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                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549

                                    FORM 40-F

[_]   Registration Statement pursuant to section 12 of the Securities
      Exchange Act of 1934


[X]   Annual report pursuant to section 13(a) or 15(d) of the Securities
      Exchange Act of 1934

For the fiscal year ended December 31, 2005       Commission File Number: 1-8795

                       CANADIAN NATURAL RESOURCES LIMITED
             (Exact name of Registrant as specified in its charter)

                                     ALBERTA
        (Province or other jurisdiction of incorporation or organization)

                                      1311
            (Primary Standard Industrial Classification Code Numbers)

                                 NOT APPLICABLE
             (I.R.S. Employer Identification Number (if applicable))


          2500, 855-2ND STREET S.W., CALGARY, ALBERTA, CANADA, T2P 4J8
                            TELEPHONE: (403) 517-7345
   (Address and telephone number of Registrant's principal executive offices)


         CT CORPORATION SYSTEM, 111-8TH AVENUE, NEW YORK, NEW YORK 10011
                                 (212) 894-8940
                (Name, address (including zip code) and telephone
                    number (including area code) of agent for
                          service in the United States)


SECURITIES REGISTERED OR TO BE REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

                                                NAME OF EACH EXCHANGE
TITLE OF EACH CLASS:                            ON WHICH REGISTERED:
-------------------------------                 -----------------------------
Common Shares, no par value                     New York Stock Exchange
                                                Toronto Stock Exchange

              SECURITIES REGISTERED OR TO BE REGISTERED PURSUANT TO
                           SECTION 12(G) OF THE ACT:

                            TITLE OF EACH CLASS: None

        SECURITIES FOR WHICH THERE IS A REPORTING OBLIGATION PURSUANT TO
                         SECTION 15(D) OF THE ACT: None

FOR ANNUAL REPORTS, INDICATE BY CHECK MARK THE INFORMATION FILED WITH THIS FORM:

   [X] Annual information form          [X] Audited annual financial statements

          NUMBER OF OUTSTANDING SHARES OF EACH OF THE ISSUER'S CLASSES
            OF CAPITAL OR COMMON STOCK AS OF THE CLOSE OF THE PERIOD
                          COVERED BY THE ANNUAL REPORT.
          536,347,796 Common Shares outstanding as of December 31, 2005
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<PAGE>

Indicate by check mark whether the  Registrant is furnishing  the  information
contained in this Form to the Commission  pursuant to Rule 12g3-2(b) under the
Securities  Exchange  Act of 1934 (the  "Exchange  Act").  If "Yes" is marked,
indicate the filing number  assigned to the Registrant in connection with such
Rule.

              Yes [_]                               No [X]


Indicate  by check  mark  whether  the  Registrant  (1) has filed all  reports
required  to be filed by  Section 13 or 15(d) of the  Exchange  Act during the
preceding  12 months  (or for such  shorter  period  that the  Registrant  was
required  to file  such  reports)  and (2) has  been  subject  to such  filing
requirements for the past 90 days.


              Yes [X]                               No [_]


This Annual Report on Form 40-F shall be incorporated by reference into, or as
an exhibit to, as applicable,  the registrant's Registration Statement on Form
F-9 (Registration No. 333-104919) under the Securities Act of 1933.



<PAGE>

PRINCIPAL DOCUMENTS
-------------------

The following  documents have been filed as part of this Annual Report on Form
40-F, starting on the following page:


         A.       ANNUAL INFORMATION FORM

         Annual   Information  Form  of  Canadian  Natural  Resources  Limited
         ("Canadian Natural") for the year ended December 31, 2005.


         B.       AUDITED ANNUAL FINANCIAL STATEMENTS

         Canadian Natural's audited consolidated  financial statements for the
         years ended  December  31,  2005 and 2004,  including  the  auditor's
         report  with  respect  thereto.  For a  reconciliation  of  important
         differences  between  Canadian and United States  generally  accepted
         accounting  principles,  see Note 15 of the Notes to the Consolidated
         Financial Statements.


         C.       MANAGEMENT'S DISCUSSION AND ANALYSIS

         Canadian Natural's Management's  Discussion and Analysis for the year
         ended December 31, 2005.


SUPPLEMENTARY OIL & GAS INFORMATION

For Canadian Natural's  Supplementary Oil & Gas Information for the year ended
December 31, 2005, see Exhibit 1 of this Annual Report on Form 40-F.


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    C A N A D I A N   N A T U R A L   R E S O U R C E S   L I M I T E D







                            ANNUAL INFORMATION FORM










                                MARCH 29, 2006





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                                       1

TABLE OF CONTENTS

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS............................5

THE COMPANY..................................................................7

GENERAL DEVELOPMENT OF THE BUSINESS..........................................8

REGULATORY MATTERS..........................................................11

RISK FACTORS................................................................12

ENVIRONMENTAL MATTERS.......................................................16

DESCRIPTION OF THE BUSINESS.................................................16

A.   PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES..............18

         DRILLING ACTIVITY..................................................19
         PRODUCING CRUDE OIL AND NATURAL GAS WELLS..........................20
         NORTHEAST BRITISH COLUMBIA.........................................20
         NORTHWEST ALBERTA..................................................21
         NORTHERN PLAINS....................................................22
         SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN.........................25
         HORIZON OIL SANDS PROJECT..........................................26
         UNITED KINGDOM NORTH SEA...........................................28
         OFFSHORE WEST AFRICA...............................................29
         COTE D'IVOIRE......................................................30
         ANGOLA.............................................................31
         GABON..............................................................31

B.   CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES...................32

C.   RECONCILIATION OF CHANGES IN NET CONVENTIONAL RESERVES.................37

D.   OIL SANDS MINING DISCLOSURE............................................38

E.   CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION.............................45

F.   HISTORICAL DRILLING ACTIVITY BY PRODUCT................................50

G.   CAPITAL EXPENDITURES...................................................51

H.   UNDEVELOPED ACREAGE....................................................53

I.   DEVELOPED ACREAGE......................................................53

SELECTED FINANCIAL INFORMATION..............................................54

<PAGE>
                                      2


CAPITAL STRUCTURE...........................................................55

MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES....................57

DIVIDEND HISTORY............................................................58

TRANSFER AGENTS AND REGISTRAR...............................................58

DIRECTORS AND OFFICERS......................................................59

CONFLICTS OF INTEREST.......................................................63

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS..................63

AUDIT COMMITTEE INFORMATION.................................................63

LEGAL PROCEEDINGS...........................................................65

MATERIAL CONTRACTS..........................................................65

INTERESTS OF EXPERTS........................................................65

ADDITIONAL INFORMATION......................................................65

SCHEDULE "A" REPORT ON RESERVES DATA........................................67

SCHEDULE "B" REPORT OF MANAGEMENT AND DIRECTORS.............................70

SCHEDULE "C" CHARTER OF THE AUDIT COMMITTEE.................................72



                                   CURRENCY

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


<PAGE>
                                       3


                                  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.

"BBL/D" means barrels per day.

"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",  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.

"CONVENTIONAL  CRUDE OIL,  NGLS AND NATURAL GAS" includes all of the Company's
light and medium crude oil,  heavy crude oil,  thermal  in-situ,  natural gas,
coal bed methane and  natural gas liquid  activities.  It does not include the
Company's oil sands mining assets.

"DEVELOPMENT  WELL"  means a well  drilled  into a zone  that is  known  to be
productive and expected to produce crude oil or natural gas in the future.

"DRY WELL" means a well drilled  that is not capable of  producing  commercial
quantities of crude oil or natural gas to justify completion.  A dry well will
be plugged back, abandoned and reclaimed.

"EXPLORATORY  WELL" means a well drilled into an unproven  territory  with the
intention to discover commercial quantities of crude oil or natural gas.

"FPSO" means a 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.

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                                      4


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

"PRODUCTIVE WELL" a well that is not dry.

"SAGD" means steam-assisted gravity drainage.

"UNDEVELOPED  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.



<PAGE>
                                      5


               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 Securities 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  "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;  political  uncertainty,  including  actions of or against
terrorists or 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;  the  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 ability of the Company to attract the necessary
labour  required  to build  its  projects;  the  operating  hazards  and other
difficulties  inherent in the exploration for and production and sale of crude
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  asset
retirement  obligations;   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  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 were 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.  Except as required by law, 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

<PAGE>
                                      6


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 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.

For the year ended  December 31, 2005,  Canadian  Natural  retained  qualified
independent  reserve  evaluators,  Sproule Associates Limited  ("Sproule") and
Ryder  Scott  Company  ("Ryder  Scott"),  to  evaluate  100% of the  Company's
conventional  proved and probable  crude oil,  natural gas liquid  ("NGL") and
natural gas reserves and prepare Evaluation Reports on these reserves. Sproule
evaluated the Company's  North  American  conventional  assets and Ryder Scott
evaluated its conventional  international assets. The Company has been granted
an exemption from the 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.  There are two  principal  differences
between the two standards.  The first is the additional  requirement  under NI
51-101 to disclose  both proved and proved and probable  reserves,  as well as
the related net present value of future net revenues using forecast prices and
costs.  The  second is in the  definition  of  proved  reserves;  however,  as
discussed in the  Canadian  Oil and Gas  Evaluation  Handbook  ("COGEH"),  the
standards that NI 51-101 employs,  the difference in estimated proved reserves
based on constant pricing and costs between the two standards is not material.

The Company has disclosed  conventional  proved reserves and the  Standardized
Measure of discounted future net cash flows using constant prices and costs as
mandated by the SEC in the  supplementary  oil and gas information  section of
its Annual  Report.  The Company  has also  elected to provide the net present
value of these same  conventional  proved reserves as well as the conventional
proved and probable reserves and the net present value of these reserves under
the same parameters as additional  voluntary  information.  In addition to the
constant price and cost scenario, the Company has also elected to provide both
conventional proved and conventional proved and probable reserves,  as well as
the net present value of these  reserves,  using forecast  prices and costs as
voluntary additional information.

Reserves and net present values of these reserves 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.

For the year ended  December  31,  2005,  the  Company  retained  a  qualified
independent reserves evaluator, GLJ Petroleum Consultants ("GLJ"), to evaluate
100% of phases 1 through 3 of the  Company's  Horizon  Oil Sands  Project  and
prepare an Evaluation  Report on the Company's  proved,  as well as proved and
probable oil sands mining reserves incorporating both the mining and upgrading
projects.  These reserves were evaluated  adhering to the  requirements of SEC
Industry  Guide 7 using  year-end  constant  pricing  and have been  disclosed
separately  from the  Company's  conventional  crude oil,  NGL and natural gas
reserves.

The Reserves  Committee of the  Company's  Board of Directors has met with and
carried out independent due diligence  procedures with each of Sproule,  Ryder
Scott and GLJ to review  the  qualifications  of and  procedures  used by each

<PAGE>
                                      7


evaluator in  determining  the estimate of the  Company's  quantities  and net
present  value of  remaining  conventional  crude  oil,  NGL and  natural  gas
reserves, as well as the Company's quantity of oil sands mining reserves.

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,  adjusted net
earnings  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.  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.


                                  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.  Canadian Natural 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.

Canadian  Natural  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  ("Ranger"),  including its
subsidiaries,  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.

<PAGE>
                                      8


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

     -----------------------------------------------------------------------
                                                          JURISDICTION
     NAME OF COMPANY                                    OF INCORPORATION
     -----------------------------------------------------------------------
     CanNat Energy Inc.                                     Delaware
     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
     CNR International (Gabon) Limited                      Bahamas
     Horizon Construction Management Ltd.                   Alberta
     Renata Resources Inc.                                  Alberta

Canadian  Natural,  as the managing  partner,  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, CNR
(ECHO)  Resources  Inc.,  Renata  Resources  Inc.,  and  Canadian  Natural are
partners of Canadian Natural Resources Northern Alberta Partnership, a general
partnership.  The two partnerships hold the majority of the producing Canadian
crude oil and natural gas properties of Canadian Natural. The Company also has
a 15 per cent  interest  in Cold  Lake  Pipeline  Ltd.,  which is the  general
partner of Cold Lake Pipeline  Limited  Partnership in which Canadian  Natural
holds a separate 14.7 per cent partnership interest.  Canadian Natural, 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.  Canadian Natural, as the managing
partner,  and  1081840  Alberta  Ltd.  are the  partners  of  1081840  Alberta
Partnership,  which holds certain crude oil and natural gas  properties of the
Company.

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


                      GENERAL DEVELOPMENT OF THE BUSINESS

Canadian  Natural'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.  Canadian  Natural'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, 2005 the Company had 2,580
permanent  employees  in North  America  and 317  permanent  employees  in its
international operations.

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

<PAGE>
                                      9


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 crude 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 crude 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 mmcf/d of natural  gas and 200
bbl/d of light crude oil and NGLs and  contained  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 mmcf/d 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  has  added  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  crude 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  crude 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 mmcf/d of natural gas and 7.5 mbbl/d of light crude oil
and NGLs being  approximately  25,000  boe/d.  The  acquisition  included over
510,000 net acres of  undeveloped  land.  The vast  majority  of the  acquired
properties is located in the  Company's  core regions and extends its Northern
Plains core region into the light crude 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

<PAGE>
                                      10


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  ("Horizon  Project").  The Horizon  Project is
designed as a phased  development and includes the mining of bitumen  combined
with an onsite upgrader.  Phase 1 production is planned to begin in the second
half of 2008 at 110 mbbl/d of 34(degree) API light,  sweet synthetic crude oil
("SCO"). Phase 2 would increase production to 155 mbbl/d of SCO in 2010. Phase
3 would further  increase  production to 232 mbbl/d of SCO in 2012. The phased
approach  provides  the  Company  with  improved  cost  and  project  controls
including labour and materials  management,  and  directionally  mitigates the
effects of growth on local infrastructure.

Based upon stratigraphic  drilling the Company's oil sands leases located near
Fort McMurray,  Alberta  contain an estimated 6 billion barrels of potentially
recoverable   bitumen  using  existing  mining  and  upgrading   technologies.
Additional  in-situ  potential  also  exists on the  western  portions  of the
leases. The first three phases of the Horizon Project,  which encompasses only
a portion of these oil sands leases,  will deliver  approximately  37 years of
production without the declines normally associated with petroleum operations.
GLJ  Petroleum  Consultants  ("GLJ"),  a  qualified  independent  third  party
petroleum  consultant firm, was retained by the Reserves Committee of Canadian
Natural's Board of Directors to evaluate the mining  reserves  associated with
the Horizon Project.  Their report estimated that 3.4 billion barrels of gross
proved and probable bitumen reserves are located on the leases associated with
the first three phases of the Horizon Project.

In August 2005,  the Company  entered  into an  agreement  to obtain  pipeline
transportation service for the Horizon Project. This agreement allows Canadian
Natural  to gain  access to major  sales  pipelines  out of  Edmonton  for the
Company's  synthetic crude oil which will be produced at the Horizon  Project,
while at the same time provides  significant  quality benefits associated with
being the only shipper on the Horizon  Pipeline.  The expected twinning of the
existing  Alberta Oil Sands  Pipeline  ("AOSPL"),  resulting  in two  parallel
pipelines, one of which will be dedicated to Canadian Natural, combined with a
new  pipeline  constructed  from the  Horizon  Project  site down to the AOSPL
Terminal  (collectively,  the  "Horizon  Pipeline"),  will  provide  crude oil
transportation  service  for the  Horizon  Project.  The  initial  term of the
agreement is 25 years, which will commence on the in-service date. In addition
to having the option to renew the  agreement  for  successive  10-year  terms,
Canadian  Natural  has the  right to  request  incremental  expansions  of the
Horizon  Pipeline  based  upon  applicable   National  Energy  Board  approved
multi-pipeline economics. The construction of the Horizon Pipeline is expected
to begin in 2006 and will be fully  operational  by mid 2008 to coincide  with
first  production  at the  Horizon  Project.  See  below  "Horizon  Oil  Sands
Project".

In April 2005, the Company  monetized,  through a sale, a large portion of its
overriding  royalty  interests  on  various  producing  properties  throughout
Western Canada and Ontario for proceeds of approximately $345 million. In 2004
these interests produced  approximately 3,700 boe/d and over the 2003 and 2004
fiscal years cash flow from these interests averaged approximately $50 million
per year. As part of the transaction,  the Company  purchased  3,858,520 trust
units of Freehold  Royalty trust for $60 million and, after the mandatory hold
period,  the trust  units were sold to an  underwriting  group  pursuant to an
agreement for a net gain of approximately $11 million.

<PAGE>
                                      11


On June 1, 2005,  the  Company  issued $400  million of 10-year  4.95 per cent
unsecured  notes  maturing  June  1,  2015  pursuant  to a  short  form  shelf
prospectus  for the  issuance of medium term notes in Canada  dated  August 1,
2003.  In January  2006 the Company  issued a further $400 million of 4.50 per
cent unsecured notes maturing January 23, 2013 as the first issuance under the
short form Canadian base shelf  prospectus dated August 29, 2005, which allows
for the issuance of debt securities in an aggregate  principal amount of up to
C$2 billion.

During 2005,  the Company  completed 96  transactions  in the normal course to
acquire  additional  interests in crude oil and natural gas  properties  at an
aggregate net expenditure of $134 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 a large portion of its overriding  royalty  interests and
operated and non-operated properties not located in the Company's core regions
for proceeds of $454 million.


                              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  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  approval of a
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  NGLs  from  each  province.
Government  royalties are payable on crude oil and natural gas production from

<PAGE>
                                      12


leases owned by the province.  The royalties are  determined by regulation and
are generally  calculated as a percentage of production  varied by a number of
different  factors  including  selling  prices,  production  levels,  recovery
methods, transportation and processing costs, location and date of discovery.

In addition  to  government  royalties,  the Company is subject to federal and
provincial income taxes in Canada at a combined rate of approximately 38.1 per
cent after allowable deductions.

UNITED KINGDOM

Under  existing  law, the UK  Government  has broad  authority to regulate the
petroleum industry, including 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.  Approvals  granted on or after March 16,
1993 are exempted from PRT and government royalties.  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 deductible for CT purposes. The CT rate,
which  became  effective  April 1, 1999,  was set at 30 per cent.  In its 2002
budget  speech  by  the UK  Chancellor  of the  Exchequer,  the UK  Government
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.  In  December  2005,  the UK
Chancellor of the Exchequer announced an increase to the Supplementary CT from
10 per cent to 20 per cent, effective January 1, 2006.

OFFSHORE WEST AFRICA

Terms of licences,  including  royalties  and taxes  payable on  production or
profit sharing arrangements, vary by country and, in some cases, by concession
within each country.  Development  of the Espoir field on CI-26 and the Baobab
Field on CI-40, in 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").

In October 2005,  Canadian Natural  completed the acquisition of the permit to
develop the Olowi Field,  offshore  Gabon.  Development of this field 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.


                                 RISK FACTORS

VOLATILITY OF CRUDE OIL AND NATURAL GAS PRICES

The Company's  financial  condition is 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 the
Company's  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.
Crude 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

<PAGE>
                                      13


and Asian economies, government regulation,  political stability in the Middle
East and  elsewhere,  the  foreign  supply of crude oil,  the price of foreign
imports,  the  availability of alternate fuel sources and weather  conditions.
Natural gas prices  realized by the Company are  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  GAAP. If crude oil and natural gas prices
decline,  the  carrying  value of the  assets  could be  subject  to  downward
revisions, and net earnings could be adversely affected.

Approximately  27 percent of the Company's 2005  production on a boe basis was
primary and thermal  heavy  crude oil.  The market  prices for heavy crude oil
differ from the  established  market  indices  for light and medium  grades of
crude oil, due  principally  to the higher  transportation  and refining costs
associated  with heavy crude oil. As a result,  the price  received  for heavy
crude oil is  generally  lower than the price for medium and light  crude oil,
and the production  costs  associated  with heavy crude oil may be higher than
for lighter grades. Future differentials are uncertain and any increase in the
heavy  crude oil  differentials  could have a material  adverse  effect on the
Company's business.

ENVIRONMENTAL RISKS

All  phases  of the  crude  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>
                                      14


NEED TO REPLACE RESERVES

Canadian  Natural's  future crude 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 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 crude 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 crude 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 crude oil and natural gas  interests and the
transportation  and marketing of crude oil, natural gas, NGLs 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  relate  to  operational  risks,  the  cost of  capital
available to fund exploration and development programs, fluctuation in foreign
exchange rates,  the  availability of skilled labour and manpower,  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>
                                      15


Canadian  Natural's  private ownership of crude oil and natural gas properties
in Canada differs distinctly from its ownership interests in foreign crude 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 crude 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 crude oil, NGL and natural gas reserves
and the future net cash flow there from 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 crude oil, NGL 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 there
from,  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>
                                      16


                             ENVIRONMENTAL MATTERS

The  Company  carries  out its  activities  in  compliance  with all  relevant
regional,  national and  international  regulations  and  industry  standards.
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 by changes in applicable legislation.  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 its 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  ("GHG")  reduction;  and  flaring  and venting
reduction.  Canadian  Natural  participates  in both the Canadian  federal and
provincial regulated GHG emissions reporting for facilities with GHG emissions
greater  than 100  thousand  tonnes of CO2  equivalent  per year.  The Company
continues to quantify  annual GHG emissions for internal  reporting  purposes.
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  to help us achieve  our
overall goal of a net reduction of GHG emissions per unit of production.

The costs incurred by the Company for compliance  with  environmental  matters
and site restoration amounted 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, 2005, 2004 and 2003.


                          DESCRIPTION OF THE BUSINESS

Canadian Natural is a Canadian based senior independent energy company engaged
in the acquisition,  exploration,  development, production, marketing and sale
of  crude  oil,  NGLs,  natural  gas and  bitumen  production.  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  Canadian  Natural  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 presence in
existing core regions.

<PAGE>
                                      17


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 43 per cent of 2005 production.
Virtually all of the Company's  natural gas and NGLs  production is located in
the  Canadian  provinces  of Alberta and British  Columbia  and is marketed in
Canada and the United States.  Light crude oil and NGLs,  representing  26 per
cent of 2005 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 crude
oil operations in the Provinces of Alberta and Saskatchewan account for 27 per
cent of 2005 production.  Other heavy crude oil, which accounts for 4 per cent
of 2005  production,  is produced from the Pelican Lake area in north Alberta.
This  production,  which has  medium  crude oil  netback  characteristics,  is
developed through a staged horizontal  drilling program  complimented by water
flooding.  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.  Canadian  Natural
expects its ownership of crude oil sands leases near Fort McMurray, Alberta to
provide a basis for long-term synthetic crude oil production growth. The first
three phases of the Horizon Project, which encompasses only a portion of these
oil sands  leases is expected to deliver  approximately  37 years of synthetic
crude oil production.

As a result of the Company's  core  undeveloped  land base of 10.9 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>
                                      18


A.   PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES

Set forth below is a summary of the principal  crude oil,  natural gas and oil
sands properties as at December 31, 2005. The information reflects the working
interests owned by the Company.

<TABLE>
<CAPTION>
                                                      YEAR ENDED
                            2005 AVERAGE DAILY       DECEMBER 31,               MAJOR INFRASTRUCTURE
                             PRODUCTION RATES            2005                 AS AT DECEMBER 31, 2005
                           ---------------------   -----------------       ----------------------------

                               CRUDE                                                  BATTERIES/
                               OIL &    NATURAL       UNDEVELOPED               COMPRESSORS & PLANTS/
                                NGLs        GAS         ACREAGE                       PLATFORMS
        REGION                  mbbl       mmcf       (thousands)                       /FPSO

<S>                           <C>       <C>           <C>                       <C>
NORTH AMERICA

Northeast B. C.                  6.7      434.4           2,027                        1/9/-/-

Northwest Alberta               13.5      403.4           1,507                        -/8/-/-

Northern Plains                181.8      419.2           6,594                       12/6/-/-

Southern Plains                 10.7      155.4             621                       -/2/-/-

Southeast Saskatchewan           8.8        3.1              82                       -/-/-/-

Non - core regions               0.2        0.8             236                       -/-/-/-

Horizon Oil Sands                  -          -             115                       -/-/-/-


INTERNATIONAL

North Sea UK Sector             68.6       18.4             352                       -/-/6/1

Offshore West Africa

     Cote d'Ivoire              22.9        4.1             274                       -/-/0/2

     Gabon                         -          -             152                       -/-/-/-

Non - core regions

     South Africa                  -                      4,002                       -/-/-/-

-------------------------------------------------------------------------------------------------------
TOTAL                          313.2     1438.8          15,963                      13/25/6/3
-------------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>
                                      19


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, 2005 by geographic region:

<TABLE>
<CAPTION>
                                                                         2005
-------------------------------------------------------------------------------------------------------------------------
                                              NET EXPLORATORY                              NET DEVELOPMENT
                                 PRODUCTIVE      DRY HOLES        TOTAL         PRODUCTIVE      DRY HOLES        TOTAL
-------------------------------------------------------------------------------------------------------------------------
<S>                              <C>             <C>            <C>             <C>             <C>           <C>
CANADA
                                       32.1            7.2         39.3              179.9           21.1         201.0
  Northeast B. C.
                                       29.9            9.0         38.9              135.2            7.3         142.5
  Northwest Alberta
                                       63.5           11.5         75.0              671.4           51.9         723.3
  Northern Plains
                                       50.6            5.0         55.6              294.9            2.0         296.9
  Southern Plains
                                        1.0              -          1.0               43.0              -          43.0
  Southeast Saskatchewan
                                          -              -           -                 0.3              -           0.3
  Non - core regions

NORTH SEA UK SECTOR                       -            0.8          0.8               11.5            0.9          12.4

OFFSHORE WEST AFRICA

  Cote d'Ivoire                           -            0.6          0.6                3.5              -           3.5
-------------------------------------------------------------------------------------------------------------------------
TOTAL                                 177.1           34.1        211.2             1339.7           83.2        1422.9
-------------------------------------------------------------------------------------------------------------------------

<CAPTION>
                                                                         2004
-------------------------------------------------------------------------------------------------------------------------
                                              NET EXPLORATORY                              NET DEVELOPMENT
                                 PRODUCTIVE      DRY HOLES        TOTAL         PRODUCTIVE      DRY HOLES        TOTAL
-------------------------------------------------------------------------------------------------------------------------
<S>                              <C>             <C>            <C>             <C>             <C>           <C>
CANADA
                                       23.8            6.2        30.0               146.8           14.4         161.2
  Northeast B. C.
                                       42.8            7.6        50.4               100.4            3.9         104.3
  Northwest Alberta
                                      116.6           26.6       143.2               333.8           23.2         357.0
  Northern Plains
                                       18.5            7.0        25.5               209.9            4.0         213.9
  Southern Plains
                                          -              -           -                12.5              -          12.5
  Southeast Saskatchewan
                                          -              -           -                 0.5            0.3           0.8
  Non - core regions

NORTH SEA UK SECTOR                       -            2.0         2.0                 9.2              -           9.2

OFFSHORE WEST AFRICA

  Cote d'Ivoire                           -            0.7         0.7                 2.3              -           2.3
-------------------------------------------------------------------------------------------------------------------------
TOTAL                                 201.7           50.1       251.8               815.4           45.8         861.2
-------------------------------------------------------------------------------------------------------------------------

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

NORTH SEA UK SECTOR                       -            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>

<PAGE>
                                      20


PRODUCING CRUDE 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, 2005:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
                                  NATURAL GAS WELLS              CRUDE OIL WELLS                  TOTAL WELLS
                                GROSS            NET           GROSS           NET           GROSS            NET
-----------------------------------------------------------------------------------------------------------------------
<S>                             <C>             <C>            <C>           <C>             <C>           <C>
CANADA

  Northeast B. C.                   1,177           983.7            278          204.4           1,455        1,188.1

  Northwest Alberta                 1,196           948.7            195          140.1           1,391        1,088.8

  Northern Plains                   3,502         2,923.7          5,799        5,291.9           9,301        8,215.6

  Southern Plains                   4,260         3,698.5          1,026          922.0           5,286        4,620.5

  Southeast Saskatchewan                -               -          1,092          768.0           1,092          768.0

  Non - core regions                  837           334.3          1,483          470.0           2,320          804.3

UNITED STATES                           4             0.5              2            0.2               6            0.7

NORTH SEA UK SECTOR                     4             0.3            118           98.4             122           98.7

OFFSHORE WEST AFRICA

  Cote d'Ivoire                         -               -             15            8.7              15            8.7
-----------------------------------------------------------------------------------------------------------------------
TOTAL                              10,980         8,889.7         10,008        7,903.7          20,988       16,793.4
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

All reserves data in the following  property report is based on the applicable
independent  engineering  report. See below  "Conventional  Crude Oil, NGL and
Natural Gas Reserves" and "Oil Sands Mining Disclosure".

NORTHEAST BRITISH COLUMBIA


                               [GRAPHIC OMITTED]


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,
NGLs and natural gas. The Company  holds working  interests  ranging up to 100
per cent and averaging 77 per cent in 3,776,051 gross (2,895,451 net) acres of
producing and undeveloped land in the region.

<PAGE>
                                      21


Crude oil  reserves  are  found  primarily  in the  Halfway  or lower  Halfway
formation,  while natural gas and associated  NGLs 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  434.4  mmcf/d in 2005  compared  to the average of 437.3
mmcf/d in 2004.  Crude oil and NGLs  production  was steady at to 6.7 thousand
bbl/d in 2005 from an average of 6.8 thousand bbl/d in 2004.

During 2005, 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 generally 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 2005, the Company  drilled 10.9 (2004- 3.6) net crude oil wells,  201.1
(2004  -   167.0)   net   natural   gas   wells,   1.0   (2004   -  1.0)   net
stratigraphic/service  wells and 28.3 (2004 - 20.6) net dry wells on its lands
in this region for a total of 241.3 (2004 - 192.2) net wells. The Company held
an average 85.6 per cent working interest in these wells.

NORTHWEST ALBERTA


                               [GRAPHIC OMITTED]


The Company holds working  interests  ranging up to 100 per cent and averaging
76 per  cent in  2,809,179  gross  (2,128,874  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  meters.  The northern  portion of this core

<PAGE>
                                      22


region provides extensive multi-zone  Cretaceous  opportunities similar to the
geology of the Company's  Northern  Plains 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 403.4 mmcf/d in 2005 compared
to an  average  of 303.2  mmcf/d in 2004.  Crude oil and NGLs  production  was
steady at 13.5 thousand bbl/d in 2005 from 10.9 thousand bbl/d in 2004.

During 2005, the Company  drilled 12.9  (2004-5.8) net crude oil wells,  152.4
(2004-137.5) net natural gas wells, 0.7 (2004 - 1.5) net stratigraphic/service
wells,  and 16.3  (2004-11.5)  net dry wells on its lands in this region for a
total of 182.3  (2004-156.3)  net wells.  The Company held an average 82.1 per
cent working interest in these wells.

NORTHERN PLAINS


                               [GRAPHIC OMITTED]


The Company holds working  interests  ranging up to 100 per cent and averaging
84 per  cent in  11,608,488  gross  (9,806,002  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,  NGLs and light  crude oil are also
encountered at slightly greater 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 419.2 mmcf/d in 2005 compared to 429.9 mmcf/d in
2004.  Crude oil and NGLs  production  from  this  region  increased  to 181.8
thousand  bbl/d in 2005  from  166.3  thousand  bbl/d in 2004.  Production  of
natural gas was negatively  impacted by the shut-in  effective July 1, 2004 of
approximately  11 mmcf/d in the  Athabasca  Wabiskaw-McMurray  oil sands  area
pursuant to the decision of the Alberta Energy and Utilities Board.

In February 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.

<PAGE>
                                      23


Natural gas in this  region is produced  from  shallow,  low-risk,  multi-zone
prospects  and  more  recently  from the  Horseshoe  Canyon  coal bed  methane
("CBM").   The  Company   targets   low-risk   exploration   and   development
opportunities and plans to expand its commercial CBM project. During 2005, CBM
development drilling included 42 net wells and the Company has an inventory of
over 500 net Horseshoe Canyon CBM locations.

In the area near Lloydminster, Alberta, reserves of heavy crude oil (averaging
12(Degree)-14(degree)  API) and natural gas are produced through  conventional
vertical, slant and horizontal well bores from a number of productive horizons
up to 1,000  meters deep.  The energy  required to flow the heavy crude oil to
the  wellbore in this type of heavy crude 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  crude 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 crude 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 contiguous to the Company's holdings.  With
the  operations  combined  in 2000,  development  in the  region  became  more
effective  and  provided  opportunities  for  cost  savings.  As  part  of the
acquisition of Ranger, the Company also acquired a 50 per cent interest in the
ECHO Pipeline system, a crude oil  transportation  pipeline;  and, in 2001 the
Company acquired the remaining 50 per cent. The pipeline was extended north to
the Company operated Beartrap field during 2001, enhancing further development
of the Company's  extensive holdings in the area. This pipeline was capable of
transporting 57 thousand bbl/d of hot, unblended crude oil to sales facilities
at Hardisty,  Alberta and in 2003 its capacity was expanded to handle up to 72
thousand  bbl/d.  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.
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.  The  ECHO  Pipeline  system  permits  the  Company  to  transport
approximately 80 per cent of its heavy crude oil to the international mainline
liquids pipelines.

Production  from the 100% owned  Primrose  and Wolf Lake Fields  located  near
Bonnyville,  Alberta  involves  processes  that utilize  steam to increase the
recovery  of the crude 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 thereby  improving  its flow  characteristics.  There is
also an  infrastructure  of  gathering  systems,  a  processing  plant  with a
capacity  of 80  thousand  bbl/d of crude oil 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 apply

<PAGE>
                                      24


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 was
effectively completed in 2005 with total capital expenditures of approximately
$300 million  incurred.  The Primrose North  expansion  entails a remote steam
treating  facility  and  additional  high  pressure  wells.  First  crude  oil
production from the expansion  project began in January 2006. Also in 2004 the
Company  filed a public  disclosure  document for  regulatory  approval of its
Primrose East  project,  a new facility  located about 15 kilometers  from its
existing  Primrose  South  steam  plant and 25  kilometers  from its Wolf Lake
central processing facility. The development  application was submitted to the
Alberta Energy and Utilities  Board in January 2006,  with  potential  impacts
associated   with  the  use  of  bitumen  as  fuel  being   evaluated  in  the
Environmental Impact Assessment.  The Company expects construction to begin in
2007,  with the first  steam  scheduled  for  January  2009.  A 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 holdings at Pelican Lake;  generally having a 100
per cent  ownership  rate by the  Company.  These  lands  contain  reserves of
12(Degree)-17(Degree)  API heavy crude oil. Operating costs are low due to the
absence of sand  production  and 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  ("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 was slow. Due to the slow response
time,  the  Company  reverted  to a  waterflood  scheme  for this  field.  The
waterflood  provided  initial  production  increases as expected and has shown
positive waterflood response.  To enhance the waterflood scheme, in the second
quarter of 2005,  the Company  installed  facilities for a polymer flood pilot
test.  Initial  behaviour of the polymer  flood pilot test has been  positive,
however definitive  conclusions  regarding the feasibility of the program will
not be known  until  late 2006 or early  2007.  In  advance  of the pilot test
results,  preparations for commercial  polymer flood have commenced  including
source water  development  and advance  ordering of some of the long lead time
equipment.

During  2005,  the Company  drilled  536.1 (2004 - 287.0) net crude oil wells,
198.9  (2004 -  163.4)  net  natural  gas  wells,  108.9  (2004 -  112.0)  net
stratigraphic/service  wells, and 63.4 (2004 - 49.8) net dry wells for a total
of 907.3 (2004 - 612.2) net wells.  The Company's  average working interest in
these wells was 91.7 per cent.

<PAGE>
                                      25


SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN


                               [GRAPHIC OMITTED]


In the Southern Plains area, the Company holds interests ranging up to 100 per
cent and  averaging 83 per cent in 2,037,923  gross  (1,699,254  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
higher than average  return on capital  employed  with low drilling  costs and
longer life reserves.

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

The Company's  share of  production in the Southern  Plains area averaged 10.7
thousand  bbl/d of crude oil and NGLs compared to 12.7 thousand bbl/d in 2005.
Natural gas production  amounted to 155.4 mmcf/d in 2005 compared to the 155.5
mmcf/d averaged in 2004.

During  2005,  the  Company  drilled a total of 9.0 (2004 - 7.8) net crude oil
wells,  336.5  (2004 - 220.6)  net  natural  gas  wells,  1.7 (2004 - 1.0) net
stratigraphic/service  well and 7.0 (2004 - 11.0) net dry wells in this region
for a total of 354.2 (2004 - 240.4) net wells.  The Company's  average working
interest in these wells was 81.0 per cent.

The Williston Basin is located in Southeast  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.

<PAGE>
                                      26


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 8.8 thousand bbl/d of
crude oil and NGLs in 2005 compared to 9.3 thousand bbl/d in 2004. Natural gas
production was steady averaging 3.1 mmcf/d in both 2005 and 2004.

The Company  drilled 43.0 (2004 - 12.5) net crude oil wells,  1.0 (2004 - 0.0)
net gas well, 7.6 (2004 - 0.0) net stratigraphic/service wells and 0.0 (2004 -
0.0) net dry wells in this  region in 2005,  for a total of 51.6 (2004 - 12.5)
net wells.  The Company's  average working interest in these wells is 83.2 per
cent.

HORIZON OIL SANDS PROJECT


                               [GRAPHIC OMITTED]


Canadian  Natural owns a 100 per cent working  interest in its  Athabasca  Oil
Sands  leases in  Northern  Alberta,  of which a portion  (being  lease 18) is
subject to a 5 per cent net carried interest in the bitumen  development.  The
Horizon Oil Sands  Project  ("Horizon  Project")  is located on these  leases,
about 70 kilometers  north of Fort McMurray.  The project includes surface oil
sands mining, bitumen extraction, bitumen upgrading to produce a 34 o -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 2011 or 2012. Phase 1 production is targeted to begin in
the second half of 2008 at 110 thousand bbl/d of SCO. Current plans have Phase
2  increasing  production  to 155  thousand  bbl/d of SCO in 2010 and  Phase 3
further  increasing  production  to 232 thousand  bbl/d of SCO in 2012.  These
targeted rates of production represent nominal design capacity. The Company is
currently  evaluating  the  opportunity  to combine  Phase 2 and Phase 3 for a
joint  operational  date of  2011.  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 may mitigate
any negative effects of growth on local infrastructure.

Using a cost  environment  associated  with a US $45 WTI price  per  barrel of
crude  oil,  total  estimated  capital   construction   costs  of  the  phased
development are $10.8 billion, of which approximately $6.8 billion,  including

<PAGE>
                                      27


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 $15 per  barrel  (based  upon a
natural gas price input of US$ 5.83/mcf).

Canadian  Natural filed an application for regulatory  approval of the Horizon
Project in June 2002. The application  included a comprehensive  environmental
impact assessment and a social and economic  assessment and was accompanied by
public consultation.  A federal-provincial  regulatory Joint Review Panel (the
"Panel") examined the project in a public hearing in September 2003. The Panel
issued its decision  report in January 2004,  finding that the Horizon Project
is in the public interest. 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 developed in the context of Canada's
negotiations  for a  second  Kyoto  implementation  phase.  In  mid  2003  the
Government of Canada acknowledged the need for greater clarity and established
eight  principles  that will  guide the  Government  of  Canada's  longer-term
climate  change  policies.  These eight guiding  principles  addressed the key
concerns  of  Canadian   Natural  with  regard  to   equability,   efficiency,
flexibility and competitiveness issues for the post-2012 period.

Canadian  Natural 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  for  Phase  1,
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  Project.  The third phase of FEL for
Phase 2 is expected to be completed in the first quarter of 2007.

The Horizon Project 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 2005,  Canadian
Natural's  Horizon Project team,  consisted of 521 permanent  employees.  This
represents a total of 67 per cent of the 773 staff positions  required by year
end 2006. Of the 252 outstanding  positions,  110 are filled by contractors on
an  interim  basis  for  total of 82 per cent of our  2006  year end  position
requirements.

Horizon Project costs were  approximately  $1.5 billion in 2005 and cumulative
expenditures  were  approximately  $2.2 billion through the end of 2005. These
expenditures  include capitalized  interest,  stock based compensation,  lease

<PAGE>
                                      28


evaluation, engineering definition, technology acquisition, completion of road
infrastructure to the site, initial camp construction,  detailed  engineering,
significant site development and initial foundation construction. Construction
costs for 2006 are budgeted to be approximately  $2.6 billion reflecting major
expenditures for detailed engineering, procurement and construction of Phase 1
of the Project. In addition, capital expenditures of $128 million are budgeted
for Phase 2 EDS development in 2006.

During 2005, the Company drilled 126 (2004 - 218)  stratigraphic test wells to
further delineate the ore body and confirm resource quality and quantity.

UNITED KINGDOM NORTH SEA


             [GRAPHIC OMITTED]               [GRAPHIC OMITTED]



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  595,051  gross   (444,314  net)  acres  of  producing  and
non-producing  properties  in the UK  sector of the North  Sea.  In 2005,  the
Company produced from 16 crude oil fields.

The  northerly  fields are centered  around the Ninian Field where the Company
has an 87.1 per cent  working  interest.  The central  processing  facility is
connected  to other  fields  including  the Columba  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 its 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.  The
Company also owns a 45.7 per cent operated working interest in the Kyle Field.
Beginning in the third quarter of 2005,  all production for the Kyle Field was
processed  through  the Banff  FPSO  facilities.  The  consolidation  of these
production  facilities is expected to result in lower combined operating costs
from these fields.

<PAGE>
                                      29


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.

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 by the existing processing facilities.

During 2005, production to the Company from this region averaged 68.6 thousand
bbl/d of  crude  oil,  up from  64.7  thousand  bbl/d  in  2004.  Natural  gas
production  averaged  18.4  mmcf/d  in 2005,  down  from  50.4  mmcf/d in 2004
primarily due to the  re-injection  of associated  natural gas production into
the Banff Field for improved crude oil recovery.

The Company  drilled  11.5 (2004 - 9.2) net crude oil wells,  0.9 (2004 - 2.7)
net stratigraphic/service  wells and 1.7 (2004 - 2.0) net dry wells in 2004 in
this region for a total of 14.1 (2004 - 13.9) net wells. The Company's average
working interest in these wells is 88.0 per cent.

OFFSHORE WEST AFRICA


                               [GRAPHIC OMITTED]


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  1,596,013  gross  (887,657  net) acres in
those countries.  Since 2000, the Company has either  relinquished or sold all
of its interests in offshore Angola.

In 2005, the Company acquired the permit to develop the Olowi Field,  offshore
Gabon, West Africa, consisting of 151,818 acres. The Company has a 90 per cent
interest in a production sharing agreement for the block.

The Company also has a 100 per cent interest in 4,001,574 acres offshore South
Africa  where it is  shooting  and  evaluating  seismic  data and  undertaking
environmental studies.


<PAGE>
                                      30


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 58.7 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. The
construction and installation of a new wellhead tower for the West Espoir part
of the field were completed in 2005. An infill drilling program in East Espoir
was commenced in 2005 and following its completion  development  drilling will
commence at West Espoir.

Crude oil from the East Espoir Field is produced into an FPSO with  associated
natural  gas  delivered  onshore  through a subsea  pipeline  for local  power
generation.  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.

The unsuccessful Zaizou exploration well was drilled in block CI-40 in 2005.

In the first  quarter  of 2001,  the  Company  drilled  and  tested the Baobab
exploration prospect, identified on Block CI-40, eight kilometers south of the
Espoir facilities,  in which the Company has a 58 per cent interest.  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 first oil was  achieved  in August  2005  producing  at  approximately  30
thousand  bbl/d net to  Canadian  Natural  from 4 wells.  Upon  completion  of
drilling additional wells in 2006,  production levels are expected to increase
another 5  thousand  bbl/d net to the  Company.  In East  Espoir,  two of four
infill wells were completed in 2005 increasing  production by 3 thousand bbl/d
in the second  quarter of 2005. The remaining two infill wells are expected to
be  completed  in 2006.  Construction  of the West Espoir  drilling  tower was
completed and installed to  facilitate  development  drilling of the reservoir
and it is expected that production will commence in 2006.

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 a nearby  country if the situation  warrants such a
move.

During 2005,  Company  production  averaged 22.9  thousand  bbl/d of crude oil
compared  to 11.6  thousand  bbl/d in 2004.  Company  natural  gas  production
amounted to 4.2 mmcf/d in 2005 compared to 7.5 mmcf/d in 2004.

In 2005, the Company drilled 3.5 (2004 - 2.3) net crude oil wells, 1.1 (2004 -
0.0) net stratigraphic/service  wells and 0.6 (2004 - 0.7) net dry wells for a
total of 5.2 (2004 - 3.0) net wells. The Company's average working interest in
these wells is 58.2 per cent.

<PAGE>
                                      31


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  data 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 data and the well results during 2004
and even though  additional  review of seismic and geological data on Block 16
indicates  that  significant  upside  remains a  possibility,  the risk  level
associated  with Block 16 is outside the normal  operating  parameters  of the
Company.  As a result, the Company entered into an agreement to dispose of its
interest in Block 16 effective  December 31, 2005. As of the sale of Block 16,
the Company no longer has any holdings in Angola.

GABON


                               [GRAPHIC OMITTED]


The Company  acquired permit (No.  G4-187)  comprising a 90 per cent operating
interest in the  production  sharing  agreement for the block  containing  the
Olowi Field,  located  about 20 kilometers  from the Gabonese  coast and in 30
meters water depth.  Olowi has been  delineated by the drilling of 15 wells on
the block and is estimated to potentially contain up to 500 million barrels of
34(0) API  light  crude  original  oil in place.  The crude oil  reservoir  is
overlain by a large gas cap with  potentially  up to 1 trillion  cubic feet of
original  gas in  place.  A  development  plan,  comprising  an FPSO  and four
drilling  towers,  was filed  with the  Gabonese  Government  in late 2005 and
approved in February  2006.  The  development  of the crude oil reserves  will
commence in late 2006 with first  production  targeted for late 2008 at a rate
of 20 thousand bbl/d.


<PAGE>
                                      32


B.    CONVENTIONAL CRUDE OIL, NGL, AND NATURAL GAS RESERVES

For the year ended  December 31, 2005,  Canadian  Natural  retained  qualified
independent  reserve  evaluators,  Sproule Associates Limited  ("Sproule") and
Ryder  Scott  Company  ("Ryder  Scott"),  to  evaluate  100% of the  Company's
conventional  proved and probable  crude oil, NGL and natural gas reserves and
prepare Evaluation Reports on these reserves.  Sproule evaluated the Company's
North America  conventional assets and Ryder Scott evaluated its international
conventional  assets.  The  Company  has been  granted an  exemption  from the
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.  There are two  principal  differences
between the two standards.  The first is the additional  requirement  under NI
51-101 to disclose both proved,  proved and probable reserves,  as well as the
related net present  value of future net revenues  using  forecast  prices and
costs.  The  second is in the  definition  of  proved  reserves;  however,  as
discussed in the  Canadian  Oil and Gas  Evaluation  Handbook  ("COGEH"),  the
standards that NI 51-101 employs,  the difference in estimated proved reserves
based on constant pricing and costs between the two standards is not material.

The Company has disclosed  proved  conventional  reserves and the Standardized
Measure of discounted future net cash flows using constant prices and costs as
mandated by the SEC in the supplemental oil and gas information section of its
annual  report.  The Company has also elected to provide the net present value
of these same conventional  proved reserves as well as the conventional proved
and probable  reserves and the net present value of these  reserves  under the
same  parameters  as  additional  voluntary  information.  In  addition to the
constant price and cost scenario, the Company has also elected to provide both
conventional proved and conventional proved and probable reserves,  as well as
the net present value of these  reserves,  using forecast  prices and costs as
voluntary additional information.

Reserves and net present values of these reserves 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.

The Reserves  Committee of the  Company's  Board of Directors has met with and
carried out  independent  due  diligence  procedures  with each of Sproule and
Ryder  Scott to  review  the  qualifications  of and  procedures  used by each
evaluator in  determining  the estimate of the  Company's  quantities  and net
present  value of  remaining  conventional  crude  oil,  NGL and  natural  gas
reserves.

The following  tables  summarize the evaluations of conventional  reserves and
estimated net present values of these reserves at December 31, 2005.

THE ESTIMATED NET PRESENT VALUES OF RESERVES 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.  ONLY FUTURE  DEVELOPMENT  COSTS AND
ASSOCIATED FUTURE MATERIAL WELL ABANDONMENT LIABILITIES HAVE BEEN APPLIED WITH
THE   EXCEPTION  OF  OFFSHORE  WEST  AFRICA  WHERE  ALL  EXISTING  AND  FUTURE
ABANDONMENT  LIABILITIES  HAVE  BEEN  INCLUDED.  NO  INDIRECT  COSTS  SUCH  AS
OVERHEAD,  INTEREST AND  ADMINISTRATIVE  EXPENSES  HAVE BEEN DEDUCTED FROM THE

<PAGE>
                                      33


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.

<TABLE>
<CAPTION>
NET CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES (NET OF ROYALTIES)

                                                               Constant Prices and Costs
                                      ----------------------------------------------------------------------------

                                            Crude Oil & NGLs (mmbbl)                   Natural Gas (bcf)

                                           Total             Total                 Total             Total
                                          Proved      Proved and Probable          Proved     Proved and Probable
                                         Reserves           Reserves              Reserves         Reserves
                                      -------------------------------------    -----------------------------------
<S>                                      <C>                <C>                   <C>              <C>
NORTH AMERICA

Canada                                           694                1,035              2,739               3,546

United States                                      -                    -                  2                   2

INTERNATIONAL

United Kingdom                                   290                  417                 29                  69

Cote d'Ivoire                                    119                  189                 72                 110

Gabon                                             15                   17                  -                   -
                                      -------------------------------------    -----------------------------------
TOTAL                                          1,118                1,658              2,842               3,727
                                      =====================================    ===================================


<CAPTION>
CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES

                                                              Constant Prices and Costs
                                      ---------------------------------------------------------------------------
                                            Crude Oil & NGLs (mmbbl)                    Natural Gas (Bcf)

                                         Company Gross             Net           Company Gross            Net
                                      -------------------------------------   -----------------------------------
<S>                                      <C>                  <C>                <C>                <C>
Proved developed reserves                          762                696                2,871            2,326

Proved undeveloped reserves                        461                422                  619              516
                                      -------------------------------------   -----------------------------------

TOTAL PROVED RESERVES                            1,223              1,118                3,490            2,842

TOTAL PROVED AND PROBABLE
RESERVES                                         1,801              1,658                4,568            3,727
                                      =====================================   ===================================


<CAPTION>
ESTIMATED NET PRESENT VALUES

         ($ millions)                                         Constant Prices and Costs
                                      --------------------------------------------------------------------------

                                          Undiscounted                             Discounted at

                                                                           10%             15%           20%
                                      --------------------       -----------------------------------------------
<S>                                       <C>                       <C>               <C>           <C>
Proved developed reserves                          37,183                 24,275         20,939         18,514

Proved undeveloped reserves                        12,035                  6,342          4,881          3,843
                                      --------------------       ----------------    -----------     -----------

TOTAL PROVED RESERVES                              49,218                 30,617         25,820         22,357

TOTAL PROVED AND PROBABLE RESERVES                 68,543                 38,682         31,642         26,764
                                      ====================       ================    ===========     ===========
</TABLE>

<PAGE>
                                      34


<TABLE>
<CAPTION>
CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES

                                                              Forecast Prices and Costs
                                      ---------------------------------------------------------------------------
                                            Crude Oil & NGLs (mmbbl)                  Natural Gas (bcf)

                                        Company Gross          Net              Company Gross         Net
                                      -------------------------------------   -----------------------------------
<S>                                     <C>                 <C>                 <C>               <C>
Proved developed reserves                         752                685                2,814            2,276

Proved undeveloped reserves                       462                421                  617              517

TOTAL PROVED RESERVES                           1,214              1,106                3,431            2,793

TOTAL PROVED AND PROBABLE RESERVES              1,792              1,642                4,485            3,657


<CAPTION>
ESTIMATED NET PRESENT VALUES

         ($ millions)                                         Forecast Prices and Costs
                                      ---------------------------------------------------------------------------

                                          Undiscounted                             Discounted at

                                                                           10%             15%           20%
                                      --------------------       -----------------------------------------------
<S>                                       <C>                       <C>               <C>           <C>
Proved developed reserves                          31,154                 22,175          19,662        17,774

Proved undeveloped reserves                        10,543                  5,501           4,232         3,338

TOTAL PROVED RESERVES                              41,697                 27,676          23,894        21,112

TOTAL PROVED AND PROBABLE RESERVES                 57,892                 34,446          28,800        24,849
                                      ====================       ===============================================
</TABLE>


                                     NOTES

1.    "Company  Gross"  reserves  means the total  working  interest  share of
      remaining recoverable reserves owned by the Company before consideration
      of royalties.

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 net present values using forecast prices and costs as well as
      before royalties as additional voluntary information.

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

<PAGE>
                                      35


9.    The  constant  price  and cost  case  assumes  that  prices in effect at
      year-end  2005  adjusted for quality and  transportation  as well as the
      2005 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 been
      held constant at the 2006 values shown below. 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   Edmonton      North
                  Average    Henry Hub               Huntingdon/      Average        WTI@      Heavy 12        Par        Sea
                    Price    Louisiana        AECO        Sumas         Price   Cushing(i)  (degree)API        (ii)     Brent
          YEAR     C$/MCF    US$/MMBTU    C$/MMBTU     C$/MMBTU        C$/BBL     US$/BBL        C$/BBL     C$/BBL    US$/BBL
          ----     ------    ---------    --------     --------        ------     -------        ------     ------    -------
<S>                 <C>       <C>            <C>         <C>           <C>         <C>            <C>        <C>       <C>
          2006      9.45      10.08          9.99        9.53          46.12       61.04          32.64      68.12     58.21
</TABLE>

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

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

                (iii)  Foreign exchange rate used was US$0.8598/C$1.00

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,  NGLs and  natural  gas price  forecasts  were  based on  Sproule's
      December  31, 2005 crude oil,  NGLs and natural gas pricing  model.  The
      Company's  weighted  average  crude oil and NGLs price and the  weighted
      average  natural  gas price in 2005 were $46.86 per barrel and $8.57 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   Edmonton      North
                  Average    Henry Hub               Huntingdon/      Average        WTI@      Heavy 12        Par        Sea
                    Price    Louisiana        AECO        Sumas         Price   Cushing(i)  (degree)API        (ii)     Brent
          YEAR     C$/MCF    US$/MMBTU    C$/MMBTU     C$/MMBTU        C$/BBL     US$/BBL        C$/BBL     C$/BBL    US$/BBL
          ----     ------    ---------    --------     --------        ------     -------        ------     ------    -------
<S>                <C>       <C>          <C>          <C>            <C>        <C>           <C>         <C>        <C>
          2006     11.07       11.59        11.58         11.34         48.30       60.81         37.07     70.07       58.81

          2007     10.33       10.11        10.84         10.70         49.59       61.61         37.29     70.99       59.58

          2008      8.43        8.50         8.95          8.81         45.31       54.60         34.23     62.73       52.54

          2009      7.35        7.58         7.87          7.73         42.12       50.19         32.27     57.53       48.10

          2010      7.05        7.32         7.57          7.43         39.53       47.76         31.15     54.65       45.64

          2011      7.21        7.43         7.70          7.56         40.57       48.48         31.94     55.47       46.32

          2012      7.34        7.54         7.83          7.69         40.14       49.20         32.74     56.31       47.02

          2013      7.48        7.66         7.96          7.82         41.22       49.94         33.56     57.16       47.72

          2014      7.61        7.77         8.09          7.95         41.34       50.69         34.39     58.02       48.44

          2015      7.75        7.89         8.23          8.09         42.02       51.45         35.23     58.89       49.17

          2016      7.86        8.01         8.37          8.23         42.03       52.22         36.08     59.78       49.90
</TABLE>

                (i)    Foreign   exchange   rate  used  was   US$0.8598/C$1.00
                       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  NGLs,  less all
      capital  costs,   production  taxes,  and  operating  costs  and  before
      provision for income taxes,  administrative  overhead costs and existing
      asset abandonment liabilities with the exception of Offshore West Africa
      where existing asset liabilities were included.

<PAGE>
                                      36


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

<TABLE>
<CAPTION>
                                PROVED                                    PROVED AND PROBABLE
              ----------------------------------------------------------------------------------------------
              FORECAST PRICE CASE    CONSTANT PRICE CASE      FORECAST PRICE CASE      CONSTANT PRICE CASE
                  ($ millions)          ($ millions)              ($ millions)            ($ millions)
              ----------------------------------------------------------------------------------------------
<C>                 <C>                    <C>                     <C>                      <C>
2006                   1,433                  1,412                   1,614                    1,593
2007                     815                    774                   1,140                    1,087
2008                   1,017                    930                   1,774                    1,645
2009                     428                    373                   1,144                    1,023
2010                     315                    286                     794                      718
2011                     173                    154                     306                      273
2012                     223                    191                     362                      313
2013                     180                    102                     200                      168
2014                      87                    115                     222                      140
2015                     143                    120                     247                      249
2016                     182                    141                     220                      173
2017                     174                    136                     238                      188
Thereafter               555                    398                     773                      554
</TABLE>

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  found by  Sproule  and  Ryder  Scott to be
      reasonable and no field inspection was conducted.

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



<PAGE>
                                      37


C.    RECONCILIATION OF CHANGES IN NET CONVENTIONAL 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 & NGLs (mmbbl)                            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       2,552
                                 ------------------------------------------------------------------------------------------------
Extensions & Discoveries                 17           -           -          17          334           -           -         334
Infill Drilling                          24          35           -          59           74           -           -          74
Improved Recovery                         1          10           -          11            6           -           -           6
Property purchases                       36          38           -          74          182          10           -         192
Property disposals                        -           -           -           -          (8)           -           -         (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        2,591          27          72       2,690
                                 ------------------------------------------------------------------------------------------------
Extensions & Discoveries                 98           -           -          98          506           -           -         506
Infill Drilling                           3           3           2           8           22           -           -          22
Improved Recovery                         -           -           -           -            8           -           -           8
Property purchases                        -           -          15          15            6           -           -           6
Property disposals                       (3)          -           -          (3)         (23)          -           -         (23)
Production                              (70)        (25)         (8)       (103)        (411)         (7)         (1)       (419)
Revisions of prior estimates             18           9          10          37           42           9           1          52
                                 ------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2005             694         290         134       1,118        2,741          29          72       2,842
                                 ------------------------------------------------------------------------------------------------
PROVED AND PROBABLE RESERVES
                                 ------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2003             857         317         133       1,307        2,919         102          72       3,093
                                 ------------------------------------------------------------------------------------------------
Extensions & Discoveries                 20           -           -          20          418           -           -         418
Infill Drilling                          29          49           -          78          106           -           -         106
Improved Recovery                         2          10           -          12            6           -           -           6
Property purchases                       49          49           -          98          236          18           -         254
Property disposals                        -           -           -           -         (10)           -           -        (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        3,319          57          90       3,466
                                 ------------------------------------------------------------------------------------------------
Extensions & Discoveries                200           -           -         200          645           -           -         645
Infill Drilling                           3           5           6          14           23           -           1          24
Improved Recovery                         -           -           -           -           14           -           -          14
Property purchases                        -           -          17          17            8           -           -           8
Property disposals                       (4)          -           -          (4)         (30)          -           -         (30)
Production                              (70)        (25)         (8)       (103)        (411)         (7)         (1)       (419)
Revisions of prior estimates            (20)         22          (5)         (3)         (20)         19          20          19
                                 ------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2005           1,035         417         206       1,658        3,548          69         110       3,727
                                 ------------------------------------------------------------------------------------------------
</TABLE>

Information  on the  Company's  conventional  crude oil,  NGLs and natural gas
reserves is provided in  accordance  with United  States FAS 69,  "Disclosures
About Oil and Gas Producing  Activities"  in the Company's  2005 Annual Report
under  "Supplementary  Oil  and Gas  Information"  on  pages  97 to 101 and is
incorporated herein by reference.

<PAGE>
                                      38


D.    OIL SANDS MINING DISCLOSURE

INTRODUCTION

Canadian  Natural  holds a 100 per cent working  interest in its Athabasca Oil
Sands  leases in Northern  Alberta,  of which a portion  (being  lease 18), is
subject to a 5 per cent net carried interest in the bitumen  development.  The
Horizon Project was initiated in 2000 to evaluate the potential for mining and
processing the oil sands on these leases.

The  Horizon  Project is  located in  northeastern  Alberta  approximately  70
kilometers  north of Fort  McMurray in Townships 96 and 97,  Ranges 11, 12 and
13, west of the 4th Meridian. The project site is accessible by a private road
as well as a private  airstrip.  Figure 1 shows the  location  of the  Horizon
Project  within  Alberta,  Canada  and  within the  region.  The leases  being
developed  for  the  Horizon  Project  are 18,  25,  10,  19 and 20.  Canadian
Natural's  development  plan for the  Horizon  Project is to  produce  232,000
barrels of synthetic  crude oil per day. The project  production  schedule has
been  developed  such that  production  rates are increased over three phases.
Synthetic  crude oil  production is planned for the second half of 2008 at 110
thousand bbl/d, increasing to 232 thousand bbl/d by the third quarter of 2011.
Mining of the oil  sands  will be done  using  conventional  truck and  shovel
technology.  The ore is then processed through  extraction and froth treatment
to produce  bitumen,  which is upgraded  on-site into synthetic crude oil. The
synthetic  crude oil is transported  from the site by pipeline to the Edmonton
area for distribution.  An on-site cogeneration plant provides power and steam
for the  operation.  Preparation  for  construction  of Phase 1 of the Horizon
Project began in late 2004.  Total targeted capital costs for all three phases
of the development are projected to be  approximately  $10.8 billion at a cost
environment associated with a US $45 WTI price per barrel of crude oil.

An  independent  qualified  reserves  evaluator,   GLJ  Petroleum  Consultants
("GLJ"),  was  retained to evaluate  100 per cent of the first three phases of
the Horizon Project's development plan. GLJ's Evaluation Report indicates that
the gross proved and probable reserves associated with the Horizon Project are
2.9 billion barrels of synthetic crude oil with a production life of 37 years.

Since 1999, Canadian Natural has acquired over 46,000 hectares,  comprising 11
leases in the Fort McMurray area.



<PAGE>
                                      39


FIGURE 1 - LOCATION OF THE HORIZON OIL SANDS PROJECT



                [GRAPHIC OMITTED]               [GRAPHIC OMITTED]




TABLE 1 - CANADIAN NATURAL ATHABASCA REGION OIL SAND LEASES

<TABLE>
<CAPTION>
===========================================================================================================
       SHORT LEASE NAME           OFFICIAL LEASE NUMBER       LEASE EXPIRY DATE(1)      AREA IN HECTARES
===========================================================================================================
<S>                               <C>                         <C>                       <C>
           Lease 18                     727912T18              Continued Producing(2)           19,988
-----------------------------------------------------------------------------------------------------------
           Lease 10                     7400120010                  December 14, 2015            3,840
-----------------------------------------------------------------------------------------------------------
           Lease 25                     7401050025                       May 17, 2016            1,536
-----------------------------------------------------------------------------------------------------------
           Lease 11                     7400120011                  December 14, 2015              518
-----------------------------------------------------------------------------------------------------------
           Lease 12                     7400120012                  December 14, 2015            9,216
-----------------------------------------------------------------------------------------------------------
           Lease 13                     7400120013                  December 14, 2015               69
-----------------------------------------------------------------------------------------------------------
           Lease 15                     7400120015                  December 14, 2015            1,536
-----------------------------------------------------------------------------------------------------------
           Lease 19                     7402050019                       May 30, 2017            5,120
-----------------------------------------------------------------------------------------------------------
           Lease 20                     7402050020                       May 30, 2017              768
-----------------------------------------------------------------------------------------------------------
           Lease 6                      7597050T06                        May 6, 2012            2,584
-----------------------------------------------------------------------------------------------------------
           Lease 7                      7597050T07                        May 6, 2012            1,144
===========================================================================================================
</TABLE>

(1)  The Company can apply for an extension of the leases past the expiry
     date.
(2)  Pursuant to section 14 of the Oil Sands Tenure Regulation.


Lease 18,  the main oil sand  lease  for the  Horizon  Project,  has a gradual
topographic  slope from west to east. To the west,  the  topography  begins to
rise into the Birch Mountains and reaches an elevation of 485 meters above sea
level in the northwest  corner of the lease.  To the east, the elevation drops
sharply at the Athabasca River  escarpment to 230 meters above sea level along
the river. The Tar and Calumet Rivers flow through the lease.


<PAGE>
                                      40


PROJECT DEVELOPMENT

On June 28, 2002, Pursuant to Sections 10 and 11 of the Oil Sands Conservation
Act,  Canadian  Natural filed  Application No. 1273113 for approval for an oil
sands mine, a bitumen  extraction  plant,  a bitumen  upgrader and  associated
facilities for the proposed Horizon Project. As part of the application to the
Energy and Utilities Board, the Company also submitted an Environmental Impact
Assessment  ("EIA")  report  to  the  Director  of  the  Regulatory  Assurance
Division,  Alberta  Environment,  pursuant  to  the  Environmental  Protection
Enhancement Act ("EPEA").  On June 26, 2003, the Federal Minister of Fisheries
and Oceans  referred  the EIA of the project to a review  panel  charged  with
fulfilling  the  review  as  required  by  both  the  Canadian   Environmental
Assessment Act ("CEAA") and the Energy Resources  Conservation Act ("ERCA"). A
public hearing was held in Fort McMurray,  Alberta on September  15-19,  22-26
and 29, 2003. The  application  and hearing  provided  significant  background
detail on the geology,  mine  planning and  development  scheme and formed the
basis for the approval from the EUB in February  2004 and Alberta  Environment
("AENV")  under the  Environmental  Protection and  Enhancement  Act, in April
2004.

The following are the primary  regulatory  applications  and approvals for the
Horizon  Project,  which  contain  information  pertaining to the project of a
material engineering, geologic or metallurgic nature:

     1.   Application  for Approval of Horizon Oil Sands Project  submitted in
          June 2002 to the EUB (Application  No.1273113) and AENV (Application
          No.  001-149968)  (available  at the EUB  library,  640 5th Ave. SW,
          Calgary, Alberta - Tel: (403) 297-8311).

     2.   Supplemental   Information   for  the  Horizon  Oil  Sands   Project
          (Application No. 1273113 and Application No.  001-149968)  submitted
          in March 2003 to the EUB and AENV)  (available  at the EUB  library,
          640 5th Ave. SW, Calgary, Alberta - Tel: (403) 297-8311).

     3.   Horizon Oil Sands Project Decision  2004-005 by a joint panel review
          established  by the EUB and the  Government  of Canada dated January
          27, 2004 (available online at www.eub.gov.ab.ca).

     4.   Horizon Oil Sands Project Order in Council  Authorization 26/2004 by
          the Province of Alberta dated February 4, 2004 (available at the EUB
          library, 640 5th Ave. SW, Calgary, Alberta - Tel: (403) 297-8311).

     5.   Horizon  Oil  Sands  Project  Approval  No.  9752 by the  EUB  dated
          February 10, 2004  (available  at the EUB library,  640 5th Ave. SW,
          Calgary, Alberta - Tel: (403) 297-8311).

     6.   Horizon Oil Sands Project  Environmental  Protection and Enhancement
          Act  Approval  No.  149968-00-01  from  AENV  dated  April  6,  2004
          (available  online  at   www.gov.ab.ca/env/water/approvalviewer.html
          search parameter - Approval No. 149968-00-01).

     7.   Horizon Oil Sands Project Water Act Approval No. 00201931-00-00 from
          AENV    dated    April    6,    2004     (available     online    at
          www.gov.ab.ca/env/water/approvalviewer.html   search   parameter   -
          Approval No. 149968-00-01).

<PAGE>
                                      41


As of year-end 2005, key development achievements associated with the Horizon
Project were as follows:

     o    Phase 1 Construction is 19% complete.
     o    Mine  overburden  is at 6.7  million  bank cubic  meters of material
          removed.
     o    Coker and Extraction Separation Cell foundations are complete.
     o    Critical path underground piping is complete.

The Coker Drums and Naphtha Reactor arrived on site in January 2006

REGIONAL AND PROJECT GEOLOGY

In the area of the Horizon Project, the oil sands resource is found within the
Cretaceous  McMurray  Formation.  The  McMurray  Formation  is  comprised of a
sequence of uncemented  quartz sands and  associated  shales that reside above
the unconformity with the underlying Upper Devonian carbonates  (limestone) of
the Waterways  Formation.  The general  stratigraphy  of the Horizon Oil Sands
Project is shown in Figure 2.

The  McMurray  Formation  was  formed by the  infilling  of a broad  northwest
trending  depression  in the exposed  Devonian  limestone  landscape by mostly
non-marine and estuarine sediments about 115 million years ago. The deposition
of these terrestrial  derived sediments ended when the Boreal Sea transgressed
the entire region,  ushering in marine  conditions  that formed the Clearwater
Formation  shales and  glauconitic  Wabiskaw  member.  This interplay  between
rising  sea level  and  sediment  transport  from the  northeast  gave rise to
various depositional environments (fluvial, estuarine, and marine). The entire
McMurray/Clearwater  succession  was (most  recently  about  10,000 years ago)
covered by unconsolidated sands, silts, and clays (glacial drift) deposited by
glaciers as they melted and receded from the region at the end of the last ice
age.

The McMurray  Formation at the site of the Horizon  Project is subdivided into
three informal members:  lower,  middle,  and upper.  These informal divisions
correspond  to changes in the  depositional  environments  within the McMurray
from  predominantly   fluvial  to  tidal/estuarine   through  to  tidal/marine
conditions.  Most of the Horizon  Project's oil sands resource is found within
the lower and middle McMurray.

The lower  McMurray,  where  present,  is comprised of  predominantly  fluvial
channel deposits. The lower McMurray occupies lows on the Devonian (Paleozoic)
surface  resulting in the thickest  McMurray  intervals.  Clean sands in these
fluvial  channels  result in excellent  quality ore.  Flood plain  deposits of
significant  thickness are found in the upper  portions of the lower  McMurray
and are typically  removed as waste. In the deepest portions of the mine area,
the lower  McMurray is comprised of "water  sands".  These sands are barren of
bitumen;  having  never  been  saturated  with  bitumen  or,  in some  places,
originally  containing  bitumen  that has since  been  removed  from the sands
through the movement of basal waters over time producing "swept" zones.

The middle  McMurray is comprised of thick estuarine  channel  successions and
tidal flat deposits  resulting in  interbedded  sands and muds.  The estuarine
channel  sands  provide good quality  ore.  The muddier  intervals  within the
channels  and the tidal flat  deposits  within the middle  McMurray  represent
zones of interburden in the mining area.

The upper McMurray consists of  shoreface/channel  transition  deposits and is
typically  thin,  less than 5 meters.  Locally,  this  member may be  entirely
eroded. Exceptional thickness of about 15 meters can be found within the upper
McMurray.  In most cases, the bitumen saturation in the upper McMurray is poor
and the material is included with the overburden.

<PAGE>
                                      42


FIGURE 2 - GENERAL STRATIGRAPHY OF THE HORIZON OIL SANDS PROJECT



                              [GRAPHIC OMITTED]




HORIZON OIL SANDS PROJECT MINING RESERVES


For the year ended December 31, 2005, the Company retained GLJ to evaluate 100
per cent of phases 1, 2 and 3 of the Horizon Project and prepare an Evaluation
Report  on the  Company's  proved  and  probable  oil  sands  mining  reserves
incorporating  both the mining and  upgrading  projects.  These  reserves were
evaluated  adhering to the requirements of SEC Industry Guide 7 using constant
pricing and have been  disclosed  separately  from the Company's  conventional
proved and probable crude oil, NGL and natural gas reserves.

The pit limits and mine plans were updated in 2005  incorporating  the results
from the most  recent and past  drilling  programs.  Figure 3 shows the mining
areas  associated with the reserves and Figure 4 shows the drill hole coverage
used to  develop  the mine  plan.  The oil sands  mining  reserves  from GLJ's
Evaluation  Report are  provided in Table 2. The 2.9 million  barrels of gross
proved  and  probable  synthetic  crude  oil  reserves  shown in the table are
produced from 37 years of projected  production from the first three phases of
the project commencing in 2008.

The Reserve  Committee of the  Company's  Board of Directors  has met with and
carried  out  independent  due  diligence  procedures  with GLJ to review  the
qualifications  of and  procedures  used by the evaluator in  determining  the
estimate of the Company's oil sands mining reserves.


<PAGE>
                                      43


FIGURE 3 - HORIZON OIL SANDS PROJECT RESOURCE AREAS AND GENERAL LAYOUT





                              [GRAPHIC OMITTED]



<PAGE>
                                      44


FIGURE 4 - HORIZON OIL SANDS PROJECT CORE HOLE COVERAGE






                              [GRAPHIC OMITTED]


<PAGE>
                                      45


OIL SANDS MINING RESERVES

The following table sets out Canadian Natural's reserves of bitumen and
synthetic crude oil from the Horizon Project as of December 31, 2005:

<TABLE>
<CAPTION>
                                                                            Constant Prices
                                           ----------------------------------------------------------------------------------
                                                         Bitumen (mmbbl)                   Synthetic Crude Oil (1) (mmbbl)
                                                   Gross (2)              Net                 Gross (2)              Net
                                           -------------------- ------------------     ------------------- ------------------
<S>                                                <C>                <C>                   <C>                <C>
Total proved reserves                                  2,235              1,848                   1,833              1,626
Total proved and probable reserves                     3,430              2,848                   2,878              2,566
</TABLE>

(1)  Synthetic  crude oil reserves are based on the upgrading of Bitumen using
     technologies  implemented at the Horizon Project.  The reserves shown for
     bitumen and synthetic crude oil are not additive.
(2)  Gross  reserves  mean the total  remaining  recoverable  reserves  before
     consideration of company interests or royalties.


E.    CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION

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

<TABLE>
<CAPTION>
                                                                           YEAR ENDED DECEMBER 31
                                                         -------------------------------------------------------------
                                                                 2005                 2004                 2003
                                                                 ----                 ----                 ----
<S>                                                            <C>                  <C>                   <C>
        Daily Production, before royalties
             Crude Oil and NGLs (bbl/d)                        313,168              282,489              242,392
             Natural Gas (mmcf/d)                                1,439                1,388                1,299
        Annual Production, before royalties
             Crude Oil and NGLs (mbbl)                         114,306              103,391               88,473
             Natural Gas (bcf)                                     525                  508                  474
</TABLE>


<PAGE>
                                      46


<TABLE>
<CAPTION>
NETBACKS
INFORMATION BY QUARTER

                                                  YEAR 2005                                            YEAR 2004
                              -------------------------------------------------    ----------------------------------------------
                                1ST       2ND       3RD       4TH      YEAR          1ST      2ND       3RD       4TH       YEAR
                                ----      ----      ----      ----     -----         ----     ----      ----      ----      -----
                              QUARTER   QUARTER   QUARTER   QUARTER    ENDED       QUARTER   QUARTER   QUARTER   QUARTER    ENDED
                              -------   -------   -------   -------    -----       -------   -------   -------   -------    -----
<S>                           <C>       <C>       <C>       <C>       <C>          <C>       <C>       <C>       <C>       <C>

Average Daily Production
Volumes, before royalties

     Crude oil and
      NGLs (bbl/d)            287,803   289,064   334,724   340,268   313,168      261,286   275,398   297,262   295,704   282,489

     Natural Gas (mcf/d)        1,455     1,454     1,423     1,423     1,439        1,294     1,452     1,396     1,410     1,388

PRODUCT NETBACKS
Crude oil and NGLs ($/bbl)
     Sales Price (1)          $ 39.81   $ 42.51   $ 57.35   $ 46.38   $ 46.86      $ 34.21   $ 36.72   $ 43.50   $ 36.92   $ 37.99
     Royalties                $  3.39   $  3.33   $  5.11   $  3.89   $  3.97      $  2.91   $  3.15   $  3.59   $  2.95   $  3.16
     Production Expenses      $ 11.30   $ 11.66   $ 11.48   $ 10.33   $ 11.17      $  9.58   $  9.92   $ 10.21   $ 10.41   $ 10.05
     NETBACK                  $ 25.12   $ 27.52   $ 40.76   $ 32.16   $ 31.72      $ 21.72   $ 23.65   $ 29.70   $ 23.56   $ 24.78

Natural Gas ($mcf)
     Sales Price (1)          $  6.68   $  7.33   $  8.61   $ 11.67   $  8.57      $  6.31   $  6.64   $  6.24   $  6.77   $  6.50
     Royalties                $  1.30   $  1.48   $  1.93   $  2.30   $  1.75      $  1.27   $  1.38   $  1.39   $  1.34   $  1.35
     Production Expenses      $  0.69   $  0.71   $  0.76   $  0.76   $  0.73      $  0.65   $  0.66   $  0.71   $  0.68   $  0.67
     NETBACK                  $  4.69   $  5.14   $  5.92   $  8.61   $  6.09      $  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)          $ 53.14   $ 56.85   $ 66.81   $ 58.87   $ 59.16      $ 40.75   $ 45.28   $ 51.54   $ 48.60   $ 46.71
     Royalties                $  5.20   $  4.55   $  5.50   $  4.40   $  4.90      $  3.71   $  3.98   $  3.99   $  4.12   $  3.95
     Production Expenses      $ 11.58   $ 12.28   $ 11.47   $  8.90   $ 10.93      $  9.77   $ 10.36   $ 10.70   $ 11.20   $ 10.53
     NETBACK                  $ 36.36   $ 40.02   $ 49.84   $ 45.57   $ 43.33      $ 27.27   $ 30.94   $ 36.85   $ 33.28   $ 32.23

Heavy  Crude Oil ($/bbl)
     Sales Price (1)          $ 25.21   $ 27.82   $ 47.25   $ 30.27   $ 33.09      $ 27.00   $ 28.08   $ 35.33   $ 25.16   $ 28.99
     Royalties                $  1.41   $  2.07   $  4.83   $  3.08   $  2.92      $  2.02   $  2.31   $  3.18   $  1.77   $  2.34
     Production Expenses      $ 11.00   $ 11.03   $ 11.50   $ 12.18   $ 11.44      $  9.38   $  9.47   $  9.72   $  9.62   $  9.56
     Netback                  $ 12.80   $ 14.72   $ 30.92   $ 15.01   $ 18.73      $ 15.60   $ 16.30   $ 22.43   $ 13.77   $ 17.09
</TABLE>

     NOTE:  Pelican Lake crude oil has an API of 12(0) to 17(0),  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>
                                      47

NETBACKS
INFORMATION BY QUARTER

<TABLE>
<CAPTION>
                                                 YEAR 2005                                            YEAR 2004
                             ------------------------------------------------     ------------------------------------------------
                               1ST       2ND       3RD        4TH      YEAR         1ST       2ND       3RD       4TH       YEAR
                             QUARTER   QUARTER   QUARTER    QUARTER    ENDED      QUARTER   QUARTER   QUARTER   QUARTER     ENDED
                             -------   -------   -------    -------   -------     -------   -------   -------   -------   --------
<S>                          <C>       <C>       <C>        <C>       <C>         <C>       <C>       <C>       <C>       <C>
SEGMENTED
NORTH AMERICA PRODUCT NETBACKS
Light/Pelican Lake/NGLs ($/bbl)

   Sales Price (1)           $ 45.80   $ 49.78   $ 61.21    $ 52.10   $ 52.35     $ 37.54   $ 41.03   $ 44.89   $ 43.80   $ 41.81
   Royalties                 $ 10.64   $  8.77   $ 11.49    $  9.62   $ 10.13     $  7.20   $  7.91   $  8.59   $  8.76   $  8.12
   Production Expenses          8.30   $  8.40   $  9.27    $  8.60   $  8.65     $  7.30   $  7.74   $  7.75   $  7.85   $  7.66
   NETBACK                   $ 26.86   $ 32.61   $ 40.45    $ 33.88   $ 33.57     $ 23.04   $ 25.38   $ 28.55   $ 27.19   $ 26.03

Heavy Crude Oil ($/bbl)
   Sales Price (1)           $ 25.21   $ 27.82   $ 47.25    $ 30.27   $ 33.09     $ 27.00   $ 28.08   $ 35.33   $ 25.16   $ 28.99
   Royalties                 $  1.41   $  2.07   $  4.83    $  3.08   $  2.92     $  2.02   $  2.31   $  3.18   $  1.77   $  2.34
   Production Expenses       $ 11.00   $ 11.03   $ 11.50    $ 12.18   $ 11.44     $  9.38   $  9.47   $  9.72   $  9.62   $  9.56
   NETBACK                   $ 12.80   $ 14.72   $ 30.92    $ 15.01   $ 18.73     $ 15.60   $ 16.30   $ 22.43   $ 13.77   $ 17.09

Natural Gas ($/mcf)
   Sales Price (1)           $  6.73   $   7.38  $  8.69    $ 11.79   $  8.65     $  6.37   $  6.78   $  6.36   $  6.88   $  6.61
   Royalties                 $  1.33   $   1.50  $  1.96    $  2.34   $  1.78     $  1.33   $  1.44   $  1.45   $  1.39   $  1.40
   Production Expenses       $  0.66   $   0.68  $  0.74    $  0.74   $  0.71     $  0.60   $  0.60   $  0.63   $  0.63   $  0.62
   NETBACK                   $  4.74   $   5.20  $  5.99    $  8.71   $  6.16     $  4.44   $  4.74   $  4.28   $  4.86   $  4.59

NORTH SEA PRODUCT NETBACKS
Light Oil ($/bbl)
   Sales Price (1)           $ 59.56   $ 64.81   $ 74.46    $ 66.88   $ 66.57     $ 44.27   $ 49.22   $ 57.39   $ 52.77   $ 51.37
   Royalties                 $  0.05   $  0.11   $  0.12    $  0.14   $  0.10     $  0.06   $  0.10   $  0.09   $  0.08   $  0.08
   Production Expenses       $ 14.91   $ 17.41   $ 15.15    $ 12.11   $ 14.94     $ 13.26   $ 13.84   $ 13.88   $ 14.96   $ 14.03
   NETBACK                   $ 44.60   $ 47.29   $ 59.19    $ 54.63   $ 51.53     $ 30.95   $ 35.28   $ 43.42   $ 37.73   $ 37.26

Natural Gas ($/mcf)
   Sales Price (1)           $  3.52   $  3.07   $  2.64    $  3.40   $  3.17     $  5.08   $  3.28   $  3.17   $  3.26   $  3.73
   Royalties                 $    --   $    --   $    --    $    --   $    --     $    --   $    --   $    --   $    --   $    --
   Production Expenses       $  2.52   $  2.92   $  2.30    $  1.96   $  2.44     $  1.65   $  1.92   $  2.48   $  2.29   $  2.07
   NETBACK                   $  1.00   $  0.15   $  0.34    $  1.44   $  0.73     $  3.43   $  1.36   $  0.69   $  0.97   $  1.66

OFFSHORE WEST AFRICA
PRODUCT NETBACKS
Light Oil ($/bbl)
   Sales Price (1)           $ 62.34   $ 58.24   $ 59.09    $ 60.19   $ 59.91     $ 42.08   $ 49.34   $ 53.86   $ 51.28   $ 49.05
   Royalties                 $  1.90   $  1.81   $  1.54    $  1.57   $  1.62     $  1.28   $  1.52   $  1.42   $  1.52   $  1.43
   Production Expenses       $ 11.43   $  8.47   $  5.81    $  5.62   $  6.50     $  7.09   $  7.43   $  8.05   $  7.82   $  7.59
   NETBACK                   $ 49.01   $ 47.96   $ 51.74    $ 53.00   $ 51.79     $ 33.71   $ 40.39   $ 44.39   $ 41.94   $ 40.03

Natural Gas ($/mcf)
   Sales Price (1)           $  7.67   $   6.88  $  5.52    $  5.13   $  5.91     $  4.80   $  5.18   $  6.31   $  4.73   $  5.25
   Royalties                 $  0.23   $   0.21  $  0.13    $  0.14   $  0.16     $  0.15   $  0.16   $  0.17   $  0.14   $  0.15
   Production Expenses       $  1.25   $   1.37  $  1.09    $  0.80   $  1.05     $  1.23   $  1.38   $  1.39   $  1.31   $  1.33
   NETBACK                   $  6.19   $   5.30  $  4.30    $  4.19   $  4.70     $  3.42   $  3.64   $  4.75   $  3.28   $  3.77
</TABLE>


NOTE: Pelican Lake crude oil has an API of 12(0) to 17(0), 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>
                                      48

NETBACKS
INFORMATION BY QUARTER

<TABLE>
<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 NGLs (bbl/d)             237,560         240,607         247,016         244,262         242,392

     Natural Gas (mcf/d)                      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 NGLS 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 Crude Oil ($/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 crude oil has an API of 12(0) to 17(0), 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>
                                      49


NETBACKS
INFORMATION BY QUARTER

<TABLE>
<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 Crude Oil  ($/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 Crude 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 Crude 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 crude oil has an API of 12(0) to 17(0), but receives medium
quality  crude  netbacks  due to  exceptionally  low  operating  costs and low
royalty rates.

Including transportation and excluding risk management activities

<PAGE>
                                      50


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:

<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31
                                               ---------------------------------------------------------
                                                        2005                             2004
                                                  Gross          Net                Gross        Net
                                               ------------------------         ------------------------
<S>                                              <C>           <C>                  <C>        <C>
      Natural Gas                                  1,071         890                  801        689
      Crude Oil                                      685         627                  378        328
      Service/Stratigraphic                          251         248                  339        336
      Dry Holes                                      136         117                  106         96
                                               ------------------------         ------------------------
      Total                                        2,143       1,882                1,624      1,449
                                               ========================         ========================

      *Total Success Rate                                         93%                             91%
</TABLE>

      *excluding service and stratigraphic test wells


<PAGE>
                                      51


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:

<TABLE>
<CAPTION>
                                                                  YEAR ENDED DECEMBER 31
                                                            -------------------------------------
                                                                   2005                2004
                                                            ----------------      ---------------
<S>                                                             <C>                 <C>
       Net property (dispositions) acquisitions((1))               (320)              1,835
       Land acquisition and retention                               254                 120
       Seismic evaluation                                           132                  89
       Well drilling, completion and equipping                    2,000               1,394
       Pipeline and production facilities                         1,295                 821
                                                            ----------------      ---------------

       Reserve replacement expenditures                           3,361               4,259
                                                            ----------------      ---------------
       Horizon Project:
       Phase 1 construction costs                                 1,329                  --
       Capitalized interest and other                               170                 291
                                                            ----------------      ---------------
       Total Horizon Project                                      1,499                 291
                                                            ----------------      ---------------
       Midstream operations                                           4                  16
       Abandonments((2))                                             46                  32
       Head office equipment                                         22                  35
                                                            ----------------      ---------------

       Total Net Capital Expenditures                             4,932               4,633
                                                            ================      ===============
</TABLE>

       (1)   Includes Business Combinations.

       (2)   Abandonments represent expenditures to settle retirement
             obligations and have been reflected as capital expenditures in
             this table.

<PAGE>
                                      52


<TABLE>
<CAPTION>
                                                                  2005 THREE MONTHS ENDED
                                                 -----------------------------------------------------------
                                                                        ($ millions)
CAPITAL EXPENDITURES
BY QUARTER                                         MAR. 31         JUNE 30         SEPT. 30        DEC. 31
                                                   -------         -------         --------        -------
<S>                                                <C>             <C>             <C>             <C>
Net property (dispositions) acquisitions((1))            2           (341)                0             19

Land acquisition and retention                          36              52               69             97

Seismic evaluation                                      41              20               31             40

Well drilling, completion and equipping                634             306              431            629

Pipeline and production facilities                     432             283              266            314
                                                   -------         -------         --------        -------


Reserve replacement expenditures                     1,145             320              797          1,099

Horizon Project

Phase 1 construction costs                             132             259              432            506

Capitalized interest and other                          83              16               20             51
                                                   -------         -------         --------        -------

Total Horizon Project                                  215             275              452            557

Midstream operations                                     4              --               (1)             1

Abandonments((2))                                        4               7               19             16

Head office equipment                                    4               7                5              6

Total Net Capital Expenditures                       1,372             609            1,272          1,679
                                                   =======================================================
</TABLE>

(1)  Includes Business Combinations.

(2)  Abandonments represent expenditures to settle retirement obligations and
     have been reflected as capital expenditures in this table.


<TABLE>
<CAPTION>
                                                                     2004 THREE MONTHS ENDED
                                                   -------------------------------------------------------
                                                                           ($ millions)
CAPITAL EXPENDITURES((1))
BY QUARTER                                         MAR. 31         JUNE 30         SEPT. 30        DEC. 31
                                                   -------         -------         --------        -------

<S>                                                  <C>               <C>              <C>          <C>
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((2))
                                                         7               6               14              5
Head office equipment
                                                         7               8               12              8
                                                   -------         -------         --------        -------

Total Net Capital Expenditures                       1,493             844              875          1,421
                                                   =======================================================
</TABLE>

(1)  Includes Business Combinations.

(2)  Abandonments represent expenditures to settle retirement obligations and
     have been reflected as capital expenditures in this table.


<PAGE>
                                      53


H.    UNDEVELOPED ACREAGE

The following table summarizes the Company's working interest holdings in core
region non-reserve acreage as at December 31, 2005:

                                        GROSS ACRES           NET ACRES
                                        -----------           ---------
                                         (thousands)         (thousands)

           NORTH AMERICA
           -------------
           Alberta                            9,892               8,376
           British Columbia                   2,645               2,010
           Saskatchewan                         615                 549
           Manitoba                              11                  11


           NORTH SEA
           ---------
           United Kingdom                       457                 352


           OFFSHORE WEST AFRICA
           --------------------
           Cote d'Ivoire                        369                 274
           Gabon                                152                 152
                                          ---------           ---------
           Total                             14,141              11,724
                                          =========           =========


I.    DEVELOPED ACREAGE

The following table summarizes the Company's working interest holdings in core
region developed acreage as at December 31, 2005:

                                        GROSS ACRES           NET ACRES
                                        -----------           ---------
                                         (thousands)         (thousands)

           NORTH AMERICA
           -------------
           Alberta                            5,727               4,545
           British Columbia                   1,111                 870
           Saskatchewan                         341                 279
           Manitoba                               5                   5


           NORTH SEA
           ---------
           United Kingdom                       138                  93


           OFFSHORE WEST AFRICA
           --------------------
           Cote d'Ivoire                          7                   4
                                          ---------           ---------
           Total                              7,329               5,796
                                          =========           =========


<PAGE>
                                      54


                        SELECTED FINANCIAL INFORMATION

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

<TABLE>
<CAPTION>
                                                                     ------------------------------------
                                                                            YEAR ENDED DECEMBER 31
                                                                     ------------------------------------
                                                                             2005            2004
                                                                             ----            ----
                                                                  ($ millions, except per share information)

<S>                                                                       <C>             <C>
Revenues (1) (net of  royalties)                                             8,741           6,536

Cash flow from operations                                                    5,021           3,769

Per common share - basic  (3)                                                 9.36            7.03

                 - diluted (3)                                                9.33            6.98

Net earnings                                                                 1,050           1,405

Per common share - basic (3)                                                  1.96            2.62

                 - diluted (3)                                                1.95            2.60

Total assets                                                                21,852          18,372

Total long-term debt(2)                                                      3,321           3,538

<CAPTION>
                                           ---------------------------------------------------------
                                                          2005 THREE MONTHS ENDED
                                           ---------------------------------------------------------
                                           MARCH 31         JUNE 30         SEPT. 30         DEC. 31
                                           --------         -------         --------         -------
                                                   ($ millions, except per share information)
<S>                                        <C>              <C>             <C>              <C>
Revenues (1) (net of  royalties)              1,734           1,881            2,515           2,611

Net earnings (loss)                            (424)            219              151           1,104

Per common share - basic (3)                  (0.79)           0.41             0.28            2.06

                 - diluted (3)                (0.79)           0.41             0.28            2.06

<CAPTION>
                                           ---------------------------------------------------------
                                                          2004 THREE MONTHS ENDED
                                           ---------------------------------------------------------
                                           MARCH 31         JUNE 30         SEPT. 30         DEC. 31
                                           --------         -------         --------         -------
                                                   ($ millions, except per share information)
<S>                                        <C>              <C>             <C>              <C>
Revenues (1) (net of royalties)               1,420           1,603            1,799           1,714

Net earnings                                    258             259              311             577

Per common share - basic (3)                   0.49            0.48             0.58            1.07

                 - diluted (3)                 0.48            0.48             0.57            1.06
</TABLE>

(1)  Excluding transportation costs and risk management activities.
(2)  Excluding current portion of long-term debt.
(3)  Restated to reflect two-for-one-share split in May 2005.

<PAGE>
                                      55


                               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, we are under no obligation to update this Annual Information Form.

The Company's senior unsecured long-term debt securities are rated "Baa1" with
a stable  trend 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 rating outlook to
the  Company  and not to  individual  debt  instruments.  S&P has  assigned  a
negative outlook to the Company.

                Rated Debt Issuances

                $125 CAD million 7.40% unsecured note due 2007
                $400 CAD million 4.95% unsecured note due 2015
                $93 US million 6.45% adjustable rate note due 2009
                $400 US million 6.70% unsecured note due 2011
                $350 US million 5.45% unsecured note due 2012
                $350 US million 4.90% unsecured note due 2014
                $400 US million 7.20% unsecured note due 2032
                $350 US million 6.54% unsecured note due 2033
                $350 US million 5.85% unsecured note due 2035

<PAGE>
                                      56


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>
                                      57


           MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES

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

           2005 Monthly Historical Trading on Toronto Stock Exchange

Month                High             Low          Close         Volume Traded
January             $55.70          $48.55        $54.74          23,564,720
February             74.25           54.60         70.09          31,090,409
March                74.75           63.79         68.36          29,853,739
April                71.88           61.07         62.40          27,675,887
May 1 - 17           71.09           61.90         67.00          13,881,359
*May 18 - 31         37.60           33.36         36.25          18,362,198
June                 46.98           36.68         44.40          53,797,555
July                 51.45           45.52         51.00          52,706,687
August               59.96           50.61         58.47          57,286,467
September            60.00           51.25         52.50          50,127,673
October              53.34           43.55         48.29          66,484,410
November             58.24           48.25         52.87          55,369,037
December             62.00           53.31         57.63          31,725,589

* Shares began trading on a post two-for-one subdivision basis on May 18, 2005.


On January 22,  2003,  the Company  announced  its  intention to make a Normal
Course  Issuer  Bid  through  the  facilities  of TSX and the NYSE,  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 TSX and the NYSE,  commencing
January 24, 2004 and ending January 23, 2005, to purchase for  cancellation up
to 6,690,385  (13,380,770  post May 21, 2004  two-for-one  stock split) common
shares of the Company,  being 5 per cent of the 133,807,695  (267,615,390 post
May 21, 2004 two-for-one stock split) 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.

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  (26,818,012  post May 20, 2005
two-for-one stock split) common shares of the Company, being 5 per cent of the
268,180,123  (536,360,246  post May 20, 2005  two-for-one  stock split) common

<PAGE>
                                      58


shares of the Company outstanding on January 12, 2005. Under this program, the
Company  purchased  a total of 850,000  common  shares for  cancellation  at a
weighted  average  purchase  price of $53.26 for each common share  purchased;
$53.29 after costs.

At the  Annual  and  Special  Meeting of  Shareholders  held May 5, 2005,  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 20, 2005.

On January 20,  2006,  the Company  announced  its  intention to make a Normal
Course  Issuer Bid  through  the  facilities  of TSE and the NYSE,  commencing
January 24, 2006 and ending January 23, 2007, to purchase for  cancellation up
to  26,852,545  common  shares  of  the  Company,  being  5 per  cent  of  the
537,050,902  common shares of the Company  outstanding on January 17, 2006. As
of the date of this Annual Information Form, no shares have been purchased.


                               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 regular  quarterly  dividends.  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 and May 2005 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.

                                                   2005      2004      2003
                                                   ----      ----      ----

     Cash dividends declared per common share     $0.24     $0.20     $0.15


                         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>
                                      59


                            DIRECTORS AND OFFICERS

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

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                               POSITION                     PRINCIPAL
                               PRESENTLY                    OCCUPATION
NAME                           HELD                         DURING PAST 5 YEARS
---------------------------------------------------------------------------------------------------------------------
<S>                            <C>                          <C>
Catherine M. Best              Director(2) (4)              Executive  Vice-President,   Risk  Management  and  Chief
Calgary, Alberta               (age 52)                     Financial  Officer of  Financial  Officer of the  Calgary
Canada                                                      Health  Region from 2002 the  Calgary  Health to present;
                                                            Vice-President,  Corporate Services and Chief 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
                                                            of the Company since November 2003.

N. Murray Edwards              Vice-Chairman and            President,   Edco  Financial  Holdings  Ltd.  (a  private
Calgary/Banff, Alberta         Director(3)                  management   and   consulting   company).    Has   served
Canada                         (age 46)                     continuously as a director of the Company since September
                                                            1988.  Currently  serving  on the board of  directors  of
                                                            Ensign  Energy  Services  Inc.  and  Magellan   Aerospace
                                                            Corporation.

Honourable Gary A. Filmon      Director (1)(2)              Consultant,  Exchange  Group  (business  consulting  firm
Winnipeg, Manitoba             (age 63)                     based in Winnipeg,  Manitoba).  Prior thereto,  served as
Canada                                                      Premier  of  Manitoba  from  1988  to  1999.  Has  served
                                                            continuously  as a director of the Company since February
                                                            2006.  Currently  serving  on the board of  directors  of
                                                            Manitoba Telecom  Services Inc.,  Pollard Banknote Income
                                                            Fund,  Arctic Glacier Income Trust,  Exchange  Industrial
                                                            Income  Fund,  and as a member of the  Advisory  Board of
                                                            Marsh Canada.

Ambassador Gordon D. Giffin    Director(1)(2)               Senior  Partner,  McKenna  Long & Aldridge LLP (law firm)
Atlanta, Georgia               (age 56)                     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               Vice-Chairman and            Officer  of  the  Company.  Has  served continuously as a
Calgary, Alberta               Director                     director of the Company since June 1982.
Canada                         (age 60)

Keith A.J. MacPhail            Director(3)(5)               Chairman, President and Chief Executive Officer, Bonavista
Calgary, Alberta               (age 49)                     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  Energy Trust and NuVista Energy
                                                            Ltd.

Allan P. Markin                Chairman and Director(5)     Chairman  of the  Company.  Has  served  continuously as a
Calgary, Alberta               (age 60)                     director of the Company since January 1989.
Canada

Norman F. McIntyre             Director(3)(4)(5)            An  independent   businessman.   Prior  thereto  Executive
Calgary, Alberta               (age 60)                     Vice-President, Petro-Canada  from  1995 to 2002  and most
Canada                                                      recently  President, Petro-Canada 2002 to 2004. Has served
                                                            continuously as a director of the Company since July 2005.
                                                            Currently  serving  on the  board of directors  of  Signal
                                                            Energy Inc. and Petro Andina Resources, a private company.
</TABLE>

<PAGE>
                                      60

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                               POSITION                     PRINCIPAL
                               PRESENTLY                    OCCUPATION
NAME                           HELD                         DURING PAST 5 YEARS
----------------------------------------------------------------------------------------------------------------------
<S>                            <C>                          <C>
James S. Palmer, C.M., A. O.   Director(3)(4)(5)            Chairman,  Burnet, Duckworth & Palmer LLP (law firm).  Has
E., Q.C.                       (age 77)                     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 66)                     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.,  Pheromone
                                                            Sciences Corp. and Overlord Financial Inc.

David A. Tuer                  Director(1)(2)(3)            An  independent  businessman.  Chairman,   Calgary  Health
Calgary, Alberta               (age 56)                     Region since  October 2001 and  President,  Value Creation
Canada                                                      Inc.  since April 2005.  Prior thereto President and Chief
                                                            Executive Officer, PanCanadian Energy Corporation and most
                                                            recently  President  and  CEO  of  Hawker  Resources  Inc.
                                                            (independent  oil and natural gas  company)  from  January
                                                            2003 to March 2005. Has served  continuously as a director
                                                            of the Company  since May 2002.  Currently  serving on the
                                                            board of directors of Sequoia Oil and Gas Trust, Rockwater
                                                            Capital Corporation; and, Norquay Capital Corporation.

Steve W. Laut                  President and Chief          Officer of the Company.
Calgary, Alberta               Operating Officer
Canada                         (age 48)

Real M. Cusson                 Senior Vice-President,       Officer of the Company.
Calgary, Alberta               Marketing
Canada                         (age 55)

Real J. H. Doucet              Senior Vice-President,       Officer of the Company.
Calgary, Alberta               Oil Sands
Canada                         (age 53)

Allen M. Knight                Senior Vice-President,       Officer of the Company.
Calgary, Alberta               International &
Canada                         Corporate Development
                               (age 56)

Tim S. McKay                   Senior Vice-President,       Officer of the Company.
Calgary, Alberta               Operations
Canada                         (age 44)

Douglas A. Proll               Chief Financial Officer      Officer of the  Company  since April  2001;  prior thereto
Calgary, Alberta               and Senior                   Vice President Finance and Treasurer of Renaissance Energy
Canada                         Vice-President, Finance      Ltd.  to  August  2000 and  most  recently  Vice President
                               (age 55)                     Finance and Business Development of Husky Energy Inc. from
                                                            August 2000 to February 2001.

Lyle G. Stevens                Senior Vice-President,       Officer of the Company.
Calgary, Alberta               Exploitation
Canada                         (age 51)

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 53)
</TABLE>

<PAGE>
                                      61

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                               POSITION                     PRINCIPAL
                               PRESENTLY                    OCCUPATION
NAME                           HELD                         DURING PAST 5 YEARS
----------------------------------------------------------------------------------------------------------------------
<S>                            <C>                          <C>
Corey B. Bieber                Vice-President, Investor     Officer of the  Company  since April  2005;  prior thereto
Calgary, Alberta               Relations                    Director of Corporate Accounting of Enbridge Inc. to March
Canada                         (age 42)                     2001, Treasurer of the Company March 2001 to July 2002 and
                                                            most recently Director,  Investor Relations of the Company
                                                            from July 2002 to April 2005.

Mary-Jo Case                   Vice-President, Land         Officer  of the  Company  since  May 2002;  prior  thereto
Calgary, Alberta               (age 47)                     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.

Wayne M. Chorney               Vice-President,              Officer of the  Company  since April  2004;  prior thereto
Calgary, Alberta               Development Operations       Production  Manager,  Thermal  Operations  of  the Company
Canada                         (age 46)                     October 1999 to August 2001,  General  Manager, Production
                                                            of CNR  International  (U.K.)  Limited  ("CNRI")  a wholly
                                                            owned  subsidiary of the Company  September 2000 to August
                                                            2001 and most recently Director,  Production Operations of
                                                            CNRI August 2001 to April 2004.

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 43)

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 52)

Randall S. Davis               Vice-President,              Officer  of the  Company  since July  2004;  prior thereto
Calgary, Alberta               Financial Accounting and     Manager,  Financial Reporting  of the Company to July 2002
Canada                         Controls                     and most recently Financial Controller of the Company from
                               (age 39)                     July 2002 to July 2004.

Larry C. Galea                 Vice-President,              Officer of the  Company since April  2005;  prior  thereto
Calgary, Alberta               Operations Planning          Exploitation  Manager  of  the Company  to  January  2002,
Canada                         (age 40)                     Manager,  Operations  Planning January 2002 to April 2004,
                                                            and most recently Exploitation  Manager from April 2004 to
                                                            April 2005.

Jerome W.  Harvey              Vice-President,              Officer of the  Company  since April  2004;  prior thereto
Calgary, Alberta               Commercial Operations        Manager, Commercial Operations.
Canada                         (age 52)

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 48)                     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 38)

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 Project    and  Offsites  Project  Manager January 2002 to July 2002,
                               (age 42)                     Director,  Utilities  and  Offsites July 2002 to July 2003
                                                            and most recently General  Manager, Utilities and Offsites
                                                            July 2003 to December 2004.
</TABLE>

<PAGE>
                                      62

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                               POSITION                     PRINCIPAL
                               PRESENTLY                    OCCUPATION
NAME                           HELD                         DURING PAST 5 YEARS
----------------------------------------------------------------------------------------------------------------------
<S>                            <C>                          <C>
Philip A. Keele                Vice-President, Mining,      Officer of the Company since December 2004;  prior thereto
Calgary, Alberta               Horizon Oil Sands Project    from Mine  Manager at  Fording  Coal Limited  to  February
Canada                         (age 46)                     2001,  Chief Mine Engineer of the Company February 2001 to
                                                            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 38)                     recently  Manager,  Field  Operations of the Company  from
                                                            April 2000 to September 2002.

Leon Miura                     Vice-President, Upgrading    Officer of the Company  since August 2003;  prior  thereto
Calgary, Alberta               (age 51)                     held progressively senior positions at Petroleos de Canada
                                                            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 44)                     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 July
Canada                         (age 44)                     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 39)

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 59)                     President of 960925  Alberta  Ltd.  from  November 2001 to
                                                            April 2002, Manager,  Site Development of the Company from
                                                            May  2002 to  December  2002  and  most  recently  General
                                                            Manager Site  Development of the Company from January 2003
                                                            to April 2004.

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 38)                     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 44)                     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 49)                     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.
</TABLE>

<PAGE>

                                      63

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
                               POSITION                     PRINCIPAL
                               PRESENTLY                    OCCUPATION
NAME                           HELD                         DURING PAST 5 YEARS
----------------------------------------------------------------------------------------------------------------------
<S>                            <C>                          <C>
Kimberly I. McKay              Treasurer                    Officer of the Company since December 2004;  prior thereto
Calgary, Alberta               (age 37)                     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 56)
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 Canadian
Natural  shareholders.  With the exception of Messrs. N. F. McIntyre and G. A.
Filmon who were  appointed to the Board  effective  July 29, 2005 and February
21, 2006 respectively,  all of the current directors were elected to the Board
at the last annual  meeting of  shareholders  held on May 5, 2005.  All of the
current  directors are standing for election at the Annual General  Meeting of
Shareholders scheduled for May 4, 2006.

As at December  31, 2005,  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 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).

          INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No, director,  executive officer or principal shareholder of Canadian Natural,
or associate or affiliate of those persons, has any material interest,  direct
or  indirect,  in any  transaction  within  the  last  three  years  that  has
materially affected or will materially affect the Company.

                          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. A. Filmon, G. D. Giffin and D. A. Tuer each
of whom is  independent  and  financially  literate as those terms are defined

<PAGE>
                                      64


under Canadian securities regulations MI 52-110 and the NYSE listing standards
as they pertain to audit  committees  of listed  issuers.  The  education  and
experience  of  each  member  of  the  Audit   Committee   relevant  to  their
responsibilities as an Audit Committee member is described below.

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.

Honourable  G. A. Filmon holds both a Bachelor of Science  degree and a Master
of Science  degree in Civil  Engineering.  He was  Premier of the  Province of
Manitoba for several years and during that time chaired the Treasury Board for
a period of five years. He was President of Success  Commercial College for 11
years and is currently a business management consultant. Mr. G. A. Filmon is a
director  of other  public  companies  and is an active  member of other audit
committees, one of which he chairs.

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.

The Audit Committee in 2005 approved specified audit and non-audit services to
be performed by PricewaterhouseCoopers  LLP ("PwC") the independent auditor of
the Corporation.  The following table lists the fees accrued to PwC for fiscal
year 2005.

AUDITOR SERVICE FEES

    AUDITOR SERVICE                          2005               2004
    ---------------                          ----               ----
    Audit fees                         $1,200,235         $1,100,548
    Audit related fees                 $  266,923         $  183,663
    Tax related fees                   $   39,331         $   39,330
    All other fees                     $    7,290         $        0
    -----------------------------------------------------------------
    Total Accrued Fees                 $1,513,779         $1,323,541
    =================================================================

The Charter of the Audit  Committee of the Company is attached as Schedule "C"
to this Annual Information Form.

<PAGE>
                                      65


                               LEGAL PROCEEDINGS

From time to time,  Canadian Natural 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.


                              MATERIAL CONTRACTS

Other than  contracts  entered  into in the ordinary  course of business,  the
Company has not  entered  into any  material  contracts  in the most  recently
completed financial year nor has it entered into any material contracts before
the most recently completed financial year and which are still in effect.


                             INTERESTS OF EXPERTS

PricewaterhouseCoopers LLP, Chartered Accountants,  are the Company's auditors
and  such  firm  has  prepared  an  opinion  with  respect  to  the  Company's
consolidated  financial  statements as at and for the year ended  December 31,
2005.  PricewaterhouseCoopers  LLP is independent in accordance with the Rules
of Professional Conduct as outlined by the Institute of Chartered  Accountants
of Alberta.

Sproule Associates Limited,  Ryder Scott Company and GLJ Petroleum Consultants
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 GLJ Petroleum  Consultants 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 General
Meeting and  Information  Circular dated March 15, 2006 in connection with the
Annual General Meeting of  Shareholders of Canadian  Natural to be held on May
4, 2006 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, 2005 found on pages 45 to
73,  74 to 96 and 97 to 101  respectively,  of the 2005  Annual  Report to the
Shareholders, which information is incorporated herein by reference.


<PAGE>
                                      66


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>
                                      67


                                 SCHEDULE "A"

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

REPORT ON RESERVES DATA

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

1.     We have  evaluated the  Corporation's  reserves data as at December 31,
       2005. The reserves data consist of the following:

(a)    (i)     proved  conventional crude oil, natural gas liquids and natural
               gas reserve quantities  estimated as at December 31, 2005 using
               constant  prices  and costs;

       (ii)    the related estimated net present value; and

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

(b)    (i)     both proved,  and proved and probable  conventional  crude oil,
               natural  gas   liquids  and  natural  gas  reserve   quantities
               estimated  as at December  31, 2005 using  forecast  prices and
               costs; and

       (ii)    the related estimated net present value.

(c)    (i)     both  proved,  and proved and  probable  bitumen and  synthetic
               crude oil reserve  quantities  relating to surface mineable oil
               sands projects estimated as at December 31, 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
       conventional  reserves (before deduction of income taxes) attributed to
       proved conventional crude oil, NGL and natural gas reserves quantities,
       estimated  using  constant  prices  and  costs and  calculated  using a

<PAGE>
                                      68


       discount  rate of 10  percent,  included  in the  reserves  data of the
       Corporation  evaluated by us for the year ended  December 31, 2005, and
       identifies the respective  portions  thereof that we have evaluated and
       reported on to the Corporation's management and board of directors:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
   INDEPENDENT    DESCRIPTION AND  LOCATION OF RESERVES
    QUALIFIED       PREPARATION    (COUNTRY OR FOREIGN
     RESERVES         DATE OF        GEOGRAPHIC AREA)           NET PRESENT VALUES OF CONVENTIONAL RESERVES
   EVALUATOR OR      EVALUATION
     AUDITOR           REPORT                                     (BEFORE INCOME TAXES, 10% DISCOUNT RATE)
---------------------------------------------------------------------------------------------------------------------
                                                            AUDITED       EVALUATED      REVIEWED         TOTAL
                                                              MM$            MM$            MM$            MM$
---------------------------------------------------------------------------------------------------------------------
<S>               <C>             <C>                       <C>          <C>              <C>          <C>
Sproule           Sproule         Canada, USA                 $0          $20,727          $0           $20,727
Associates Ltd.   Evaluated the
                  P&NG Reserves
                  as reported
                  February 7,
                  2006.
---------------------------------------------------------------------------------------------------------------------
Ryder Scott       Ryder Scott     United Kingdom and          $0           $ 9,890          $0           $ 9,890
Company           Evaluated the   Offshore West Africa
                  P&NG Reserves
                  as reported
                  February 7,
                  2006.
---------------------------------------------------------------------------------------------------------------------
  TOTALS                                                      $0           $30,617          $0           $30,617
---------------------------------------------------------------------------------------------------------------------
</TABLE>

In addition, both proved, and proved and probable reserves have been evaluated
for oil sands  mining  properties  located  in  Canada.  The  Horizon  Project
reserves were  evaluated as at December 31, 2005.  GLJ  Petroleum  Consultants
("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 disclosed  separately  from the Company's  conventional  crude oil and
natural 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.

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

<PAGE>
                                      69


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 7, 2006

       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




       GLJ PETROLEUM CONSULTANTS

       ORIGINAL SIGNED BY:

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


<PAGE>
                                      70


                                 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 conventional crude oil, 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  conventional  crude oil,  NGLs and  natural gas reserve
               quantities  estimated  as at December  31, 2005 using  constant
               prices and costs;

       (ii)    the related estimated net present value; and

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

(b)    (i)     both proved,  and proved and probable  conventional  crude oil,
               NGL and natural gas reserve quantities estimated as at December
               31, 2005 using forecast prices and costs;

       (ii)    the related estimated net present value; and,

(c)    (i)     both  proved,  and proved and  probable  bitumen and  synthetic
               crude oil reserve  quantities  relating to surface mineable oil
               sands operations estimated as at December 31, 2005.

Sproule Associates Limited, Ryder Scott Company and GLJ Petroleum Consultants,
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>
                                      71


The  Reserves   Committee   of  the  Board  of  Directors   has  reviewed  the
Corporation's  procedures  for  assembling  and  reporting  other  information
associated  with crude 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  crude 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.


       /s/ Steve W. Laut
       ----------------------
       Steve W. Laut
       President and Chief Operating Officer


       /s/ Douglas A. Proll
       ----------------------
       Douglas A. Proll
       Chief Financial Officer and Senior Vice President, Finance


       /s/ David A. Tuer
       ----------------------
       David A. Tuer
       Independent Director and Chair of the Reserve Committee


       /s/ Norman F. McIntyre
       ----------------------
       Norman F. McIntyre
       Independent Director and Member of the Reserve Committee




       Dated this 21st day of February, 2006
       Calgary, Alberta

<PAGE>
                                      72


                                 SCHEDULE "C"

                      CANADIAN NATURAL RESOURCES LIMITED
                              (THE "CORPORATION")

CHARTER OF THE AUDIT COMMITTEE OF THE BOARD OF DIRECTORS

I      AUDIT COMMITTEE PURPOSE

       The  Audit  Committee  is  appointed  by the  Board of  Directors  (the
       "Board") to assist the Board in fulfilling its  responsibility  for the
       stewardship  of the  Corporation in overseeing the business and affairs
       of  the  Corporation.   The  Audit   Committee's   primary  duties  and
       responsibilities are to:

       1.   ensure  that  the   Corporation's   management  has  designed  and
            implemented an effective system of internal financial controls;

       2.   monitor and report on the integrity of the Corporation's financial
            statements,  financial reporting processes and systems of internal
            controls  regarding  financial,  accounting  and  compliance  with
            regulatory and statutory  requirements as they relate to financial
            statements, taxation matters and disclosure of material facts;

       3.   select and  recommend for  appointment  by the  shareholders,  the
            Corporation's  independent  auditors,  pre-approve  all  audit and
            non-audit  services  to be  provided  to  the  Corporation  by the
            Corporation's  independent auditors consistent with all applicable
            laws, and establish the fees and other  compensation to be paid to
            the independent auditors;

       4.   monitor the  independence  and  performance  of the  Corporation's
            independent auditors;

       5.   monitor the performance of the internal auditing function;

       6.   establish procedures for the receipt,  retention,  response to and
            treatment  of  complaints,   including   confidential,   anonymous
            submissions by the Corporation's employees,  regarding accounting,
            internal controls or auditing matters; and,

       7.   provide an avenue of communication among the independent auditors,
            management, the internal auditing function and the Board.

II     AUDIT COMMITTEE COMPOSITION, PROCEDURES AND ORGANIZATION

       1.   The Audit  Committee shall consist of at least three (3) directors
            as  determined  by the Board,  each of whom shall be  independent,
            non-executive  directors,  free from any  relationship  that would
            interfere  with the exercise of his or her  independent  judgment.
            Audit Committee members shall meet the independence and experience
            requirements of the regulatory  bodies to which the Corporation is
            subject to. All members of the Audit  Committee shall have a basic
            understanding  of finance and  accounting  and be able to read and
            understand  fundamental  financial statements at the time of their
            appointment  to the Audit  Committee.  At least one  member of the
            Audit  Committee  shall  have  accounting  or  related   financial

<PAGE>
                                      73


            management  expertise  and  qualify  as a  "financial  expert"  or
            similar  designation in accordance  with the  requirements  of the
            regulatory bodies to which the Corporation may be subject to.

       2.   The Board at its  organizational  meeting held in conjunction with
            each annual general meeting of the shareholders  shall appoint the
            members of the Audit Committee for the ensuing year. The Board may
            at any time  remove or replace  any member of the Audit  Committee
            and may fill any vacancy in the Audit Committee.

       3.   The Board shall  appoint a member of the Audit  Committee as chair
            of  the  Audit  Committee.  If an  Audit  Committee  Chair  is not
            designated  by the  Board,  or is not  present at a meeting of the
            Audit Committee,  the members of the Audit Committee may designate
            a chair by majority vote of the Audit Committee membership.

       4.   The Secretary or the Assistant  Secretary of the Corporation shall
            be secretary  of the Audit  Committee  unless the Audit  Committee
            appoints a secretary of the Audit Committee.

       5.   The  quorum for  meetings  shall be one half (or where one half of
            the  members of the Audit  Committee  is not a whole  number,  the
            whole  number  which is  closest to and less than one half) of the
            members of the Audit Committee subject to a minimum of two members
            of the Audit Committee  present in person or by telephone or other
            telecommunications  device that permits all persons  participating
            in the meeting to speak and to hear each other.

       6.   Meetings of the Audit Committee shall be conducted as follows:

            (a)   the  Audit  Committee  shall  meet at least  four (4)  times
                  annually  at  such  times  and at such  locations  as may be
                  requested by the Chair of the Audit Committee;

            (b)   the  Audit  Committee  shall  meet  privately  in  executive
                  sessions at each  meeting  with  management,  the manager of
                  internal  auditing,  the  independent  auditors,  and  as  a
                  committee to discuss any matters that the Audit Committee or
                  each of these groups believe should be discussed.

       7.   The independent auditors and internal auditors shall have a direct
            line of communication to the Audit Committee through its chair and
            may bypass management if deemed necessary.  Any employee may bring
            before the Audit Committee  directly and may bypass  management if
            deemed  necessary any matter  involving  questionable,  illegal or
            improper financial practices or transactions.

III    AUDIT COMMITTEE DUTIES AND RESPONSIBILITIES

       1.   The overall  duties and  responsibilities  of the Audit  Committee
            shall be as follows:

            a.    to assist the Board in the discharge of its responsibilities
                  relating  to  the   Corporation's   accounting   principles,
                  reporting  practices and internal  controls and its approval
                  of  the  Corporation's  annual  and  quarterly  consolidated
                  financial statements;

<PAGE>
                                      74


            b.    to  establish  and  maintain a direct line of  communication
                  with the  Corporation's  internal  auditors and  independent
                  auditors and assess their performance;

            c.    to  ensure  that  the  management  of  the  Corporation  has
                  designed, implemented and is maintaining an effective system
                  of internal controls;

            d.    to report  regularly to the Board on the  fulfillment of its
                  duties and responsibilities; and,

            e.    to review annually the Audit Committee Charter and recommend
                  any  changes  to the  Nominating  and  Corporate  Governance
                  Committee for approval by the Board.

       2.   The duties and  responsibilities  of the Audit  Committee  as they
            relate to the independent auditors shall be as follows:

            a.    to select and recommend for appointment by the shareholders,
                  the   Corporation's   independent   auditors,   review   the
                  independence and performance of the independent auditors and
                  approve  any  discharge  of  auditors   when   circumstances
                  warrant;

            b.    to approve the fees and other significant compensation to be
                  paid to the  independent  auditors,  scope and timing of the
                  audit and other related services rendered by the independent
                  auditors;

            c.    to approve  the  independent  auditor's  annual  audit plan,
                  including  scope,  staffing,  locations  and  reliance  upon
                  management  and  internal  audit  department  prior  to  the
                  commencement of the audit;

            d.    to approve proposed non-audit services to be provided by the
                  independent   auditors  except  those   non-audit   services
                  prohibited by legislation;

            e.    on an  annual  basis,  obtain  and  review a  report  by the
                  independent   auditors   describing   (i)  the   independent
                  auditor's  internal  quality  control  procedures;  (ii) any
                  material  issues  raised by the most recent  quality-control
                  review,  or peer review,  of the firm,  or by any inquiry or
                  investigation  by governmental  or professional  authorities
                  within  the  preceding  five  years  respecting  one or more
                  independent  audits carried out by the firm;  and, (iii) any
                  steps  taken to address  any such  issues  arising  from the
                  review,  inquiry or  investigation,  and,  receive a written
                  statement  from  the  independent   auditors  outlining  all
                  significant  relationships  they have  with the  Corporation
                  that  could   impair   the   auditor's   independence.   The
                  Corporation's  independent  auditors  may not be  engaged to
                  perform  prohibited  activities under the Sarbanes-Oxley Act
                  of  2002  or the  rules  of the  Public  Company  Accounting
                  Oversight  Board  or  other  regulatory  bodies,  which  the
                  Corporation is governed by;

            f.    to review and discuss with the  independent  auditors,  upon
                  completion  of  their  audit  and  prior  to the  filing  or
                  releasing annual financial statements:

                  (i)    contents of their report, including :
<PAGE>
                                      75


                         (a)  all critical  accounting  policies and practices
                              used;

                         (b)  all   alternative    treatments   of   financial
                              information within GAAP that have been discussed
                              with  management,  ramifications  of the  use of
                              such  treatments and the treatment  preferred by
                              the independent auditor;

                         (c)  other material  written  communications  between
                              the independent auditor and management;

                  (ii)   scope and quality of the audit work performed;
                  (iii)  adequacy of the Corporation's  financial and auditing
                         personnel;
                  (iv)   cooperation received from the Corporation's personnel
                         during the audit;
                  (v)    internal    resources    used;
                  (vi)   significant   transactions   outside  of  the  normal
                         business of the Corporation;
                  (vii)  significant  proposed adjustments and recommendations
                         for   improving   internal    accounting    controls,
                         accounting principles or management systems;
                  (viii) the non-audit  services  provided by the  independent
                         auditors; and,
                  (ix)   consider the  independent  auditor's  judgments about
                         the quality and  appropriateness of the Corporation's
                         accounting   principles   and   critical   accounting
                         estimates as applied in its financial reporting; and,

            g.    to review and approve a report to  shareholders as required,
                  to be included in the Corporation's Information Circular and
                  Proxy Statement,  disclosing any non-audit services approved
                  by the Audit Committee.

       3.   The duties and  responsibilities  of the Audit  Committee  as they
            relate to the internal auditors shall be as follows:

            a.    to review the budget,  internal  audit function with respect
                  to the organization structure,  staffing,  effectiveness and
                  qualifications   of   the   Corporation's   internal   audit
                  department;

            b.    to review and approve the internal audit plan; and

            c.    to  review   significant   internal   audit   findings   and
                  recommendations  together  with  management's  response  and
                  follow-up thereto.

       4.   The duties and  responsibilities  of the Audit  Committee  as they
            relate to the internal control procedures of the Corporation shall
            be as follows:

            a.    to  review  the  appropriateness  and  effectiveness  of the
                  Corporation's  policies and business  practices which impact
                  on the  financial  integrity of the  Corporation,  including
                  those relating to internal auditing, insurance,  accounting,
                  information  services  and systems and  financial  controls,
                  management reporting and risk management;

            b.    to review any unresolved  issues between  management and the
                  independent   auditors   that  could  affect  the  financial
                  reporting or internal controls of the Corporation; and

<PAGE>
                                      76


            c.    to  periodically  review  the  Corporation's  financial  and
                  auditing procedures and the extent to which  recommendations
                  made  by the  internal  audit  staff  or by the  independent
                  auditors have been implemented.

       5.   Other duties and  responsibilities of the Audit Committee shall be
            as follows:

            a.    to review the Corporation's unaudited quarterly consolidated
                  financial  statements  and related  Management  Discussion &
                  Analysis  including  the impact of unusual items and changes
                  in  accounting  principles  and  estimates and report to the
                  Board with respect thereto;

            b.    to review  the  Corporation's  audited  annual  consolidated
                  financial  statements  and related  Management  Discussion &
                  Analysis  including  the impact of unusual items and changes
                  in  accounting  principles  and  estimates and report to the
                  Board with respect thereto;

            c.    to review and approve  regulatory  filings and  decisions as
                  they  relate  to the  Corporation's  consolidated  financial
                  statements and related Management  Discussion & Analysis and
                  report to the Board thereto with respect to:

                  (i)    the annual report to shareholders;
                  (ii)   the annual information form;
                  (iii)  the annual information form on Form 40-F;
                  (iv)   prospectuses; and,
                  (v)    other disclosure  reports  requiring  approval by the
                         Board;

            d.    to review the appropriateness of the policies and procedures
                  used in the  preparation of the  Corporation's  consolidated
                  financial statements and other required disclosure documents
                  and consider recommendations for any material change to such
                  policies;

            e.    to review with management,  the independent  auditors and if
                  necessary with legal counsel, any litigation, claim or other
                  contingency,  including  tax  assessments  that could have a
                  material  affect upon the  financial  position or  operating
                  results  of the  Corporation  and the  manner in which  such
                  matters have been  disclosed in the  consolidated  financial
                  statements;

            f.    to co-ordinate  meetings with the Reserves  Committee of the
                  Corporation,    the   Corporation's    senior    engineering
                  management, independent evaluating engineers and auditors as
                  required  and  consider   such  further   inquiries  as  are
                  necessary to approve the consolidated financial statements;

            g.    to develop a calendar of  activities to be undertaken by the
                  Audit  Committee  for each  ensuing  year and to submit  the
                  calendar in the  appropriate  format to the Board  following
                  each annual general meeting of shareholders;

            h.    to  perform  any  other  activities   consistent  with  this
                  Charter, the Corporation's By-laws and governing law, as the
                  Audit Committee or the Board deems necessary or appropriate;
                  and,

<PAGE>
                                      77


            i.    to maintain  minutes of meetings  and to report on a regular
                  basis to the Board on  significant  results of the foregoing
                  activities.

The Audit Committee has the authority to conduct any investigation appropriate
to  fulfilling  its  responsibilities,   and  it  has  direct  access  to  the
independent auditors as well as officers and employees of the Corporation. The
Audit  Committee has the authority to retain,  at the  Corporation's  expense,
special legal,  accounting or other  consultants or experts it deems necessary
in the  performance  of its duties.  The  Corporation  shall at all times make
adequate  provisions  for the  payment  of all  fees  and  other  compensation
approved by the Audit  Committee,  to the  Company's  independent  auditors in
connection  with the issuance of its audit report,  or to any  consultants  or
experts employed by the Audit Committee.

<PAGE>

==============================================================================






   THE PREMIUM VALUE,

DEFINED GROWTH, INDEPENDENT




                                                [GRAPIC OMITTED]

                                            [LOGO - CANADIAN NATURAL]

                                               2005 ANNUAL REPORT




==============================================================================


<PAGE>

M A N A G E M E N T'S   R E P O R T

The accompanying  consolidated financial statements and all information in the
annual report are the responsibility of management. The consolidated financial
statements  have been prepared by management in accordance with the accounting
policies  in  the  notes  to  the  consolidated  financial  statements.  Where
necessary, management has made informed judgements and estimates in accounting
for  transactions  that were not  complete at the balance  sheet date.  In the
opinion  of  management,  the  financial  statements  have  been  prepared  in
accordance with Canadian generally accepted accounting principles  appropriate
in the circumstances. The financial information elsewhere in the annual report
has  been  reviewed  to  ensure  consistency  with  that  in the  consolidated
financial statements.

Management  maintains  appropriate  systems of internal control.  Policies and
procedures are designed to give  reasonable  assurance that  transactions  are
appropriately authorized, assets are safeguarded from loss or unauthorized use
and financial records are properly maintained to provide reliable  information
for preparation of financial statements.

PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants,  has
been engaged,  as approved by a vote of the shareholders at the Company's most
recent  Annual  General  Meeting,   to  examine  the  consolidated   financial
statements in accordance with generally  accepted auditing standards in Canada
and provide an  independent  professional  opinion.  Their report is presented
with the consolidated financial statements.

The  Board of  Directors  (the  "Board")  is  responsible  for  ensuring  that
management fulfills its  responsibilities for financial reporting and internal
controls.  The Board exercises this responsibility through the Audit Committee
of the Board. This committee,  which is comprised of non-management directors,
meets  with  management  and the  external  auditors  to satisfy  itself  that
management   responsibilities  are  properly  discharged  and  to  review  the
consolidated  financial  statements before they are presented to the Board for
approval.  The  consolidated  financial  statements  have been approved by the
Board on the recommendation of the Audit Committee.


<TABLE>
<S>                           <C>                                       <C>
/s/ Steve W. Laut             /s/ Douglas A. Proll                      /s/ Randall S. Davis
--------------------          -----------------------                   -----------------------
Steve W. Laut                 Douglas A. Proll CA                       Randall S. Davis CA
President & Chief             Senior Vice President, Finance &          Vice President, Financial
Operating Officer             Chief Financial Officer                   Accounting & Controls
February 21, 2006
</TABLE>


A U D I T O R'S   R E P O R T

TO THE SHAREHOLDERS OF CANADIAN NATURAL RESOURCES LIMITED,

We have audited the consolidated  balance sheets of Canadian Natural Resources
Limited as at December 31, 2005 and 2004 and the  consolidated  statements  of
earnings,  retained earnings and cash flows for each of the years in the three
year period ended December 31, 2005. These consolidated  financial  statements
are the responsibility of the Company's  management.  Our responsibility is to
express an opinion on these financial statements based on our audits.

We  conducted  our  audits in  accordance  with  Canadian  generally  accepted
auditing standards.  Those standards require that we plan and perform an audit
to obtain reasonable  assurance  whether the financial  statements are free of
material misstatement.  An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial  statements.  An audit
also  includes  assessing  the  accounting  principles  used  and  significant
estimates  made by  management,  as well as evaluating  the overall  financial
statement presentation.

In our opinion, these consolidated financial statements present fairly, in all
material  respects,  the financial  position of the Company as at December 31,
2005 and 2004 and the results of its operations and its cash flows for each of
the years in the three year period ended December 31, 2005 in accordance  with
Canadian generally accepted accounting principles.


/s/ PricewaterhouseCoopers LLP

Chartered Accountants
Calgary, Alberta, Canada
February 21, 2006



COMMENTS BY AUDITOR FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES

In the United States, reporting standards for auditors require the addition of
an explanatory  paragraph  (following the opinion  paragraph)  when there is a
change  in  accounting   principles   that  has  a  material   effect  on  the
comparability of the Company's consolidated financial statements,  such as the
change  described in Note 10 to the  consolidated  financial  statements.  Our
report to the shareholders  dated February 21, 2006 is expressed in accordance
with Canadian  reporting  standards which do not require a reference to such a
change in accounting  principles  in the  Auditors'  report when the change is
properly accounted for and adequately disclosed in the consolidated  financial
statements.


/s/ PricewaterhouseCoopers LLP

Chartered Accountants
Calgary, Alberta, Canada
February 21, 2006


74    Management and Auditors' Reports

<PAGE>

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
As at DECEMBER 31
(millions of Canadian dollars)                                           2005           2004
----------------------------------------------------------------------------------------------
<S>                                                                  <C>            <C>
ASSETS
Current assets
  Cash and cash equivalents                                          $     18       $     28
  Accounts receivable and other                                         1,546          1,055
  Future income tax (note 6)                                              487             83
  Current portion of other long-term assets (note 2)                        -             34
----------------------------------------------------------------------------------------------
                                                                        2,051          1,200
Property, plant and equipment (note 3)                                 19,694         17,064
Other long-term assets (note 2)                                           107            108
----------------------------------------------------------------------------------------------
                                                                     $ 21,852       $ 18,372
==============================================================================================
LIABILITIES
Current liabilities
  Accounts payable                                                   $    573       $    379
  Accrued liabilities                                                   1,781          1,019
  Current portion of long-term debt (note 4)                                -            194
  Current portion of other long-term liabilities (note 5)               1,471            260
----------------------------------------------------------------------------------------------
                                                                        3,825          1,852
Long-term debt (note 4)                                                 3,321          3,538
Other long-term liabilities (note 5)                                    1,434          1,208
Future income tax (note 6)                                              5,035          4,450
----------------------------------------------------------------------------------------------
                                                                       13,615         11,048
----------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 7)                                                  2,442          2,408
Retained earnings                                                       5,804          4,922
Foreign currency translation adjustment (note 8)                           (9)            (6)
----------------------------------------------------------------------------------------------
                                                                        8,237          7,324
----------------------------------------------------------------------------------------------
                                                                     $ 21,852       $ 18,372
==============================================================================================
</TABLE>
COMMITMENTS (note 11)

Approved by the Board of Directors:


/s/ Catherine M. Best                  /s/ N. Murray Edwards
--------------------------             --------------------------
Catherine M. Best                      N. Murray Edwards
Chair of the Audit Committee           Vice-Chairman of the Board of Directors
and Director                           and Director



                                        Consolidated Financial Statements   75

<PAGE>

CONSOLIDATED STATEMENTS OF EARNINGS

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
For the years ended December 31
(millions of Canadian dollars, except per common share amounts)        2005             2004         2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                <C>              <C>          <C>
Revenue                                                            $ 10,107         $  7,547     $  6,155
Less: royalties                                                      (1,366)          (1,011)        (872)
-----------------------------------------------------------------------------------------------------------
Revenue, net of royalties                                             8,741            6,536        5,283
-----------------------------------------------------------------------------------------------------------
Expenses
Production                                                            1,663            1,400        1,209
Transportation                                                          270              250          262
Depletion, depreciation and amortization                              2,013            1,769        1,509
Asset retirement obligation accretion (note 5)                           69               51           62
Administration                                                          151              125           87
Stock-based compensation (note 5)                                       723              249          200
Interest, net                                                           149              189          201
Risk management activities (note 10)                                  1,952              434          148
Foreign exchange gain                                                  (132)             (91)        (335)
-----------------------------------------------------------------------------------------------------------
                                                                      6,858            4,376        3,343
-----------------------------------------------------------------------------------------------------------
Earnings before taxes                                                 1,883            2,160        1,940
Taxes other than income tax (note 6)                                    194              165          107
Current income tax (note 6)                                             286              116           92
Future income tax (note 6)                                              353              474          338
-----------------------------------------------------------------------------------------------------------
Net earnings                                                       $  1,050         $  1,405     $  1,403
-----------------------------------------------------------------------------------------------------------
Net earnings per common share (note 9)
  Basic                                                            $   1.96         $   2.62     $   2.62
  Diluted                                                          $   1.95         $   2.60     $   2.53
===========================================================================================================


<CAPTION>

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

-----------------------------------------------------------------------------------------------------------
For the years ended December 31
(millions of Canadian dollars)                                         2005             2004         2003
-----------------------------------------------------------------------------------------------------------
<S>                                                                <C>              <C>          <C>
Balance - beginning of year                                        $  4,922         $  3,650     $  2,424
Net earnings                                                          1,050            1,405        1,403
Dividends on common shares (note 7)                                    (127)            (107)         (81)
Purchase of common shares under Normal Course Issuer Bid (note 7)       (41)             (26)         (96)
-----------------------------------------------------------------------------------------------------------
Balance - end of year                                              $  5,804         $  4,922     $  3,650
===========================================================================================================
</TABLE>


76   Consolidated Financial Statements

<PAGE>

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
For the years ended December 31
(millions of Canadian dollars)                                         2005             2004         2003
----------------------------------------------------------------------------------------------------------
<S>                                                                <C>              <C>          <C>
Operating activities
Net earnings                                                       $  1,050         $  1,405     $  1,403
Non-cash items
  Depletion, depreciation and amortization                            2,013            1,769        1,509
  Asset retirement obligation accretion                                  69               51           62
  Stock-based compensation                                              723              249          200
  Unrealized risk management activities                                 925              (40)           -
  Unrealized foreign exchange gain                                     (103)             (94)        (343)
  Deferred petroleum revenue tax recovery                                (9)             (45)          (9)
  Future income tax                                                     353              474          338
Deferred charges                                                        (31)             (33)          10
Abandonment expenditures                                                (46)             (32)         (40)
Net change in non-cash working capital (note 12)                       (147)             (14)         (48)
----------------------------------------------------------------------------------------------------------
                                                                      4,797            3,690        3,082
----------------------------------------------------------------------------------------------------------
Financing activities
(Repayment) issue of bank credit facilities                            (435)             357         (647)
Issue (repayment) of medium-term notes                                  400             (125)           -
Repayment of senior unsecured notes                                    (194)             (54)         (85)
Repayment of preferred securities                                      (107)               -            -
Issue of US dollar debt securities                                        -              830            -
Repayment of obligations under capital leases                             -               (7)          (8)
Dividends on common shares                                             (121)            (101)         (77)
Issue of common shares on exercise of stock options                       9               24           89
Purchase of common shares                                               (45)             (33)        (144)
Net change in non-cash working capital (note 12)                         19                6          (11)
----------------------------------------------------------------------------------------------------------
                                                                       (474)             897         (883)
----------------------------------------------------------------------------------------------------------
Investing activities
Expenditures on property, plant and equipment                        (5,340)          (4,582)      (2,486)
Net proceeds on sale of property, plant and equipment                   454                7           20
----------------------------------------------------------------------------------------------------------
Net expenditures on property, plant and equipment                    (4,886)          (4,575)      (2,466)
Net proceeds on sale of other assets                                     11                -            -
Net change in non-cash working capital (note 12)                        542              (88)         341
----------------------------------------------------------------------------------------------------------
                                                                     (4,333)          (4,663)      (2,125)
----------------------------------------------------------------------------------------------------------
(Decrease) increase in cash                                             (10)             (76)          74
Cash - beginning of year                                                 28              104           30
----------------------------------------------------------------------------------------------------------
Cash - end of year                                                 $     18         $     28     $    104
==========================================================================================================
</TABLE>


                                        Consolidated Financial Statements   77
<PAGE>


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(tabular amounts in millions of Canadian dollars, unless otherwise stated)


1.   ACCOUNTING POLICIES

Canadian  Natural  Resources  Limited (the "Company") is a senior  independent
crude oil and natural gas  exploration,  development  and  production  company
head-quartered  in Calgary,  Alberta,  Canada.  The Company's  operations  are
focused  in North  America,  largely  in western  Canada,  the United  Kingdom
portion of the North Sea and Offshore West Africa.  Within western Canada, the
Company is developing  its Horizon Oil Sands  Project (the "Horizon  Project")
and maintains its midstream activities. The Horizon Project involves a plan to
recover  bitumen  through mining  operations,  while the midstream  activities
include the Company's  pipeline  operations and an  electricity  co-generation
system.

The  consolidated  financial  statements  of the Company have been prepared in
accordance with accounting  principles generally accepted in Canada ("Canadian
GAAP"). A summary of differences  between accounting  principles in Canada and
those generally accepted in the United States ("US GAAP") is contained in note
15.

Significant accounting policies are summarized as follows:

(A)  PRINCIPLES OF CONSOLIDATION
The consolidated  financial statements include the accounts of the Company and
all of  its  subsidiaries  and  partnerships.  A  significant  portion  of the
Company's  activities are conducted  jointly with others and the  consolidated
financial statements reflect only the Company's proportionate interest in such
activities.

(B)  MEASUREMENT UNCERTAINTY
Management  has made  estimates  and  assumptions  regarding  certain  assets,
liabilities,  revenues and  expenses in the  preparation  of the  consolidated
financial   statements.   Such   estimates   primarily   relate  to  unsettled
transactions  and  events  as  of  the  date  of  the  consolidated  financial
statements. Accordingly, actual results may differ from estimated amounts.

Depletion,  depreciation and  amortization,  and amounts used for ceiling test
calculations  are based on estimates of crude oil and natural gas reserves and
commodity  prices,  production  expenses and capital costs required to develop
and  produce  those  reserves.  Substantially  all  of the  Company's  reserve
estimates are evaluated  annually by independent  engineering  firms. By their
nature, estimates of reserves and the related future cash flows are subject to
measurement  uncertainty,  and the impact of  differences  between  actual and
estimated amounts on the consolidated  financial  statements of future periods
could be material.

The  calculation of asset  retirement  obligations  includes  estimates of the
future costs to settle the asset retirement obligation, the timing of the cash
flows to settle the obligation,  and the future inflation rates. The impact of
differences  between actual and estimated  costs,  timing and inflation on the
consolidated financial statements of future periods could be material.

The measurement of petroleum  revenue tax expense and the related provision in
the consolidated  financial  statements are subject to uncertainty  associated
with future  recoverability  of crude oil and natural gas reserves,  commodity
prices and the timing of future events, which could result in material changes
to deferred amounts.

(C)  CASH AND CASH EQUIVALENTS
Cash  comprises  cash on hand and demand  deposits.  Other  investments  (term
deposits and  certificates  of deposit)  with an original  term to maturity of
three months or less are reported as cash equivalents on the balance sheet.

(D)  PROPERTY, PLANT AND EQUIPMENT
The  Company  follows  the full cost  method of  accounting  for crude oil and
natural gas properties  and equipment as prescribed by the Canadian  Institute
of Chartered  Accountants  ("CICA").  Accordingly,  all costs  relating to the
exploration  for and  development  of crude oil and natural gas  reserves  are
capitalized and accumulated in country-by-country cost centres. Administrative
overhead  incurred during the development  phase of large capital  projects is
capitalized  until the projects are available for their intended use. Proceeds
on disposal of  properties  are  ordinarily  deducted  from such costs without
recognition  of  profit or loss  except  where  such  disposal  constitutes  a
significant portion of the Company's reserves in that country.

Contractual  arrangements  that meet the definition of a lease as specified in
Emerging Issues  Committee  ("EIC") 150 - "Determining  Whether an Arrangement
Contains a Lease" are accounted for as capital  leases or operating  leases as
appropriate.


78    Notes to the Consolidated Financial Statements

<PAGE>

For mining  activities,  property  acquisition,  construction  and development
costs are capitalized.  The Company reviews the recoverability of the carrying
amount of its mining properties when events or circumstances indicate that the
carrying amounts may not be recoverable.

(E)  DEPLETION, DEPRECIATION AND AMORTIZATION
Costs  related to each cost  centre  are  depleted  on the  unit-of-production
method based on the estimated proved reserves of that country.  Volumes of net
production and net reserves before royalties are converted to equivalent units
on the  basis  of  estimated  relative  energy  content.  In  determining  its
depletion base, the Company includes  estimated future costs to be incurred in
developing  proved  reserves and excludes the cost of unproved  properties and
major development  projects.  Unproved properties are assessed periodically to
determine whether  impairment has occurred.  When proved reserves are assigned
or the value of unproved  property is considered  to be impaired,  the cost of
the  unproved  property  or the  amount  of the  impairment  is added to costs
subject to  depletion.  Certain costs for major  development  projects are not
subject to depletion until the projects are available for their intended uses.
Processing and production  facilities are depreciated on a straight-line basis
over their estimated lives.

The  Company  reviews  the  carrying  amount of its crude oil and  natural gas
properties  ("the  properties")  relative to their  recoverable  amount  ("the
ceiling test") for each cost centre at each annual balance sheet date, or more
frequently if circumstances  or events indicate  impairment may have occurred.
The recoverable  amount is calculated as the  undiscounted  cash flow from the
properties  using proved reserves and expected future prices and costs. If the
carrying  amount  of the  properties  exceeds  their  recoverable  amount,  an
impairment  loss is recognized  in depletion  equal to the amount by which the
carrying  amount of the  properties  exceeds  their fair value.  Fair value is
calculated  as the cash flow from those  properties  using proved and probable
reserves  and  expected  future  prices and costs,  discounted  at a risk-free
interest rate.

Midstream assets are depreciated on a straight-line basis over their estimated
lives.  The Company reviews the  recoverability  of the carrying amount of the
midstream  assets  when events or  circumstances  indicate  that the  carrying
amount  might not be  recoverable.  If the  carrying  amount of the  midstream
assets  exceeds their  recoverable  amount,  an  impairment  loss equal to the
amount by which the carrying amount of the midstream assets exceeds their fair
value is recognized in depreciation.

Head office  capital  assets are  amortized on a declining  balance basis over
their estimated useful lives.

(F)  CAPITALIZED INTEREST
Beginning in 2005,  following the Board of Directors'  approval of the Horizon
Project, the Company commenced  capitalization of construction period interest
based  on  costs  incurred  and  the  Company's  cost of  borrowing.  Interest
capitalization will cease once construction is substantially  complete and the
Horizon Project is available for its intended use.

(G)  DEFERRED CHARGES
Deferred charges  primarily  include deferred  financing costs associated with
the issuance of long-term debt and settlement  costs of long-term  natural gas
contracts.  Deferred  charges  are  amortized  over the  original  term of the
related instrument.

(H) ASSET RETIREMENT OBLIGATIONS
The Company provides for future asset  retirement  obligations on its resource
properties,  facilities,  production  platforms and gathering  system based on
current legislation and industry operating practices. The fair values of asset
retirement obligations related to property, plant and equipment are recognized
as a  liability  in the period in which they are  incurred.  Retirement  costs
equal to the fair value of the asset retirement obligations are capitalized as
part of the cost of the  associated  property,  plant  and  equipment  and are
amortized to expense through  depletion and depreciation  over the life of the
asset.  The fair  value of an asset  retirement  obligation  is  estimated  by
discounting  the  expected  future  cash flows to settle the asset  retirement
obligation at the Company's average  credit-adjusted  risk-free interest rate.
In subsequent  periods,  the asset  retirement  obligation is adjusted for the
passage  of time and for  changes  in the  amount or timing of the  underlying
future cash flows.  Actual  expenditures  are charged  against the accumulated
asset retirement obligation as incurred.

(I)   FOREIGN CURRENCY TRANSLATION
Foreign operations that are  self-sustaining  are translated using the current
rate method.  Under this method,  assets and  liabilities  are  translated  to
Canadian  dollars from their  functional  currency  using the exchange rate in
effect at the  consolidated  balance  sheet date.  Revenues  and  expenses are
translated to Canadian dollars at the monthly average exchange rates. Gains or
losses  on  translation  are  included  in the  foreign  currency  translation
adjustment in shareholders' equity in the consolidated balance sheets.

Foreign  operations  that are  integrated  are  translated  using the temporal
method.  For foreign currency balances and integrated  subsidiaries,  monetary
assets and liabilities are translated to Canadian dollars at the exchange rate
in effect at the  consolidated  balance  sheet date.  Non-monetary  assets and
liabilities are translated at the exchange rate in effect when the assets were
acquired or


                           Notes to the Consolidated Financial Statements   79
<PAGE>


obligations incurred. Revenues and expenses are translated to Canadian dollars
at the monthly average exchange rates. Provisions for depletion,  depreciation
and amortization  are translated at the same rate as the related items.  Gains
or losses  on  translation  are  included  in the  consolidated  statement  of
earnings.

Gains or losses on the translation of long-term debt denominated in US dollars
are either recognized in net earnings immediately,  or in the foreign currency
translation  adjustment  (note 8) for  translation  gains or  losses  for that
portion  of  the  US  dollar   denominated  debt  designated  as  a  hedge  of
self-sustaining foreign operations.

(J)  REVENUE RECOGNITION
Revenue from the  production of crude oil and natural gas is  recognized  when
title  passes to the  customer  and  delivery  has taken  place.  The  Company
assesses  customer  creditworthiness,  both before entering into contracts and
throughout the revenue recognition process.

Revenue as reported  represents  the Company's  share and is presented  before
royalty payments to governments and other mineral  interest  owners.  Revenue,
net of royalties  represents  the Company's  share after  royalty  payments to
governments and other mineral interest owners.

(K)  TRANSPORTATION COSTS
Transportation  costs  incurred  to  transport  crude oil and  natural  gas to
customers  are recorded as a separate  cost in the  consolidated  statement of
earnings.

(L)  PRODUCTION SHARING CONTRACT
Production  generated from Offshore West Africa is currently  shared under the
terms of various Production  Sharing Contracts  ("PSC").  Revenues are divided
into cost recovery revenues and profit revenues.  Cost recovery revenues allow
the  Company to recover  its share and the  government's  share of capital and
operating  costs carried by the Company.  Profit revenues are allocated to the
Company in accordance with its respective equity interest, after a portion has
been  allocated  to the  government.  Cost  recovery  and profit  revenues are
reported as sales revenues. The government's share of revenues attributable to
the Company's equity interest, except for income tax, is reported as a royalty
expense in accordance with the PSCs.

(M)  PETROLEUM REVENUE TAX
The Company accounts for the United Kingdom  petroleum  revenue tax ("PRT") by
the life-of-the-field method. The total future liability or recovery of PRT is
estimated using current  reserves and anticipated  sales prices and costs. The
estimated  future PRT is  apportioned  to  accounting  periods on the basis of
total estimated future operating income. Changes in the estimated total future
PRT are accounted for prospectively.

(N)  INCOME TAX
The Company follows the liability method of accounting for income taxes. Under
this method,  future income tax assets and liabilities are recognized based on
the estimated tax effects of temporary  differences  in the carrying  value of
assets and  liabilities  in the  consolidated  financial  statements and their
respective  tax bases,  using  income tax rates  substantively  enacted on the
consolidated balance sheet date. The effect of a change in income tax rates on
the future income tax assets and  liabilities is recognized in net earnings in
the period of the change.

(O)  STOCK-BASED COMPENSATION PLANS
The  Company  accounts  for  its  stock-based  compensation  plans  using  the
intrinsic  value method.  The Company's  Stock Option Plan (the "Option Plan")
provides current employees with the right to elect to receive common shares or
direct cash  payment in  exchange  for options  surrendered.  A liability  for
potential cash  settlements  under the Option Plan is accrued over the vesting
period of the stock options based on the difference between the exercise price
of the stock options and the market price of the Company's common shares. This
liability is revalued at each reporting date to reflect  changes in the market
price of the Company's  common shares,  with the net change  recognized in net
earnings,  or capitalized  during the  construction  period in the case of the
Horizon  Project.  When  stock  options  are  surrendered  for cash,  the cash
settlement  paid reduces the  outstanding  liability.  When stock  options are
exercised  for common  shares  under the Option  Plan,  consideration  paid by
employees and any previously  recognized  liability  associated with the stock
options are recorded as share capital.

The  Company  has an  employee  stock  savings  plan and a stock  bonus  plan.
Contributions  to the employee stock savings plan are recorded as compensation
expense at the time of the contribution. Contributions to the stock bonus plan
are recognized as compensation expense over the related vesting period.


80   Notes to the Consolidated Financial Statements
<PAGE>


(P)  RISK MANAGEMENT ACTIVITIES
The Company utilizes various  derivative  financial  instruments to manage its
commodity  price,  currency  and interest  rate  exposures.  These  derivative
financial  instruments  are not  used for  trading  or  speculative  purposes.
Changes in fair value of derivative financial instruments designated as hedges
are not recognized in net earnings until such time as the corresponding  gains
or losses on the related  hedged  items are also  recognized.  Changes in fair
value of  derivative  financial  instruments  not  designated  as  hedges  are
recognized in the balance sheet each period with the offset  reflected in risk
management activities in the consolidated statements of earnings.

The Company  formally  documents all hedging  transactions at the inception of
the hedging  relationship,  in accordance  with the Company's risk  management
policies. The effectiveness of the hedging relationship is evaluated,  both at
inception of the hedge and on an ongoing basis.

The Company enters into commodity price contracts to manage  anticipated sales
of crude oil and  natural  gas  production  in order to protect  cash flow for
capital expenditure programs.  Gains or losses on these contracts are included
in risk management activities.

The Company  enters into interest rate swap  agreements to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. Gains or losses on interest
rate swap  contracts  designated  as hedges are included in interest  expense.
Gains or losses on non-designated interest rate contracts are included in risk
management activities.

Cross  currency  swap  agreements  are  periodically  used to manage  currency
exposure on US dollar  denominated  long-term  debt.  The cross  currency swap
contracts  require the  periodic  exchange of  payments  with the  exchange at
maturity of notional  principal amounts on which the payments are based. Gains
or losses on cross currency swap  contracts  designated as hedges are included
in interest expense.

Gains or losses on the  termination  of financial  instruments  that have been
accounted for as hedges are deferred  under other assets or liabilities on the
consolidated  balance  sheets and amortized into net earnings in the period in
which  the  underlying  hedged  transaction  is  recognized.  In the  event  a
designated  hedged  item  is  sold,  extinguished  or  matures  prior  to  the
termination of the related derivative  instrument,  any unrealized  derivative
gain or loss is recognized immediately in net earnings. Gains or losses on the
termination  of  financial  instruments  that have not been  accounted  for as
hedges are recognized in net earnings immediately.

(Q)  PER COMMON SHARE AMOUNTS
The Company uses the treasury stock method to determine the dilutive effect of
stock  options  and other  dilutive  instruments.  This  method  assumes  that
proceeds received from the exercise of in-the-money stock options not included
as a liability are used to purchase  common shares at the average market price
during the year. The dilutive  effect of convertible  securities is calculated
by applying the "if-converted"  method,  which assumes that the securities are
converted at the beginning of the period and that income items are adjusted to
net earnings.

(R)  RECENTLY ISSUED ACCOUNTING STANDARDS UNDER CANADIAN GAAP

FINANCIAL INSTRUMENTS

In January 2005, the CICA issued four new standards relating to the accounting
for and disclosure of financial instruments.

     o    Section  3855  --  "Financial   Instruments   --   Recognition   and
          Measurement" prescribes when a financial asset, financial liability,
          or non-financial derivative is to be recognized on the balance sheet
          as well as its measurement  amount.  This Section also specifies how
          financial   instruments  gains  and  losses  are  to  be  presented.
          Transitional  provisions  for this Section vary based on the type of
          financial instruments under consideration.

     o    Section 3865 -- "Hedges" expands on existing Accounting Guideline 13
          -- "Hedging  Relationships,"  and  Section  1650  "Foreign  Currency
          Translation,"  by specifying  how hedge  accounting is to be applied
          and what  disclosures are necessary when it is applied.  Retroactive
          application of this Section is not permitted.

     o    Section 1530 - "Comprehensive  Income"  introduces new standards for
          reporting and  disclosure  of  comprehensive  income.  Comprehensive
          income is the change in equity (net assets) of the Company  during a
          reporting   period   from   transactions   and  other   events   and
          circumstances  from  non-owner  sources.  It includes all changes in
          equity during a period except those  resulting  from  investments by
          owners and  distributions to owners.  Financial  statements of prior
          periods  are  required  to  be  restated   only  for   non-financial
          instrument items.

     o    Section  3251  -  "Equity"   replaces  Section  3250  "Surplus"  and
          establishes  standards for the presentation of equity and changes in
          equity  during a reporting  period.  Financial  statements  of prior
          periods  are  required  to  be  restated   only  for   non-financial
          instrument  items.  For  all  other  items,   comparative  financial
          statements  presented  are not  restated,  but an  adjustment to the
          opening  balance of accumulated  other  comprehensive  income may be
          required.


                           Notes to the Consolidated Financial Statements   81
<PAGE>

The  Company  plans to adopt  these  new  standards  for  interim  and  annual
financial  statements  effective  January 1, 2007. The effect on the Company's
consolidated financial statements cannot be reasonably determined at this time
as the  financial  derivatives  outstanding  at  December  31,  2006 and their
related fair values are not known.

(S)  COMPARATIVE FIGURES
Certain figures provided for prior years have been  reclassified to conform to
the  presentation  adopted in 2005.  Common  share data has been  restated  to
reflect the two-for-one share split in May 2005.

2.   OTHER LONG-TERM ASSETS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------
                                                                                                    2005          2004
------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>            <C>
Deferred charges                                                                                $    107       $    76
Risk management (note 10)                                                                              -            66
------------------------------------------------------------------------------------------------------------------------
                                                                                                     107           142
Less: current portion                                                                                  -            34
------------------------------------------------------------------------------------------------------------------------
                                                                                                $    107       $   108
========================================================================================================================
</TABLE>


3.   PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
                                                        2005                                        2004
------------------------------------------------------------------------------------------------------------------------
                                                 Accumulated                                 Accumulated
                                                   depletion                                   depletion
                                                         and                                         and
                                          Cost   depreciation          Net          Cost    depreciation          Net
------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>           <C>           <C>           <C>             <C>           <C>
Crude oil and natural gas
  North America                      $  22,258     $   7,948     $  14,310     $  19,750       $   6,356     $  13,394
  North Sea                              2,703         1,022         1,681         2,550             727         1,823
  Offshore West Africa                   1,547           294         1,253         1,091             190           901
  Other                                     27            14            13            22              14             8
Horizon Project                          2,169             -         2,169           672               -           672
Midstream                                  251            48           203           241              32           209
Head office                                124            59            65           101              44            57
------------------------------------------------------------------------------------------------------------------------
                                     $  29,079     $   9,385     $  19,694     $  24,427       $   7,363     $  17,064
========================================================================================================================
</TABLE>

During  the  year  ended   December   31,   2005,   the  Company   capitalized
administrative  overhead  of  $41  million  (2004  - $49  million,  2003 - $35
million) relating to exploration and development in the North Sea and Offshore
West Africa and $236 million (2004 - $35 million, 2003 - $23 million) in North
America, primarily related to the Horizon Project.

During the year ended December 31, 2005, the Company  capitalized  $72 million
(2004 and 2003 - $nil) in  construction  period  interest costs related to the
Horizon Project.

Included in property,  plant and equipment are unproved  properties  and major
development projects that are not subject to depletion or depreciation:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
                                                                                                   2005          2004
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                                            <C>           <C>
 Crude oil and natural gas
   North America                                                                               $  1,372      $  1,028
   North Sea                                                                                         28            44
   Offshore West Africa                                                                             182           528
   Other                                                                                             13             8
 Horizon Project                                                                                  2,169           672
-----------------------------------------------------------------------------------------------------------------------
                                                                                               $  3,764      $  2,280
=======================================================================================================================
</TABLE>


82   Notes to the Consolidated Financial Statements

<PAGE>

The  Company  has  used  the  following   estimated  benchmark  future  prices
("escalated pricing") in its ceiling test prepared in accordance with Canadian
GAAP, as at December 31, 2005:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
                                                                                                                        Average
                                                                                                                  annual change
                                                2006             2007          2008          2009          2010      thereafter
--------------------------------------------------------------------------------------------------------------------------------
<S>                                          <C>             <C>           <C>           <C>           <C>                 <C>
Crude oil and NGLs
North America
  WTI at Cushing (US$/bbl)                   $  60.81        $  61.61      $  54.60      $  50.19      $  47.76            1.5%
  Hardisty Heavy 12(degree) API (C$/bbl)     $  37.07        $  37.29      $  34.23      $  32.27      $  31.15            1.6%
  Edmonton Par (C$/bbl)                      $  70.07        $  70.99      $  62.73      $  57.53      $  54.65            1.5%
North Sea and Offshore West Africa
  North Sea Brent (US$/bbl)                  $  58.81        $  59.58      $  52.54      $  48.10      $  45.64            1.5%
--------------------------------------------------------------------------------------------------------------------------------
Natural gas
North America
  Henry Hub Louisiana (US$/mmbtu)            $  11.59        $  10.11      $   8.50      $   7.58      $   7.32            1.5%
  AECO (C$/mmbtu)                            $  11.58        $  10.84      $   8.95      $   7.87      $   7.57            1.5%
  Huntingdon/Sumas (C$/mmbtu)                $  11.34        $  10.70      $   8.81      $   7.73      $   7.43            1.5%
================================================================================================================================
</TABLE>

4.   LONG-TERM DEBT

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
                                                                                                           2005           2004
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                     <C>            <C>
Bank credit facilities
  Bankers' acceptances                                                                                  $   122        $     -
  US dollar bankers' acceptances (2005 - US$nil, 2004 - US$471 million)                                       -            557

Medium-term notes
  7.40% unsecured debentures due March 1, 2007                                                              125            125
  4.95% unsecured debentures due June 1, 2015                                                               400              -

Senior unsecured notes
  7.69% due December 19, 2005 (2005 - US$nil, 2004 - US$125 million)                                          -            194
  Adjustable rate due May 27, 2009 (2005 - US$93 million, 2004 - US$93 million)                             108            112

Preferred securities
  8.30% due June 25,2011 (2005 - US$nil, 2004 - US$80 million)                                                -             96

US dollar debt securities
  6.70% due July 15, 2011 (2005 - US$400 million, 2004 - US$400 million)                                    467            482
  5.45% due October 1, 2012 (2005 - US$350 million, 2004 - US$350 million)                                  408            421
  4.90% due December 1, 2014 (2005 - US$350 million, 2004 - US$350 million)                                 408            421
  7.20% due January 15, 2032 (2005 - US$400 million, 2004 - US$400 million)                                 467            482
  6.45% due June 30, 2033 (2005 - US$350 million, 2004 - US$350 million)                                    408            421
  5.85% due February 1, 2035 (2005 - US$350 million, 2004 - US$350 million)                                 408            421
-------------------------------------------------------------------------------------------------------------------------------
                                                                                                          3,321          3,732
Less: current portion of long-term debt                                                                       -            194
-------------------------------------------------------------------------------------------------------------------------------
                                                                                                        $ 3,321        $ 3,538
===============================================================================================================================
</TABLE>

BANK CREDIT FACILITIES

As at December  31, 2005 the Company had in place  unsecured  syndicated  bank
credit facilities of $3,425 million, comprised of:

     o    a $100 million operating demand facility;
     o    a  two-tranche  revolving  credit and term loan  facility  of $1,825
          million; and
     o    a 5-year revolving and term loan facility of $1,500 million.

The first  $1,000  million  tranche of the $1,825  million  facility  is fully
revolving for a period of three years to June 2008. The second tranche of $825
million  is fully  revolving  for a period of five  years to June  2010.  Both
tranches are extendible  annually for one-year periods at the mutual agreement
of the  Company  and the  lenders.  If not  extended,  the full  amount of the
outstanding  principal would be repayable at the end of year two following the
initiation of the term period.  The $1,500 million  revolving  credit and term
loan facility has a five-year term, with three, one-year extension provisions.
If the facility is not extended,  the amount outstanding would be repayable in
December 2009. These facilities provide that the borrowings may be made by way
of operating advances,  prime loans, bankers' acceptances,  US base rate loans
or US dollar LIBOR advances,  which bear interest at the bank's prime rates or
at money market rates plus applicable margins.

The weighted average interest rate of the bank credit  facilities  outstanding
at  December  31,  2005,  was 5.44%  (2004 - 3.47%).  The  Company  also has a
(pound)15  million demand  overdraft  credit facility related to the Company's
North Sea operations. At December 31, 2005 there were no amounts drawn on this
facility.

In addition to the outstanding debt, as at December 31, 2005 letters of credit
aggregating $24 million (2004 - $24 million) have been issued.


                           Notes to the Consolidated Financial Statements   83

<PAGE>


MEDIUM-TERM NOTES
In May 2005, the Company issued $400 million of debt securities  maturing June
2015, bearing interest at 4.95%. Proceeds from the securities issued were used
to repay bankers' acceptances under the Company's bank credit facilities.

In May 2004,  the Company repaid the $125 million 6.85%  unsecured  debentures
due May 2004, which were issued under a previous medium-term note program.

In January 2006, the Company issued $400 million of debt  securities  maturing
January 2013,  bearing interest at 4.50%.  Proceeds from the securities issued
were used to repay  bankers'  acceptances  under  the  Company's  bank  credit
facilities.  After  issuing  these  securities,  the Company has $1.6  billion
remaining on its $2 billion shelf  prospectus filed in August 2005 that allows
for the issue of medium-term  notes in Canada until September 2007. If issued,
these securities will bear interest as determined at the date of issuance.

SENIOR UNSECURED NOTES
In December 2005, the Company repaid the US$125 million 7.69% senior unsecured
notes. The 6.42% senior unsecured notes were repaid in May 2004.

The  adjustable  rate senior  unsecured  notes bear interest at 6.54% and have
annual principal  repayments of US$31 million  commencing in May 2007, through
May 2009.

PREFERRED SECURITIES
In September  2005,  the Company  redeemed the US$80 million  8.30%  preferred
securities due May 25, 2011 for cash consideration of US$91 million, including
an early  repayment  premium  of US$11  million  as  required  under  the Note
Purchase Program.

US DOLLAR DEBT SECURITIES
In June 2005,  the Company filed a short form  prospectus  that allows for the
issue of up to US$2 billion of debt securities in the United States until July
2007. If issued, these securities will bear interest determined as at the date
of issuance.

In  December  2004,  the  Company  issued  US$350  million of debt  securities
maturing  December 2014,  bearing interest at 4.90% and US$350 million of debt
securities  maturing February 2035,  bearing interest at 5.85%.  Proceeds from
the  securities  issued  were  used to repay  bankers'  acceptances  under the
Company's  bank  credit  facilities.  The Company  has  entered  into  certain
interest rate swap contracts to convert the fixed rate interest  coupon into a
floating interest rate on the securities due December 2014 (note 10).

REQUIRED DEBT REPAYMENTS

Required debt repayments are as follows:

------------------------------------------------------------------------------
Year                                                                Repayment
------------------------------------------------------------------------------
2006                                                                 $      -
2007                                                                 $    161
2008                                                                 $     36
2009                                                                 $     36
2010                                                                 $      -
Thereafter                                                           $  2,966
==============================================================================


No debt  repayments  are reflected for the bank credit  facilities  due to the
extendable nature of the facilities.

5.   OTHER LONG-TERM LIABILITIES

------------------------------------------------------------------------------
                                                         2005            2004
------------------------------------------------------------------------------
Asset retirement obligations                         $  1,112        $  1,119
Stock-based compensation                                  891             323
Risk management (note 10)                                 885              26
Other                                                      17               -
------------------------------------------------------------------------------
                                                        2,905           1,468
Less: current portion                                   1,471             260
------------------------------------------------------------------------------
                                                     $  1,434        $  1,208
==============================================================================


84    Notes to the Consolidated Financial Statements

<PAGE>


ASSET RETIREMENT OBLIGATIONS
At December 31, 2005,  the Company's  total  estimated  undiscounted  costs to
settle its asset retirement  obligations with respect to crude oil and natural
gas properties and facilities was approximately  $3,325 million (2004 - $3,060
million).  Payments to settle these asset retirement obligations will occur on
an  ongoing  basis  over a period  of  approximately  60 years  and have  been
discounted using an average credit-adjusted risk-free interest rate of 6.8%. A
reconciliation of the discounted asset retirement obligations is as follows:


------------------------------------------------------------------------------
                                                         2005            2004
------------------------------------------------------------------------------
Asset retirement obligations
Balance - beginning of year                          $  1,119        $    897
  Liabilities incurred                                     47             339
  Liabilities settled                                     (46)            (32)
  Asset retirement obligation accretion                    69              51
  Revision of estimates                                   (56)            (86)
  Foreign exchange                                        (21)            (50)
------------------------------------------------------------------------------
Balance - end of year                                $  1,112       $   1,119
==============================================================================

The  Company's  pipelines  have an  indeterminant  life and therefore the fair
values of the  related  asset  retirement  obligations  cannot  be  reasonably
determined. The asset retirement obligations for these assets will be recorded
in the first year in which the lives of the assets are determinable.

STOCK-BASED COMPENSATION
The Company  recognizes a liability for the potential cash  settlements  under
its Option Plan.  The current  portion  represents  the maximum  amount of the
liability  payable  within the next 12-month  period if all vested options are
surrendered for cash settlement.

------------------------------------------------------------------------------
                                                         2005            2004
------------------------------------------------------------------------------
Stock-based compensation
Balance - beginning of year                          $    323        $    171
  Stock-based compensation provision                      723             249
  Cash payment for options surrendered                   (227)            (80)
  Transferred to common shares                            (29)            (38)
  Capitalized to Horizon Project                          101              21
------------------------------------------------------------------------------
Balance - end of year                                     891             323
Less: current portion of stock-based compensation         629             243
------------------------------------------------------------------------------
                                                     $    262        $     80
==============================================================================


6.   TAXES

TAXES OTHER THAN INCOME TAX

------------------------------------------------------------------------------
                                             2005        2004            2003
------------------------------------------------------------------------------
Current petroleum revenue tax              $  181    $    190        $    106
Deferred petroleum revenue tax recovery        (9)        (45)            (9)
Provincial capital taxes and surcharges        22          20              10
------------------------------------------------------------------------------
                                           $  194    $    165        $    107
==============================================================================

INCOME TAX

The provision for income tax is as follows:

------------------------------------------------------------------------------
                                                2005        2004         2003
------------------------------------------------------------------------------
Current income tax expense
  Current income tax - North America          $   82    $     89     $     43
  Large Corporations Tax - North America          16          11           16
  Current income tax - North Sea                 155           2           23
  Current income tax - Offshore West Africa       32          13           10
  Current income tax - other                       1           1            -
------------------------------------------------------------------------------
                                                 286         116           92
Future income tax expense                        353         474          338
------------------------------------------------------------------------------
Income tax                                    $  639    $    590     $    430
==============================================================================


                           Notes to the Consolidated Financial Statements   85

<PAGE>


The provision for income tax is different from the amount computed by applying
the combined  statutory  Canadian  federal and provincial  income tax rates to
earnings before taxes. The reasons for the difference are as follows:

<TABLE>
<CAPTION>
                                                                   2005           2004            2003
--------------------------------------------------------------------------------------------------------
<S>                                                            <C>            <C>             <C>
Canadian statutory income tax rate                                38.0%          39.3%           41.1%
--------------------------------------------------------------------------------------------------------
Income tax provision at statutory rate                         $    716       $    849        $    797
Effect on income taxes of:
  Non-deductible portion of Canadian crown payments                 309            221             285
  Canadian resource allowance                                      (293)          (270)           (281)
  Large Corporations Tax                                             16             11              16
  Deductible UK petroleum revenue tax                               (65)           (57)            (40)
  Foreign tax rate differentials                                     (1)           (31)             20
  Federal income tax rate reductions                                  -              -            (247)
  Provincial income tax rate reductions                             (19)           (66)            (31)
  Non-taxable portion of foreign exchange                           (15)           (36)           (103)
  Attributed Canadian Royalty Income                                (21)            (4)              4
  Other                                                              12            (27)             10
--------------------------------------------------------------------------------------------------------
Income tax                                                     $    639       $    590        $    430
========================================================================================================
</TABLE>


The following table summarizes the temporary differences that give rise to the
net future income tax asset and liability:

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------
                                                                                  2005            2004
--------------------------------------------------------------------------------------------------------
<S>                                                                           <C>             <C>
Future income tax liabilities
  Property, plant and equipment                                               $  3,960        $  3,677
  Timing of partnership items                                                    1,646           1,254
  Unrealized foreign exchange gain on long-term debt                               112             102
  Risk management activities                                                         -              19
  Other                                                                             31              43
Future income tax assets
  Asset retirement obligations                                                    (384)           (418)
  Capital loss carryforwards                                                       (79)            (92)
  Attributed Canadian Royalty Income                                               (75)            (54)
  Stock-based compensation                                                        (300)           (106)
  Risk management activities                                                      (304)              -
Deferred petroleum revenue tax                                                     (59)            (58)
--------------------------------------------------------------------------------------------------------
Future income tax liability                                                      4,548           4,367
Less: future income tax asset                                                     (487)            (83)
--------------------------------------------------------------------------------------------------------
Net future income tax liability                                               $  5,035        $  4,450
========================================================================================================
</TABLE>

A  significant  portion of North  America's  taxable  income is  generated  by
partnerships. Income taxes are incurred on the partnerships' taxable income in
the year following their inclusion in the Company's consolidated net earnings.
Current  income tax will vary and is  dependent  upon the nature and amount of
capital expenditures incurred in Canada.

During 2005, the Government of British Columbia enacted  legislation to reduce
its corporate income tax rate by 1.5%,  effective July 1, 2005, resulting in a
$19 million reduction in the Company's future income tax liability.

During 2004,  the  Government  of Alberta  enacted  legislation  to reduce its
corporate income tax rate by 1.0% effective April 1, 2004,  resulting in a $66
million reduction in the Company's future income tax liability.

During 2003,  the  Government  of Alberta  enacted  legislation  to reduce its
corporate  income tax rate by 0.5% effective  April 1, 2003. Also during 2003,
the Canadian federal government enacted  legislation to change the taxation of
resource  income.  The  legislation  reduces the corporate  income tax rate on
resource  income  from 28% to 21% over five years  beginning  January 1, 2003.
Over the same period, the deduction for resource allowance is being phased out
and a  deduction  for  actual  crown  royalties  paid is being  phased in. The
Company's  future income tax liability was reduced by $31 million with respect
to the Alberta  corporate  income tax rate  reduction and by $247 million with
respect to the federal resource income tax rate changes.


86    Notes to the Consolidated Financial Statements
<PAGE>


7.   SHARE CAPITAL

AUTHORIZED

200,000 Class 1 preferred shares with a stated value of $10.00 each.
Unlimited number of common shares without par value.

<TABLE>
<CAPTION>
ISSUED
                                                                            2005                           2004
-------------------------------------------------------------------------------------------------------------------------
                                                                Numbers of                    Numbers of
                                                                    shares                        shares
Common shares                                                   (thousands)         Amount    (thousands)        Amount
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>           <C>             <C>          <C>
Balance - beginning of year                                        536,361       $   2,408       534,926      $   2,353
Issued upon exercise of stock options                                  837               9          3,182            24
Previously recognized liability on stock options
  exercised for common shares                                            -              29              -            38
Purchase of common shares under Normal Course Issuer Bid              (850)            (4)        (1,747)            (7)
-------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                              536,348       $   2,442       536,361      $   2,408
=========================================================================================================================
</TABLE>

SHARE SPLIT
The Company's shareholders approved a subdivision or share split of its issued
and outstanding  common shares on a two-for-one  basis at the Company's Annual
and Special Meeting held on May 5, 2005. All common share and per common share
amounts have been restated to retroactively reflect the share split.

NORMAL COURSE ISSUER BID
In January 2005, the Company announced the renewal of its Normal Course Issuer
Bid through the  facilities  of the Toronto  Stock  Exchange  and the New York
Stock  Exchange  to  purchase  up to  26,818,012  common  shares  or 5% of the
outstanding  common shares of the Company on the date of announcement,  during
the 12-month period beginning January 24, 2005 and ending January 23, 2006. As
at December 31, 2005, the Company had purchased  850,000 common shares (2004 -
1,746,800  common shares) at an average price of $53.29 per common share (2004
- $19.00  per  common  share),  for a total  cost of $45  million  (2004 - $33
million).  Retained  earnings was reduced by $41 million (2004 - $26 million),
representing  the excess of the purchase price of the common shares over their
stated value.

On January  20, 2006, the Company  announced  the renewal of its Normal Course
Issuer Bid through the  facilities of the Toronto  Stock  Exchange and the New
York Stock  Exchange to purchase up to  26,852,545  common shares or 5% of the
outstanding  common  shares of the  Company  on the date of the  announcement,
during the  12-month  period  beginning  January 24,  2006 and ending  January
23,2007. As at February 21, 2006, the Company had not purchased any additional
shares under the Normal Course Issuer Bid.

DIVIDEND POLICY
The Company  pays regular  quarterly  dividends  in January,  April,  July and
October of each year.

On  February  21,  2006,  the Board of  Directors  set the  Company's  regular
quarterly dividend at $0.075 per common share (2005 - $0.059 per common share,
2004 - $0.050 per common share).

STOCK OPTIONS
The Option Plan  provides for granting of stock  options to  employees.  Stock
options  granted  under the  Option  Plan have a maximum  term of six years to
expiry and vest equally over a five-year  period.  The exercise  price of each
stock option  granted is determined at the closing  market price of the common
shares on the Toronto Stock Exchange on the day prior to the grant. Each stock
option granted  permits the holder to purchase one common share of the Company
at the stated exercise price.

In June 2003 the Company  approved a modification to its Option Plan providing
the stock option  holder the right to elect to receive a cash payment equal to
the  difference  between the exercise price of the stock option and the market
price of the Company's  common shares on the date of surrender,  multiplied by
the number of common shares covered by the stock options surrendered,  in lieu
of receiving common shares.  The modification to the Option Plan was accounted
for prospectively.


                           Notes to the Consolidated Financial Statements   87

<PAGE>


For  the  year  ended  December  31, 2005, the  Company  recorded  stock-based
compensation  expense  of  $723  million  (2004  - $249  million,  2003 - $200
million). In 2005, $101 million was capitalized to the Horizon Project (2004 -
$21 million, 2003 - $10 million). As at December 31, 2005, the total liability
for expected cash  settlements  under the Option Plan was $891 million (2004 -
$323  million),  of which $629 million (2004 - $243 million) was included as a
current  liability.  During the year ended December 31, 2005, cash payments of
$227 million were made for 7,523,000  stock options  surrendered  (2004 - cash
payments  of  $80  million  for  7,562,000  stock  options  surrendered).  The
following table summarizes  information  relating to stock options outstanding
at December 31, 2005 and 2004:

<TABLE>
<CAPTION>
                                                                            2005                         2004
-------------------------------------------------------------------------------------------------------------------------
                                                                                  Weighted                      Weighted
                                                                      Stock        average         Stock         average
                                                                    options       exercise       options        exercise
                                                                 (thousands)         price    (thousands)          price
=========================================================================================================================
<S>                                                              <C>             <C>           <C>             <C>
Outstanding - beginning of year                                      32,522       $  12.37        35,578        $   9.86
Granted                                                               7,959       $  32.51         9,722        $  17.95
Exercised for common shares                                            (837)      $   9.81        (3,182)       $   7.55
Surrendered for cash settlement                                      (7,523)      $  10.49        (7,562)       $   9.36
Forfeited                                                            (1,611)      $  19.36        (2,034)       $  13.86
-------------------------------------------------------------------------------------------------------------------------
Outstanding - end of year                                            30,510       $  17.79        32,522        $  12.37
-------------------------------------------------------------------------------------------------------------------------
Exercisable - end of year                                             8,677       $  11.21         7,632        $   9.92
=========================================================================================================================
</TABLE>

The range of exercise  prices of stock options  outstanding and exercisable at
December 31, 2005 was as follows:

<TABLE>
<CAPTION>
                                                        Stock options outstanding             Stock options exercisable
-------------------------------------------------------------------------------------------------------------------------
                                                                   Weighted
                                                       Stock        average       Weighted         Stock        Weighted
                                                     options      remaining        average       options         average
                                                 outstanding           term       exercise   exercisable        exercise
Range of exercise prices                          (thousands)        (years)         price    (thousands)          price
-------------------------------------------------------------------------------------------------------------------------
<S>                                              <C>              <C>            <C>          <C>             <C>
$ 7.85 - $ 9.99                                        8,794           1.41      $    9.63         4,835        $   9.54
$10.00 - $14.99                                        6,690           2.50      $   11.74         2,780        $  11.54
$15.00 - $19.99                                        6,234           3.53      $   17.07           883        $  17.05
$20.00 - $24.99                                        1,568           4.82      $   22.89           176        $  22.55
$25.00 - $29.99                                        4,301           4.18      $   26.26             3        $  26.26
$30.00 - $34.99                                        1,449           4.84      $   33.22             -        $      -
$40.00 - $44.99                                          201           5.45      $   40.25             -        $      -
$45.00 - $49.99                                          251           5.54      $   47.16             -        $      -
$50.00 - $54.99                                          600           5.72      $   54.43             -        $      -
$55.00 - $59.35                                          422           5.88      $   55.89             -        $      -
-------------------------------------------------------------------------------------------------------------------------
                                                      30,510           3.02      $   17.79         8,677        $  11.21
=========================================================================================================================
</TABLE>

8.   FOREIGN CURRENCY TRANSLATION ADJUSTMENT

The foreign  currency  translation  adjustment  represents the unrealized gain
(loss) on the Company's net investment in self-sustaining  foreign operations.
Effective July 1, 2002, the Company  designated  certain US dollar denominated
debt as a hedge against its net investment in US dollar-based  self-sustaining
foreign  operations.  Accordingly,  translation  gains  and  losses on this US
dollar  denominated  debt are  included  in the foreign  currency  translation
adjustment.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------
                                                                                                    2005            2004
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>              <C>
Balance - beginning of year                                                                     $     (6)        $     3
  Unrealized loss on translation of net investment                                                   (12)            (24)
  Hedge of net investment with US dollar denominated debt, net of tax                                  9              15
-------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                                                           $     (9)        $    (6)
=========================================================================================================================
</TABLE>


88    Notes to the Consolidated Financial Statements
<PAGE>

9.   NET EARNINGS PER COMMON SHARE

The  following  table  provides a  reconciliation  between  basic and  diluted
amounts per common share:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------
                                                                                      2005          2004(2)         2003(2)
---------------------------------------------------------------------------------------------------------------------------
(thousands of shares)
<S>                                                                             <C>            <C>             <C>
Weighted average common shares outstanding - basic                                 536,650       536,223         536,940
Effect of dilutive stock options (1)                                                     -             -           4,889
Assumed settlement of preferred securities with common shares                        1,775         4,461           7,816
---------------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding - diluted                               538,425       540,684         549,645
---------------------------------------------------------------------------------------------------------------------------
Net earnings                                                                    $    1,050     $   1,405       $   1,403
Interest on preferred securities, net of tax                                             4             5               5
Revaluation of preferred securities, net of tax                                         (2)           (4)            (18)
---------------------------------------------------------------------------------------------------------------------------
Diluted net earnings                                                            $    1,052     $   1,406       $   1,390
---------------------------------------------------------------------------------------------------------------------------
Net earnings per common share
 Basic                                                                          $     1.96     $    2.62       $    2.62
 Diluted                                                                        $     1.95     $    2.60       $    2.53
===========================================================================================================================
</TABLE>
(1)  The Option Plan  described  in note 7 results in a liability  and expense
     for all outstanding  stock options.  As such, the potential common shares
     associated  with the stock  options are not included in diluted  earnings
     per share effective from June 2003, the date of the modification.
(2)  Restated to reflect two-for-one share split in May 2005.

10.  FINANCIAL INSTRUMENTS

RISK MANAGEMENT

On January 1, 2004, the fair values of all  outstanding  derivative  financial
instruments  that were not designated as hedges for  accounting  purposes were
recorded on the  consolidated  balance sheet,  with an offsetting net deferred
revenue  amount.  Subsequent  net changes in the fair value of  non-designated
financial  instruments have been recognized on the consolidated  balance sheet
and in net earnings.  The estimated  fair value for all  derivative  financial
instruments is based on third party indications.

As at December 31, 2005 and 2004, the estimated fair values of  non-designated
financial derivatives were comprised as follows:

<TABLE>
<CAPTION>
                                                                            2005                          2004
-------------------------------------------------------------------------------------------------------------------------
                                                                       Risk                          Risk
                                                                 management     Deferred       management       Deferred
                                                             mark-to-market      revenue   mark-to-market        revenue
-------------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>                <C>        <C>                <C>
Balance - beginning of year                                        $     66      $   (26)        $     40       $    (40)
  Net cost of put options outstanding as at December 31                 190            -               38              -
  Net change in fair value of financial instruments
    outstanding as at December 31                                      (943)           -               26              -
  Amortization of deferred revenue                                        -           18                -             14
-------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                                  (687)          (8)             104            (26)
Less: put premium financing obligations                                (190)           -              (38)             -
-------------------------------------------------------------------------------------------------------------------------
                                                                       (877)          (8)              66            (26)
Less: current portion (1)                                               834            8               34             17
-------------------------------------------------------------------------------------------------------------------------
                                                                   $    (43)     $     -         $     32       $     (9)
=========================================================================================================================
</TABLE>
(1)  The Company has  negotiated  payment of put option  premiums with various
     counterparties at the time of actual settlement of the respective option.

Net  losses  (gains)  from risk  management  activities  for the  years  ended
December 31 were as follows:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------
                                                                                    2005             2004           2003
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>               <C>            <C>
Net realized risk management loss                                              $   1,027         $    474       $    148
Net unrealized risk management loss (gain)                                           925              (40)             -
-------------------------------------------------------------------------------------------------------------------------
                                                                               $   1,952         $    434       $    148
=========================================================================================================================
</TABLE>

As at  December  31,  2005,  the net  unrecognized  liability  related  to the
estimated fair values of derivative financial instruments designated as hedges
was $990 million (December 31, 2004 - net unrecognized asset of $33 million).


                           Notes to the Consolidated Financial Statements   89
<PAGE>

FINANCIAL CONTRACTS

The Company's  financial  instruments  recognized in the consolidated  balance
sheets  consist  of  cash,  accounts  receivable,  accounts  payable,  accrued
liabilities,   risk  management  activities,   stock-based   compensation  and
long-term debt.

The estimated fair values of financial  instruments have been determined based
on the  Company's  assessment  of available  market  information,  appropriate
valuation methodologies and third party indications.  However, these estimates
may not  necessarily  be  indicative  of the amounts that could be realized or
settled in a current market transaction.

The carrying value of cash,  accounts  receivable,  accounts payable,  accrued
liabilities,   stock-based  compensation  and  long-term  debt  with  variable
interest rates approximate their fair value.

The estimated fair values of other financial instruments were as follows:

<TABLE>
<CAPTION>
                                                          2005                              2004
-----------------------------------------------------------------------------------------------------------
                                              Carrying Value   Fair Value     Carrying Value     Fair Value
-----------------------------------------------------------------------------------------------------------
<S>                                           <C>              <C>            <C>                <C>
Asset (liability)
Derivative financial instruments              $     (687)      $   (1,700)    $      66          $     33
Fixed rate notes                              $   (3,199)      $  ( 3,367)    $  (3,175)         $ (3,364)
============================================================================================================
</TABLE>


COMMODITY PRICE RISK MANAGEMENT

The  Company  uses  certain  derivative  financial  instruments  to manage its
commodity price exposures. These financial instruments are entered into solely
for  hedging  purposes  and are not used  for  trading  or  other  speculative
purposes. The following summarizes transactions outstanding as at December 31,
2005:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------
                                 Remaining term                   Volume            Average price                 Index
-------------------------------------------------------------------------------------------------------------------------
<S>                         <C>                            <C>                 <C>                      <C>
Crude oil
Crude oil price collars     Jan 2006 - Dec 2006            167,644 bbl/d       US$38.26 - US$48.28                  WTI
                            Jan 2006 - Dec 2006             82,356 bbl/d       US$44.75 - US$76.93                  WTI
                            Jan 2006 - Dec 2006             22,000 bbl/d        C$46.53 -  C$58.67                  WTI
Crude oil puts (1)          Mar 2006 - Jul 2006             55,000 bbl/d                  US$40.00                  WTI
                            Aug 2006 - Dec 2006             51,000 bbl/d                  US$45.00                  WTI
                            Jan 2007 - Dec 2007            100,000 bbl/d                  US$28.00                  WTI
                            Jan 2007 - Dec 2007            100,000 bbl/d                  US$45.00                  WTI
Brent differential swaps    Jan 2006 - Dec 2006             25,000 bbl/d                   US$1.29      WTI/Dated Brent
                            Jan 2007 - Dec 2007             50,000 bbl/d                   US$1.34      WTI/Dated Brent
=========================================================================================================================
</TABLE>
(1)  Subsequent to year end, the Company  settled 17,000 bbl/d of the US$40.00
     put options for 2006 and purchased  100,000  bbl/d of US$50.00 put options
     for 2007.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------
                                 Remaining term                   Volume            Average price                 Index
-------------------------------------------------------------------------------------------------------------------------
<S>                         <C>                            <C>                 <C>                      <C>
Natural gas
AECO collars                Jan 2006 - Mar 2006             700,0OO GJ/d          C$5.88 - C$8.78                  AECO
                            Jan 2006 - Mar 2006             400,000 GJ/d          C$6.00 - C$12.29                 AECO
                            Jan 2006 - Mar 2006             100,000 GJ/d          C$8.00 - C$27.75                 AECO
                            Apr 2006 - Jun 2006             993,000 GJ/d          C$5.71 - C$8.13                  AECO
                            Apr 2006 - Jun 2006             100,000 GJ/d          C$7.00 - C$14.16                 AECO
                            Jul 2006 - Sep 2006             725,000 GJ/d          C$5.60 - C$7.59                  AECO
                            Jul 2006 - Sep 2006             100,000 GJ/d          C$7.00 - C$14.16                 AECO
                            Oct 2006 - Dec 2006             244,000 GJ/d          C$5.60 - C$7.59                  AECO
                            Oct 2006 - Dec 2006             100,000 GJ/d          C$7.00 - C$14.16                 AECO
                            Oct 2006 - Dec 2006             464,000 GJ/d          C$7.50 - C$18.80                 AECO
                            Jan 2007 - Mar 2007             700,000 GJ/d          C$7.50 - C$18.80                 AECO
=========================================================================================================================
</TABLE>

Commodity related  derivative  financial  instruments  designated as hedges at
December 31, 2005, were all classified as cash flow hedges.


90    Notes to the Consolidated Financial Statements
<PAGE>

INTEREST RATE / RISK MANAGEMENT

The Company is exposed to interest rate price risk on its fixed rate long-term
debt and to interest rate cash flow-risk on its floating rate long-term  debt.
The Company  enters into interest rate swap  agreements to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal  amounts on which the payments are based.  At December 31, 2005, the
Company had the following interest rate swap contracts outstanding:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------
                                          Remaining term        Amount ($ millions)    Fixed rate        Floating rate
------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>                                 <C>                <C>       <C>
Interest rate
Swaps -  fixed to floating           Jan 2006 - Jan 2007                 US$200 (2)         7.20%     LIBOR (1) + 2.23%
                                     Jan 2006 - Oct 2012                 US$350             5.45%     LIBOR (1) + 0.81%
                                     Jan 2006 - Dec 2014                 US$350             4.90%     LIBOR (1) + 0.38%
Swaps -  floating to fixed           Jan 2006 - Mar 2007                    C$6             7.36%              CDOR (3)
========================================================================================================================
</TABLE>
(1) London Interbank Offered Rate
(2) Subsequent to year end the Company received approximately $1 million in
    settlement of the 7.20% fixed to floating rate swap.
(3) Canadian Deposit Overnight Rate

Interest rate related derivative financial instruments designated as hedges at
December 31, 2005, were all classified as fair value hedges.

FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

The  Company  is exposed  to  foreign  exchange  rate risk in Canada on its US
dollar  denominated  debt and on product sales based on US dollar  denominated
benchmarks.  The  Company is also  exposed to  foreign  exchange  rate risk on
transactions  conducted in foreign currencies in its foreign  subsidiaries and
in the  carrying  value of its self  sustaining  foreign  subsidiaries.  Cross
currency swap agreements are periodically  used to manage currency exposure on
US dollar  denominated  long-term  debt.  The cross  currency  swap  contracts
require the  periodic  exchange of payments  with the  exchange at maturity of
notional  principal  amounts on which the payments are based.  The Company may
also enter into foreign currency denominated  financial  instruments to manage
future US dollar  denominated crude oil and natural gas sales. The Company has
designated  certain  US dollar  denominated  debt as a hedge  against  its net
investment in US dollar-based self-sustaining foreign operations (note 8).

COUNTERPARTY CREDIT RISK MANAGEMENT

Accounts receivable are mainly with customers in the crude oil and natural gas
industry and are subject to normal industry credit risks.  The Company manages
this risk by entering into sales contracts with only highly rated entities. In
addition,  the Company  reviews  its  exposure to  individual  companies  on a
regular  basis and where  appropriate,  ensures that  parental  guarantees  or
letters of credit are in place to minimize the impact in the event of default.
The Company is also exposed to possible losses in the event of non-performance
by counterparties to derivative  financial  instruments;  however, the Company
manages this credit risk by entering  into  agreements  with only highly rated
financial institutions and other entities.

11.  COMMITMENTS

The Company has committed to certain payments as follows:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------
                                            2006       2007           2008        2009        2010     Thereafter
-----------------------------------------------------------------------------------------------------------------
<S>                                      <C>        <C>           <C>         <C>         <C>          <C>
Product transportation and pipeline (1)  $   195    $   133       $   148     $    94     $    85      $   1,111
Offshore equipment operating lease       $    51    $    51       $    52     $    51     $    51      $     180
Offshore drilling                        $   132    $   100       $    35     $    --     $    --      $      --
Asset retirement obligations (2)         $    82    $     4       $     4     $     4     $     7      $   3,224
Other (3)                                $    61    $    62       $    21     $    29     $    23      $       8
=================================================================================================================
</TABLE>
(1) During  the  year,   the  Company   entered   into  a  25  year   pipeline
    transportation  agreement  commencing in 2008, related to future crude oil
    production.  The agreement is renewable for successive  10-year periods at
    the Company's option. During the initial term, annual toll payments before
    operating costs will be approximately $35 million.
(2) Represents  management's  estimate of the future undiscounted  payments to
    settle  asset  retirement  obligations  related  to  resource  properties,
    facilities,   production   platform  and   pipelines,   based  on  current
    legislation and industry operating practices.
(3) Consists  of  future  expenditures  related  primarily  to  office  lease,
    electricity and crude oil processing.

The Board of Directors has approved the construction  costs for Phase 1 of the
Horizon  Project,  which  are  budgeted  to  be  $6.8  billion,   including  a
contingency  fund of $700 million,  with $1.3 billion  incurred in 2005,  $2.6
billion to be  incurred  in 2006 and $2.9  billion to be  incurred in 2007 and
2008.

The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business.  The Company  believes that any  liabilities
that might arise  pertaining to such matters would not have a material  effect
on its consolidated financial position.


                           Notes to the Consolidated Financial Statements   91
<PAGE>

12.  SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Changes in non-cash working capital were as follows:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------
                                                                     2005          2004       2003
----------------------------------------------------------------------------------------------------
<S>                                                             <C>           <C>           <C>
Decrease (increase) in non-cash working capital
Accounts receivable and other                                   $    (498)    $    (329)    $   35
Accounts payable                                                      196            39        125
Accrued liabilities                                                   716           194        122
----------------------------------------------------------------------------------------------------
Net change in non-cash working capital                          $     414     $     (96)    $  282
----------------------------------------------------------------------------------------------------
Relating to:
Operating activities                                            $    (147)    $     (14)    $  (48)
Financing activities                                                   19             6        (11)
Investing activities                                                  542           (88)       341
----------------------------------------------------------------------------------------------------
                                                                $     414     $     (96)    $  282
----------------------------------------------------------------------------------------------------
Other cash flow information:
----------------------------------------------------------------------------------------------------
Interest paid                                                   $    200      $     192     $  178
Taxes paid                                                      $    430      $     218     $   51
====================================================================================================
</TABLE>


13. SEGMENTED INFORMATION

The  Company's  crude oil and natural gas  activities  are  conducted in three
geographic segments:  North America, North Sea and Offshore West Africa. These
activities relate to the exploration, development, production and marketing of
crude oil, natural gas liquids and natural gas.

The Company's  Horizon Project has been classified as a separate  segment.  As
the  bitumen  will  be  recovered  through  mining  operations,  this  project
constitutes  a distinct  segment  from crude oil and natural  gas  activities.
There are  currently no revenues  for this  project and all  directly  related
expenditures have been capitalized.

Midstream   activities  include  the  Company's  pipeline  operations  and  an
electricity co-generation system.

Activities  that are not  included in the above  segments  are included in the
segmented information as other.

Inter-segment  eliminations  include internal  transportation  and electricity
charges.

<TABLE>
<CAPTION>
                                                  Crude oil and natural gas
---------------------------------------------------------------------------------------------------------------
                                    North America                    North Sea           Offshore West Africa
                             2005      2004        2003      2005      2004    2003     2005     2004     2003
---------------------------------------------------------------------------------------------------------------
<S>                      <C>        <C>        <C>        <C>       <C>       <C>     <C>      <C>      <C>
Segmented  revenue       $  7,932   $ 5,979    $  5,021   $ 1,659   $ 1,317   $ 953   $  485   $  222   $  155
Less: royalties            (1,350)   (1,003)       (868)       (3)       (2)      1      (13)      (6)      (5)
---------------------------------------------------------------------------------------------------------------
Revenue, net of
   royalties                6,582     4,976       4,153     1,656     1,315     954      472      216      150
---------------------------------------------------------------------------------------------------------------
Segmented expenses
Production                  1,211       976         845       379       370     314       53       36       38
Transportation                287       256         264        20        32      30       --       --       --
Depletion, depreciation
  and amortization          1,595     1,444       1,209       306       265     252      104       53       41
Asset retirement
  obligation accretion         34        28          26        34        22      36        1        1       --
Realized risk
  management activities       870       362         157       157       112      (9)      --       --       --
---------------------------------------------------------------------------------------------------------------
Total segmented
    expenses                3,997     3,066       2,501       896       801     623      158       90       79
---------------------------------------------------------------------------------------------------------------
Segmented earnings
  before the
  following              $  2,585   $ 1,910    $  1,652   $   760   $   514   $ 331   $  314   $  126   $   71
---------------------------------------------------------------------------------------------------------------
Non-segmented expenses
Administration
Stock-based
  compensation
Interest
Unrealized risk
  management activities
Foreign exchange gain
Total non-segmented
  expenses
Earnings before taxes
Taxes other than
  income tax
Current income tax
  expense
Future income tax
  expense
Net earnings
</TABLE>


92    Notes to the Consolidated Financial Statements
<PAGE>

<TABLE>
<CAPTION>
                                                                  Inter-segment
                                     Midstream               elimination and other               Total
----------------------------------------------------------------------------------------------------------------
                             2005      2004        2003      2005      2004    2003      2005     2004     2003
----------------------------------------------------------------------------------------------------------------
<S>                      <C>        <C>        <C>        <C>       <C>       <C>     <C>      <C>      <C>
Segmented  revenue       $     77   $    68    $     61   $   (46)  $   (39)  $ (35)  $10,107  $ 7,547  $ 6,155
Less: royalties                --        --          --        --        --      --    (1,366)  (1,011)    (872)
----------------------------------------------------------------------------------------------------------------
Revenue, net of
   royalties                   77        68          61       (46)      (39)    (35)    8,741    6,536    5,283
----------------------------------------------------------------------------------------------------------------
Segmented expenses
Production                     24        20          15        (4)       (2)     (3)    1,663    1,400    1,209
Transportation                 --        --          --       (37)      (38)    (32)      270      250      262
Depletion, depreciation
  and amortization              8         7           7        --        --      --     2,013    1,769    1,509
Asset retirement
  obligation accretion         --        --          --        --        --      --        69       51       62
Realized risk
  management activities        --        --          --        --        --      --     1,027      474      148
----------------------------------------------------------------------------------------------------------------
Total segmented
    expenses                   32        27          22       (41)      (40)    (35)    5,042    3,944    3,190
----------------------------------------------------------------------------------------------------------------
Segmented earnings
  before the
  following              $     45   $    41    $     39   $    (5)  $     1   $  --   $ 3,699  $ 2,592  $ 2,093
--------------------------------------------------------------------------------------
Non-segmented expenses
Administration                                                                            151      125       87
Stock-based
  compensation                                                                            723      249      200
Interest                                                                                  149      189      201
Unrealized risk
  management activities                                                                   925      (40)      --
Foreign exchange gain                                                                    (132)     (91)    (335)
                                                                                      --------------------------
Total non-segmented
  expenses                                                                              1,816      432      153
                                                                                      --------------------------
Earnings before taxes                                                                   1,883    2,160    1,940
Taxes other than
  income tax                                                                              194      165      107
Current income tax
  expense                                                                                 286      116       92
Future income tax
  expense                                                                                 353      474      338
                                                                                      --------------------------
Net earnings                                                                          $ 1,050  $ 1,405  $ 1,403
                                                                                      ==========================
</TABLE>


                         Notes to the Consolidated Financial Statements    93
<PAGE>

<TABLE>
<CAPTION>
CAPITAL EXPENDITURES

                                                         2005                                              2004
--------------------------------------------------------------------------------------------------------------------------------
                                                 Non-cash and                                      Non-cash and
                                        Cash       fair value     Capitalized            Cash        fair value     Capitalized
                                expenditures    adjustments(1)          costs    expenditures       adjustments(1)        costs
--------------------------------------------------------------------------------------------------------------------------------
<S>                             <C>             <C>                <C>           <C>                <C>             <C>
Crude oil and natural gas
  North America                 $      2,530    $       (22)       $    2,508    $      3,329       $       508     $     3,837
  North Sea                              387           (136)              251             608               172             780
  Offshore West Africa                   439             27               466             295                --             295
  Other                                    5             --                 5               1                --               1
--------------------------------------------------------------------------------------------------------------------------------
                                       3,361           (131)            3,230           4,233               680           4,913
Horizon Project                        1,499             --             1,499             291                --             291
Midstream                                  4             --                 4              16                --              16
Head office                               22             --                22              35                --              35
--------------------------------------------------------------------------------------------------------------------------------
                                 $     4,886    $      (131)       $    4,755    $      4,575       $       680     $     5,255
================================================================================================================================
</TABLE>
(1) Asset  retirement  obligations,  future income tax  adjustments on non-tax
    base assets, and other fair value adjustments.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------
Segmented property, plant and equipment, net                                                        2005           2004
------------------------------------------------------------------------------------------------------------------------
<S>                                                                                            <C>            <C>
Crude oil and natural gas
North America                                                                                  $  14,310      $  13,394
North Sea                                                                                          1,681          1,823
Offshore West Africa                                                                               1,253            901
Other                                                                                                 13              8
Horizon Project                                                                                    2,169            672
Midstream                                                                                            203            209
Head office                                                                                           65             57
------------------------------------------------------------------------------------------------------------------------
                                                                                               $  19,694      $  17,064
========================================================================================================================

Segmented assets                                                                                    2005          2004
------------------------------------------------------------------------------------------------------------------------
Crude oil and natural gas
North America                                                                                  $  15,939      $  14,390
North Sea                                                                                          1,950          2,036
Offshore West Africa                                                                               1,371            914
Other                                                                                                 30             35
Horizon Project                                                                                    2,239            672
Midstream                                                                                            258            268
Head office                                                                                           65             57
------------------------------------------------------------------------------------------------------------------------
                                                                                               $  21,852      $  18,372
========================================================================================================================
</TABLE>

14. BUSINESS COMBINATIONS

PETROVERA PARTNERSHIP

In February  2004, the Company  acquired  certain  resource  properties in its
Northern Plains core region,  collectively known as the Petrovera  Partnership
("Petrovera"), for $471 million.

The acquisition was accounted for based on the purchase  method.  Results from
Petrovera are consolidated  with the results of the Company effective from the
date of  acquisition.  The allocation of the purchase price to assets acquired
and liabilities assumed based on their fair values was as follows:

------------------------------------------------------------------------------
                                                             FEBRUARY 1, 2004
------------------------------------------------------------------------------
Purchase price:
Cash consideration                                           $            467
Cash acquired                                                             (23)
Non-cash working capital deficit assumed                                   27
------------------------------------------------------------------------------
Total purchase price                                         $            471
==============================================================================

Purchase price allocated as follows:
Property, plant and equipment                                $            643
Future income tax liability                                              (129)
Asset retirement obligation                                               (43)
------------------------------------------------------------------------------
                                                             $            471
==============================================================================


94    Notes to the Consolidated Financial Statements


<PAGE>

15.  DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
     ACCOUNTING PRINCIPLES

The  Company's   consolidated  financial  statements  have  been  prepared  in
accordance with generally accepted accounting  principles in Canada ("Canadian
GAAP").  These principles  conform in all material  respects with those in the
United  States ("US GAAP") except for those noted below.  Differences  arising
from US GAAP disclosure requirements are not addressed.

The  application of US GAAP would have the following  effects on  consolidated
net earnings as reported:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars, except per common share amounts)      Notes         2005           2004            2003
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>      <C>            <C>             <C>
Net earnings - Canadian GAAP                                                  $   1,050      $   1,405       $   1,403

Adjustments
  Depletion, net of tax of $3 million (2004 - $2 million; 2003
    - $3 million)                                                       (A)           4              4               4
  Derivative financial instruments and hedging activities,
    net of tax of $11 million (2004 - $7 million; 2003 - $20
    million)                                                            (B)         (19)            (9)            (49)
  Capitalized interest, net of tax of $11 million                       (C)          --             16              --
  Cumulative effect of change in accounting policy, net of tax
  of $3 million                                                         (D)          --             --              (4)
-----------------------------------------------------------------------------------------------------------------------
Net earnings - US GAAP                                                        $   1,035      $   1,416       $   1,354
-----------------------------------------------------------------------------------------------------------------------
Net earnings - US GAAP per common share
  Basic                                                                       $    1.93      $    2.64       $    2.52
  Diluted                                                                     $    1.93      $    2.62       $    2.44
=======================================================================================================================
</TABLE>

Comprehensive income under US GAAP would be as follows:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars)                                       Notes         2005           2004            2003
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>      <C>            <C>             <C>
Net earnings - US GAAP                                                        $   1,035      $   1,416       $   1,354
  Derivative financial instruments and hedging activities,
    net of tax of $312 million (2004 - $3 million; 2003 - $9
    million)                                                            (B)        (635)             8              20
  Foreign currency translation adjustment                               (E)          (3)            (9)            (23)
-----------------------------------------------------------------------------------------------------------------------
  Comprehensive income                                                        $     397      $   1,415       $   1,351
=======================================================================================================================
</TABLE>

The  application  of  US  GAAP  would  have  the  following   effects  on  the
consolidated balance sheets as reported:

<TABLE>
<CAPTION>
                                                                                               2005
                                                                              -----------------------------------------
                                                                               Canadian       Increase              US
(millions of Canadian dollars)                                        Notes        GAAP      (decrease)           GAAP
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>       <C>            <C>             <C>
Current assets                                                          (B)   $   2,051      $     338       $   2,389
Property, plant and equipment                                         (A,C)      19,694            (20)         19,674
Other long-term assets                                                              107             --             107
-----------------------------------------------------------------------------------------------------------------------
                                                                              $  21,852      $     318       $  22,170
-----------------------------------------------------------------------------------------------------------------------
Current liabilities                                                     (B)   $   3,825      $   1,005       $   4,830
Long-term debt                                                          (B)       3,321            (18)          3,303
Other long-term liabilities                                             (B)       1,434              8           1,442
Future income tax                                                   (A,B,C)       5,035             (5)          5,030
Shareholders' equity                                                  (B,E)       8,237           (672)          7,565
-----------------------------------------------------------------------------------------------------------------------
                                                                              $  21,852      $     318       $  22,170
=======================================================================================================================

<CAPTION>
                                                                                                2004
                                                                              -----------------------------------------
                                                                               Canadian       Increase              US
(millions of Canadian dollars)                                       Notes         GAAP      (decrease)           GAAP
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>       <C>            <C>             <C>
Current assets                                                          (B)   $   1,200      $     (33)      $   1,167
Property, plant and equipment                                         (A,C)      17,064            (27)         17,037
Other long-term assets                                                              108             --             108
-----------------------------------------------------------------------------------------------------------------------
                                                                              $  18,372      $     (60)      $  18,312
-----------------------------------------------------------------------------------------------------------------------
Current liabilities                                                     (B)   $   1,852      $     (44)      $   1,808
Long-term debt                                                                    3,538             --           3,538
Other long-term liabilities                                                       1,208             --           1,208
Future income tax                                                   (A,B,C)       4,450              6           4,456
Shareholders' equity                                                  (B,E)       7,324            (22)          7,302
-----------------------------------------------------------------------------------------------------------------------
                                                                              $  18,372      $     (60)      $  18,312
=======================================================================================================================
</TABLE>

                           Notes to the Consolidated Financial Statements   95
<PAGE>

NOTES:
(A)  Under Canadian full cost accounting rules, costs capitalized in each cost
     centre, net of future income taxes, are limited to an amount equal to the
     undiscounted,  future net revenues from proved  reserves using  estimated
     future prices and costs, plus the carrying amount of unproved  properties
     and major development  projects (the "ceiling test"). Under the full cost
     method of  accounting  as set  forth by the US  Securities  and  Exchange
     Commission,  the ceiling test differs from  Canadian  GAAP in that future
     net revenues from proved reserves are based on prices and costs as at the
     balance sheet date ("constant dollar pricing") and are discounted at 10%.

(B)  The Company  accounts  for its  derivative  financial  instruments  under
     Canadian GAAP as described in note 1(P). For US GAAP purposes,  Financial
     Accounting   Standards  Board  Statement  ("FAS")  133,  "Accounting  for
     Derivative  Financial  Instruments and Hedging Activities," as amended by
     FAS  138 and FAS  149,  establishes  US  GAAP  accounting  and  reporting
     standards  for  derivative  instruments,   including  certain  derivative
     instruments  embedded in other  contracts,  and for  hedging  activities.
     Generally,  all derivatives,  whether designated in hedging relationships
     or not, and excluding  normal purchases and normal sales, are required to
     be recorded on the balance  sheet at fair  value.  If the  derivative  is
     designated  as a fair  value  hedge,  changes  in the  fair  value of the
     derivative and changes in the fair value of the hedged item  attributable
     to the hedged  risk are  recognized  in the  consolidated  statements  of
     earnings  each period.  If the  derivative  is  designated as a cash flow
     hedge,  the  effective  portions  of the  changes  in fair  value  of the
     derivative are initially recorded in other  comprehensive  income ("OCI")
     each period and are recognized in the consolidated statements of earnings
     when the hedged item is recognized.  Therefore,  ineffective  portions of
     changes in the fair value of hedging  instruments  are  recognized in net
     earnings immediately for both fair value and cash flow hedges.

     The  determination  of hedge  effectiveness  and the measurement of hedge
     ineffectiveness  of cash flow hedges is based on a  combination  of third
     party  indications and internally  derived  valuations.  The Company uses
     these  valuations to estimate the fair values of the underlying  physical
     commodity contracts.

(C)  Under  Canadian  GAAP,  the Company  began  capitalizing  interest on the
     Horizon  Project  when the Board of  Directors  approval  was received in
     2005.  For US GAAP,  capitalization  of interest on projects  constructed
     over time is mandatory and interest has been  capitalized to the costs of
     construction beginning in 2004.

(D)  Under Canadian GAAP, when the asset  retirement  obligation  standard was
     adopted  prior period  comparative  balances were restated to reflect the
     effect of the new  standard on that year.  Under US GAAP,  when the asset
     retirement  obligation  standard was adopted the cumulative effect of the
     new  standard  on prior  periods  was  included  in  earnings in the year
     adopted.

(E)  Under US GAAP,  exchange gains and losses arising from the translation of
     self-sustaining foreign operations are included in comprehensive income.

(F)  Recently issued accounting standards under US GAAP:

SHARE-BASED PAYMENT

In December 2004, the Financial Accounting Standards Board ("FASB") issued FAS
123(R)  "Share-Based  Payment,"  which is a revision of FAS 123. This standard
requires all companies to reflect stock based  compensation in their statement
of earnings for US GAAP. The fair value of stock options must be recognized at
the date of  grant  using  option  pricing  models.  The  fair  value  must be
remeasured  each  quarter  and  changes in fair value  must flow  through  the
statement of earnings.  This is a difference  from  Canadian  GAAP,  where the
Company's options are valued at the difference  between the exercise price and
the stock price.  This  standard is effective  for the first interim or annual
reporting  period of a  registrant's  first fiscal year  beginning on or after
June 15, 2005. The Company plans to adopt this standard January 1, 2006.

ACCOUNTING CHANGES AND ERROR CORRECTIONS

In  May  2005,  the  FASB  issued  FAS  154  "Accounting   Changes  and  Error
Corrections,"  which replaces FAS 3 "Reporting  Accounting  Changes in Interim
Financial  Statements"  and APB Opinion 20 "Accounting  Changes." The previous
standards  required  that changes in  accounting  principle be  recognized  by
including in net income of the period of the change the  cumulative  effect of
changing to the new  accounting  principle.  The new  standard  requires  that
accounting  changes  be  applied  retrospectively  and that  prior  accounting
periods be restated as if the accounting  principle had always been used. This
change  eliminates a difference  from Canadian  GAAP. The new standard will be
applied to all future US GAAP accounting policy changes.


96    Notes to the Consolidated Financial Statements
<PAGE>

                      MANAGEMENT'S DISCUSSION & ANALYSIS


SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain  statements  in this  document  or  documents  incorporated  herein by
reference  for  Canadian  Natural   Resources   Limited  (the  "Company")  may
constitute  "forward-looking  statements"  within  the  meaning  of the United
States Private Securities 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  "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: general economic and business
conditions which will, among other things, impact demand for and market prices
of  the  Company's  products;   foreign  currency  exchange  rates;   economic
conditions  in the  countries  and  regions  in  which  the  Company  conducts
business; political uncertainty, including actions of or against terrorists or
insurgent groups or other conflict including conflict between states; industry
capacity; ability of the Company to implement its business strategy, including
exploration  and   development   activities;   impact  of   competition;   the
availability and cost of seismic, drilling and other equipment; ability of the
Company to complete its capital programs;  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 ability of
the Company to attract the  necessary  labour  required to build its projects;
operating hazards and other  difficulties  inherent in the exploration for and
production  and sale of crude oil and natural  gas;  availability  and cost of
financing;  success of  exploration  and  development  activities;  timing and
success of  integrating  the business and  operations  of acquired  companies;
production levels;  uncertainty of reserve estimates;  actions by governmental
authorities;  government  regulations and the expenditures  required to comply
with them (especially  safety and environmental  laws and regulations);  asset
retirement  obligations;   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,  and the  Company'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 were 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.  Except as required by law, the
Company  assumes no obligation  to update  forward-looking  statements  should
circumstances or the Company's estimates or opinions change.

SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES

Management's discussion and analysis includes references to financial measures
commonly  used in the crude oil and  natural gas  industry,  such as cash flow
from  operations,  adjusted  net  earnings  from  operations,  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  activities).
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  its  performance.  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.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's  discussion and analysis ("MD&A") of the financial  condition and
results of operations of the Company  should be read in  conjunction  with the
Company's audited consolidated  financial statements and related notes for the
year ended December 31, 2005. The consolidated  financial statements have been
prepared in accordance with Canadian GAAP. A  reconciliation  of Canadian GAAP
to United  States GAAP is included  in note 15 to the  consolidated  financial
statements.  All dollar  amounts are  referenced in Canadian  dollars,  except
where  otherwise  noted.  Common  share data has been  restated to reflect the
two-for-one  share  split in May  2005.  The  calculation  of  barrels  of oil
equivalent  ("boe") is based on a conversion  ratio of six thousand cubic feet
("mcf") of natural gas to one barrel ("bbl") of crude oil to estimate relative
energy content.  This conversion may be misleading,  particularly when used in
isolation,  since the 6 mcf:1 bbl ratio is based on an energy  equivalency  at
the burner tip and does not represent the value  equivalency at the well head.
Production volumes are the Company's  interest before royalties,  and realized
prices exclude the effect of risk  management  activities,  except where noted
otherwise.  The  following  discussion  and analysis  refers  primarily to the
Company's 2005 financial  results compared to 2004 and 2003,  unless otherwise
indicated.  In addition, this discussion details the Company's capital program
and outlook for 2006. This MD&A is dated February 21, 2006.

                                      Management's Discussion & Analysis    45
<PAGE>

ABBREVIATIONS

AECO                Alberta natural gas reference location
AIF                 Annual Information Form
bbl                 barrel
bbl/d               barrels per day
BCF                 billion cubic feet
bcf/d               billion cubic feet per day
BOE                 barrels of oil equivalent
boe/d               barrels of oil equivalent per day
C$                  Canadian dollars
FPSO                Floating Production, Storage and Offtake Vessel
GHG                 Greenhouse Gas
Horizon Project     Horizon Oil Sands Project
mbbl                thousand barrels
mbbl/d              thousand barrels per day
mboe                thousand barrels of oil equivalent
mboe/d              thousand barrels of oil equivalent per day
mcf                 thousand cubic feet
mcf/d               thousand cubic feet per day
mmbbl               million barrels
mmboe               million barrels of oil equivalent
mmbtu               million British thermal units
mmcf/d              million cubic feet per day
NGLs                Natural gas liquids
NYMEX               New York Mercantile Exchange
NYSE                New York Stock Exchange
SCO                 Synthetic light crude oil
SEC                 Securities and Exchange Commission
TSX                 Toronto Stock Exchange
UK                  United Kingdom
US                  United States
US$                 United States dollars
WCS                 Western Canadian Select crude oil blend
WTI                 West Texas Intermediate


OBJECTIVE AND STRATEGY

The Company's  objective is to increase crude oil and natural gas  production,
reserves,  cash  flow and net  asset  value (1) on a per  common  share  basis
through the  development  of its existing crude oil and natural gas properties
and  through  the  discovery  and  acquisition  of new  reserves.  The Company
accomplishes this objective by having a defined growth and a value enhancement
plan for each of its  products  and  segments.  The  Company  takes a balanced
approach  to  growth  and  investments  and  focuses  on  creating   long-term
shareholder  wealth.  The  Company   effectively   allocates  its  capital  by
maintaining:

     o    Balance among its  products,  namely  natural gas,  light crude oil,
          Pelican  Lake crude oil (2),  primary  heavy  crude oil and  thermal
          heavy crude oil;
     o    Balance among near-, mid- and long-term projects;
     o    Balance among acquisitions, exploitation and exploration; and,
     o    Balance  between sources of debt and by maintaining a strong balance
          sheet.

(1)  Discounted  value of conventional  crude oil and natural gas reserves and
     undeveloped land, less net debt.
(2)  Pelican  Lake crude oil is 14-17 (degree) API oil,  but  receives  medium
     quality crude netbacks due to low operating costs and low royalty rates.


The Company's three-phase crude oil marketing strategy includes:

     o    Blending   various   crude  oil  streams  with  diluents  into  more
          attractive feedstock;
     o    Supporting and participating in pipeline expansion or new additions;
          and
     o    Supporting  and  participating  in projects  that will  increase the
          conversion capacity of heavy crude oil.

Operational  discipline and cost control is central to the Company's strategy.
By controlling costs consistently  throughout all cycles of the industry,  the
Company  believes  that it will  achieve  continued  growth.  Cost  control is
attained  by  developing  area  knowledge,  by  core  area  domination  and by
maintaining a high working interest in its properties.

The  Company  is  committed  to  maintaining  its  strong  financial  position
throughout  construction of the Horizon Oil Sands Project ("Horizon Project").
The Company  believes  that it has built the necessary  financial  capacity to
complete the Horizon Project while at the same time not compromising  delivery
from  its  conventional  crude  oil  and  natural  gas  growth  opportunities.
Additionally, the Company's risk management hedge program has been expanded to
reduce the risk of  volatility  in commodity  price markets and to support the
Company's  cash  flow for its  capital  expenditures  program  throughout  the
construction period of the Horizon Project.

Strategic  accretive  acquisitions  are  a  key  component  of  the  Company's
strategy.  The Company has used a  combination  of internally  generated  cash
flows and debt to selectively acquire properties  generating future cash flows
in its core regions.  These targeted  acquisitions  provide  relatively  quick
repayment of initial  investments and should provide additional free cash flow
during the  construction  years of the Horizon  Project while still  achieving
targeted returns.

The year ended December 31, 2005, was another successful year in the execution
of the Company's strategy. Highlights are as follows:

     o    Maintained strong levels of net earnings;
     o    Achieved record levels of adjusted net earnings from operations;
     o    Achieved record levels of cash flow;
     o    Completed  the  disposition  of a large  portion  of its  overriding
          royalty interests,  which were considered  non-core to the Company's
          operations, for proceeds of approximately $345 million;
     o    Completed the  subdivision  of its common shares on the basis of two
          for one;
     o    Increased the quarterly dividend by 20% to $0.06 per common share;
     o    Purchased  850,000  common  shares for a total  cost of $45  million
          under the Company's Normal Course Issuer Bid;
     o    Achieved  record  levels  of  natural  gas and  crude  oil and  NGLs
          production;
     o    Achieved its annual production  guidance for crude oil and NGLs, and
          natural gas;
     o    Completed the  development  of the 57.61% owned and operated  Baobab
          Field offshore Cote d'lvoire West Africa, which commenced production
          on August 9, 2005 at approximately 30,000 bbl/d net to the Company;
     o    Completed the  acquisition of the permit to develop the Olowi Field,
          offshore  Gabon,  West Africa with  development  plans to proceed in
          2006;
     o    Received  Board of  Directors'  approval of the Horizon  Project and
          completed 19% of Phase 1 construction;


46   Management's Discussion & Analysis

<PAGE>

     o    Signed a key  pipeline  transportation  agreement,  which will allow
          Horizon  Project  Synthetic  Crude Oil ("SCO") to reach the pipeline
          hub at Edmonton, Alberta;
     o    Completed all major 2005 milestones on the Horizon  Project,  before
          winter' onset;
     o    Commenced steam  injection at Primrose  North.  First oil production
          began in January 2006 and is expected to increase to 30,000 bbl/d by
          the third quarter of 2006;
     o    Drilled  a  record   1,634  net   wells,   excluding   stratigraphic
          test/service wells; and
     o    Announced  a  strategy  to review the  building  of a 100% owned and
          operated upgrader  ("Canadian  Natural  Upgrader") for the Company's
          in-situ oil sands assets in the Cold Lake to Athabasca region.

<TABLE>
<CAPTION>
NET EARNINGS AND CASH FLOW FROM OPERATIONS
-----------------------------------------------------------------------------------------------------
FINANCIAL HIGHLIGHTS ($ millions, except per
common share amounts)                                   2005               2004               2003
-----------------------------------------------------------------------------------------------------
<S>                                                <C>                <C>                <C>
Revenue, before royalties                          $  10,107          $   7,547          $   6,155
Net earnings                                       $   1,050          $   1,405          $   1,403
Per common share
   - basic (1)                                     $    1.96          $    2.62          $    2.62
   - diluted (1)                                   $    1.95          $    2.60          $    2.53
Adjusted net earnings from operations (2)          $   2,034          $   1,405          $     987
Per common share
   - basic (1)                                     $    3.79          $    2.62          $    1.84
   - diluted (1)                                   $    3.78          $    2.60          $    1.80
Cash flow from operations (3)                      $   5,021          $   3,769          $   3,160
Per common share
   - basic (1)                                     $    9.36          $    7.03          $    5.88
   - diluted (1)                                   $    9.33          $    6.98          $    5.76
Dividends declared per common share                $   0.236          $   0.200          $   0.150
Total assets                                       $  21,852          $  18,372          $  14,643
Total long-term liabilities                        $   9,790          $   9,196          $   7,277
Capital expenditures, net of dispositions          $   4,932          $   4,633          $   2,506
=====================================================================================================
</TABLE>
(1)  Restated to reflect two-for-one share split in May 2005.
(2)  Adjusted net earnings from  operations is a non-GAAP term that represents
     net earnings adjusted for certain items of a non-operational  nature. The
     Company  evaluates  its  performance  based on adjusted net earnings from
     operations.  The following  reconciliation lists the after-tax effects of
     certain  items  of a  non-operational  nature  that are  included  in the
     Company's  financial  results.  Adjusted net earnings from operations may
     not be comparable to similar measures presented by other companies.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
($ millions)                                            2005               2004               2003
---------------------------------------------------------------------------------------------------
<S>                                                <C>                <C>                <C>
Net earnings as reported                           $   1,050          $   1,405          $   1,403
Stock-based compensation, net of tax (a)                 481                168                136
Unrealized risk management loss (gain),
  net of tax (b)                                         607                (27)                 -
Unrealized foreign exchange gain, net
  of tax (c)                                             (85)               (75)              (274)
Effect of statutory tax rate changes on
  future income tax liabilities (d)                      (19)               (66)              (278)
---------------------------------------------------------------------------------------------------
Adjusted net earnings from operations              $   2,034          $   1,405          $     987
===================================================================================================
</TABLE>

     (a)  The Company's employee stock option plan provides for a cash payment
          option.  Accordingly,  the intrinsic value of the outstanding vested
          options is recorded as a liability on the  Company's  balance  sheet
          and periodic  changes in the  intrinsic  value,  net of taxes,  flow
          through net earnings.

     (b)  Effective  January 1, 2004,  the  Company  adopted a new  accounting
          standard whereby financial  instruments not designated as hedges are
          recorded at fair value on its balance  sheet,  with  changes in fair
          value,  net of taxes,  flowing  through  net  earnings.  The amounts
          ultimately  realized may be materially  different  than reflected in
          the financial  statements due to changes in prices of the underlying
          items hedged, primarily crude oil and natural gas.

     (c)  Unrealized  foreign  exchange gains and losses result primarily from
          the  translation  of  US  dollar   denominated   long-term  debt  to
          period-end  exchange  rates and are  immediately  recognized  in net
          earnings.

     (d)  All substantively enacted adjustments in applicable income tax rates
          are applied to underlying  assets and  liabilities  on the Company's
          balance   sheet  in   determining   future  income  tax  assets  and
          liabilities. The impact of these tax rate changes is recorded in net
          earnings during the period the legislation is substantively enacted.
          In 2005,  the province of British  Columbia  enacted  legislation to
          reduce its  corporate  income  tax rate by 1.5%.  During  2004,  the
          province  of Alberta  enacted  legislation  to reduce its  corporate
          income tax rate by 1%.  During 2003 the province of Alberta  enacted
          legislation  to reduce its corporate  income tax rate by 0.5%.  Also
          during 2003, the Canadian federal government enacted  legislation to
          change the  taxation of  resource  income.  The federal  legislation
          reduces the corporate income tax rate on resource income from 28% to
          21% over five years beginning  January 1, 2003. Over the same period
          the  deduction  for  resource  allowance  is being  phased out and a
          deduction  of actual  crown  royalties  paid is being phased in. The
          Company's  future  income tax  liability  was reduced by $31 million
          with respect to the Alberta  corporate income tax rate reduction and
          by $247 million with respect to the federal resource income tax rate
          changes.

(3)  Cash flow from operations is a non-GAAP term that represents net earnings
     adjusted for non-cash items. The Company  evaluates its performance based
     on cash  flow  from  operations.  The  Company  considers  cash flow from
     operations  a key measure as it  demonstrates  the  Company's  ability to
     generate the cash flow  necessary to fund future growth  through  capital
     investment  and to repay  debt.  Cash  flow  from  operations  may not be
     comparable to similar measures presented by other companies.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
($ millions)                                            2005               2004               2003
---------------------------------------------------------------------------------------------------
<S>                                                <C>                <C>                <C>
Net earnings                                       $   1,050          $   1,405          $   1,403
Non-cash items:
  Depletion, depreciation and amortization             2,013              1,769              1,509
  Asset retirement obligation accretion                   69                 51                 62
  Stock-based compensation                               723                249                200
  Unrealized risk management activities                  925                (40)                 -
  Unrealized foreign exchange gain                      (103)               (94)              (343)
  Deferred petroleum revenue tax recovery                 (9)               (45)                (9)
  Future income tax                                      353                474                338
---------------------------------------------------------------------------------------------------
Cash flow from operations                          $   5,021          $   3,769          $   3,160
===================================================================================================
</TABLE>

                                       Management's Discussion & Analysis   47

<PAGE>

The   Company  achieved  record  levels  of  cash  flow  from  operations  and
production in 2005 as a result of strong operational performance combined with
increased  commodity prices.  The strong operating results are attributable to
the Company following its defined growth strategy and to the strong asset base
the Company has  developed  over time  through  organic  growth and  accretive
acquisitions.

For the year ended  December  31, 2005,  the Company  recorded net earnings of
$1,050  million  compared to net earnings of $1,405 million for the year ended
December  31, 2004 (2003 - $1,403  million).  Net  earnings  for 2005  include
unrealized  after-tax  expenses of $984 million  related to the Company's risk
management  activities  and  stock-based  compensation  plans,  net of foreign
exchange  gains and the effect of statutory  tax rate changes  ($nil for 2004;
2003 -unrealized  after-tax income of $416 million).  Excluding the effects of
these items,  adjusted net earnings  from  operations  increased 45% to $2,034
million from $1,405  million in 2004 (2003 - $987  million) due to  continuing
strong  crude oil and  natural  gas  prices as well as record  levels of total
sales on a boe basis,  offset by realized risk  management  activities and the
impact of a strengthening Canadian dollar.

Cash flow  from  operations  reached  record  levels  in 2005.  Cash flow from
operations  increased 33% to $5,021 million ($9.36 per common share),  up from
$3,769  million  ($7.03  per common  share) in 2004 (2003 - $3,160  million or
$5.88 per common  share).  The increase in cash flow  from  operations was due
mainly to strong commodity prices and record levels of total sales volume on a
boe basis,  offset by realized risk management  activities and the impact of a
strengthening  Canadian dollar. In 2005, the Company's average sales price per
bbl of crude oil and NGLs  increased 23% to $46.86 per bbl from $37.99 per bbl
in 2004 (2003 - $32.66  per bbl).  The  Company's  average  natural  gas price
increased  32% to $8.57 per mcf from  $6.50 per mcf in 2004  (2003 - $6.21 per
mcf).

Production volumes before royalties increased 8% to a record 552,960 boe/d, up
from 513,835 boe/d in 2004 (2003 - 458,814 boe/d).  The increase in production
was due to organic growth from the Company's  extensive  North America capital
expenditure  program and the  commencement of production from the Baobob Field
offshore  Cote  d'lvoire,  as  well  as the  full  year  impact  of  accretive
acquisitions  completed  in  2004.  Production  of crude  oil and NGLs  before
royalties  increased 11% to 313,168 bbl/d, up from 282,489 bbl/d in 2004 (2003
- 242,392  bbl/d).  Natural gas production  before  royalties  increased 4% to
1,439 mmcf/d, up from 1,388 mmcf/d in 2004 (2003 - 1,299 mmcf/d).

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
OPERATING HIGHLIGHTS                                    2005               2004               2003
---------------------------------------------------------------------------------------------------
<S>                                                <C>                <C>                <C>
CRUDE OIL AND NGLS ($/bbl) (1)
Sales price (2)                                    $   46.86          $   37.99          $   32.66
Royalties                                               3.97               3.16               2.77
Production expense                                     11.17              10.05              10.28
---------------------------------------------------------------------------------------------------
Netback                                            $   31.72          $   24.78          $   19.61
---------------------------------------------------------------------------------------------------

NATURAL GAS ($/mcf) (1)
Sales price (2)                                    $    8.57          $    6.50          $    6.21
Royalties                                               1.75               1.35               1.32
Production expense                                      0.73               0.67               0.60
---------------------------------------------------------------------------------------------------
Netback                                            $    6.09          $    4.48          $    4.29
---------------------------------------------------------------------------------------------------

BARREL OF OIL EQUIVALENT ($/boe) (1)
Sales price (2)                                    $   48.77          $   38.45          $   34.84
Royalties                                               6.82               5.37               5.20
Production expense                                      8.21               7.35               7.15
---------------------------------------------------------------------------------------------------
Netback                                            $   33.74          $   25.73          $   22.49
---------------------------------------------------------------------------------------------------
</TABLE>

(1)  Amounts expressed on a per unit basis are based on sales volumes.
(2)  Including transportation costs and excluding risk management activities.


SUMMARY OF QUARTERLY RESULTS
The  following is a summary of the  Company's  quarterly  results for the most
recently completed quarters: ($ millions, except per common share amounts)

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------
2005                                                     TOTAL         DEC 31         SEP 30         JUN 30         MAR 31
----------------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>           <C>             <C>            <C>            <C>
Revenue, before royalties                            $  10,107     $    3,032      $   2,918      $   2,164      $   1,993
Net earnings (loss)                                  $   1,050     $    1,104      $     151      $     219      $    (424)
Net earnings (loss) per common share
        - basic (1)                                  $    1.96     $     2.06      $    0.28      $    0.41      $   (0.79)
        - diluted (1)                                $    1.95     $     2.06      $    0.28      $    0.41      $   (0.79)
============================================================================================================================

<CAPTION>
----------------------------------------------------------------------------------------------------------------------------
2004                                                     TOTAL         DEC 31         SEP 30         JUN 30         MAR 31
----------------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>           <C>             <C>            <C>            <C>
Revenue, before royalties                            $   7,547     $    1,969      $   2,075      $   1,865      $   1,638
Net earnings                                         $   1,405     $      577      $     311      $     259      $     258
Net earnings per common share
        - basic (1)                                  $    2.62     $     1.07      $    0.58      $    0.48      $    0.49
        - diluted (1)                                $    2.60     $     1.06      $    0.57      $    0.48      $    0.48
=============================================================================================================================
</TABLE>

(1)  Restated to reflect two-for-one share split in May 2005.


48   Management's Discussion & Analysis

<PAGE>

Quarterly  revenues have steadily  increased  throughout  2004 and 2005.  This
trend  reflects  increasing  world  benchmark crude oil and natural gas prices
and increasing sales volumes.

     o    Prices   continued  to  reflect   world-wide   economic  growth  and
          persistent   geopolitical   uncertainty,   further   exacerbated  by
          hurricane  activity in the Gulf of Mexico during the third  quarters
          of 2004 and 2005. As a result,  the Company's realized crude oil and
          NGLs price  increased  from C$34.21 per bbl for the first quarter of
          2004 to C$46.38 per bbl for the fourth quarter of 2005. The realized
          natural gas price  increased  from C$6.31 per mcf to C$11.67 per mcf
          for the same periods.  A  strengthening  Canadian dollar relative to
          the US dollar offset the impact of increasing  commodity prices. The
          US / Canadian  dollar average  exchange rate increased from 0.76 for
          the first quarter of 2004 to 0.84 for the fourth quarter of 2005.
     o    Strong sales  volumes in 2005 versus 2004 were also  fundamental  to
          the steady increase in revenue,  driven by North America's extensive
          capital  program,  the  commencement  of production  from the Baobab
          Field  offshore  Cote  d'lvoire  in 2005,  as well as the full  year
          impact  of  accretive  acquisitions  completed  late in 2004.  Daily
          production  increased from 476,944 boe/d day in the first quarter of
          2004 to 577,505 boe/d for the fourth quarter of 2005.
     o    The  Company  acquired  certain  heavy crude oil  properties  in its
          Northern Plains core region in the first quarter of 2004.
     o    The Company completed the acquisition of certain resource properties
          located in Northeast  British Columbia and Northwest  Alberta in the
          second quarter of 2004. These properties  include further  ownership
          in the Ladyfern natural gas field.
     o    The Company acquired certain light crude oil producing properties in
          the Central  North Sea in the third  quarter of 2004.  The  acquired
          properties comprise operated interests in T-Block (Tiffany, Toni and
          Thelma Fields) and B-Block (Balmoral, Stirling and Glamis Fields).
     o    The Company completed the acquisition of certain resource properties
          located in Alberta,  British Columbia and Saskatchewan in the fourth
          quarter of 2004.

In addition to commodity prices, sales volumes and acquisitions,  net earnings
continued to be impacted by:

     o    The impact of the mark-to-market  ("MTM") treatment of the Company's
          commodity price contracts as part of its commodity  hedging program.
          Steadily  increasing  commodity  prices have resulted in significant
          realized  and  unrealized  risk  management  losses  as the  Company
          strives  to lock  in prices  and  secure  cash flow for its  capital
          expenditure program.
     o    The  MTM  treatment  on  its  stock-based   compensation  plan.  The
          Company's  strong stock  performance has resulted in the recognition
          of significant stock-based compensation expense.
     o    Increasing  production expense.  Higher service costs as a result of
          increased  industry-wide  activity in  reaction to higher  commodity
          prices  as well as the  impact of  higher  crude oil  prices on fuel
          related expenses have resulted in increased costs.
     o    Corporate  income tax rates.  During the first quarter of 2004,  the
          North  America  future tax liability was reduced by $66 million as a
          result of a reduction in the Alberta  corporate income tax rate from
          12.5% to 11.5%.  During the third  quarter of 2005,  the province of
          British Columbia enacted  legislation to reduce its corporate income
          tax rate by 1.5%  effective  July 1,  2005.  As a result,  the North
          America future income tax liability was reduced by $19 million.

<TABLE>
<CAPTION>
BUSINESS ENVIRONMENT
---------------------------------------------------------------------------------------------------
(Yearly average)                                        2005               2004               2003
---------------------------------------------------------------------------------------------------
<S>                                                <C>                <C>                <C>
WTI benchmark price (US$/bbl) (1)                  $   56.61          $   41.43          $   31.02
Dated Brent benchmark price (US$/bbl)              $   54.45          $   38.28          $   28.83
Differential to LLB blend (US$/bbl)                $   20.83          $   13.44          $    8.55
Differential to LLB blend as a % of WTI                  37%                32%                28%
Condensate benchmark price (US$/bbl)               $   57.25          $   41.62          $   31.42
NYMEX benchmark price (US$/mmbtu)                  $    8.56          $    6.09          $    5.44
AECO benchmark price (C$/GJ)                       $    8.05          $    6.43          $    6.35
US/Canadian dollar average exchange rate (US$)        0.8253             0.7683             0.7135
===================================================================================================
</TABLE>

(1)  Refers to West Texas  Intermediate  crude oil barrel  prices at  Cushing,
     Oklahoma.


World light crude oil prices reached all-time highs in 2005, supported by:

     o    Strong demand growth,  particularly  in China,  India and the United
          States;
     o    Ongoing  geopolitical  uncertainties  in  Iran,  Nigeria,  Iraq  and
          Venezuela;
     o    Production losses in the Gulf of Mexico from hurricanes  Katrina and
          Rita.   Many  platforms  and  refineries  are  not  expected  to  be
          operational until sometime late in 2006; and
     o    Restricted crude oil refining  capacity,  which increased  refiners'
          demand  for light  crude oil to  maximize  yields  of  gasoline  and
          distillates.

                                       Management's Discussion & Analysis   49

<PAGE>

West Texas  Intermediate  ("WTI") averaged US$56.61 per bbl for the year ended
December  31,  2005,  an increase of 37%  compared to US$41.43 per bbl for the
year ended December 31, 2004 (2003 - US$31.02 per bbl).

Higher WTI pricing is not fully  reflected  in the  Company's  crude oil price
realizations.  The positive impact of higher WTI prices on the Company's crude
oil   production   continues   to  be  mitigated  by  wider  heavy  crude  oil
differentials,  which  increased  55% to  US$20.83  per bbl for the year ended
December 31, 2005 from  US$13.44 per bbl for the year ended  December 31, 2004
(2003 - $US8.55 per bbl).

Heavy  crude  oil  differentials  in 2005  continued  to be  higher  than  the
long-term  average  primarily  due  to  physical  limitations  for  demand  at
refineries.  Following hurricanes Katrina and Rita, refiners sought to process
lighter  barrels to increase their yields of gasoline and  distillates,  which
resulted in the further deterioration of heavy crude oil differentials.  Plant
turnarounds and maintenance during the year, additional problems at refineries
and upgraders,  the higher cost of diluents,  and the stronger Canadian dollar
also  mitigated the effect of higher WTI prices on the  Company's  heavy crude
oil price  realizations.  A  strengthening  in the Canadian dollar reduces the
Canadian dollar sales price the Company  receives for its crude oil production
as crude oil prices are based on US dollar denominated benchmarks.

North American  natural gas prices also climbed in 2005 due to concerns around
supply as well as the impact of higher  crude oil  prices.  NYMEX  natural gas
prices  increased 41% to average US$8.56 per mmbtu for the year ended December
31, 2005, up from US$6.09 per mmbtu for the year ended December 31, 2004 (2003
- $5.44 per mmbtu).  AECO natural gas pricing moved  directionally with NYMEX,
increasing  25% to average $8.05 per GJ for the year ended  December 31, 2005,
up from $6.43 per GJ for the year ended  December  31,  2004 (2003 - $6.35 per
GJ).

<TABLE>
<CAPTION>
REVENUE, BEFORE ROYALTIES
Analysis of changes in revenue, before royalties
---------------------------------------------------------------------------------------------------------------------------------
                                                  Changes due to                                Changes due to
($ millions)                     2003     Volumes      Prices    Other        2004     Volumes      Prices     Other        2005
---------------------------------------------------------------------------------------------------------------------------------
<S>                          <C>         <C>         <C>        <C>       <C>         <C>         <C>         <C>       <C>
North America
Crude oil and NGLs           $  1,953    $    342    $    283   $   --    $  2,578    $    170    $    546    $   --    $  3,294
Natural gas                     3,068         207         126       --       3,401         208       1,029        --       4,638
---------------------------------------------------------------------------------------------------------------------------------
                                5,021         549         409       --       5,979         378       1,575        --       7,932
---------------------------------------------------------------------------------------------------------------------------------

North Sea
Crude oil and NGLs                873         123         227       --       1,223          31         382        --       1,636
Natural gas                        80           5           9       --          94         (59)        (12)       --          23
---------------------------------------------------------------------------------------------------------------------------------
                                  953         128         236       --       1,317         (28)        370        --       1,659
---------------------------------------------------------------------------------------------------------------------------------

Offshore West Africa
Crude oil and NGLs                141          13          54       --         208         182          86        --         476
Natural gas                        14          (1)          1       --          14          (6)          1        --           9
---------------------------------------------------------------------------------------------------------------------------------
                                  155          12          55       --         222         176          87        --         485
---------------------------------------------------------------------------------------------------------------------------------

Subtotal
Crude oil and NGLs              2,967         478         564       --       4,009         383       1,014        --       5,406
Natural gas                     3,162         211         136       --       3,509         143       1,018        --       4,670
---------------------------------------------------------------------------------------------------------------------------------
                                6,129         689         700       --       7,518         526       2,032        --      10,076

Midstream                          61          --          --        7          68          --          --         9          77
Intersegment eliminations
  and other (1)                   (35)         --          --       (4)        (39)         --          --        (7)        (46)
---------------------------------------------------------------------------------------------------------------------------------
Total                        $  6,155    $    689    $    700   $    3    $  7,547    $    526    $  2,032    $    2    $ 10,107
=================================================================================================================================
</TABLE>

(1)  Eliminates primarily internal transportation and electricity charges.


Revenue rose 34% to $10,107  million in 2005,  up from $7,547  million in 2004
(2003 -  $6,155  million).  Price  increases  accounted  for  79% of the  2005
increase (2004 - 51%), while volume increases  accounted for the remaining 21%
(2004 - 49%).

In 2005, 21% of the Company's  crude oil and natural gas revenue was generated
outside  of  North  America,  up from  20% in 2004  (2003  - 18%).  North  Sea
accounted for 16% of crude oil and natural gas revenue in 2005 and 17% in 2004
(2003 - 16%),  and  Offshore  West  Africa  accounted  for 5% of crude oil and
natural gas revenue in 2005 and 3% in 2004 (2003 - 2%).


50   Management's Discussion & Analysis
<PAGE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
ANALYSIS OF PRODUCT PRICES (1)                          2005               2004               2003
---------------------------------------------------------------------------------------------------
<S>                                                <C>                <C>                <C>
CRUDE OIL AND NGLS ($/bbl) (2)
North America                                      $   39.62          $   33.16          $   29.40
North Sea                                          $   66.57          $   51.37          $   42.00
Offshore West Africa                               $   59.91          $   49.05          $   36.47
Company average                                    $   46.86          $   37.99          $   32.66
---------------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (2)
North America                                      $    8.65          $    6.61          $    6.34
North Sea                                          $    3.17          $    3.73          $    3.03
Offshore West Africa                               $    5.91          $    5.25          $    4.37
Company average                                    $    8.57          $    6.50          $    6.21
---------------------------------------------------------------------------------------------------
Company average ($/boe) (2)                        $   48.77          $   38.45          $   34.84
---------------------------------------------------------------------------------------------------
PERCENTAGE OF REVENUE (excluding midstream
revenue)
Crude oil and NGLs                                      54%                54%                50%
Natural gas                                             46%                46%                50%
===================================================================================================
</TABLE>
(1)  Including transportation costs and excluding risk management activities.
(2)  Amounts expressed on a per unit basis are based on sales volumes.

Realized crude oil prices  increased 23% to average $46.86 per bbl in 2005, up
from  $37.99  per bbl in 2004  (2003 - $32.66  per  bbl).  This  increase  was
primarily  due to  higher  benchmark  world  crude oil  prices,  as well as an
increased  proportion  of crude oil and NGLs sales coming from  Offshore  West
Africa, offset by higher heavy crude oil differentials and a stronger Canadian
dollar.  Higher  benchmark crude oil prices were primarily driven by increased
demand in  countries  such as China,  India and the  United  States as well as
concerns around supply, which increased pricing volatility.

The Company's  realized  natural gas price  increased 32% to average $8.57 per
mcf in 2005,  up from $6.50 per mcf in 2004 (2003 - $6.21 per mcf),  primarily
due to supply  concerns  and a  continued  strengthening  in  benchmark  North
America gas pricing.

NORTH AMERICA

North America  realized  crude oil prices  increased 19% to average $39.62 per
bbl in 2005,  up from  $33.16  per bbl in 2004  (2003 - $29.40  per bbl).  The
increase  in the  realized  crude oil price in 2005 was  mainly  due to higher
benchmark  crude  oil  prices,  partially  offset  by wider  heavy  crude  oil
differentials and the strengthening Canadian dollar.

North  America  continues  to  focus  on its  crude  oil  marketing  strategy,
including the  development of a blending  strategy that expands markets within
current  pipeline  infrastructure,  supporting  pipeline  projects  that  will
provide capacity to transport crude oil to new geographic markets, and working
with refiners to add incremental heavy crude oil conversion capacity.  As part
of an  industry  initiative  to develop new blends of Western  Canadian  crude
oils, the Company has access to blending  capacity of up to 140,000 bbl/d. The
Company is currently  contributing  approximately 139,000 bbl/d of heavy crude
oil blends to the Western Canadian Select ("WCS") stream, a new blend of up to
10  different  crude oil  streams.  WCS  resembles a Bow River type crude with
distillation cuts approximating a natural heavy crude oil with premium quality
asphalt  characteristics and has an API of  19(degree)-22(degree).  Volumes of
the new  blend  are  expected  to grow,  with the  potential  to  become a new
benchmark  for North  American  markets in  addition  to WTI.  The Company has
committed to 25,000 bbl/d of capacity on the  Corsicana  Pipeline,  which will
carry crude oil to the Gulf of Mexico and is expected to be in operation  late
in the first  quarter of 2006.  The Corsicana  Pipeline is made up of a series
of segments  extending from Patoka  Illinois to Nederland  Texas,  near the US
Gulf Coast.

North America  realized  natural gas prices increased 31% to average $8.65 per
mcf for the year ended  December 31, 2005,  up from $6.61 per mcf for the year
ended  December  31,  2004 (2003 - $6.34 per mcf).  This  increase  was due to
supply concerns and  fluctuations in the North America  benchmark  natural gas
price in response to crude oil pricing.

A comparison of the price received for the Company's North America  production
is as follows:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
                                                        2005               2004               2003
---------------------------------------------------------------------------------------------------
<S>                                                <C>                <C>                <C>
Wellhead price (1)(2)
Light crude oil and NGLs (C$/bbl)                  $   58.41          $   45.90          $   37.59
Pelican Lake crude oil (C$/bbl)                    $   38.39          $   32.12          $   28.05
Primary heavy crude oil (C$/bbl)                   $   33.53          $   28.99          $   26.21
Thermal heavy crude oil (C$/bbl)                   $   32.29          $   29.00          $   25.56
Natural gas (C$/mcf)                               $    8.65          $    6.61          $    6.34
===================================================================================================
</TABLE>
(1)  Including transportation costs and excluding risk management activities.
(2)  Amounts expressed on a per unit basis are based on sales volumes.



                                       Management's Discussion & Analysis   51

<PAGE>

NORTH SEA

North Sea realized  crude oil prices  increased 30% to average  $66.57 per bbl
for the year ended  December  31,  2005,  up from  $51.37 per bbl for the year
ended  December 31, 2004 (2003 - $42.00 per bbl). The increase in the realized
crude oil price  compared  to 2004 was due  mainly to higher  world  benchmark
crude oil prices and a narrowing of the average Brent differential,  offset by
the strengthening Canadian dollar.

OFFSHORE WEST AFRICA

Offshore West Africa realized crude oil prices increased 22% to average $59.91
per bbl for the year ended  December 31, 2005, an increase from $49.05 per bbl
for the year ended  December 31, 2004 (2003 - $36.47 per bbl). The increase in
realized  crude  oil  prices  from  2004 was  primarily  due to  higher  world
benchmark crude oil prices offset by the strengthening Canadian dollar.

CRUDE OIL INVENTORY VOLUMES

The  Company  recognizes  revenue  on its  crude  oil  production  when  title
transfers  to the  customer  and  delivery  has taken  place,  referred  to as
"liftings"  in this  MD&A.  For  production  where  revenue  has not yet  been
recognized,  the related  crude oil  inventory  volumes,  by segment,  were as
follows at December 31, 2005:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
(bbl)                                                                                                                     2005
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                                 <C>
North America, related to Corsicana pipeline line fill                                                                 484,157
North Sea, related to timing of liftings                                                                               747,141
Offshore West Africa, related to timing of liftings, net of government entitlement to profit oil                       412,841
-------------------------------------------------------------------------------------------------------------------------------
                                                                                                                     1,644,139
===============================================================================================================================
</TABLE>

At December 31, 2004,  variances between  production volumes and liftings were
not significant.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
ANALYSIS OF DAILY PRODUCTION, BEFORE ROYALTIES          2005               2004               2003
---------------------------------------------------------------------------------------------------
<S>                                                <C>                <C>                <C>
CRUDE OIL AND NGLS (bbl/d)
North America                                        221,669            206,225            174,895
North Sea                                             68,593             64,706             56,869
Offshore West Africa                                  22,906             11,558             10,628
---------------------------------------------------------------------------------------------------
                                                     313,168            282,489            242,392
---------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America                                          1,416              1,330              1,245
North Sea                                                 19                 50                 46
Offshore West Africa                                       4                  8                  8
---------------------------------------------------------------------------------------------------
                                                       1,439              1,388              1,299
---------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d)               552,960            513,835            458,814
---------------------------------------------------------------------------------------------------
PRODUCT MIX (%)
Light crude oil and NGLs                                 26%                 24%               25%
Pelican Lake crude oil                                    4%                  4%                5%
Primary heavy crude oil                                  17%                 19%               15%
Thermal heavy crude oil                                  10%                  8%                8%
Natural gas                                              43%                 45%               47%
===================================================================================================


<CAPTION>
---------------------------------------------------------------------------------------------------
DAILY PRODUCTION, NET OF ROYALTIES                      2005               2004               2003
---------------------------------------------------------------------------------------------------
<S>                                                <C>                <C>                <C>
CRUDE OIL AND NGLS (bbl/d)
North America                                        191,751            180,011            152,444
North Sea                                             68,487             64,598             56,928
Offshore West Africa                                  22,293             11,221             10,314
---------------------------------------------------------------------------------------------------
                                                     282,531            255,830            219,686
---------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America                                          1,125              1,048                976
North Sea                                                 18                 50                 46
Offshore West Africa                                       4                  7                  8
---------------------------------------------------------------------------------------------------
                                                       1,147              1,105              1,030
---------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d)               473,742            440,022            391,361
===================================================================================================
</TABLE>

Daily production and per barrel statistics are presented  throughout this MD&A
on a "before  royalty"  or  "gross"  basis.  Production  net of  royalties  is
presented for information purposes only.


52   Management's Discussion & Analysis

<PAGE>

The Company's  business approach is to maintain large project  inventories and
production  diversification among each of the commodities it produces;  namely
natural gas, light crude oil and NGLs,  Pelican Lake crude oil,  primary heavy
crude oil and thermal heavy crude oil.

Record levels of total crude oil and natural gas production  averaged  552,960
boe/d for the year ended  December 31, 2005, an increase of 8% or 39,125 boe/d
from  513,835  boe/d for the year  ended  December  31,  2004  (2003 - 458,814
boe/d).  The increase in production  year over year was due to organic  growth
from the Company's extensive North America capital expenditure program and the
commencement  of  production  from the Baobab Field  offshore Cote d'Ivoire in
2005, as well as the full year impact of accretive  acquisitions  completed in
2004.

Total record  crude oil and NGLs  production  for the year ended  December 31,
2005  increased  11% to 313,168  bbl/d from  282,489  bbl/d for the year ended
December 31, 2004 (2003 - 242,392  bbl/d).  Crude oil and NGLs  production for
2005 was in line with the Company's guidance of 308,000 to 316,000 bbl/d.

Natural gas production  continues to represent the Company's  largest  product
offering.  Natural  gas  production  for the  year  ended  December  31,  2005
increased 4% or 51 mmcf/d to average 1,439 mmcf/d compared to 1,388 mmcf/d for
the year ended December 31, 2004 (2003 - 1,299 mmcf/d).  Growth in natural gas
production in Western Canada was  negatively  affected by the early arrival of
spring  breakup and weather  related delays due to unusually wet conditions as
well as an overall increase in industry activity. The market for the necessary
oilfield services and material has become increasingly competitive,  resulting
in drilling, completion, tie-in and maintenance delays. Natural gas production
for 2005 was in line with the Company's guidance of 1,436 to 1,448 mmcf/d.

The Company expects annual production levels in 2006 to average 1,468 to 1,551
mmcf/d of natural  gas and  335,000  to  373,000  bbl/d of crude oil and NGLs.
First quarter 2006 production is expected to be between 1,426 and 1,475 mmcf/d
of natural gas and 306,000 to 334,000 bbl/d of crude oil and NGLs.

NORTH AMERICA

North America crude oil and NGLs  production  for the year ended  December 31,
2005 increased 7% or 15,444 bbl/d to average  221,669  bbl/d,  up from 206,225
bbl/d  for the year  ended  December  31,  2004  (2003 - 174,895  bbl/d).  The
increase  in crude oil and NGLs  production  was  mainly  due to the timing of
Primrose  production  cycles  and the  positive  results of the  Pelican  Lake
waterflood project.

North  America  natural gas  production  for the year ended  December 31, 2005
increased  6% or 86 mmcf/d to average  1,416  mmcf/d,  up from 1,330 mmcf/d in
2004 (2003 - 1,245 mmcf/d).  Natural gas  production  increased as a result of
organic growth and the full year impact of accretive property  acquisitions in
2004, but was  negatively  impacted by the early arrival of spring breakup and
weather  related  delays due to  unusually  wet  conditions  during the summer
months.  In addition to weather related  factors,  production  growth was also
negatively  impacted  by  the  increased  demand  for  oilfield  services  and
materials,  which caused delays in the timing of  production  being brought on
stream.

NORTH SEA

North Sea crude oil production for the year ended December 31, 2005 was 68,593
bbl/d,  an increase of 6% from  64,706  bbl/d for 2004 (2003 - 56,869  bbl/d).
Production  levels  were in line  with  expectations,  reflecting  anticipated
curtailments  at the Lyell Field and the  Columba B and E Terraces,  continued
restrictions  at  Murchison  Field  due to  third  party  natural  gas  export
facilities and production declines at the satellite Playfair Field.

Natural gas  production in the North Sea for the year ended  December 31, 2005
decreased  62% to average  19  mmcf/d,  down from 50 mmcf/d for the year ended
December 31, 2004 (2003 - 46 mmcf/d).  The decrease in natural gas  production
was due to the  commencement  of the  natural gas  reinjection  program in the
Banff Field in the Central North Sea late in 2004. The natural gas reinjection
project  is  expected  to  result  in an  overall  increase  in the  reservoir
recovery, but resulted in reductions in natural gas production in 2005.

OFFSHORE WEST AFRICA

Offshore West Africa crude oil production for the year ended December 31, 2005
increased  98% to 22,906 bbl/d from 11,558  bbl/d for the year ended  December
31, 2004 (2003 - 10,628 bbl/d).  The production  increase was primarily due to
commencement  of production from the 57.61% owned and operated Baobab Field in
August 2005,  as well as increased  production  from  additional  infill wells
drilled in East Espoir.


                                       Management's Discussion & Analysis   53
<PAGE>

ROYALTIES                                         2005      2004     2003
------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America                                   $ 5.37    $ 4.21   $ 3.79
North Sea                                       $ 0.10    $ 0.08   $(0.03)
Offshore West Africa                            $ 1.62    $ 1.43   $ 1.08
Company average                                 $ 3.97    $ 3.16   $ 2.77
------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
North America                                   $ 1.78    $ 1.40   $ 1.38
North Sea                                       $   --    $   --   $   --
Offshore West Africa                            $ 0.16    $ 0.15   $ 0.13
Company average                                 $ 1.75    $ 1.35   $ 1.32
------------------------------------------------------------------------------
COMPANY AVERAGE ($/boe) (1)                     $ 6.82    $ 5.37   $ 5.20
------------------------------------------------------------------------------
PERCENTAGE OF REVENUE (2)
Crude oil and NGLs                                  8%        8%       9%
Natural gas                                        20%       21%      21%
Boe                                                14%       14%      15%
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.


NORTH AMERICA

North America crude oil and NGLs royalties per bbl for the year ended December
31, 2005  increased  from 2004  primarily  due to higher  benchmark  crude oil
prices,  offset by wider heavy  crude oil  differentials  and a  strengthening
Canadian  dollar.  Royalty  rates are  expected to increase in the future as a
result of the Primrose  South Field  payout  expected to occur late in 2006 or
early 2007.

Natural gas royalties  increased from 2004 due to higher benchmark natural gas
prices,  offset by a stronger Canadian dollar and adjustments to royalty rates
related to prior years.

NORTH SEA

North Sea government  royalties on crude oil were eliminated effective January
1, 2003. The remaining North Sea royalty represents a gross overriding royalty
on the Ninian  Field.  In 2003,  the  Company  received a refund of  royalties
previously provided.

OFFSHORE WEST AFRICA

Offshore West Africa production is governed by the terms of Production Sharing
Contracts  ("PSCs").  Under the PSCs,  revenues are divided into cost recovery
revenue  and profit  revenue.  Cost  recovery  revenue  allows the  Company to
recover its capital and  operating  costs and the costs carried by the Company
on  behalf of the Government State Oil Company. Profit revenue is allocated to
the  joint  venture  partners  in  accordance  with  their  respective  equity
interests,  after a  portion  has  been  allocated  to the  Government.  These
revenues  are reported as sales  revenue.  The  Government's  share of  profit
revenue  attributable to the Company's equity interest is allocated to royalty
expense and current income tax expense in accordance  with the PSCs.  Based on
current  projections,  the Espoir  Field and the Baobab  Field are expected to
reach payout in 2007,  which will increase  royalty  rates and current  income
taxes in accordance with the PSCs.

PRODUCTION EXPENSE                              2005        2004      2003
------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America                                  $ 10.49   $  8.94   $  9.14
North Sea                                      $ 14.94   $ 14.03   $ 14.07
Offshore West Africa                           $  6.50   $  7.59   $  8.68
Company average                                $ 11.17   $ 10.05   $ 10.28
------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
North America                                  $  0.71   $  0.62   $  0.57
North Sea                                      $  2.44   $  2.07   $  1.33
Offshore West Africa                           $  1.05   $  1.33   $  1.39
Company average                                $  0.73   $  0.67   $  0.60
------------------------------------------------------------------------------
COMPANY AVERAGE ($/boe) (1)                    $  8.21   $  7.35   $  7.15
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.


The Company  continues to experience  increasing  production  expense in 2006,
reflecting industry cost pressures in all of its operating areas.

54   Management's Discussion & Analysis
<PAGE>

NORTH AMERICA

North America crude oil and NGLs production expense per bbl for the year ended
December 31, 2005  increased by 17% from 2004.  The increase was primarily due
to higher  industry wide service costs,  higher fuel related  expenses,  and a
larger  portion of the Company's  crude oil volumes being  comprised of higher
cost thermal crude oil in 2005 versus 2004,  offset by the positive  impact of
higher volumes relative to fixed costs.

North  America  natural  gas  production  expense  per mcf for the year  ended
December 31, 2005 increased from the comparable  periods in 2004. The increase
from 2004 was due to the  service  and  commodity  cost  pressures  previously
noted,  offset by the  positive  impact of higher  volumes  relative  to fixed
costs.

NORTH SEA

North Sea crude oil production  expense varied on a per barrel basis from 2004
primarily  due to the timing of  maintenance  work,  the changes in production
volumes on a relatively  fixed cost base,  the timing of liftings from various
fields and the impact of production  being diverted from the Kyle Field to the
Banff floating production storage and offtake vessel ("FPSO").

OFFSHORE WEST AFRICA

Offshore West Africa crude oil production expenses are largely fixed in nature
and  fluctuated  on a per barrel  basis  from 2004 due to changes in  volumes.
Production expenses for the year ended December 31, 2005 compared to 2004 were
primarily  impacted by the commencement of production from the Baobab Field in
August 2005.

MIDSTREAM

($ millions)                                         2005     2004      2003
------------------------------------------------------------------------------
Revenue                                              $ 77     $ 68      $ 61
Production expense                                     24       20        15
------------------------------------------------------------------------------
Midstream cash flow                                    53       48        46
Depreciation                                            8        7         7
------------------------------------------------------------------------------
Segment earnings before taxes                        $ 45     $ 41      $ 39
==============================================================================


The Company's midstream assets consist of three crude oil pipeline systems and
a 50%  working  interest in an  84-megawatt  cogeneration  plant at  Primrose.
Approximately  80% of the Company's  heavy crude oil production is transported
to  international  mainline  liquid  pipelines via the 100% owned and operated
ECHO  Pipeline,  the 62% owned and operated  Pelican Lake Pipeline and the 15%
owned Cold Lake Pipeline.  The midstream  pipeline assets allow the Company to
control  the  transport  of its own  production  volumes as well as earn third
party revenue.  This transportation  control enhances the Company's ability to
manage the full range of costs  associated  with the development and marketing
of its heavier crude oil.

Earnings  and  cash flow  attributable  to  midstream  assets  have  increased
marginally  from 2004  primarily due to increased  heavy crude oil  throughput
volumes and increased revenue from the Company's cogeneration plant.

DEPLETION, DEPRECIATION AND AMORTIZATION(1)

($ millions, except per boe amounts) (2)          2005       2004        2003
------------------------------------------------------------------------------
North America                                  $ 1,595    $ 1,444     $ 1,209
North Sea                                          306        265         252
Offshore West Africa                               104         53          41
------------------------------------------------------------------------------
Expense                                        $ 2,005    $ 1,762     $ 1,502
  $/boe                                        $ 10.02    $  9.37     $  8.96
==============================================================================
(1) DD&A excludes depreciation on midstream assets.
(2) Amounts expressed on a per unit basis are based on sales volumes.


Depletion,  Depreciation and Amortization ("DD&A") for the year ended December
31, 2005 increased in total and on a boe basis from 2004. The increase in DD&A
was due to higher finding and  development  costs  associated with natural gas
exploration in North  America,  the fair value  allocation of the  acquisition
costs associated with acquisitions  completed late in 2004, future abandonment
costs  associated with the  acquisition of additional  properties in the North
Sea, higher estimated future costs to develop the Company's proved undeveloped
reserves in the North Sea and the  commencement  of production from the Baobab
Field in August 2005.

ASSET RETIREMENT OBLIGATION ACCRETION

($ millions, except per boe amounts) (1)          2005       2004        2003
------------------------------------------------------------------------------
North America                                   $   34     $   28      $   26
North Sea                                           34         22          36
Offshore West Africa                                 1          1          --
------------------------------------------------------------------------------
Expense                                         $   69     $   51      $   62
  $/boe                                         $ 0.34     $ 0.27      $ 0.37
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.


                                        Management's Discussion & Analysis  55

<PAGE>


Accretion  expense  is  the  increase  in the  carrying  amount  of the  asset
retirement obligations due to the passage of time. Asset retirement obligation
accretion  expense for North  America  increased  $6 million or 21% from 2004,
primarily due to increased  activity in the conventional  drilling program and
increased  requirements under provincial  reclamation  legislation.  Accretion
expense for the North Sea increased $12 million or 55% from 2004,  largely due
to the  impact  of  additional  retirement  obligations  related  to  property
acquisitions completed late in 2004.

ADMINISTRATION EXPENSE

($ millions, except per boe amounts) (2)          2005       2004(1)     2003
------------------------------------------------------------------------------
Net expense                                     $  151     $  125      $   87
  $/boe                                         $ 0.75     $ 0.66      $ 0.52
==============================================================================
(1) Restated to conform to current year presentation.
(2) Amounts expressed on a per unit basis are based on sales volumes.


Net  administration  expense for the year ended December 31, 2005 increased in
total and on a boe basis from the year ended  December 31, 2004  primarily due
to higher staffing levels  associated with the Company's  expanding asset base
and costs associated with the Company's Share Bonus Plan.

The Share Bonus Plan  incorporates  employee  share  ownership  in the Company
while  reducing  the  granting of stock  options  and the  dilution of current
Shareholders.  Under the plan,  cash  bonuses  awarded  based on  Company  and
employee  performance  are  subsequently  used by a trustee to acquire  common
shares  of  the  Company.  The  common  shares  vest  to the  employee  over a
three-year  period  provided the employee does not leave the employment of the
Company.  If the employee  leaves the employment of the Company,  the unvested
common  shares are forfeited  under the terms of the plan.  For the year ended
December 31, 2005, the Company recognized $17 million of compensation  expense
under the Share Bonus Plan (December 31, 2004 - $10 million; 2003 - $nil).

STOCK-BASED COMPENSATION

($ millions)                                      2005       2004        2003
------------------------------------------------------------------------------
Stock-based compensation expense                $  723     $  249      $  200
==============================================================================

The Company's Stock Option Plan (the "Option Plan") provides current employees
(the "option  holders")  with the right to elect to receive common shares or a
direct cash  payment in exchange  for options  surrendered.  The design of the
Option Plan balances the need for a long-term  compensation  program to retain
employees  with the  benefits  of  reducing  the impact of dilution on current
Shareholders  and the  reporting  of the  obligations  associated  with  stock
options.  Transparency  of the  cost of the  Option  Plan is  increased  since
changes in the intrinsic  value of  outstanding  stock options are  recognized
each  period.   The  cash  payment   feature   provides  option  holders  with
substantially  the same benefits and allows them to realize the value of their
options through a simplified administration process.

The Company  recorded a $723  million  ($481  million  after tax)  stock-based
compensation  expense for the year ended December 31, 2005 in connection  with
the 125%  appreciation  in the  Company's  share  price  (December  31, 2005 -
C$57.63;  December 31, 2004 - C$25.63;  December 31, 2003 - C$16.34;  December
31, 2002 - C$11.70).  As required by GAAP,  the  Company's  outstanding  stock
options are valued based on the  difference  between the exercise price of the
stock options and the market price of the Company's common shares, pursuant to
a graded  vesting  schedule.  The  liability is revalued  quarterly to reflect
changes in the market  price of the  Company's  common  shares and the options
exercised or surrendered in the period,  with the net change recognized in net
earnings,  or capitalized  during the  construction  period in the case of the
Horizon Project (2005 - $101 million; 2004 - $21 million; 2003 - $10 million).
The stock-based  compensation  liability reflects the Company's potential cash
liability  should all the vested options be  surrendered  for a cash payout at
the market price on December 31, 2005. In periods when substantial stock price
changes occur, the Company is subject to significant earnings volatility.

For the year ended  December 31, 2005, the Company paid $227 million for stock
options surrendered for cash settlement (December 31, 2004 - $80 million; 2003
- $31 million).

INTEREST EXPENSE

($ millions, except per boe amounts and interest rates)(1)   2005   2004   2003
-------------------------------------------------------------------------------
Interest expense                                           $  149 $  189 $  201
  $/boe                                                    $ 0.74 $ 1.01 $ 1.20
Average effective interest rate                              5.6%   5.2%   5.8%
===============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.


56   Management's Discussion & Analysis
<PAGE>

Net  interest  expense  decreased  on a total and boe basis for the year ended
December  31,  2005  from  2004  primarily  due  to  the   capitalization   of
construction  period  interest  related to the Horizon  Project in 2005 of $72
million (2004 and 2003 - $nil).  Pre-capitalization  interest  increased  from
2004  mainly due to higher  interest  rates and  carrying  charges,  offset by
decreased  average  debt levels and the impact of the  strengthening  Canadian
dollar,  which  decreased  interest  expense  attributable to the Company's US
dollar denominated debt securities.

RISK MANAGEMENT ACTIVITIES

The Company utilizes various  derivative  financial  instruments to manage its
commodity  price,  currency  and interest  rate  exposures.  These  derivative
financial  instruments  are not  used for  trading  or  speculative  purposes.
Changes in fair value of derivative financial instruments designated as hedges
are not recognized in net earnings until such time as the corresponding  gains
or losses on the related  hedged  items are also  recognized.  Changes in fair
value of  derivative  financial  instruments  not  designated  as  hedges  are
recognized  in the  consolidated  balance  sheets  each period with the offset
reflected in risk management activities in the statements of earnings.

The Company  formally  documents all hedging  transactions at the inception of
the hedging  relationship  in accordance  with the Company's  risk  management
policies.  The effectiveness of the hedging  relationship is evaluated both at
inception of the hedge and on an ongoing basis.

The Company enters into commodity price contracts to manage  anticipated sales
of crude oil and natural  gas  production  in order  to protect  cash flow for
capital expenditure programs.  Gains or losses on these contracts are included
in risk management activities.

The Company  enters into interest rate swap  agreements to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal amount on which the payments are based.  Gains or losses on interest
rate swap  contracts  designated  as hedges are included in interest  expense.
Gains or losses on non-designated interest rate contracts are included in risk
management activities.

Cross  currency  swap  agreements  are  periodically  used to manage  currency
exposure on US dollar  denominated  long-term  debt.  The cross  currency swap
contracts  require the  periodic  exchange of  payments  with the  exchange at
maturity of notional  principal amounts on which the payments are based. Gains
or losses on cross currency swap  contracts  designated as hedges are included
in interest expense.

Gains or losses on the termination of derivative  financial  instruments  that
have been  designated as hedges are deferred under other assets or liabilities
on the  consolidated  balance  sheets and  amortized  into net earnings in the
period in which the underlying hedged transaction is recognized.  In the event
a  designated  hedged  item is  sold,  extinguished  or  matures  prior to the
termination of the related derivative  instrument,  any unrealized  derivative
gain or loss is recognized immediately in net earnings. Gains or losses on the
termination of financial  instruments  that have not been designated as hedges
are recognized in net earnings immediately.

($ millions)                                      2005       2004        2003
------------------------------------------------------------------------------
Realized loss (gain)
Crude oil and NGLs financial instruments       $   753    $   501     $    95
Natural gas financial instruments                  283          5          88
Interest rate swaps                                 (9)       (32)        (35)
------------------------------------------------------------------------------
                                               $ 1,027    $   474     $   148
------------------------------------------------------------------------------
Unrealized loss (gain)
Crude oil and NGLs financial instruments       $   847    $   (47)    $    --
Natural gas financial instruments                   77         --          --
Interest rate swaps                                  1          7          --
------------------------------------------------------------------------------
                                               $   925    $   (40)    $    --
------------------------------------------------------------------------------
Total                                          $ 1,952    $   434     $   148
==============================================================================


The  realized  loss  from  crude  oil  and  NGLs  and  natural  gas  financial
instruments decreased the Company's average realized prices as follows:

                                                  2005       2004        2003
------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)(1)                   $ 6.68     $ 4.85      $ 1.07
Natural gas ($/mcf)(1)                          $ 0.54     $ 0.01      $ 0.19
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volume.


                                        Management's Discussion & Analysis  57
<PAGE>

The realized gain on  non-designated  interest rate swaps would have decreased
the Company's reported interest expense as follows:

($ millions, except interest rates)               2005       2004        2003
------------------------------------------------------------------------------
Interest expense as reported                  $    149    $   189     $   201
Less: realized risk management gain                 (9)       (32)        (35)
------------------------------------------------------------------------------
                                              $    140    $   157     $   166
Average effective interest rate                   5.2%       4.4%        4.8%
==============================================================================


As effective as commodity  hedges are against  reference  commodity  prices, a
substantial  portion of the derivative  financial  instruments entered into by
the Company do not meet the  requirements  for hedge accounting under GAAP due
to currency,  product quality and location  differentials (the "non-designated
hedges").  The  Company is  required to  mark-to-market  these  non-designated
hedges based on prevailing  forward  commodity  prices in effect at the end of
each  reporting  period.  Accordingly,   unrealized  risk  management  expense
reflects,  at the balance sheet date, the implied price  differentials for the
non-designated  hedges for future years. Due to the dramatic increase in crude
oil and  natural  gas forward  pricing in 2005,  the  Company  recorded a $925
million  ($607  million  after  tax)  unrealized  loss on its risk  management
activities  for the year ended December 31, 2005 (2004 - a $40 million gain or
$27 million after tax; 2003 - $nil).

The  cash  settlement  amount  of the  risk  management  financial  derivative
instruments  may vary materially  depending upon the underlying  crude oil and
natural gas prices at the time of final settlement of the financial derivative
instruments, as compared to their mark-to-market value at December 31, 2005.

In addition to the risk management  liability  recognized on the balance sheet
at December 31, 2005, the net unrecognized liability related to the fair value
of  derivative  financial  instruments  designated  as hedges was $990 million
(December 31, 2004 - net unrecognized asset of $33 million).

Details relating to outstanding  derivative financial  instruments at December
31, 2005 are disclosed in note 10 to the Company's audited annual consolidated
financial statements as at December 31, 2005.

FOREIGN EXCHANGE

($ millions)                                      2005       2004        2003
------------------------------------------------------------------------------
Realized foreign exchange (gain) loss            $ (29)     $   3      $    8
Unrealized foreign exchange gain                  (103)       (94)       (343)
------------------------------------------------------------------------------
Total                                            $(132)     $ (91)     $ (335)
==============================================================================


The Company's  results are affected by the exchange rates between the Canadian
dollar, US dollar, and UK pound sterling.  A majority of the Company's revenue
is based on reference to US dollar benchmark  prices. An increase in the value
of the Canadian  dollar in relation to the US dollar  results in lower revenue
from the sale of the Company's production.  Conversely a decrease in the value
of the  Canadian  dollar in  relation  to the US dollar  will result in higher
revenue from the sale of the  Company's  production.  Production  expenses are
also subject to  fluctuations  due to changes in the  exchange  rate of the UK
pound sterling to the US dollar related to North Sea operations.  The value of
the Company's US dollar  denominated debt is also impacted by the value of the
Canadian dollar in relation to the US dollar.

In 2005, the majority of the realized  foreign exchange gain was the result of
the repayment of the Company's US dollar  preferred  securities.  In addition,
net foreign exchange gains were realized on foreign exchange rate fluctuations
on working capital items denominated in US dollars or UK pounds sterling.  The
unrealized foreign exchange gain is related to the fluctuation of the Canadian
dollar in  relation  to the US dollar  with  respect to the US dollar debt and
working capital denominated in US dollars or UK pounds sterling.  The Canadian
dollar ended the year at US$0.8577  compared to US$0.8308 at December 31, 2004
(2003 - US$0.7738).

In order to mitigate a portion of the volatility  associated with fluctuations
in exchange rates,  the Company has designated  certain US dollar  denominated
debt as a hedge against its net investment in US dollar based  self-sustaining
foreign  operations.  Accordingly,  translation  gains  and  losses on this US
dollar  denominated  debt are  included  in the foreign  currency  translation
adjustment in Shareholders' equity in the consolidated balance sheets.


58    Management's Discussion & Analysis
<PAGE>

TAXES

($ millions, except income tax rates)             2005       2004        2003
------------------------------------------------------------------------------
Taxes other than income tax
Current                                       $    203    $   210    $    116
Deferred                                            (9)       (45)         (9)
------------------------------------------------------------------------------
Total                                         $    194    $   165    $    107
==============================================================================
Current income tax
North America - Current income tax            $     82    $    89    $     43
North America - Large Corporations Tax              16         11          16
North Sea                                          155          2          23
Offshore West Africa                                32         13          10
Other                                                1          1          --
------------------------------------------------------------------------------
Total                                         $    286    $   116    $     92
==============================================================================
Future income tax                             $    353    $   474    $    338
Effective income tax rate                        37.8%      29.6%       23.5%
==============================================================================


Taxes other than income tax includes  current and deferred  petroleum  revenue
tax ("PRT") and  Canadian  provincial  capital  taxes and  surcharges.  PRT is
charged on certain fields in the North Sea at the rate of 50% of net operating
income,   after  allowing  for  certain   deductions   including   abandonment
expenditures.

Taxable  income from the  conventional  crude oil and natural gas  business in
Canada is generated by partnerships,  with the related income taxes payable in
a subsequent  year.  North America  current income taxes have been provided on
the basis of the corporate  structure and available  income tax deductions and
will vary upon the  nature  and amount of  capital  expenditures  incurred  in
Canada.

The North Sea  current  income tax expense  for 2005  increased  from 2004 due
mainly to higher  realized  product  prices,  increased  sales volumes and the
deductibility  in 2004 of the cost of assets  acquired  in the UK. In December
2005, the UK government  announced plans to double the supplementary charge on
profits  from UK North Sea crude oil and  natural  gas  production  to 20%. If
enacted,  the  increased  North Sea  supplementary  charge would  increase the
Company's income tax rate in the North Sea from 40% to 50%. The  supplementary
charge  excludes any  deduction  for  financing  costs.  A charge has not been
reflected  in  2005  net  earnings  as  the  proposed   change  has  not  been
substantively  enacted.  If enacted in 2006, the Company anticipates that this
rate change will  result in a charge to future  income  taxes in the amount of
$111 million.

During 2005, the province of British  Columbia  enacted  legislation to reduce
its corporate income tax rate by 1.5% effective July 1, 2005. As a result, the
North America future income tax liability was reduced by $19 million. In 2004,
the North America  future tax liability was reduced by $66 million as a result
of a reduction in the Alberta  corporate  income tax rate from 12.5% to 11.5%.
In 2003, the Federal  Government  enacted  legislation to reduce the corporate
income tax rate on income from resource  activities  over a  five-year  period
starting  January 1, 2003,  bringing  the  resource  industry in line with the
general  corporate  income tax rate. As part of the corporate  income tax rate
reduction,  the  legislation  also provides for the phased  elimination of the
existing 25% resource allowance and the introduction of a deduction for actual
provincial and other crown royalties paid.

The  following  table  shows the effect of  non-recurring  benefits  on income
taxes:

($ millions, except income tax rates)             2005       2004        2003
------------------------------------------------------------------------------
Income tax as reported
Current income tax                              $  286    $   116     $    92
Future income tax expense                          353        474         338
------------------------------------------------------------------------------
                                                   639        590         430
Provincial corporate tax rate reductions            19         66          31
Federal corporate tax rate reductions               --         --         247
------------------------------------------------------------------------------
Total                                           $  658    $   656     $   708
Expected effective income tax rate
   before non-recurring benefits                 39.0%      32.9%       38.6%
==============================================================================


The effective  income tax rate for 2005 increased over 2004 due to the effects
of  the  phased   elimination  of  the  resource   allowance  and  the  phased
deductibility  of crown  royalties.  It is anticipated  that in 2006, based on
budgeted  prices and the  current  availability  of tax pools,  the Company is
expected  to be cash  taxable in Canada in the amount of $110  million to $170
million.


                                     Management's Discussion & Analysis    59
<PAGE>

CAPITAL EXPENDITURES (1)
($ millions)                                       2005       2004       2003
------------------------------------------------------------------------------
Expenditures on property, plant and equipment
Net property acquisitions (2)                  $   (320)  $  1,835   $    336
Land acquisition and retention                      254        120        154
Seismic evaluations                                 132         89         77
Well drilling, completion and equipping           2,000      1,394      1,194
Pipeline and production facilities                1,295        821        522
------------------------------------------------------------------------------
Total net reserve replacement expenditures        3,361      4,259      2,283
------------------------------------------------------------------------------
Horizon Project:
  Phase 1 construction costs                      1,329         --         --
  Capitalized interest and other                    170        291        152
------------------------------------------------------------------------------
Total Horizon Project                             1,499        291        152
------------------------------------------------------------------------------
Midstream                                             4         16         11
Abandonments (3)                                     46         32         40
Head office                                          22         35         20
------------------------------------------------------------------------------
Total net capital expenditures                 $  4,932   $  4,633   $  2,506
------------------------------------------------------------------------------
By segment
------------------------------------------------------------------------------
North America                                  $  2,530   $  3,355   $  1,769
North Sea                                           387        608        338
Offshore West Africa                                439        295        176
Other                                                 5          1         --
Horizon Project                                   1,499        291        152
Midstream                                             4         16         11
Abandonments (3)                                     46         32         40
Head office                                          22         35         20
------------------------------------------------------------------------------
Total                                          $  4,932   $  4,633   $  2,506
==============================================================================
(1) The net capital  expenditures do not include non-cash property,  plant and
    equipment additions or disposals.
(2) Includes Business  Combinations.  The 2004 comparative figure includes $26
    million in non-cash consideration.
(3) Abandonments represent expenditures to settle asset retirement obligations
    and have been reflected as capital expenditures in this table.


The Company's strategy is focused on building a diversified asset base that is
balanced among various products.  In order to facilitate efficient operations,
the Company  focuses its  activities in core regions where it can dominate the
land base and  infrastructure.  The Company  focuses on  maintaining  its land
inventories to enable the continuous exploitation of play types and geological
trends,   greatly   reducing   overall   exploration   risk.   By   dominating
infrastructure,  the Company is able to maximize utilization of its production
facilities, thereby increasing control over production costs.

Net  capital  expenditures  for the year ended  December  31, 2005 were $4,932
million  compared to $4,633 million for the year ended December 31, 2004 (2003
- $2,506  million).  During 2005,  the Company  continued to make  significant
progress  on its  larger,  future-growth  projects,  most  notably the Horizon
Project, while maintaining its focus on existing assets. The Company drilled a
total of 1,882 net wells in 2005  consisting  of 890  natural  gas wells,  627
crude oil wells, 248 stratigraphic  test and service wells, and 117 wells that
were dry.  This  compared to 1,449 net wells drilled in 2004 (2003 - 1,793 net
wells).  The  Company  achieved  an  overall  success  rate of 93%,  excluding
stratigraphic test and service wells (2004 and 2003 - 91%).

NORTH AMERICA

North  America   accounted  for   approximately   83%  of  the  total  capital
expenditures  for the year ended  December 31, 2005 compared to  approximately
80% in 2004 (2003 - 79%).

During  2005,  the  Company  drilled  975 net  wells  targeting  natural  gas,
including 228 wells in Northeast British  Columbia,  238 wells in the Northern
Plains region, 166 wells in Northwest  Alberta,  and 343 wells in the Southern
Plains  region.  The Company  also drilled 642 net wells  targeting  crude oil
during 2005.  The majority of these wells were  concentrated  in the Company's
crude oil Northern  Plains region where 360 heavy crude oil wells,  84 Pelican
Lake crude oil wells, 109 thermal crude oil wells, and 7 light crude oil wells
were drilled. Another 82 light crude oil wells were drilled during the year in
the Company's other regions.

As part of the  development of the Company's  heavy crude oil  resources,  the
Company is continuing with its Primrose thermal  projects,  which includes the
Primrose North expansion project and drilling additional wells in the Primrose
South project to augment existing production. The Primrose North expansion was
substantially   completed  in  2005  with  total   capital   expenditures   of
approximately  $300 million incurred.  Initial steaming  commenced in November
2005 and first crude oil production began in January 2006.


60    Management's Discussion & Analysis
<PAGE>

In  2004,  the  Company  filed a public  disclosure  document  for  regulatory
approval  of its  Primrose  East  project,  a new  facility  located  about 15
kilometers from its existing Primrose South steam plant and 25 kilometers from
its Wolf Lake central  processing  facility.  The development  application was
submitted to the Alberta  Energy and  Utilities  Board in January  2006,  with
potential  impacts  associated with the use of bitumen as fuel being evaluated
in the Environmental  Impact Assessment.  The Company expects  construction to
begin in 2007, with initial steaming scheduled for January 2009.

Development  at Pelican Lake  continued on track in 2005,  with 84 wells being
drilled  and  production   increasing  from  approximately   18,000  bbl/d  to
approximately  28,000  bbl/d  over the  course  of the  year.  The  waterflood
conversion   project  is  on  schedule  with  production   response  exceeding
expectations.  The Company  plans to enhance the  waterflood  process  through
utilization  of Polymer  Flood  technology.  A Polymer Flood pilot has been in
operation since May 2005 with positive results. The drilling of 150 horizontal
wells is planned for 2006.

During  2005,  the  Company  sold a large  portion of its  overriding  royalty
interests  on  various  producing  properties  throughout  Western  Canada and
Ontario  that were  considered  non-core to its  operations,  for  proceeds of
approximately $345 million, after giving effect to anticipated adjustments.

Above average temperatures have continued into 2006. Accordingly,  the Company
is leveraging  its deep drilling  inventory and  optimizing  drilling plans to
adjust for road bans and/or site access issues.  Despite these  challenges the
Company still expects to complete the majority of its winter drilling program.
However,   the  risk  remains  for  an  early  spring   breakup   which  could
significantly delay tie-ins of many of these new wells. In 2006, the Company's
overall  drilling  activity in North  America is expected to be  comprised  of
approximately  1,139  net  natural  gas  wells  and 697 net  crude  oil  wells
excluding stratigraphic test/service wells.

HORIZON PROJECT

On February 9, 2005 the Board of Directors of the Company unanimously approved
the Company to proceed with Phase 1 of the Horizon Project.

The Horizon Project has continued on schedule and on budget. Specifically,  as
at December 31, 2005:

    o    Phase 1 Horizon Project construction was 19% complete;
    o    The detailed  engineering work was on schedule,  with 3-D engineering
         models progressing as planned;
    o    The Company  awarded $3.8 billion of contracts  and purchase  orders,
         with a further $600 million in various stages of the tender  process;
         and
    o    Approximately 1,700 people were on site and functional.

Major activities for 2006 will include:

    o    Substantial completion of detailed engineering;
    o    Completion and setting of main piperack modules;
    o    Receiving and erecting of critical equipment;
    o    Beginning construction of ore preparation plant; and
    o    Substantial completion of foundations in each area.

First production of light, sweet Synthetic Crude Oil from Phase 1 construction
is targeted to commence in the second half of 2008. The Horizon  Project is in
the early stages of construction.

NORTH SEA

The Company  continued  in 2005 with its planned  program of infill  drilling,
recompletions,  workovers and  waterflood  optimizations.  During 2005, 14 net
wells were drilled, consisting of 12 net crude oil wells, 1 net dry well and 1
net service well, with an additional 2.9 net wells drilling at quarter-end.

In anticipation of the 2005 program of infill drilling,  workovers,  and third
party  business  on  the  T  and B  Blocks,  the  Company  completed  a  major
refurbishment  of the Tiffany  platform  drilling rig, which is facilitating a
two-well program  targeting unswept areas of the field. The first of these two
wells was drilled and completed late in 2005.

Production  from the Kyle Field was  diverted to the Banff FPSO  during  2005.
Under the terms of an early termination agreement,  the existing Kyle FPSO was
released in September 2005. The  consolidation of these production  facilities
is expected to result in lower combined  operating costs from these fields and
may ultimately extend field lives for both fields.


                                      Management's Discussion & Analysis    61
<PAGE>

OFFSHORE WEST AFRICA

Offshore  West Africa  capital  expenditures  include the  development  of the
57.61% owned and operated Baobab Field,  which commenced  production on August
9, 2005 at approximately  30,000 bbl/d net to the Company.  Upon completion of
drilling  additional wells in 2006,  production levels are expected to achieve
approximately 35,000 bbl/d net to the Company.

In East Espoir,  two of the four infill  wells  scheduled  for  drilling  were
completed  during 2005,  with the remainder  expected to be completed in 2006.
The drilling of these wells was a result of additional  testing and evaluation
that revealed a larger  quantity of crude oil in place,  based upon  reservoir
studies  and  production  history  to date.  These  new  producer  wells  will
effectively   exploit  this  additional   potential  and  could  increase  the
recoverable  resources and production.  The West Espoir drilling tower,  which
will  facilitate  development  drilling of the  reservoir,  is on site and was
installed in late 2005. This project is progressing on time and on budget with
first crude oil expected in 2006,  increasing  to  approximately  13,000 boe/d
once fully developed.

The Company purchased a 100% operator interest in the Olowi PSC offshore Gabon
in  October  2005  and  received  approval  of its  development  plan for this
acquisition  subsequent to year end. Development plans include a FPSO handling
input from two or three  shallow-water  producing  platforms.  Development  is
expected to begin late in 2006, with first oil expected late in 2008 at a rate
of approximately 20,000 bbl/d.

LIQUIDITY AND CAPITAL RESOURCES

($ millions, except ratios)                        2005       2004       2003
------------------------------------------------------------------------------
Working capital deficit (1)                    $  1,774   $    652   $    505
Long-term debt                                 $  3,321   $  3,538   $  2,748
------------------------------------------------------------------------------
Shareholders' equity
Share capital                                  $  2,442   $  2,408   $  2,353
Retained earnings                                 5,804      4,922      3,650
Foreign currency translation adjustment              (9)        (6)         3
------------------------------------------------------------------------------
Total                                          $  8,237   $  7,324   $  6,006
==============================================================================
Debt to cash flow (2)                              0.7x       l.0x       0.9x
Debt to EBITDA (3)                                 0.6x       0.9x       0.8x
Debt to book capitalization (4)                   28.7%      33.8%      32.8%
Debt to market capitalization                      9.7%      21.4%      25.1%
After tax return on average common
   shareholders' equity (5)                       14.3%      21.4%      25.6%
After tax return on average capital
   employed (6)                                   10.4%      15.3%      17.1%
==============================================================================
(1) Calculated as current assets less current liabilities.
(2) Calculated  as  current  and  long-term  debt;  divided  by cash flow from
    operations for the year.
(3) Calculated  as current and  long-term  debt;  divided by  earnings  before
    interest,   taxes,   depreciation,   depletion  and  amortization,   asset
    retirement obligation accretion,  unrealized foreign exchange, stock-based
    compensation  expense and unrealized  risk  management  activities for the
    year.
(4) Calculated  as current and  long-term  debt;  divided by the book value of
    common shareholders' equity plus current and long-term debt.
(5) Calculated as net earnings for the year as a percentage of average  common
    shareholders' equity for the period.
(6) Calculated as net earnings plus after-tax  interest  expense for the year;
    as a percentage of average capital  employed.  Average capital employed is
    the average  shareholders'  equity and current and long-term  debt for the
    year.


The Company's capital resources at December 31, 2005 consist primarily of cash
flow  from  operations  and  available  credit  facilities.   Cash  flow  from
operations  is dependent on factors  discussed in the Risks and  Uncertainties
section  of  this  MD&A.  The  Company's  ability  to  renew  existing  credit
facilities and raise new debt is dependent upon these factors,  maintaining an
investment  grade debt rating and the condition of capital and credit markets.
Management  believes   internally   generated  cash  flows  supported  by  the
implementation  of the Company's hedge policy,  the flexibility of its capital
expenditure  programs supported by  its five and ten year financial plans, the
Company's  existing credit  facilities and the Company's  ability to raise new
debt,  will be  sufficient  to sustain its  operations  and support its growth
strategy.

At December  31,  2005 the Company had undrawn  bank lines of credit of $3,285
million.  These credit lines are supported by credit facilities,  which if not
extended, mature in 2008, 2009 and 2010.

At December 31, 2005, the Company's working capital deficit was $1,774 million
and  included the current  portion of other  long-term  liabilities  of $1,471
million,  comprised  of  stock-based  compensation  of  $629  million  and the
mark-to-market   valuation  of   non-designated   risk  management   financial
derivative  instruments  of $842 million.  The  settlement of the  stock-based
compensation  liability is dependant  upon both the  surrender of vested stock
options for cash  settlement by employees and the value of the Company's share
price  at the  time of  surrender.  The  cash  settlement  amount  of the risk
management financial derivative instruments may vary materially depending upon
the  underlying  crude  oil and  natural  gas  prices  at the  time  of  final
settlement  of the  financial  derivative  instruments,  as  compared to their
mark-to-market value at December 31, 2005.

The Company is committed to maintaining a strong financial position.  In 2005,
strong operational  results and high commodity prices resulted in debt to book
capitalization  levels of 28.7%.  The Company  believes  it has the  necessary
financial  capacity to complete the


62    Management's Discussion & Analysis
<PAGE>

Horizon  Project  while  at  the  same  time  not  compromising   delivery  of
conventional crude oil and natural gas growth opportunities.  The financing of
Phase  1 of the  Horizon  Project  development  is  guided  by  the  competing
principles of retaining as much direct  ownership  interest as possible  while
maintaining a strong  balance sheet.  Existing  proved  development  projects,
which have largely  been funded  prior to December  31, 2005,  such as Baobab,
Primrose North and West Espoir should provide  identified growth in production
volumes in 2006 through 2008,  and are expected to generate  incremental  free
cash flows during this period.

In January  2005,  the Board of  Directors  authorized  the  expansion  of the
Company's  commodity  hedging  program  to reduce  the risk of  volatility  in
commodity  price  markets  and to  underpin  the  Company's  cash flow for its
capital  expenditures program through the Horizon Project construction period.
This  expanded  program  allows  for the  hedging  of up to 75% of the near 12
months  budgeted  production,  up to  50%  of the  following  13 to 24  months
estimated  production and up to 25% of production  expected in months 25 to 48
through the use of derivative financial  instruments.  For the purpose of this
program,  the  purchase  of crude oil put  options is in addition to the above
parameters. As a result,  approximately 75% of budgeted 2006 crude oil volumes
have been hedged  through the use of  collars.  Approximately  60% of budgeted
2006  natural  gas  volumes  have  similarly  been  hedged  through the use of
collars.  In addition,  for 2007,  put options  have been  acquired on 200,000
bbl/d at an average floor price of US$47.50 and a further  100,000 bbl/d at an
average  floor price of  US$28.00.  The Company has not hedged any  production
volumes  beyond 2007.  The Company  continues to evaluate the need for further
hedging in 2007 and beyond,  given continuing capital requirements for Horizon
and other capital projects.

LONG-TERM DEBT

Long-term  debt at December 31, 2005 amounted to $3,321  million.  The debt to
EBITDA ratio decreased to 0.6x and the debt to book  capitalization  decreased
to  28.7%  compared  to a debt to  EBITDA  ratio  of  0.9x  and a debt to book
capitalization  of  33.8%  in 2004.  These  ratios  are  currently  below  the
Company's guidelines for balance sheet management of debt to EBITDA of 1.5x to
2.0x and debt to book capitalization of 35% to 45%.

OPERATING FACILITIES

As at December  31, 2005 the Company had in place  unsecured  syndicated  bank
credit facilities of $3,425 million, comprised of:

     o   a $100 million operating demand facility;

     o   a  two-tranche  revolving  credit  and term loan  facility  of $1,825
         million; and

     o   a 5-year revolving and term loan facility of $1,500 million.


The first  $1,000  million  tranche of the $1,825  million  facility  is fully
revolving for a period of three years to June 2008. The second tranche of $825
million  is fully  revolving  for a period of five  years to June  2010.  Both
tranches are extendible  annually for one-year periods at the mutual agreement
of the  Company  and the  lenders.  If not  extended,  the full  amount of the
outstanding  principal would be repayable at the end of year two following the
initiation of the term period.  The $1,500 million  revolving  credit and term
loan facility has a five-year term, with three, one-year extension provisions.
If the facility is not extended,  the amount outstanding would be repayable in
December 2009. These facilities provide that the borrowings may be made by way
of operating advances,  prime loans, bankers' acceptances,  US base rate loans
or US dollar LIBOR advances,  which bear interest at the bank's prime rates or
at money market rates plus applicable margins.

The weighted average interest rate of the bank credit  facilities  outstanding
at December 31, 2005, was 5.44% (2004 - 3.47%).

The Company also has an unsecured  (pound)15  million demand  overdraft credit
facility for the Company's  North Sea  operations.  At December 31, 2005 there
were no amounts drawn on this facility.

In addition to the outstanding debt, as at December 31, 2005 letters of credit
aggregating $24 million have been issued.

MEDIUM-TERM NOTES

In May 2005, the Company issued $400 million of debt securities  maturing June
2015, bearing interest at 4.95%. Proceeds from the securities issued were used
to repay bankers' acceptances under the Company's bank credit facilities.

In May 2004,  the Company repaid the $125 million 6.85%  unsecured  debentures
due May 2004, which were issued under a previous medium-term note program.

In January 2006, the Company issued $400 million of debt  securities  maturing
January 2013,  bearing interest at 4.50%.  Proceeds from the securities issued
were used to repay  bankers'  acceptances  under  the  Company's  bank  credit
facilities.  After  issuing  these  securities,  the Company has $1.6  billion
remaining on its $2 billion shelf  prospectus filed in August 2005 that allows
for the issue of medium-term  notes in Canada until September 2007. If issued,
these securities will bear interest as determined at the date of issuance.


                                         Management's Discussion & Analysis 63
<PAGE>

SENIOR UNSECURED NOTES

In December 2005, the Company repaid the US$125 million 7.69% senior unsecured
notes. The 6.42% senior unsecured notes were repaid in May 2004.

The  adjustable  rate senior  unsecured  notes bear interest at 6.54% and have
annual principal  repayments of US$31 million  commencing in May 2007, through
May 2009.

PREFERRED SECURITIES

In September  2005,  the Company  redeemed the US$80 million  8.30%  preferred
securities due May 25, 2011 for cash consideration of US$91 million, including
an early  repayment  premium  of US$11  million  as  required  under  the Note
Purchase Agreement.

US DOLLAR DEBT SECURITIES

In June 2005, the Company filed a short form shelf  prospectus that allows for
the issue of up to US$2 billion of debt  securities in the United States until
July 2007. If issued, these securities will bear interest as determined at the
date of issuance.

In  December  2004,  the  Company  issued  US$350  million of debt  securities
maturing  December 2014,  bearing interest at 4.90% and US$350 million of debt
securities  maturing February 2035,  bearing interest at 5.85%.  Proceeds from
the  securities  issued  were  used to repay  bankers'  acceptances  under the
Company's bank credit  facilities.  The Company has entered into interest rate
swap  contracts  to convert  the fixed rate  interest  coupon  into a floating
interest rate on the securities due December 2014.

The  ratings of the  Company's  debt  securities  and its  relationships  with
principal  banks are  important  to the Company as it  continues to expand and
grow.  Hence,  it is the Company's  management  intention to maintain a strong
balance sheet and financial position.  The Company's debt securities are rated
"Baa1" with a stable  outlook by Moody's  Investor  Services  Inc.,  "BBB+" by
Standard & Poors  Corporation  ("S&P") and "BBB(high)"  with a stable trend by
Dominion Bond Rating  Services  Limited.  S&P assigns a rating  outlook to the
Company  and  not to the  individual  debt  instruments.  S&P has  assigned  a
negative outlook to the Company.

SHARE CAPITAL

Shareholders  of the  Company  approved a  subdivision  or share  split of its
issued and outstanding  common shares on a two-for-one  basis at the Company's
Annual and Special Meeting held on May 5, 2005. As at December 31, 2005, there
were  536,348,000  common  shares  outstanding.  As at February 21, 2006,  the
Company had 537,156,000 common shares outstanding.

In January 2005, the Company  renewed its Normal Course Issuer Bid allowing it
to purchase up to 26,818,012 common shares or 5% of the Company's  outstanding
common  shares  on the  date  of  announcement,  during  the  12-month  period
beginning  January 24, 2005 and ending  January 23,  2006.  As at December 31,
2005,  the Company had purchased  850,000 common shares at an average price of
$53.29 per common share for a total cost of $45 million.

In January 2006, the Company announced the renewal of its Normal Course Issuer
Bid through the  facilities  of the Toronto  Stock  Exchange  and the New York
Stock  Exchange  to  purchase  up to  26,852,545  common  shares  or 5% of the
outstanding  common  shares of the  Company  on the date of the  announcement,
during the 12-month period  beginning  January 24, 2006 and ending January 23,
2007. As at February 21, 2006,  the Company had not  purchased any  additional
shares under the Normal Course Issuer Bid.

In February  2005,  the Board of Directors  approved an increase in the annual
dividend  paid by the  Company to $0.225 per common  share.  In May 2005,  the
Board of  Directors  approved an increase in the annual  dividend  paid by the
Company to $0.24 per common share.  In February  2004,  the Board of Directors
increased  the annual  dividend paid by the Company to $0.20 per common share,
up from the previous level of $0.15 per common share.

In February 2006, the Company's Board of Directors approved an increase in the
annual  dividend  paid by the Company to $0.30 per common share for 2006.  The
increase  represents  a 27%  increase  from the  prior  year,  recognizes  the
stability of the Company's cash flow,  and provides a return to  Shareholders.
This is the sixth consecutive year in which the Company has paid dividends and
the fifth  consecutive  year of an  increase in the  distribution  paid to its
Shareholders.


64    Management's Discussion & Analysis
<PAGE>

COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS

In the normal  course of  business,  the  Company  has  entered  into  various
contractual  arrangements  and  commitments  that  will  have an impact on the
Company's future  operations.  These  contractual  obligations and commitments
primarily relate to debt repayments, operating leases relating to office space
and  offshore  production  and  storage  vessels,  and  firm  commitments  for
gathering,  processing  and  transmission  services,  as well as  expenditures
relating to asset retirement obligations. The Company has not entered into any
contracts that would require  consolidation  under CICA  Accounting  Handbook,
AcG-15,  Consolidation  of Variable  Interest  Entities.  The following  table
summarizes the Company's commitments as at December 31, 2005:

<TABLE>
<CAPTION>
($ millions)                            2006       2007       2008       2009       2010     Thereafter
--------------------------------------------------------------------------------------------------------
<S>                                   <C>        <C>        <C>        <C>        <C>        <C>
Product transportation and
  pipeline (1)                        $  195     $  133     $  148     $   94     $   85     $    1,111
Offshore equipment operating
  lease                               $   51     $   51     $   52     $   51     $   51     $      180
Offshore drilling                     $  132     $  100     $   35     $   --     $   --     $       --
Asset retirement obligations (2)      $   82     $    4     $    4     $    4     $    7     $    3,224
Long-term debt (3)                    $   --     $  161     $   36     $   36     $   --     $    2,966
Other (4)                             $   61     $   62     $   21     $   29     $   23     $        8
========================================================================================================
</TABLE>
(1) During  the  year,   the  Company   entered   into  a  25  year   pipeline
    transportation  agreement  commencing in 2008, related to future crude oil
    production.  The agreement is renewable for successive  10-year periods at
    the Company's option. During the initial term, annual toll payments before
    operating costs will be approximately $35 million.
(2) Represents  management's  estimate of the future  payments to settle asset
    retirement   obligations  related  to  resource  properties,   facilities,
    production  platforms and gathering systems,  based on current legislation
    and industry operating practices.
(3) No debt repayments are reflected for the bank credit facilities due to the
    extendable nature of the facilities.
(4) Consists  of  future  expenditures  related  primarily  to  office  lease,
    electricity and crude oil processing.


The Board of Directors has approved the construction  costs for Phase 1 of the
Horizon  Project,  which  are  budgeted  to  be  $6.8  billion,   including  a
contingency  fund of $700 million,  with $1.3 billion  incurred in 2005,  $2.6
billion to be  incurred  in 2006 and $2.9  billion to be  incurred in 2007 and
2008.

The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business.  The Company  believes that any  liabilities
that might arise  pertaining to such matters would not have a material  effect
on its consolidated financial position.

RESERVES

For  the  year  ended  December  31,  2005,  the  Company  retained  qualified
independent  reserve  evaluators,  Sproule Associates Limited  ("Sproule") and
Ryder  Scott  Company  ("Ryder  Scott")  to  evaluate  100%  of the  Company's
conventional  proved and probable crude oil,  natural gas liquids  ("NGL") and
natural gas reserves  (1) and prepare  Evaluation  Reports on these  reserves.
Sproule  evaluated the Company's North America  conventional  assets and Ryder
Scott evaluated its international  conventional  assets.  The Company 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.  There  are  two  principal
differences between the two standards. The first is the additional requirement
under NI 51-101 to disclose both proved, and proved and probable reserves,  as
well as the related net present  value of future net revenues  using  forecast
prices and costs. The second is in the definition of proved reserves; however,
as discussed in the Canadian Oil and Gas Evaluation  Handbook  ("COGEH"),  the
standards that NI 51-101 employs,  the difference in estimated proved reserves
based on constant pricing and costs between the two standards is not material.

The Company has disclosed  proved  conventional  reserves and the Standardized
Measure of discounted future net cash flows using year-end constant prices and
costs as  mandated  by the SEC in the  supplementary  oil and gas  information
section of this  Annual  Report.  The  Company  has elected to provide the net
present value (2) of these same  conventional  proved  reserves as well as the
conventional  proved and probable  reserves and the net present value of these
reserves under the same parameters as additional  voluntary  information.  The
Company  has also  elected to provide  both  proved,  and proved and  probable
conventional  reserves  and the net  present  value  of these  reserves  using
forecast  prices  and  costs as  voluntary  additional  information,  which is
disclosed in the Company's most recent Annual Information Form.

Reserves  and net  present  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.

For the year ended  December  31,  2005,  the  Company  retained  a  qualified
independent reserves evaluator, GLJ Petroleum Consultants ("GLJ"), to evaluate
100% of Phases 1 through 3 of the  Company's  Horizon  Project  and prepare an
Evaluation  Report on the  Company's  proved  and  probable  oil sands  mining
reserves incorporating both the mining and upgrading projects.  These reserves
were  evaluated  adhering to the  requirements  of SEC Industry  Guide 7 using
year-end  constant  pricing  and  have  been  disclosed  separately  from  the
Company's  conventional  proved and  probable  crude oil,  NGL and natural gas
reserves.


                                      Management's Discussion & Analysis    65
<PAGE>

The Reserve  Committee of the  Company's  Board of Directors  has met with and
carried out independent due diligence  procedures with each of Sproule,  Ryder
Scott and GLJ to review  the  qualifications  of and  procedures  used by each
evaluator in  determining  the estimate of the  Company's  quantities  and net
present  value of  remaining  conventional  crude  oil,  NGL and  natural  gas
reserves as well as the Company's quantity of oil sands mining reserves.

Additional  reserve  disclosure is contained in the  supplementary oil and gas
information  of this  Annual  Report  and the  Company's  most  recent  Annual
Information Form.

(1) Conventional  crude oil, NGL and natural gas includes all of the Company's
    light and medium,  heavy,  and thermal  crude oil,  natural gas,  coal bed
    methane  and  natural  gas  liquid  activities.  It does not  include  the
    Company's oil sands mining assets.

(2) Net present values of conventional reserves are based upon discounted cash
    flows  prior to the  consideration  of  income  taxes and  existing  asset
    abandonment  liabilities.  Only future  development  costs and  associated
    material well abandonment liabilities have been applied with the exception
    of  Offshore  West  Africa  where all  abandonment  liabilities  have been
    included.


RISKS AND  UNCERTAINTIES

The Company is exposed to various  operational  risks  inherent in  exploring,
developing,  producing and marketing  crude oil and natural gas and the mining
and upgrading of bitumen.  These inherent  risks include,  but are not limited
to, the following items:

     o   Economic risk of finding and producing reserves at a reasonable cost,
         including the risk of reserve revisions due to economic and technical
         factors.  Reserve revisions can have a positive or negative impact on
         asset valuations and depletion rates.

     o   Pricing  risk of  marketing  reserves  at an  acceptable  price given
         current market conditions.

     o   Regulatory  risk related to approval for  exploration and development
         activities, which can add to costs or cause delays in projects.

     o   Labour risk  associated  with  securing  the  manpower  necessary  to
         complete capital projects in a timely and cost effective manner.

     o   Credit  risk   related  to   non-payment   for  sales   contracts  or
         non-performance by counterparties to contracts.

     o   Interest rate risk  associated  with the Company's  ability to secure
         financing at commercially acceptable terms.

     o   Foreign  exchange  risk due to  fluctuating  exchange  rates,  as the
         majority of sales are based in US dollars.

     o   Environmental impact risk associated with exploration and development
         activities.

     o   Risk of catastrophic loss due to fire, explosion or acts of nature.

     o   Other risks associated with changing  governmental  policies,  social
         instability and other political,  economic or diplomatic developments
         in the Company's international operations.

The Company uses a variety of means to help minimize these risks.  The Company
maintains a  comprehensive  insurance  program to reduce risk to an acceptable
level and to protect it against  significant  losses.  Operational  control is
enhanced by focusing efforts on large core regions with high working interests
and  by  assuming   operatorship  of  all  key  facilities.   Product  mix  is
diversified,  ranging from the  production of natural gas to the production of
crude oil of various grades. The Company believes this diversification reduces
price risk when compared with  over-leverage to one commodity.  Sales of crude
oil and natural gas are aimed at various markets to ensure that undue exposure
to any one market does not exist.  Financial  instruments are utilized to help
ensure targets are met and to manage commodity prices,  foreign currency rates
and interest rate  exposure.  The Company  minimizes  credit risks by entering
into sales contracts and financial derivatives with only highly rated entities
and financial  institutions.  The  arrangements  and policies  concerning  the
Company's  financial  instruments  are under  constant  review  and may change
depending upon the prevailing market conditions. Refer to the "Risk management
activities"  section  of this MD&A.  In  addition,  the  Company  reviews  its
exposure to individual  companies on a regular  basis,  and where  appropriate
ensures that parental guarantees or letters of credit are in place to minimize
the impact in the event of default.

The Company's  capital structure mix is also monitored on a continual basis to
ensure that it optimizes  flexibility,  minimizes cost and offers the greatest
opportunity for growth.  This includes the determination of a reasonable level
of debt and any interest rate exposure risk that may exist.

For additional detail regarding the Company's risks and  uncertainties,  refer
to the Company's most recent Annual Information Form.


66    Management's Discussion & Analysis
<PAGE>

ENVIRONMENT

The Company continues to employ an Environmental  Management Plan (the "Plan")
to ensure the welfare of its employees,  the communities in which it operates,
and the  environment  as a whole.  Environmental  protection is of fundamental
importance and is undertaken in accordance with guiding principles approved by
the  Company's  Board of Directors.  A detailed copy of the Company's  Plan is
presented  to, and reviewed by, the Board of Directors  annually.  The Plan is
updated quarterly at the Directors' meetings.

The Company's environmental  management plan and operating guidelines focus on
minimizing   the  impact  of  field   operations   while  meeting   regulatory
requirements and corporate  standards.  The Company, as part of this plan, has
implemented a proactive program that includes:

     o   An annual  internal  environmental  compliance  audit and  inspection
         program of the Company's operating facilities;

     o   A suspended well inspection  program to support future development or
         eventual abandonment;

     o   Appropriate  reclamation and decommissioning  standards for wells and
         facilities ready for abandonment;

     o   An effective surface reclamation program;

     o   A due diligence program related to groundwater monitoring;

     o   An active program related to preventing and reclaiming spill sites;

     o   A solution gas reduction and conservation program; and

     o   A program to replace the  majority of fresh water for  steaming  with
         brackish water.

The Company has also established stringent operating standards in four areas:

     o   Using  water-based,  environmentally  friendly drilling muds whenever
         possible;

     o   Implementing cost effective ways of reducing  greenhouse  natural gas
         emissions per unit of production;

     o   Exercising care with respect to all waste produced through  effective
         waste management plans; and

     o   Minimizing  produced  water  volumes  onshore  and  offshore  through
         cost-effective measures.

In  2005,  the  Company's  capital  expenditures   included  $46  million  for
abandonment  expenditures,  an  increase  from $32 million in 2004 (2003 - $40
million).


Estimated asset retirement obligation,
undiscontinued ($ millions)                                   2005       2004
------------------------------------------------------------------------------
North America                                             $  2,050   $  1,770
North Sea                                                    1,185      1,265
Offshore West Africa                                            90         25
------------------------------------------------------------------------------
                                                             3,325      3,060
North Sea PRT recovery                                        (370)      (600)
------------------------------------------------------------------------------
                                                          $  2,955   $  2,460
==============================================================================


The estimate of the future site restoration liability is based on estimates of
future  costs to abandon  and  restore the wells,  production  facilities  and
offshore  production  platforms.  There are numerous factors that affect these
costs including such things as the number of wells drilled, well depth and the
specific  environmental   legislation.   The  estimated  costs  are  based  on
engineering  estimates  using current costs and technology in accordance  with
present  legislation and industry operating  practice.  The future abandonment
costs to be  incurred  by the  Company  in the  North  Sea will  result  in an
estimated  recovery of PRT of $370 million (2004 - $600  million,  2003 - $330
million),  as abandonment costs are an allowable  deduction in determining PRT
and may be carried  back to reclaim  PRT  previously  paid.  The PRT  recovery
reduces the net abandonment liability of the Company to $2,955 million (2004 -
$2,460  million,  2003 - $1,950  million).  The  North  Sea PRT  recovery  has
decreased  substantially from 2004 primarily due to improved economics related
to the various  fields,  including a higher pricing  environment  and stronger
Canadian dollar at December 31, 2005. Under these economic conditions,  end of
field losses at Tiffany  previously assumed to be available for relief against
PRT due from other fields is significantly  reduced. The Company's strategy in
the North Sea consists of developing  commercial hubs around its core operated
properties  with  the  goal  of  increasing  production,  lowering  costs  and
extending the economic lives of its production  facilities,  thereby  delaying
the eventual abandonment dates.

KYOTO PROTOCOL

In December 2002, the Canadian Federal Government  ratified the Kyoto Protocol
("Kyoto").  The Company  continues  to work with the  Federal  and  Provincial
governments  on the  regulatory  framework  for  greenhouse  gases for  larger
emitters.  The framework  under  development  would see harmonized  regulation
between the two levels of government. Both levels of government have indicated
that  existing   legislation  will  be  amended  in  2006  to  create  further
requirements  for  reporting  emissions,   facility-based  emission  intensity
targets and regulatory compliance.  Compliance with emission intensity targets
is expected for 2008, which is the first year of the compliance period for the
Kyoto Protocol.


                                         Management's Discussion & Analysis 67
<PAGE>

The Company will  continue to develop  strategies  that will enable it to deal
with the risks and opportunities  associated with new climate change policies.
In addition,  the Company will work with  relevant  parties to ensure that new
policies  encourage  innovation,  energy  efficiency,  targeted  research  and
development while not impacting Canada's competitive position.

Due to the  high  degree  of cost  uncertainty  when  the  Federal  Government
ratified  Kyoto,  maximum  per tonne cost  assurances  were  agreed with large
emitters for 2008 - 2012.  Beyond 2012  investment  concerns were addressed by
the Federal  Government as outlined in eight  principles  that would guide its
negotiations and policies for this later stage.

CRITICAL ACCOUNTING ESTIMATES

The  preparation  of  financial   statements  requires  the  Company  to  make
judgements, assumptions and estimates in the application of generally accepted
accounting  principles  that  have  a  significant  impact  on  the  Company's
financial  position and  operations.  Actual  results  could differ from those
estimates,  and  those  differences  could be  material.  Critical  accounting
estimates are reviewed by the Company's Audit Committee annually.  The Company
believes the following are the most critical accounting estimates in preparing
its consolidated financial statements.

PROPERTY, PLANT AND EQUIPMENT/DEPLETION, DEPRECIATION AND AMORTIZATION

The Company  follows the full cost method of accounting  for its  conventional
crude oil and natural gas  properties and  equipment.  Accordingly,  all costs
relating to the exploration for and development of conventional  crude oil and
natural  gas  reserves,   whether  successful  or  not,  are  capitalized  and
accumulated  in  country-by-country  cost  centres.  Proceeds  on  disposal of
properties  are  ordinarily  deducted from such costs without  recognition  of
profit or loss except where such disposal constitutes a significant portion of
the Company's  reserves in that country.  Under Canadian GAAP, the capitalized
costs and future capital costs related to each cost centre from which there is
production  are  depleted  on  the  unit-of-production  method  based  on  the
estimated  proved reserves of that country using  estimated  future prices and
costs,  rather  than  constant  dollar  pricing as  required  by the SEC.  The
carrying  amount of crude oil and natural gas  properties  in each cost centre
may not exceed their recoverable  amount ("the ceiling test"). The recoverable
amount is calculated as the  undiscounted  cash flow using proved reserves and
estimated  future  prices and costs.  If the carrying  amount of a cost centre
exceeds its  recoverable  amount,  an  impairment  loss equal to the amount by
which the carrying amount of the properties exceeds their estimated fair value
is charged  against net  earnings.  Fair value is  calculated as the cash flow
from those properties using proved and probable  reserves and estimated future
prices and costs, discounted at a risk-free interest rate.

The alternate  acceptable  method of accounting  for crude oil and natural gas
properties and equipment is the successful  efforts method. A major difference
in applying the successful  efforts method is that  exploratory  dry holes and
geological  and  geophysical  exploration  costs would be charged  against net
earnings in the year incurred rather than being capitalized to property, plant
and equipment.  In addition,  under this method cost centres are defined based
on reserve pools rather than by country.

The use of the full cost method usually  results in higher  capitalized  costs
and higher DD&A rates compared to the successful efforts method.

CRUDE OIL AND NATURAL GAS RESERVES

The Company retains qualified  independent reserves evaluators to evaluate the
Company's  proved and probable  crude oil and natural gas  reserves.  In 2005,
100%  of the  Company's  reserves  were  evaluated  by  qualified  independent
reserves evaluators.

The estimation of reserves  involves the exercise of judgement.  Forecasts are
based on engineering data, future prices,  expected future rates of production
and the timing of future  capital  expenditures,  all of which are  subject to
many uncertainties and interpretations. The Company expects that over time its
reserve  estimates  will be  revised  upward  or  downward  based  on  updated
information  such as the results of future  drilling,  testing and  production
levels.  Reserve estimates can have a significant  impact on net earnings,  as
they are a key component in the  calculation  of depletion,  depreciation  and
amortization and for determining  potential asset impairment.  For example,  a
revision to the reserve estimate would result in a higher or lower DD&A charge
to net earnings.  Downward revisions to reserve estimates could also result in
a  write-down  of crude oil and  natural  gas  property,  plant and  equipment
carrying amounts under the ceiling test.

ASSET RETIREMENT OBLIGATION

Under CICA Handbook Section 3110, Asset Retirement  Obligations  ("ARO"),  the
Company is  required  to  recognize  a  liability  for the  future  retirement
obligations  associated with the Company's property,  plant and equipment.  An
ARO is  recognized  to the extent of a legal  obligation  associated  with the
retirement of a tangible long-lived asset the Company is required to settle as
a result of an existing or enacted law, statute,  ordinance or written or oral
contract,  or by legal  construction  of a  contract  under  the  doctrine  of
promissory estoppel.  The ARO is based on estimated costs, taking into account
the  anticipated  method  and  extent of  restoration  consistent  with  legal
requirements,  technological  advances and the possible use of the site. Since
these estimates are specific to the sites involved,  there are many individual
assumptions  underlying  the  Company's  total ARO  amount.  These  individual
assumptions can be subject to change based on experience.

68  Management's Discussion & Analysis
<PAGE>

The estimated fair values of asset retirement obligations related to long-term
assets are recognized as a liability in the period in which they are incurred.
Retirement  costs equal to the  estimated  fair value of the asset  retirement
obligations are  capitalized as part of the cost of associated  capital assets
and are amortized to expense through depletion over the life of the asset. The
fair value of the asset retirement  obligation is estimated by discounting the
expected  future cash flows to settle the asset  retirement  obligation at the
Company's  average  credit-adjusted   risk-free  interest  rate  of  6.8%.  In
subsequent  periods,  the asset  retirement  obligation  is  adjusted  for the
passage of time and for any changes in the amount or timing of the  underlying
future cash flows. The estimates described impact earnings by way of depletion
on the  capital  cost and  accretion  on the asset  retirement  liability.  In
addition,  differences  between actual and estimated costs to settle the asset
retirement  obligation,  timing of cash  flows to settle  the  obligation  and
future inflation rates could result in gains or losses on the final settlement
of the asset retirement obligations.

An ARO is not  recognized for assets with an  indeterminate  useful life (e.g.
pipeline assets) because an amount cannot be reasonably estimated.  An ARO for
these  assets will be recorded in the first period in which the lives of these
assets are determinable.

RISK MANAGEMENT ACTIVITIES

The Company  utilizes  various  instruments to manage its commodity  price and
foreign  currency  exposures  on revenue,  and interest  rate  exposures on US
dollar  denominated  debt. These derivative and financial  instruments are not
used for trading or speculative purposes.

On January 1, 2004, the Company  prospectively  adopted the Canadian Institute
of Chartered  Accountants'  ("CICA") Accounting Guideline ("AcG") 13, "Hedging
Relationships"  and Emerging  Issues  Committee  ("EIC") 128,  "Accounting for
Trading,   Speculative  or  Non-Hedging  Derivative  Financial   instruments".
Derivative instruments that do not qualify as hedges, or are not designated as
hedges,  are recorded using the  mark-to-market  method of accounting  whereby
instruments are recorded on the consolidated  balance sheet as either an asset
or  liability  with  changes in fair value  recognized  in net  earnings.  The
estimate of fair value of all derivative instruments is based on quoted market
prices  or,  in  their  absence,  third  party  market  indications.  The cash
settlement amount of the risk management financial derivative  instruments may
vary materially depending upon the underlying crude oil and natural gas prices
at the time of final settlement of the financial  derivative  instruments,  as
compared to their mark-to-market value at December 31, 2005.

PURCHASE PRICE ALLOCATIONS

The costs of corporate  and asset  acquisitions  are allocated to the acquired
assets  and  liabilities  based on their  estimated  fair value at the time of
acquisition.  The  determination  of fair value  requires  the Company to make
assumptions and estimates  regarding future events.  The allocation process is
inherently   subjective  and  impacts  the  amount  assigned  to  individually
identifiable  assets  and  liabilities.   As  a  result,  the  purchase  price
allocation  impacts the Company's  reported  assets and liabilities and future
net earnings due to the impact on future DD&A expense and impairment tests.

The Company has made various assumptions in determining the fair values of the
acquired  assets  and  liabilities.   The  most  significant  assumptions  and
judgments made relate to the estimation of the fair value of the crude oil and
natural gas properties.  To determine the fair value of these properties,  the
Company  estimates  (a) crude oil and  natural  gas  reserves,  and (b) future
prices of crude oil and natural gas.  Reserve  estimates are based on the work
performed by the Company's  engineers and outside  consultants.  The judgments
associated with these estimated reserves are described above in "Crude oil and
natural gas reserves".  Estimates of future prices are based on prices derived
from  future  price   forecasts   amongst   industry   analysts  and  internal
assessments.  The Company  applies  estimated  future  prices to the estimated
reserves quantities  acquired,  and estimates future operating and development
costs, to arrive at estimated future net revenues for the properties acquired.

CONTROL ENVIRONMENT

Based on their evaluation as of December 31, 2005, the Company's President and
the Chief  Financial  Officer  concluded,  pursuant to  Canadian  Multilateral
Instrument  52-109  Part  2.1,  that the  Company's  disclosure  controls  and
procedures are effective to ensure that  information  required to be disclosed
by the Company in its annual  filings is recorded,  processed,  summarized and
reported  within the time periods that meet the  regulatory  requirements.  In
addition,  as of December  31,  2005,  there were no changes in the  Company's
internal controls over financial reporting that occurred during 2005 that have
materially  affected,  or are  reasonably  likely  to  materially  affect  its
internal  controls  over  financial  reporting.  The Company will  continue to
periodically  evaluate its  disclosure  controls and  procedures  and internal
controls over financial reporting and will make any modifications from time to
time as deemed necessary.



                                         Management's Discussion & Analysis 69
<PAGE>

NEW ACCOUNTING STANDARDS

In  January  2005,  the  CICA  issued  four  new  standards  relating  to  the
recognition, measurement and disclosure of financial instruments.

     o   Section 3855 - "Financial  Instruments - Recognition and Measurement"
         prescribes  when  a  financial   asset,   financial   liability,   or
         non-financial  derivative is to be recognized on the balance sheet as
         well as its  measurement  amount.  This  Section also  specifies  how
         financial   instruments   gains  and  losses  are  to  be  presented.
         Transitional  provisions  for this  Section vary based on the type of
         financial instruments under consideration.

     o   Section  3865 -  "Hedges"  expands  on  existing  AcG  13 -  "Hedging
         Relationships",  and Section 1650 "Foreign Currency Translation",  by
         specifying how hedge accounting is to be applied and what disclosures
         are necessary  when it is applied.  Retroactive  application  of this
         Section is not permitted.

     o   Section 1530 -  "Comprehensive  Income"  introduces new standards for
         reporting  and  disclosure  of  comprehensive  income.  Comprehensive
         income is the change in equity (net  assets) of the Company  during a
         reporting period from transactions and other events and circumstances
         from  non-owner  sources.  It includes all changes in equity during a
         period  except  those  resulting  from   investments  by  owners  and
         distributions  to owners.  Financial  statements of prior periods are
         required to be restated only for non-financial instrument items.

     o   Section  3251  -  "Equity"   replaces   Section  3250  "Surplus"  and
         establishes  standards for the  presentation of equity and changes in
         equity  during a  reporting  period.  Financial  statements  of prior
         periods are required to be restated only for non-financial instrument
         items.  For  all  other  items,   comparative   financial  statements
         presented are not restated,  but an adjustment to the opening balance
         of accumulated other comprehensive income may be required.

The Company plans to adopt these new standards  effective January 1, 2007. The
effect on the Company's consolidated financial statements cannot be reasonably
determined at this time as the financial  derivatives  outstanding at December
31, 2006 and their related fair values are not known.

OUTLOOK

The  Company  continues  to  implement  its  strategy of  maintaining  a large
portfolio of varied projects,  which the Company believes will enable it, over
an extended  period of time, to provide  consistent  growth in production  and
high shareholder returns. Annual budgets are developed, scrutinized throughout
the year and changed if necessary in the context of project  returns,  product
pricing  expectations,  and  balance in project  risk and time  horizons.  The
Company maintains a high ownership level and operatorship  level in all of its
properties and can therefore control the nature,  timing and extent of capital
expenditures in each of its project areas.

The Company expects production levels in 2006 to average 1,468 mmcf/d to 1,551
mmcf/d of natural  gas and  335,000  bbl/d to  373,000  bbl/d of crude oil and
NGLs.

The budgeted  capital  expenditures  in 2006 are  currently  expected to be as
follows:  Drilling will comprise both deep and conventional  targets, with new
production  growth coming from the Company's  Northeast  British  Columbia and
Northwest Alberta areas.

($ millions)                                                      2006 Budget
------------------------------------------------------------------------------
North America natural gas                                             $ 1,741
North America crude oil and NGLs                                        1,097
North Sea                                                                 733
Offshore West Africa                                                      187
Property acquisitions, dispositions and midstream                          63
------------------------------------------------------------------------------
                                                                        3,821
Horizon Project Phase 1 Construction                                    2,561
Capitalized interest and other items                                      222
Horizon Project Phases 2/3 engineering                                    128
Canadian Natural Upgrader engineering                                      30
------------------------------------------------------------------------------
Total                                                                 $ 6,762
==============================================================================


70  Management's Discussion & Analysis
<PAGE>

NORTH AMERICA NATURAL GAS

The 2006 North American natural gas program will be as follows:

(number of wells)                                                 2006 Budget
------------------------------------------------------------------------------
Northeast British Columbia                                                262
Northwest Alberta                                                         147
Northern Plains                                                           251
Southern Plains                                                           479
------------------------------------------------------------------------------
Total                                                                   1,139
==============================================================================


NORTH AMERICA CRUDE OIL AND NGLS

The 2006 North America crude oil drilling  program is highlighted by continued
development   of  Primrose   North  thermal   production  and  another  strong
conventional heavy program, as follows:

(number of wells)                                                 2006 Budget
------------------------------------------------------------------------------
Conventional heavy crude oil                                              344
Thermal heavy crude oil                                                    92
Light crude oil                                                           111
Pelican Lake crude oil                                                    150
------------------------------------------------------------------------------
Total                                                                     697
==============================================================================


The  Company  continues  the  disciplined  development  of its heavy crude oil
resources.  Conventional  heavy crude oil  drilling  is expected to  increase,
reflecting favourable crude oil prices and new opportunities identified in the
property  acquisitions  made during 2004. Due to the nature of heavy crude oil
production patterns,  where production volumes ramp up during the first months
of  production,  much of the  production  resulting  from the  expanded  drill
program will not be realized until late 2007.

In 2006,  the  Company  expects to continue  its  Primrose  thermal  crude oil
expansion  plans.  Activity  in 2006 will be  focused  on the  Primrose  South
expansion.  Production  from this  project is subject to the  cycling of steam
injection and crude oil production and is expected to remain at similar levels
to the 2005 production.  The waterflood conversion project is on schedule with
production  response exceeding  expectations.  The Polymer Flood pilot project
has yielded positive results to date and will continue in 2006.

THE HORIZON PROJECT

The Horizon  Project is  designed as a phased  development  and  includes  two
components:  the mining of bitumen and an onsite upgrader.  Phase 1 production
is  expected  to  commence  in the  second  half of 2008 at  110,000  bbl/d of
34(degree) API light,  sweet synthetic crude oil ("SCO").  The phased approach
provides the Company with improved cost and project controls  including labour
and materials management, and directionally mitigates the effects of growth on
local infrastructure.

Construction  costs for Phase 1 of the Horizon  Project are  estimated at $6.8
billion  including a contingency  reserve of $700  million,  with $1.3 billion
incurred in 2005,  $2.6  billion to be incurred in 2006 and $2.9 billion to be
incurred in 2007 and 2008.

Extensive  front end design and the high  degree of  project  definition  have
enabled  the Company to obtain  approximately  68% of Phase 1 costs on a fixed
price basis. The high degree of up front project  engineering and pre-planning
is expected to reduce the risks associated with scope changes.

NORTH SEA

The capital  budget in 2006 for the North Sea is $733 million and includes the
drilling of  approximately  12 net  platform  wells on Ninian,  Murchison  and
Tiffany.  The Company will also conduct a mobile drilling  program for which 6
subsea  producer  wells will be drilled at Columba E, Lyell,  Toni and Thelma.
Average  crude oil  production  is expected to increase  from 2005  production
levels;  however,  natural gas volumes are  expected to be flat as natural gas
production at the Banff Field is diverted to reinjection.

OFFSHORE WEST AFRICA

In 2006,  the capital  budget for Offshore West Africa is set at $187 million,
of which the Company  anticipates $79 million to be spent on completing infill
drilling at East Espoir and  developing  the West  Espoir  Field.  West Espoir
development is expected to yield first oil by mid-2006 at approximately 13,000
boe/d.  Two  additional  wells will be completed  at Baobab in 2006,  allowing
production  to ramp to  approximately  35,000  bbl/d net to the  Company.  $32
million will be expended on  development  of the Olowi Field offshore Gabon in
2006, with first oil expected late in 2008.


                                        Management's Discussion & Analysis  71
<PAGE>

SENSITIVITY ANALYSIS (1)

The following table is indicative of the annualized sensitivities of cash flow
from  operations and net earnings from changes in certain key  variables.  The
analysis is based on business  conditions  and sales volumes during the fourth
quarter of 2005.  Each separate  item in the  sensitivity  analysis  shows the
effect of an increase in that  variable  only;  all other  variables  are held
constant.

<TABLE>
<CAPTION>
                                            CASH FLOW FROM   CASH FLOW FROM
                                                OPERATIONS       OPERATIONS     NET EARNINGS    NET EARNINGS
                                               ($ millions) ($/share, basic)    ($ millions) ($/share, basic)
-------------------------------------------------------------------------------------------------------------
<S>                                            <C>             <C>              <C>                <C>
Price changes
Crude oil - WTI US$1.00/bbl (2)
Excluding financial derivatives                $       113     $       0.21     $         79       $    0.15
Including financial derivatives                $        60     $       0.11     $         40       $    0.07
Natural gas - AECO C$0.10/mcf (2)
Excluding financial derivatives                $        38     $       0.07     $         24       $    0.05
Including financial derivatives                $        14     $       0.03     $          8       $    0.01

Volume changes
Crude oil - 10,000 bbl/d                       $       104     $       0.19     $         53       $    0.10
Natural gas - 10 mmcf/d                        $        32     $       0.06     $         17       $    0.03

Foreign currency rate change
$0.01 change in C$ in relation to US$ (2)      $     82-84     $  0.15-0.16     $      32-33       $    0.06
Interest rate change - 1%                      $         7     $       0.01     $          7       $    0.01
=============================================================================================================
</TABLE>
(1)  The  sensitivities  are calculated  based on 2005 fourth quarter  results
     excluding mark-to-market gains (losses) on risk management activities.
(2)  For details of financial  instruments  in place,  refer to note 10 to the
     Company's audited annual consolidated financial statements as at December
     31, 2005.

<TABLE>
<CAPTION>
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES (1)

                                       Q1        Q2        Q3        Q4       2005      2004       2003
--------------------------------------------------------------------------------------------------------
<S>                               <C>       <C>       <C>       <C>        <C>       <C>        <C>
Crude oil and NGLs (bbl/d)
North America                     209,125   215,693   231,260   230,263    221,669   206,225    174,895
North Sea                          71,139    62,884    73,543    66,798     68,593    64,706     56,869
Offshore West Africa                7,539    10,487    29,921    43,207     22,906    11,558     10,628
--------------------------------------------------------------------------------------------------------
Total                             287,803   289,064   334,724   340,268    313,168   282,489    242,392
--------------------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
North America                       1,430     1,434     1,400     1,402      1,416     1,330      1,245
North Sea                              23        17        18        15         19        50         46
Offshore West Africa                    2         3         5         6          4         8          8
--------------------------------------------------------------------------------------------------------
Total                               1,455     1,454     1,423     1,423      1,439     1,388      1,299
--------------------------------------------------------------------------------------------------------
Barrels of oil equivalent (boe/d)
North America                     447,446   454,602   464,607   463,869    457,695   427,936    382,315
North Sea                          74,956    65,751    76,545    69,361     71,651    73,093     64,469
Offshore West Africa                7,914    11,027    30,759    44,275     23,614    12,806     12,030
--------------------------------------------------------------------------------------------------------
Total                             530,316   531,380   571,911   577,505    552,960   513,835    458,814
--------------------------------------------------------------------------------------------------------
</TABLE>
(1)  The Company  recognizes  revenue on its crude oil  production  when title
     transfers to the customer  and delivery has taken place.  For  production
     where  revenue  has  not yet  been  recognized,  the  related  crude  oil
     inventory volumes, by segment, were as follows at December 31, 2005:

<TABLE>
<CAPTION>
(bbls)                                                                                             2005
--------------------------------------------------------------------------------------------------------
<S>                                                                                           <C>
North America, related to Corsicana pipeline line fill                                          484,157
North Sea, related to timing of liftings                                                        747,141
Offshore West Africa, related to timing of liftings, net of government entitlement to
   profit oil                                                                                   412,841
--------------------------------------------------------------------------------------------------------
                                                                                              1,644,139
========================================================================================================
</TABLE>

At December 31, 2004,  variances between  production volumes and liftings were
not significant.


72    Management's Discussion & Analysis
<PAGE>

<TABLE>
<CAPTION>
PER UNIT RESULTS (1)
                                        Q1        Q2           Q3        Q4       2005      2004       2003
-------------------------------------------------------------------------------------------------------------
<S>                               <C>        <C>        <C>        <C>        <C>       <C>        <C>
Crude oil and NGLs ($/bbl)
Sales price (2)                   $  39.81   $  42.51   $  57.35   $  46.38   $  46.86  $  37.99   $  32.66
Royalties                             3.39       3.33       5.11       3.89       3.97      3.16       2.77
Production expense                   11.30      11.66      11.48      10.33      11.17     10.05      10.28
-------------------------------------------------------------------------------------------------------------
Netback                           $  25.12   $  27.52   $  40.76   $  32.16   $  31.72  $  24.78   $  19.61
-------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (2)                   $   6.68   $   7.33   $   8.61   $  11.67   $   8.57  $   6.50   $   6.21
Royalties                             1.30       1.48       1.93       2.30       1.75      1.35       1.32
Production expense                    0.69       0.71       0.76       0.76       0.73      0.67       0.60
-------------------------------------------------------------------------------------------------------------
Netback                           $   4.69   $   5.14   $   5.92   $   8.61   $   6.09  $   4.48   $   4.29
-------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent ($/boe)
Sales price (2)                   $  39.94   $  43.05   $  54.87   $  56.08   $  48.77  $  38.45   $  34.84
Royalties                             5.42       5.85       7.84       8.01       6.82      5.37       5.20
Production expense                    8.04       8.29       8.56       7.93       8.21      7.35       7.15
-------------------------------------------------------------------------------------------------------------
Netback                           $  26.48   $  28.91   $  38.47   $  40.14   $  33.74  $  25.73   $  22.49
=============================================================================================================
</TABLE>
(1) Amounts expressed on a per unit basis are based on sales volume.
(2) Including transportation costs and excluding risk management activities.

<TABLE>
<CAPTION>
NETBACK ANALYSIS
($/boe) (1)                                                                 2005          2004         2003
------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>            <C>          <C>
Sales price (2)                                                       $    48.77     $   38.45    $   34.84
Royalties                                                                   6.82          5.37         5.20
Production expense (3)                                                      8.21          7.35         7.15
------------------------------------------------------------------------------------------------------------
Netback                                                                    33.74         25.73        22.49
Midstream contribution (3)                                                 (0.26)        (0.26)       (0.28)
Administration (4)                                                          0.75          0.66         0.52
Interest, net                                                               0.74          1.01         1.20
Realized risk management activities loss                                    5.13          2.52         1.09
Realized foreign exchange (gain) loss                                      (0.15)         0.02         0.05
Taxes other than income tax - current                                       1.01          1.12         0.69
Current income tax - North America                                          0.41          0.47         0.14
Current income tax - Large Corporations Tax                                 0.08          0.05         0.06
Current income tax - North Sea                                              0.77          0.01         0.26
Current income tax - Offshore West Africa                                   0.17          0.07         0.09
Current income tax - other                                                  0.01          0.01           --
------------------------------------------------------------------------------------------------------------
Cash flow                                                             $    25.08     $   20.05    $   18.67
============================================================================================================
</TABLE>
(1) Amounts expressed on a per unit basis are based on sales volume.
(2) Including transportation costs and excluding risk management activities.
(3) Excluding inter-segment eliminations.
(4) Restated to conform to current year presentation.

<TABLE>
<CAPTION>
TRADING AND SHARE STATISTICS

                                                         Q1         Q2          Q3         Q4   2005 Total   2004 Total(1)
--------------------------------------------------------------------------------------------------------------------------
<S>                                                <C>        <C>         <C>        <C>          <C>         <C>
TSX - C$
Trading volume (thousands)                          169,018    155,274     160,121    153,579      637,992      606,024
Share price ($/share)
High                                               $  37.38   $  46.98    $  60.00   $  62.00     $  62.00    $   27.58
Low                                                $  24.28   $  30.54    $  45.52   $  43.55     $  24.28    $   15.96
Close                                              $  34.18   $  44.40    $  52.50   $  57.63     $  57.63    $   25.63
Market capitalization at December 31 ($ millions)                                                 $ 30,910    $  13,744
Shares outstanding (thousands)                                                                     536,348      536,361
--------------------------------------------------------------------------------------------------------------------------
NYSE - US$
Trading volume (thousands)                           48,333     68,743      66,802     67,676      251,554      125,468
Share price ($/share)
High                                               $  30.37   $  38.03    $  50.73   $  54.05     $  54.05    $   22.37
Low                                                $  19.74   $  24.49    $  36.87   $  36.65     $  19.74    $   11.94
Close                                              $  28.41   $  36.38    $  45.19   $  49.62     $  49.62    $   21.39
Market capitalization at December 31 ($ millions)                                                 $ 26,614    $  11,470
Shares outstanding (thousands)                                                                     536,348      536,361
==========================================================================================================================
</TABLE>
(1) Restated to reflect two-for-one share split in May 2005.


                                         Management's Discussion & Analysis 73

<PAGE>

TEN-YEAR REVIEW

<TABLE>
<CAPTION>
Years ended December 31                    2005     2004     2003     2002     2001     2000     1999     1998     1997     1996
---------------------------------------------------------------------------------------------------------------------------------
<S>                                     <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>
FINANCIAL INFORMATION
(C$ millions, except per share amounts)
Net earnings                              1,050    1,405    1,403      539      639      758      213       31      104       88
  Per share - basic (1)                 $  1.96  $  2.62  $  2.62  $  1.06  $  1.32  $  1.62  $  0.51  $  0.08  $  0.26  $  0.27
Cash flow from operations (2)             5,021    3,769    3,160    2,254    1,290    1,884      724      444      503      360
  Per share - basic (1)                 $  9.36  $  7.03  $  5.88  $  4.41  $  3.96  $  4.04  $  1.74  $  1.12  $  1.28  $  1.08
---------------------------------------------------------------------------------------------------------------------------------
Capital expenditures, net of dispositions
  (including business combinations)       4,932    4,633    2,506    4,069    1,885    2,823    1,901      610    1,119    1,204
---------------------------------------------------------------------------------------------------------------------------------
Balance Sheet information
Working capital (deficiency) surplus     (1,774)    (652)    (505)     (14)      (6)     (77)      36       58      (19)      (1)
Property, plant and equipment, net       19,694   17,064   13,714   12,934    8,766    7,439    4,679    3,135    2,831    1,993
Total assets                             21,852   18,372   14,643   13,793    9,290    8,051    4,976    3,329    3,016    2,144
Long-term debt                            3,321    3,538    2,748    4,200    2,788    2,573    2,157    1,426    1,136      588
Shareholders' equity                      8,237    7,324    6,006    4,754    3,928    3,297    1,962    1,317    1,250    1,108
---------------------------------------------------------------------------------------------------------------------------------
SHARE INFORMATION
Common shares outstanding (thousands)   536,348  536,361  534,926  535,104  484,804  489,116  445,816  399,236  395,276  389,532
Weighted average shares
  outstanding (thousands)               536,650  536,223  536,940  511,532  485,200  466,804  415,624  397,324  392,168  332,984
Dividends declared per common share     $  0.24  $  0.20  $  0.15  $  0.13  $  0.10  $     -  $     -  $     -  $     -  $    -
---------------------------------------------------------------------------------------------------------------------------------
Trading statistics (1)
TSX-C$
Trading volume (thousands)              637,992  606,024  590,702  619,316  534,976  567,412  430,460  410,440  402,152  396,888
Share Price ($/share)
  High                                  $ 62.00  $ 27.58  $ 16.81  $ 13.64  $ 13.09  $ 14.05  $  9.65  $  7.88  $ 11.06  $  9.85
  Low                                   $ 24.28  $ 15.96  $ 11.30  $  9.40  $  8.98  $  7.45  $  4.95  $  4.56  $  7.23  $  4.81
  Close                                 $ 57.63  $ 25.63  $ 16.34  $ 11.70  $  9.58  $ 10.38  $  8.81  $  5.75  $  7.65  $  9.40
---------------------------------------------------------------------------------------------------------------------------------
NYSE-US$
Trading volume (thousands)              251,554  l25,468   46,916   31,864   20,764    3,172        -        -        -        -
Share Price ($/share)
  High                                  $ 54.05  $ 22.37  $ 12.85  $  8.72  $  8.63  $  9.46  $     -  $     -  $     -  $     -
  Low                                   $ 19.74  $ 11.94  $  7.32  $  5.89  $  5.70  $  6.19  $     -  $     -  $     -  $     -
  Close                                 $ 49.62  $ 21.39  $ 12.61  $  7.42  $  6.10  $  6.88  $     -  $     -  $     -  $     -
---------------------------------------------------------------------------------------------------------------------------------
RATIOS
Debt to cash flow (3)                      0.7x     1.0x     0.9x     1.9x     1.5x     1.4x     3.0x     3.2x     2.3x     1.6x
Debt to book capitalization (3)           28.7%    33.8%    32.8%    47.1%    41.7%    44.0%    52.4%    52.0%    47.6%    34.7%
Return on average common shareholders'
  equity, after tax (3)                   14.3%    21.4%    25.6%    13.0%    17.7%    28.8%    13.0%     2.4%     8.8%    10.9%
Debt to EBITDA (3)                         0.6x     0.9x     0.8x     1.7x     1.4x     1.2x     2.6x     2.9x     4.8x     3.Ox
Daily production before royalties per
  ten thousand common shares (boe/d)       10.3      9.6      8.5      8.2      7.4      6.6      5.0      4.7      4.5      3.6
Conventional proved and probable
  reserves per common share (boe) (4)       4.8      4.3      4.0      3.3      3.1      2.9      2.4      1.9      1.7      1.3
Net asset value
  per common share (1)(5)                 60.44    33.13    23.35    19.57    16.88    20.54    12.33     8.08     6.80     6.46
=================================================================================================================================
</TABLE>
(1)  Restated to reflect two-for-one share splits in May 2004 and May 2005.
(2)  Cash flow from operations is a non-GAAP term that represents net earnings
     adjusted for non-cash items. The Company  evaluates its performance based
     on  earnings  and  cash  flow.  Cash  flow  from  operations  may  not be
     comparable to similar measures used by other companies.
(3)  Refer to the MD&A, page 62,  "Liquidity and Capital  Resources",  for the
     definitions of these items.
(4)  Based upon constant  dollar  Company gross reserves  (before  royalties),
     using year-end common shares outstanding.
(5)  Based upon 10% discounted, forecast price pre-tax proved and probable net
     present  values  as  reported  in  the  Company's  AIF  for  conventional
     reserves,  with  $250/acre  added for core  undeveloped  land in 2005 and
     $75/acre  for all years prior,  less  long-term  debt and existing  asset
     liabilities and adjusted for working capital. See reserves disclosures on
     pages 40 to 44.


74   Ten-Year Review

<PAGE>

<TABLE>
<CAPTION>
Years ended December 31                    2005     2004    2003    2002    2001    2000    1999    1998    1997    1996
-------------------------------------------------------------------------------------------------------------------------
<S>                                      <C>      <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>
OPERATING INFORMATION
Conventional crude oil and NGLs (mmbbl)
-------------------------------------------------------------------------------------------------------------------------
Company gross proved reserves
  (before royalties)
     North America                          785      695     672     665     644     643     554     284     257     136
     North Sea                              290      303     222     203      83     102       -       -       -       -
     Offshore West Africa                   148      125     106      94      61      36       -       -       -       -
-------------------------------------------------------------------------------------------------------------------------
                                          1,223    1,123   1,000     962     788     781     554     284     257     136
-------------------------------------------------------------------------------------------------------------------------
Company gross proved and probable reserves
  (before royalties)
     North America                        1,154      992     977     742     740     731     640     380     329      185
     North Sea                              417      415     317     277     106     134       -       -       -       -
     Offshore West Africa                   230      214     187     162     1ll      46       -       -       -       -
-------------------------------------------------------------------------------------------------------------------------
                                          1,801    1,621   1,481   1,181     957     911     640     380     329     185
-------------------------------------------------------------------------------------------------------------------------
Conventional natural gas (bcf)
Company gross proved
  reserves (before royalties)
     North America                        3,378    3,202   3,006   3,048   2,566   2,360   2,183   1,901   1,716   1,566
     North Sea                               29       27      62      71      94      91       -       -       -       -
     Offshore West Africa                    83       81      86      90      69      65       -       -       -       -
-------------------------------------------------------------------------------------------------------------------------
                                          3,490    3,310   3,154   3,209   2,729   2,516   2,183   1,901   1,716   1,566
-------------------------------------------------------------------------------------------------------------------------
Company gross proved and
  probable reserves (before
  royalties)
     North America                        4,372    4,100   3,611   3,450   2,915   2,762   2,547   2,211   2,078   1,926
     North Sea                               69       57     101      89     118     114       -       -       -       -
     Offshore West Africa                   127      102     111     120      96      84       -       -       -       -
-------------------------------------------------------------------------------------------------------------------------
                                          4,568    4,259   3,823   3,659   3,129   2,960   2,547   2,211   2,078   1,926
-------------------------------------------------------------------------------------------------------------------------
Total proved reserves
(before royalties) (mmboe)                1,804    1,674   1,526   1,497   1,243   1,200     918     601     543     397
-------------------------------------------------------------------------------------------------------------------------
Total proved and probable reserves
  (before royalties) (mmboe)              2,562    2,330   2,118   1,791   1,479   1,404   1,065     749     675     506
-------------------------------------------------------------------------------------------------------------------------
Oil sands, mining (mmbbl)
Gross proved and probable
  reserves (before royalties)
     Bitumen                              3,430        -       -       -       -       -       -       -       -       -
     Synthetic crude oil *                2,878        -       -       -       -       -       -       -       -       -
-------------------------------------------------------------------------------------------------------------------------
Daily production (before royalties)
Crude oil and NGLs (mbbl/d)
     North America                          222      206     175     169     167     155      87      76      71      37
     North Sea                               68       65      57      39      36      17       -       -       -       -
     Offshore West Africa                    23       12      10       7       3       2       -       -       -       -
-------------------------------------------------------------------------------------------------------------------------
                                            313      283     242     215     206     174      87      76      71      37
-------------------------------------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
     North America                        1,416    1,330   1,245   1,204     906     793     721     673     626     499
     North Sea                               19       50      46      27      12       1       -       -       -       -
     Offshore West Africa                     4        8       8       1       -       -       -       -       -       -
-------------------------------------------------------------------------------------------------------------------------
                                          1,439    1,388   1,299   1,232     918     794     721     673     626     499
-------------------------------------------------------------------------------------------------------------------------
Total production
(before royalties)(mboe/d)                  553      514     459     421     359     306     207     188     175     120
-------------------------------------------------------------------------------------------------------------------------
Product pricing
  Average crude oil and NGLs
  price ($/bbl)                           46.86    37.99   32.66   31.22   23.45   31.89   22.26   11.98   18.99   24.73
  Average natural gas price ($/mcf)        8.57     6.50    6.21    3.77    5.45    4.92    2.52    2.11    1.97    1.67
=========================================================================================================================
</TABLE>
*  SCO reserves are based upon upgrading of the bitumen reserves. The reserves
   shown for bitumen and SCO are not additive.


                                                          Ten-Year Review   75

<PAGE>

                             ADDITIONAL DISCLOSURE


DISCLOSURE CONTROLS AND PROCEDURES
----------------------------------

As of the end of the  registrant's  fiscal year ended  December 31,  2005,  an
evaluation of the effectiveness of Canadian Natural's "disclosure controls and
procedures"  (as such term is defined in Rules  13a-15(c) and 15d-15(e) of the
Securities  Exchange Act of 1934, as amended (the "Exchange  Act") was carried
out by Canadian Natural's  principal executive officer and principal financial
officer.  Based upon the evaluation,  Canadian Natural's  principle  executive
officer and principal  financial  officer have concluded that as of the end of
the fiscal year,  Canadian  Natural's  disclosure  controls and procedures are
effective  to  ensure  that  information  required  to  be  disclosed  by  the
registrant  in reports that it files or submits  under the Exchange Act is (i)
recorded, processed, summarized and reported within the time periods specified
in Securities and Exchange Commission rules and forms and (ii) accumulated and
communicated to the registrant's management, including its principal executive
officer and principal  financial officer,  to allow timely decisions regarding
required disclosure.

It should be noted that while Canadian Natural's  principal  executive officer
and principal  financial  officer believe that Canadian  Natural's  disclosure
controls and procedures  provide a reasonable level of assurance that they are
effective,  they do not expect the Canadian Natural's  disclosure controls and
procedures  or internal  control  over  financial  reporting  will prevent all
errors and fraud. A control system,  no matter how well conceived or operated,
can provide only  reasonable,  not absolute,  assurance that the objectives of
the control system are met.

During the fiscal year ended  December 31, 2005,  there were no changes in the
registrant's  internal controls over financial  reporting that have materially
affected,  or are reasonably  likely to materially  affect,  the  registrant's
internal controls over financial reporting.

NOTICES PURSUANT TO REGULATION BTR
----------------------------------

None

AUDIT COMMITTEE FINANCIAL EXPERT
--------------------------------

The Board of Directors of Canadian  Natural has determined  that Ms. C.M. Best
qualifies as an "audit  committee  financial  expert" (as defined in paragraph
8(b)  of  General  Instruction  B to the  Form  40-F)  serving  on  its  Audit
Committee.  Ms. C.M. Best is, as are all members of the Audit Committee of the
Board of Directors of Canadian Natural,  "independent" as such term is defined
in the New York Stock Exchange Listed Company Manual.

CODE OF ETHICS
--------------

Canadian  Natural has a long-standing  Code of Integrity,  Business Ethics and
Conduct  (the  "Code of  Ethics"),  which  covers  such  topics as  employment
standards, conflict of interest, the treatment of confidential information and
trading in  Canadian  Natural's  shares,  to ensure  that  Canadian  Natural's
business  is  conducted  in a  consistently  legal and  ethical  manner.  Each
director and all  employees,  including  each member of senior  management and
more specifically the principal  executive  officers,  the principal financial
officer and the  principal  accounting  officer,  are required to abide by the
Code of Ethics. The Nominating and Corporate Governance Committee periodically
reviews  the Code of  Ethics to ensure it  addresses  appropriate  topics  and
complies with regulatory  requirements and recommends any appropriate  changes
to the Board for approval.

Any  waivers of or  amendments  to the Code of Ethics  must be approved by the
Board of  Directors  and will be  appropriately  disclosed.  No waivers and no
implicit waivers to the Code of Ethics in whole or in part have been asked for
or granted to any director,  senior officer or employee as of the date of this
Annual Report.


<PAGE>

The Code of Ethics is available through the System for Electronic Document and
Analysis and Retrieval (SEDAR) at WWW.SEDAR.COM.  Requests for copies can also
be made by contacting: Bruce E. McGrath, Corporate Secretary, Canadian Natural
Resources Limited,  2500-855 2nd Street,  S.W., Calgary,  Alberta,  Canada T2P
4J8.

PRINCIPAL ACCOUNTANT FEES AND SERVICES
--------------------------------------

PricewaterhouseCoopers  LLP ("PwC")  has been the auditor of Canadian  Natural
since Canadian  Natural's  inception.  The aggregate amounts billed by PwC for
each of the last two fiscal years for audit fees, audit-related fees, tax fees
and all other fees, excluding expenses, are set forth below.

      AUDIT FEES:  The  aggregate  fees billed for each of the last two fiscal
years of Canadian  Natural ending December 31, 2005 and December 31, 2004, for
professional services rendered by PwC for the audit of its annual consolidated
financial  statements in connection  with statutory and regulatory  filings or
engagements for those fiscal years, unaudited reviews of the first, second and
third quarters of its interim consolidated  financial Statements and audits of
certain  of  Canadian   Natural's   subsidiary   companies'  annual  financial
statements were $1,200,235 and $1,100,548, respectively.

      AUDIT-RELATED  FEES:  The aggregate fees billed for each of the last two
fiscal years of Canadian  Natural,  ending  December 31, 2005 and December 31,
2004,  for   audit-related   services  by  PwC  consisting  of  debt  covenant
compliance, Crown Royalty Statements, and services related to internal control
reviews and assistance  with  Sarbanes-Oxley  Section 404 relating to internal
control  reporting  requirements  were,  $266,923 and  $183,663  respectively.
Canadian  Natural's  Audit  Committee  approved  all  of  these  audit-related
services.

      TAX FEES:  The  aggregate  fees  billed  for each of the last two fiscal
years of Canadian Natural, ending December 31, 2005 and December 31, 2004, for
professional  services  rendered by PwC for  tax-related  services  related to
expatriate  personal tax and compliance as well as other  corporate tax return
matters  provided in 2005 were  $39,331 and  $39,330,  respectively.  Canadian
Natural's Audit Committee approved all of these tax-related services.

      ALL OTHER  FEES:  The  aggregate  fees  billed  for each of the last two
fiscal years of Canadian  Natural,  ending  December 31, 2005 and December 31,
2004 for other services were $7,290 and $nil respectively.  The fees for other
services paid in 2005 related to accessing  resource  materials  through PwC's
accounting literature library. Canadian Natural's Audit Committee approved all
of the noted services.

      AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES:

The Audit  Committee's  duties  and  responsibilities  include  the review and
approval of fees to be paid to the independent  auditors,  scope and timing of
the audit and other related services rendered by the independent auditors. The
Audit  Committee also reviews and approves the  independent  auditor's  annual
audit plan, including scope, staffing,  locations and reliance upon management
and  internal  audit  department  prior to the  commencement  of the audit and
reviews  and  approves  proposed  non-audit  services  to be  provided  by the
independent   auditors,   except  those  non-audit   services   prohibited  by
legislation.  Canadian  Natural  did  not  rely  on the de  minimis  exemption
provided by paragraph (c)(7)(i)(c) of Rule 2.01 of Regulation S-X in 2005.

<PAGE>

OFF-BALANCE SHEET ARRANGEMENTS
------------------------------

Canadian Natural does not have any off-balance sheet arrangements that have or
are  reasonably  likely to have an  effect on its  results  of  operations  or
financial condition. See page 65 of Canadian Natural's Management's Discussion
and Analysis of Financial  Condition and Results of Operations  for the fiscal
year ended December 31, 2005, filed herewith,  under the caption  "Commitments
and Off Balance Sheet Arrangements".

CONTRACTUAL OBLIGATIONS
-----------------------

In the normal  course of  business,  the  Company  has  entered  into  various
contractual  arrangements  and  commitments  that  will  have an impact on the
Company's future  operations.  These  contractual  obligations and commitments
primarily relate to debt repayments, operating leases relating to office space
and  offshore  production  and  storage  vessels,  and  firm  commitments  for
gathering,  processing  and  transmission  services,  as well as  expenditures
relating to asset retirement obligations. The Company has not entered into any
contracts that would require  consolidation  under CICA  Accounting  Handbook,
AcG-15,  Consolidation  of Variable  Interest  Entities.  The following  table
summarizes the Company's commitments as at December 31, 2005:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------
 ($ MILLIONS)                            TOTAL        2006       2007        2008       2009       2010       THEREAFTER
-------------------------------------------------------------------------------------------------------------------------
<S>                                      <C>          <C>        <C>         <C>         <C>        <C>       <C>
Product transportation and pipline        1,766        195        133         148         94         85            1,111
-------------------------------------------------------------------------------------------------------------------------
Offshore equipment and leasing              436         51         51          52         51         51              180
-------------------------------------------------------------------------------------------------------------------------
Offshore drilling                           267        132        100          35          -          -                -
-------------------------------------------------------------------------------------------------------------------------
Asset Retirement Obligation(1)            3,325         82          4           4          4          7            3,224
-------------------------------------------------------------------------------------------------------------------------
Long-term debt(2)                         3,199          -        161          36         36          -            2,966
-------------------------------------------------------------------------------------------------------------------------
Other(3)                                    204         61         62          21         29         23                8
-------------------------------------------------------------------------------------------------------------------------
                              TOTAL       9,197        521        511         296        214        166            7,489
=========================================================================================================================
</TABLE>

(1)  Represents  management's  estimate of the future payments to settle asset
     retirement  obligations  related  to  resource  properties,   facilities,
     production  platforms and  pipelines,  based on current  legislation  and
     industry operating practices.

(2)  No debt  repayments  are reflected for the bank credit  facilities due to
     the extendable  nature of the  facilities.  As at December 31, 2005 there
     was $122 million outstanding owed under the bank credit facilities.

(3)  Consists  of future  expenditures  related  primarily  to  office  lease,
     electricity and crude oil processing.


Total  construction  costs  for  the  three  phases  of  the  Horizon  Project
development  are  expected to be  approximately  $10.8  billion.  The Board of
Directors  has  approved  the  construction  costs for Phase 1 of the  Horizon
Project,  which are expected to be $6.8 billion,  including a contingency fund
of $700 million,  with $1.3 billion incurred in 2005, $2.6 billion forecast to
be incurred in 2006 and $2.9 billion  forecast to be incurred in 2007 and 2008
combined.


The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business.  The Company  believes that any  liabilities
that might arise  pertaining to such matters would not have a material  effect
on its consolidated financial position.

IDENTIFICATION OF THE AUDIT COMMITTEE
-------------------------------------

Canadian  Natural  has  a  separately   designated  standing  audit  committee
established  in accordance  with section  3(a)(58)(A) of the Exchange Act. The
members of the Audit Committee are Messrs.  G. A. Filmon,  G. D. Giffin, D. A.
Tuer and Ms. C.M. Best who chairs the Audit Committee.


<PAGE>

NEW YORK STOCK EXCHANGE DISCLOSURE
----------------------------------

PRESIDING DIRECTOR AT MEETINGS OF NON-MANAGEMENT DIRECTORS
----------------------------------------------------------

Canadian  Natural  schedules  executive  sessions at each regularly  scheduled
Board  of  Directors  meeting  in  which  Canadian  Natural's  "non-management
directors"  (as that  term is  defined  in the  rules  of the New  York  Stock
Exchange) meet without  management  participation.  Mr. G. D. Giffin serves as
the presiding director (the "Presiding  Director") at such sessions and in his
absence the  non-management  directors appoint a Presiding Director from among
the non-management directors.

COMMUNICATION WITH NON-MANAGEMENT DIRECTORS
-------------------------------------------

Shareholders  may send  communications  to Canadian  Natural's  non-management
directors  by  writing  to the  Presiding  Director,  c/o  Bruce  E.  McGrath,
Corporate  Secretary,  Canadian  Natural  Resources  Limited,  2500, 855 - 2nd
Street S.W., Calgary, Alberta, T2P 4J8. Communications will be referred to the
Presiding  Director  for  appropriate  action.  The status of all  outstanding
concerns  addressed to the Presiding Director will be reported to the board of
directors as appropriate.

CORPORATE GOVERNANCE GUIDELINES
-------------------------------

In accordance with Section 303A.09 of the NYSE Listed Company Manual, Canadian
Natural  has  adopted  a set of  corporate  governance  guidelines,  which are
available in print at no charge to any shareholder who requests them. Requests
for  copies  of  the  corporate  governance   guidelines  should  be  made  by
contacting: Bruce E. McGrath, Corporate Secretary,  Canadian Natural Resources
Limited,  2500-855 2nd Street,  S.W.,  Calgary,  Alberta,  Canada T2P 4J8. The
corporate governance  guidelines are attached as a schedule to the Information
Circular for the Annual  General  Meeting of  Shareholders  which is available
through the System for Electronic  Document and Analysis and Retrieval (SEDAR)
at WWW.SEDAR.COM

BOARD COMMITTEE CHARTERS
------------------------

The charters of Canadian  Natural's Audit Committee,  Nominating and Corporate
Governance  Committee and Compensation  Committee are available in print at no
charge to any  shareholder  who  requests  them.  Requests for copies of these
documents should be made by contacting: Bruce E. McGrath, Corporate Secretary,
Canadian  Natural  Resources  Limited,  2500-855  2nd Street,  S.W.,  Calgary,
Alberta,  Canada T2P 4J8. The Charter of Canadian Natural's Audit Committee is
also attached as a schedule to Canadian  Natural's Annual Information Form for
year ending December 31, 2005,  which forms part of this Form 40-F. The Annual
Information Form is also available through the System for Electronic  Document
and Analysis and Retrieval (SEDAR) at www.sedar.com.

<PAGE>

                 UNDERTAKING AND CONSENT TO SERVICE OF PROCESS


UNDERTAKING

Canadian  Natural  undertakes  to make  available,  in person or by telephone,
representatives  to respond to inquiries made by the Commission  staff, and to
furnish promptly, when requested to do so by the Commission staff, information
relating to: the securities  registered  pursuant to Form 40-F; the securities
in  relation  to which the  obligation  to file an annual  report on Form 40-F
arises; or transactions in said securities.

CONSENT TO SERVICE OF PROCESS

The Company has  previously  filed a Form F-X in connection  with the class of
securities in relation to which the obligation to file this report arises.

Any  change to the name or  address  of the agent for  service  of  process of
Canadian  Natural  shall be  communicated  promptly  to the  Commission  by an
amendment  to the  Form  F-X  referencing  the  file  number  of the  relevant
registration statement.



                                  SIGNATURES

Pursuant to the requirements of the Exchange Act,  Canadian Natural  certifies
that it meets  all of the  requirements  for  filing on Form 40-F and has duly
caused  this  Annual  Report to be signed  on its  behalf by the  undersigned,
thereto duly authorized.

Dated this 29th day of March, 2006.


                                          CANADIAN NATURAL RESOURCES LIMITED



                                          By: /s/ Steve W. Laut
                                              -----------------------------
                                              Name:   Steve W. Laut
                                              Title:  President and Chief
                                                      Operating Officer

<PAGE>

Documents filed as part of this report:


                              EXHIBIT INDEX

EXHIBIT
NUMBER       DESCRIPTION
-------      -----------

  1.         Supplementary  Oil & Gas Information for the fiscal year ended
             December 31, 2005.

  2.         Certification  of Chief  Executive  Officer  pursuant  to Rule
             13a-14(a) or 15d-14 of the Securities Exchange Act of 1934.

  3.         Certification  of Chief  Financial  Officer  pursuant  to Rule
             13a-14(a) or 15d-14 of the Securities Exchange Act of 1934.

  4.         Certification  of Chief  Executive  Officer  pursuant  to Rule
             13(a)-14(b)  and Section 1350 of Chapter 63 of Title 18 of the
             United States Code (18 U.S.C. 1350).

  5.         Certification  of Chief  Financial  Officer  pursuant  to Rule
             13(a)-14(b)  and Section 1350 of Chapter 63 of Title 18 of the
             United States Code (18 U.S.C. 1350).

  6.         Consent of  PricewaterhouseCoopers  LLP, independent chartered
             accountants.

  7.         Consent of Sproule Associates Limited,  independent  petroleum
             engineering consultants.

  8.         Consent  of  Ryder  Scott   Company,   independent   petroleum
             engineering consultants.

  9.         Consent of Gilbert Laustsen Jung Associates Ltd.,  independent
             petroleum engineering consultants.