
  38.50
  
  29.50
  
  5.35
  
  5.65
  
  24.75
  
  27.25
  
  39.50FUTURE FORECAST2003
  
  25.50
  
  38.50
  
  29.50
  
  5.35
  
  5.65
  
  24.75
  
  27.25
  
  39.502004
  
  22.00
  
  32.50
  
  25.50
  
  4.75
  
  5.00
  
  19.75
  
  21.50
  
  33.002005
  
  21.00
  
  30.50
  
  24.50
  
  4.50
  
  4.70
  
  19.50
  
  20.50
  
  31.002006
  
  21.00
  
  30.50
  
  25.00
  
  4.65
  
  4.85
  
  19.50
  
  20.50
  
  31.002007
  
  21.25
  
  30.50
  
  25.00
  
  4.65
  
  4.85
  
  19.50
  
  20.50
  
  31.002008
  
  21.75
  
  31.00
  
  25.50
  
  4.65
  
  4.85
  
  19.75
  
  21.00
  
  31.502009
  
  22.00
  
  31.50
  
  26.00
  
  4.65
  
  4.85
  
  20.25
  
  21.50
  
  32.002010
  
  22.25
  
  32.00
  
  26.50
  
  4.70
  
  4.90
  
  20.50
  
  22.00
  
  32.502011
  
  22.50
  
  32.50
  
  27.00
  
  4.75
  
  4.95
  
  20.75
  
  22.50
  
  33.002012
  
  23.00
  
  33.00
  
  27.50
  
  4.85
  
  5.05
  
  21.00
  
  23.00
  
  33.502013
  
  23.25
  
  33.50
  
  28.00
  
  4.90
  
  5.10
  
  21.50
  
  23.50
  
  34.002014+
  
  +1.5%/yr
  
  +1.5%/yr
  
  +1.5%/yr
  
  
  
  +1.5%/yr
  
  Escalate at
  1.5% per year 
 Notes:  (a)West Texas Intermediate quality
(D2/S2) crude landed in Cushing, Oklahoma. (b)Equivalent price for Light
Sweet Crude (D2/S2) landed in Edmonton after transportation and exchange rate
adjustments. (c)Bow River at Hardisty,
Alberta.  (905 kg/m3, 21.0 g sulphur). (d)Capital expenditures and
operating costs are escalated at 1.5% per year. (e)Alberta Reference Price (ARP)
represents the average of all system and direct (spot and firm) sales. (f)Price paid at field delivery
point.  21 
    (g)Reference point is FOB
Edmonton for fractionated product.  (8)Net production revenue is
income derived from the sale of net reserves, less all capital costs,
production taxes, royalties and operating costs and before provision for income
taxes and administrative overhead costs.  (9)Alberta Royalty Tax Credits
(ARTC)
are not applicable for these properties.  (10)Capital expenditures and
operating costs are escalated at 1.5% per year.  (11)Product prices used in
constant price evaluation were the first year natural gas, oil and NGL prices
in the GLJ Report reflecting the estimated average prices expected from January
1, 2003 to December 31, 2003. The constant price assumptions assume the
continuance of current laws, regulations and operating costs in effect on the
date of the GLJ Report.  (12)The $U.S./$Can. exchange rate
is assumed to be $0.65 in 2002 and 2003, $0.66 in 2004, $0.67 in 2005 and 2006,
and $0.68 thereafter.  (13)In the escalated price case,
capital expenditures of $380,000 and $661,000 in 2002 and 2003, respectively,
and $52,000 after 2008 were scheduled in the total proved case. In the proved
plus probable case, capital expenditures of $380,000 and $3,019,000 in 2002 and
2003, respectively, $1,419,000 in 2004 and $53,000 after 2009 were scheduled.  Reconciliation of Reserves  The following
table summarizes changes in the Corporations gross reserves (net to appraised
interest) of crude oil, natural gas liquids and natural gas from
January 1, 2002 to January 1, 2003 and gives effect to the Dramheller
asset acquisition which closed March 21, 2003. 
See escalated prices tables under Narrative Description of the Business  Oil and Gas
Operations, Excluding the El Paso Properties - Oil and Gas Reserves
and Narrative
Description of the Business  Oil and Gas Operations, El Paso Properties - Oil
and Gas Reserves.  Note that
this information is based on the reserves of the El Paso properties as at
October 1, 2002, however the Corporation believes there has been no material
adverse change to the El Paso reserves information from October 1, 2002 to
January 1, 2003. Oil
  and NGLs (MBbls)
  
  Natural
  Gas (MMcf)Proven
  
  50%
  of Probables
  
  Total
  
  Proven
  
  50%
  of Probables
  
  TotalJanuary 1, 2002
  
  350
  
  1,285
  
  1,635
  
  28,586
  
  12,867
  
  41,453
  
  
  
  
  
  
  
  
  
  Production (Sales)
  
  (15
  )
  
  
  (15
  )
  (1,374
  )
  
  
  (1,374
  )Acquisitions & Dispositions(1)
  
  1,369
  
  1,000
  
  2,369
  
  16,910
  
  2,138
  
  19,048Discoveries & Extensions
  
  28
  
  130
  
  158
  
  2,730
  
  5,053
  
  7,783Revisions
  
  (224
  )
  (141
  )
  (365
  )
  (20,899
  )
  (10,046
  )
  (30,945
  )January 1, 2003
  
  1,508
  
  2,274
  
  3,782
  
  25,953
  
  10,012
  
  35,965 
 Notes:  (1)The acquisition of the
Drumheller area El Paso assets, which closed March 21, 2003, is the sole
acquisition and disposition reflected herein.   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, 2002, and in conjunction with the Drumheller acquisition, the
Corporation entered into the following contracts:  Contract
  
  Volume
  
  Price
  
  TermNatural GasFixed Price
  
  3,000 gj/d
  
  $6.46/gj
  (Aeco)
  
  April 1 
  December 31, 2003Put Option
  
  2,000 gj/d
  
  $6.50/gj
  (Aeco) 
  strike cost $0.43/gj
  
  April 1 
  December 31, 2003Crude OilFixed Price
  
  275 bbl/d
  
  $35.75
  CAD/bbl WTI
  
  June 1, 2003
   May 31, 2004   22 
    In regard to
its Nova Scotia offshore exploration licences, the Corporation and, where
applicable, its partner have a work commitment to expend the amount of its bid
on each parcel over an initial period of five years.  The Marquis Project licences were acquired for Work Commitment
Bids aggregating $27.7 million.  The
initial term of the Marquis Project licences expires on January 1,
2006.  The Mayflower prospect was
acquired for a Work Commitment Bid of $41.25 million.  The Mariner prospect was acquired for a Work Commitment Bid of
$15.51 million.  The initial terms of
the Mayflower and Mariner licences expire on January 1, 2007.  Provided that certain conditions are met
during the initial five year term, the licences may be extended to their full
nine year terms. As a condition
of the issuance of the licences, the Corporation has posted as security for the
performance of its share of work, letters of guarantee equal to 25% of its
share of its expenditure bids. Upon
completion of work, the Corporation may from time to time apply for approval of
allowable expenditures incurred and may have a portion of the performance
deposit refunded.  The portion refunded
will be equal to 25% of the approved expenditures. At
December 31, 2002, after release of funds related to the drilling of the
Marquis 235 Well, the Corporation has on deposit funds totalling $12,031,978. Exploration and
Development During 2002
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. 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. Excluding the
Drumheller lands, at the end of 2002, Canadian Superior held 1,019,318 net
acres of undeveloped land and exploration licences.  During the year, the Corporation had capital expenditures of $55
million, of which $35.5 million was allocated to exploration and development
drilling. To date, the
corporation has identified approximately 40 drilling prospects on the
Drumheller lands.  In 2003 the
corporation will establish a program to develop and increase production in the
Drumheller area which will provide a stable production base and cash flow
which, in addition to funding the Drumheller development, will provide a source
of funding for exploration and development in more high impact areas. The following
operations strategies build on and augment the successful efforts in 2003: a)Pursue balanced capital programs focused on
development of recently acquired properties which can be developed at
relatively low cost and which can utilize existing infrastructure. b)Pursue high impact exploration plays that
offer maximum returns for shareholders;  23 
   c)Allocate capital to projects and activities
that provide potential for strong rates of return; d)Leverage the Corporations reach in high
risk, high impact exploration plays through industry participation; e)Increase efficiencies and reduce operating
costs; f)Pursue property acquisitions to strengthen
existing core areas and establish new core growth areas, and; g)Utilize expertise developed in conjunction
with our offshore activities to evaluate and pursue other international
opportunities. SELECTED FINANCIAL
INFORMATION Current and Annual
Information ($ thousands
except for share and per share amounts) Year
  Ended
  December 31, 2002
  
  Year
  Ended
  December 31, 2001
  
  Year
  Ended
  December 31, 2000(Audited)
  
  (Audited)
  
  (Audited)Gross Production Revenue
  
  $
  7,741
  
  4,945
  
  4,869Income (loss) from operations
  
  $
  (48,485
  )
  (322
  )
  1,599Income (loss) from operations per share
  
  $
  (0.89
  )
  (0.01
  )
  0.07Income (loss) from operations per share  diluted
  
  $
  (0.85
  )
  (0.01
  )
  0.07Net Income (loss)
  
  $
  (28,173
  )
  8,109
  
  1,181Net income (loss) per common share
  
  $
  (0.51
  )
  0.20
  
  0.05Net income (loss) per common share  diluted
  
  $
  (0.51
  )
  0.19
  
  0.05Total Assets
  
  $
  49,956
  
  68,588
  
  31,236Total assets per common share
  
  $
  0.77
  
  1.36
  
  0.87Long term liabilities
  
  $
  411
  
  116
  
  53Future income taxes
  
  $
  5,213
  
  14,824
  
  4,344Shares outstanding
  
  65,031,673
  
  50,419,108
  
  35,832,834   24 
    Dividends  The
Corporation does not intend to pay dividends on the Common Shares in the foreseeable
future.  The future payment of dividends
will be dependent upon the financial requirements of Canadian Superior to fund
future growth, the financial condition of the Corporation and other factors the
Board of Directors of the Corporation may consider appropriate in the
circumstances. FINANCIAL STATEMENTS The
Corporations audited financial statements for the year ended December 31,
2002, which are set out in the Corporations 2002 Annual Report, are
incorporated herein by reference and form an integral part of this Annual
Information Form. MANAGEMENTS DISCUSSION
AND ANALYSIS The
Corporations Management Discussion and Analysis relating to the financial
statements for the year ended December 31, 2002, which are set out in the
Corporations 2002 Annual Report, under the heading Management Discussion and
Analysis, are incorporated herein by reference and form an integral part of
this Annual Information Form. MARKET FOR SECURITIES The common
shares of Canadian Superior are listed and posted for trading on the Toronto
Stock Exchange and the American Stock Exchange under the symbol SNG. DIRECTORS AND OFFICERS 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. Name and
  Municipality of Residence
  
  Office
  or Position
  
  Present
  and Principal Occupation
  During the Last Five Years
  
  Common
  Shares Beneficially Owned (%)Leigh Bilton(4) Calgary, Alberta
  
  Manager,
  Field Operations and a Director
  
  Manager
  Field Operations of Canadian Superior form 2001 to present.  Vice-President, Operations of Canadian 88
  Energy Corporation from prior to 1998 to 2001.  Director of the Corporation since 2002.
  
  14,654
  (0.01)%Dale G. Blue(2) Toronto, Ontario
  
  Director
  
  Retired.  Prior thereto Chairman, Chief Executive
  Officer and President, Chase Manhattan Bank of Canada from 1996 to 2001.  Director of the Corporation since 2001.
  
  Nil
  (0)%Charles Dallas Innisfail, Alberta
  
  Director
  
  Rancher and
  independent businessman.  Director of
  the Corporation since 2000.
  
  43,444
  (0.04)%   25 
    Name and
  Municipality of Residence
  
  Office
  or Position
  
  Present
  and Principal Occupation
  During the Last Five Years
  
  Common
  Shares Beneficially Owned (%)Thomas J. Harp(1)(7) Calgary, Alberta
  
  Director
  
  President of
  Harp Resources Ltd., a private resources company.  Chief Executive Officer of Coyote Oilfield Rentals (Alberta)
  Ltd.  Director of the Corporation since
  2000.
  
  Nil
  (0)%Gregory S. Noval(2)(4) Turner Valley,
  Alberta
  
  President
  and Chief Executive Officer, and a Director
  
  President
  and Chief Executive Officer of Canadian Superior from 1997 to present.  President and Chief Executive Officer,
  Canadian 88 from 1988 to 2000. 
  Director of the Corporation since 1996.
  
  3,899,551
  (4.45)%Robert A. Pilling(4)(5)Calgary, Alberta
  
  Vice
  President and Corporate Secretary, and a Director
  
  Vice-President
  and Corporate Secretary from 2000 to present.  Vice-President, Administration and Corporate Secretary,
  Canadian 88 from 1988 to 2000. 
  Director of the Corporation since 1996.
  
  206,948
  (0.23)%]Frederick T. Purich(1) Calgary, Alberta
  
  Director
  
  Independent
  businessman.  Director of the
  Corporation since 1998.
  
  229,268
  (0.26)%J. Ronald Woods(1) Toronto, Ontario
  
  Director
  
  President of
  Rowood Capital Corp., a private investment company.  Director of the Corporation since 2001.
  
  6,920
  (0.01)% 
 Notes:  (1)Member of the audit committee. (2)Member of the executive committee. (3)The compensation committee is constituted
of every member of the Board of Directors. (4)Devotes his full time to the affairs of the
Corporation. (5)Mr. Pilling is a Certified General
Accountant. (6)Mr. Axford is a professional
geologist. (7)Mr. Harp is a professional engineer. As at April
30, 2003, the number of Common Shares beneficially owned directly or indirectly
or controlled by the directors and officers of the Corporation, as a group, was
4,400,785 Common Shares, being 5.02% of the outstanding Common Shares. Corporate Cease Trade
Orders or Bankruptcies Other than as
described below, in the 10 years preceding the date of this Annual Information
Form, none of the directors, officers or insiders of the Corporation are or
have been a director or officer of any other issuer that, while acting in such
capacity, was subject to any corporate cease trade order or bankruptcies.  26 
   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. Penalties or Sanctions Other than as
described in the preceding section, none of the directors, officers or insiders
of the Corporation have been subject to any penalties or sanctions under
securities legislation.  See Directors
and Officers  Corporate Cease Trade Orders or Bankruptcies. Personal Bankruptcies None of the
directors, officers or insiders of the Corporation have in the 10 years
preceding the date of this Annual Information Form, become bankrupt, made a
proposal under any legislation relating to bankruptcy or insolvency, or been
subject to or instituted any proceedings, arrangement or compromise with
creditors, or had a receiver, receiver manager or trustee appointed to hold
their assets. Conflicts of Interest Circumstances
may arise where members of the board of directors of Canadian Superior are
directors or officers of corporations which are in competition to the interests
of Canadian Superior.  No assurances can
be given that opportunities identified by such board members will be provided
to Canadian Superior.  Pursuant to the Business
Corporations Act (Alberta), directors who have an interest in a
proposed transaction upon which the board of directors is voting are required
to disclose their interests and refrain from voting on the transaction. ADDITIONAL INFORMATION The
Corporation will provide upon request to the Secretary of the Corporation: a)when the securities of the Corporation are
in the course of a distribution under a preliminary short form prospectus or a
short form prospectus: i)one copy of this Annual Information Form,
together with one copy of any document, or the pertinent pages of any document,
incorporated by reference in this Annual Information Form; ii)one copy of the comparative financial
statements of the Corporation for the financial year ended December 31,
2002 together with the accompanying report of the auditor and one copy of any
interim financial statements of the Corporation subsequent to the financial
statements of the Corporation for its financial year ended December 31,
2002;  27 
   iii)one copy of the Corporations Management
Information Circular dated April 30, 2003 which relates to the Annual General
Meeting of Shareholders to be held on June 27, 2003; and iv)one copy of any other documents that are
incorporated by reference into the preliminary short form prospectus or the
short form prospectus and are not required to be provided under (i) to (iii)
above; or b)at any other time, one copy of any other
documents referred to in (a)(i), (ii) and (iii) above, provided that the
Corporation may require the payment of a reasonable charge if the request is
made by a person or company who is not a security holder of the Corporation. Additional
information including directors and officers remuneration and indebtedness,
principal holders of the Corporations securities, options to purchase
securities and interests of insiders in material transactions, where
applicable, is contained in the Corporations Management Information Circular
for its most recent annual meeting of shareholders that involved the election
of directors, and additional information is provided in the Corporations
comparative financial statements for its most recently completed financial
year. Additional
copies of this Annual Information Form and the materials listed in this section
are available upon request by contacting the Corporate Secretary of 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.  28