EXHIBIT 1
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                       CANADIAN NATURAL RESOURCES LIMITED

                             ANNUAL INFORMATION FORM

                                 March 30, 2005

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                                TABLE OF CONTENTS

DEFINITIONS....................................................................3

SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS..............................4

THE COMPANY....................................................................6

GENERAL DEVELOPMENT OF THE BUSINESS............................................7

REGULATORY MATTERS.............................................................9

RISK FACTORS..................................................................10

ENVIRONMENTAL MATTERS.........................................................14

DESCRIPTION OF THE BUSINESS...................................................14

A. PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES.............................16

   Drilling Activity..........................................................17
   Producing Oil and Natural Gas Wells........................................18
   Northeast British Columbia.................................................18
   Northwest Alberta..........................................................20
   Northern Plains............................................................21
   Southern Plains and Southeast Saskatchewan.................................23
   United Kingdom North Sea...................................................24
   Offshore West Africa.......................................................25
   Cote d'Ivoire..............................................................26
   Angola.....................................................................26
   Horizon Oil Sands Project..................................................27

B. CRUDE OIL AND NATURAL GAS RESERVES.........................................28

C. RECONCILIATION OF CHANGES IN NET RESERVES..................................33

D. OIL SANDS MINING RESERVES..................................................34

E. CRUDE OIL AND NATURAL GAS PRODUCTION.......................................34

F. HISTORICAL DRILLING ACTIVITY BY PRODUCT....................................38

G. CAPITAL EXPENDITURES.......................................................39

H. NON-RESERVE ACREAGE........................................................41

I. DEVELOPED ACREAGE..........................................................41

SELECTED FINANCIAL INFORMATION................................................42

CAPITAL STRUCTURE.............................................................43

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MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES......................45

DIVIDEND HISTORY..............................................................46

TRANSFER AGENTS and REGISTRAR.................................................46

DIRECTORS AND EXECUTIVE OFFICERS..............................................47

AUDIT COMMITTEE INFORMATION...................................................51

LEGAL PROCEEDINGS.............................................................52

INTERESTS OF EXPERTS..........................................................52

ADDITIONAL INFORMATION........................................................52

SCHEDULE "A"..................................................................53

SCHEDULE "B"..................................................................56

                                    CURRENCY

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

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                                   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.

"BOE" or "boe" means  natural gas is converted to oil  equivalent at the rate of
six thousand cubic feet equals one barrel of oil equivalent.

"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.

"mbbl" means one thousand barrels.

"mcf" means one thousand cubic feet.

"mcf/d" means one thousand cubic feet per day.

"mmbbl" 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.

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                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.

Special Note Regarding Currency, Production and Reserves

In this  document,  all  references to dollars refer to Canadian  dollars unless
otherwise  stated.  Reserves  and  production  data  is  presented  on a  before
royalties basis unless otherwise stated.  In addition,  reference is made to oil
and natural gas in common units called barrel of oil equivalent  ("boe").  A boe
is derived by converting six thousand cubic feet of natural gas to one barrel of

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crude oil (6mcf:1bbl).  This conversion may be misleading,  particularly if used
in isolation, since the 6mcf:1bbl ratio is based on an energy equivalency at the
burner tip and does not represent the value equivalency at the well head.

Canadian Natural retains qualified  independent  reserves evaluators to evaluate
the  Company's  proved and  probable  oil and natural gas  reserves  and prepare
Evaluation  Reports on the Company's total reserves.  Canadian  Natural has been
granted an exemption from 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 related  information  for companies
listed 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  proved and  probable
reserves and 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 is 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 Board
of Directors of the Company has a Reserves Committee, which has met with each of
the Company's  third party reserve  evaluators and carried out  independent  due
diligence procedures with them as to the Company's reserves.

Reserves and net asset values  presented for years prior to 2003 were  evaluated
in  accordance  with the  standards  of  National  Policy 2-B which has now been
replaced  by NI  51-101.  The  stated  reserves  were  reasonably  evaluated  as
economically productive using year-end costs and prices escalated at appropriate
rates throughout the productive life of the properties.

Horizon oil sands mining  reserves have been evaluated  under SEC Industry Guide
7. Resource  potential as determined for thermal oil assets and other  potential
mining leases are determined using generally accepted industry methodologies for
resource  delineation based upon  stratigraphic  well drilling  completed on the
properties.

Special Note Regarding non-GAAP Financial Measures

Management's  discussion and analysis includes  references to financial measures
commonly  used in the oil and gas  industry,  such as cash  flow,  cash flow per
share and EBITDA (net earnings before interest,  taxes,  depreciation  depletion
and amortization,  asset retirement  obligation  accretion,  unrealized  foreign
exchange,  stock-based  compensation  expense  and  unrealized  risk  management
activity).  These  financial  measures  are not  defined by  generally  accepted
accounting  principles  ("GAAP")  and  therefore  are  referred  to as  non-GAAP
measures.  The non-GAAP  measures  used by the Company may not be  comparable to
similar measures  presented by other companies.  The Company uses these non-GAAP
measures  to  evaluate  the  performance  of the  Company  and  of its  business
segments.  The non-GAAP  measures  should not be considered an alternative to or
more  meaningful  than net earnings,  as determined in accordance  with Canadian
GAAP, as an indication of the Company's performance.

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                                   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.) Investments 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.  CNRL as the  managing
partner and Renata Resources Inc. are the partners of Canadian Natural Resources
2005  Partnership,  a  general  partnership  which  holds  certain  natural  gas
facilities situated in Alberta.

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

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                       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, 2004 the Company had 2,137 full time employees in
North America and 273 full time employees in its international operations.

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 included  approximately 2.9
million net acres of undeveloped lands and provided 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.  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.

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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.

In February 2004,  the Company  completed the  acquisition  of 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
production from the working interests at the time of the acquisition 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 Northern Plains.

In April 2004,  the Company  completed an acquisition of certain oil and natural
gas properties  located in Northeast  British Columbia and Northwest Alberta for
consideration  of $280 million.  The properties at the time of acquisition  were
producing  approximately  68 million  cubic feet per day of natural  gas and 200
barrels per day of light crude oil and natural gas liquids and contain  over 415
thousand acres of developed and  undeveloped  land.  The  properties  included a
further  interest in the Ladyfern natural gas field. The portion of the Ladyfern
field  included in the  acquisition  included  production  of  approximately  50
million  cubic feet per day of natural  gas.  As part of this  acquisition,  the
Company also acquired  undeveloped  acreage in the Foothills area of Alberta and
British  Columbia.  This area is characterized by large,  undeveloped pools with
significant natural gas potential in deeper zones and will add a new exploration
base in the Alberta Foothills, complementing the Company's existing holdings and
production base in the British Columbia Foothills.

In the  third  quarter  of 2004  the  Company's  wholly  owned  subsidiary,  CNR
International  (U.K.) Limited acquired certain oil and natural gas properties in
the central North Sea. The acquired  properties  comprise operated  interests in
T-Block (Tiffany,  Toni and Thelma fields) and B-Block  (Balmoral,  Stirling and
Glamis  fields)  together with  associated  production  facilities  and adjacent
exploration acreage.

On  December 1, 2004 the  Company  issued US $350.0  million of 10 year 4.90 per
cent unsecured notes maturing  December 1, 2014 and US $350.0 million of 30 year
5.85 per cent unsecured notes maturing February 1, 2035 pursuant to a short form
shelf prospectus dated May 8, 2003.

In December  2004, the Company  acquired  certain oil and natural gas properties
located in Alberta and British Columbia,  for an aggregate cash consideration of
approximately  $703  million,  net of proceeds  received  from an  agreement  to
concurrently  dispose  of a portion of such  properties  for  approximately  $50
million and cash flows realized from the effective date of September 1, 2004. At
the time of the acquisition  production from the properties acquired by Canadian
Natural,  after the above noted disposition,  was estimated at 105 million cubic
feet per day of natural  gas and 7,500  barrels  per day of light  crude oil and
NGLs being approximately 25,000 barrels of oil equivalent of daily production on
a six to  one  basis.  The  acquisition  included  over  510,000  net  acres  of
undeveloped land. The vast majority of the acquired

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properties  is located in the  Company's  core areas and  extends  its  Northern
Plains core region into the light oil operating area of Dawson.

During  2004,  the  Company  completed  109  transactions  (including  the  four
acquisitions  mentioned  above)  in the  normal  course  to  acquire  additional
interests  in  crude  oil  and  natural  gas  properties  at  an  aggregate  net
expenditure of $1.371 billion (excluding the Petrovera  Partnership  acquisition
described  above).  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 $7 million.

In February 2005 the Board of Directors of the Company  approved  Phase 1 of the
Horizon Oil Sands Project. See below "Horizon Oil Sands Project".

                               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  is 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. 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

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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 39.3 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.

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.  Development of the Espoir field on CI-26, and the Baobab Field on
CI-40,  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").

                                  RISK FACTORS

Volatility of Oil and Natural Gas Prices

The Company's financial condition will be substantially dependent on, and highly
sensitive to, the prevailing  prices of crude oil and natural gas.  Fluctuations
in crude oil or natural gas prices could have a material  adverse  effect on its
operations  and  financial  condition  and the value and amount of its reserves.
Prices for crude oil and  natural  gas  fluctuate  in response to changes in the
supply of and demand for, crude oil and natural gas,  market  uncertainty  and a
variety of  additional  factors  beyond the  Company's  control.  Oil prices are
determined by  international  supply and demand.  Factors which affect crude oil
prices include the actions of the Organization of Petroleum Exporting Countries,
the condition of the Canadian,  United  States and Asian  economies,  government
regulation,  political  stability in the Middle East and elsewhere,  the foreign
supply of oil, the price of foreign imports,  the availability of alternate fuel
sources and

<PAGE>

                                       11


weather conditions.  Natural gas prices realized by the Company will be affected
primarily in North America by supply and demand,  weather  conditions and prices
of  alternate  sources of energy.  Any  substantial  or extended  decline in the
prices of crude oil or natural gas could  result in a delay or  cancellation  of
existing or future drilling, development or construction programs or curtailment
in   production   at  some   properties   or  resulting   unutilized   long-term
transportation commitments, all of which could have a material adverse effect on
Canadian Natural's revenues, profitability and cash flows.

Canadian  Natural  conducts an annual  assessment  of the carrying  value of its
assets in accordance with Canadian generally accepted accounting principles.  If
oil and natural gas prices  decline,  the carrying  value of the assets could be
subject to downward revisions, and earnings could be adversely affected.

Approximately  27 percent of the  Company's  2004  production on a boe basis was
primary and thermal  heavy oil. The market prices for this heavy oil differ from
the  established  market  indices  for  light  and  medium  grades  of oil,  due
principally  to the higher  transportation  and refining costs  associated  with
heavy oil. As a result, the price received for heavy oil is generally lower than
the price for medium and light oil, and the  production  costs  associated  with
heavy oil are relatively  higher than for lighter grades.  Future  differentials
are  uncertain  and any  increase  in the heavy oil  differentials  could have a
material adverse effect on the Company's business.

Environmental Risks

All phases of the oil and natural  gas  business  are  subject to  environmental
regulation  pursuant to a variety of Canadian,  United States,  United  Kingdom,
European  Union and other  federal,  provincial,  state and  municipal  laws and
regulations, as well as international conventions (collectively,  "environmental
legislation").

Environmental legislation imposes, among other things, restrictions, liabilities
and  obligations  in  connection  with  the   generation,   handling,   storage,
transportation,  treatment and disposal of hazardous substances and waste and in
connection  with spills,  releases and  emissions of various  substances  to the
environment.  Environmental legislation also requires that wells, facility sites
and other  properties  associated  with the  Company's  operations  be operated,
maintained, abandoned and reclaimed to the satisfaction of applicable regulatory
authorities. In addition, certain types of operations, including exploration and
development  projects and significant changes to certain existing projects,  may
require the  submission  and approval of  environmental  impact  assessments  or
permit  applications.  Compliance  with  environmental  legislation  can require
significant  expenditures and failure to comply with  environmental  legislation
may result in the imposition of fines and penalties. The costs of complying with
environmental  legislation  in the future may have a material  adverse effect on
Canadian Natural's financial condition or results of operations.

Canadian  Natural  anticipates  that changes in  environmental  legislation  may
require,  among  other  things,  reductions  in  emissions  to the air  from its
operations which may result in increased capital expenditures. Future changes in
environmental  legislation  could  occur and result in  stricter  standards  and
enforcement,  larger fines and liability, and increased capital expenditures and
operating  costs,  which could have a material  adverse  effect on the Company's
financial condition or results of operations.

<PAGE>

                                       12


Need to Replace Reserves

Canadian  Natural's  future oil and natural gas  reserves  and  production,  and
therefore its cash flows and results of  operations,  are highly  dependent upon
success in  exploiting  its current  reserve base and  acquiring or  discovering
additional   reserves.   Without  additions  to  reserves  through  exploration,
acquisition or  development  activities,  the Company's  reserves and production
will decline over time as reserves are depleted.  The business of exploring for,
developing  or  acquiring  reserves  is  capital  intensive.  To the  extent the
Company's  cash  flows  from   operations  are   insufficient  to  fund  capital
expenditures and external sources of capital become limited or unavailable,  the
Company's  ability to make the  necessary  capital  investments  to maintain and
expand its oil and natural gas reserves will be impaired. In addition,  Canadian
Natural  may be unable to find and  develop or acquire  additional  reserves  to
replace its oil and natural gas production at acceptable costs.

Competition in Energy Industry

The  energy  industry  is  highly  competitive  in all  aspects,  including  the
exploration for, and the development of, new sources of supply, the construction
and  operation  of crude oil and  natural  gas  pipelines  and  facilities,  the
acquisition  of oil  and  natural  gas  interests  and  the  transportation  and
marketing  of crude oil,  natural  gas,  natural gas  liquids  and  electricity.
Canadian  Natural  will  compete  not  only  among  participants  in the  energy
industry,  but also between  petroleum  products and other energy  sources.  The
Company's  competitors will include integrated oil and natural gas companies and
numerous  other  senior oil and  natural gas  companies,  some of which may have
greater financial and other resources than the Company.

Other Business Risks

Other business risks include operational risks, the cost of capital available to
fund exploration and development  programs,  regulatory  issues and taxation and
the  requirements  of new  environmental  laws and  regulations.  Exploring for,
producing and transporting  petroleum substances involves many risks, which even
a combination of experience, knowledge and careful evaluation may not be able to
overcome.  These  activities are subject to a number of hazards which may result
in  fires,  explosions,  spills,  blow-outs  or other  unexpected  or  dangerous
conditions causing personal injury,  property damage,  environmental  damage and
interruption of operations.  Canadian Natural's liability, property and business
interruption  insurance may not provide adequate coverage in certain  unforeseen
circumstances.

Foreign Investments

The Company's  foreign  investments  involve  risks  typically  associated  with
investments in developing countries such as uncertain political, economic, legal
and tax  environments.  These risks may include,  among other  things,  currency
restrictions  and  exchange  rate  fluctuations,  loss of revenue,  property and
equipment as a result of hazards such as  expropriation,  nationalization,  war,
insurrection  and  other  political  risks,  risks of  increases  in  taxes  and
governmental  royalties,  renegotiation of contracts with governmental  entities
and  quasi-governmental   agencies,  changes  in  laws  and  policies  governing
operations of  foreign-based  companies and other  uncertainties  arising out of
foreign government sovereignty over the Company's international  operations.  In
addition,  if a dispute  arises in its  foreign  operations,  the Company may be
subject to the exclusive jurisdiction of foreign courts or may not be successful
in  subjecting  foreign  persons  to the  jurisdiction  of a court in the United
States or Canada.

<PAGE>

                                       13


Canadian Natural's private ownership of oil and natural gas properties in Canada
differs  distinctly from its ownership  interests in foreign oil and natural gas
properties.  In some  foreign  countries  in which the  Company  does and may do
business in the future,  the state generally  retains  ownership of the minerals
and  consequently  retains  control of, and in many cases  participates  in, the
exploration  and  production  of reserves.  Accordingly,  operations  outside of
Canada may be materially  affected by host governments through royalty payments,
export taxes and regulations,  surcharges, value added taxes, production bonuses
and other  charges.  In  addition,  changes in prices  and costs of  operations,
timing of production  and other factors may affect  estimates of oil and natural
gas  reserve  quantities  and  future  net cash  flows  attributable  to foreign
properties  in a manner  materially  different  than such  changes  would affect
estimates for Canadian  properties.  Agreements covering foreign oil and natural
gas operations  also  frequently  contain  provisions  obligating the Company to
spend  specified  amounts on exploration  and  development or to perform certain
operations, or forfeit all or a portion of the acreage subject to the contract.

Uncertainty of Reserve Estimates

There are numerous  uncertainties inherent in estimating quantities of reserves,
including many factors beyond the Company's  control.  In general,  estimates of
economically  recoverable  oil and natural gas  reserves and the future net cash
flow therefrom are based upon a number of factors and assumptions made as of the
date on which the reserve  estimates  were  determined,  such as geological  and
engineering estimates which have inherent uncertainties,  the assumed effects of
regulation by governmental agencies and estimates of future commodity prices and
operating costs,  all of which may vary  considerably  from actual results.  All
such estimates are, to some degree,  uncertain and  classifications  of reserves
are only  attempts  to define  the  degree of  uncertainty  involved.  For these
reasons,  estimates of the economically recoverable oil and natural gas reserves
attributable to any particular group of properties,  the  classification of such
reserves based on risk of recovery and estimates of future net revenues expected
therefrom, prepared by different engineers or by the same engineers at different
times, may vary substantially.  Canadian Natural's actual production,  revenues,
taxes and development,  abandonment and operating  expenditures  with respect to
its reserves will likely vary from such  estimates,  and such variances could be
material.

Estimates  with respect to reserves  that may be  developed  and produced in the
future are often based upon volumetric  calculations and upon analogy to similar
types of reserves,  rather than upon actual production history.  Estimates based
on these  methods  generally  are  less  reliable  than  those  based on  actual
production  history.  Subsequent  evaluation  of the same  reserves  based  upon
production  history will result in  variations,  which may be  material,  in the
estimated reserves.

Priority  of  Subsidiary  Indebtedness;   Consequences  of  Holding  Corporation
Structure

The Company carries on business through corporate and partnership  subsidiaries.
The  majority  of the  Company's  assets  are held in one or more  corporate  or
partnership  subsidiaries.  The  results of  operations  and  ability to service
indebtedness,  including  debt  securities,  are  dependent  upon the results of
operations of these  subsidiaries and the payment of funds by these subsidiaries
to the Company in the form of loans, dividends or otherwise. In the event of the
liquidation  of any  corporate  or  partnership  subsidiary,  the  assets of the
subsidiary  would be used  first to repay the  indebtedness  of the  subsidiary,
including  trade payables or obligations  under any  guarantees,  prior to being
used by the Company to pay its indebtedness.

<PAGE>

                                       14


                              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  management  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 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 has participated in Canada's Climate Change Voluntary Challenge
&  Registry  Inc (VCR)  and plans to  participate  in a new  Canadian  Standards
Association  (CSA) program when the transition from VCR to CSA is complete.  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  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, 2004, 2003, and 2002.

                           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.

<PAGE>

                                       15


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 crude oil, Pelican Lake crude oil, primary heavy crude
oil and  thermal  heavy  crude 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 45 per cent of 2004 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  24 per  cent of 2004
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  27  per  cent  of  2004
production.  Other heavy oil, which accounts for 4 per cent of 2004  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 Pelican  Lake crude 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 11.5  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.


<PAGE>

                                       16


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, 2004.  The  information  is  proportionate  to the
working interests owned by the Company.

<TABLE>
<CAPTION>
                           2004 AVERAGE
                              DAILY         YEAR ENDED
                            PRODUCTION     DECEMBER 31,     MAJOR INFRASTRUCTURE
                              RATES            2004       AS AT DECEMBER 31, 2004
                         ---------------   ------------   -----------------------
                                                                 BATTERIES/
                         OIL &   NATURAL    UNDEVELOPED    COMPRESSORS & PLANTS/
                          NGLs     GAS        ACREAGE            PLATFORMS
REGION                   Mbbls     MMcf     (thousands)            /FPSO
------                   -----   -------    -----------    ---------------------
<S>                      <C>     <C>           <C>               <C>
North America

Northeast B. C.            6.8     437.3        2,040              1/8/-/-

Northwest Alberta         10.9     303.2        1,660              -/7/-/-

Northern Plains          166.3     429.9        6,922              9/5/-/-

Southern Plains           12.7     155.5          661              -/-/-/-

Southeast Saskatchewan     9.3       3.1          123              -/-/-/-

Non - core regions         0.2       1.1        1,822              -/-/-/-

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

International

North Sea                 64.7      50.4          565              -/-/5/3

Offshore West Africa

   Cote d'Ivoire          11.6       7.5          276              -/-/1/1

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

   South Africa             --                  5,550              -/-/-/-
                         -----   -------       ------            ---------
Total                    282.5   1,388.0       20,346            10/20/6/4
                         -----   -------       ------            ---------
</TABLE>

<PAGE>

                                       17


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 three fiscal years
up to December 31, 2004 by geographic region:

<TABLE>
<CAPTION>
                                                          2004
                            ---------------------------------------------------------------
                                    NET EXPLORATORY                  NET DEVELOPMENT
                            ------------------------------   ------------------------------
                            PRODUCTIVE   DRY HOLES   TOTAL   PRODUCTIVE   DRY HOLES   TOTAL
                            ----------   ---------   -----   ----------   ---------   -----
<S>                            <C>          <C>      <C>        <C>          <C>      <C>
Canada
   Northeast B. C               23.8         6.2        30      146.8        14.4     161.2
   Northwest Alberta            42.8         7.6      50.4      100.4         3.9     104.3
   Northern Plains             116.6        26.6     143.2      333.8        23.2       357
   Southern Plains              18.5         7.0      25.5      209.9         4.0     213.9
   Southeast Saskatchewan         --          --        --       12.5           0      12.5
   Non - core regions             --          --        --        0.5         0.3       0.8
North Sea                         --         2.0       2.0        9.2         0.0       9.2
Offshore West Africa
   Cote d'Ivoire                  --         0.7       0.7        2.3         0.0       2.3
   Angola                         --          --        --         --          --        --
                               -----        ----     -----      -----        ----     -----
Total                          201.7        50.1     251.8      815.4        45.8     861.2
                               -----        ----     -----      -----        ----     -----
</TABLE>

<TABLE>
<CAPTION>
                                                           2003
                            -----------------------------------------------------------------
                                    NET EXPLORATORY                   NET DEVELOPMENT
                            ------------------------------   --------------------------------
                            PRODUCTIVE   DRY HOLES   TOTAL   PRODUCTIVE   DRY HOLES    TOTAL
                            ----------   ---------   -----   ----------   ---------   -------
<S>                            <C>          <C>      <C>       <C>           <C>      <C>
Canada
   Northeast B. C               15.5        13.3      28.8        67.8        9.1        76.9
   Northwest Alberta            31.7        11.8      43.5        69.9        7.9        77.8
   Northern Plains              57.5        26.6      84.1       531.6       37.9       569.5
   Southern Plains              33.0         4.0      37.0       387.9        5.0       392.9
   Southeast Saskatchewan         --          --        --        26.9         --        26.9
   Non - core regions             --          --        --         0.4         --         0.4
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
                               -----        ----     -----     -------       ----     -------
</TABLE>

<TABLE>
<CAPTION>
                                                          2002
                            ---------------------------------------------------------------
                                    NET EXPLORATORY                  NET DEVELOPMENT
                            ------------------------------   ------------------------------
                            PRODUCTIVE   DRY HOLES   TOTAL   PRODUCTIVE   DRY HOLES   TOTAL
                            ----------   ---------   -----   ----------   ---------   -----
<S>                             <C>         <C>       <C>       <C>          <C>      <C>
Canada
   Northeast B. C               16.8         4.4      21.2       25.4          --      25.4
   Northwest Alberta             3.9         3.0       6.9        6.1          --       6.1
   Northern Plains              31.5         6.0      37.5      278.1         8.6     286.7
   Southern Plains              12.0          --      12.0       40.6         2.5      43.1
   Southeast Saskatchewan         --          --        --        4.3         1.0       5.3
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
                               -----        ----     -----      -----        ----     -----
</TABLE>

<PAGE>

                                       18


Producing Oil & Natural Gas Wells

Set forth  below is a summary  of the  number of gross and net wells  within the
Company that were producing or capable of producing as of December 31, 2004:

<TABLE>
<CAPTION>
                            NATURAL GAS WELLS      OIL WELLS         TOTAL WELLS
                            -----------------   ---------------   -----------------
                             GROSS     NET      GROSS     NET      GROSS      NET
                             -----   -------    -----   -------   ------   --------
<S>                          <C>     <C>        <C>     <C>       <C>      <C>
Canada
   Northeast B. C.             937     816.0      173     135.6    1,110      951.7
   Northwest Alberta           894     745.2      252     149.9    1,146      895.1
   Northern Plains           2,619   2,148.4    5,029   4,457.4    7,648    6,605.8
   Southern Plains           4,184   3,557.1    1,832   1,705.8    6,016    5,262.9
   Southeast Saskatchewan       --        --      991     752.2      991      752.2
   Non - core regions          738     107.5      301     160.6    1,039      268.1
United States                    4       0.5        2       0.2        6        0.7
North Sea                        2       0.1      106      88.5      108       88.6
Offshore West Africa
   Cote d'Ivoire                --        --        5       2.9        5        2.9
   Angola                       --        --       --        --       --         --
                             -----   -------    -----   -------   ------   --------
Total                        9,378   7,374.8    8,691   7,453.1   18,069   14,827.9
                             -----   -------    -----   -------   ------   --------
</TABLE>

All reserves data in the following  property  report was based on the applicable
independent engineering report. See below "Crude Oil and Natural Gas Reserves".

Northeast British Columbia

                                    [GRAPHIC]

This region comprises lands from Fort St. John, British Columbia to the northern
border as well as the eastern  border of British  Columbia.  Similar  geological
attributes extend throughout the region,  producing light crude oil, natural gas
liquids and natural gas. The Company holds working  interests  ranging up to 100
per cent and averaging 74 per cent in 3,799,223  gross  (2,812,965 net) acres of
producing and undeveloped land in the region.

<PAGE>

                                       19


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  2,500 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.  Natural gas production from
the region  averaged  437.3  million cubic feet per day for 2004 compared to the
average of 372.3  million  cubic feet per day produced  for 2003.  Crude oil and
natural gas liquids  production was steady at to 6.8 thousand barrels per day in
2004 from an average of 6.7 thousand barrels per day in 2003.

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. In May of 2004 the
Company acquired additional lands, facilities and production in the area.

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 has
resulted in 30 to 50 wells being drilled in the area each year.

During 2004, 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 up to 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  2004 the Company  drilled  3.6 (2003- 5.1) net oil wells,  167.0 (2003 -
78.2) net natural gas wells, 1.0 (2003 - 0) net stratigraphic/service  wells and
20.6  (2003 - 22.4)  net dry wells on its  lands in this  region  for a total of
192.2  (2003 - 105.7)  net wells.  The  Company  held an  average  92.9 per cent
working interest in these wells.

<PAGE>

                                       20


Northwest Alberta

                                    [GRAPHIC]

The Company holds working  interests ranging up to 100 per cent and averaging 76
per cent in 2,865,122  gross  (2,166,652 net) acres of producing and undeveloped
land in the region located along the border of British Columbia and Alberta west
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 700 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.

Natural gas production from the region averaged 303.2 million cubic feet per day
for 2004  compared to an average of 261.3  million  cubic feet per day for 2003.
Crude oil and natural gas liquids production was steady at 10.9 thousand barrels
per day in 2004 from 11.1 thousand barrels per day in 2003.

During 2004 the Company drilled 5.8 (2003-3.7) net oil wells,  137.5 (2003-97.9)
net natural gas wells, 1.5 (2003 - 0) net stratigraphic/service  wells, and 11.5
(2003-19.7)  net dry  wells  on its  lands in this  region  for a total of 156.3
(2003-121.3)  net  wells.  The  Company  held an average  82.6 per cent  working
interest in these wells.

<PAGE>

                                       21


Northern Plains

                                    [GRAPHIC]

The Company holds working  interests ranging up to 100 per cent and averaging 82
per cent in 11,829,563  gross (9,667,926 net) acres of producing and undeveloped
land in the region  located  just south of Edmonton  north to Fort  McMurray and
from the  northwest  Alberta  border  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 crude 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 429.9  million cubic feet per day in 2004 compared
to 462.4 million  cubic feet per day in 2003.  Crude oil and natural gas liquids
production from this region  increased to 166.3 thousand barrels per day in 2004
from 136.7  thousand  barrels  per day in 2003.  Production  of natural  gas was
impacted by the shut-in effective July 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 crude oil (averaging
12 DEG.-14 DEG. 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 crude oil to the wellbore in
this  type of heavy  oil  reservoir  comes  from  solution  gas.  The  crude 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 of the
original oil in place.  A key  component  to  maintaining  profitability  in the
production  of  heavy  crude  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.

In the area around Elk Point,  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

<PAGE>

                                       22


operated  Beartrap  field  during 2001,  enhancing  further  development  of the
Company's  extensive  holdings  in  the  area.  This  pipeline  was  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  permits  the  Company  to
transport  approximately 80 per cent of its heavy crude 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 crude oil.

On February 18, 2004 the Company purchased the Petrovera Partnership which added
additional  properties  in this  region.  Approximately  one  third of the total
acquisition was sold to another independent  producer.  The properties that were
retained further consolidated the Company's position in the area.

Production  from the 100%  owned  Primrose  and Wolf Lake  fields  located  near
Bonnyville,  Alberta  involve  processes  that  utilize  steam to  increase  the
recovery of the oil. The two processes  employed by the Company are cyclic steam
stimulation  and  Steam  Assisted  Gravity  Drainage  ("SAGD").   Both  recovery
processes  inject steam to heat the heavy crude 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 58 high-pressure  wells in 2004.
Additional  development of the leases will be undertaken in phases over the next
several  years.  The Company in 2004 started to proceed with its Primrose  North
expansion  project  which is expected to be  completed  by  November  2005.  The
Primrose North expansion entails a remote steam treating facility and additional
high pressure wells which are expected to be on production in 2006. 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 approximately 100 per cent owned holdings at Pelican
Lake. These lands contain  reserves of 14 DEG.-17 DEG. API heavy oil.  Operating
costs  are  low due to no  sand  production  or  disposal  requirements  and the
gathering and pipeline  facilities in place. 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.
The Company holds and controls  approximately  75 percent 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 percent  recovery  factor  using  existing
primary  technologies  on the Company's  developed  leases.  Hence,  in 2002 the
Company embarked upon an Enhanced Oil Recovery

<PAGE>

                                       23


("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.  The  implementation  plan will result in the
conversion of existing  producing wells into water injectors and the drilling of
additional  producing wells. The Company will also examine  opportunities to use
polymer  flooding  in  conjunction  with  waterflooding  to obtain  the  highest
recovery factor while  maximizing  value.  This pilot is expected to commence in
the second quarter of 2005.

During 2004, the Company drilled 287.0 (2003 - 405.7) net oil wells, 163.4 (2003
- 183.4) net  natural gas wells,  112.0 (2003 - 63.5) net  stratigraphic/service
wells,  and 49.8 (2003 - 64.5) net wells dry wells for a total of 612.2  (2003 -
717.1) net wells. The Company's average working interest in these wells was 91.4
per cent.

Southern Plains and Southeast Saskatchewan

                                    [GRAPHIC]

In the Southern Plains area, the Company holds  interests  ranging up to 100 per
cent and  averaging  82 per cent in  1,771,346  gross  (1,451,816  net) acres of
producing and undeveloped  land in the region  principally  located south of the
Northern  Plains area to the United States border and to the east bounded by the
Alberta-Saskatchewan border.

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

<PAGE>

                                       24


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  in the Southern  Plains area averaged 12.7
(2003 - 10.9) thousand  barrels of crude oil and natural gas liquids per day and
155.5 (2003- 141.9) million cubic feet of natural gas per day in 2004.

During  2004,  the  Company  drilled a total of 7.8 (2003 - 4.4) net oil  wells,
220.6   (2003  -  416.5)  net   natural   gas  wells,   1.0  (2003  -  0.0)  net
stratigraphic/service  well and 11.0  (2003 - 9.0) net dry wells in this  region
for a total of 240.4 (2003 - 429.9) net wells.  The  Company's  average  working
interest in these wells was 86.5 per cent.

The Williston Basin is located in Southeastern Saskatchewan with lands extending
into Manitoba.  This region 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 80 per cent in 246,304 gross (196,200 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.  The Company's share of
production in the Southeast Saskatchewan area averaged 9.3 (2003 - 9.2) thousand
barrels of crude oil and natural gas liquids per day and 3.1 (2003- 3.4) million
cubic feet of natural gas per day in 2004.

The Company  drilled  12.5 (2003 - 26.9) net oil wells with 0.0 (2003 - 0.0) net
dry wells in this  region in 2004,  for a total of 12.5 (2003 - 26.9) net wells.
The Company's average working interest in these wells is 65.9 per cent.

United Kingdom North Sea

                                    [GRAPHIC]

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 876,422 gross  (657,802  net) acres of producing  and  non-producing
properties in the UK sector of the North Sea. In 2004, the Company produced from
15 crude oil fields.

<PAGE>

                                       25


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  Terraces  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.

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.  In 2004
the Company  acquired 100 per cent working  interest in T-block  (comprising the
Tiffany, Toni and Thelma Fields) and 68.7 per cent to 75.3 per cent interests in
the Fields known as B-block  (comprising  Balmoral,  Stirling  and Glamis).  The
Company took over as operator of these fields.  The Company also owns a 45.7 per
cent operated working interest in the Kyle Field.

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 processing of crude
oil and natural gas through some of the processing facilities. Opportunities for
further  long-reach  well  development on adjacent  fields are provided from the
existing processing facilities.

During 2004,  production  to the Company from this region  averaged 64.7 (2003 -
56.9) thousand barrels of crude oil per day and 50.4 (2003 - 45.6) million cubic
feet of  natural  gas per day.  The  Company  drilled  9.2 (2003 - 11.1) net oil
wells,  2.7 (2003 - 4.8) net service wells and 2.0 (2003 - 1.8) net dry wells in
2004 in this region for a total of 13.9 (2003 - 17.7) net wells.  The  Company's
average working interest in these wells is 92.3 per cent.

Offshore West Africa

                                    [GRAPHIC]

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 1,589,213 gross

<PAGE>

                                       26


(885,541  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 275,625 net acres. During 2001, the Company increased its interest in
Block  CI-26,  which  contains  the  Espoir  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 first phase of 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 an
infill drilling program in East Espoir and development plans for the West Espoir
part of the Field were  completed in 2004.  Oil from the East Espoir is produced
into an FPSO with  associated  natural gas  delivered  onshore  through a subsea
pipeline  for local power  generation.  In 2003 the Company  drilled a satellite
pool, Acajou,  which encountered a reservoir with good quality and hydrocarbons.
The extent of this  accumulation was further appraised by a well drilled in 2004
which did not encounter commercial hydrocarbons.

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
and is progressing according to plan towards first oil in 2005.

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 2004,  net daily  production  to the Company  averaged 11.6 (2003 - 10.6)
thousand barrels of crude oil and 7.5 (2003 - 8.4) million cubic feet of natural
gas. In 2004,  the Company  drilled 2.3 (2003 - 1.3) net oil wells,  0.0 (2003 -
2.0) net  service  wells  and 0.7  (2003 - 0.0) net dry wells for a total of 3.0
(2003 - 3.3) net wells. The Company's average working interest in these wells is
59.3 per cent.

Angola

During  2002,  the Company was awarded  operatorship  and a 50 per cent  working
interest in  exploration  Block 16 situated  offshore The  People's  Republic of
Angola. 3-D seismic was obtained 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.  Following further
evaluation  of  seismic  and the  well  results  during  2004,  the  Company  is
considering various options, including divestment.

<PAGE>

                                       27


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.

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,  which has two aspects;  namely,  bitumen  production  and bitumen
upgrading  to SCO,  is  designed  as a phased  development.  Site  clearing  and
pre-construction  preparation activities commenced in 2004 and construction will
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 estimated  capital costs of the phased  development are $10.8 billion,  of
which  approximately $6.8 billion including  contingency funding of $700 million
would be required for Phase 1. When the Horizon  Project is fully  commissioned,
operating costs - including sustaining capital - are expected to be in the range
of $14 per barrel.

Canadian  Natural filed an application  for  regulatory  approval of the Horizon
Project in June 2002. The  application  included a  comprehensive  environmental
impact  assessment,  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.  An Alberta  Order-in-Council  approval was received in
February   2004.   Subsequently,   key  approvals  were  received  from  Alberta
Environment  under the  Environmental  Protection  Act and Water  Act,  and from
Fisheries and Oceans Canada under the Fisheries Act.

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.

<PAGE>

                                       28


Canadian  Natural  used 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 and  final  front-end  engineering  phase,  completing  the work in
December 2004. The products of this phase include a detailed  project  execution
plan,  Engineering  Design  Specifications  ("EDS") and a detailed cost estimate
(plus or minus  10%).  The EDS  provided  sufficient  definition  for a lump sum
inquiry  for the  Detailed  Engineering,  Procurement  and  Construction  of the
various project  components.  With this information a "cost certainty"  estimate
was  developed as a basis for project  sanction by the Board of Directors  which
was given in February 2005 authorizing management to proceed with Phase 1 of the
Horizon Oil Sands Project.

Horizon is designed to use proven  technology and will seek to take advantage of
technology improvements that advance environmental performance, enhance the work
environment for workers,  increase reliability and production and reduce capital
and  operating  costs.  By the end of 2004  the  Company  had  acquired  all key
technologies  for the project.  At year end,  Horizon  Project staff,  including
direct hire and contract,  representing the many skill  disciplines  required to
define and implement the project  numbered 800,  about 75% of the required staff
compliment to implement Phase 1.

Canadian  Natural  expended  $291  million  on  the  Horizon  Project  in  2004.
Cumulative  expenditures  on the  project  are $672  million to the end of 2004.
These expenditures include lease evaluation,  engineering definition, technology
acquisition,  environmental and socio-economic assessment,  public consultation,
regulatory  application,  completion  of road  infrastructure  to the  site  and
preliminary site development.  Capital  expenditures for 2005 are budgeted to be
$1.4  billion  reflecting  the  beginning  of major  expenditures  for  detailed
engineering, procurement and construction of Phase 1 of the Project.

During 2004, the Company  drilled 218 (2003 - 370)  stratigraphic  test wells to
further delineate the ore body and confirm resource quality and quantity.

B.   CRUDE OIL AND NATURAL GAS RESERVES

The Company retains  independent  qualified  petroleum  engineering  consultants
Sproule Associates  Limited  ("Sproule") and Ryder Scott Company ("Ryder Scott")
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 Evaluation Reports are effective December
31,  2004 as  prepared  February  18,  2005.  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

<PAGE>

                                       29


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
each of Sproule and Ryder Scott and carried out the appropriate  independent due
diligence  procedures with Sproule and Ryder Scott to review the  qualifications
of and procedures used by Sproule and Ryder Scott 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, 2004.

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 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)

                            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
                  --------   ----------    --------   ----------
North America
Canada                648         926        2,590       3,317
United States           0           0            1           2
International
United Kingdom        303         415           27          57
Cote d'Ivoire         115         196           72          90
                    -----       -----        -----       -----
Total               1,066       1,537        2,690       3,466
                    =====       =====        =====       =====

<PAGE>

                                       30


Crude Oil, NGL and Natural Gas Reserves

                                             Constant Prices and Costs
                                     -----------------------------------------
                                     Crude Oil and Natural
                                      Gas Liquids (MMbbls)   Natural Gas (Bcf)
                                     ---------------------   -----------------
                                       Gross        Net       Gross      Net
                                     ---------   ---------   -------   -------
Proved developed                         638         605      2,761     2,230
Proved undeveloped                       485         461        549       460
                                       -----       -----      -----     -----
Total proved reserves                  1,123       1,066      3,310     2,690
Total proved and probable reserves     1,621       1,537      4,259     3,466
                                       =====       =====      =====     =====
Estimated Future Net Revenues

                                            Constant Prices and Costs
                                     ---------------------------------------
($ Millions)                         Undiscounted         Discounted at
                                     ------------   ------------------------
                                                      10%      15%      20%
                                                    ------   ------   ------
Proved developed                        21,092      13,739   11,838   10,453
Proved undeveloped                       8,059       4,399    3,440    2,748
                                        ------      ------   ------   ------
Total proved reserves                   29,151      18,138   15,279   13,201
Total proved and probable reserves      40,088      22,937   18,802   15,899
                                        ======      ======   ======   ======

Crude Oil, NGL and Natural Gas Reserves

                                             Forecast Prices and Costs
                                     -----------------------------------------
                                     Crude Oil and Natural
                                      Gas Liquids (MMbbls)   Natural Gas (Bcf)
                                     ---------------------   -----------------
                                       Gross        Net       Gross      Net
                                     ---------   ---------   -------   -------
Proved developed                         627         582      2,702     2,179
Proved undeveloped                       487         451        545       456
                                       -----       -----      -----     -----
Total proved reserves                  1,114       1,033      3,247     2,635
Total proved and probable reserves     1,617       1,501      4,178     3,394
                                       =====       =====      =====     =====

Estimated Future Net Revenues

                                            Forecast Prices and Costs
                                     ---------------------------------------
($ Millions)                         Undiscounted         Discounted at
                                     ------------   ------------------------
                                                      10%      15%      20%
                                                    ------   ------   ------
Proved developed                        17,838      12,708   11,267   10,181
Proved undeveloped                       7,856       4,071    3,164    2,528
                                        ------      ------   ------   ------
Total proved reserves                   25,694      16,779   14,431   12,709
Total proved and probable reserves      35,579      20,985   17,515   15,080
                                        ======      ======   ======   ======

                                      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.

<PAGE>

                                       31


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-jurisdictional  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.

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 2004
     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
       -----------------------------------------------   -----------------------------------------------------------
        Company                                           Company                   Hardisty
        Average   Henry Hub                Huntingdon/    Average      WTI @          Heavy     Edmonton   North Sea
         Price    Louisiana      AECO         Sumas        Price    Cushing (i)   12 DEG. 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     6.44     6.62(iii)      6.78          6.94        32.14     44.04(iv)       17.45        51.62      40.47
</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  (40 DEG.
          API), low sulphur content crude oil at Edmonton, Alberta.

     (iii)There was no trading of Henry Hub on December  31,  2004.  This posted
          value was  determined  on the basis of December  30, 2004 posted price
          for Henry Hub  adjusted  for the change in the AECO price as posted by
          the Canadian Gas Price Reporter.

     (iv) There was no trading on WTI on December  31,  2004.  This posted value
          was  determined on the basis of December 30, 2004 posted price for WTI
          adjusted  for the  change in the Brent  price as posted by the  Platts
          Oilgram Price Report.

     (v)  Foreign exchange rate used was $0.832 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  transportation.  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, 2005 crude oil,  natural  gas  liquids  and  natural gas pricing
     model.

<PAGE>

                                       32


The Company's weighted average crude oil and NGLs price and the weighted average
natural gas price in 2004 were $37.99 per barrel and $6.50 per mcf respectively,
before adjustments due to hedging. The crude oil and natural gas forecast prices
used in the Evaluation Reports are as follows:
--------------------------------------------------------------------------------

<TABLE>
<CAPTION>
                         NATURAL GAS                                          CRUDE OIL & NGLs
       -----------------------------------------------   -------------------------------------------------------
        Company                                           Company               Hardisty
        Average   Henry Hub                Huntingdon/    Average    WTI @       Heavy      Edmonton   North Sea
         Price    Louisiana      AECO         Sumas        Price    Cushing   12 DEG. 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>
2005     6.63        6.74        6.97          7.13        38.50     44.29       28.91       51.25       42.79
2006     6.31        6.48        6.66          6.92        36.80     41.60       28.12       48.03       40.08
2007     5.84        6.08        6.21          6.47        33.66     37.09       26.19       42.64       34.54
2008     5.36        5.70        5.73          5.99        31.04     33.46       25.06       38.31       31.89
2009     5.01        5.41        5.37          5.63        29.04     31.84       23.60       36.36       30.25
2010     5.10        5.49        5.47          5.73        29.53     32.32       24.12       36.91       30.70
2011     5.24        5.58        5.57          5.83        30.33     32.80       24.64       37.47       31.16
2012     5.32        5.66        5.67          5.93        29.74     33.30       25.17       38.03       31.63
2013     5.40        5.75        5.77          6.03        29.76     33.79       25.71       38.61       32.11
2014     5.49        5.83        5.87          6.13        30.29     34.30       26.26       39.19       32.59
2015     5.59        5.92        5.98          6.24        30.21     34.82       26.82       39.78       33.08
</TABLE>

     (i)  Foreign  exchange  rate used was $0.84 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.

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:

                          PROVED                      PROVED AND PROBABLE
             ------------------------------------------------------------------
             FORECAST PRICE   CONSTANT PRICE   FORECAST PRICE   CONSTANT PRICE
                  CASE             CASE             CASE             CASE
               ($Millions)      ($Millions)      ($Millions)      ($Millions)
             --------------   --------------   --------------   ---------------
2005              1,331            1,325            1,465            1,458
2006                541              534              633              621
2007                302              292              472              438
2008                212              199              535              497
2009                133              123              486              452
2010                129              117              402              367
2011                164              305              415              438
2012                 81               97              229              151
2013                 37               81              171              175
2014                213               62               49               79
2015                120               36              160               46
2016                 90               80               54               83
Thereafter          561              460              825              634

13.  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  conventional  reserves data by Sproule and Ryder Scott 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>

                                       33


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, 2003      588      222       85        895    2,426      62       64      2552
Extensions & Discoveries          17        0        0         17      334       0        0       334
Infill Drilling                   24       35        0         59       74       0        0        74
Improved Recovery                  1       10        0         11        6       0        0         6
Property purchases                36       38        0         74      182      10        0       192
Property disposals                 0        0        0          0       (8)      0        0        (8)
Production                       (66)     (24)      (4)       (94)    (383)    (18)      (3)     (404)
Revisions of prior estimates      48       22       34        104      (40)    (27)      11       (56)
                                 ---      ---      ---      -----    -----     ---      ---      ----
Reserves, December 31, 2004      648      303      115      1,066     2591      27       72      2690
                                 ---      ---      ---      -----    -----     ---      ---      ----
Proved + Probable reserves
Reserves, December 31, 2003      857      317      133      1,307     2919     102       72      3093
Extensions & Discoveries          20        0        0         20      418       0        0       418
Infill Drilling                   29       49        0         78      106       0        0       106
Improved Recovery                  2       10        0         12        6       0        0         6
Property purchases                49       49        0         98      236      18        0       254
Property disposals                 0        0        0          0      (10)      0        0       (10)
Production                       (66)     (24)      (4)       (94)    (383)    (18)      (3)     (404)
Revisions of prior estimates      35       14       67        116       27     (45)      21         3
                                 ---      ---      ---      -----    -----     ---      ---      ----
Reserves, December 31, 2004      926      415      196      1,537     3319      57       90      3466
</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 2004 Annual Report under "Supplementary Oil and Gas
Information" on pages 91 to 95 and is incorporated herein by reference.

<PAGE>

                                       34


D.   OIL SANDS MINING RESERVES

Horizon oil sands mining  reserves are not part of Canadian  Natural's  year-end
reserves disclosure.  Horizon reserves were evaluated as of February 9, 2005, as
reported in their report dated February 18, 2004, with the  authorization by the
Board of Directors to proceed with Phase 1 of the Horizon Oil Sands Project (the
"Horizon  Project").  Gilbert Laustsen Jung Associates Ltd. ("GLJ"), a qualified
independent  reserves  evaluator,  was  retained by the  Reserves  Committee  of
Canadian  Natural's Board of Directors to evaluate reserves  associated with the
Horizon  Project  incorporating  both the mining and upgrading  projects.  These
reserves were evaluated  under SEC Industry Guide 7. The Reserves  Committee has
met with GLJ and carried out independent due diligence procedures with GLJ as to
the Company's Horizon Project reserves.

The following table sets out, on a gross basis,  Canadian  Natural's  proved and
probable  reserves of bitumen and synthetic  crude oil from its Oil Sands mining
leases as of February 9, 2005.

                                        Gross Oil Sands Mining Reserves (MMbbls)
                                        ----------------------------------------
                                         Proved   Probable   Proved and Probable
                                         ------   --------   -------------------
Bitumen                                   1,900     1,420           3,320

Synthetic crude oil (1)                   1,560     1,230           2,790

(1)  Synthetic  crude  oil  reserves  are  based  on  upgrading  of the  bitumen
     reserves.  The reserves  shown for bitumen and synthetic  crude oil are not
     additive.

A report on Horizon oil sands  mining  reserves  data by GLJ and a report of the
Company's management and directors on mining reserves 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 and
mining reserves with any U. S. agency or federal authority other than the SEC.

E.   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
                                                     ---------------------------
                                                       2004      2003      2002
                                                     -------   -------   -------
Daily Production
   Crude Oil and NGLs (bbls/d)                       282,489   242,392   215,335
   Natural Gas (MMcf/d)                                1,388     1,299     1,232
Annual Production
   Crude Oil and NGLs (Mbbls)                        103,391    88,473    78,597
   Natural Gas (Bcf)                                     508       474       450

<PAGE>

                                       35


NETBACKS
INFORMATION BY QUARTER

<TABLE>
<CAPTION>
                                                                  YEAR 2004
                                     ------------------------------------------------------------------
                                     1st Quarter   2nd Quarter   3rd Quarter   4th Quarter   Year Ended
                                     -----------   -----------   -----------   -----------   ----------
<S>                                    <C>           <C>           <C>           <C>          <C>
Average Daily Production Volumes
   Crude oil and NGL's (bbl)            261,286       275,398       297,262       295,704      282,489
   Natural Gas (mcf)                      1,294         1,452         1,396         1,410        1,388

Product Netbacks
Crude oil and NGLs ($/bbl)
   Sales Price (1)                     $  34.21      $  36.72      $  43.50      $  36.92     $  37.99
   Royalties                           $   2.91      $   3.15      $   3.59      $   2.95     $   3.16
   Production Expenses                 $   9.58      $   9.92      $  10.21      $  10.41     $  10.05
   Netback                             $  21.72      $  23.65      $  29.70      $  23.56     $  24.78

Natural Gas ($/Mcf)
   Sales Price (1)                     $   6.31      $   6.64      $   6.24      $   6.77     $   6.50
   Royalties                           $   1.27      $   1.38      $   1.39      $   1.34     $   1.35
   Production Expenses                 $   0.65      $   0.66      $   0.71      $   0.68     $   0.67
   Netback                             $   4.39      $   4.60      $   4.14      $   4.75     $   4.48

Crude Oil and NGL Netbacks by Type
Light/Pelican Lake/NGLs ($/bbl)
   Sales Price (1)                     $  40.75      $  45.28      $  51.54      $  48.60     $  46.71
   Royalties                           $   3.71      $   3.98      $   3.99      $   4.12     $   3.95
   Production Expenses                 $   9.77      $  10.36      $  10.70      $  11.20     $  10.53
   Netback                             $  27.27      $  30.94      $  36.85      $  33.28     $  32.23

Heavy ($/bbl)
   Sales Price (1)                     $  27.00      $  28.08      $  35.33      $  25.16     $  28.99
   Royalties                           $   2.02      $   2.31      $   3.18      $   1.77     $   2.34
   Production Expenses                 $   9.38      $   9.47      $   9.72      $   9.62     $   9.56
   Netback                             $  15.60      $  16.30      $  22.43      $  13.77     $  17.09

<CAPTION>
                                                                  YEAR 2003
                                     ------------------------------------------------------------------
                                     1st Quarter   2nd Quarter   3rd Quarter   4th Quarter   Year Ended
                                     -----------   -----------   -----------   -----------   ----------
<S>                                    <C>           <C>           <C>           <C>          <C>
Average Daily Production Volumes
   Crude oil and NGL's (bbl)            237,560       240,607       247,016       244,262      242,392
   Natural Gas (mcf)                      1,310         1,325         1,289         1,270        1,299

Product Netbacks
Crude oil and NGLs ($/bbl)
   Sales Price (1)                     $  39.37      $  30.66      $  31.45      $  29.47     $  32.66
   Royalties                           $   3.56      $   2.78      $   2.56      $   2.22     $   2.77
   Production Expenses                 $  10.79      $  10.80      $  10.14      $   9.45     $  10.28
   Netback                             $  25.02      $  17.08      $  18.75      $  17.80     $  19.61

Natural Gas ($/Mcf)
   Sales Price (1)                     $   7.75      $   6.25      $   5.57      $   5.26     $   6.21
   Royalties                           $   1.78      $   1.35      $   1.11      $   1.05     $   1.32
   Production Expenses                 $   0.57      $   0.59      $   0.63      $   0.63     $   0.60
   Netback                             $   5.40      $   4.31      $   3.83      $   3.58     $   4.29

Crude Oil and NGL Netbacks by Type
Light/Pelican Lake/NGLs ($/bbl)
   Sales Price (1)                     $  44.38      $  34.60      $  36.06      $  35.76     $  37.66
   Royalties                           $   4.18      $   3.32      $   3.11      $   2.82     $   3.35
   Production Expenses                 $  10.42      $   9.76      $   9.53      $   9.65     $   9.83
   Netback                             $  29.78      $  21.52      $  23.42      $  23.29     $  24.48

Heavy ($/bbl)
   Sales Price (1)                     $  32.44      $  25.37      $  25.17      $  21.45     $  25.98
   Royalties                           $   2.71      $   2.06      $   1.83      $   1.47     $   2.00
   Production Expenses                 $  11.30      $  12.19      $  10.96      $   9.19     $  10.88
   Netback                             $  18.43      $  11.12      $  12.38      $  10.79     $  13.10
</TABLE>

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

(1) Including transportation and excluding risk management activities

<PAGE>

                                       36


NETBACKS
INFORMATION BY QUARTER

<TABLE>
<CAPTION>
                                                                     YEAR 2004
                                        ------------------------------------------------------------------
                                        1st Quarter   2nd Quarter   3rd Quarter   4th Quarter   Year Ended
                                        -----------   -----------   -----------   -----------   ----------
<S>                                        <C>           <C>           <C>           <C>          <C>
SEGMENTED
North America Product Netbacks
Light/Pelican Lake/NGLs ($/bbl)
   Sales Price (1)                         $37.54        $41.03        $44.89        $43.80       $41.81
   Royalties                               $ 7.20        $ 7.91        $ 8.59        $ 8.76       $ 8.12
   Production Expenses                     $ 7.30        $ 7.74        $ 7.75        $ 7.85       $ 7.66
   Netback                                 $23.04        $25.38        $28.55        $27.19       $26.03

Heavy ($/bbl)
   Sales Price (1)                         $27.00        $28.08        $35.33        $25.16       $28.99
   Royalties                               $ 2.02        $ 2.31        $ 3.18        $ 1.77       $ 2.34
   Production Expenses                     $ 9.38        $ 9.47        $ 9.72        $ 9.62       $ 9.56
   Netback                                 $15.60        $16.30        $22.43        $13.77       $17.09

Natural Gas ($/Mcf)
   Sales Price (1)                         $ 6.37        $ 6.78        $ 6.36        $ 6.88       $ 6.61
   Royalties                               $ 1.33        $ 1.44        $ 1.45        $ 1.39       $ 1.40
   Production Expenses                     $ 0.60        $ 0.60        $ 0.63        $ 0.63       $ 0.62
   Netback                                 $ 4.44        $ 4.74        $ 4.28        $ 4.86       $ 4.59

North Sea Product Netbacks
Light Oil ($/bbl)
   Sales Price (1)                         $44.27        $49.22        $57.39        $52.77       $51.37
   Royalties                               $ 0.06        $ 0.10        $ 0.09        $ 0.08       $ 0.08
   Production Expenses                     $13.26        $13.84        $13.88        $14.96       $14.03
   Netback                                 $30.95        $35.28        $43.42        $37.73       $37.26

Natural Gas ($/Mcf)
   Sales Price (1)                         $ 5.08        $ 3.28        $ 3.17        $ 3.26       $ 3.73
   Royalties                               $   --        $   --        $   --        $   --       $   --
   Production Expenses                     $ 1.65        $ 1.92        $ 2.48        $ 2.29       $ 2.07
   Netback                                 $ 3.43        $ 1.36        $ 0.69        $ 0.97       $ 1.66

Offshore West Africa Product Netbacks
Light Oil ($/bbl)
   Sales Price (1)                         $42.08        $49.34        $53.86        $51.28       $49.05
   Royalties                               $ 1.28        $ 1.52        $ 1.42        $ 1.52       $ 1.43
   Production Expenses                     $ 7.09        $ 7.43        $ 8.05        $ 7.82       $ 7.59
   Netback                                 $33.71        $40.39        $44.39        $41.94       $40.03

Natural Gas ($/Mcf)
   Sales Price (1)                         $ 4.80        $ 5.18        $ 6.31        $ 4.73       $ 5.25
   Royalties                               $ 0.15        $ 0.16        $ 0.17        $ 0.14       $ 0.15
   Production Expenses                     $ 1.23        $ 1.38        $ 1.39        $ 1.31       $ 1.33
   Netback                                 $ 3.42        $ 3.64        $ 4.75        $ 3.28       $ 3.77

<CAPTION>
                                                                      YEAR 2003
                                        ------------------------------------------------------------------
                                        1st Quarter   2nd Quarter   3rd Quarter   4th Quarter   Year Ended
                                        -----------   -----------   -----------   -----------   ----------
<S>                                        <C>           <C>           <C>           <C>          <C>
SEGMENTED
North America Product Netbacks
Light/Pelican Lake/NGLs ($/bbl)
   Sales Price (1)                         $40.89        $32.73        $32.78        $30.95       $34.37
   Royalties                               $ 7.65        $ 6.33        $ 6.04        $ 5.51       $ 6.39
   Production Expenses                     $ 6.09        $ 6.42        $ 6.76        $ 7.24       $ 6.62
   Netback                                 $27.15        $19.98        $19.98        $18.20       $21.36

Heavy ($/bbl)
   Sales Price (1)                         $32.44        $25.37        $25.17        $21.45       $25.98
   Royalties                               $ 2.71        $ 2.06        $ 1.83        $ 1.47       $ 2.00
   Production Expenses                     $11.30        $12.19        $10.96        $ 9.19       $10.88
   Netback                                 $18.43        $11.12        $12.38        $10.79       $13.10

Natural Gas ($/Mcf)
   Sales Price (1)                         $ 7.88        $ 6.39        $ 5.70        $ 5.35       $ 6.34
   Royalties                               $ 1.84        $ 1.40        $ 1.16        $ 1.10       $ 1.38
   Production Expenses                     $ 0.55        $ 0.56        $ 0.58        $ 0.60       $ 0.57
   Netback                                 $ 5.49        $ 4.43        $ 3.96        $ 3.65       $ 4.39

North Sea Product Netbacks
Light Oil ($/bbl)
   Sales Price (1)                         $49.74        $37.08        $39.63        $41.70       $42.00
   Royalties                               $ 0.11        $(0.19)       $ 0.09        $(0.15)      $(0.03)
   Production Expenses                     $15.50        $14.17        $13.25        $13.42       $14.07
   Netback                                 $34.13        $23.10        $26.29        $28.43       $27.96

Natural Gas ($/Mcf)
   Sales Price (1)                         $ 4.03        $ 2.21        $ 2.57        $ 3.32       $ 3.03
   Royalties                               $   --        $   --        $   --        $   --       $   --
   Production Expenses                     $ 1.09        $ 1.45        $ 1.60        $ 1.16       $ 1.33
   Netback                                 $ 2.94        $ 0.76        $ 0.97        $ 2.16       $ 1.70

Offshore West Africa Product Netbacks
Light Oil ($/bbl)
   Sales Price (1)                         $37.86        $34.34        $37.37        $36.42       $36.47
   Royalties                               $ 1.20        $ 0.99        $ 1.13        $ 1.03       $ 1.08
   Production Expenses                     $14.03        $ 9.32        $ 7.11        $ 6.67       $ 8.68
   Netback                                 $22.63        $24.03        $29.13        $28.72       $26.71

Natural Gas ($/Mcf)
   Sales Price (1)                         $ 3.80        $ 5.09        $ 4.58        $ 3.95       $ 4.37
   Royalties                               $ 0.11        $ 0.15        $ 0.14        $ 0.11       $ 0.13
   Production Expenses                     $ 2.37        $ 1.45        $ 1.24        $ 1.18       $ 1.39
   Netback                                 $ 1.32        $ 3.49        $ 3.20        $ 2.66       $ 2.85
</TABLE>

NOTE: Pelican Lake oil has an API of 14 DEG.  to 17 DEG.,  but  receives  medium
      qualitycrude netbacks due to  exceptionally  low  operating  costs and low
      royalty rates.

(1) Including transportation and excluding risk management activities

<PAGE>

                                       37


NETBACKS
INFORMATION BY QUARTER

<TABLE>
<CAPTION>
                                                                  YEAR 2002
                                     ------------------------------------------------------------------
                                     1st Quarter   2nd Quarter   3rd Quarter   4th Quarter   Year Ended
                                     -----------   -----------   -----------   -----------   ----------
<S>                                   <C>            <C>           <C>           <C>          <C>
Average Daily Production Volumes
   Crude Oil and NGLs (bbls)           188,439        189,386       242,051       240,596      215,335
   Natural Gas (Mcf)                     1,053          1,078         1,427         1,365        1,232

Product Netbacks
   Crude oil and NGLs ($/bbl)
   Sales Price (1)                    $  25.00       $  30.12      $  35.19      $  32.83     $  31.22
   Royalties                          $   2.28       $   3.02      $   3.56      $   3.53     $   3.16
   Production Expenses                $   7.81       $   7.95      $   8.67      $   9.10     $   8.45
Netback                               $  14.91       $  19.15      $  22.96      $  20.20     $  19.61

Natural Gas ($/Mcf)
   Sales Price (1)                    $   2.98       $   3.77      $   3.08      $   5.07     $   3.77
   Royalties                          $   0.55       $   0.77      $   0.67      $   1.09     $   0.78
   Production Expenses                $   0.58       $   0.57      $   0.55      $   0.57     $   0.57
   Netback                            $   1.85       $   2.43      $   1.86      $   3.41     $   2.42

Crude Oil and NGL Netbacks by Type
   Light/Pelican Lake/NGLs ($/bbl)
   Sales Price (1)                    $  29.09       $  33.37      $  38.05      $  37.97     $  35.16
   Royalties                          $   3.25       $   4.04      $   4.48      $   4.39     $   4.10
   Production Expenses                $   7.48       $   8.36      $  10.06      $   9.38     $   8.97
   Netback                            $  18.36       $  20.97      $  23.51      $  24.20     $  22.09

Heavy ($/bbl)
   Sales Price (1)                    $  20.49       $  26.42      $  31.59      $  26.45     $  26.52
   Royalties                          $   1.21       $   1.86      $   2.42      $   2.45     $   2.03
   Production Expenses                $   8.18       $   7.48      $   6.91      $   8.77     $   7.84
   Netback                            $  11.10       $  17.08      $  22.26      $  15.23     $  16.65
</TABLE>

SEGMENTED
North America Product Netbacks

<TABLE>
<CAPTION>
                                                                  YEAR 2002
                                     ------------------------------------------------------------------
                                     1st Quarter   2nd Quarter   3rd Quarter   4th Quarter   Year Ended
                                     -----------   -----------   -----------   -----------   ----------
<S>                                     <C>           <C>           <C>           <C>          <C>
Light/Pelican Lake/NGLs ($/bbl)
   Sales Price (1)                      $25.75        $31.10        $35.01        $34.34       $31.88
   Royalties                            $ 4.24        $ 5.11        $ 5.98        $ 5.81       $ 5.35
   Production Expenses                  $ 5.25        $ 5.30        $ 5.00        $ 5.28       $ 5.20
   Netback                              $16.26        $20.69        $24.03        $23.25       $21.33

Heavy ($/bbl)
   Sales Price (1)                      $20.49        $26.42        $31.59        $26.45       $26.52
   Royalties                            $ 1.21        $ 1.86        $ 2.42        $ 2.45       $ 2.03
   Production Expenses                  $ 8.18        $ 7.48        $ 6.91        $ 8.77       $ 7.84
   Netback                              $11.10        $17.08        $22.26        $15.23       $16.65

Natural Gas ($/Mcf)
   Sales Price (1)                      $ 2.96        $ 3.81        $ 3.10        $ 5.11       $ 3.79
   Royalties                            $ 0.57        $ 0.79        $ 0.69        $ 1.11       $ 0.80
   Production Expenses                  $ 0.56        $ 0.55        $ 0.52        $ 0.55       $ 0.55
   Netback                              $ 1.83        $ 2.47        $ 1.89        $ 3.45       $ 2.44

North Sea Product Netbacks
Light Oil ($/bbl)
   Sales Price (1)                      $34.43        $39.43        $42.24        $42.46       $40.32
   Royalties                            $ 1.54        $ 1.76        $ 2.56        $ 2.79       $ 2.30
   Production Expenses                  $10.09        $15.72        $18.30        $14.68       $15.06
   Netback                              $22.80        $21.95        $21.38        $24.99       $22.96

Natural Gas ($/Mcf)
   Sales Price (1)                      $ 3.77        $ 1.80        $ 1.98        $ 3.20       $ 2.75
   Royalties                                --            --            --            --           --
   Production Expenses                  $ 1.33        $ 1.90        $ 1.78        $ 1.25       $ 1.53
   Netback                              $ 2.44        ($0.10)       $ 0.20        $ 1.95       $ 1.22
</TABLE>

<PAGE>

                                       38


Offshore West Africa Product Netbacks

<TABLE>
<CAPTION>
                                                                  YEAR 2002
                                     ------------------------------------------------------------------
                                     1st Quarter   2nd Quarter   3rd Quarter   4th Quarter   Year Ended
                                     -----------   -----------   -----------   -----------   ----------
<S>                                     <C>           <C>           <C>           <C>          <C>
Light Oil ($/bbl)
   Sales Price (1)                      $37.61        $33.92        $42.78        $43.15       $40.10
   Royalties                            $ 1.65        $ 1.11        $ 1.34        $ 1.35       $ 1.35
   Production Expenses                  $18.62        $12.76        $11.23        $13.68       $13.63
   Netback                              $17.34        $20.05        $30.21        $28.12       $25.12

Natural Gas ($/Mcf)
   Sales Price (1)                          --            --        $ 4.97        $ 4.63       $ 4.82
   Royalties                                --            --        $ 0.15        $ 0.15       $ 0.15
   Production Expenses                      --            --        $ 1.77        $ 1.85       $ 1.81
   Netback                              $   --        $   --        $ 3.05        $ 2.63       $ 2.86
</TABLE>

1) Including transportation and excluding risk management activities

F.   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
                                                   ----------------------------
                                                       2004           2003
                                                   ------------   -------------
                                                   Gross    Net   Gross    Net
                                                   -----   ----   -----   -----
Natural Gas                                         801     689     841     777
Crude Oil                                           378     328     490     458
Service/Stratigraphic                               339     336     447     440
Dry Holes                                           106      96     126     118
                                                   ----    ----   -----   -----
Total                                              1624    1449   1,904   1,793
                                                   ====    ====   =====   =====
*Total Success Rate                                          91%             91%

*excluding service and stratigraphic test wells

<PAGE>

                                       39


G.   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
                                                                   -------------
                                                                    2004    2003
                                                                   -----   -----
Net property acquisitions(1)                                       1,835     336
Land acquisition and retention                                       120     154
Seismic evaluation                                                    89      77
Well drilling, completion and equipping                            1,394   1,194
Pipeline and production facilities                                   821     522
                                                                   -----   -----
Reserve replacement expenditures                                   4,259   2,283
Midstream operations                                                  16      11
Horizon Project                                                      291     152
Abandonments                                                          32      40
Head office equipment                                                 35      20
                                                                   -----   -----
Total Net Capital Expenditures                                     4,633   2,506
                                                                   =====   =====

(1) Includes Business Combinations

<PAGE>

                                       40


                                                  2004 THREE MONTHS ENDED
                                          --------------------------------------
                                                       ($ Millions)
CAPITAL EXPENDITURES
BY QUARTER                                MAR. 31   JUNE 30   SEPT. 30   DEC. 31
                                          -------   -------   --------   -------
Net property acquisitions(1)                 507      277        290        761
Land acquisition and retention                31       39         37         13
Seismic evaluation                            32       11         25         21
Well drilling, completion and equipping      583      231        221        359
Pipeline and production facilities           280      166        190        185
                                           -----      ---        ---      -----
Reserve replacement expenditures           1,433      724        763      1,339
Midstream operations                          --        3          2         11
Horizon Project                               46      103         84         58
Abandonments                                   7        6         14          5
Head office equipment                          7        8         12          8
                                           -----      ---        ---      -----
Total Net Capital Expenditures             1,493      844        875      1,421
                                           =====      ===        ===      =====

(1) Includes Business Combinations

                                                  2003 THREE MONTHS ENDED
                                          --------------------------------------
                                                        ($ Millions)
CAPITAL EXPENDITURES
BY QUARTER                                MAR. 31   JUNE 30   SEPT. 30   DEC. 31
                                          -------   -------   --------   -------
Net property acquisitions(1)                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
                                            ===       ===        ===       ===

(1) Includes Business Combinations

<PAGE>

                                       41


H.   NON-RESERVE ACREAGE

The following table summarizes the Company's  working interest  holdings in core
region non-reserve acreage as at December 31, 2004:

                                                       Gross Acres     Net Acres
                                                       -----------   -----------
                                                       (thousands)   (thousands)
North America
Alberta                                                   10,869        9,032
British Columbia                                           2,436        1,824
Saskatchewan                                                 738          659
Manitoba                                                       8            7

North Sea
United Kingdom                                               738          565

Offshore West Africa
Angola                                                     1,220          610
Cote d'Ivoire                                                369          276
South Africa                                               5,550        5,550
                                                          ------       ------
Total                                                     21,928       18,523
                                                          ======       ======

I.   DEVELOPED ACREAGE

The following table summarizes the Company's  working interest  holdings in core
region developed acreage as at December 31, 2004:

                                                       Gross Acres    Net Acres
                                                       -----------   -----------
                                                       (thousands)   (thousands)
North America
Alberta                                                   5,350         3,960
British Columbia                                            895           682
Saskatchewan                                                326           242
Manitoba                                                      6             5

North Sea
United Kingdom                                              138            93

Offshore West Africa
Cote d'Ivoire                                                 8             5
                                                          -----         -----
Total                                                     6,723         4,987
                                                          =====         =====

<PAGE>

                                       42


                         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:

                                      ------------------------------------------
                                                YEAR ENDED DECEMBER 31
                                      ------------------------------------------
                                                     2004     2003
                                                    ------   ------
                                      ($ millions, except per share information)

Revenues (1) (net of royalties)                      6,536    5,283
Cash flow from operations                            3,769    3,160
Per common share - basic                             14.06    11.77
                 - diluted                           13.98    11.53
Net earnings (4)                                     1,405    1,403
Per common share - basic                              5.24     5.23
                 - diluted                            5.20     5.06
Total assets (4)                                    18,410   14,643
Total long-term debt(2,3)                            3,538    2,748

                                      ------------------------------------------
                                                2004 THREE MONTHS ENDED
                                      ------------------------------------------
                                        MARCH 31   JUNE 30   SEPT. 30   DEC. 31
                                        --------   -------   --------   -------
                                      ($ millions, except per share information)

Revenues (1) (net of royalties)           1,420     1,603      1,799     1,714
Net earnings                                258       259        311       577
Per common share - basic                   1.92      0.97       1.16      2.15
                 - diluted                 1.92      0.97       1.13      2.13

                                      ------------------------------------------
                                                2003 THREE MONTHS ENDED
                                      ------------------------------------------
                                        MARCH 31   JUNE 30   SEPT. 30   DEC. 31
                                        --------   -------   --------   -------
                                      ($ millions, except per share information)

Revenues (1) (net of royalties)           1,554     1,279      1,264     1,186
Net earnings (4)                            427       525        201       250
Per common share - basic                   1.60      1.96       0.75      0.93
                 - diluted                 1.52      1.89       0.74      0.91

(1)  Excluding transportation costs and risk management activities.

(2)  Restated to include preferred securities

(3)  Excluding current portion of long-term debt.

(4)  Restated for asset retirement obligations

<PAGE>

                                       43


                                CAPITAL STRUCTURE

Common Shares

The Company is authorized to issue an unlimited number of common shares, without
nominal or par  value.  Holders of common  shares are  entitled  to one vote per
share at a  meeting  of  shareholders  of  Canadian  Natural,  to  receive  such
dividends  as declared  by the Board of  Directors  on the common  shares and to
receive  pro-rata  the  remaining  property  and assets of the Company  upon its
dissolution or winding up, subject to any rights having priority over the common
shares.

Preferred Shares

The  Company  has no  preferred  shares  outstanding,  however,  the  Company is
authorized to issue two-hundred  thousand (200,000)  preferred shares designated
as Class 1 Preferred  Shares.  Holders of preferred shares shall not be entitled
as such to receive notice of or to attend any meeting of the shareholders of the
Company  and shall not be  entitled  to vote at any such  meeting  except  under
certain  circumstances as described in the Articles of Amalgamation.  Holders of
preferred  shares are entitled to receive such dividends as and when declared by
the Board of  Directors  in priority  to common  shares and shall be entitled to
receive pro-rata in priority to holders of commons shares the remaining property
and assets of Canadian  Natural upon its dissolution or winding-up.  The Company
may redeem or purchase for  cancellation at any time all or any part of the then
outstanding  preferred shares and the holders of the preferred shares shall have
the right at any time and from time to time to  convert  such  preferred  shares
into the common shares of the company.  There are no preferred  shares currently
outstanding.

Credit Ratings

Credit ratings accorded to the Company's debt securities are not recommendations
to purchase,  hold or sell the debt  securities  inasmuch as such ratings do not
comment as to market price or suitability for a particular investor.  Any rating
may not  remain in  effect  for any given  period of time or may be  revised  or
withdrawn  entirely  by a  rating  agency  in  the  future  if in  its  judgment
circumstances so warrant, and if any such rating is so revised or withdrawn.

The Company's senior unsecured long-term debt securities are rated "Baa1" with a
stable  outlook  by  Moody's  Investor  Services,  Inc.  ("Moody's"),  "BBB+" by
Standard & Poor's  Corporation  ("S&P")  and "BBB  high" with a stable  trend by
Dominion Bond Rating Service  Limited  ("DBRS").  S&P assigns a "BBB-" rating to
the Company's  subordinated  notes.  S&P assigns a rating outlook to the Company
and not to individual debt  instruments.  S&P has assigned a negative outlook to
the Company.

     Debt Rated

     $125 CAD million 7.40% unsecured note due 2007
     $400 US million 6.70% unsecured note due 2011
     $400 US million 7.20% unsecured note due 2032
     $350 US million 5.45% unsecured note due 2012
     $350 US million 6.54% unsecured note due 2033
     $125 US million 7.69% unsecured note due 2005
     $93 US million 6.45% Adjustable rate note due 2009
     $350 US million 4.90% unsecured note  due 2014
     $350 US million 5.85% unsecured note due 2035
     $80 US million 8.30% subordinated note due 2011

<PAGE>

                                       44


Moody's credit ratings are on a long-term debt rating scale that ranges from Aaa
to C,  which  represents  the  range  from  highest  to lowest  quality  of such
securities rated.  According to the Moody's rating system, debt securities rated
Baa1 are considered as  medium-grade  obligations,  i.e. they are neither highly
protected nor poorly secured.  Interest  payments and principal  security appear
adequate for the present but certain  protective  elements may be lacking or may
be characteristically  unreliable over any great length of time. Such securities
lack  outstanding  investment  characteristics  and  in  fact  have  speculative
characteristics as well. Moody's applies numerical  modifiers 1, 2 and 3 in each
generic rating  classification  from Aa through Caa in its corporate bond rating
system.  The modifier 1 indicates  that the issue ranks in the higher end of its
generic rating  category,  the modifier 2 indicates a mid-range  ranking and the
modifier 3 indicates that the issue ranks in the lower end of its generic rating
category.  A Moody's rating outlook is an opinion regarding the likely direction
of a rating over the medium term.

S&P's credit  ratings are on a long-term  debt rating scale that ranges from AAA
to D,  which  represents  the  range  from  highest  to lowest  quality  of such
securities rated.  According to the S&P rating system, debt securities rated BBB
exhibit adequate protection parameters.  However, adverse economic conditions or
changing  circumstances  are more  likely to lead to a weakened  capacity of the
obligor to meet its financial commitments on the notes. The ratings from AA to B
may be modified by the addition of a plus (+) or minus (-) sign to show relative
standing within the major rating categories.  An S&P rating outlook assesses the
potential direction of a long term credit rating over the intermediate to longer
term. In determining a rating outlook,  consideration is given to any changes in
the economic and/or fundamental business conditions.

DBRS' credit  ratings are on a long-term  debt rating scale that ranges from AAA
to D,  which  represents  the  range  from  highest  to lowest  quality  of such
securities rated. According to the DBRS rating system, debt securities rated BBB
are of  adequate  credit  quality.  Protection  of  interest  and  principal  is
considered  acceptable,  but the entity is fairly susceptible to adverse changes
in financial and economic  conditions.  The  assignment of a "(high)" or "(low)"
modifier within each rating  category  indicates  relative  standing within such
category.  The "high" and "low"  grades are not used for the AAA  category.  The
rating trend is DBRS' opinion regarding the outlook for the rating.

<PAGE>

                                       45


            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.

            2004 Monthly Historical Trading on Toronto Stock Exchange

Month            High      Low     Close   Volume Traded
-----           ------   ------   ------   -------------
January         $71.80   $63.82   $64.00     12,121,445
February         73.85    63.99    73.25      9,749,239
March            76.50    70.20    72.70     12,853,959
April            81.65    72.85    75.40     12,279,432
May 1 - 18       81.70    73.80    78.55      8,416,911
*May 19 - 31     39.40    35.08    37.00     12,306,037
June             41.15    35.26    40.05     27,235,021
July             44.27    39.75    44.25     16,359,717
August           45.45    40.52    42.71     22,497,977
September        51.04    41.75    50.50     26,159,733
October          55.15    48.61    51.28     27,437,454
November         52.33    45.90    51.03     31,361,601
December         51.90    45.50    51.25     28,812,709

*    Shares began  trading on a post  two-for-one  subdivision  basis on May 19,
     2004.

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.  Under this program,  the Company  purchased a total of 873,400 common
shares for  cancellation at an average  purchase price of $37.98 for each common
share purchased; $38.01 after costs.

<PAGE>

                                       46


At the  Annual  and  Special  Meeting  of  Shareholders  held May 6,  2004,  the
shareholders passed a special resolution amending the Articles of the Company to
divide the issued and  outstanding  Common  Shares on a two-for-one  basis.  The
subdivision of the Common Shares occurred on May 21, 2004.

On January 20, 2005, 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, 2005 and ending  January 23, 2006,  to
purchase for cancellation up to 13,409,006 common shares of the Company, being 5
per cent of the 268,180,123 common shares of the Company  outstanding on January
12, 2005.  As of the date of this Annual  Information  Form, no shares have been
purchased.

On March 9,  2005,  the Board of  Directors  passed a  resolution  proposing  an
amendment  to  the  Articles  of  the  Company  to  sub-divide  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 5, 2005.

                                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.  Dividends
have been paid on the first day of January, April, July and October of each year
since 2001.

The  following  table  restated for the  two-for-one  subdivision  of the common
shares  which  occurred  in May 2004  shows  the  aggregate  amount  of the cash
dividends  declared  per common  share of the Company and accrued in each of its
last three years ended December 31.

                                                            2004    2003    2002
                                                           -----   -----   -----
Cash dividends declared per common share                   $0.40   $0.30   $0.25

                          TRANSFER AGENTS AND REGISTRAR

The   Company's   transfer   agent  and  registrar  for  its  common  shares  is
Computershare  Trust  Company of Canada in the cities of Calgary and Toronto and
Computershare  Shareholder Services, Inc. in the city of New York. The registers
for transfers of the Company's  common  shares are  maintained by  Computershare
Trust Company of Canada.

<PAGE>

                                       47


                        DIRECTORS AND EXECUTIVE 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>
NAME                           POSITION PRESENTLY HELD   PRINCIPAL OCCUPATION DURING PAST 5 YEARS
----                           -----------------------   ----------------------------------------
<S>                            <C>                       <C>
Catherine M. Best              Director(2)(4)            Executive   Vice-President,   Risk   Management  and  Chief
Calgary, Alberta               (age 51)                  Financial  Officer of the Calgary  Health  Region from 2002
Canada                                                   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/Banff, Alberta         Director(3)(5)            management    and   consulting    company).    Has   served
Canada                         (age 45)                  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 55)                  since May 2001;  prior thereto United States  Ambassador to
USA                                                      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.

John G. Langille               President and Director    Officer  of  the  Company.  Has  served  continuously  as a
Calgary, Alberta               (age 59)                  director of the Company since June 1982.
Canada

Keith A.J. MacPhail            Director(3)(4)(5)         Chairman,  President and Chief Executive Officer, Bonavista
Calgary, Alberta               (age 48)                  Petroleum  Ltd.  (independent  oil and natural gas company)
Canada                                                   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              Chairman  of the  Company.  Has  served  continuously  as a
Calgary, Alberta               Director(3)(5)            director of the Company since January 1989.
Canada                         (age 59)

James S. Palmer, C.M., A. O.   Director(3)(4)(5)         Chairman,  Burnet,  Duckworth & Palmer LLP (law firm).  Has
E., Q.C.                       (age 76)                  served  continuously as a director of the Company since May
Calgary, Alberta                                         1997.  Currently  serving  on the  board  of  directors  of
Canada                                                   Magellan Aerospace  Corporation;  Trenton Iron Works; Rally
                                                         Energy  Corp.;  and,  on the board of  trustees  for Rogers
                                                         Sugar Income Fund.

Dr. Eldon R. Smith, M.D.       Director(1)(4)(5)         Emeritus  Professor  and Former Dean,  Faculty of Medicine,
Calgary, Alberta               (age 65)                  University  of  Calgary.   Has  served  continuously  as  a
Canada                                                   director of the Company since May 1997.  Currently  serving
                                                         on the board of directors of Vasogen Inc.;  and,  Pheromone
                                                         Sciences Corp.
</TABLE>

<PAGE>

                                       48


<TABLE>
<CAPTION>
NAME                           POSITION PRESENTLY HELD   PRINCIPAL OCCUPATION DURING PAST 5 YEARS
----                           -----------------------   ----------------------------------------
<S>                            <C>                       <C>
David A. Tuer                  Director(1)(2)(3)         An  independent  businessman.   Chairman,   Calgary  Health
Calgary, Alberta               (age 55)                  Region since  October 2001 and  President and CEO of Hawker
Canada                                                   Resources  Inc.  (independent  oil and natural gas company)
                                                         from January 2003 to March 2005.  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  Rockwater  Capital  Corporation;  and,  Argo
                                                         Energy Ltd.

Steve W. Laut                  Chief Operating Officer   Officer of the Company.
Calgary, Alberta               (age 47)
Canada

Real M. Cusson                 Senior Vice-President,    Officer of the Company.
Calgary, Alberta               Marketing
Canada                         (age 54)

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.
Canada                         (age 52)

Allen M. Knight                Senior Vice-President,    Officer of the Company.
Calgary, Alberta               International &
Canada                         Corporate Development
                               (age 55)

Tim S. McKay                   Senior Vice-President,    Officer of the Company.
Calgary, Alberta               Operations
Canada                         (age 43)

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
Canada                         (age 54)                  Ltd.  to  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
Canada                         (age 50)

Jeffrey W. Wilson              Senior Vice-President,    Officer of the Company since September 2003;  prior thereto
Calgary, Alberta               Exploration               Exploration Manager of the Company.
Canada                         (age 52)

Mary-Jo Case                   Vice-President, Land      Officer  of the  Company  since  May  2002;  prior  thereto
Calgary, Alberta               (age 46)                  Co-ordinator Land at PanCanadian  Petroleum Limited to 1999
Canada                                                   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.
Canada                         and Environmental
                               Affairs (age 42)

Gordon M. Coveney              Vice-President,           Officer of the Company since September 2003;  prior thereto
Calgary, Alberta               Exploration, Northeast    Exploration Manager for the Company.
Canada                         District
                               (age 51)

Randall S. Davis               Vice-President,           Officer  of the  Company  since July  2004;  prior  thereto
Calgary, Alberta               Financial Accounting      Manager,  Financial  Reporting  of the Company to July 2002
Canada                         and Controls (age 38)     and most recently Financial  Controller of the Company from
                                                         July 2002 to July 2004.
</TABLE>

<PAGE>

                                       49


<TABLE>
<CAPTION>
NAME                           POSITION PRESENTLY HELD   PRINCIPAL OCCUPATION DURING PAST 5 YEARS
----                           -----------------------   ----------------------------------------
<S>                            <C>                       <C>
Jerome W. Harvey               Vice-President,           Officer of the  Company  since April  2004;  prior  thereto
Calgary, Alberta               Commercial Operations     Manager, Commercial Operations.
Canada                         (age 51)

Peter Janson                   Vice-President,           Officer of the Company since December  2004;  prior thereto
Calgary, Alberta               Engineering Integration   Director,  Production Planning and Control to June 2000 and
Canada                         (age 47)                  Director,  Health and Safety and Environment from June 2000
                                                         to  November  2002 at Suncor  Oil  Sands and most  recently
                                                         Director,  Engineering  Integration  of  the  Company  from
                                                         November 2002  to December 2004.

Terry J. Jocksch               Vice-President,           Officer of the  Company  since April  2004;  prior  thereto
Calgary, Alberta               Exploitation East         Exploitation Manager of the Company to April 2004.
Canada                         (age 37)

Christopher M. Kean            Vice-President,           Officer of the Company since December  2004;  prior thereto
Calgary, Alberta               Utilities and Offsite,    Manager Facilities  Engineering to January 2002,  Utilities
Canada                         Horizon Oil Sands         and  Offsites  Project  Manager  January 2002 to July 2002,
                               Project                   Director,  Utilities  and  Offsites  July 2002 to July 2003
                               (age 41)                  and most recently General  Manager,  Utilities and Offsites
                                                         July 2003 to December 2004.

Philip A. Keele                Vice-President, Mining,   Officer of the Company since December  2004;  prior thereto
Calgary, Alberta               Horizon Oil Sands         from Mine  Manager at  Fording  Coal  Limited  to  February
Canada                         Project                   2001,  Chief Mine Engineer of the Company  February 2001 to
                               (age 45)                  September   2002   and   most   recently   Director,   Mine
                                                         Engineering  of the Company from September 2002 to December
                                                         2004.

Cameron S. Kramer              Vice-President,           Officer of the Company since September 2002;  prior thereto
Calgary, Alberta               Field Operations          Production  Engineer  of the Company to March 2000 and most
Canada                         (age 37)                  recently  Manager,  Field  Operations  of the Company  from
                                                         April 2000 to September 2002.

Leon Miura                     Vice-President,           Officer of the Company  since  August 2003;  prior  thereto
Calgary, Alberta               Upgrading                 held   progressively   senior  positions  at  Petroleos  de
Canada                         (age 50)                  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.

John S. J. Parr                Vice-President,           Officer of the  Company  since April  2004;  prior  thereto
Calgary, Alberta               Production, East          Production  Engineer,  NE Gas of the  Company to July 2001,
Canada                         (age 43)                  Manager,  Production  Engineering  of the Company from July
                                                         2002 to June  2002 and most  recently  Production  Manager,
                                                         Heavy Oil of the Company from July 2002 to April 2004.

David A. Payne                 Vice-President,           Officer of the Company since  October  2004;  prior thereto
Calgary, Alberta               Exploitation, West        Exploitation  Manager,  Thermal  Heavy  of the  Company  to
Canada                         (age 43)                  July  2000,  Director,  Exploitation  of CNR  International
                                                         (U.K.)  Limited a  wholly-owned  subsidiary  of the Company
                                                         from   July  2000  to   August   2003  and  most   recently
                                                         Exploitation  Manager,  Technical  Projects  of the Company
                                                         from August 2003 to October 2004.

William R. Peterson            Vice-President,           Officer of the  Company  since April  2004;  prior  thereto
Calgary, Alberta               Production, West          Production Manager, West of the Company.
Canada                         (age 38)

John C. Puckering              Vice President, Site      Officer of the  Company  since April  2004;  prior  thereto
Calgary, Alberta               Development               General  Manager DCL  Construction  Inc. to November  2001,
Canada                         (age 58)                  President of 960925  Alberta  Ltd.  from  November  2001 to
                                                         April 2002,  Manager,  Site  Development of the Company May
                                                         2002 to December  2002 and most  recently  General  Manager
                                                         Site  Development of the Company from January 2003 to April
                                                         2004.
</TABLE>

<PAGE>

                                       50


<TABLE>
<CAPTION>
NAME                           POSITION PRESENTLY HELD   PRINCIPAL OCCUPATION DURING PAST 5 YEARS
----                           -----------------------   ----------------------------------------
<S>                            <C>                       <C>
Sheldon L. Schroeder           Vice-President, Project   Officer of the  Company  since April  2004;  prior  thereto
Calgary, Alberta               Control                   engineer  with 729248  Alberta  Ltd. to June 2001,  Project
Canada                         (age 37)                  Control   Manager  of  the   Company   from  June  2001  to
                                                         September 2002 and most recently Director,  Project Control
                                                         of the Company from September 2002 to April 2004.

Kendall W. Stagg               Vice-President,           Officer of the Company since  October  2004;  prior thereto
Calgary, Alberta               Exploration, West         Cardium  Geophysicist  of the Company to April 2001,  Chief
Canada                         (age 43)                  Geophysicist  of the  Company  from April 2001 to June 2002
                                                         and  most  recently  Manager  Exploration,  B.  C.  of  the
                                                         Company from June 2002 to September 2004.

Lynn M. Zeidler                Vice-President, Bitumen   Officer of the Company  since  August 2003;  prior  thereto
Calgary, Alberta               Production                held   progressively   senior  positions  at  Shell  Canada
Canada                         (age 48)                  Limited  including on secondment  from Shell Canada Limited
                                                         as Manager-Tier 1  Implementation  at Sable Offshore Energy
                                                         Inc to September  2000 and most  recently  General  Project
                                                         Manager,  Athabasca  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.

Kimberly I. McKay              Treasurer                 Officer of the Company since December  2004;  prior thereto
Calgary, Alberta               (age 36)                  Financial  Accountant  of  the  Company  to  October  2001,
Canada                                                   Advisor Capital Markets and Treasury  Administration of the
                                                         Company from  October  2001 to July 2002 and most  recently
                                                         Treasury  Manager of the Company from July 2002 to December
                                                         2004.

Bruce E. McGrath               Corporate Secretary       Officer of the Company.
Calgary, Alberta               (age 55)
Canada
</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. All of the current directors were elected to the Board at the last
annual meeting of shareholders held on May 6, 2004. All of the current directors
are  standing  for  election  at the  Annual  General  Meeting  of  Shareholders
scheduled for May 5, 2005.

As at December 31, 2004, 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 4 per cent of the total outstanding common
shares  (approximately  5 per cent after the  exercise  of options  held by them
pursuant to the Company's stock option plan).

Conflicts of Interest

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

<PAGE>

                                       51


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).

                           AUDIT COMMITTEE INFORMATION

Audit Committee Members

The Audit Committee of the Board of Directors of the Company is comprised of Ms.
C. M.  Best,  Chair,  Messrs.  G. D.  Giffin  and D. A. Tuer each of whom is (i)
independent as defined under Canadian  securities  regulations NI 52-110 and the
NYSE listing  standards as they pertain to audit  committees of listed  issuers;
and, (ii) financially literate.

Ms. C. M. Best is a chartered  accountant  with 20 years  experience  as a staff
member and partner of an international public accounting firm. During her tenure
she was  responsible  for direct  oversight and  supervision of a large staff of
auditors  conducting audits of the financial  reporting of significant  publicly
traded  entities,  many of which were oil and gas companies.  This oversight and
supervision  required  Ms. C. M. Best to  maintain  a current  understanding  of
generally  accepted  accounting   principles,   and  be  able  to  assess  their
application  in each  of her  clients.  It also  required  an  understanding  of
internal controls and financial reporting processes and procedures.

Ambassador G. D. Giffin's  education and experience  relevant to the performance
of his  responsibilities  as an audit committee  member is derived from a thirty
year  law  practice  involving  complex  accounting  and  audit-related   issues
associated  with  complicated  commercial  transactions  and  disputes.  He  has
developed  extensive  practical  experience  and an  understanding  of  internal
controls  and  procedures  for  financial  reporting  from his  service on audit
committees  for  several  publicly  traded  issuers  and  continues  pursuit  of
extensive professional reading and study on related subjects.

Mr. D. A. Tuer's  education and  experience  relevant to the  performance of his
responsibilities  as an audit  committee  member is  derived  from  professional
training and a business career as a Chief Executive  Officer in a large publicly
traded company which provided  experience in analyzing and evaluating  financial
statements and  supervising  persons  engaged in the  preparation,  analysis and
evaluation of financial  statements of publicly traded companies.  He has gained
an  understanding  of internal  controls and procedures for financial  reporting
through  oversight of those functions,  and the understanding of Audit Committee
functions through his years of Chief Executive involvement.

Auditor Service Fees

Auditor Service                                               2004        2003
---------------                                            ----------   --------
Audit fees                                                 $1,100,548   $886,000
Audit related fees                                         $  183,663   $ 12,500
Tax related fees                                           $   39,330   $ 11,000
All other fees                                             $        0   $ 10,000

<PAGE>

                                       52


                                LEGAL PROCEEDINGS

From  time to  time,  CNRL  is the  subject  of  litigation  arising  out of the
Company's  operations.  Damages claimed under such litigation may be material or
may be  indeterminate  and the outcome of such litigation may materially  impact
the Company's  financial  condition or results of operations.  While the Company
assesses the merits of each lawsuit and defends itself accordingly,  the Company
may be required to incur significant expenses or devote significant resources to
defend itself  against such  litigation.  The claims that have been made to date
are not currently expected to have a material impact on the Company's  financial
position.

                              INTERESTS OF EXPERTS

Canadian Natural's auditor is PricewaterhouseCoopers LLP, Chartered Accountants,
3100,  111-5th  Avenue S. W.  Calgary,  Alberta T2P 5L3. The  Company's  audited
consolidated financial statements for the year ended December 31, 2004 have been
filed  under   National   Instrument   51-102  in  reliance  on  the  report  of
PricewaterhouseCoopers  LLP, independent chartered  accountants,  given on their
authority as experts in auditing and accounting.

Sproule  Associates  Limited,  Ryder Scott  Company and  Gilbert  Laustsen  Jung
Associates  Ltd.  have provided the Report on Reserves Data attached as Schedule
"A" to  this  Annual  Information  Form  in  their  capacity  as  the  Company's
Independent  Qualified Reserves  Evaluators.  Sproule Associates Limited,  Ryder
Scott Company and Gilbert  Laustsen Jung  Associates  Ltd. and their  directors,
officers  and  associates,  collectively  own  less  than  1% of  the  Company's
outstanding common shares.

                             ADDITIONAL INFORMATION

Additional information relating to the Company can be found on the SEDAR website
at www.sedar.com

Additional information including Directors' and Executive Officers' remuneration
and  indebtedness,  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 17, 2005 in connection with the Annual and
Special Meeting of  Shareholders  of Canadian  Natural to be held on May 5, 2005
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, 2004 found on pages 39 to 67, 68 to 90
and 91 to 95 respectively, of the 2004 Annual Report to the Shareholders,  which
information is incorporated herein by reference.

For additional copies of this Annual Information Form, please contact:

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

<PAGE>

                                       53


                                  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.   Except as noted in 1(c) (i), we have evaluated the  Corporation's  reserves
     data as at December 31, 2004. The reserves data consist of the following:

(a)  (i)  proved oil and natural gas reserve quantities estimated as at December
          31, 2004 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, 2004 using forecast prices and costs;  and (ii) the
          related estimated future net revenue

(c)  (i)  proved  and proved  plus  probable  bitumen  and  synthetic  crude oil
          reserves relating to surface mineable oil sands projects  estimated as
          at February 9, 2005

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.

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
     natural 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, 2004 except as noted in 1(c)(i), and identifies the respective
     portions

<PAGE>

                                       54


thereof that we have evaluated and reported on to the  Corporation's  management
and board of directors:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
   Independent    Description and      Location of         Net Present Values of Future Cash Flows
    Qualified       Preparation     Reserves (Country     (Before Income Taxes, 10% Discount Rate)
     Reserves         Date of           or Foreign      --------------------------------------------
   Evaluator or      Evaluation         Geographic      Audited    Evaluated   Reviewed      Total
     Auditor           Report             Area)           MM$         MM$         MM$         MM$
----------------------------------------------------------------------------------------------------
<S>               <C>               <C>                    <C>    <C>             <C>     <C>
Sproule           Sproule           Canada, USA            $0     $11,242.36      $0      $11,242.36
Associates Ltd.   Evaluated the
                  P&NG
                  Reserves as
                  reported
                  February 18,
                  2005.
----------------------------------------------------------------------------------------------------
Ryder Scott       Ryder Scott       Canada (assets         $0     $   468.00      $0      $   468.00
Company           Evaluated the     acquired November
                  P&NG Reserves     2004)
                  as reported
                  February 18,
                  2005.
----------------------------------------------------------------------------------------------------
Ryder Scott       Ryder Scott       United Kingdom         $0     $ 6,427.80      $0      $ 6,427.80
Company           Evaluated the     and Offshore West
                  P&NG Reserves     Africa
                  as reported
                  February 18,
                  2005.
----------------------------------------------------------------------------------------------------
Totals                                                     $0     $18,138.16      $0      $18,138.16
----------------------------------------------------------------------------------------------------
</TABLE>

In addition all proved and proved plus probable company gross reserves have been
evaluated  for oil sands mining  properties  located in Canada.  Horizon  mining
reserves are not part of Canadian  Natural's year end. The Horizon reserves were
evaluated  as at February  9th,  2005.  Gilbert  Laustsen  Jung  Associates  Ltd
("GLJ"),  an  independent  qualified  reserves  evaluator,  was  retained by the
Reserves Committee of Canadian Natural's Board of Directors to evaluate reserves
associated with the Horizon Project  incorporating both the mining and upgrading
projects.  These  reserves  were  evaluated  under SEC Industry  Guide 7 and are
discussed separately from the Company's conventional oil and gas activities.

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.

<PAGE>

                                       55


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

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, 2005

     SPROULE ASSOCIATES LIMITED

     Original Signed By:

     /s/ Harry J. Helwerda
     ------------------------------------
     Harry J. Helwerda, P.Eng.,
     Vice-President, Engineering,

     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, Canada and U.S.


     RYDER SCOTT COMPANY

     Original Signed By:

     /s/ Jane Tink
     ------------------------------------
     Jane Tink, P.Eng.,
     Vice-President, Engineering


     GILBERT LAUSTSEN JUNG ASSOCIATES LTD.

     Original Signed By:

     /s/ James H. Willmon
     ------------------------------------
     James H. Willmon, P.Eng.
     Vice-President

<PAGE>

                                       56


                                  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 and surface mineable oil sands 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, 2004 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, 2004 using forecast prices and costs;
     (ii) the related estimated future net revenue; and,

(c)  (i)  proved and probable working interest oil reserve  quantities  relating
          to surface mineable oil sands  operations  estimated as at February 9,
          2005.

Sproule  Associates  Limited,  Ryder Scott  Company and  Gilbert  Laustsen  Jung
Associates Ltd. all independent qualified reserves evaluators have 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 each of the  independent  qualified  reserves  evaluators  to
          determine whether any restrictions  placed by management  affected the
          ability of the  independent  qualified  reserves  evaluators to report
          without reservation; and

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

<PAGE>

                                       57


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 and surface  mineable oil
          sands information;

     (b)  the  filing  of the  reports  of the  independent  qualified  reserves
          evaluators 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"
     Steve W. Laut
     Chief Operating Officer

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

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

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

     Dated this 18th day of February, 2005
     Calgary, Alberta