EXHIBIT 1
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                       CANADIAN NATURAL RESOURCES LIMITED




                             ANNUAL INFORMATION FORM





                                  APRIL 2, 2004

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                                        1


                                TABLE OF CONTENTS

DEFINITIONS....................................................................2

SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS..............................3

THE COMPANY....................................................................4

GENERAL DEVELOPMENT OF THE BUSINESS............................................5

REGULATORY MATTERS.............................................................6

COMPETITIVE MATTERS............................................................8

ENVIRONMENTAL MATTERS..........................................................8

DESCRIPTION OF THE BUSINESS....................................................9

A.   PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES...........................10

         DRILLING ACTIVITY....................................................11
         PRODUCING OIL AND GAS WELLS..........................................12
         PRESENT ACTIVITIES...................................................12
         NORTHEAST BRITISH COLUMBIA...........................................12
         NORTHWEST ALBERTA....................................................13
         NORTH ALBERTA........................................................14
         HORIZON OIL SANDS PROJECT............................................16
         SOUTH ALBERTA........................................................17
         SOUTHEAST SASKATCHEWAN...............................................18
         UNITED KINGDOM NORTH SEA.............................................18
         OFFSHORE WEST AFRICA.................................................19
         COTE D'IVOIRE........................................................19
         ANGOLA...............................................................20

B.   CRUDE OIL AND NATURAL GAS RESERVES.......................................20

C.   RECONCILIATION OF CHANGES IN NET RESERVES................................25

D.   CRUDE OIL AND NATURAL GAS PRODUCTION.....................................26

E.   HISTORICAL DRILLING ACTIVITY BY PRODUCT..................................29

F.   CAPITAL EXPENDITURES.....................................................30

G.   NON-RESERVE ACREAGE......................................................32

H.   DEVELOPED ACREAGE........................................................32

SELECTED FINANCIAL INFORMATION................................................33

MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES......................34

DIVIDEND HISTORY..............................................................34

DIRECTORS AND OFFICERS........................................................35

ADDITIONAL INFORMATION........................................................38

SCHEDULE "A"..................................................................40

SCHEDULE "B"..................................................................43


                                    CURRENCY

Unless otherwise indicated, all dollar figures stated in this Annual Information
Form represent Canadian dollars.

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                                        2


                                   DEFINITIONS

The following are definitions of selected abbreviations used in this Annual
Information Form:

"ARTC" means Alberta Royalty Tax Credit.

"BBL" or "BARREL" means 34.972 Imperial gallons or 42 U.S. gallons.

"BCF" means one billion cubic feet.

"BBLS/D" means barrels per day.

"CANADIAN NATURAL RESOURCES LIMITED", "CANADIAN NATURAL", "CNRL" or "COMPANY"
means Canadian Natural Resources Limited and includes, where applicable,
reference to subsidiaries of and partnership interests held by Canadian Natural
Resources Limited and its subsidiaries.

"FPSO" means floating production, storage and off-take vessel.

"GROSS ACRES" means the total number of acres in which the Company holds a
working interest or the right to earn a working interest.

"GROSS WELLS" means the total number of wells in which the Company has a working
interest.

"MBBLS" means one thousand barrels.

"MCF" means one thousand cubic feet.

"MCF/D" means one thousand cubic feet per day.

"MMBBLS" means one million barrels.

"MMBTU" means one million British thermal units.

"MMCF" means one million cubic feet.

"MMCF/D" means one million cubic feet per day.

"NGLS" means natural gas liquids.

"NET ACRES" refers to gross acres multiplied by the percentage working interest
therein owned or to be owned by the Company.

"NET WELLS" refers to gross wells multiplied by the percentage working interest
therein owned or to be owned by the Company.

"SAGD" means steam-assisted gravity drainage.

"UNDEVELOPED LAND" or "NON-RESERVE ACREAGE" refers to lands on which wells have
not been drilled or completed to a point that would permit the production of
commercial quantities of crude oil and natural gas.

"WORKING INTEREST" means the interest held by the Company in a crude oil or
natural gas property, which interest normally bears its proportionate share of
the costs of exploration, development, and operation as well as any royalties or
other production burdens.

"WTI" means West Texas Intermediate.

Natural gas is converted to oil equivalent at the rate of six thousand cubic
feet equals one barrel of oil equivalent.

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                                        3


                SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this document or incorporated herein by reference may
constitute "forward-looking statements" within the meaning of the United States
Private Litigation Reform Act of 1995. These forward-looking statements can
generally be identified as such because of the context of the statements
including words such as the Company "believes", "anticipates", "expects",
"plans", "estimates", or words of a similar nature.

The forward-looking statements are based on current expectations and are subject
to known and unknown risks, uncertainties and other factors that may cause the
actual results, performance or achievements of the Company, or industry results,
to be materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements. Such factors include,
among others: the general economic and business conditions which will, among
other things, impact demand for and market prices of the Company's products; the
foreign currency exchange rates; the economic conditions in the countries and
regions in which the Company conducts business; the political uncertainty,
including actions of or against terrorists, insurgent groups or other conflict
including conflict between states; the industry capacity; the ability of the
Company to implement its business strategy, including exploration and
development activities; the impact of competition, availability and cost of
seismic, drilling and other equipment; the ability of the Company to complete
its capital programs; the ability of the Company to transport its products to
market; potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; the operating hazards and other
difficulties inherent in the exploration for and production and sale of oil and
natural gas; the availability and cost of financing; the success of exploration
and development activities; the timing and success of integrating the business
and operations of acquired companies; the production levels; the uncertainty of
reserve estimates; the actions by governmental authorities; the government
regulations and the expenditures required to comply with them (especially safety
and environmental laws and regulations); the site restoration costs; and other
circumstances affecting revenues and expenses. The impact of any one factor on a
particular forward-looking statement is not determinable with certainty as such
factors are interdependent upon other factors, and management's course of action
would depend upon its assessment of the future considering all information then
available.

Statements relating to "reserves" are deemed to be forward-looking statements as
they involve the implied assessment based on certain estimates and assumptions
that the reserves described can be profitably produced in the future.

Readers are cautioned that the foregoing list of important factors is not
exhaustive. Although the Company believes that the expectations conveyed by the
forward-looking statements are reasonable based on information available to it
on the date such forward-looking statements are made, no assurances can be given
as to future results, levels of activity and achievements. All subsequent
forward-looking statements, whether written or oral, attributable to the Company
or persons acting on its behalf are expressly qualified in their entirety by
these cautionary statements. The Company assumes no obligation to update
forward-looking statements should circumstances or management's estimates or
opinions change.

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                                        4


                                   THE COMPANY

Canadian Natural Resources Limited was incorporated under the laws of the
Province of British Columbia on November 7, 1973 as AEX Minerals Corporation
(N.P.L.) and on December 5, 1975 changed its name to Canadian Natural Resources
Limited. CNRL was continued under the COMPANIES ACT OF ALBERTA on January 6,
1982 and was further continued under the BUSINESS CORPORATIONS ACT (Alberta) on
November 6, 1985. The head, principal and registered office of the Company is
located in Calgary, Alberta, Canada at 2500, 855 - 2nd Street S.W., T2P 4J8.

CNRL formed a wholly owned subsidiary, CanNat Resources Inc. ("CanNat") in
January 1995. Pursuant to a Plan of Arrangement, the Company acquired all of the
outstanding shares of Sceptre Resources Limited ("Sceptre") in September 1996
and in January 1997, Sceptre and CanNat amalgamated pursuant to the BUSINESS
CORPORATIONS ACT (Alberta) under the name CanNat Resources Inc.

Pursuant to an Offer to Purchase all of the outstanding shares, the Company
completed the acquisition of Ranger Oil Limited, including its subsidiaries,
("Ranger") in July 2000. On October 1, 2000 Ranger and the Company amalgamated
pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name Canadian
Natural Resources Limited.

Pursuant to a Plan of Arrangement, the Company acquired all of the outstanding
shares of Rio Alto Exploration Ltd. ("RAX") in July 2002. On January 1, 2003 RAX
and the Company amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta)
under the name Canadian Natural Resources Limited.

On January 1, 2004 CanNat and the Company amalgamated pursuant to the BUSINESS
CORPORATIONS ACT (Alberta) under the name Canadian Natural Resources Limited.

The material operating subsidiaries of the Company, each of which is directly or
indirectly wholly-owned, and their jurisdiction of incorporation are as follows:

  NAME OF COMPANY                                  JURISDICTION OF INCORPORATION
  ---------------                                  -----------------------------

  CNR (ECHO) Resources Inc.                                   Alberta
  CNR International (U. K.) Developments Limited              England
  CNR International (U. K.) Limited                           England
  CNR International Cote d'Ivoire SARL                        Cote d'Ivoire
  Renata Resources Inc.                                       Alberta

CNRL as the managing partner and CNR (ECHO) Resources Inc. and Renata Resources
Inc. are the partners of Canadian Natural Resources, a general partnership.
Canadian Natural Resources as the managing partner and Renata Resources Inc. and
CNRL are partners of Canadian Natural Resources Northern Alberta Partnership, a
general partnership. The two partnerships hold the Canadian crude oil and
natural gas properties of CNRL. CNRL also has a 15 per cent interest in Cold
Lake Pipeline Ltd., which is the general partner of Cold Lake Pipeline Limited
Partnership of which CNRL has a 14.7 per cent interest.

The consolidated financial statements of CNRL include the accounts of the
Company and all of its subsidiaries and partnerships.

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                                        5


                       GENERAL DEVELOPMENT OF THE BUSINESS

CNRL's business is the acquisition of interests in crude oil and natural gas
rights and the exploration, development, production, marketing and sale of crude
oil and natural gas.

The Company initiates, operates and maintains a large working interest in a
majority of the prospects in which it participates. CNRL's objective is to
increase cash flow and earnings through the development of its existing crude
oil and natural gas properties and through the discovery and acquisition of new
reserves. The Company's principal regions of crude oil and natural gas
operations are in the Western Canadian Sedimentary Basin, the United Kingdom
(the "UK") sector of the North Sea and Offshore West Africa. The Company has a
full complement of management, technical and support staff to pursue these
objectives. As at December 31, 2003 the Company had 1671 full time employees in
North America and 204 full time employees in its international operations.

In 2001, the Company completed 121 transactions in the normal course to acquire
additional interests in crude oil and natural gas properties at an aggregate
expenditure of $582.2 million. These properties are located in the Company's
principal operating regions and are comprised of producing and non-producing
leases together with related facilities. In addition, the Company disposed of
non-operated properties not located in the Company's core regions for proceeds
of $63.0 million, including a large portion of the properties acquired with
Ranger in the United States Gulf Coast.

On July 24, 2001, the Company issued US $400.0 million of 10 year 6.70 per cent
unsecured notes maturing July 15, 2011 pursuant to a prospectus supplement dated
July 19, 2001 to the short form shelf prospectus dated July 6, 2001. Pursuant to
a prospectus supplement dated January 15, 2002 to the short form shelf
prospectus dated July 6, 2001, the Company issued on January 23, 2002, US $400.0
million of 30 year 7.20 per cent unsecured notes maturing January 15, 2032.

In July 2002, pursuant to the terms of a Plan of Arrangement, the Company
acquired 100 per cent of RAX. The total purchase price was $2,393.2 million,
comprised of $850.0 million in cash, $522.4 million attributable to the issue of
10,008,218 common shares of the Company, and the assumption of $936.3 million of
debt and $84.5 million of working capital deficiency. The acquisition provided
the Company with a new core region for natural gas exploration and exploitation
activities in Northwest Alberta. The RAX properties include approximately 2.9
million net acres of undeveloped lands and provide additional opportunities for
the Company to increase its production and reserves of natural gas and natural
gas liquids. The acquisition added additional production, which averaged 376
million cubic feet per day of natural gas and 11 thousand barrels per day of
crude oil and natural gas liquids during the second half of 2002 and 2-D and 3-D
seismic of 57,820 kilometres and 14,565 square kilometres respectively. Future
exploration and development projects will take advantage of the large
undeveloped land base, high quality seismic database information and excess
capacity within existing facilities. The acquisition solidified the Company as
the second largest producer of natural gas in Canada and the second largest
undeveloped landholder in western Canada.

During 2002, the Company completed 128 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties at an
aggregate expenditure of $516.3 million. These properties are located in the
Company's principal operating regions and are comprised of producing and
non-producing leases together with related facilities.

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                                       6


In addition, the Company disposed of non-operated properties not located in the
Company's core regions for proceeds of $76.1 million.

On September 16, 2002, the Company issued US $350.0 million of 10 year 5.45 per
cent unsecured notes maturing October 1, 2012 and US $350.0 million of 31 year
6.45 per cent unsecured notes maturing June 30, 2033 pursuant to a prospectus
supplement dated September 9, 2002 to a short form shelf prospectus dated August
16, 2002.

During 2003, the Company completed 111 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties at an
aggregate expenditure of $355.3 million. These properties are located in the
Company's principal operating regions and are comprised of producing and
non-producing leases together with related facilities. In addition, the Company
disposed of non-operated properties not located in the Company's core regions
for proceeds of $19.3 million.

On February 18, 2004 the Company acquired certain resource properties located in
East Central Alberta and Saskatchewan (collectively known as the Petrovera
Partnership) for aggregate consideration of $701 million. In a separate
transaction, the Company sold specific resource properties in the Petrovera
Partnership, representing approximately one third of the total acquisition, to
another independent producer for proceeds of $234 million, resulting in a net
cost of $467 million for the retained properties. The net current production
from the working interests retained by the Company was approximately 27.5 mbbl/d
of heavy oil and 9 mmcf/d of natural gas together with volumes associated with
royalty interests of 1.2 mbbl/d of heavy oil and 2 mmcf/d of natural gas. All of
the retained properties are situated in the Company's core region of North
Alberta.


                               REGULATORY MATTERS

The Company's business is subject to regulations generally established by
government legislation and governmental agencies. The regulations are summarized
in the following paragraphs.

CANADA

The petroleum and natural gas industry in Canada operates under various
government legislation and regulations, which govern exploration, development,
production, refining, marketing, prevention of waste and other activities.

The Company's Canadian properties are located in Alberta, British Columbia,
Saskatchewan, Manitoba and the Northwest Territories. Most of these properties
are held under leases/licences obtained from the respective provincial or
federal governments, which give the holder the right to explore for and produce
crude oil and natural gas. The remainder of the properties are held under
freehold (private ownership) lands.

Conventional petroleum and natural gas leases issued by the provinces of
Alberta, Saskatchewan and Manitoba have a primary term from two to five years,
and British Columbia leases/licences presently have a term of up to ten years.
Those portions of the leases that are producing or are capable of producing at
the end of the primary term will "continue" for the productive life of the
lease. The exploration licences in the Northwest Territories are administered by
the Federal Government and only grant the right to explore. They have initial
terms of four to five years.

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                                       7


A Commercial Discovery Licence must be obtained in order to produce crude oil
and natural gas, which requires the approval of a satisfactory development plan.

An oil sands permit and oil sands primary lease is issued for five and fifteen
years respectively. If the minimum level of evaluation of an oil sands permit is
attained, a primary oil sands lease will be issued out of the permit. A primary
oil sands lease is continued based on the minimum level of evaluation attained
on such lease. Continued primary oil sands leases that are designated as
"producing" will continue for their productive lives while those designated as
"non-producing" can be continued by payment of escalating rentals.

The provincial governments regulate the production of crude oil and natural gas
as well as the removal of natural gas and natural gas liquids from each
province. Government royalties are payable on crude oil and natural gas
production from leases owned by the province. The royalties are determined by
regulation and are generally calculated as a percentage of production varied by
a number of different factors including selling prices, production levels,
recovery methods, transportation and processing costs, location and date of
discovery.

The Company is subject to federal and provincial income taxes in Canada at a
combined rate of approximately 41 per cent after allowable deductions.

UNITED KINGDOM

Under existing law, the UK Government has broad authority to regulate the
petroleum industry, including the power to regulate exploration, development,
conservation and rates of production.

Production from offshore fields as defined by applicable legislation, whose
development was approved prior to April 1, 1982, were subject to Royalty of 12.5
per cent on or after deduction of certain allowances. Fields receiving
development approval after April 1, 1982 were not subject to Royalty. On
November 27, 2002, the UK Government announced the elimination of Royalty
effective January 1, 2003.

Crude oil and natural gas fields granted development approval before March 16,
1993 are subject to UK Petroleum Revenue Tax ("PRT") of 50 per cent charged on
crude oil and natural gas profits. Crude oil and natural gas fields granted
development approval on or after March 16, 1993 are exempted from PRT. Profits
for PRT purposes are calculated on a field-by-field basis by deducting field
operating costs and field development costs from production and third party
tariff revenue. In addition, certain statutory allowances are available, which
may reduce the PRT payable.

The Company is subject to UK Corporation Tax ("CT") on its UK profits as
adjusted for CT purposes. PRT paid is a deductible for CT purposes. The current
CT rate, which became effective April 1, 1999, is 30 per cent.

On April 17, 2002, the UK Government, in its 2002 budget speech by the UK
Chancellor of the Exchequer, announced changes to taxation policies on UK North
Sea crude oil and natural gas production. A supplementary CT charge of 10 per
cent, charged on the same profits as calculated for `normal' CT but excluding
any deduction for financing costs, was added to the current 30 per cent CT
charge. Also the deduction for expenditures on capital items was changed from 25
per cent per annum to 100 per cent in the year incurred.

OFFSHORE WEST AFRICA

Terms of licences, including royalties and taxes payable on production or profit
sharing arrangements, vary by country and in some countries by concession within
each country. For instance, production from the Kiame field, on Block 4 in
Angola, was subject to a 6 per cent

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                                       8


royalty on gross income and 50 per cent Petroleum Income Tax, which equates to 7
per cent calculated on the Company's gross income. Development of the Espoir
field on CI-26, Cote d'Ivoire, is under the terms of a production sharing
arrangement that provides that tax or royalty payments to the Government are
deemed to be met from the Government's share of profit oil (See "Principal Crude
Oil and Natural Gas Properties - Offshore West Africa").

Any changes in government policies or operating environment in the countries
where the Company conducts business could have a significant impact on the
Company's business ventures in such jurisdictions. Risks of foreign operations
include, but are not necessarily limited to, changes of laws affecting foreign
ownership, government participation, taxation, royalties, duties, rates of
exchange, inflation, exchange control, repatriation of earnings and domestic or
international unrest. The effect of changes in any of these factors cannot be
accurately predicted.


                               COMPETITIVE MATTERS

The crude oil and natural gas industry, domestically and in the international
arena, is highly competitive by nature. The Company must compete with integrated
oil and natural gas companies and independent producers and marketers of crude
oil and natural gas products in all aspects of the Company's business. This
competition extends to exploration, property and asset acquisition and the
selling of the Company's crude oil and natural gas products. The financial
strength of some of the Company's competitors may be greater than that of the
Company.


                              ENVIRONMENTAL MATTERS

The Company carries out its activities in compliance with all relevant regional,
national and international regulations and best industry practice. Environmental
specialists in the UK and Canada review the operations of the Company's
world-wide interests and report on a regular basis to the senior management of
the Company, which in turn reports on environmental matters directly to the
Health, Safety and Environmental Committee of the Board of Directors.

The Company regularly meets with, and submits to inspections by the various
governments in the regions where the Company operates. At present, the Company
believes that it meets all existing environmental standards and regulations and
has included appropriate amounts in its capital expenditure budget to continue
to meet current environmental protection requirements. Since these requirements
apply to all operators in the crude oil and natural gas industry, it is not
anticipated that the Company's competitive position within the industry will be
adversely affected. The Company has internal procedures designed to ensure that
the environmental aspects of new acquisitions and developments are taken into
account prior to proceeding. The Company's environmental plan and operating
guidelines focus on minimizing the environmental impact of field operations
while meeting regulatory requirements and corporate standards. The Company's
proactive program includes: an annual environmental compliance audit and
inspection program of our operating facilities; an aggressive suspended well
inspection program to support future development or eventual abandonment;
appropriate reclamation and decommissioning standards for wells and facilities
ready for abandonment; an effective surface reclamation program; progressive due
diligence related to groundwater monitoring; prevention of and reclamation of
spill sites, greenhouse gas reduction, and flaring and venting reduction.
Canadian Natural participates in Canada's Climate Change Voluntary Challenge &
Registry Inc. The Company has participated in the Canadian Association of
Petroleum Producers (CAPP) Stewardship Program since 2000 and is currently a
Gold Level Reporter. Canadian Natural

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                                       9


continues to invest in proven and new technologies and in improved operating
strategies that will help us achieve our overall goal of a net reduction of
greenhouse gas emissions per unit of production.

The costs incurred by the Company for compliance with environmental matters and
site restoration costs amount to less than 3 per cent of the total exploration
and development expenditures incurred by the Company in each of the years ended
December 31, 2003, 2002, and 2001.


                           DESCRIPTION OF THE BUSINESS

CNRL is a Canadian based senior independent energy company engaged in the
acquisition, exploration, development, production, marketing and sale of crude
oil, natural gas liquids and natural gas. The Company's principal core regions
of operations are western Canada, the United Kingdom sector of the North Sea and
Offshore West Africa.

The Company focuses on exploiting its core properties and actively maintaining
cost controls. Whenever possible CNRL takes on significant ownership levels,
operates the properties and attempts to dominate the local land position and
operating infrastructure. The Company has grown through a combination of
internal growth and strategic acquisitions. Acquisitions are made with a view to
either entering new core regions or increasing dominance in existing core
regions.

The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces: namely
natural gas, NGLs, light oil, Pelican Lake oil, primary heavy oil and thermal
heavy oil. The Company's operations are centred on balanced product offerings,
which together provide complementary infrastructure and balance throughout the
business cycle. Natural gas is the largest single commodity sold, accounting for
47 per cent of 2003 production. Virtually all of the Company's natural gas and
natural gas liquids production is located in the Canadian provinces of Alberta
and British Columbia and is marketed in Canada and the United States. Light oil
and NGLs, representing 25 per cent of 2003 production, is located principally in
the Company's North Sea and Offshore West Africa properties, with additional
production in the Provinces of Saskatchewan, British Columbia and Alberta.
Primary and thermal heavy oil operations in the Provinces of Alberta and
Saskatchewan account for 23 per cent of 2003 production. Other heavy oil, which
accounts for 5 per cent of 2003 production, is produced from the Pelican Lake
area in north Alberta. This production, which has medium oil netback
characteristics, is developed through a staged horizontal drilling program.
Midstream assets, comprised of three crude oil pipelines and an electricity
co-generation facility, provide cost effective infrastructure supporting the
heavy and medium oil operations. CNRL expects its ownership of oil sands leases
near Ft. McMurray, Alberta to provide a basis for long-term synthetic oil
production growth.

As a result of the Company's core undeveloped land base of 11.3 million net
acres in western Canada, its international concessions and the Alberta oil sands
leases, the Company believes it has sufficient project portfolios in each of the
product offerings to provide growth for the next several years.

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                                       10


A.       PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES

Set forth below is a summary of the principal crude oil and natural gas
properties as at December 31, 2003. The information is proportionate to the
working interests and royalty interests owned by the Company.

<TABLE>
<CAPTION>
                         2003 AVERAGE         YEAR ENDED
                             DAILY           DECEMBER 31,              INFRASTRUCTURE
                       PRODUCTION RATES          2003             AS AT DECEMBER 31, 2003
                       ------------------  -----------------   -------------------------------
                                                                              BATTERIES/
                                                                            COMPPRESSORS &
                         OIL &   NATURAL     UNDEVELOPED       PIPELINE        PLANTS/
                          NGLs       GAS       ACREAGE         (thousand      PLATFORMS
       REGION            Mbbls      MMcf     (thousands)        miles)          /FPSO
<S>                      <C>       <C>            <C>           <C>      <C>  <C>    <C>  <C>
NORTH AMERICA

Northeast B. C.            6.7     372.3          1,566         2.3       8/  74/    --/   --

Northwest Alberta         11.1     261.3          1,681         2.2       8/  29/    --/   --

North Alberta            136.7     462.4          5,627         6.7      23/  97/    --/   --

Horizon Oil Sands           --        --            117          --      --/  --/    --/   --

South Alberta             10.9     141.9            673         3.3      34/  61/    --/   --

SE Saskatchewan            9.2       3.4            147          --      35/  --/    --/   --

Non - core regions         0.3       3.4          1,604          --      --/  --/    --/   --

INTERNATIONAL

North Sea                 56.9      45.6          1,920         0.1      --/  --/     4/    2

Offshore West
     Africa

     Angola                 --        --            610          --      --/  --/    --/   --

     Cote d'Ivoire        10.6       8.4            333          --      --/  --/    --/    1

South Africa                --        --          5,550          --      --/  --/    --/   --
----------------------------------------------------------------------------------------------
TOTAL                    242.4   1,298.7         19,828        14.6     108/ 261/     4/    3
----------------------------------------------------------------------------------------------
</TABLE>

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                                       11


DRILLING ACTIVITY

Set forth below is a summary of the drilling activity, excluding stratigraphic
test and service wells, of the Company for each of the last two fiscal years up
to December 31, 2003 by geographic region:
<TABLE>
<CAPTION>
                                                                         2003
-------------------------------------------------------------------------------------------------------------------------
                                            NET EXPLORATORY                                NET DEVELOPMENT
                                PRODUCTIVE      DRY HOLES       TOTAL         PRODUCTIVE      DRY HOLES        TOTAL
-------------------------------------------------------------------------------------------------------------------------
<S>                               <C>             <C>          <C>            <C>               <C>          <C>
CANADA
                                   15.5           13.3          28.8             67.8            9.1            76.9
  Northeast B. C.
                                   31.7           11.8          43.5             69.9            7.9            77.8
  Northwest Alberta
                                   57.5           26.6          84.1            531.6           37.9           569.5
  North Alberta
                                   33.0            4.0          37.0            387.9            5.0           392.9
  South Alberta
                                     --             --            --             26.9             --            26.9
  Southeast Saskatchewan
                                     --             --            --              0.4             --             0.4
  Non - core regions
NORTH SEA                            --            1.0           1.0             11.1            0.8            11.9
OFFSHORE WEST AFRICA
  Cote d'Ivoire                     0.7             --           0.7              0.7             --             0.7
  Angola                             --            0.6           0.6               --             --              --
-------------------------------------------------------------------------------------------------------------------------
TOTAL                             138.4           57.3         195.7          1,096.3           60.7         1,157.0
-------------------------------------------------------------------------------------------------------------------------

                                                                         2002
-------------------------------------------------------------------------------------------------------------------------
                                            NET EXPLORATORY                                NET DEVELOPMENT
                                PRODUCTIVE      DRY HOLES       TOTAL         PRODUCTIVE      DRY HOLES        TOTAL
-------------------------------------------------------------------------------------------------------------------------
CANADA
                                   16.8            4.4          21.2             25.4             --            25.4
  Northeast B. C.
                                    3.9            3.0           6.9              6.1             --             6.1
  Northwest Alberta
                                   31.5            6.0          37.5            278.1            8.6           286.7
  North Alberta
                                   12.0             --          12.0             40.6            2.5            43.1
  South Alberta
                                     --             --            --              4.3            1.0             5.3
  Southeast Saskatchewan
NORTH SEA                           0.4             --           0.4              4.5             --             4.5
OFFSHORE WEST AFRICA
  Cote D'Ivoire                     0.6            0.9           1.5              1.8            0.6             2.4
-------------------------------------------------------------------------------------------------------------------------
TOTAL                              65.2           14.3          79.5            360.8           12.7           373.5
-------------------------------------------------------------------------------------------------------------------------

                                                                         2001
-------------------------------------------------------------------------------------------------------------------------
                                            NET EXPLORATORY                                NET DEVELOPMENT
                                PRODUCTIVE      DRY HOLES       TOTAL         PRODUCTIVE      DRY HOLES        TOTAL
-------------------------------------------------------------------------------------------------------------------------
CANADA
                                   13.1            4.5          17.6             63.5            5.0            68.5
  Northeast B. C.
                                    3.0            1.0           4.0              2.0             --             2.0
  Northwest Alberta
                                   60.7            8.1          68.8            231.3           12.7           244.0
  North Alberta
                                    1.4             --           1.4            324.9             --           324.9
  South Alberta
                                     --             --            --              4.0             --             4.0
  Southeast Saskatchewan
                                     --             --            --               --             --              --
  Non - core areas
UNITED STATES                        --            0.8           0.8              0.1             --             0.1
NORTH SEA                            --            0.2           0.2              2.2             --             2.2
OFFSHORE WEST AFRICA
  Cote D'Ivoire                     0.6             --           0.6              0.6             --             0.6
  Angola                             --             --            --               --             --              --
-------------------------------------------------------------------------------------------------------------------------
TOTAL                              78.8           14.6          93.4            628.6           17.7           646.3
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>

                                       12


PRODUCING OIL & GAS WELLS

Set forth below is a summary of the number of gross and net wells within the
Company that were on production as of December 31, 2003:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
                                  NATURAL GAS WELLS                 OIL WELLS                     TOTAL WELLS
                                GROSS            NET           GROSS           NET           GROSS            NET
-----------------------------------------------------------------------------------------------------------------------
<S>                                 <C>           <C>              <C>          <C>              <C>          <C>
CANADA
                                      757           610.4            220          159.4             977          769.8
  Northeast B. C.
                                      665           539.4            150          108.2             815          647.6
  Northwest Alberta
                                    2,583         1,980.1          4,162        3,611.9           6,745        5,592.0
  North Alberta
                                    3,415         2,686.5          1,003          891.1           4,418        3,577.6
  South Alberta
                                      677            56.0            292           97.0             969          153.0
  Southeast Saskatchewan
                                       --              --          1,084          707.9           1,084          707.9
  Non - core regions
UNITED STATES                           4             0.5              2            0.2               6            0.7
NORTH SEA                               5             0.4             91           74.5              96           74.9
OFFSHORE WEST AFRICA
  Cote d'Ivoire                        --              --              5            2.9               5            2.9
  Angola                               --              --             --             --              --             --
-----------------------------------------------------------------------------------------------------------------------
TOTAL                               8,106         5,873.3          7,009        5,653.1          15,115       11,526.4
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

PRESENT ACTIVITIES

At December 31, 2003, the Corporation was in the process of drilling 47 gross
wells (45.3 net wells). Injection of emulsion into the first waterflood injector
of a demonstration project in the Pelican Lake field commenced to determine
potential improvements in sweep efficiency and thus ultimate recovery.
Waterflooding in the remaining injectors and monitoring the field's response to
injection continued.

NORTHEAST BRITISH COLUMBIA

This region comprises lands from south of Fort St. John, British Columbia to the
northern border of British Columbia. Similar geological attributes extend
throughout the region, producing light oil, natural gas liquids and natural gas.
The Company holds working interests ranging up to 100 per cent and averaging 78
per cent in 2,780,070 gross (2,158,094 net) acres of producing and undeveloped
land in the region.

Crude oil reserves are found primarily in the Halfway or lower Halfway
formation, while natural gas and associated natural gas liquids are found in
numerous zones at depths reaching approximately 2,000 vertical meters. In the
southern portion of the region, the Company owns natural gas producing and
undeveloped lands in which the productive zones are at deeper depths up to 3,500
meters. The exploration strategy focuses on comprehensive evaluation through
two-dimensional seismic, three-dimensional seismic and targeting economic
geological areas close to existing infrastructure. Applying under-balanced,
multi-leg horizontal drilling has also proven highly effective in this region.
Natural gas production from the region averaged 372.3 million cubic feet per day
for 2003 compared to the average of 450.6 million cubic feet per day produced
for 2002. Crude oil and natural gas liquids production decreased to 6.7 thousand
barrels per day in 2003 from an average of 7.4 thousand barrels per day in 2002.

<PAGE>

                                       13


This region also contains the Ladyfern Slave Point natural gas pool, which was
placed on production in mid-2001. Prior to the first quarter of 2002, production
from the pool had been restricted due to insufficient processing facilities and
pipelines, with production exiting 2001 at approximately 150 million cubic feet
per day. In the first quarter of 2002, additional facilities were constructed,
which enabled the Company to increase production to approximately 210 million
cubic feet per day in June 2002. In late August 2002, water encroachment
resulted in the commencement of anticipated significant declines from the pool.
At the end of 2002, production was at 100 million cubic feet per day, falling to
approximately 31 million cubic feet per day in December 2003.

Through the acquisition of Ranger in 2000, the Company acquired an interest and
operatorship in extensive acreage adjacent to the northern border of this
region. A further acquisition in the fourth quarter of 2001 resulted in the
Company obtaining 100 per cent ownership in its producing natural gas assets and
undeveloped land in the Helmet area of the region. Further development of this
acreage will be enhanced through the facilities and infrastructure owned by the
Company in the region. Having identified optimal drilling strategies in the
region, the Company implemented a multi-well annual drilling program, which
resulted in 35 wells being drilled in 2003.

During 2003, the Company developed a new exploration and development program
that targets natural gas found in the shallow Notikewin formation in the Fort
St. John area. Wells drilled into this formation produce at rates of 500 to 700
thousand cubic feet per day. In combination with the Company's extensive land
base and the recently reduced royalty rates in British Columbia, this shallow
gas drilling program will add to the Company's opportunities in this region.

During 2003 the Company drilled 5.1 (2002-2.1) net oil wells, 78.2 (2002-40.1)
net natural gas wells, 0.0 (2002-1.0) net service wells and 22.4 (2002-4.4) net
dry wells on its lands in this region for a total of 105.7 (2002-47.6) net
wells. The Company held an average 93 per cent working interest in these wells.

NORTHWEST ALBERTA

The Company holds working interests ranging up to 100 per cent and averaging 81
per cent in 2,542,232 gross (2,066,138 net) acres of producing and undeveloped
land in the region located along the border of British Columbia and Alberta west
and north of Edmonton.

The majority of the Company's holdings in the region were obtained through the
Plan of Arrangement in 2002, which facilitated the acquisition of RAX. This
region contains exceptional exploration and exploitation opportunities as well
as substantial available capacity within an extensively owned and operated
infrastructure. In this region, Canadian Natural produces liquids rich natural
gas from multiple, often technically complex horizons, with formation depths
ranging from 1,000 to 4,500 metres. The northern portion of this core region
provides extensive multi-zone Cretaceous opportunities similar to the geology of
the Company's North Alberta core region. The southern portion provides a
significant opportunity in the regionally extensive Cretaceous Cardium zone. The
Cardium is a complex, tight natural gas reservoir where high productivity may be
achieved due to greater matrix porosity or natural fracturing. In this southern
portion, Canadian Natural pursued a modest well drilling program in the first
half of 2003 so that detailed geological, geophysical and engineering work could
be completed and interpreted. A more extensive drilling program was commenced in
the last quarter of 2003.

Natural gas production from the region averaged 261.3 million cubic feet per day
for 2003 compared to an average of 171.2 million cubic feet per day for 2002.
Crude oil and natural gas liquids production increased to 11.1 thousand barrels
per day in 2003 from 6.6 thousand barrels per day in

<PAGE>

                                       14


2002. During 2003 the Company drilled 3.7 (2002-2.1) net oil wells, 97.9
(2002-7.5) net natural gas wells, and 19.7 (2002-3.0) net dry wells on its lands
in this region for a total of 121.3 (2002-12.6) net wells. The Company held an
average 85 per cent working interest in these wells. The Company owns and
operates significant production facilities in this region, many of which have
excess capacity, providing for cost effective future expansion of operations.
All of the facilities are in close proximity to sales facilities.

NORTH ALBERTA

The Company holds working interests ranging up to 100 per cent and averaging 82
per cent in 9,602,862 gross (7,896,464 net) acres of producing and undeveloped
land in the region located north of Edmonton to Fort McMurray and east to the
border with Saskatchewan and extending into western Saskatchewan.

Over most of the region both sweet and sour natural gas reserves are produced
from numerous productive horizons at depths up to approximately 1,500 meters. In
the southwest portion of the region, natural gas liquids and light oil are also
encountered at slightly deeper depths. The region continues to be one of the
Company's largest natural gas producing regions, with natural gas production
from the region amounting to 462.4 million cubic feet per day in 2003 compared
to 419.8 million cubic feet per day in 2002. Crude oil and natural gas liquids
production from this region increased to 136.7 thousand barrels per day in 2003
from 135.9 thousand barrels per day in 2002. Production of natural gas was
impacted by the shut-in effective September 1, 2004 of approximately 11 million
cubic feet per day in the Athabasca Wabiskaw-McMurray oil sands area pursuant to
the decision of the Alberta Energy and Utilities Board.

In the area near Lloydminster, Alberta, reserves of heavy oil (averaging
12(Degree) - 14(degree) API) and natural gas are produced through conventional
vertical, slant and horizontal well bores from a number of productive horizons
up to 1,000 meters deep. The energy required to flow the heavy oil to the
wellbore in this type of heavy oil reservoir comes from solution gas. The oil
viscosity and the reservoir quality will determine the amount of crude oil
produced from the reservoir, which will vary from 3 to 20 per cent. A key
component to maintaining profitability in the production of heavy oil is to be a
low cost producer. The Company continues to achieve low costs producing heavy
oil by holding a dominant position that includes a significant land base and an
extensive infrastructure of batteries and disposal facilities.

The price received for heavy oil is discounted from the benchmark WTI price and
during the last quarter of 2000, this differential widened to historically high
levels. As a result, the Company took a proactive stance and consciously reduced
the number of heavy oil wells drilled in 2001, reduced heavy oil production by
15 thousand barrels per day beginning December 2001 and changed the steaming
pattern at its Primrose facility. Following the return of the heavy oil
differential to more historical levels, the Company brought most of this
production back online and expanded its 2002 and 2003 drilling programs. The
Company continues to monitor and develop the heavy oil market and work on
strategies to eliminate some of the uncertainty surrounding this commodity
pricing.

Ranger owned significant land and production in this region, with much of its
land being contiguous to the Company's holdings. With the operations combined in
2000, future development of the total lands in the region became more effective
and provided opportunities for cost savings. As part of the acquisition of
Ranger, the Company also acquired a 50 per cent interest in the ECHO Pipeline
system, a crude oil transportation pipeline; and, in 2001 the Company acquired
the remaining 50 per cent. The pipeline was extended north to the Company
operated Beartrap field during 2001, enhancing further development of the
Company's extensive holdings in the area. This pipeline was

<PAGE>

                                       15


capable of transporting 57 thousand barrels per day of hot unblended crude oil
to sales facilities at Hardisty, Alberta and in 2003 its capacity was expanded
to handle up to 72 thousand barrels per day. The ECHO Pipeline system is a high
temperature, insulated pipeline that eliminates the requirement for field
condensate blending. The pipeline enables the Company to transport its own
production volumes at a reduced operating cost as well as earn third party
transportation revenue. The ECHO Pipeline system, together with other midstream
assets in which the Company has partial interests, permits the Company to
transport in excess of 80 per cent of its heavy oil to the international
mainline liquids pipelines. This transportation control enhances the Company's
ability to control the full spectrum of costs associated with the development
and marketing of its heavy oil.

Production from the 100% owned Primrose and Wolf Lake fields located near
Bonnyville, Alberta involves processes that utilize steam to increase the
recovery of the oil. The two processes employed by the Company are cyclic steam
stimulation and SAGD. Both recovery processes inject steam to heat the heavy oil
deposits, reducing the oil viscosity and therefore improving its flow
characteristics. There is also an infrastructure of gathering systems, a
processing plant with a capacity of 60 thousand barrels per day and a 50 per
cent interest in a co-generation facility capable of producing 84 megawatts of
electricity for the Company's use and sale into the Alberta power grid at pool
prices. In 2000, the Company successfully converted and tested two existing pads
of wells from low-pressure steaming to high-pressure steaming. This conversion
increased average production at the 20 existing wells from 100 to 190 barrels of
crude oil per day per well. An additional 24 wells were drilled using the
high-pressure steam process with initial production averaging 600 barrels of
crude oil per day per well. These results have confirmed the benefits of
converting the Primrose field to high-pressure steaming. In 2001, the Company
received regulatory approval to convert an additional six low-pressure cyclic
pads to high-pressure cyclic pads, and in 2002 received approval to take
high-pressure steam methodologies throughout the field. Canadian Natural drilled
48 high-pressure wells in 2003, which will increase field production commencing
in 2004. Additional development of the leases will be undertaken in phases over
the next several years. A successful SAGD heavy oil project in which the Company
holds a 50 per cent interest is also in operation in the Saskatchewan portion of
this region.

Included in the northern part of this region, approximately 200 miles north of
Edmonton, are the Company's 100 per cent owned holdings at Pelican Lake. These
lands contain reserves of 14(Degree)-17(Degree) API heavy oil. Operating costs
are low due to no sand production or disposal requirements, the gathering and
pipeline facilities in place and negligible water production and disposal. The
Company has the major ownership position in the necessary infrastructure
including roads, drilling pads, gathering and sales pipelines, batteries, gas
plants and compressors to ensure future economic development of the large crude
oil pool located on the lands. In the first quarter of 2001, the Company added
to its holdings in this area through the acquisition of additional producing
lands from another industry participant. Following this acquisition, the Company
holds and controls in excess of 80 per cent of the known crude oil pool in this
area.

This field contains approximately three billion barrels of original oil-in-place
but is only expected to achieve a 5 per cent recovery factor using existing
primary technologies on the Company's developed leases. Hence, in 2002 the
Company embarked upon an Enhanced Oil Recovery ("EOR") scheme using an emulsion
flood to increase the ultimate recoveries from the field. The experimental
Pelican Lake emulsion flood showed that the recovery mechanism was very
efficient; however, response time is slow. In view of the slow response time,
the Company has reverted to a waterflood scheme for this field, which will
increase the overall recovery factor but not to the extent reached under an
emulsion scheme. This waterflood will be implemented in phases with
approximately 20 per cent of the field scheduled to be under waterflood by the
end of 2004. The implementation plan will result in the conversion of existing
producing wells into water injectors and the drilling of additional producing

<PAGE>

                                       16


wells. The Company will also examine opportunities to use emulsion flooding in
conjunction with waterflooding to obtain the highest recovery factor while
maximizing value.

During 2003 in this region, the Company drilled 405.7 (2002 - 246.0) net oil
wells, 183.4 (2002 - 62.4) net natural gas wells, 58.5 (2002 - 148.5) net
stratigraphic tests wells, 5.0 (2002 - 2.5) net services wells and 64.5 (2002 -
15.0) net dry wells that were abandoned for a total of 717.1 (2002 - 474.4) net
wells. The Company's average working interest in these wells was in excess of 93
per cent. The Company operates and owns significant infrastructure in the region
as shown above and has additional interests in plants and compressors in the
region that are operated by other companies.

HORIZON OIL SANDS PROJECT

Canadian Natural owns a 100 percent working interest in 116,596 gross acres in
the Athabasca Oil Sands area of Northern Alberta. The Horizon Oil Sands Project
("the Horizon Project") is located on these leases, about 80-km north of Fort
McMurray. The project includes surface oil sands mining, bitumen extraction,
bitumen upgrading to produce a 34-36o API synthetic light crude oil ("SCO"), and
associated infrastructure.

The project is designed as a phased development. Major site clearing and
pre-construction preparation activities will commence upon completed regulatory
approval and project sanction in 2004 and construction would continue through
2012. Phase 1 production is planned to begin in the fourth quarter of 2008 at
110 thousand barrels per day of SCO. Phase 2 would increase production to 155
thousand barrels per day of SCO in 2010. Phase 3 would further increase
production to 232 thousand barrels per day of SCO in 2012. These projected rates
of production represent nominal design capacity. Canadian Natural will seek to
maximize resource recovery and overall production through ongoing optimization
of operations. The phased approach provides the Company with improved cost and
project controls in terms of labour and materials management and directionally
mitigates the effects of growth on local infrastructure.

Total expected capital costs of the phased development are $8.0 billion to $8.5
billion, of which approximately $5.0 billion would be required for Phase 1.
These costs are consistent with final actual costs incurred by other recent oil
sands mining projects. When the Horizon Project is fully commissioned, operating
costs - including sustaining capital - are expected to be in the range of $9 to
$11 per barrel.

Drilling to date indicates an estimated 16 billion barrels of bitumen-in-place
on the Company's Athabasca Oil Sands Leases. Over its forty-year life span the
Horizon Project is expected to recover about six billion barrels of bitumen.
Additional surface mining and in-situ potential exists on the portion of leases
not comprising the Horizon Project. No reserves from these leases are included
in the Company's current reserves of crude oil and natural gas liquids pending
final regulatory and corporate approvals, subsequent capital expenditures and
initiation of production.

Canadian Natural filed an application for regulatory approval of the Horizon
Project in June 2002. The application included a comprehensive environmental
impact assessment and a social and economic assessment and was accompanied by
public consultation. A federal-provincial regulatory Joint Review Panel (the
"Panel") examined the project in a public hearing in September 2003. The Panel
issued its decision report in January 2004, finding that the Horizon Project is
in the public interest. Subsequent to the Panel decision, the Company has
received approval for the Horizon Project from the Alberta Energy and Utilities
Board and the Cabinets of both the Government of Canada and Alberta. Further
approvals pursuant to specific government acts and regulations are expected
mid-2004.

<PAGE>

                                       17


Due to uncertainties about the long term cost implications of the Government of
Canada climate change policies, in late 2002 Canadian Natural reduced its
estimate of 2003 capital expenditures for the Horizon Project from $300 million
to $211 million. Throughout the first half of 2003, Canadian Natural, along with
other major energy project proponents and the Canadian Association of Petroleum
Producers actively sought greater clarity from the federal government about the
long-term climate change policy framework. Of particular concern was the period
beyond 2012 when policies will be derived from Canada's negotiations for a
second Kyoto implementation phase. In mid 2003 the Government of Canada
acknowledged the need for greater clarity and established eight principles that
will guide the Government of Canada's longer-term climate change policies. These
eight guiding principles addressed the key concerns of Canadian Natural with
regard to equability, efficiency, flexibility and competitiveness issues for the
post-2012 period.

Canadian Natural is using a structured system called Front End Loading to ensure
that project definition is adequate and complete before proceeding with
implementation. This system is used successfully worldwide to mitigate risk on
large capital projects in a variety of industries. The process is well
documented at every step and is audited by an independent organization. In June
2002, the Company commenced the Design Basis Memorandum (DBM), which is the
second of three front-end engineering phases. The DBM was completed for all
project components in February 2004. In August 2003, the Company commenced work
on the third front-end engineering phase, Engineering Design Specifications
(EDS), on those components where the DBM was complete. The EDS will provide
sufficient definition for lump sum bids on various project components, and a
final detailed cost estimate that will provide the basis of project sanction by
the Company's Board of Directors. Completion of this phase is expected in the
last quarter of 2004.

During 2003, the Company drilled 370 (2002 - 293) stratigraphic test wells to
further delineate the ore body and confirm resource quality and quantity.

SOUTH ALBERTA

The Company holds interests ranging up to 100 per cent and averaging 81 per cent
in 1,726,760 gross (1,390,732 net) acres of producing and undeveloped land in
the region principally located south and east of Calgary.

Reserves of natural gas, condensate and light and medium gravity crude oil are
contained in numerous productive horizons at depths up to 2,300 meters. Unlike
the Company's other three natural gas producing regions, which have areas with
limited or winter access only, drilling can take place in this region throughout
the year. With a higher sales price for natural gas, it is economic to drill
shallow wells in closer proximity to each other, which may have smaller overall
reserves and lower productivity per well but will achieve a high return on
capital employed with low drilling costs and longer life reserves

The Company maintains a large inventory of drillable locations on its land base
in this region. This region is in the most mature portion of the Western
Canadian Sedimentary Basin and requires continual operational cost control
through efficient utilization of existing facilities, flexible infrastructure
design and consolidation of interests where appropriate.

The Company's share of production averaged 10.9 (2002 - 9.0) thousand barrels of
crude oil and natural gas liquids per day and 141.9 (2002- 145.8) million cubic
feet of natural gas per day in 2003.

<PAGE>

                                       18


During 2003, the Company drilled a total of 4.4 (2002 - 1.0) net oil wells,
416.5 (2002 - 51.6) net natural gas wells and 9.0 (2002 - 2.5) net dry wells in
this region for a total of 429.9 (2002 - 55.1) net wells. The Company's average
working interest in these wells is in excess of 97 per cent. The wells are
predominantly in areas where the Company already has gathering and processing
facilities.

SOUTHEAST SASKATCHEWAN

The Williston Basin is located in Southeastern Saskatchewan with lands extending
into Manitoba and North Dakota. This region was owned by Sceptre and became a
core region of the Company in mid 1996 with the acquisition of Sceptre. The
Company holds interests ranging up to 100 per cent and averaging 81 per cent in
273,371 gross (219,124 net) acres of producing and undeveloped lands in the
region.

The region produces primarily light sour crude oil from as many as seven
productive horizons found at depths up to 2,700 meters. During 2003, net
production to the Company averaged 9.2 (2002 - 9.4) thousand barrels of crude
oil and natural gas liquids and 3.4 (2002 - 3.2) million cubic feet of natural
gas per day in 2003. The Company drilled 26.9 (2002 - 4.3) net oil wells and no
(2002 - 1.0) net dry wells in this region in 2003 for a total of 26.9 (2002 -
5.3) net wells. The Company's average working interest in these wells is 84 per
cent.

UNITED KINGDOM NORTH SEA

The Company's wholly owned subsidiary CNR International (U.K.) Limited, formerly
Ranger Oil (U.K.) Limited, has operated in the North Sea for 30 years and has
developed a significant database, extensive operating experience and an
experienced staff. The Company owns interests ranging from 7 per cent up to 100
per cent in 910,183 gross (638,749 net) acres of producing and non-producing
properties in the UK sector of the North Sea. In 2003, the Company produced from
9 crude oil fields. The northerly fields are centered around the Ninian Field
where the Company has an 87.1 per cent working interest. The central processing
facility is connected to other fields including the Columba and Lyell Fields
where the Company operates with working interests of 91.6 per cent to 100 per
cent. In 2002, the Company completed property acquisitions in the northern North
Sea that increased ownership levels in the Ninian, Murchison, Lyell and Columba
Terraces Fields. As part of the transaction the Company also acquired an
interest in the Strathspey Field and 12 licenses covering 20 exploration blocks
and part blocks surrounding the Ninian and Murchison platforms. Increased
ownership in the Brent and Ninian pipelines and the Sullom voe Terminal was also
acquired. In 2003 the Company further consolidated its ownership with the
acquisition of additional working interests in the Ninian and Columba Fields,
associated facilities and adjacent exploration acreage. Ownership and
operatorship levels in the North Sea are now similar to those levels found
throughout the Company's other worldwide operations. The Company also receives
tariff revenue from other field owners for the transportation and processing of
crude oil and natural gas through the processing facilities. Opportunities for
further long-reach well development on adjacent fields are provided from the
existing processing facilities.

In the central portion of the North Sea, in 2003 the Company increased its
equity in the Banff Field to 87.6 per cent and took over as operator. The
Company also owns a 45.7 per cent operated working interest in the Kyle Field.

During 2003, production to the Company from this region averaged 56.9 (2002 -
38.8) thousand barrels of crude oil per day and 45.6 (2002 - 27.1) million cubic
feet of natural gas per day. The Company drilled 11.1 (2002 - 4.9) net oil
wells, 4.8 (2002 - 1.2) net service wells and 1.8 (2002 - 0.0) net dry wells in
2003 in this region for a total of 17.7 (2002 - 6.1) net wells. The Company's
average working interest in these wells is 84 per cent.

<PAGE>

                                       19


OFFSHORE WEST AFRICA

With the purchase of Ranger in 2000, the Company acquired interests in areas of
crude oil and natural gas exploration and development offshore Cote d'Ivoire and
Angola, West Africa. The Company owns working interests ranging from 50 per cent
to 100 per cent in 1,685,151 gross (952,006 net) acres in those countries. The
Company also has a 100 per cent interest in 5,550,428 acres offshore South
Africa where it is shooting and evaluating seismic.

COTE D'IVOIRE

The Company owns interests in three exploration licences offshore Cote d'Ivoire
comprising 336,758 net acres. During 2001, the Company increased its interest in
Block CI-26, which contains the Espoir crude oil and natural gas field, to a 59
per cent operating interest. The Espoir field is located in water depths ranging
from 100 to 700 meters. During the 1980s, the Espoir field produced
approximately 31 million barrels of crude oil by natural depletion prior to
relinquishment by the previous licencees in 1988. The government of Cote
d'Ivoire approved a development plan to recover the remaining reserves and the
Company will continue its exploitation and development of the field. The
development of East Espoir, which includes the drilling of both producing and
water injection wells from a single wellhead tower was completed in 2003.
Finalization of development plans for the West Espoir field will be completed in
2004. Oil from the East Espoir field is produced into an FPSO with associated
natural gas delivered onshore through a subsea pipeline for local power
generation. During December 2002 a satellite pool, Emien, was drilled, but
encountered no hydrocarbons. The Company drilled a second, satellite pool,
Acajou, during the first half of 2003. The Acajou well encountered a reservoir
with good quality and hydrocarbons but not of sufficient size to warrant
tie-back to the Espoir FPSO. Further evaluation will be undertaken to determine
if the Acajou structure extends across additional lands.

In the first quarter of 2001, the Company drilled and tested the Baobab
exploration prospect, identified on Block CI-40, in which the Company has a 58
per cent interest, eight kilometres south of the Espoir facilities. The well
encountered hydrocarbons at a rate of 6.7 thousand barrels of crude oil per day.
A second test well in 2002 also produced hydrocarbons at a rate in excess of 10
thousand barrels of crude oil per day. The Company established a field
development plan, which was approved by the Government of Cote d'Ivoire in
December 2002. In 2003 the Company awarded four major contracts for the
development of the Baobab Field. These contracts included the deep water
drilling rig to drill 8 producing and 3 water injection wells, the FPSO,
supplies for the subsea equipment and the supply of pipeline and risers, and
installation of the subsea infrastructure. Development commenced in late 2003
with the drilling of the first water injection well. The development continues
for first oil planned at initial gross production rates of 45 thousand barrels
per day in 2005, increasing with full development to 60 thousand barrels per
day.

To date political unrest in Cote d'Ivoire has had no impact on the Company's
operations. The Company has developed contingency plans to continue Cote
d'Ivoire operations from another nearby country if the situation warrants such a
move.

During 2003, net daily production to the Company averaged 10.6 (2002 - 6.0)
thousand barrels of crude oil and 8.4 (2002 - 1.3) million cubic feet of natural
gas. In 2003, the Company drilled 1.3 (2002 - 2.4) net oil wells, 2.0 (2002 -
0.6) net service wells and 0.0 (2002 - 1.2) net dry wells for a total of 3.3
(2002 - 4.2) net wells. The Company's average working interest in these wells is
67 per cent.

<PAGE>

                                       20


ANGOLA

During 2002, Canadian Natural was awarded operatorship and a 50 per cent working
interest in exploration Block 16 situated offshore The People's Republic of
Angola. Canadian Natural obtained 3-D seismic over the entire Block 16 before
obtaining title and identified two targets, Omba in the north and Zenza in the
west central portion of the Block. The Company has a two well commitment over a
four year time frame expiring August 31, 2006. The first well, Zenza-1, was
drilled during the fourth quarter of 2003 and was not considered commercial. The
second exploratory well is expected to be drilled in the first quarter of 2005
following analysis of the Zenza results and further seismic reprocessing.

The Company also owned 100 per cent of and operated the offshore Kiame Field.
The field produced from June 1998 to April 2002 through a leased FPSO. The field
reached its economic limit of production and production ceased in April 2002.
The wells were abandoned and the associated seabed equipment safely recovered
during 2003. The Company also had a 25 per cent non-operating interest in Block
19, on which a 3-D seismic survey was completed in 1999. After interpretation of
the seismic and drilling of a 25 per cent interest well in 2002 on Block 19, the
Company determined the block was not economic to develop and relinquished its
license on the block.


B.       CRUDE OIL AND NATURAL GAS RESERVES

The Company retains independent qualified petroleum engineering consultants
Sproule Associates Limited ("Sproule") to evaluate 100% of the Company's proved
and proved and probable crude oil and natural gas reserves and prepare
evaluation reports on the Company's total reserves ("Evaluation Reports"). The
Company has been granted an exemption from the recently adopted National
Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI
51-101") which prescribes the standards for the preparation and disclosure of
reserves and reserves related information for companies listed on stock
exchanges in Canada. This exemption allows the Company to substitute United
States Securities and Exchange Commission ("SEC") requirements for certain
disclosures required under NI 51-101. The primary difference between the two
standards is the additional requirement under NI 51-101 to disclose both proved
and proved plus probable reserves as well as related future net revenues using
forecast prices and costs. The Company has disclosed proved reserves using
constant prices and costs as mandated by the SEC and has elected to provide
proved plus probable reserves and values under the same parameters as well as
proved and proved plus probable reserves using forecast prices and costs as
additional voluntary information. Another difference between the two standards
lies in the definition of proved reserves. As discussed in the Canadian Oil and
Gas Evaluation handbook ("COGEH"), the standards which NI 51-101 employs, the
difference in estimated proved reserves based on constant pricing and costs
between the two standards is not material.

The Reserves Committee of the Board of Directors of the Company has met with
Sproule and carried out the appropriate independent due diligence procedures
with Sproule to review the qualifications of and procedures used by Sproule in
determining the estimate of the Company's quantities and value of remaining
petroleum and natural gas reserves.

The following tables summarize the evaluations of reserves and estimated future
net revenues at December 31, 2003.

THE ESTIMATED FUTURE NET REVENUES CONTAINED IN THE FOLLOWING TABLES ARE NOT TO
BE CONSTRUED AS A REPRESENTATION OF THE FAIR MARKET VALUE OF THE PROPERTIES TO
WHICH THEY RELATE. THE ESTIMATED FUTURE NET REVENUES DERIVED FROM THE ASSETS ARE
PREPARED PRIOR TO CONSIDERATION OF INCOME TAXES

<PAGE>

                                       21


AND EXISTING ASSET ABANDONMENT LIABILITIES. NO INDIRECT COSTS SUCH AS OVERHEAD,
INTEREST AND ADMINISTRATIVE EXPENSES HAVE BEEN DEDUCTED FROM THE ESTIMATED
FUTURE NET REVENUES. OTHER ASSUMPTIONS AND QUALIFICATIONS RELATING TO COSTS,
PRICES FOR FUTURE PRODUCTION AND OTHER MATTERS ARE SUMMARIZED IN THE NOTES TO
THE FOLLOWING TABLES. THERE IS NO ASSURANCE THAT THE PRICE AND COST ASSUMPTIONS
CONTAINED IN EITHER THE CONSTANT OR FORECAST CASES WILL BE ATTAINED AND
VARIANCES COULD BE SUBSTANTIAL.

          CRUDE OIL, NGL AND NATURAL GAS RESERVES (NET OF ROYALTIES)

<TABLE>
<CAPTION>
                                                      CONSTANT PRICES AND COSTS
                                -----------------------------------------------------------------------
                                               NET                                  NET
                                     CRUDE OIL & NGL RESERVE                NATURAL GAS RESERVE
                                         VOLUMES (MMbbls)                      VOLUMES (Bcf)
                                -----------------------------------  ----------------------------------
                                                      TOTAL                               TOTAL
                                                    PROVED AND                          PROVED AND
                                   PROVED            PROBABLE          PROVED            PROBABLE
                                  RESERVES           RESERVES         RESERVES           RESERVES
                                  --------           --------         --------           --------
          <S>                       <C>                <C>              <C>                  <C>
          NORTH AMERICA

          Canada                    588                  857            2,425                2,917

          United States              --                   --                1                    2

          INTERNATIONAL

          United Kingdom            222                  317               62                  102

          Cote d'Ivoire              85                  133               64                   72


                                --------------  -------------------  -------------  -------------------
          TOTAL                     895                1,307            2,552                3,093
                                ==============  ===================  =============  ===================
</TABLE>


CRUDE OIL, NGL AND NATURAL GAS RESERVES

<TABLE>
<CAPTION>
                                                                  CONSTANT PRICES AND COSTS
                                           -------------------------------------------------------------------------
                                                  CRUDE OIL AND NATURAL
                                                   GAS LIQUIDS (MMbbls)                   NATURAL GAS (Bcf)
                                           ------------------------------------    ---------------------------------
                                                GROSS                NET                GROSS             NET
                                                -----                ---                -----             ---
<S>                                             <C>                <C>                  <C>             <C>
Proved developed                                  568                509                2,725           2,198

Proved undeveloped                                432                386                  429             354
                                           ----------------  ------------------    ---------------  ----------------
Total proved reserves                           1,000                895                3,154           2,552

Total proved and probable reserves              1,481              1,307                3,823           3,093
                                           ================  ==================    ===============  ================
</TABLE>

ESTIMATED FUTURE NET REVENUES
<TABLE>
<CAPTION>
         ($Millions)                                              CONSTANT PRICES AND COSTS
                                           ---------------------------------------------------------------------
                                               UNDISCOUNTED                          DISCOUNTED AT
                                           ---------------------    --------------------------------------------
                                                                         10%             15%             20%
                                                                         ---             ---             ---
<S>                                            <C>                    <C>             <C>             <C>
Proved developed                               $21,079                $13,080         $11,222         $9,902

Proved undeveloped                               6,370                  3,037           2,273          1,752
                                           ---------------------    -------------  -------------  --------------
Total proved reserves                           27,449                 16,117          13,495         11,654

Total proved and probable reserves             $36,981                $20,167         $16,460        $13,929
                                           =====================    =============  =============  ==============
</TABLE>


<PAGE>

                                       22


CRUDE OIL, NGL AND NATURAL GAS RESERVES
<TABLE>
<CAPTION>
                                                                  FORECAST PRICES AND COSTS
                                           ---------------------------------------------------------------------
                                                 CRUDE OIL AND NATURAL                    NATURAL GAS (Bcf)
                                                  GAS LIQUIDS (MMbbls)
                                           -----------------------------------     -----------------------------
                                                GROSS                 NET                GROSS           NET
                                                -----                 ---                -----           ---
<S>                                             <C>                 <C>                  <C>           <C>
Proved developed                                  563                 511                2,706         2,184

Proved undeveloped                                432                 398                  429           361
                                           -----------------  ----------------     --------------  -------------
Total proved reserves                             995                 909                3,135         2,545

Total proved and probable reserves              1,480               1,332                3,797         3,079
                                           =================  ================     ==============  =============
</TABLE>


ESTIMATED FUTURE NET REVENUES
<TABLE>
<CAPTION>
         ($ Millions)                                             FORECAST PRICES AND COSTS
                                           ---------------------------------------------------------------------
                                               UNDISCOUNTED                          DISCOUNTED AT
                                           ---------------------    --------------------------------------------
                                                                         10%             15%             20%
                                                                         ---             ---             ---
<S>                                             <C>                    <C>            <C>            <C>
Proved developed                                $15,949                $ 9,819        $ 8,464        $ 7,511

Proved undeveloped                                4,705                  2,054          1,471          1,079
                                           ---------------------    -------------  -------------  --------------
Total proved reserves                            20,654                 11,873          9,935          8,590

Total proved and probable reserves              $28,056                $14,893        $12,118        $10,247
                                           =====================    =============  =============  ==============
</TABLE>

                                      NOTES

1.       "Gross" reserves means the total working interest share of remaining
         recoverable reserves owned by the Company before deduction of royalties
         payable to others.

2.       "Net" reserves mean the Company's gross reserves less all royalties
         payable to others plus royalties receivable from others.

3.       "Proved developed" reserves were evaluated using SEC standards and can
         be expected to be recovered through existing wells with existing
         equipment and operating methods. SEC standards require that these be
         evaluated using year-end constant prices and costs and be disclosed net
         of royalties. The Company has also provided these reserves and their
         associated values using forecast prices and costs as well as before
         royalties as additional voluntary information.

4.       "Proved undeveloped" reserves were evaluated using SEC standards and
         are expected to be recovered from new wells on undrilled acreage, or
         from existing wells where relatively major expenditures are required
         for the completion of these wells or for the installation of processing
         and gathering facilities prior to the production of these reserves.
         Reserves on undrilled acreage are limited to those drilling units
         offsetting productive wells that are reasonably certain of production
         when drilled. SEC standards require that these be evaluated using
         year-end constant prices and costs and be disclosed net of royalties.
         The Company has also provided these reserves and their associated
         values using forecast prices and costs as well as before royalties as
         additional voluntary information.

5.       "Proved" reserves were evaluated using SEC standards and are those
         quantities of crude oil, natural gas and natural gas liquids, which
         geological and engineering data demonstrate with reasonable certainty
         to be recoverable in future years from known reservoirs under existing
         economic and operating conditions. SEC standards require that these be
         evaluated using year-end constant prices and costs and be disclosed net
         of royalties. The Company has also provided these reserves and their
         associated values using forecast prices and costs as well as before
         royalties as additional voluntary information.

6.       "Total Proved and Probable" reserves were evaluated using the COGEH
         standards of NI 51-101 and are those reserves where there is at least a
         50 per cent probability that the quantities actually recovered will
         equal or exceed the stated values. The Company has elected to disclose
         proved plus probable reserves and their associated values using both
         constant prices and costs as well as forecast prices and costs and has
         disclosed these before and net of royalties. The calculation of a
         probable reserves and value component by subtracting the proved
         reserves from the proved plus probable reserves may be subject to error
         due to the different standards applied in the determination of each
         value. The impact, however, is not material.

7.       Canadian securities legislation and policies permit the disclosure,
         which is included or incorporated by reference herein under a
         multi-jurisdicitional disclosure system adopted by the SEC, of probable
         reserves which may not be disclosed in registration statements
         otherwise filed with the SEC. Probable reserves are generally believed
         to be less likely to be recovered than proved reserves. The reserve
         estimates, included or incorporated by reference in this Annual
         Information Form could be materially different from the quantities and
         values ultimately realized.

8.       All values are shown in Canadian dollars.

<PAGE>

                                       23


9.       The constant price and cost case assumes that prices in effect at the
         end of the year adjusted for quality and transportation as well as the
         2003 costs are held constant over life. The constant price assumptions
         assume the continuance of current laws, regulations and operating costs
         in effect on the date of the Evaluation Report. Product prices have not
         been escalated beyond 2004. In addition, operating and capital costs
         have not been increased on an inflationary basis.

         The crude oil and natural gas constant prices used in the Evaluation
Reports are as follows:
<TABLE>
<CAPTION>
                             NATURAL GAS                                    CRUDE OIL & NGLs
         ---------------------------------------------  ------------------------------------------------
                                                                             HARDISTY
          COMPANY                                        COMPANY                HEAVY              NORTH
          AVERAGE  HENRY HUB               HUNTINGDON/   AVERAGE    WTI @   12(DEGREE) EDMONTON      SEA
            PRICE  LOUISIANA        AECO         SUMAS    PRICE  CUSHING(i)      API    PAR(ii)    BRENT
YEAR     $CDN/MCF  $US/MMBTU  $CDN/MMBTU    $CDN/MMBTU  $CDN/BBL  $US/BBL    $CDN/BBL  $CDN/BBL  $US/BBL
----     --------  ---------  ----------    ----------  --------   -------   --------  --------  -------
<S>       <C>         <C>         <C>            <C>      <C>       <C>       <C>       <C>       <C>
2004      6.63        5.80        6.88           6.94     31.82     32.56     26.16     40.68     30.14
</TABLE>

(i)      "WTI @ Cushing" refers to the price of West Texas Intermediate crude
         oil at Cushing, Oklahoma.

(ii)     "Edmonton Par Price" refers to the price of light gravity (40o API),
         low sulphur content crude oil at Edmonton, Alberta.

(iii)    Foreign exchange rate used was $0.77 US / $1.00 Cdn.

10.      The forecast price and cost cases assume the continuance of current
         laws and regulations, and any increases in wellhead selling prices also
         take inflation into account. Sales prices are based on reference prices
         as detailed below and adjusted for quality and transporation.
         Subsequent to 2015, reference prices and costs are escalated at 1.5 per
         cent per year. Future crude oil, natural gas liquids and natural gas
         price forecasts were based on Sproule's January 1, 2004 crude oil,
         natural gas liquids and natural gas pricing model.

         The crude oil and natural gas forecast prices used in the Evaluation
Reports are as follows:
<TABLE>
<CAPTION>
                             NATURAL GAS                                    CRUDE OIL & NGLs
         ---------------------------------------------  ------------------------------------------------
                                                                             HARDISTY
          COMPANY                                        COMPANY                HEAVY              NORTH
          AVERAGE  HENRY HUB               HUNTINGDON/   AVERAGE    WTI @   12(DEGREE) EDMONTON      SEA
            PRICE  LOUISIANA        AECO         SUMAS    PRICE   CUSHING         API       PAR    BRENT
YEAR     $CDN/MCF  $US/MMBTU  $CDN/MMBTU    $CDN/MMBTU  $CDN/BBL  $US/BBL    $CDN/BBL  $CDN/BBL  $US/BBL
----     --------  ---------  ----------    ----------  --------   -------   --------  --------  -------
<S>       <C>         <C>         <C>            <C>      <C>       <C>       <C>       <C>       <C>
2004      5.80        5.32        6.04           6.10     29.27     29.63     23.80     37.99     27.63
2005      5.18        4.81        5.36           5.52     26.55     26.80     21.28     34.24     25.27
2006      4.63        4.39        4.80           5.06     25.89     25.76     20.80     32.87     24.21
2007      4.68        4.46        4.91           5.17     26.28     26.14     21.33     33.37     24.57
2008      4.73        4.52        4.98           5.24     26.64     26.53     21.84     33.87     24.94
2009      4.80        4.59        5.05           5.31     26.47     26.93     22.31     34.38     25.32
2010      4.92        4.66        5.14           5.40     26.37     27.34     22.80     34.90     25.70
2011      5.02        4.73        5.24           5.50     26.65     27.75     23.29     35.43     26.08
2012      5.11        4.80        5.33           5.59     26.60     28.16     23.79     35.96     26.47
2013      5.18        4.87        5.43           5.69     26.80     28.58     24.29     36.50     26.87
2014      5.29        4.95        5.52           5.78     27.78     29.01     24.81     37.05     27.27
2015      5.34        5.02        5.62           5.88     28.13     29.45     25.33     37.61     27.68
</TABLE>

(i)      Foreign exchange rate used was $0.75 US / $1.00 Cdn throughout the
         forecast

11.      Estimated future net revenue from all assets is income derived from the
         sale of net reserves of crude oil, natural gas and natural gas liquids,
         less all capital costs, production taxes, and operating costs and
         before provision for income taxes, administrative overhead costs and
         existing asset abandonment liabilities.

<PAGE>

                                       24


12.      The estimated total development capital costs net to the Company
         necessary to achieve the estimated future net "proved" and "proved and
         probable" production revenues are:

<TABLE>
<CAPTION>
                                PROVED                                    PROVED AND PROBABLE
              ----------------------------------------------------------------------------------------------
              FORECAST PRICE CASE    CONSTANT PRICE CASE      FORECAST PRICE CASE      CONSTANT PRICE CASE
                  ($Millions)            ($Millions)              ($Millions)              ($Millions)
              -------------------    -------------------      -------------------      -------------------
<C>                      <C>                    <C>                   <C>                      <C>
2004                     895                    894                   1,027                    1,026
2005                     651                    639                     986                      971
2006                     229                    221                     512                      501
2007                     197                    187                     226                      219
2008                     191                    179                     323                      290
2009                      86                     78                     121                      110
2010                      60                     55                      96                       88
2011                      58                     52                     166                      150
2012                      42                     37                      43                       38
2013                      28                     24                     178                      156
2014                       3                      2                       3                        2
2015                       1                      1                      14                       11
Thereafter               181                    148                     348                      286
</TABLE>

13       Estimated future net revenue includes the value of the Company's
         midstream assets which is estimated to be $638.9 million undiscounted
         and $313.4 million, $243.1 million and $197.3 million discounted at
         10%, 15% and 20% respectively.

14.      The Evaluation Reports involved data supplied by the Company with
         respect to quality, heating value and transportation adjustments,
         interests owned, royalties payable, operating costs and contractual
         commitments. This data was audited by Sproule against corporate
         financial statements and was found to have no material differences. No
         field inspection was conducted.

A report on reserves data by Sproule and a report of the Company's management
and directors on oil and natural gas disclosure are provided in Schedules A and
B, respectively, to this Annual Information Form. The Company does not file
estimates of its total oil and natural gas reserves with any U. S. agency or
federal authority other than the SEC.

<PAGE>

                                       25


C.       RECONCILIATION OF CHANGES IN NET RESERVES

The following table summarizes the changes during the past year in reserves
after deduction of royalties payable to others and using constant prices and
costs:

<TABLE>
<CAPTION>
                              ----------------------------------------------- -------------------------------------------------
                                CRUDE OIL AND NATURAL GAS LIQUIDS (MMBBLS)                   NATURAL GAS (BCF)
                                                        OFFSHORE                                         OFFSHORE
                                 NORTH       NORTH        WEST                    NORTH       NORTH        WEST
                                AMERICA       SEA        AFRICA      TOTAL       AMERICA       SEA        AFRICA       TOTAL
                              ----------- ----------- ----------- ----------- ------------ ----------- -----------  -----------
<S>                                   <C>         <C>         <C>       <C>          <C>           <C>          <C>       <C>
PROVED RESERVES
Reserves, December 31, 2002           571         202          75         848        2,446          71          71        2,588
Extensions and discoveries              1          --          13          14           58          --           6           64
Infill Drilling                        54          --          --          54          243          --          --          243
Improved Recovery                       9          --          --           9            8          --          --            8
Property purchases                      7          27          --          34           50          19          --           69
Property disposals                     --          --          --          --           (3)         --          --           (3)
Production                            (56)        (21)         (4)        (81)        (355)        (17)         (3)        (375)
Revisions of prior estimates            2          14           1          17         (21)         (11)        (10)         (42)
                              ----------- ----------- ----------- ----------- ------------ ----------- ----------- ------------
Reserves, December 31, 2003           588         222          85         895        2,426          62          64        2,552
                              ----------- ----------- ----------- ----------- ------------ ----------- ----------- -----------
TOTAL PROVED AND
PROBABLE RESERVES
Reserves, December 31, 2002           636         277         121       1,034        2,765          89          90        2,944
Extensions and discoveries              1          --          17          18           72          --          11           83
Infill Drilling                        58          --          --          58          285          --          --          285
Improved Recovery                      25          --          12          37           26          --          (6)          20
Property purchases                     10          33          --          43           59          22          --           81
Property disposals                     --          --          --          --           (3)         --          --           (3)
Production                            (56)        (21)         (4)        (81)        (355)        (17)         (3)        (375)
Revisions of prior estimates          183          28         (13)        198           70           8         (20)          58
                              ----------- ----------- ----------- ----------- ------------ ----------- ----------- ------------
Reserves, December 31, 2003           857         317         133       1,307        2,919         102          72        3,093
                              ----------- ----------- ----------- ----------- ------------ ----------- ----------- ------------
</TABLE>

Information on the Company's oil and natural gas reserves is provided in
accordance with United States FAS 69, "Disclosures About Oil and Gas Producing
Activities" in the Company's 2003 Annual Report under "Supplementary Oil and Gas
Information" on pages 82 to 85 and is incorporated herein by reference.

<PAGE>

                                       26


D.       CRUDE OIL AND NATURAL GAS PRODUCTION

The Company's working interest share of oil, NGLs and natural gas production and
revenues received for the last three financial years is summarized in the
following tables:

                                                       YEAR ENDED DECEMBER 31
                                         ---------------------------------------
                                           2003          2002          2001
                                           ----          ----          ----
  Daily Production
       Crude Oil and NGLs (bbls/d)       242,392       215,335      206,323
       Natural Gas (MMcf/d)              1,298.7       1,232.3        918.1
  Annual Production
       Crude Oil and NGLs (Mbbls)         88,473        78,597       75,308
       Natural Gas (Bcf)                   474.0         449.8        355.1


<TABLE>
<CAPTION>
NETBACKS
INFORMATION BY QUARTER

                                                        YEAR 2003                                     YEAR 2002
                                   -----------------------------------------------   -----------------------------------------------
                                       1ST       2ND       3RD       4TH      YEAR       1ST       2ND       3RD        4TH     YEAR
                                   QUARTER   QUARTER   QUARTER   QUARTER     ENDED   QUARTER   QUARTER   QUARTER    QUARTER    ENDED
                                   -------   -------   -------   -------     -----   -------   -------   -------    -------    -----
<S>                                 <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>        <C>      <C>
PRODUCT NETBACKS
Crude oil and NGLs ($/bbl)
    Sales Price                     $35.26    $30.27    $30.97    $30.02    $31.59    $24.50    $28.27    $33.57     $31.10   $29.76
    Royalties                       $ 3.56    $ 2.78    $ 2.56    $ 2.22    $ 2.77    $ 2.28    $ 3.02    $ 3.56     $ 3.53   $ 3.16
    Production Expenses             $10.79    $10.80    $10.14    $ 9.45    $10.28    $ 7.81    $ 7.95    $ 8.67     $ 9.10   $ 8.45
    NETBACK                         $20.91    $16.69    $18.27    $18.35    $18.54    $14.41    $17.30    $21.34     $18.47   $18.15

Natural Gas ($/Mcf)
    Sales Price                      $7.25     $6.12     $5.50     $5.23     $6.02     $3.06     $3.68     $3.13      $5.00    $3.76
    Royalties                        $1.78     $1.35     $1.11     $1.05     $1.32     $0.55     $0.77     $0.67      $1.09    $0.78
    Production Expenses              $0.57     $0.59     $0.63     $0.63     $0.60     $0.58     $0.57     $0.55      $0.57    $0.57
    NETBACK                          $4.90     $4.18     $3.76     $3.55     $4.10     $1.93     $2.34     $1.91      $3.34    $2.41

CRUDE OIL AND NGL NETBACKS BY TYPE
Light/Pelican Lake/NGLs ($/bbl)
    Sales Price                     $41.51    $34.53    $35.75    $36.20    $36.97    $28.58    $31.84    $36.58     $36.38   $33.84
    Royalties                       $ 4.18    $ 3.32    $ 3.11    $ 2.82    $ 3.35    $ 3.25    $ 4.04    $ 4.48     $ 4.39   $ 4.10
    Production Expenses             $10.42    $ 9.76    $ 9.53    $ 9.65    $ 9.83    $ 7.48    $ 8.36    $10.06     $ 9.38   $ 8.97
    NETBACK                         $26.91    $21.45    $23.11    $23.73    $23.79    $17.85    $19.44    $22.04     $22.61   $20.77

Heavy ($/bbl)
    Sales Price                     $26.63    $24.56    $24.46    $22.14    $24.39    $20.01    $24.20    $29.78     $24.54   $24.89
    Royalties                       $ 2.71    $ 2.06    $ 1.83    $ 1.47    $ 2.00    $ 1.21    $ 1.86    $ 2.42     $ 2.45   $ 2.03
    Production Expenses             $11.30    $12.19    $10.96    $ 9.19    $10.88    $ 8.18    $ 7.48    $ 6.91     $ 8.77   $ 7.84
    Netback                         $12.62    $10.31    $11.67    $11.48    $11.51    $10.62    $14.86    $20.45     $13.32   $15.02
</TABLE>


NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium quality
      crude netbacks due to exceptionally low operating costs and low royalty
      rates.

<PAGE>

                                       27


<TABLE>
<CAPTION>
NETBACKS
INFORMATION BY QUARTER

                                                        YEAR 2003                                     YEAR 2002
                                   -----------------------------------------------   -----------------------------------------------
                                       1ST       2ND       3RD       4TH      YEAR       1ST       2ND       3RD        4TH     YEAR
                                   QUARTER   QUARTER   QUARTER   QUARTER     ENDED   QUARTER   QUARTER   QUARTER    QUARTER    ENDED
                                   -------   -------   -------   -------     -----   -------   -------   -------    -------    -----
<S>                                 <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>        <C>      <C>
SEGMENTED
NORTH AMERICA PRODUCT NETBACKS
Light/Pelican Lake/NGLs ($/bbl)
     Sales Price                    $35.08    $32.01    $31.97    $31.64    $32.69    $25.27    $28.90    $32.83     $31.94   $30.01
     Royalties                      $ 7.65    $ 6.33    $ 6.04    $ 5.51    $ 6.39    $ 4.24    $ 5.11    $ 5.98     $ 5.81   $ 5.35
     Production Expenses            $ 6.09    $ 6.42    $ 6.76    $ 7.24    $ 6.62    $ 5.25    $ 5.30    $ 5.00     $ 5.28   $ 5.20
     NETBACK                        $21.34    $19.26    $19.17    $18.89    $19.68    $15.78    $18.49    $21.85     $20.85   $19.46

Heavy ($/bbl)
     Sales Price                    $26.63    $24.56    $24.46    $22.14    $24.39    $20.01    $24.20    $29.78     $24.54   $24.89
     Royalties                      $ 2.71    $ 2.06    $ 1.83    $ 1.47    $ 2.00    $ 1.21    $ 1.86    $ 2.42     $ 2.45   $ 2.03
     Production Expenses            $11.30    $12.19    $10.96    $ 9.19    $10.88    $ 8.18    $ 7.48    $ 6.91     $ 8.77   $ 7.84
     NETBACK                        $12.62    $10.31    $11.67    $11.48    $11.51    $10.62    $14.86    $20.45     $13.32   $15.02

Natural Gas ($/Mcf)
     Sales Price                     $7.36     $6.25     $5.62     $5.32     $6.14     $3.05     $3.72     $3.15      $5.04    $3.78
     Royalties                       $1.84     $1.40     $1.16     $1.10     $1.38     $0.57     $0.79     $0.69      $1.11    $0.80
     Production Expenses             $0.55     $0.56     $0.58     $0.60     $0.57     $0.56     $0.55     $0.52      $0.55    $0.55
     NETBACK                         $4.97     $4.29     $3.88     $3.62     $4.19     $1.92     $2.38     $1.94      $3.38    $2.43

NORTH SEA PRODUCT NETBACKS
Light Oil ($/bbl)
     Sales Price                    $50.27    $37.83    $39.84    $41.93    $42.43    $33.75    $39.36    $41.68     $41.83   $39.79
     Royalties                      $ 0.11    ($0.19)   $ 0.09    ($0.15)   ($0.03)   $ 1.54    $ 1.76    $ 2.56     $ 2.79   $ 2.30
     Production Expenses            $15.50    $14.17    $13.25    $13.42    $14.07    $10.09    $15.72    $18.30     $14.68   $15.06
     NETBACK                        $34.66    $23.85    $26.50    $28.66    $28.39    $22.12    $21.88    $20.82     $24.36   $22.43

Natural Gas ($/Mcf)
     Sales Price                     $4.03     $2.21     $2.57     $3.32     $3.03     $3.77     $1.80     $1.98      $3.20    $2.75
     Royalties                          --        --        --        --        --        --        --        --         --       --
     Production Expenses             $1.09     $1.45     $1.60     $1.16     $1.33     $1.33     $1.90     $1.78      $1.25    $1.53
     NETBACK                         $2.94     $0.76     $0.97     $2.16     $1.70     $2.44    ($0.10)    $0.20      $1.95    $1.22

OFFSHORE WEST AFRICA
PRODUCT NETBACKS
Light Oil ($/bbl)
     Sales Price                    $37.86    $34.34    $37.37    $36.42    $36.47    $37.61    $33.92    $42.78     $43.15   $40.10
     Royalties                       $1.20     $0.99     $1.13     $1.03     $1.08     $1.65     $1.11     $1.34      $1.35    $1.35
     Production Expenses            $14.03     $9.32     $7.11     $6.67     $8.68    $18.62    $12.76    $11.23     $13.68   $13.63
     NETBACK                        $22.63    $24.03    $29.13    $28.72    $26.71    $17.34    $20.05    $30.21     $28.12   $25.12

Natural Gas ($/Mcf)
     Sales Price                     $3.80     $5.09     $4.59     $3.95     $4.37        --        --     $4.97      $4.63    $4.82
     Royalties                       $0.11     $0.15     $0.14     $0.11     $0.13        --        --     $0.15      $0.15    $0.15
     Production Expenses             $2.37     $1.45     $1.24     $1.18     $1.39        --        --     $1.77      $1.85    $1.81
     NETBACK                         $1.32     $3.49     $3.21     $2.66     $2.85    $   --     $  --     $3.05      $2.63    $2.86
</TABLE>



NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium quality
      crude netbacks due to exceptionally low operating costs and low royalty
      rates.

<PAGE>

                                       28


NETBACKS
INFORMATION BY QUARTER

<TABLE>
<CAPTION>
                                                                      YEAR 2001
                                          ---------------------------------------------------------------
                                               1ST          2ND         3RD           4TH            YEAR
                                           QUARTER      QUARTER     QUARTER       QUARTER           ENDED
                                           -------      -------     -------       -------           -----
<S>                                        <C>          <C>         <C>           <C>             <C>
AVERAGE DAILY PRODUCTION VOLUMES
    Crude Oil and NGLs (bbls)              205,588      214,716     207,065       198,000         206,323
    Natural Gas (Mcf)                        850.8        884.6       923.8       1,011.6           918.1

PRODUCT NETBACKS
    Crude oil and NGLs ($/bbl)
    Sales Price                             $22.06       $25.32      $28.37        $21.28          $24.31
    Royalties                                 2.36         2.42        2.47          1.41            2.17
    Production Expenses                       8.18         7.57        7.29          7.52            7.64
NETBACK                                     $11.52       $15.33      $18.61        $12.35          $14.50

NATURAL GAS ($/MCF)
    Sales Price                              $9.30        $5.93       $3.12         $2.94           $5.16
    Royalties                                 2.40         1.47        0.67          0.62            1.25
    Production Expenses                       0.50         0.50        0.50          0.53            0.51
    NETBACK                                  $6.40        $3.96       $1.95         $1.79           $3.40

CRUDE OIL AND NGL NETBACKS BY TYPE
    Light/Pelican Lake/NGLs ($/bbl)
    Sales Price                             $30.96       $33.59      $32.75        $26.95          $31.13
    Royalties                                 4.03         3.86        3.30          2.29            3.38
    Production Expenses                       5.99         6.10        6.12          7.15            6.34
    NETBACK                                 $20.94       $23.63      $23.33        $17.51          $21.41

HEAVY ($/BBL)
    Sales Price                             $12.76       $15.83      $23.21        $14.85          $16.63
    Royalties                                 0.61         0.77        1.50          0.43            0.83
    Production Expenses                      10.48         9.24        8.68          7.93            9.10
    Netback                                  $1.67        $5.82      $13.03         $6.49           $6.70

NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium quality crude netbacks due to
exceptionally low operating costs and low royalty rates.

SEGMENTED
NORTH AMERICA PRODUCT NETBACKS
                                                                      YEAR 2001
                                          ---------------------------------------------------------------
                                               1ST          2ND         3RD           4TH            YEAR
                                           QUARTER      QUARTER     QUARTER       QUARTER           ENDED
                                           -------      -------     -------       -------           -----
Light/Pelican Lake/NGLs ($/bbl)
    Sales Price                             $27.04       $27.49      $29.95        $23.83          $27.10
    Royalties                                 4.57         5.04        4.17          2.79            4.16
    Production Expenses                       3.84         4.02        4.22          4.74            4.19
    NETBACK                                 $18.63       $18.43      $21.56        $16.30          $18.75

Heavy ($/bbl)
    Sales Price                             $12.76       $15.83      $23.21        $14.85          $16.63
    Royalties                                 0.61         0.77        1.50          0.43            0.83
    Production Expenses                      10.48         9.24        8.68          7.93            9.10
    NETBACK                                  $1.67        $5.82      $13.03         $6.49           $6.70

Natural Gas ($/Mcf)
    Sales Price                              $9.30        $5.99       $3.13         $2.94           $5.19
    Royalties                                 2.40         1.49        0.68          0.63            1.26
    Production Expenses                       0.50         0.50        0.50          0.52            0.50
    NETBACK                                  $6.40        $4.00       $1.95         $1.79           $3.43

NORTH SEA PRODUCT NETBACKS
Light Oil ($/bbl)
    Sales Price                             $41.04       $43.07      $37.28        $33.39          $38.66
    Royalties                                $2.86        $2.23       $1.97         $1.52           $2.10
    Production Expenses                      $9.22        $8.42       $8.09        $10.54           $9.00
    NETBACK                                 $28.96       $32.42      $27.22        $21.33          $27.56

Natural Gas ($/Mcf)
    Sales Price                             $   --       $ 1.74      $ 2.51        $ 3.00          $ 2.51
    Royalties                               $   --       $   --      $   --        $   --          $   --
    Production Expenses                     $   --       $ 0.61      $ 0.74        $ 1.34          $ 0.94
    NETBACK                                 $   --       $ 1.13      $ 1.77        $ 1.66          $ 1.57
</TABLE>


<PAGE>

                                       29


OFFSHORE WEST AFRICA PRODUCT NETBACKS
<TABLE>
<CAPTION>
                                                                      YEAR 2001
                                          ---------------------------------------------------------------
                                               1ST          2ND         3RD           4TH            YEAR
                                           QUARTER      QUARTER     QUARTER       QUARTER           ENDED
                                           -------      -------     -------       -------           -----
<S>                                         <C>          <C>         <C>           <C>             <C>
Light Oil ($/bbl)
    Sales Price                             $40.58       $39.75      $34.66        $19.56          $33.57
    Royalties                               $   --       $ 0.65      $ 2.03        $ 0.64          $ 0.93
    Production Expenses                     $38.80       $17.23      $19.05        $19.15          $21.77
    NETBACK                                 $ 1.78       $21.87      $13.58        $(0.23)         $10.87

Natural Gas ($/Mcf)
    Sales Price                                 --           --          --            --              --
    Royalties                                   --           --          --            --              --
    Production Expenses                         --           --          --            --              --
    NETBACK                                 $   --       $   --      $   --        $   --          $   --
</TABLE>


E.       HISTORICAL DRILLING ACTIVITY BY PRODUCT

The following table sets forth the gross and net wells in which the Company has
participated for the period indicated:

                                            YEAR ENDED DECEMBER 31
                            ---------------------------------------------------
                                     2003                       2002
                            ------------------------   ------------------------
                                GROSS         NET          GROSS        NET
                                -----         ---          -----        ---
Natural Gas                       841         777            183        162
Crude Oil                         490         458            316        264
Service/Stratigraphic             447         440            456        447
Dry Holes                         126         118             32         27
                            ------------------------   ------------------------
Total                           1,904       1,793            987        900
                            ========================   ========================
*Total Success Rate                           91%                       94%

*excluding service and stratigraphic test wells

<PAGE>

                                       30


F.       CAPITAL EXPENDITURES

Costs incurred by the Company in respect of its programs of acquisition and
disposition, and exploration and development of crude oil and natural gas
properties, are summarized in the following tables:

                                                 YEAR ENDED DECEMBER 31
                                           -------------------------------------
                                                  2003                2002
                                           ----------------      ---------------
Corporate acquisition                               --               2,393
Net property acquisitions                          336                 440
Land acquisition and retention                     154                 114
Seismic evaluation                                  77                  63
Well drilling, completion and equipping          1,194                 626
Pipeline and production facilities                 522                 292
                                           ----------------      ---------------

Reserve replacement expenditures                 2,283               3,928
Midstream operations                                11                  20
Horizon Project                                    152                  68
Abandonments                                        40                  43
Head office equipment                               20                  10
                                           ----------------      ---------------

Total Net Capital Expenditures                   2,506               4,069
                                           ================      ===============

<PAGE>

                                       31


<TABLE>
<CAPTION>
                                                                     2003 THREE MONTHS ENDED
                                               ---------------------------------------------------------------------
                                                                           ($ Millions)
CAPITAL EXPENDITURES
BY QUARTER                                         MAR. 31            JUNE 30         SEPT. 30          DEC. 31
                                                   -------            -------         --------          -------
<S>                                                    <C>                <C>              <C>              <C>
Corporate acquisition                                   --                 --               --               --

Net property acquisitions                              178                 23              106               29

Land acquisition and retention                          21                 36               53               44

Seismic evaluation                                      19                 21               12               25

Well drilling, completion and equipping                396                190              256              352

Pipeline and production facilities                     149                107              133              133
                                                   -------            -------         --------          -------

Reserve replacement expenditures                       763                377              560              583

Midstream operations                                     3                  1                5                2

Horizon Project                                         41                 27               32               52

Abandonments                                             3                  3               14               20

Head office equipment                                    3                  2               10                5
                                                   -------            -------         --------          -------

Total Net Capital Expenditures                         813                410              621              662
                                               =====================================================================



                                                                     2002 THREE MONTHS ENDED
                                               ---------------------------------------------------------------------
                                                                           ($ Millions)
CAPITAL EXPENDITURES
BY QUARTER                                         MAR. 31            JUNE 30         SEPT. 30          DEC. 31
                                                   -------            -------         --------          -------

Corporate acquisition
                                                        --                 --            2,393               --
Net property acquisitions
                                                        35                 33              333               39
Land acquisition and retention
                                                        28                 19               48               18
Seismic evaluation
                                                        25                 14                5               19
Well drilling, completion and equipping
                                                       207                136              144              139
Pipeline and production facilities
                                                       124                 67               56               45
                                                   -------            -------         --------          -------

Reserve replacement expenditures                       419                269            2,979              260
Midstream operations
                                                        10                  5               --                6
Horizon Project
                                                        22                 17               10               19
Abandonments
                                                         7                 12               20                4
Head office equipment
                                                         1                  2                4                3
                                                   -------            -------         --------          -------

Total Net Capital Expenditures                         459                305            3,013              292
                                               =====================================================================
</TABLE>

<PAGE>

                                       32


G.       NON-RESERVE ACREAGE

The following table summarizes the Company's working interest holdings in core
area non-reserve acreage as at December 31, 2003:

                                          GROSS ACRES                NET ACRES
                                          -----------                ---------
                                          (thousands)               (thousands)
         NORTH AMERICA
         Alberta                                9,304                    7,859
         British Columbia                       2,011                    1,560
         Saskatchewan                             449                      380
         Manitoba                                  12                       12

         NORTH SEA
         United Kingdom                           804                      573
         France                                 2,693                    1,347

         OFFSHORE WEST AFRICA
         Angola                                 1,220                      610
         Cote d'Ivoire                            452                      333
                                                5,550                    5,550
         South Africa
                                         ---------------          --------------
         Total                                 22,495                   18,224
                                         ===============          ==============


H.                DEVELOPED ACREAGE

The following table summarizes the Company's working interest holdings in core
region developed acreage as at December 31, 2003:

                                          GROSS ACRES                NET ACRES
                                          -----------                ---------
                                          (thousands)               (thousands)
         NORTH AMERICA
         Alberta                                4,361                    3,415
         British Columbia                         605                      461
         Saskatchewan                             295                      156
         Manitoba                                   5                        4

         NORTH SEA
         United Kingdom                           106                       65
         France                                    --                       --

         OFFSHORE WEST AFRICA
         Angola                                    --                       --
         Cote d'Ivoire                              8                        5
         South Africa                              --                       --
                                         ---------------          --------------
         Total                                  5,380                    4,106
                                         ===============          ==============

<PAGE>

                                       33


                         SELECTED FINANCIAL INFORMATION

The following table summarizes the consolidated financial statements of the
Company, which follows the full cost method of accounting for crude oil and
natural gas operations:

<TABLE>
<CAPTION>
                                                                          -----------------------------------------
                                                                                   YEAR ENDED DECEMBER 31
                                                                          -----------------------------------------
                                                                                 2003                 2002
                                                                                 ----                 ----
                                                                          ($ millions, except per share information)
<S>                                                                             <C>                  <C>
Revenues (1) (net of royalties)                                                  5,100                3,742

Cash flow from operations attributable to common shareholders                    3,160                2,254

Per common share - basic                                                         23.54                17.63

                 - diluted                                                       23.06                16.99

Net earnings attributable to common shareholders                                 1,407                  570

Per common share - basic                                                         10.48                 4.46

                 - diluted                                                       10.14                 4.31

Total assets                                                                    14,198               13,359

Total long-term debt(2)                                                          2,645                4,074
</TABLE>

<TABLE>
<CAPTION>
                                  ---------------------------------------------------------------------------------
                                                              2003 THREE MONTHS ENDED
                                  ---------------------------------------------------------------------------------
                                             MARCH 31             JUNE 30            SEPT. 30              DEC. 31
                                             --------             -------            --------              -------
                                                     ($ millions, except per share information)
<S>                                           <C>                 <C>                 <C>                  <C>
Revenues (1) (net of  royalties)              1,407               1,254               1,244                1,195
Net earnings attributable to                    428                 525                 203                  251
common shareholders

Per common share - basic                       3.19                3.91                1.51                 1.87
                 - diluted                     3.03                3.78                1.49                 1.83


                                  ---------------------------------------------------------------------------------
                                                              2002 THREE MONTHS ENDED
                                  ---------------------------------------------------------------------------------
                                             MARCH 31             JUNE 30            SEPT. 30              DEC. 31
                                             --------             -------            --------              -------
                                                     ($ millions, except per share information)

Revenues (1) (net of royalties)                 690                 797               1,072                1,183
Net earnings attributable to                     99                 145                 117                  209
common shareholders

Per common share - basic                       0.81                1.18                0.88                 1.56
                 - diluted                     0.79                1.09                0.86                 1.51
</TABLE>

(1)  Restated to exclude transportation costs from revenue.
(2)  Excluding current portion of ling-term debt.

<PAGE>

                                       34


            MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES

The Company's common shares are listed and posted for trading on Toronto Stock
Exchange and the New York Stock Exchange under the symbol CNQ.

On January 17, 2001, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of Toronto Stock Exchange and the New York
Stock Exchange, beginning January 22, 2001 and ending January 21, 2002, to
purchase for cancellation up to 6,114,726 common shares of the Company, being 5
per cent of the 122,294,533 common shares of the Company outstanding on January
17, 2001. During this period, 2,537,800 common shares were purchased for
cancellation at an average price of $44.61.

On January 21, 2002, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of Toronto Stock Exchange and the New York
Stock Exchange, beginning January 23, 2002 and ending January 22, 2003, to
purchase for cancellation up to 6,060,180 common shares of the Company, being 5
per cent of the 121,203,603 common shares of the Company outstanding on January
18, 2002. No common shares were purchased during this program.

In January 2002, the Company issued 60,000 flow-through common shares at a price
of $39.00 per common share. The value of the common shares was determined as the
closing market price on Toronto Stock Exchange on the day prior to the allotment
of the common shares.

On January 22, 2003, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of Toronto Stock Exchange and the New York
Stock Exchange, beginning January 24, 2003 and ending January 23, 2004, to
purchase for cancellation up to 6,692,799 common shares of the Company, being 5
per cent of the 133,855,988 common shares of the Company outstanding on January
17, 2003. Under this program, the Company purchased a total of 2,734,800 common
shares for cancellation at an average purchase price of $52.51 for each common
share purchased.

On January 22, 2004, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of Toronto Stock Exchange and the New York
Stock Exchange, commencing January 24, 2004 and ending January 23, 2005, to
purchase for cancellation up to 6,690,385 common shares of the Company, being 5
per cent of the 133,807,695 common shares of the Company outstanding on January
13, 2004.

On February 19, 2004, the Board of Directors passed a resolution proposing an
amendment to the Articles of the Company to split the issued and outstanding
Common Shares of the Company on a two-for-one basis subject to shareholder
approval at the Annual and Special Meeting of Shareholders scheduled for May 6,
2004.

                                DIVIDEND HISTORY

The dividend policy of the Company undergoes a periodic review by the Board of
Directors and is subject to change at any time depending upon the earnings of
the Company, its financial requirements and other factors existing at the time.
Prior to 2001, dividends had not been paid on the common shares of the Company.
On January 17, 2001 the Board of Directors approved a dividend policy for the
payment of a regular quarterly dividend of $0.10 per common share. On February
25, 2002 the Board of Directors approved an increase in the quarterly dividend
to $0.125 per common share commencing with the dividend payable April 1, 2002.
On February

<PAGE>

                                       35


20, 2003 the Board of Directors approved a further increase in the quarterly
dividend to $0.15 per common share commencing with the dividend payable April 1,
2003. The Board of Directors reviewed the dividend payments for 2004 and on
February 19, 2004 the Board of Directors approved a 33 per cent increase in the
quarterly dividend to $0.20 per common share commencing with the dividend
payable April 1, 2004. Dividends have been paid on the first day of January,
April, July and October of each year since 2001.

                             DIRECTORS AND OFFICERS

The names, municipalities of residence, offices held with the Company and
principal occupations of the directors and officers of the Company are set forth
below:

<TABLE>
<CAPTION>
                               POSITION                  PRINCIPAL
                               PRESENTLY                 OCCUPATION
NAME                           HELD                      DURING PAST 5 YEARS
<S>                            <C>                       <C>
Catherine M. Best              Director(2)               Senior Vice-President,  Risk Management and Chief Financial
Calgary, Alberta               (age 50)                  Officer of the Calgary  Health Region from 2002 to present,
                                                         Vice-President, Corporate Services and Chief Financial
                                                         Officer of the Calgary Health Region from February 2000 to
                                                         2002; prior thereto with Ernst & Young since 1980, most
                                                         recently as a Corporate Audit Partner from 1991 to 2000.
                                                         Has served continuously as a director since November 2003.

N. Murray Edwards              Vice-Chairman and         President, Edco Financial Holdings Ltd. (a private
Calgary, Alberta               Director(3)(5)            management and consulting company). Has served
                               (age 44)                  continuously as a director of the Company since September
                                                         1988. Currently serving on the board of directors of Ensign
                                                         Resource Service Group Inc.; Magellan Aerospace
                                                         Corporation; and, Penn West Petroleum Ltd.

Ambassador Gordon D. Giffin    Director(1)(2)            Senior  Partner,  McKenna  Long &  Aldridge  LLP (law firm)
Atlanta, Georgia               (age 54)                  since May 2001;  prior thereto United States  Ambassador to
                                                         Canada. Has served continuously as a director of the
                                                         Company since May 2002. Currently serving on the board of
                                                         directors of Bowater, Inc.; Canadian National Railway;
                                                         Canadian Imperial Bank of Commerce; and, Transalta
                                                         Corporation.

James T. Grenon                Director(2)(4)            Managing  Director,  TOM Capital Associates Inc. (a private
Calgary, Alberta               (age 47)                  investment   company).   Has  served   continuously   as  a
                                                         director of the Company  since  September  1988.  Currently
                                                         serving on the board of trustees  for  Foremost  Industries
                                                         Income Fund.

John G. Langille               President and Director    Officer  of  the  Company.  Has  served  continuously  as a
Calgary, Alberta               (age 58)                  director of the Company since June 1982.

Keith A.J. MacPhail            Director(3)(5)            Chairman,  President and Chief Executive Officer, Bonavista
Calgary, Alberta               (age 47)                  Petroleum  Ltd.  (independent  oil and natural gas company)
                                                         since November 1997 and Chairman, NuVista Energy Ltd since
                                                         July 2003. Has served continuously as a director of the
                                                         Company since October 1993. Currently serving on the board
                                                         of directors of Bonavista Petroleum Ltd., Bonavista Energy
                                                         Trust and NuVista Energy Ltd.

Allan P. Markin                Chairman and Director     Chairman  of the  Company.  Has  served  continuously  as a
Calgary, Alberta               (age 58)                  director of the Company since January 1989.

James S. Palmer, C.M., A. O.   Director(1)(2)(3)(4)      Chairman,  Burnet,  Duckworth & Palmer LLP (law firm).  Has
E., Q.C.                       (age 75)                  served  continuously as a director of the Company since May
Calgary, Alberta                                         1997. Currently serving on the board of directors of Magellan
                                                         Aerospace Corporation; Trenton Iron Works; Rally Energy
                                                         Corp.; and, on the board of trustees for Rogers Sugar
                                                         Income Fund.
</TABLE>

<PAGE>

                                                         36


<TABLE>
<CAPTION>
                               POSITION                  PRINCIPAL
                               PRESENTLY                 OCCUPATION
NAME                           HELD                      DURING PAST 5 YEARS
<S>                            <C>                       <C>
Dr. Eldon R. Smith, M.D.       Director(4)(5)            Professor  and  Former  Dean,  Faculty  of  Medicine,   The
Calgary, Alberta               (age 64)                  University  of  Calgary.   Has  served  continuously  as  a
                                                         director of the Company since May 1997.  Currently  serving
                                                         on the  board  of  directors  of  Vasogen  Inc.;  Pheromone
                                                         Sciences Corp.; and, Biomax Technologies Inc.

David A. Tuer                  Director(1)(3)            President  and CEO of Hawker  Resources  Inc.  (independent
Calgary, Alberta               (age 54)                  oil  and  natural  gas  company)  since  January  2003  and
                                                         Chairman,  Calgary Health Region since October 2001.  Prior
                                                         thereto President and Chief Executive Officer,  PanCanadian
                                                         Energy  Corporation.  Has served continuously as a director
                                                         of the  Company  since May 2002.  Currently  serving on the
                                                         board of  directors  of Hawker  Resources  Inc.;  Rockwater
                                                         Capital Corporation;  Ultima Energy Trust; and, Argo Energy
                                                         Ltd

Steve W. Laut                  Chief Operating Officer   Officer of the Company
Calgary, Alberta               (age 46)

Real M. Cusson                 Senior Vice-President,    Officer of the Company
Calgary, Alberta               Marketing
                               (age 53)

Real J. H. Doucet              Senior Vice-President,    Officer of the Company since  October  2000;  prior thereto
Calgary, Alberta               Oil Sands                 director of various divisions at Suncor Inc. since 1993.
                               (age 51)

Allen M. Knight                Senior Vice-President,    Officer of the Company
Calgary, Alberta               International &
                               Corporate Development
                               (age 54)

Tim S. McKay                   Senior Vice-President,    Officer of the Company
Calgary, Alberta               Operations
                               (age 42)

Douglas A. Proll               Senior Vice-President,    Officer of the  Company  since April  2001;  prior  thereto
Calgary, Alberta               Finance                   Vice President Finance and Treasurer of Renaissance  Energy
                               (age 53)                  Ltd.  until August 2000 and most  recently  Vice  President
                                                         Finance and Business  Development of Husky Energy Inc. from
                                                         August 2000 to February 2001.

Lyle G. Stevens                SeniorVice-President,     Officer of the Company
Calgary, Alberta               Exploitation
                               (age 49)

Mary-Jo Case                   Vice-President, Land      Officer  of the  Company  since  May  2002;  prior  thereto
Calgary, Alberta               (age 45)                  Co-ordinator Land at PanCanadian  Petroleum Limited 1994 to
                                                         1999 and most recently Manager Commercial Ventures and Land
                                                         at PanCanadian Petroleum Limited 1999 to 2002.

William  R. Clapperton         Vice-President,           Officer of the Company since  January  2002;  prior thereto
Calgary, Alberta               Regulatory, Stakeholder   Manager, Surface Land and Environment for the Company.
                               and Environmental Affairs
                               (age 41)

Gordon M. Coveney              Vice-President,           Officer of the Company since September 2003;  prior thereto
Calgary, Alberta               Exploration, Northeast    Exploration Manager for the Company.
                               District
                               (age 50)

Cameron S. Kramer              Vice-President,           Officer of the Company since September 2002;  prior thereto
Calgary, Alberta               Field Operations          Production  Engineer  of the  Company  until March 2000 and
                               (age 36)                  most  recently  Manager,  Field  Operations  of the Company
                                                         from April 2000 to September 2002.
</TABLE>

<PAGE>

                                                         37


<TABLE>
<CAPTION>
                               POSITION                  PRINCIPAL
                               PRESENTLY                 OCCUPATION
NAME                           HELD                      DURING PAST 5 YEARS
<S>                            <C>                       <C>
Leon Miura                     Vice-President, Upgrading Officer of the Company since August 2003; prior thereto
Calgary, Alberta               (age 49)                  from 1978 to 2003 held progressively
                                                         senior positions at Petroleos de Venezuela including Cerro
                                                         Negro Execution Manager, Heavy Oil Upgrading from 1997 to
                                                         2001 and most recently Nitrogen Injection Project Director,
                                                         Secondary Recovery at Petroleos de Venezuela 2002 to 2003.

J. Kevin Stromquist            Vice-President,           Officer of the Company since September 2003, prior thereto
Calgary, Alberta               Exploration, Northwest    Exploration Manager for the Company.
Alberta                        (age 44)

Jeffrey W. Wilson              Vice-President,           Officer of the Company since September 2003;  prior thereto
Calgary, Alberta               Exploration, B. C./S.     Exploration Manager for the Company.
                               AB. Districts (age 51)

Lynn M. Zeidler                Vice-President, Bitumen   Officer of the Company  since  August 2003;  prior  thereto
Calgary, Alberta               Production                from  May  1980  to July  2003  held  progressively  senior
                               (age 47)                  positions at Shell Canada  Limited  including on secondment
                                                         from   Shell    Canada    Limited   as    Manager-Tier    1
                                                         Implementation  at Sable  Offshore  Energy Inc January 1998
                                                         to  September  2000  and  most  recently   General  Project
                                                         Manager,  Athahasca  Oil  Sands  Project  at  Shell  Canada
                                                         Limited  October 2000 to May 2003 and  concurrently as Vice
                                                         President & Project  Director,  Muskeg River Mine at Albian
                                                         Sands  Energy  Inc.  May  2002 to  July  2003  and  General
                                                         Manager Claims  Athabasca Oil Sands Project at Shell Canada
                                                         Limited May 2003 to July 2003.

Bruce E. McGrath               Corporate  Secretary      Officer of the Company
Calgary, Alberta               (age 54)
</TABLE>

(1)      Member of the Nominating and Corporate Governance Committee
(2)      Member of the Audit Committee
(3)      Member of the Reserves Committee
(4)      Member of the Compensation Committee
(5)      Member of the Safety, Health and Environmental Committee

All directors stand for election at each Annual General Meeting of CNRL
shareholders. With the exception of Ms. C. M. Best who was appointed to the
Board effective November 17, 2003, all of the current directors were elected to
the Board at the last annual meeting of shareholders held on May 8, 2003. All of
the current directors are standing for election at the Annual and Special
Meeting of Shareholders scheduled for May 6, 2004.

There are potential conflicts of interest to which the directors and officers of
the Company may become subject in connection with the operations of the Company.
Some of the directors and officers have been and will continue to be engaged in
the identification and evaluation of businesses and assets with a view to
potential acquisition of interests on their own behalf and on behalf of other
corporations, and situations may arise where the directors and officers will be
in direct competition with the Company. Conflicts, if any, will be subject to
the procedures and remedies under the BUSINESS CORPORATIONS ACT (Alberta).

As at December 31, 2003, the directors and officers of the Company, as a group,
beneficially owned, directly or indirectly, or exercised control or direction
over, in the aggregate, approximately 5 per cent of the total outstanding common
shares (approximately 6 per cent after the exercise of options held by them
pursuant to the Company's stock option plan).

<PAGE>

                                       38


                             ADDITIONAL INFORMATION

Additional information including Directors' and Executive Officers'
remuneration, principal holders of the Company's securities, options to purchase
the Company's securities and interest of insiders in material transactions is
contained in the Company's Notice of Annual and Special Meeting and Information
Circular dated March 25, 2004 in connection with the Annual and Special Meeting
of Shareholders of CNRL to be held on May 6, 2004 which information is
incorporated herein by reference. Additional financial information and
discussion of the affairs of the Company and the business environment in which
the Company operates is provided in the Company's Management Discussion and
Analysis, comparative Consolidated Financial Statements and Supplementary Oil &
Gas Information for the most recently completed fiscal year ended December 31,
2003 found on pages 38 to 59, 60 to 81 and 82 to 85 respectively, of the 2003
Annual Report to the Shareholders, which information is incorporated herein by
reference.

The Company shall provide to any person, upon request to the Corporate Secretary
of the Company:

         (a)      when securities of the Company are in the course of
                  distribution pursuant to a short form prospectus or a
                  preliminary short form prospectus has been filed in respect of
                  a distribution of its securities,

                  (i)      one copy of the Annual Information Form of the
                           Company, together with one copy of any document, or
                           the pertinent pages of any document, incorporated by
                           reference in the Annual Information Form,

                  (ii)     one copy of the comparative consolidated financial
                           statements of the Company for its most recently
                           completed financial year together with the
                           accompanying report of the auditor and one copy of
                           any interim consolidated financial statements of the
                           issuer subsequent to the consolidated financial
                           statements for its most recently completed financial
                           year,

                  (iii)    one copy of the information circular of the Company
                           in respect of its most recent annual meeting of
                           shareholders that involved the election of directors
                           or one copy of any annual filing prepared in lieu of
                           that information circular, as appropriate, 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 the Company may
                  require the payment of a reasonable charge if a person who is
                  not a security holder of the issuer makes the request.

<PAGE>

                                       39


For additional copies of this Annual Information Form and the materials listed
in the preceding paragraphs, please contact:

                  Corporate Secretary of the Corporation at:
                  2500, 855 - 2nd Street S.W.
                  Calgary, Alberta T2P 4J8



<PAGE>

                                       40


                                  SCHEDULE "A"

                              AMENDED FORM 51-101F2
                           REPORT ON RESERVES DATA BY
               INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

REPORT ON RESERVES DATA

To the Board of Directors of Canadian Natural Resources Limited (the
"Corporation"):

1. We have evaluated the Corporation's reserves data as at December 31, 2003.
The reserves data consist of the following:

         (a)    (i) proved oil and natural gas reserves quantities estimated as
                at December 31, 2003 using constant prices and costs;

                (ii) the related estimated future net revenue; and

                (iii) the related standardized measure calculation for proved
                oil and natural gas reserves quantities.

         (b)    (i) proved and proved plus probable oil and natural gas reserves
                estimated as at December 31, 2003 using forecast prices and
                costs; and

                (ii) the related estimated future net revenue.

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

3.       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) with the necessary modifications to
         reflect definitions and standards under the U.S. Financial Accounting
         Standards Board policies (the "FASB Standards") and the legal
         requirements of the U.S. Securities and Exchange Commission ("SEC
         Requirements").

4.       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 as
         outlined above.

<PAGE>

                                       41


5.       The following table sets forth the estimated net present value of
         future cash flows (before deduction of income taxes) attributed to
         proved oil and gas reserves quantities, estimated using constant prices
         and costs and calculated using a discount rate of 10 percent, included
         in the reserves data of the Corporation evaluated by us for the year
         ended December 31, 2003, and identifies the respective portions thereof
         that we have evaluated and reported on to the Corporation's management
         and board of directors:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
   INDEPENDENT        DESCRIPTION    LOCATION OF RESERVES
    QUALIFIED             AND         (COUNTRY OR FOREIGN
     RESERVES         PREPARATION      GEOGRAPHIC AREA)              NET PRESENT VALUES OF FUTURE CASH FLOWS
   EVALUATOR OR         DATE OF
     AUDITOR          EVALUATION                                     (BEFORE INCOME TAXES, 10% DISCOUNT RATE)
                        REPORT
--------------------------------------------------------------------------------------------------------------------
                                                               AUDITED       EVALUATED       REVIEWED        TOTAL
                                                                 MM$            MM$             MM$           MM$
--------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------
<S>                 <C>              <C>                         <C>         <C>               <C>       <C>
Sproule             Sproule          North America United        0           $13,015.6         $0        $13,015.6
                    Evaluated the    Kingdom, West Africa        0           $ 2,086.9         $0        $ 2,086.9
                    P&NG Reserves                                0           $ 1,014.9         $0        $ 1,014.9
                    of CNRL (As of
                    January 1,
                    2004)
--------------------------------------------------------------------------------------------------------------------
  TOTALS                                                         $0         $16,117.4          $0        $16,117.4
--------------------------------------------------------------------------------------------------------------------
</TABLE>


6.       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 as modified by the FASB Standards and SEC requirements.
         We express no opinion on the reserves data that we reviewed but did not
         audit or evaluate.

7.       We have no responsibility to update our evaluation for events and
         circumstances occurring after their respective preparation dates.

<PAGE>

                                       42


8.       Reserves are estimates only, and not exact quantities. In addition, as
         the reserves data are based on judgments regarding future events,
         actual results will vary and the variations may be material.

         Executed as to our report referred to above:

         February 18, 2004

                                               SPROULE ASSOCIATES LIMITED



                                               ORIGINAL SIGNED BY:

                                               /s/  Harry J. Helwerda
                                               ------------------------------
                                               Harry J. Helwerda, P.Eng.,
                                               Vice-President, Engineering,
                                                    Canada and U.S.

                                               ORIGINAL SIGNED BY:

                                               /s/ R. Keith MacLeod
                                               ------------------------------
                                               R. Keith MacLeod,
                                               P.Eng. Executive
                                               Vice-President

                                                ORIGINAL SIGNED BY:

                                               /s/ Doug Ho
                                               ------------------------------
                                               Doug Ho, P.Eng.
                                               Manager, Engineering, and
                                                          Associate

                                                ORIGINAL SIGNED BY:

                                               /s/ Ken H. Crowther
                                               ------------------------------
                                               Ken H. Crowther, P.Eng.
                                               President


<PAGE>

                                       43


                                  SCHEDULE "B"

                                    REPORT OF
                            MANAGEMENT AND DIRECTORS
                            ON OIL AND GAS DISCLOSURE

    REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

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

(a)      (i)      proved oil and natural gas reserve quantities estimated as at
                  December 31, 2003 using constant prices and costs;

         (ii)     the related estimated future net revenue; and

         (iii)    the related standardized measure calculation for proved oil
                  and natural gas reserve quantities.

(b)      (i)      proved and proved plus probable oil and natural gas
                  reserves estimated as at December 31, 2003 using forecast
                  prices and costs; and

         (ii)     the related estimated future net revenue

Sproule Associates Limited, an independent qualified reserves evaluator has
evaluated the Corporation's reserves data. The report of the independent
qualified reserves evaluator will be filed with securities regulatory
authorities concurrently with this report.

The reserves committee (the "Reserves Committee") of the board of directors (the
"Board of Directors") of the Corporation has:

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

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

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

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

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

<PAGE>

                                       44


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

         (c)      the content and filing of this report.


         Reserves data are estimates only, and are not exact quantities. In
         addition, as the reserves data are based on judgments regarding future
         events, actual results will vary and the variations may be material.


         "Signed"
         Douglas A. Proll
         Senior Vice President, Finance


         "Signed"
         Steve W. Laut
         Chief Operating Officer


         "Signed"
         David A. Tuer
         Independent Director, and Chairman of the Reserve Committee


         "Signed"
          Keith A.J. MacPhail
         Independent Director, and Member of the Reserve Committee



         Dated this 19th day of February, 2004
         Calgary, Alberta