================================================================================
                                  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, 2006    Commission File Number: 333-12138


                       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:


TITLE OF EACH CLASS:                 NAME OF EACH EXCHANGE ON WHICH REGISTERED:
Common Shares, no par value          New York 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.

          537,903,260 Common Shares outstanding as of December 31, 2006

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

<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. 333-138873) 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, 2006.

         B.       AUDITED ANNUAL FINANCIAL STATEMENTS

         Canadian Natural's audited  consolidated  financial statements for the
         years ended December 31, 2006 and 2005, including the auditors' report
         with respect thereto.  For a reconciliation  of important  differences
         between  Canadian  and United  States  generally  accepted  accounting
         principles,  see Note 16 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, 2006.

SUPPLEMENTARY OIL & GAS INFORMATION

For Canadian  Natural's  Supplementary Oil & Gas Information for the year ended
December 31, 2006, see Exhibit 1 of this Annual Report on Form 40-F.


                                       1
<PAGE>


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



    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 28, 2007

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

<PAGE>
                                       1


                               TABLE OF CONTENTS

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

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

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

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

REGULATORY MATTERS...........................................................12

RISK FACTORS.................................................................13

ENVIRONMENTAL MATTERS........................................................19

DESCRIPTION OF THE BUSINESS..................................................20

A.   PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES...............21

         DRILLING ACTIVITY...................................................22
         PRODUCING CRUDE OIL AND NATURAL GAS WELLS...........................23
         NORTHEAST BRITISH COLUMBIA..........................................23
         NORTHWEST ALBERTA...................................................24
         NORTHERN PLAINS.....................................................25
         SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN..........................28
         HORIZON OIL SANDS PROJECT...........................................30
         UNITED KINGDOM NORTH SEA............................................32
         OFFSHORE WEST AFRICA................................................33
         COTE D'IVOIRE.......................................................33
         ANGOLA..............................................................34
         GABON...............................................................35

B.   CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES....................36

C.   RECONCILIATION OF CHANGES IN NET CONVENTIONAL RESERVES..................41

D.   OIL SANDS MINING DISCLOSURE.............................................42

E.   CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION..............................49

F.   HISTORICAL DRILLING ACTIVITY BY PRODUCT.................................54

G.   NET CAPITAL EXPENDITURES................................................55

H.   UNDEVELOPED ACREAGE.....................................................58

I.   DEVELOPED ACREAGE.......................................................58

SELECTED FINANCIAL INFORMATION...............................................59

<PAGE>
                                       2


CAPITAL STRUCTURE............................................................60

MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES.....................61

DIVIDEND HISTORY.............................................................62

TRANSFER AGENTS AND REGISTRAR................................................63

DIRECTORS AND OFFICERS.......................................................63

CONFLICTS OF INTEREST........................................................68

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS...................68

AUDIT COMMITTEE INFORMATION..................................................69

LEGAL PROCEEDINGS............................................................70

MATERIAL CONTRACTS...........................................................70

INTERESTS OF EXPERTS.........................................................70

ADDITIONAL INFORMATION.......................................................71

SCHEDULE "A" REPORT ON RESERVES DATA.........................................72

SCHEDULE "B" REPORT OF MANAGEMENT AND DIRECTORS..............................75

SCHEDULE "C" CHARTER OF THE AUDIT COMMITTEE..................................77


                                    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:

"ARO" means Asset Retirement Obligation

 "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.

"CBM" means coalbed methane

"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 Offtake vessel.

"GHG" means greenhouse gas.

"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.

"HORIZON PROJECT" means the Horizon Oil Sands Project

"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.

<PAGE>
                                       4


"NGLS" means natural gas liquids.

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

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

"PRODUCTIVE WELL" means a well that is not a dry well.

"PRT" means Petroleum Revenue Tax

"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  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  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 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
crude oil and  natural  gas in common  units  called  barrel of oil  equivalent
("boe").  A boe is derived by converting six thousand cubic feet of natural gas
to one barrel of crude oil  (6mcf:1bbl).  This  conversion  may be  misleading,

<PAGE>
                                       6


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,  2006,  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,  as well as proved and  probable  crude oil,  natural gas
liquids ("NGL") and natural gas reserves (not including the Company's oil sands
mining  assets)  and  prepare  Evaluation  Reports on these  reserves.  Sproule
evaluated  the  Company's  North  America  conventional  assets and Ryder Scott
evaluated the 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
Security and Exchange  Commission ("SEC")  requirements for certain disclosures
required under NI 51-101.  There are two principal  differences between the two
standards  (i) the  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;  and, (ii) the definition
of proved  reserves used by the SEC to that of NI 51-101.  However with respect
to the definition of proved reserves,  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
should not be material.

For the year  ended  December  31,  2006,  the  Company  retained  a  qualified
independent  reserves  evaluator,  GLJ Petroleum  Consultants Ltd. ("GLJ"),  to
evaluate 100% of Phases 1 through 3 of the Company's  Horizon Oil Sands Project
("Horizon  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 proved and probable
crude oil, NGLs and natural gas reserves.

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  crude oil and natural gas
information  section of the Company's Annual Report. The Company has elected to
provide the net present  value of these same  conventional  proved  reserves as
well as its conventional proved and probable reserves and the net present value
of  these   reserves  under  the  same   parameters  as  additional   voluntary
information.  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.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 this Annual Information
Form.

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,  NGLs and  natural  gas
reserves as well as the Company's quantity of oil sands mining reserves.

<PAGE>
                                       7


SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES

Management's  Discussion and Analysis ("MD&A") 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 net asset
value.   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.

                                  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.

On September  14, 2006,  the Company  announced  entering  into an agreement to
acquire  Anadarko  Canada  Corporation,  a  subsidiary  of  Anadarko  Petroleum
Corporation  for net cash  consideration  of $4,641 million  including  working
capital and other adjustments.  Pursuant to a Purchase and Sale Agreement,  the
Company acquired all of the outstanding  shares of Anadarko Canada  Corporation
effective November 2, 2006. On November 3, 2006 Anadarko Canada Corporation and
a wholly owned subsidiary of the Company,  1266701 Alberta Ltd.  amalgamated to
form ACC-CNR Resources Corporation.  Subsequently,  on January 1, 2007, ACC-CNR
Resources  Corporation and Canadian Natural Resources  Limited  amalgamated and
the amalgamated  company  continued under the name Canadian  Natural  Resources
Limited.

<PAGE>
                                       8


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

    NAME OF COMPANY                               JURISDICTION 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 (Olowi) 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,  as the managing partner,  CNR (ECHO) Resources
Inc.,  Renata  Resources Inc., and Canadian  Natural  Resources 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.  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 situated in Alberta. Canadian Natural, as the managing partner, and CNR
2006 ULC are the partners of CNR 2006  Partnership,  which holds  certain crude
oil  and  natural  gas  properties   situated  in  the  provinces  of  Alberta,
Saskatchewan and British Columbia and in the Yukon Territories.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.

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 NGLs, natural gas and bitumen production.

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 net 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,  2006 the  Company  had  3,360
permanent  employees  in  North  America  and 340  permanent  employees  in its
international operations.

<PAGE>
                                       9


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. 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
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.

<PAGE>
                                      10


In February 2005, the Board of Directors of the Company approved Phase 1 of the
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"). Future expansion using
a phased approach would further  increase  production to 232 mbbl/d of 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.

Based upon  stratigraphic  drilling and the Company's own internal estimates it
is believed  that 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  Ltd.  ("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 3.5 billion barrels of gross lease 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  began  in 2006 and is
expected to 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.

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.

<PAGE>
                                      11


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.

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.

On August 17, 2006, the Company issued US$250.0 million of 10 year 6.0 per cent
unsecured notes maturing  August 15, 2016 and US$450.0  million of 30 year 6.50
per cent unsecured  notes  maturing  February 15, 2037 pursuant to a short form
base shelf prospectus dated June 3, 2005.

In November 2006,  the Company  completed the  acquisition  of Anadarko  Canada
Corporation  ("ACC") for net cash  consideration  of $4,641 million,  including
working capital and other adjustments.  The Company immediately  integrated ACC
into its ongoing operations.  The land and production base acquired are located
substantially in Western Canada and are natural gas weighted assets with a long
reserve  life.  The assets  produce in excess of 350 mmcf/d of natural  gas and
approximately  9,000 bbl/d of light crude oil and NGLs  production.  The assets
acquired also include  approximately  1.5 million net undeveloped acres and key
strategic  facilities in Northeast British Columbia and Northwest  Alberta.  In
conjunction  with the closing of the acquisition of ACC, the Company executed a
$3,850 million, three-year non-revolving syndicated credit facility maturing in
October 2009. This facility is subject to certain prepayment requirements up to
a maximum of $1,500 million.

During 2006,  the Company  completed 83  transactions  in the normal  course to
acquire  additional  interests  in crude oil and  natural gas  properties.  The
aggregate net expenditure of the transactions was $4,801 million, including the
ACC acquisition of $4,755 million.  The properties  acquired are located in the
Company's  principal  operating  regions and are  comprised  of  producing  and
non-producing  leases  together  with related  facilities.  As well the Company
participated  in  48   transactions   to  dispose  of  non-core   operated  and
non-operated properties for proceeds of $68 million. Included in this amount is
a royalty disposition for $66 million.

On March 19, 2007, the Company issued US$1,100 million of 10 year 5.70 per cent
unsecured notes maturing May 15, 2017 and US$1,100 million of 30 year 6.25 per
cent unsecured notes maturing March 15, 2038 pursuant to a short form base shelf
prospectus dated November 27, 2006. Concurrently, the Company entered into
cross-currency interest-rate swaps to fix the Canadian dollar interest and
principal repayment amounts on US$1,100 million of unsecured notes due May 15,
2017 at 5.10% and C$1,287 million. The Company also entered into a
cross-currency interest-rate swap to fix the Canadian dollar interest and
principal repayment amounts on US$550 million of unsecured notes due March 15,
2038 at 5.76% and C$644 million.

<PAGE>
                                      12


                               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 primarily  located in Alberta,  British
Columbia, Saskatchewan,  Manitoba and the Northwest and Yukon 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  and  Yukon   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 NGLs, crude oil and natural gas production from leases
owned by the  province.  The royalties  are  determined  by regulation  and are
generally  calculated  as a  percentage  of  production  varied  by a number of
different  factors  including  selling  prices,   production  levels,  recovery
methods, transportation and processing costs, location and date of discovery.

In addition  to  government  royalties,  the  Company is  currently  subject to
federal  and  provincial   income  taxes  in  Canada  at  a  combined  rate  of
approximately 34.91 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

<PAGE>
                                      13


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  Charge Tax ("SCT") 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.  During 2005, the UK Chancellor of
the Exchequer  announced a further increase to the SCT of 10% to 20% on profits
from UK North Sea crude oil and natural gas  production,  effective  January 1,
2006. In December  2006,  the UK  Government  announced the abolition of PRT on
profits of decommissioned fields subsequently  redeveloped,  subject to certain
conditions being met.

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,   are  subject  to  production   sharing
arrangements  that provide 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 August 2006,
the Government of Cote d'lvoire  announced a reduction in the rate of Corporate
Income Tax from 35 to 27 per cent, effective January 1, 2006.

In October 2005,  Canadian  Natural  completed the acquisition of the permit to
develop  the  Olowi  Field,   offshore  Gabon  and  received  approval  of  its
development  plan for this  acquisition  from the Gabonese  Government in early
2006  and  from  Canadian  Natural's  Board  of  Directors  in  November  2006.
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,  European 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,

<PAGE>
                                      14


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  2006  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.

The crude oil and natural gas industry is experiencing incremental increases in
costs related to  environmental  regulation,  particularly in North America and
the North Sea.  Existing and expected  legislation and regulations will require
the  Company to  address  and  mitigate  the  effect of its  activities  on the
environment.   This  will  include   dismantling   production   facilities  and
remediating  damage caused by the disposal or release of specified  substances.
Increasingly  stringent laws and  regulations may have an adverse effect on the
Company's future net earnings and cash flow from operations.

The  Company's  associated  risk  management  strategies  focus on working with
legislators  and  regulators  to  ensure  that  any  new or  revised  policies,
legislation or regulations  properly reflect a balanced approach to sustainable
development.  Specific  measures in  response  to  existing or new  legislation
include a focus on the Company's energy efficiency,  air emissions  management,
released water  quality,  reduced fresh water use and the  minimization  of the
impact on the  landscape.  The  Company's  strategy  employs  an  Environmental
Management Plan known as the Stewardship  Report (the "Plan"),  a detailed copy
of  of  the  Plan  is  presented  to,  and  reviewed  by,  Health,  Safety  and

<PAGE>
                                      15


Environmental Committee of the Board of Directors annually. The Plan is updated
quarterly at the Health, Safety and Environmental Committee meetings.

The Company's Plan and operating  guidelines  focus on minimizing the impact of
operations  while  meeting  regulatory   requirements  and  internal  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:

1.   The use of water-based, environmentally friendly drilling muds;

2.   Implementing cost effective ways of reducing  greenhouse gas emissions per
     unit of production;

3.   Exercising care with respect to all waste produced through effective waste
     management plans; and

4.   Minimizing   produced   water   volumes   onshore  and  offshore   through
     cost-effective measures.

In  2006,  the  Company's  capital   expenditures   included  $75  million  for
abandonment  expenditures,  an  increase  from $46  million in 2005 (2004 - $32
million).

The Company's estimated undiscounted ARO at December 31, 2006 was as follows:

<TABLE>
<CAPTION>
                                                          -------------
Estimated ARO, undiscounted ($millions)                           2006          2005
-------------------------------------------------------------------------------------
<S>                                                        <C>          <C>
North America                                              $     2,826  $      2,050
North Sea                                                        1,543         1,185
Offshore West Africa                                               128            90
-------------------------------------------------------------------------------------
                                                                 4,497         3,325
North Sea PRT recovery                                           (625)         (370)
-------------------------------------------------------------------------------------
                                                           $     3,872  $      2,955
=====================================================================================
</TABLE>

<PAGE>
                                      16


The  estimate of the ARO is based on  estimates  of future costs to abandon and
restore the wells,  production  facilities and offshore  production  platforms.
Factors that affect costs include number of wells  drilled,  well depth and the
specific   environmental   legislation.   The  estimated  costs  are  based  on
engineering   estimates   using  current  costs  in  accordance   with  present
legislation  and industry  operating  practice.  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. The future  abandonment costs incurred in the North Sea are
expected to result in an estimated  PRT  recovery of $625 million  (2005 - $370
million),  as abandonment  costs are an allowable  deduction in determining PRT
and may be carried  back to reclaim  PRT  previously  paid.  The  expected  PRT
recovery  reduces the Company's  net  abandonment  liability to $3,872  million
(2005 - $2,955 million).

GREENHOUSE GAS ("GHG") AND OTHER AIR EMISSIONS

The Company is  concurrently  working with  legislators  and  regulators on the
design of new greenhouse gas emission laws and  regulations  and is pursuing an
integrated  emissions  reduction  strategy,  to ensure  the  Company is able to
comply with existing and future emission reductions  requirements.  The Company
continues to develop  strategies that will enable it to deal with the risks and
opportunities  associated with new climate change  policies.  In addition,  the
Company is working with relevant parties to ensure that new policies  encourage
innovation,  energy  efficiency,  targeted  research and development  while not
impacting competitiveness.

The Company continues to work with Canadian federal and provincial  governments
on the  regulatory  framework for  greenhouse  gases for larger  emitters.  The
Company is actively promoting a harmonized regulatory framework between the two
levels of  government.  Both levels of government  have indicated that existing
legislation  will be  amended  in  2007  to  create  further  requirements  for
reporting emissions,  facility-based  emission intensity targets and regulatory
compliance. Compliance with emission intensity targets is expected for 2008 and
possibly a part of 2007 for larger facilities in Alberta.

Issues  to be  resolved  include,  but are  not  limited  to:  the  outcome  of
discussions  between  the  Federal and  Provincial  Governments,  the impact of
implementing  legislation,  the  allocations  of  reduction  obligations  among
industry sectors and international developments.

Canadian  Natural  anticipates  that changes in  environmental  legislation may
require,  among  other  things,  reductions  in  emissions  to the air from its
operations.  Any required  reductions in the greenhouse  gases emitted from the
Company's   operations  could  increase  capital   expenditures  and  operating
expenses,  especially  those  related to the Horizon  Project and the Company's
other existing and planned large oil sands  projects.  This may have an adverse
effect on the  Company's  net  earnings and cash flow from  operations.  Future
changes in  environmental  legislation  could 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.

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,

<PAGE>
                                      17


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.  The Company has developed
a comprehensive  health and safety  management  framework to mitigate  physical
risks.   The  Company  also  mitigates   insurable  risks  to  protect  against
significant  losses by maintaining a  comprehensive  insurance  program,  while
maintaining  levels and  amounts of risk within the  Company  which  management
believes to be acceptable.  However, Canadian Natural's liability, property and
business interruption  insurance may not and possibly will not provide adequate
coverage in all 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.

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

<PAGE>
                                      18


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

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

PRIORITY  OF  SUBSIDIARY  INDEBTEDNESS;  CONSEQUENCES  OF  HOLDING  CORPORATION
STRUCTURE

The Company carries on business through corporate and partnership subsidiaries.
The  majority  of the  Company's  assets are held in one or more  corporate  or
partnership  subsidiaries.  The  results of  operations  and ability to service
indebtedness,  including  debt  securities,  are dependent  upon the results of
operations of these subsidiaries and the payment of funds by these subsidiaries
to the Company in the form of loans,  dividends or other means employed for the
payment  of funds  to the  Company.  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>
                                      19


                             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 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.

Canadian  Natural is committed to managing air emissions  through an integrated
corporate approach which considers  opportunities to reduce both air pollutants
and GHG emissions. Air quality programs continue to be an essential part of our
environmental  work plan and are operated  within all regulatory  standards and
guidelines.  Our  strategy  for  managing  GHG  emissions is based on four core
principles: energy conservation and efficiency;  reduced intensity;  innovative
technology and associated research and development; and, trading capacity; both
domestically and globally.

The Company continues to implement  flaring,  venting and fuel and solution gas
conservation  programs.  In 2006 the Company  completed  approximately  122 gas
conservation  projects,  resulting in reduction of 1.24 million  tonnes/year of
carbon dioxide equivalents  ("CO2E").  Over the past five years the Company has
spent over $100 million to conserve the  equivalent of over 5 million tonnes of
CO2E. In heavy crude oil production  Canadian Natural is evaluating tank heater
efficiciencies  in an effort to  conserve  fuel gas at  facilities  with  field
tanks. The Company also monitors the performance of its compressor fleet and it
is continually  modified and optimized for maximum efficiency.  Another project
of note is the  trial of "no  emissions"  chemical  injection  pumps  which are
designed to eliminate  fuel gas venting.  These  programs  also  influence  and

<PAGE>
                                      20


direct the Company's plans for new projects and facilities.  It is planned that
the Horizon  Project will  incorporate  advancements  in  technology  to reduce
further  GHG  emissions  through  maximizing  heat  integration,   the  use  of
cogeneration  to meet  steam  and  electricity  demands  and the  design of the
hydrogen production facility to enable carbon dioxide ("CO2") capture.

In its North Sea operations  the Company is operating  below its CO2 allocation
and continues to implement an improvement program based on efficiency audits of
its major facilities. Canadian Natural also began a Produced Water Re-injection
trial which has resulted in re-injecting  approximately  30 thousand barrels of
produced water each day.

The costs incurred by the Company for compliance with environmental matters and
site  restoration  exceeded  three  per  cent  of  the  total  exploration  and
development  expenditures  incurred  by the  Company in each of the years ended
December 31, 2006, 2005 and 2004.

                          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.

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/medium  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 42 per cent of 2006 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/medium crude oil and NGLs, representing 26
per cent of 2006 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 2006  production.  Other heavy crude oil, which accounts for
five per cent of 2006  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 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 are  expected to deliver  approximately  37 years of
synthetic crude oil production.

<PAGE>
                                       21


As a result of the  Company's  core  undeveloped  land base of 12.8 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.

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, 2006. The information  reflects the working
interests owned by the Company.


<TABLE>
<CAPTION>
                                                      YEAR ENDED
                            2006 AVERAGE DAILY       DECEMBER 31,        MAJOR INFRASTRUCTURE
                             PRODUCTION RATES            2006          AS AT DECEMBER 31, 2006
                           ---------------------   ----------------   -------------------------

                               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        408           2,721               1/11/-/-

Northwest Alberta               15.0        454           1,750               -/14/-/-

Northern Plains                194.5        437           7,211               12/6/-/-

Southern Plains                 10.5        165             870               -/3/-/-

Southeast                        8.4          3             117               -/-/-/-
     Saskatchewan

Non - core regions               0.2          1             249               -/-/-/-

Horizon Oil Sands                  -          -             116               -/-/-/-

INTERNATIONAL

North Sea UK Sector             60.1         15             299               -/-/6/1

Offshore West Africa

     Cote d'Ivoire              36.7          9              55               -/-/-/2

     Gabon                         -          -             152               -/-/-/-

Non - core regions

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

TOTAL                          332.1      1,492          17,542              13/34/6/3
===============================================================================================
</TABLE>

<PAGE>

                                      22

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
ending December 31, 2006 by geographic region:

<TABLE>
<CAPTION>
                                                                         2006
-------------------------------------------------------------------------------------------------------------------------
                                            NET EXPLORATORY                                NET DEVELOPMENT
                                PRODUCTIVE      DRY HOLES       TOTAL         PRODUCTIVE      DRY HOLES        TOTAL
-------------------------------------------------------------------------------------------------------------------------
<S>                                   <C>             <C>        <C>                 <C>             <C>          <C>
CANADA
                                       17.2            5.6         22.8             158.9            14.1         173.0
  Northeast B. C.
                                       17.7            9.5         27.2             149.6            14.6         164.2
  Northwest Alberta
                                      104.1           28.2        132.3             598.5            36.1         634.6
  Northern Plains
                                       31.8            8.4         40.2              78.6             1.0          79.6
  Southern Plains
                                          -              -            -              72.7             2.0          74.7
  Southeast Saskatchewan
                                        0.6              -          0.6               2.7               -           2.7
  Non - core regions
NORTH SEA UK SECTOR                       -              -            -               7.4               -           7.4
OFFSHORE WEST AFRICA
  Cote d'Ivoire                           -              -            -               4.1               -           4.1
-------------------------------------------------------------------------------------------------------------------------
TOTAL                                 171.4           51.7        223.1           1,072.5            67.8       1,140.3
=========================================================================================================================

                                                                         2005
-------------------------------------------------------------------------------------------------------------------------
                                           NET EXPLORATORY                                 NET DEVELOPMENT
                                PRODUCTIVE      DRY HOLES      TOTAL           PRODUCTIVE      DRY HOLES       TOTAL
-------------------------------------------------------------------------------------------------------------------------
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             1,339.7           83.2       1,422.9
=========================================================================================================================

                                                                         2004
-------------------------------------------------------------------------------------------------------------------------
                                           NET EXPLORATORY                                 NET DEVELOPMENT
                                PRODUCTIVE      DRY HOLES      TOTAL           PRODUCTIVE      DRY HOLES       TOTAL
-------------------------------------------------------------------------------------------------------------------------
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
=========================================================================================================================
</TABLE>

<PAGE>

                                      23

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, 2006:

<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.                 1,548.0         1,305.5          243.0          203.5         1,791.0        1,509.0
  Northwest Alberta               1,681.0         1,294.7          521.0          305.9         2,202.0        1,600.6
  Northern Plains                 4,022.0         3,233.4        5,705.0        5,204.6         9,727.0        8,438.0
  Southern Plains                 6,955.0         5,986.9        1,140.0        1,032.0         8,095.0        7,018.9
  Southeast Saskatchewan                -               -        1,092.0          694.8         1,092.0          694.8
  Non - core regions                316.0           118.6          665.0          202.1           981.0          320.7
UNITED STATES                         4.0             0.5            4.0            0.7             8.0            1.2
NORTH SEA UK SECTOR                   2.0             0.1          118.0           96.8           120.0           96.9
OFFSHORE WEST AFRICA
  Cote d'Ivoire                       0.0             0.0           15.0            8.7            15.0            8.7
-----------------------------------------------------------------------------------------------------------------------
TOTAL                            14,528.0        11,939.7        9,503.0        7,749.1        24,031.0       19,688.8
=======================================================================================================================
</TABLE>

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

NORTHEAST BRITISH COLUMBIA

                            [GRAPHIC OMITTED - MAP]


Significant  geological variation extends throughout the productive  reservoirs
in region,  producing  light crude oil, NGLs and natural gas. The Company holds
working  interests  ranging  up to 100 per  cent and  averaging  74 per cent in
5,107,623 gross  (3,721,424 net) acres of producing and undeveloped land in the
region.

<PAGE>
                                      24


Crude oil reserves are found primarily in the Halfway formation,  while natural
gas  and  associated  NGLs  are  found  in  numerous  carbonate  and  sandstone
formations at depths up to 4,500  vertical  meters.  The  exploration  strategy
focuses  on   comprehensive   evaluation   through   two-dimensional   seismic,
three-dimensional  seismic and targeting  economic  prospects close to existing
infrastructure.  The  region  has a mix of low risk  multi-zone  targets,  deep
higher risk  exploration  plays and emerging  unconventional  natural gas plays
including  shale  gas  and  CBM.  The  2006  acquisition  of ACC  significantly
increases  the  Company's  asset base in Northeast  British  Columbia  with the
addition of the ACC  properties in Adsett,  Caribou and Ft. St. John West.  The
southern portion of this region  encompasses the Company's BC Foothills assets;
here natural gas is produced  from the deep  Mississippian  and  Triassic  aged
reservoirs  in this highly  deformed  structural  area.  In 2006 the  Company's
assets in Monkman and Ojay were augmented by the assets previously owned by ACC
in the area.

Natural gas production  from the region averaged 408 mmcf/d in 2006 compared to
the average of 434.4 mmcf/d in 2005.  Crude oil and NGLs  production was steady
at 6,700 bbl/d in 2006, unchanged from an average of 6,700 bbl/d in 2005.

During 2005, the Company  initiated a new exploration and development play 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 mmcf/d. 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.
Development  of this play  continued  in 2006 with the  drilling of 45 wells at
Ladyfern.  Another shallow gas play was pursued in 2006 with the drilling of 50
Banff wells at Shekelie.

During 2006, the Company drilled 12.9 (2005 - 10.9) net crude oil wells,  163.2
(2005   -   201.1)   net   natural   gas   wells,   0.0   (2005   -  1.0)   net
stratigraphic/service  wells and 19.7  (2005 - 28.3) net dry wells on its lands
in this region for a total of 195.8 (2005 - 241.3) net wells.  The Company held
an average 86 per cent working interest in these wells.

NORTHWEST ALBERTA

                            [GRAPHIC OMITTED - MAP]

<PAGE>
                                      25


The Company holds working interests ranging up to 100 per cent and averaging 73
per cent in 3,537,210 gross  (2,582,042 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  initial  holdings in the region were  obtained
through the 2002 acquisition of RAX;  subsequent to 2002 the Company  augmented
these holdings with  additional land  purchases,  acquisitions  and in 2006 the
purchase  of the ACC assets.  The ACC  acquisition  added two very  prospective
properties  to this  region,  Wild River and Peace River  Arch.  The Wild River
assets will provide a premium  developed and undeveloped  land base in the deep
basin,  multi-zone gas fairway and the Peace River Arch assets provides premium
lands in a multi-zone region along with key  infrastructure.  Northwest Alberta
provides  exploration and  exploitation  opportunities  in combination  with an
extensive 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  region  provides   extensive   multi-zone   Cretaceous
opportunities  similar to the  geology of the  Company's  Northern  Plains core
region.  The Company is also pursuing  development  of a Doig shale gas play in
this  region.  The  southern  portion  provides   exploration  and  development
opportunities in the regionally  extensive  Cretaceous Cardium formation and in
the  deeper,  tight gas  formations  throughout  the  region.  The Cardium is a
complex,  tight natural gas reservoir where high  productivity  may be achieved
due to greater matrix porosity or natural fracturing. Recent regulatory changes
have  improved  the  economics  of  multi-zone   production  by  providing  the
opportunity  to commingle  multiple zones within a single  wellbore.  The south
western portion of this region also contains significant  Foothills assets with
natural gas produced from the deep  Mississippian and Triassic aged reservoirs.
In 2006 Canadian Natural had significant  success in this Foothills region with
drilling successes at Copton, Dinosaur and Cabin Creek.

Natural gas production  from the region averaged 454 mmcf/d in 2006 compared to
an average of 403.4 mmcf/d in 2005. Crude oil and NGLs production  increased to
15.0 thousand bbl/d in 2006 from 13.5 thousand bbl/d in 2005.

During 2006, the Company drilled 14.5  (2005-12.9)  net crude oil wells,  152.8
(2005-152.4) net natural gas wells, 0.0 (2005 - 0.7) net  stratigraphic/service
wells,  and 24.1  (2005-16.3)  net dry wells on its lands in this  region for a
total of 191.4  (2005-182.3) net wells. The Company held an average 72 per cent
working interest in these wells.

NORTHERN PLAINS

                            [GRAPHIC OMITTED - MAP]

<PAGE>
                                      26


The Company holds working interests ranging up to 100 per cent and averaging 83
per  cent  in  12,781,313  gross   (10,711,563  net)  acres  of  producing  and
undeveloped  land in the region  located  just south of Edmonton  north to Fort
McMurray  and  from  the  Northwest  Alberta  area  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 437 mmcf/d in 2006  compared to 419.2  mmcf/d in
2005.  Crude  oil and NGLs  production  from  this  region  increased  to 194.5
thousand bbl/d in 2006 from 181.8 thousand bbl/d in 2005. 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.

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  Horseshoe  Canyon CBM  project.  During  2006,
natural  gas  development  drilling  included  120.5  net  wells  and  48.0 net
Horseshoe  Canyon CBM locations.  Evaluation of the potential for production of
CBM from the  Mannville  coals  commenced  in 2006 with the  drilling  of three
horizontal  wells;  these wells will be tested and  produced to  determine  the
economic viability of this play.

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.

The Company's  holdings in this region of primary heavy oil production are both
the result of Crown land  purchases and several  acquisitions  including  major
acquisitions  from  Sceptre  Resources,   Koch  Exploration,   Ranger  Oil  and
Petrovera. 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
and to the Morgan field in 2006 enhancing  development  and reducing  operating
costs for 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

<PAGE>
                                      27


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 heavy  (10(Degree)-11(Degree)API)  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.  Since  acquiring  the assets  from BP Amoco in 2000,  the  Company has
successfully  converted the field from  low-pressure  steaming to high-pressure
steaming.  This  conversion  resulted  in a  significant  improvement  in  well
productivity  and  in  ultimate  oil  recovery.  Canadian  Natural  drilled  58
high-pressure  wells in 2004. In 2004, the Company  started to proceed with its
Primrose North expansion project,  which was effectively completed in late 2005
with total capital  expenditures of approximately  $300 million  incurred.  The
Primrose  North  expansion  entails  a remote  steam  generation  facility  and
additional  high pressure  cyclic steam 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 for Primrose East 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 received regulatory approval for the project in
February,  2007 and  construction  will  begin in 2007,  with the  first  steam
injection  scheduled for first quarter 2009. A mature 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. In December 2006 Canadian Natural issued a
Public Disclosure  Document outlining our proposed  development plan for the 30
thousand  bbl/d Kirby In-Situ Oil Sands  Project  located  approximately  85 km
northeast of Lac La Biche. Regulatory applications for the project are expected
to be submitted in late 2007.

In 2006 the Company  undertook a Scoping Study to evaluate the  construction of
an  upgrader  to  process  the  Company's   Athabasca  and  Cold  Lake  thermal
production.  The study included evaluating the product alternatives,  location,
technology,  gasification and integration with existing assets.  The next steps
in this process would include a Design Base Memorandum  ("DBM") and Engineering
Design Specifications  ("EDS") which would be required to be completed prior to
construction  and  sanctioning  of the project by the Board of Directors of the
Company.  Based upon the results of the Scoping Study, which identified growing
concerns  relating to increased  environmental  costs for upgraders  located in
Canada,   inflationary   capital  cost   pressures  and  narrowing   heavy  oil
differentials  in  North  America,  the  Company  has,  at this  point in time,
deferred  the  DBM  and  EDS  pending  clarification  on  the  cost  of  future
environmental legislation and a more stable cost environment.

Included in the northern part of this region,  approximately 200 miles north of
Edmonton,  are the  Company's  holdings at Pelican Lake.  These assets  produce
crude oil from the Wabasca  formation with  gravities of  11(Degree)-17(Degree)

<PAGE>
                                      28


API.  Production  costs  are low due to the  absence  of sand  production,  its
associated  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 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.

It is estimated  this field  contains  approximately  four  billion  barrels of
original  crude oil in place but is only  expected to achieve  less than a five
percent  average  recovery  factor using  existing  primary  production  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 date
approximately  11% of the field has been  converted to  waterflood.  To further
enhance the expected  crude oil  recovery  from the  waterflood,  in the second
quarter of 2005,  the Company  initiated a five well polymer  flood pilot test.
Performance of the polymer flood pilot test has been  positive,  with crude oil
production rates from the three production wells increasing from  approximately
60 bbl/d in 2005 to over 500 bbl/d by December 2006.  These results have led to
the  commercial  expansion  of this EOR  technology  with 36  additional  wells
undergoing polymer flooding by year end 2006. Pelican Lake production  averaged
approximately 30 thousands bbl/d in 2006.

During  2006,  the  Company  drilled  484.0 (2005 - 536.1) net crude oil wells,
218.6  (2005  -  198.9)  net  natural  gas  wells,  206.9  (2005 -  108.9)  net
stratigraphic/service  wells,  and 64.3 (2005 - 63.4) net dry wells for a total
of 973.8 (2005 - 907.3) net wells.  The Company's  average working  interest in
these wells was 88.4 per cent.

SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN

                            [GRAPHIC OMITTED - MAP]


In the Southern Plains area, the Company holds interests  ranging up to 100 per
cent and  averaging 86 per cent in  2,147,945  gross  (1,838,811  net) acres of
producing and undeveloped land in the region,  principally located south of the
Northern  Plains area to the United States  border and  extending  into western
Saskatchewan.

<PAGE>
                                      29


Reserves of natural gas,  condensate  and light 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.  It is economic to drill  shallow wells with reduced well
spacings in this region  despite  having  smaller  overall  reserves  and lower
productivity per well since they achieve a favourable rate of return on capital
employed  with  low  drilling  costs  and long  life  reserves.  The  Company's
extensive  shallow gas assets in this region have been  augmented  in 2006 as a
result  of the  Company's  development  of the  Senate  shallow  gas play in SW
Saskatchewan  and the  purchase  of the ACC Hatton  assets in SW  Saskatchewan.
Other assets  acquired from ACC in this region  include the crude oil producing
assets at Taber.

The Company maintains a large inventory of drillable locations on its land base
in this  region.  This region is one of the more mature  regions 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 10.5
thousand  bbl/d of crude oil and NGLs compared to 10.7 thousand  bbl/d in 2005.
Natural gas  production  amounted  to 165 mmcf/d in 2006  compared to the 155.4
mmcf/d averaged in 2005.

During  2006,  the  Company  drilled  a total of 6.2 (2005 - 9.0) net crude oil
wells,  104.2  (2005 - 336.5)  net  natural  gas  wells,  0.0  (2005 - 1.7) net
stratigraphic/service  wells and 9.4 (2005 - 7.0) net dry wells in this  region
for a total of 119.8 (2005 - 354.2) net wells.  The Company's  average  working
interest in these wells was 57.3 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  82 per  cent in  220,266  gross  (181,691  net)  acres of
producing and undeveloped lands in the region.

The  region  produces  primarily  light  sour  crude  oil from as many as seven
productive  horizons found at depths up to 2,700 meters. The Company's share of
production in the Southeast Saskatchewan area averaged 8,400 bbl/d of crude oil
and NGLs in 2006  compared  to 8,800  bbl/d in  2005.  Natural  gas  production
averaged 3 mmcf/d in 2006 (2005 - 3.1 mmcf/d).

The Company  drilled  72.7 (2005 - 43.0) net crude oil wells,  0.0 (2005 - 1.0)
net natural gas well, 0.0 (2005 - 7.6) net stratigraphic/service  wells and 2.0
(2005 - 0.0) net dry wells in this region in 2006,  for a total of 74.7 (2005 -
51.6) net wells. The Company's  average working interest in these wells is 86.9
per cent.

<PAGE>
                                      30


HORIZON OIL SANDS PROJECT

                            [GRAPHIC OMITTED - MAP]


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 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 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 is
planned to 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.  Subsequent
expansion  is expected to increase  production  to 232  thousand  bbl/d of SCO.
These  targeted rates of production  represent  nominal  design  capacity.  The
Company is currently evaluating the opportunity to combine Phase 2 and Phase 3,
for which certain  major items were ordered in 2006 and certain major  facility
components had  construction  commence on them in 2006.  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.

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.

The Company is  concurrently  working with  legislators  and  regulators on the
design of new greenhouse gas emission laws and  regulations  and is pursuing an
integrated  emissions  reduction  strategy,  to ensure  the  Company is able to
comply with existing and future emission reductions  requirements.  The Company
continues to develop  strategies that will enable it to deal with the risks and
opportunities  associated with new climate change  policies.  In addition,  the
Company is working with relevant parties to ensure that new policies  encourage

<PAGE>
                                      31


innovation,  energy  efficiency,  targeted  research and development  while not
impacting competitiveness.

The Company continues to work with Canadian Federal and Provincial  governments
on the  regulatory  framework for  greenhouse  gases for larger  emitters.  The
Company is actively promoting a harmonized regulatory framework between the two
levels of  government.  Both levels of government  have indicated that existing
legislation  will be  amended  in  2007  to  create  further  requirements  for
reporting emissions,  facility-based  emission intensity targets and regulatory
compliance. Compliance with emission intensity targets is expected for 2008 and
possibly a part of 2007 for larger facilities in Alberta.

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 Company is now  developing  various  cost  effective
options for execution of additional  construction on Phase 2 and Phase 3 of the
Horizon Project taking into account the current business environment.

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  production  costs.  By the end of 2004 the Company had
acquired  all key  technologies  for the  project.  At year end 2006,  Canadian
Natural's  Horizon  Project  team,  consisted of 705  permanent  employees  and
several  interim  contractors  to  fill  79% of  the  projected  team  position
requirements.

Horizon Project Phase 1 construction costs were approximately  $2.77 billion in
2006 and cumulative  expenditures were  approximately  $4.0 billion through the
end of 2006.  Construction  costs  for 2007 are  budgeted  to range  from  $2.4
billion to $2.8 billion reflecting major expenditures for detailed engineering,
procurement and  construction of Phase 1 of the Project.  In addition,  capital
expenditures  of $109 million are budgeted for Phase 2 and Phase 3  development
and construction in 2007. These  expenditures are direct project costs only and
do  not  include  capitalized   interest,   stock  based  compensation,   lease
evaluation, or Front End Engineering.

During 2006, the Company drilled 163.0 (2005 - 126.0)  stratigraphic test wells
to further delineate the ore body and confirm resource quality and quantity.

<PAGE>
                                      32


UNITED KINGDOM NORTH SEA

                           [GRAPHIC OMITTED - MAPS]


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 367,251 gross  (296,658  net) acres of producing and  non-producing
properties  in the UK sector of the North Sea. In 2006,  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  resulted in lower combined  production costs from these
fields.

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

<PAGE>
                                      33


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 2006,  production to the Company from this region averaged 60.1 thousand
bbl/d of  crude  oil  (2005 - 68.6  thousand  bbl/d).  Natural  gas  production
averaged 15.0 mmcf/d in 2006 (2005 - 18.4 mmcf/d).

During  2006 the  Company  drilled  7.4 (2005 - 11.5) net crude oil wells,  1.8
(2005 - 0.9) net stratigraphic/service wells and 0.0 (2005 - 1.7) net dry wells
in this  region  for a total of 9.2  (2005 - 14.1)  net  wells.  The  Company's
average working interest in these wells is 92.0 per cent.

OFFSHORE WEST AFRICA

                            [GRAPHIC OMITTED - MAP]


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.  As a result,  the Company  owned  working  interests
ranging from 50 per cent to 100 per cent in 1,596,013 gross (887,657 net) acres
in those countries. During 2005, the Company either relinquished or sold all of
its interests in offshore Angola. In 2006, certain  exploration acreage in Cote
d'Ivoire was also relinquished.

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.

COTE D'IVOIRE

The Company owns interests in two exploration  licences  offshore Cote d'Ivoire
comprising 55,408 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

<PAGE>
                                      34


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 included 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.  Due to a  successful  infill  drilling
program  completed  at East  Espoir in early  2006 the  Company  achieved  24.0
thousand bbl/d of net production from the Field.  Following the infill drilling
at East Espoir,  development  drilling  commenced at West Espoir with first oil
from the Field delivered July, 2006.

Crude oil from the East and West Espoir  Fields is produced to an FPSO with the
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 increased as expected.
Subsequent problems with the control of sand and solids production lead to five
of the ten production wells being shut in by the end of the year,  resulting in
approximately 15.5 thousand bbl/d of net production capacity being shut in. The
Company  does not plan to  complete  these wells until such time as a deepwater
rig can be secured on commercially acceptable terms.

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 2006, Company production averaged 36.7 thousand bbl/d of crude oil (2005
- 22.9 thousand bbl/d).  Company natural gas production  amounted to 9.5 mmcf/d
in 2006 (2005 - 4.2 mmcf/d).

In 2006, the Company drilled 4.1 (2005 - 3.5) net crude oil wells,  1.7 (2005 -
1.1) net  stratigraphic/service  wells and 0.0 (2005 - 0.6) net dry wells for a
total of 5.8 (2005 - 5.2) net wells. The Company's  average working interest in
these wells is 58.7 per cent.

ANGOLA

During  2002,  the Company was awarded  operatorship  and a 50 per cent working
interest in  exploration  Block 16 situated  offshore The People's  Republic of
Angola. 3-D seismic 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 had a two well commitment over a four
year time frame expiring August 31, 2006. The first well, Zenza-1,  was drilled

<PAGE>
                                      35


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 indicated
that significant upside remained a possibility,  the risk level associated with
Block 16 was 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 - MAP]


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.  Based on estimates  from the previous  owner it was estimated  that the
properties  held 500 million  barrels of  original  oil in place and 1 trillion
cubic feet of original gas in place. Subsequent to acquiring the assets and all
technical  data, the Company  performed a detailed  analysis on the geological,
geophysical  and  engineering  data  and has  reestimated  the pool  size.  The
Company's  internal  estimates  for Olowi are that the pool  contains up to 215
million  barrels  of 34(0)  API light  crude  original  oil in  place,  with an
underlying  gas cap  containing up to 590 billion 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  plan for the pool commenced in late 2006 and first  production
is targeted for late 2008.



<PAGE>
                                      36


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

For the year ended  December  31, 2006,  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 as well as 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  (i) the  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;  and, (ii) the definition
of proved  reserves used by the SEC to that of NI 51-101.  However with respect
to the definition of proved reserves,  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
should not be 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.

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, 2006.

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

<PAGE>
                                      37


<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                                           887                1,502              3,703               4,855

United States                                      -                    -                  2                   2

INTERNATIONAL

United Kingdom                                   299                  422                 37                  93

Cote d'Ivoire                                    115                  173                 56                  99

Gabon                                             15                   22                  -                   -
                                      -------------------------------------    -----------------------------------
                                      -------------------------------------    -----------------------------------
TOTAL                                          1,316                2,119              3,798               5,049
                                      =====================================    ===================================
</TABLE>

<TABLE>
<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                          779                697                3,619            2,963

Proved undeveloped reserves                        708                619                  994              835
                                      -------------------------------------   -----------------------------------

TOTAL PROVED RESERVES                            1,487              1,316                4,613            3,798

TOTAL PROVED AND PROBABLE
RESERVES                                         2,397              2,119                6,112            5,049
                                      =====================================   ===================================

<CAPTION>
ESTIMATED NET PRESENT VALUES

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

                                          Undiscounted                            Discounted at

                                                                        10%             15%            20%
                                      ----------------------     ------------------------------------------------

<S>                                                <C>                    <C>            <C>            <C>
Proved developed reserves                          31,286                 20,028         17,296         15,321

Proved undeveloped reserves                        17,974                  7,469          5,247          3,787
                                      ----------------------     -----------------  ------------   ------------
TOTAL PROVED RESERVES                              49,260                 27,497         22,543         19,108

TOTAL    PROVED   AND   PROBABLE
RESERVES                                           75,787                 37,291         29,350         24,102
                                      ======================     =================  ============   ============
</TABLE>


<PAGE>
                                      38


<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                         771                698                3,643            2,982

Proved undeveloped reserves                       706                633                  994              831
                                      -------------------     --------------       ------------     ------------
TOTAL PROVED RESERVES                           1,477              1,331                4,637            3,813

TOTAL    PROVED   AND   PROBABLE
RESERVES                                        2,540              2,294                6,141            5,067
                                      ===================     ==============       ============     ============


ESTIMATED NET PRESENT VALUES

         ($ millions)                                         Forecast Prices and Costs
                                      ---------------------------------------------------------------------------
                                          Undiscounted                            Discounted at

                                                                        10%             15%            20%
                                      ----------------------     ------------------------------------------------
Proved developed reserves                          33,483                 21,734          18,975        16,973

Proved undeveloped reserves                        17,446                  7,410           5,267         3,856
                                      ----------------------     -----------------  -------------   ------------
TOTAL PROVED RESERVES                              50,929                 29,144          24,242        20,829

TOTAL    PROVED   AND   PROBABLE
RESERVES                                           78,155                 38,896          30,883        25,604
                                      ======================     =================  =============   ============
</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 using forecast
      prices and costs as well as before  royalties  and their  associated  net
      present values 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 using forecast prices and costs as well as before
      royalties and their associated net present values 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 using forecast  prices and costs
      as well as before  royalties and their  associated  net present values 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  using both constant  prices and costs as well as
      forecast  prices  and costs and has  disclosed  these  before  and net of
      royalties and their  associated net present values.  The calculation of a
      probable  reserves and value component by subtracting the proved reserves
      from the proved plus probable reserves may be subject to immaterial error
      due to the  different  standards  applied  in the  determination  of each
      value.

7.    Canadian  securities  legislation and policies permit the disclosure,  of
      probable  reserves  which may not be disclosed in reports  filed with the
      SEC by United States companies.  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>
                                      39


9.    The  constant  price  and cost  case  assumes  that  prices  in effect at
      year-end 2006 adjusted for quality and transportation as well as the 2006
      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 2007 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   (based  on  a  foreign   exchange   rate  of
      US$0.860/C$1.00):

<TABLE>
<CAPTION>
                                  NATURAL GAS                                     CRUDE OIL & NGLs
              --------------------------------------------------  ----------------------------------------------
               Company                                             Company            Hardisty  Edmonton  North
               Average  Henry Hub                    Huntingdon/   Average   WTI @      Heavy    Par(ii)    Sea
               Price    Louisiana       AECO           Sumas       Price  Cushing(i) 12(degree)   API      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>
      2007      6.07      5.52           6.13            6.52       51.11     61.05     41.94     67.59    58.93
</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.

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, 2006 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 2006 were  $51.11 per barrel and $6.07 per
      mcf respectively,  before  adjustments due to hedging.  The crude oil and
      natural  gas  forecast  prices  used  in the  Evaluation  Reports  are as
      follows:
<TABLE>
<CAPTION>
      ------------------------------------------------------------------------------------------------------------
                                   NATURAL GAS                                      CRUDE OIL & NGLs
          ---------------------------------------------------  ---------------------------------------------------
               Company                                             Company            Hardisty  Edmonton  North
               Average  Henry Hub                    Huntingdon/   Average   WTI @      Heavy    Par(ii)    Sea
               Price    Louisiana       AECO           Sumas       Price  Cushing(i) 12(degree)   API      Brent
      YEAR     C$/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>
      2007      7.57        7.85         7.72           7.48        53.95     65.73     42.98     74.10     63.73
      2008      8.45        8.39         8.59           8.45        56.07     68.82     45.02     77.62     66.78
      2009      7.58        7.65         7.74           7.60        52.36     62.42     40.74     70.25     60.34
      2010      7.35        7.48         7.55           7.41        48.60     58.37     38.03     65.56     56.24
      2011      7.49        7.63         7.72           7.58        45.62     55.20     35.90     61.90     53.04
      2012      7.64        7.75         7.85           7.71        47.26     56.31     36.63     63.15     54.10
      2013      7.80        7.86         7.99           7.85        47.45     57.43     37.36     64.42     55.18
      2014      7.97        7.98         8.12           7.98        48.75     58.58     38.12     65.72     56.29
      2015      8.13        8.10         8.26           8.12        49.55     59.75     38.88     67.04     57.41
      2016      8.27        8.22         8.40           8.26        48.95     60.95     39.67     68.39     58.56
      2017      8.43        8.34         8.54           8.40        50.25     62.17     40.46     69.76     59.73
</TABLE>
         (i)   Foreign exchange rate used was US$0.870/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.

<PAGE>
                                      40


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)
                  ------------          ------------              ------------            ------------
<S>                    <C>                    <C>                     <C>                      <C>
2007                   1,781                  1,783                   2,138                    2,097
2008                   1,555                  1,615                   2,275                    2,040
2009                   1,819                  1,718                   2,561                    2,054
2010                     915                    841                   2,096                    1,479
2011                     838                    745                   1,764                    1,294
2012                     420                    370                     630                      549
2013                     281                    251                     601                      510
2014                     344                    299                     709                      603
2015                     197                    172                     602                      500
2016                     193                    168                     418                      341
2017                     115                    102                     346                      220
2018                     215                    180                     424                      332
Thereafter             1,143                    919                   2,317                    1,694
</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 Schedule "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>
                                      41


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, 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
                              ----------------------------------------------- ------------------------------------------------
Extensions & Discoveries              53           3           -          56          250           -           -         250
Infill Drilling                      190          14           -         204           71           -           -          71
Improved Recovery                      -          12           -          12            3           -           -           3
Property purchases                    26           -           -          26        1,111           -           -       1,111
Property disposals                     -           -           -           -          (1)           -           -         (1)
Production                           (75)        (22)        (13)       (110)        (433)         (5)         (3)       (441)
Revisions of prior estimates         (1)           2           9          10          (37)         13         (13)        (37)
                              ----------------------------------------------- ------------------------------------------------
RESERVES, DECEMBER 31, 2006          887         299         130       1,316        3,705          37          56       3,798
                              ----------------------------------------------- ------------------------------------------------
PROVED AND PROBABLE RESERVES
                              ----------------------------------------------- ------------------------------------------------
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
                              ----------------------------------------------- ------------------------------------------------
Extensions & Discoveries             128           3           -         131          307           -           -         307
Infill Drilling                      384          17           -         401           95           -           -          95
Improved Recovery                      -          12           -          12            4           -           -           4
Property purchases                    34           -           -          34        1,466           -           -       1,466
Property disposals                     -           -           -           -           (1)          -           -          (1)
Production                           (75)        (22)        (13)       (110)        (433)         (5)         (3)       (441)
Revisions of prior estimates          (4)         (5)          2          (7)        (129)         29          (8)       (108)
                              ----------------------------------------------- ------------------------------------------------
RESERVES, DECEMBER 31, 2006        1,502         422         195       2,119        4,857          93          99       5,049
                              ----------------------------------------------- ------------------------------------------------
</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 Form 40-F filed with
the SEC and in the Company's  2006 Annual Report under  "Supplementary  Oil and
Gas Information" on pages 99 to 103 and is incorporated herein by reference.

<PAGE>
                                      42


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 and is
targeted to to reach 232 thousand  bbl/d with future  expansion.  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.

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
lease proved and probable reserves  associated with the Horizon Project are 3.0
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>
                                      43


FIGURE 1 - LOCATION OF THE HORIZON OIL SANDS PROJECT

                           [GRAPHIC OMITTED - MAPS]

TABLE 1 - CANADIAN NATURAL ATHABASCA REGION OIL SAND LEASES

--------------------------------------------------------------------------------
 SHORT LEASE NAME       OFFICIAL LEASE                  LEASE           AREA IN
                            NUMBER                  EXPIRY DATE(1)      HECTARES
================================================================================
     Lease 18              727912T18                     Continued        19,988
                                                      Producing(2)
--------------------------------------------------------------------------------
     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
--------------------------------------------------------------------------------
(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>
                                      44


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
Alberta  Energy and  Utilities  Board  ("EUB"),  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>

                                      45

As of year-end 2006, key development achievements associated with the Horizon
Project were as follows:

      o   Phase 1 is 57 per cent complete.
      o   Mine  overburden  has  removed  25.1  million  bank  cubic  meters of
          material.
      o   Majority of foundations are complete.
      o   Main Piperack on site and set.
      o   Coke drums transported and erected.
      o   Hydrotreating reactors erected.

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 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 five meters.  Locally,  this member may be entirely
eroded.  Exceptional thickness of about 15 meters can be found within the upper

<PAGE>
                                      46


McMurray.  In most cases, the bitumen  saturation in the upper McMurray is poor
and the material is included with the overburden.

FIGURE 2 - GENERAL STRATIGRAPHY OF THE HORIZON OIL SANDS PROJECT

                               [GRAPHIC OMITTED]


HORIZON OIL SANDS PROJECT MINING RESERVES

For the year ended December 31, 2006, 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, NGLs and natural gas reserves.

The pit limits and mine plans were  updated in 2006  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 3.0  billion  barrels of gross
lease 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>
                                      47


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

                          [GRAPHIC OMITTED - PLOT MAP]




<PAGE>
                                      48


FIGURE 4 - HORIZON OIL SANDS PROJECT CORE HOLE COVERAGE

                          [GRAPHIC OMITTED - PLOT MAP]


<PAGE>
                                      49


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, 2006:

<TABLE>
<CAPTION>
                                                                            Constant Prices
                                           -----------------------------------------------------------------------------
                                                      Bitumen (mmbbl)              Synthetic Crude Oil (1) (mmbbl)
                                              Gross Lease (2)               Net       Gross Lease (2)                Net
                                           ------------------------------------    -------------------------------------
<S>                                                    <C>                <C>                   <C>                <C>
Total proved reserves                                  2,275              1,853                 1,866              1,596
Total proved and probable reserves                     3,530              2,872                 2,962              2,542
</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 Lease reserves are the total  remaining  recoverable  reserves on the
    Lease 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
                                                       -------------------------------------------------------
                                                             2006                 2005                 2004
                                                             ----                 ----                 ----
        <S>                                                <C>                  <C>                  <C>
        Daily Production, before royalties
             Crude Oil and NGLs (bbl/d)                    331,998              313,168              282,489
             Natural Gas (mmcf/d)                            1,492                1,439                1,388
        Annual Production, before royalties
             Crude Oil and NGLs (mbbl)                     121,179              114,306              103,391
             Natural Gas (bcf)                                 545                  525                  508
</TABLE>

<PAGE>
                                      50


<TABLE>
<CAPTION>
NETBACKS
INFORMATION BY QUARTER

                                             YEAR 2006                                       YEAR 2005
                             -----------------------------------------       ------------------------------------------
                             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)                323,662  338,852 321,665  343,705  331,998      287,803  289,064  334,724  340,268  313,168

     Natural Gas (mcf/d)      1,436    1,475   1,437    1,620    1,492        1,455    1,454    1,423    1,423    1,439

PRODUCT NETBACKS
Crude oil and NGLs ($/bbl)
     Sales Price (1)          43.79    60.05   62.55    47.27    53.65      $ 39.81  $ 42.51  $ 57.35  $ 46.38  $ 46.86
     Royalties                 3.48     5.14    5.11     4.10     4.48      $  3.39  $  3.33  $  5.11  $  3.89  $  3.97
     Production Expenses      11.33    11.92   13.47    12.32    12.29      $ 11.30  $ 11.66  $ 11.48  $ 10.33  $ 11.17
     NETBACK                  28.98    42.99   43.97    30.85    36.88      $ 25.12  $ 27.52  $ 40.76  $ 32.16  $ 31.72

Natural Gas ($mcf)
     Sales Price (1)           8.30     6.16    5.83     6.66     6.72      $  6.68  $ 7.33   $ 8.61   $ 11.67  $  8.57
     Royalties                 1.70     1.11    1.11     1.26     1.29      $  1.30  $ 1.48   $ 1.93   $  2.30  $  1.75
     Production Expenses       0.80     0.80    0.84     0.86     0.82      $  0.69  $ 0.71   $ 0.76   $  0.76  $  0.73
     NETBACK                   5.80     4.25    3.88     4.54     4.61      $  4.69  $ 5.14   $ 5.92   $  8.61  $  6.09


Light/Pelican Lake/NGLs
($/bbl)
     Sales Price (1)          58.28    69.02   71.65    57.68    64.33      $ 53.14  $ 56.85  $ 66.81  $ 58.87  $ 59.16
     Royalties                 4.65     5.53    5.39     4.39     5.00      $  5.20  $  4.55  $  5.50  $  4.40  $  4.90
     Production Expenses      11.15    11.18   14.12    12.99    12.42      $ 11.58  $ 12.28  $ 11.47  $ 8.90   $ 10.93
     NETBACK                  42.48    52.31   52.14    40.30    46.91      $ 36.36  $ 40.02  $ 49.84  $ 45.57  $ 43.33

Heavy  Crude Oil ($/bbl)
     Sales Price (1)          25.22    50.08   51.38    36.11    41.20      $ 25.21  $ 27.82  $ 47.25  $ 30.27  $ 33.09
     Royalties                 1.98     4.71    4.76     3.78     3.88      $  1.41  $  2.07  $  4.83  $  3.08  $  2.92
     Production Expenses      11.55    12.73   12.67    11.60    12.15      $ 11.00  $ 11.03  $ 11.50  $ 12.18  $ 11.44
     NETBACK                  11.69    32.64   33.95    20.73    25.17      $ 12.80  $ 14.72  $ 30.92  $ 15.01  $ 18.73
</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)  NET OF  TRANSPORTATION  AND BLENDING COSTS AND EXCLUDING  RISK  MANAGEMENT
     ACTIVITIES.

<PAGE>
                                      51

<TABLE>
<CAPTION>
NETBACKS
INFORMATION BY QUARTER

                                                                    YEAR 2004
                                              -------------------------------------------------------
                                                  1ST        2ND        3RD         4TH         YEAR
                                                QUARTER    QUARTER    QUARTER     QUARTER      ENDED
                                                -------    -------    -------     -------      -----
<S>                                             <C>        <C>        <C>         <C>        <C>
Average Daily Production Volumes

     Crude oil and NGLs (bbl/d)                 261,286    275,398    297,262     295,704    282,489

     Natural Gas (mcf/d)                          1,294      1,452      1,396       1,410      1,388

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

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

CRUDE OIL AND NGLS NETBACKS BY TYPE
Light/Pelican Lake/NGLs ($/bbl)
     Sales Price (1)                            $ 40.75    $ 45.28    $ 51.54     $ 48.60    $ 46.71
     Royalties                                  $  3.71    $  3.98    $  3.99     $  4.12    $  3.95
     Production Expenses                        $  9.77    $ 10.36    $ 10.70     $ 11.20    $ 10.53
     NETBACK                                    $ 27.27    $ 30.94    $ 36.85     $ 33.28    $ 32.23

Heavy Crude Oil ($/bbl)
     Sales Price (1)                            $ 27.00    $ 28.08    $ 35.33     $ 25.16    $ 28.99
     Royalties                                  $  2.02    $  2.31    $  3.18     $  1.77    $  2.34
     Production Expenses                        $  9.38    $  9.47    $  9.72     $  9.62    $  9.56
     NETBACK                                    $ 15.60    $ 16.30    $ 22.43     $ 13.77    $ 17.09
</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)  NET OF  TRANSPORTATION  AND BLENDING COSTS AND EXCLUDING  RISK  MANAGEMENT
     ACTIVITIES.

<PAGE>
                                      52

<TABLE>
<CAPTION>
NETBACKS
INFORMATION BY QUARTER

                                             YEAR 2006                                       YEAR 2005
                             -----------------------------------------       ------------------------------------------
                             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)           $48.83   $64.35   $65.15  $48.47   $56.52       $45.80   $49.78   $61.21   $52.10   $52.35
   Royalties                 $ 8.98   $10.87   $10.86  $ 7.80   $ 9.59       $10.64   $ 8.77   $11.49   $ 9.62   $10.13
   Production Expenses       $ 9.86   $ 9.75   $10.81  $13.18   $10.93       $ 8.30   $ 8.40   $ 9.27   $ 8.60   $ 8.65
   NETBACK                   $29.99   $43.73   $43.48  $27.49   $36.00       $26.86   $32.61   $40.45   $33.88   $33.57

Heavy Crude Oil ($/bbl)
   Sales Price (1)           $25.22   $50.08   $51.38  $36.11   $41.20       $25.21   $27.82   $47.25   $30.27   $33.09
   Royalties                 $ 1.98   $ 4.71   $ 4.76  $ 3.78   $ 3.88       $ 1.41   $ 2.07   $ 4.83   $ 3.08   $ 2.92
   Production Expenses       $11.55   $12.73   $12.67  $11.60   $12.15       $11.00   $11.03   $11.50   $12.18   $11.44
   NETBACK                   $11.69   $32.64   $33.95  $20.73   $25.17       $12.80   $14.72   $30.92   $15.01   $18.73

Natural Gas ($/mcf)
   Sales Price (1)           $ 8.39   $ 6.21   $ 5.86  $ 6.70   $ 6.77       $ 6.73   $ 7.38   $ 8.69   $11.79   $ 8.65
   Royalties                 $ 1.73   $ 1.13   $ 1.12  $ 1.29   $ 1.31       $ 1.33   $ 1.50   $ 1.96   $ 2.34   $ 1.78
   Production Expenses       $ 0.79   $ 0.79   $ 0.83  $ 0.84   $ 0.81       $ 0.66   $ 0.68   $ 0.74   $ 0.74   $ 0.71
   NETBACK                   $ 5.87   $ 4.29   $ 3.91  $ 4.57   $ 4.65       $ 4.74   $ 5.20   $ 5.99   $ 8.71   $ 6.16

NORTH SEA PRODUCT NETBACKS
Light Crude Oil ($/bbl)
   Sales Price (1)           $68.05   $73.19   $78.68  $67.72   $72.62       $59.56   $64.81   $74.46   $66.88   $66.57
   Royalties                 $ 0.12   $ 0.17   $ 0.11  $ 0.14   $ 0.13       $ 0.05   $ 0.11   $ 0.12   $ 0.14   $ 0.10
   Production Expenses       $16.85   $17.18   $20.28  $14.76   $17.57       $14.91   $17.41   $15.15   $12.11   $14.94
   NETBACK                   $51.08   $55.84   $58.29  $52.82   $54.92       $44.60   $47.29   $59.19   $54.63   $51.53

Natural Gas ($/mcf)
   Sales Price (1)           $ 2.38   $ 2.33   $ 2.38  $ 3.48   $ 2.66       $ 3.52   $ 3.07   $ 2.64   $ 3.40   $ 3.17
   Royalties                 $    -   $    -   $    -  $    -   $    -       $    -   $    -   $    -   $    -   $    -
   Production Expenses       $ 1.26   $ 1.47   $ 1.30  $ 1.54   $ 1.40       $ 2.52   $ 2.92   $ 2.30   $ 1.96   $ 2.44
   NETBACK                   $ 1.12   $ 0.86   $ 1.08  $ 1.94   $ 1.26       $ 1.00   $ 0.15   $ 0.34   $ 1.44   $ 0.73

OFFSHORE WEST AFRICA PRODUCT NETBACKS
Light Crude Oil ($/bbl)
   Sales Price (1)           $65.23   $72.97   $70.59  $63.50   $67.99       $62.34   $58.24   $59.09   $60.19   $59.91
   Royalties                 $ 1.55   $ 1.87   $ 4.89  $ 3.02   $ 2.81       $ 1.90   $ 1.81   $ 1.54   $ 1.57   $ 1.62
   Production Expenses       $ 6.08   $ 5.61   $ 7.97  $10.05   $ 7.45       $11.43   $ 8.47   $ 5.81   $ 5.62   $ 6.50
   NETBACK                   $57.60   $65.49   $57.73  $50.43   $57.73       $49.01   $47.96   $51.74   $53.00   $51.79

Natural Gas ($/mcf)
   Sales Price (1)           $ 5.59   $ 5.30   $ 4.97  $ 5.72   $ 5.37       $ 7.67   $ 6.88   $ 5.52   $ 5.13   $ 5.91
   Royalties                 $ 0.13   $ 0.14   $ 0.34  $ 0.27   $ 0.22       $ 0.23   $ 0.21   $ 0.13   $ 0.14   $ 0.16
   Production Expenses       $ 1.00   $ 0.36   $ 1.39  $ 2.01   $ 1.19       $ 1.25   $ 1.37   $ 1.09   $ 0.80   $ 1.05
   NETBACK                   $ 4.46   $ 4.80   $ 3.24  $ 3.44   $ 3.96       $ 6.19   $ 5.30   $ 4.30   $ 4.19   $ 4.70
</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)  NET OF  TRANSPORTATION  AND BLENDING COSTS AND EXCLUDING  RISK  MANAGEMENT
     ACTIVITIES.

<PAGE>
                                      53

<TABLE>
<CAPTION>
NETBACKS
INFORMATION BY QUARTER

                                                                        YEAR 2004
                                             --------------------------------------------------------------
                                                1ST           2ND          3RD           4TH          YEAR
                                              QUARTER       QUARTER      QUARTER       QUARTER       ENDED
                                              -------       -------      -------       -------       -----
<S>                                             <C>         <C>          <C>           <C>         <C>
SEGMENTED
NORTH AMERICA PRODUCT NETBACKS
Light/Pelican Lake/NGLs ($/bbl)
      Sales Price (1)                           $37.54      $ 41.03      $  44.89      $ 43.80     $ 41.81
      Royalties                                 $ 7.20      $  7.91      $   8.59      $  8.76     $  8.12
      Production Expenses                       $ 7.30      $  7.74      $   7.75      $  7.85     $  7.66
      NETBACK                                   $23.04      $ 25.38      $  28.55      $ 27.19     $ 26.03

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

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

NORTH SEA PRODUCT NETBACKS
Light Crude oil ($/bbl)
      Sales Price (1)                           $44.27      $ 49.22      $  57.39      $ 52.77     $ 51.37
      Royalties                                 $ 0.06      $  0.10      $   0.09      $  0.08     $  0.08
      Production Expenses                       $13.26      $ 13.84      $  13.88      $ 14.96     $ 14.03
      NETBACK                                   $30.95      $ 35.28      $  43.42      $ 37.73     $ 37.26

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

OFFSHORE WEST AFRICA PRODUCT NETBACKS
Light Crude oil ($/bbl)
      Sales Price (1)                           $42.08      $ 49.34      $  53.86      $ 51.28     $ 49.05
      Royalties                                 $ 1.28      $  1.52      $   1.42      $  1.52     $  1.43
      Production Expenses                       $ 7.09      $  7.43      $   8.05      $  7.82     $  7.59
      NETBACK                                   $33.71      $ 40.39      $  44.39      $ 41.94     $ 40.03

Natural Gas ($/mcf)
      Sales Price (1)                           $ 4.80      $  5.18      $   6.31      $  4.73     $  5.25
      Royalties                                 $ 0.15      $  0.16      $   0.17      $  0.14     $  0.15
      Production Expenses                       $ 1.23      $  1.38      $   1.39      $  1.31     $  1.33
      NETBACK                                   $ 3.42      $  3.64      $   4.75      $  3.28     $  3.77
</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)  NET OF  TRANSPORTATION  AND BLENDING COSTS AND EXCLUDING  RISK  MANAGEMENT
     ACTIVITIES..

<PAGE>



F.       HISTORICAL DRILLING ACTIVITY BY PRODUCT

The following table sets forth the gross and net wells  (excluding  service and
stratigraphic  test wells) in which the Company has participated for the period
indicated:

<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31
                                               ---------------------------------------------------------
                                                        2006                             2005
                                                  Gross          Net                Gross        Net
                                               ------------------------         ------------------------
      <S>                                          <C>         <C>                  <C>        <C>
      Natural Gas                                    855         641                1,071        890
      Crude Oil                                      666         603                  685        627
      Service/Stratigraphic                          376         375                  251        248
      Dry Holes                                      133         119                  136        117
                                               ------------------------         ------------------------
      Total                                        2,030       1,738                2,143      1,882
                                               ========================         ========================
      Total Success Rate                                         91%                             93%
</TABLE>



<PAGE>
                                      55


G.       NET 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. Net capital expenditures do
not include non-cash property, plant and equipment additions and disposals.

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31
                                                                       -------------------------------------
                                                                              2006                2005
                                                                       -------------------------------------
                                                                                  $millions
                  <S>                                                        <C>                 <C>
                  Net property acquisitions (dispositions)  (1)              4,733               (320)
                  Land acquisition and retention                               210                 254
                  Seismic evaluations                                          130                 132
                  Well drilling, completion and equipping                    2,340               2,000
                  Pipeline and production facilities                         1,314               1,295
                                                                       ----------------      ---------------

                  Reserve replacement expenditures                           8,727               3,361
                                                                       ----------------      ---------------
                  Horizon Project:
                     Phase 1 construction costs (2)                          2,768               1,249
                     Phase 2 and 3 costs                                        79                   -
                     Capitalized interest, stock based                         338                 250
                     compensation and other (2)
                                                                       ----------------      ---------------
                  Total Horizon Project                                      3,185               1,499
                                                                       ----------------      ---------------
                  Midstream                                                     12                   4
                  Abandonments (3)                                              75                  46
                  Head office                                                   26                  22
                                                                       ----------------      ---------------

                  Total Net Capital Expenditures                            12,025               4,932
                                                                       ================      ===============
</TABLE>



<PAGE>
                                      56


<TABLE>
<CAPTION>
                                                                     2006 THREE MONTHS ENDED
                                               ---------------------------------------------------------------------
                                                                           ($ millions)
CAPITAL EXPENDITURES
BY QUARTER                                         MAR. 31           JUNE 30          SEPT. 30          DEC. 31
                                                   -------           -------          --------          -------
<S>                                                  <C>                 <C>            <C>            <C>
Net property acquisitions (dispositions) (1)            12                  7              (6)            4,720

Land acquisition and retention                          99                 54               29               28

Seismic evaluation                                      52                 35               26               17

Well drilling, completion and equipping                936                418              524              462

Pipeline and production facilities                     500                233              270              311
                                                     -----              -----            -----            -----
Reserve replacement expenditures                     1,599                747              843            5,538

Horizon Project:

     Phase 1 construction costs (2)                    616                680              727              745

     Phase 2 and 3 costs                                 1                  6               18               54
     Capitalized interest, stock based
     compensation and other (2)                         69                 96               39              134
                                                     -----              -----            -----            -----
Total Horizon Project                                  686                782              784              933

Midstream                                                3                  6                2                1

Abandonments (3)                                        15                 17               24               19

Head office                                              6                  6                8                6
                                                     -----              -----            -----            -----
Total Net Capital Expenditures                       2,309              1,558            1,661            6,497
                                                     =====              =====            =====            =====
</TABLE>


<PAGE>
                                      57


<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 acquisitions (dispositions)(1)
                                                         2              (341)                -               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 (2)                    131                236              413              469
     Phase 2 and 3 costs                                 -                  -                -                -
     Capitalized interest, stock based
     compensation and other (2)                         84                 39               39               88
                                                     -----                ---            -----            -----
Total Horizon Project                                  215                275              452              557

Midstream                                                4                  -              (1)                1

Abandonments (3)                                         4                  7               19               16

Head office                                              4                  7                5                6
                                                     -----                ---            -----            -----
Total Net Capital Expenditures                       1,372                609            1,272            1,679
                                                     =====                ===            =====            =====
</TABLE>

(1) Includes Business Combinations

(2) Certain prior period amounts have been reclassified with respect to
    stock-based compensation costs.

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

<PAGE>
                                      58


H.       UNDEVELOPED ACREAGE

The following table summarizes the Company's  working interest holdings in core
region undeveloped acreage as at December 31, 2006:

                                                 GROSS ACRES          NET ACRES
                                                 -----------          ---------
                                                 (thousands)         (thousands)
                  NORTH AMERICA
                  Alberta                             11,298              9,363
                  British Columbia                     3,752              2,692
                  Saskatchewan                           787                719
                  Manitoba                                11                 11

                  NORTH SEA
                  United Kingdom                         367                299

                  OFFSHORE WEST AFRICA
                  Cote d'Ivoire                           95                 55
                  Gabon                                  152                152
                                                 --------------      -----------
                  Total                               16,462             13,291
                                                 ==============      ===========

I.       DEVELOPED ACREAGE

The following table summarizes the Company's working interest holdings in core
region developed acreage as at December 31, 2006:

                                                 GROSS ACRES          NET ACRES
                                                 -----------          ---------
                                                 (thousands)         (thousands)
                  NORTH AMERICA
                  Alberta                              6,398              5,078
                  British Columbia                     1,319                996
                  Saskatchewan                           340                287
                  Manitoba                                 5                  5

                  NORTH SEA
                  United Kingdom                         138                 93

                  OFFSHORE WEST AFRICA
                  Cote d'Ivoire                            7                  4
                                                 --------------      -----------
                  Total                                8,207              6,463
                                                 ==============      ===========


<PAGE>
                                      59


                         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
                                                             -----------------------------
                                                               2006                 2005
                                                               ----                 ----
                                                             ($ millions, except per share
                                                                      information)
<S>                                                           <C>                   <C>
Revenues (1) (net of  royalties)                              10,398                9,764

Cash flow from operations                                      4,932                5,021

Per common share - basic                                        9.18                 9.36

                 - diluted                                      9.18                 9.33

Net earnings                                                   2,524                1,050

Per common share - basic                                        4.70                 1.96

                 - diluted                                      4.70                 1.95

Total assets                                                  33,160               21,852

Total long-term debt                                          11,043                3,321
</TABLE>

<TABLE>
<CAPTION>
                                             ---------------------------------------------------------------------
                                                              2006 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)              2,352               2,739               2,798                2,509
Net earnings                                     57               1,038               1,116                  313

Per common share - basic                       0.11                1.93                2.08                 0.58

                 - diluted                     0.11                1.93                2.08                 0.58


                                             ---------------------------------------------------------------------
                                                              2005 THREE MONTHS ENDED
                                             ---------------------------------------------------------------------
                                             MARCH 31             JUNE 30            SEPT. 30              DEC. 31
                                             --------             -------            --------              -------
                                                     ($ millions, except per share information)

Revenues (1) (net of royalties)               1,969               2,137               2,760                2,898
Net (loss) earnings                           (424)                 219                 151                1,104

Per common share - basic                     (0.79)                0.41                0.28                 2.06

                 - diluted                   (0.79)                0.41                0.28                 2.06
</TABLE>

(1)  Blending  costs  previously  netted  against gross revenues in prior years
     have been reclassified to  transportation  and blending expense to conform
     to the presentation adopted in 2006..

<PAGE>
                                      60


                               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.

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 is rated "Baa2" with a stable outlook by Moody's Investors Service,
Inc. ("Moody's"),  "BBB" by Standard & Poor's Corporation ("S&P") with a stable
outlook and "BBB high" with a negative trend by DBRS.

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
Baa 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.

<PAGE>
                                      61


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 debt securities.  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 rating  trend is DBRS'  opinion  regarding  the  outlook for the
rating.

            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.

                     2006 Monthly Historical Trading on Toronto Stock Exchange

Month                  High           Low         Close         Volume Traded
January               $71.65        $57.75       $70.60            40,613,480
February               73.91         58.96        62.09            50,126,147
March                  68.93         61.75        64.90            43,747,239
April                  72.70         65.58        67.20            28,568,500
May                    69.37         54.39        58.00            52,879,861
June                   62.75         50.78        61.72            47,587,703
July                   62.60         54.59        60.10            31,911,426
August                 63.30         56.89        58.03            38,653,456
September              58.59         47.28        50.94            56,457,171
October                60.73         45.49        58.45            50,270,814
November               62.50         54.21        61.90            42,470,275
December               63.50         58.64        62.15            25,649,324

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

<PAGE>
                                      62


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
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.  Under this
program,   the  Company   purchased  a  total  of  485,000  common  shares  for
cancellation  at a weighted  average  purchase  price of $57.29 for each common
share purchased, $57.33 after costs.

On January 22,  2007,  the Company  announced  its  intention  to make a Normal
Course  Issuer  Bid  through  the  facilities  of TSE and the NYSE,  commencing
January 24, 2007 and ending January 23, 2008, to purchase for  cancellation  up
to 26,941,730 common shares of the Company, being 5 per cent of the 538,834,606
common shares of the Company outstanding on January 15, 2007. As of the date of
this Annual Information Form, no shares have been purchased under the program.

                                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.

                                                 2006       2005     2004
                                                 ----       ----     ----

   Cash dividends declared per common share      $0.30     $0.24     $0.20

<PAGE>
                                      63


                         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.

                             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 53)                  Financial Officer of the Calgary Health Region from 2002 to
Canada                                                   present;  Vice-President,   Corporate  Services  and  Chief
                                                         Financial   Officer  of  the  Calgary  Health  Region  from
                                                         February  2000 to 2002;  prior  thereto  with Ernst & Young
                                                         since 1980, most recently as a Corporate Audit Partner from
                                                         1991 to 2000. Has served  continuously as a director of the
                                                         Company since November 2003. Currently serving on the board
                                                         of directors of Enbridge Income Fund.

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 47)                  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 based
Winnipeg, Manitoba             (age 64)                  in Winnipeg,  Manitoba).  Prior thereto,  served as Premier
Canada                                                   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 MTS  Allstream  Inc.,
                                                         Pollard Banknote Income Fund,  Arctic Glacier Income Trust,
                                                         Exchange  Industrial  Income Fund,  Wellington West Capital
                                                         Inc. and FWS Construction Inc.

Ambassador Gordon D. Giffin    Director(1)(2)            Senior  Partner,  McKenna  Long &  Aldridge  LLP (law firm)
Atlanta, Georgia               (age 57)                  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,  Ontario  Energy  Savings  Corp.  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 61)

Steve W. Laut                  President and Chief       President and Chief Operating  Officer of the Company since
Calgary, Alberta               Operating Officer and     April  2005.   Prior  thereto   Executive   Vice-President,
Canada                         Director                  Operations  2001 to 2003 and most recently Chief  Operating
                               (age 49)                  Officer  2003  to  2005.  Has  served   continuously  as  a
                                                         director of the Company since August 2006.
</TABLE>

<PAGE>
                                      64

<TABLE>
<CAPTION>
                               POSITION                  PRINCIPAL
                               PRESENTLY                 OCCUPATION
NAME                           HELD                      DURING PAST 5 YEARS
<S>                            <C>                       <C>
Keith A.J. MacPhail            Director(3)(5)            Chairman,  President and Chief Executive Officer, Bonavista
Calgary, Alberta               (age 50)                  Petroleum Ltd. since November 1997 and Chairman,  President
Canada                                                   and Chief Executive  Officer of Bonavista  Energy Trust 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 61)                  director of the Company since January 1989.
Canada

Norman F. McIntyre             Director(3)(4)(5)         An  independent   businessman.   Prior  thereto   Executive
Calgary, Alberta               (age 61)                  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.

Frank J. McKenna               Director(1)(4)            Deputy  Chair,  TD  Bank  Financial  Group.  Prior  thereto
Cap Pele, New Brunswick        (age 59)                  Premier  of New  Brunswick  from 1987 to 1997;  Counsel  to
Canada                                                   Atlantic  Canada law firm McInnes Cooper from 1998 to 2005,
                                                         and most recently Canadian  Ambassador to the United States
                                                         from 2005 to 2006. He has served continuously as a director
                                                         of the Company since August 2006.  Currently serving on the
                                                         board of directors of  Brookfield  Asset  Management  Inc.;
                                                         and,   Perseus   Private   Equity  a  private  equity  fund
                                                         management company.

James S. Palmer, C.M., A. O.   Director(3)(4)(5)         Chairman  and a Partner of Burnet,  Duckworth  & Palmer LLP
E., Q.C.                       (age 78)                  (law firm).  Has served  continuously  as a director of the
Calgary, Alberta                                         Company since May 1997.
Canada                                                   Currently  serving on the board of  directors  of  Magellan
                                                         Aerospace  Corporation;  Rally Energy  Corp.;  and,  Energy
                                                         Resources Alberta.

Dr. Eldon R. Smith, OC, M.D.   Director(4)(5)            Emeritus  Professor  and Former Dean,  Faculty of Medicine,
Calgary, Alberta               (age 67)                  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.,  Sernova  Corp.;
                                                         and, Overlord Financial Inc.

David A. Tuer                  Director(1)(2)(3)         Chairman,  Calgary  Health  Region  since  October 2001 and
Calgary, Alberta               (age 57)                  Executive  Vice-Chairman  BA Energy Inc.  since April 2005.
Canada                                                   Prior  thereto  President  and  Chief  Executive   Officer,
                                                         PanCanadian   Energy  Corporation  from  December  1994  to
                                                         October 2001,  President and CEO of Hawker  Resources  Inc.
                                                         (independent  oil and natural  gas  company)  from  January
                                                         2003 to  March  2005  and most  recently  President,  Value
                                                         Creation Inc. from April 2005 to February  2006. Has served
                                                         continuously  as a director of the Company  since May 2002.
                                                         Currently  serving on the board of  directors  of BA Energy
                                                         Inc;  Rockwater  Capital  Corporation;  Daylight  Resources
                                                         Trust;  Xtreme Coil Drilling Corp. and, Altalink Management
                                                         Ltd. a private company.

Real M. Cusson                 Senior Vice-President,    Officer of the Company.
Calgary, Alberta               Marketing
Canada                         (age 56)

Real J. H. Doucet              Senior Vice-President,    Officer of the Company.
Calgary, Alberta               Oil Sands
Canada                         (age 54)
</TABLE>

<PAGE>
                                      65

<TABLE>
<CAPTION>
                               POSITION                  PRINCIPAL
                               PRESENTLY                 OCCUPATION
NAME                           HELD                      DURING PAST 5 YEARS
<S>                            <C>                       <C>
Allen M. Knight                Senior Vice-President,    Officer of the Company.
Calgary, Alberta               International &
Canada                         Corporate Development
                               (age 57)

Tim S. McKay                   Senior Vice-President,    Officer of the Company.
Calgary, Alberta               Operations
Canada                         (age 45)

Douglas A. Proll               Chief Financial Officer   Officer of the Company.
Calgary, Alberta               and Senior
Canada                         Vice-President, Finance
                               (age 56)

Lyle G. Stevens                Senior Vice-President,    Officer of the Company.
Calgary, Alberta               Exploitation
Canada                         (age 52)

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 54)

Corey B. Bieber                Vice-President, Finance   Officer of the  Company  since April  2005;  prior  thereto
Calgary, Alberta               and Investor Relations    Treasurer of the Company March 2001 to July 2002; Director,
Canada                         (age 43)                  Investor  Relations  of the Company from July 2002 to April
                                                         2005 and most recently  Vice-President,  Investor Relations
                                                         April 2005 to February 2007.

Mary-Jo Case                   Vice-President, Land      Officer  of the  Company  since  May  2002;  prior  thereto
Calgary, Alberta               (age 48)                  Co-ordinator Land at PanCanadian  Petroleum Limited to 1999
Canada                                                   and most recently Manager  Commercial  Ventures and Land at
                                                         PanCanadian Petroleum Limited 1999 to 2002.

William  R. Clapperton         Vice-President,           Officer of the Company since January 2002.
Calgary, Alberta               Regulatory, Stakeholder
Canada                         and Environmental Affairs
                               (age 44)

James F. Corson                Vice-President, Human     Officer of the Company since  January  2007;  prior thereto
Calgary, Alberta               Resources, Horizon        Vice-President,  Human  Resources of Qatar  Petroleum Corp.
Canada                         (age 56)                  from  March  1997 to July 2005 and most  recently  Director
                                                         Human  Resources and  Stakeholder  Relations of the Company
                                                         from July 2005 to 2007.

Gordon M. Coveney              Vice-President,           Officer of the Company since September 2003;  prior thereto
Calgary, Alberta               Exploration, East         Exploration Manager for the Company.
Canada                         (age 53)

Randall S. Davis               Vice-President, Finance   Officer  of the  Company  since July  2004;  prior  thereto
Calgary, Alberta               and Accounting            Manager,  Financial  Reporting of the Company to July 2002;
Canada                         (age 40)                  Financial  Controller of the Company from July 2002 to July
                                                         2004 and most recently  Vice-President  Financial Accouting
                                                         and Controls July 2004 to February 2007.

Allan Frankiw                  Vice-President,           Officer of the  Company  since March  2007;  prior  thereto
Calgary, Alberta               Production, Central       Manager  Midstream  for Anadarko  Canada  Corporation  from
Canada                         (age 50)                  November   1998  to  March  2005,   Manager   Facilities  &
                                                         Construction  for Anadarko  Canada  Corporation  from April
                                                         2005 to November 2006, and most recently Manager Production
                                                         of the Company from November 2006 to March 2007.
</TABLE>

<PAGE>
                                      66

<TABLE>
<CAPTION>
                               POSITION                  PRINCIPAL
                               PRESENTLY                 OCCUPATION
NAME                           HELD                      DURING PAST 5 YEARS
<S>                            <C>                       <C>
Larry C. Galea                 Vice-President,           Officer of the  Company  since April  2005;  prior  thereto
Calgary, Alberta               Exploitation, Central     Exploitation  Manager  of  the  Company  to  January  2002,
Canada                         (age 41)                  Manager,  Operations  Planning of the Company  January 2002
                                                         to April 2004,  and most recently  Exploitation  Manager of
                                                         the Company 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 53)

Peter Janson                   Vice-President,           Officer of the Company since December  2004;  prior thereto
Calgary, Alberta               Engineering Integration   Director,  Production  Planning  and  Control at Suncor Oil
Canada                         (age 49)                  Sands to June 2000 and  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 West         Exploitation Manager of the Company to April 2004.
Canada                         (age 39)

Christopher M. Kean            Vice-President,           Officer of the Company since December  2004;  prior thereto
Calgary, Alberta               Utilities and Offsite,    Manager  Facilities  Engineering  of the Company to January
Canada                         Horizon Oil Sands Project 2002  ,  Utilities  and  Offsites  Project  Manager  of the
                               (age 43)                  Company January 2002 to July 2002, Director,  Utilities and
                                                         Offsites  of the  Company  July  2002 to July 2003 and most
                                                         recently  General  Manager,  Utilities  and Offsites of the
                                                         Company July 2003 to December 2004.

Philip A. Keele                Vice-President, Mining,   Officer of the Company since December  2004;  prior thereto
Calgary, Alberta               Horizon Oil Sands Project Mine  Manager at Fording  Coal  Limited to  February  2001,
Canada                         (age 47)                  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               Development Operations    Production  Engineer of the Company to March 2000, Manager,
Canada                         (age 39)                  Field   Operations  of  the  Company  from  April  2000  to
                                                         September  2002,  Vice-President,  Field  Operations of the
                                                         Company   September  2002  until  November  2006  and  most
                                                         recently  Vice-President  Production Central of the Company
                                                         November 2006 to March 2007.

Richard P. Lock                Vice-President, Bitumen   Officer  of the  Company  since July  2006;  prior  thereto
Calgary, Alberta               Production                Senior Manager Production of Diavik Diamond Mines Inc. June
Canada                         (age 41)                  2002 to October 2003 and Vice-President Development October
                                                         2003 to June 2004 of Diavik  Diamond  Mines  Inc.,  Project
                                                         Manager  Extraction  of the Company  June 2004 to July 2005
                                                         and most recently  General Manager,  Bitumen  Production of
                                                         the Company July 2005 to July 2006.

Leon Miura                     Vice-President, Upgrading Officer of the Company  since  August 2003;  prior  thereto
Calgary, Alberta               (age 52)                  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 45)                  Manager,  Production  Engineering  of the Company from July
                                                         2001 to June  2002 and most  recently  Production  Manager,
                                                         Heavy Oil of the Company from July 2002 to April 2004.
</TABLE>

<PAGE>
                                      67

<TABLE>
<CAPTION>
                               POSITION                  PRINCIPAL
                               PRESENTLY                 OCCUPATION
NAME                           HELD                      DURING PAST 5 YEARS
<S>                            <C>                       <C>
David A. Payne                 Vice-President,           Officer of the Company since  October  2004;  prior thereto
Calgary, Alberta               Exploitation, East        Exploitation Manager,  Thermal Heavy of the Company to July
Canada                         (age 45)                  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 40)

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 60)                  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.

Timothy G. Reed                Vice-President, Human     Officer of the Company since  January  2007;  prior thereto
Calgary, Alberta               Resources                 Manager,  Human  Resources  of the Company 2000 to 2005 and
Canada                         (age 50)                  most recently  Director,  Human  Resources  2005 to January
                                                         2007.

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 39)                  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 45)                  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.

Scott G. Stauth                Vice-President, Field     Officer of the Company since November  2006;  prior thereto
Calgary, Alberta               Operations                Operations  Superintendent  of the  Company  April  1997 to
Canada                         (age 49)                  April  2003  and  most  recently  Manager,   Eastern  Field
                                                         Operations of the Company April 2003 to November 2006.

Stephen C. Suche               Vice-President,           Officer  of the  Company  since July  2006;  prior  thereto
Calgary, Alberta               Information and           Manager  Information and Corporate  Services of the Company
Canada                         Corporate Services        January 2000 to July 2006.
                               (age 47)
Domenic Torriero               Vice-President,           Officer of the Company since November  2006;  prior thereto
Calgary, Alberta               Exploration               Vice-President   Geology  and   Geophysics   of   Petrovera
Canada                         (age 42)                  Resources  Limited  January  1999 to  March  2004  and most
                                                         recently  Exploration  Manager of the Company March 2004 to
                                                         November 2006.

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 Limited
Canada                         (age 50)                  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.

Bruce E. McGrath               Corporate  Secretary      Officer of the Company.
Calgary, Alberta               (age 57)
Canada
</TABLE>

<PAGE>
                                      68


(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 Health, Safety, and Environmental Committee

All  directors  stand for election at each Annual  General  Meeting of Canadian
Natural  shareholders.  With the  exception  of  Messrs.  S. W.  Laut and F. J.
McKenna who were  appointed to the Board  effective  August 1, 2006, all of the
current  directors  were  elected  to the Board at the last  annual  meeting of
shareholders held on May 4, 2006. All of the current directors are standing for
election at the Annual  Special  Meeting of  Shareholders  scheduled for May 3,
2007.

As at December 31, 2006, 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.

<PAGE>
                                      69


                          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
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 2006 approved  specified audit and non-audit services to
be performed by  PricewaterhouseCoopers  LLP ("PwC") the independent auditor of
the Corporation.

AUDITOR SERVICE FEES

The Audit Committee of the Board of Directors in 2006 approved  specified audit
and non-audit  services to be performed by PwC. The services  provided include:
(i) the annual audit of the  Corporation's  internal  controls and December 31,
2006 consolidated  financial statements included in the Annual Information Form
and Form 40-F, reviews of the Corporation's  unaudited first, second, and third

<PAGE>
                                      70


quarter interim  Consolidated  Financial  Statements,  audits of certain of the
Corporation's  subsidiary  companies'  annual  financial  statements as well as
other audit  services  provided in connection  with  statutory  and  regulatory
filings; (ii) audit related services related to debt covenant compliance, Crown
Royalty  Statements;  (iii) tax related services related to expatriate personal
tax and  compliance  as well as other  corporate tax return  matters;  and (iv)
non-audit  services  related to  accessing  resource  materials  through  PwC's
accounting literature library.

Fiscal  2006 fees  accrued to PwC will not exceed  those  amounts  shown in the
table below.

               AUDITOR SERVICE                    2006           2005
               ---------------                    ----           ----
               Audit fees                   $3,126,287     $1,227,835
               Audit related fees             $121,353       $266,923
               Tax related fees               $134,025        $39,331
               All other fees                   $9,516         $7,290
               -------------------------------------------------------
                                            $3,391,181     $1,541,379
               -------------------------------------------------------

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

                               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,
2006. PricewaterhouseCoopers LLP is independent in accordance with the Rules of
Professional  Conduct as outlined by the Institute of Chartered  Accountants of
Alberta.

Based on information  provided by the relevant persons or companies,  there are
beneficial  interests,  direct or  indirect,  in less than 1% of the  Company's
securities  or  property  or  securities  or  property  of  our  associates  or
affiliates  held by Sproule  Associates  Limited,  Ryder  Scott  Company or GLJ
Petroleum  Consultants  Ltd. or any partners,  employees or consultants of such
independent  reserves evaluators who participated in and who were in a position
to directly  influence  the  preparation  of the relevant  report,  or any such

<PAGE>
                                      71


person who, at the time of the  preparation  of the report was in a position to
directly influence the outcome of the preparation of the report.

                             ADDITIONAL INFORMATION

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

Additional   information   including   Directors'   and   Executive   Officers'
remuneration and indebtedness,  principal holders of the Company's  securities,
options to  purchase  the  Company's  securities  and  interest  of insiders in
material  transactions  is  contained  in the  Company's  Notice of Annual  and
Special  Meeting and  Information  Circular  dated March 14, 2007 in connection
with the Annual and Special Meeting of  Shareholders of Canadian  Natural to be
held on May 3, 2007 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, 2006 found on pages 42 to 71,
72 to 98  and  99 to  103  respectively,  of  the  2006  Annual  Report  to the
Shareholders, which information is incorporated herein by reference.

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

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



<PAGE>
                                      72


                                  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,
         2006. 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,
                  2006 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, 2006 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, 2006.

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 "COGEH")  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

<PAGE>
                                      73


         using a discount rate of 10 percent,  included in the reserves data of
         the  Corporation  evaluated by us for the year ended December 31, 2006
         except as noted in 1(c)(i),  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         NET PRESENT VALUES OF CONVENTIONAL RESERVES
    QUALIFIED       PREPARATION    (COUNTRY OR FOREIGN
     RESERVES         DATE OF        GEOGRAPHIC AREA)             (BEFORE INCOME TAXES, 10% DISCOUNT RATE)
   EVALUATOR OR      EVALUATION                         ----------------------------------------------------
     AUDITOR           REPORT                            AUDITED       EVALUATED      REVIEWED         TOTAL
                                                           MM$            MM$            MM$            MM$
------------------------------------------------------------------------------------------------------------
<S>               <C>             <C>                   <C>            <C>            <C>            <C>
Sproule           Sproule         Canada, USA           $0             $20,260        $0             $20,260
Associates Ltd.   Evaluated the
                  P&NG
                  Reserves as
                  reported
                  February 5th,
                  2007.
------------------------------------------------------------------------------------------------------------
Ryder Scott       Ryder Scott     United Kingdom and    $0             $7,237         $0             $7,237
Company           Evaluated the   Offshore West Africa
                  P&NG Reserves
                  as reported
                  February 5th,
                  2007.
------------------------------------------------------------------------------------------------------------
  TOTALS                                                $0             $27,497        $0             $27,497
============================================================================================================
</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, 2006. GLJ
         Petroleum  Consultants Ltd. ("GLJ"), an independent qualified reserves
         evaluator,   was  retained  by  the  Reserves  Committee  of  Canadian
         Natural's Board of Directors to evaluate reserves  associated with the
         Horizon Project  incorporating both the mining and upgrading projects.
         These  reserves  were  evaluated  under SEC  Industry  Guide 7 and are
         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>
                                      74


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 5th, 2007

         SPROULE ASSOCIATES LIMITED

         ORIGINAL SIGNED BY:

         Harry J. Helwerda, P.Eng.,
         Senior Vice-President, Engineering,

         ORIGINAL SIGNED BY:

         Doug Ho, P.Eng.
         Vice-President, Engineering, and Director

         ORIGINAL SIGNED BY:

         Ken H. Crowther, P.Eng.
         President, Canada and U.S.


         RYDER SCOTT COMPANY

         ORIGINAL SIGNED BY:

         Jane Tink, P.Eng.,
         Senior Vice-President, Engineering


         GLJ PETROLEUM CONSULTANTS LTD.

         ORIGINAL SIGNED BY:

         James H. Willmon, P.Eng.
         Vice-President, Corporate Evaluations



<PAGE>
                                      75


                                  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, 2006 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; and,

(b)      (i)      both proved, and proved and probable  conventional crude oil,
                  NGLs and  natural  gas  reserve  quantities  estimated  as at
                  December 31, 2006 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, 2006.

Sproule Associates Limited,  Ryder Scott Company and GLJ Petroleum  Consultants
Ltd.,  all  independent   qualified  reserves  evaluators  have  evaluated  the
Corporation's  reserves data. The report of the independent  qualified reserves
evaluators 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 evaluators;

         (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.

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:

<PAGE>
                                      76


         (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.

         "Signed"
         Steve W. Laut
         President and Chief Operating Officer


         "Signed"
         Douglas A. Proll
         Chief Financial Officer and Senior Vice President, Finance


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


         "Signed"
         Norman F. McIntyre
         Independent Director and Member of the Reserve Committee




         Dated this 3rd day of March, 2007
         Calgary, Alberta

<PAGE>
                                      77


                                  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  management  expertise  and  qualify  as a

<PAGE>
                                      78


                  "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>
                                      79


                  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  to the Board of  Directors
                           for   appointment   by   the    shareholders,    the
                           Corporation's   independent  auditors,   review  the
                           independence  and  monitor  the  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 pre-approve all 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>
                                      80


                                   (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;

                  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; and

                  h.       to  review  and  approve  the  Corporation's  hiring
                           policies  regarding  partners,  employees and former
                           partners  and  employees  of the  present and former
                           independent auditor of the Corporation.

         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;

<PAGE>
                                      81


                  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,

                  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,   the  earnings  press
                           releases before  disclosure to the public 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,   the  earnings  press
                           releases before  disclosure to the public and report
                           to the Board with respect thereto;

                  c.       to ensure  adequate  procedures are in place for the
                           review of the  Corporation's  public  disclosure  of
                           financial  information extracted or derived from the
                           Corporation's  financial statements,  other than the
                           quarterly and annual  earnings press  releases,  and
                           periodically    assess   the   adequacy   of   those
                           procedures;

                  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 establish procedures for:


                           (i)    the  receipt,   retention  and  treatment  of
                                  complaints   received   by  the   Corporation
                                  regarding  accounting,   internal  accounting
                                  controls,  or auditing matters;  and

                           (ii)   the  confidential,  anonymous  submission  by
                                  employees  of  the  Corporation  of  concerns
                                  regarding questionable accounting or auditing
                                  matters;

                  g.       to co-ordinate  meetings with the Reserves Committee
                           of  the  Corporation,   the   Corporation's   senior
                           engineering   management,   independent   evaluating

<PAGE>
                                      82


                           engineers and auditors as required and consider such
                           further  inquiries  as are  necessary to approve the
                           consolidated financial statements;

                  h.       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;

                  i.       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,

                  j.       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 Corporation's  independent auditors in connection with
the issuance of its audit report,  or to any consultants or experts employed by
the Audit Committee.


<PAGE>



Consolidated Balance Sheets

As at December 31
(millions of Canadian dollars)                                  2006       2005
--------------------------------------------------------------------------------
ASSETS
Current assets
 Cash and cash equivalents                                  $     23    $    18
 Accounts receivable and other                                 1,947      1,546
 Future income tax (note 8)                                      163        487
 Current portion of other
   long-term assets (note 3)                                     106          -
--------------------------------------------------------------------------------
                                                               2,239      2,051
Property, plant and equipment (note 4)                        30,767     19,694
Other long-term assets (note 3)                                  154        107
--------------------------------------------------------------------------------
                                                            $ 33,160    $21,852
--------------------------------------------------------------------------------

LIABILITIES
Current liabilities
 Accounts payable                                           $    842    $   573
 Accrued liabilities                                           1,618      1,781
 Current portion of other long-term
   liabilities (note 6)                                          611      1,471
--------------------------------------------------------------------------------
                                                               3,071      3,825
Long-term debt (note 5)                                       11,043      3,321
Other long-term liabilities (note 6)                           1,393      1,434
Future income tax (note 8)                                     6,963      5,035
--------------------------------------------------------------------------------
                                                              22,470     13,615
--------------------------------------------------------------------------------

SHAREHOLDERS' EQUITY
Share capital (note 9)                                         2,562      2,442
Retained earnings                                              8,141      5,804
Foreign currency translation
   adjustment (note 10)                                          (13)        (9)
--------------------------------------------------------------------------------
                                                              10,690      8,237
--------------------------------------------------------------------------------
                                                            $ 33,160    $21,852
--------------------------------------------------------------------------------

  Commitments and contingencies (note 13)



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

<PAGE>

Consolidated Statements of Earnings


For the years ended December 31
(millions of Canadian dollars,
except per common share amounts)                   2006        2005       2004
--------------------------------------------------------------------------------
Revenue                                          $ 11,643   $ 11,130    $ 8,269
Less: royalties                                    (1,245)    (1,366)    (1,011)
--------------------------------------------------------------------------------
Revenue, net of royalties                          10,398      9,764      7,258
--------------------------------------------------------------------------------
Expenses
Production                                          1,949      1,663      1,400
Transportation and blending                         1,443      1,293        972
Depletion, depreciation and amortization            2,391      2,013      1,769
Asset retirement obligation accretion (note 6)         68         69         51
Administration                                        180        151        125
Stock-based compensation (note 6)                     139        723        249
Interest, net                                         140        149        189
Risk management activities (note 12)                  312      1,952        434
Foreign exchange loss (gain)                          122       (132)       (91)
--------------------------------------------------------------------------------
                                                    6,744      7,881      5,098
--------------------------------------------------------------------------------
Earnings before taxes                               3,654      1,883      2,160
Taxes other than income tax (note 8)                  256        194        165
Current income tax (note 8)                           222        286        116
Future income tax (note 8)                            652        353        474
--------------------------------------------------------------------------------
Net earnings                                    $   2,524   $  1,050    $ 1,405
--------------------------------------------------------------------------------
Net earnings per common share (note 11)
 Basic                                          $    4.70   $   1.96    $  2.62
 Diluted                                        $    4.70   $   1.95    $  2.60
--------------------------------------------------------------------------------



Consolidated Statements of Retained Earnings

For the years ended December 31
(millions of Canadian dollars)                    2006         2005       2004
--------------------------------------------------------------------------------
Balance - beginning of year                   $    5,804    $  4,922    $ 3,650
Net earnings                                       2,524       1,050      1,405
Dividends on common shares (note 9)                 (161)       (127)      (107)
Purchase of common shares under Normal
   Course Issuer Bid (note 9)                        (26)        (41)       (26)
--------------------------------------------------------------------------------
Balance - end of year                         $    8,141    $  5,804    $ 4,922
--------------------------------------------------------------------------------


<PAGE>

Consolidated Statements of Cash Flows


For the years ended December 31 (
millions of Canadian dollars)                     2006        2005        2004
--------------------------------------------------------------------------------
Operating activities
Net earnings                                  $    2,524    $  1,050 $    1,405
Non-cash items
 Depletion, depreciation and amortization          2,391       2,013      1,769
 Asset retirement obligation accretion                68          69         51
 Stock-based compensation                            139         723        249
 Unrealized risk management activities            (1,013)        925        (40)
 Unrealized foreign exchange loss (gain)             134        (103)       (94)
 Deferred petroleum revenue tax expense
    (recovery)                                        37          (9)       (45)
 Future income tax                                   652         353        474
Deferred charges                                      (2)        (31)       (33)
Abandonment expenditures                             (75)        (46)       (32)
Net change in non-cash working capital
   (note 14)                                        (679)       (147)       (14)
--------------------------------------------------------------------------------
                                                   4,176       4,797      3,690
--------------------------------------------------------------------------------
Financing activities
Issue(repayment)of bank credit facilities          6,499        (435)       357
Issue (repayment) of medium-term notes               400         400       (125)
Repayment of senior unsecured notes                    -        (194)       (54)
Issue of US dollar debt securities                   788           -        830
Repayment of preferred securities                      -        (107)         -
Repayment of obligations under capital leases          -           -         (7)
Issue of common shares on exercise of
   stock options                                      21           9         24
Dividends on common shares                          (153)       (121)      (101)
Purchase of common shares                            (28)        (45)       (33)
Net change in non-cash working capital (note 14)      37          19          6
--------------------------------------------------------------------------------
                                                   7,564        (474)       897
--------------------------------------------------------------------------------
Investing activities
Expenditures on property, plant and
   equipment                                      (7,266)     (5,340)    (4,582)
Net proceeds on sale of property, plant and
   equipment                                          71         454          7
--------------------------------------------------------------------------------
Net expenditures on property, plant and
   equipment                                      (7,195)     (4,886)    (4,575)
Acquisition of Anadarko Canada Corporation
   (note 2)                                       (4,641)          -          -
Net proceeds on sale of other assets                   -          11          -
Net change in non-cash working capital
   (note 14)                                         101         542        (88)
--------------------------------------------------------------------------------
                                                 (11,735)     (4,333)    (4,663)
--------------------------------------------------------------------------------
Increase (decrease) in cash and cash
   equivalents                                         5         (10)       (76)
Cash and cash equivalents - beginning of year         18          28        104
--------------------------------------------------------------------------------
Cash and cash equivalents - end of year       $       23    $     18    $    28
--------------------------------------------------------------------------------

Supplemental disclosure of cash flow information (note 14)


<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  produce
synthetic crude oil through mining and upgrading 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
16.

Signficant accounting policies are summarized as follows:

(A)  PRINCIPLES OF CONSOLIDATION

The consolidated  financial  statements  include the accounts of the Company and
all of its subsidiary  companies 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.

Purchase  price  allocations,  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 infiation 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 in the United Kingdom 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 at
purchase 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 its  conventional
crude oil and natural gas  properties  and equipment as prescribed by Accounting
Guideline  16 ("AcG 16") 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 are accounted for
as capital leases or operating leases as appropriate.

Property  acquisition,   construction  and  development  costs  related  to  the
Company's  Horizon  Project are not  accounted for under the full cost method of
accounting   and   accordingly,   are  excluded  from  the  Company's   Canadian
conventional  oil  and gas  cost  centre.  Construction  costs  are  capitalized
separately  to each phase of the Horizon  Project.  The Company  will review the
recoverability  of the carrying amount of the Horizon Project costs if events or
circumstances indicate that the carrying amount may not be recoverable.


<PAGE>

(E)  DEPLETION, DEPRECIATION AND AMORTIZATION

Substantially  all costs  related  to each  country-by-country  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.  Costs for major  development  projects,  as identified by
management,  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

Following the Board of Directors'  approval of Phase 1 of the Horizon Project in
2005, the Company commenced capitalization of construction period interest based
on costs incurred and the Company's cost of borrowing.  Interest  capitalization
on Phase 1 will cease once construction is substantially complete and this phase
of the Horizon  Project is  available  for its  intended  use.  The Company will
continue to capitalize a portion of interest costs related to subsequent  phases
of the Horizon Project.

(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.  Refer to policy note (R) for the effect of new financial instrument
policies on deferred charges.

(H)  ASSET RETIREMENT OBLIGATIONS

The Company  provides for future asset  retirement  obligations  on its resource
properties,  facilities,  production  platforms and  gathering  systems 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 lives of the  respective
assets.  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.

The Company's pipelines have an indeterminate 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 year in
which the lives of the assets are determinable.

(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
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 assets.

<PAGE>

Gains or losses on translation of integrated  foreign operations are included in
the  consolidated  statement of earnings.  Gains or losses on the translation of
foreign currency balances are either recognized in net earnings immediately,  or
in the foreign currency  translation  adjustment (note 10) for translation gains
or losses for that portion of the US dollar  denominated  debt  designated  as a
hedge of the net investment in 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,  delivery  has taken  place  and  collection  is
reasonably assured. 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 AND BLENDING

Transportation  and blending 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 CONTRACTS

Production  generated  from Offshore  West Africa is currently  shared under the
terms of various  Production  Sharing Contracts  ("PSCs").  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 then  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 as of 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.

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

(O)  STOCK-BASED COMPENSATION PLANS

The Company  accounts for  stock-based  compensation  using the intrinsic  value
method as 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 and an estimated
forfeiture  rate.  This  liability is revalued at each reporting date to reflect
changes  in  the  market  price  of  the  Company's  common  shares  and  actual
forfeitures,  with the net change  recognized  in net  earnings,  or adjusted to
capitalized  costs  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.

(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  intended for trading or  speculative  purposes.
Changes in fair value of derivative financial instruments formally 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

<PAGE>

value of derivative financial  instruments not formally 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 derivative financial  instruments  designated
as  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.  All  realized  and  unrealized  gains or losses on these
contracts are included in risk management  activities,  regardless of whether or
not these contracts have been formally designated as hedges.

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  formally  designated  as hedges are  included  in interest
expense. Gains or losses on non-designated  interest rate contracts are included
in risk management activities.

The Company  enters  into  cross-currency  swap  agreements  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 the foreign exchange  component of all  cross-currency  swap contracts
are  included in risk  management  activities.  Gains or losses on the  interest
component of 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  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.

Risk  management   activities  are  included  in  operating  activities  in  the
consolidated statements of cash flows.

Refer to policy note (R) for the effect of new accounting  standards  related to
the accounting for risk management activities.

(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 accounted for as a
liability are used to purchase  common shares at the average market price during
the year.  The Company's  Option Plan described in note 9 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. The dilutive effect of other 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

Effective  January 1, 2007,  the Company will adopt the following new accounting
standards  issued by the CICA relating to the  accounting  for and disclosure of
financial instruments:

o    Section  1530  -   "Comprehensive   Income"   introduces   the  concept  of
     comprehensive  income to Canadian GAAP.  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.

     Foreign  currency  translation  adjustment,  which is  currently a separate
     component of shareholders'  equity, will be recorded as part of accumulated
     other comprehensive income.

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 will be restated
     only for the foreign currency translation adjustment.

o    Section  3855 -  "Financial  Instruments  -  Recognition  and  Measurement"
     prescribes when a financial  asset,  financial  liability,  or nonfinancial
     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.

     The  Company  will  include  all   transaction   costs  that  are  directly
     attributable  to the acquisition or issue of a financial asset or financial
     liability  with  the  fair  value  of  the  financial  asset  or  financial
     liability.  These adjustments were previously recorded in deferred charges.
     Transaction  costs  included with the fair value of the financial  asset or
     financial liability will be amortized using the effective interest method.

<PAGE>

o    Section  3865  -  "Hedges"  replaces  Accounting  Guideline  13 -  "Hedging
     Relationships"  and EIC  128 -  "Accounting  for  Trading,  Speculative  or
     Non-Hedging  Derivative  Financial  Instruments"  and  specifies  how hedge
     accounting is to be applied and what  disclosures  are necessary when hedge
     accounting is applied.

     Adoption  of this  standard  will  require the Company to record all of its
     derivative  financial  instruments  on the  balance  sheet  at fair  value,
     including those designated as hedges.  Designated  hedges are currently not
     recognized  on the  balance  sheet  but are  disclosed  in the notes to the
     financial statements.  The adjustment to recognize the designated hedges on
     the balance sheet will be recorded as an adjustment to the opening  balance
     of  retained  earnings  or  accumulated  other  comprehensive   income,  as
     appropriate.

     Subsequently,  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 comprehensive income
     each period and are recognized in the  consolidated  statements of earnings
     when the hedged item is recognized.  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.

Adoption of these  standards  will have the following  estimated  effects on the
Company's consolidated balance sheet as at January 1, 2007:

Decrease future income tax asset                                        $   (62)
Increase current portion of other long-term assets                      $   193
Decrease other long-term assets                                         $   (16)
Decrease long-term debt                                                 $   (72)
Increase future income tax liability                                    $    18
Increase retained earnings                                              $    10
Increase foreign currency translation adjustment                        $    13
Increase accumulated other comprehensive income                         $   146
--------------------------------------------------------------------------------

(S) COMPARATIVE FIGURES

Certain  figures  related  to the  presentation  of  gross  revenues  and  gross
transportation  and blending  provided for prior years have been reclassified to
conform to the presentation adopted in 2006.

Common share data has been  restated to reflect the  two-for-one  share split in
May 2005.

2. BUSINESS COMBINATIONS

ANADARKO CANADA CORPORATION

In November 2006, the Company completed the acquisition of all of the issued and
outstanding common shares of Anadarko Canada  Corporation  ("ACC"), a subsidiary
of Anadarko Petroleum Corporation,  for net cash consideration of $4,641 million
including working capital and other adjustments. Substantially all of ACC's land
and production base are located in Western Canada.

The acquisition was accounted for using the purchase method.  Operating  results
from ACC have been  consolidated  with the results of the Company effective from
November 2, 2006, the date of acquisition, and are reported in the North America
segment.  The  preliminary  allocation  of the net purchase  price is subject to
change as actual amounts are determined.  The preliminary  allocation of the net
purchase price to assets  acquired and  liabilities  assumed based on their fair
values was as follows:

Net purchase price:
 Net cash consideration (1)                                             $ 4,641
--------------------------------------------------------------------------------
Net purchase price allocated as follows:
 Non-cash working capital deficit assumed
   and other                                                            $  (105)
 Property, plant and equipment                                            6,249
 Long-term debt                                                              (9)
 Asset retirement obligation                                                (56)
 Future income tax                                                       (1,438)
--------------------------------------------------------------------------------
                                                                        $ 4,641
================================================================================
(1)  Net cash consideration was reduced by $88 million to reflect the settlement
     of US dollar  currency  forward  contracts  designated as hedges of the ACC
     share purchase price.

<PAGE>

3.   OTHER LONG-TERM ASSETS

                                                              2006       2005
--------------------------------------------------------------------------------
Deferred charges                                            $   109     $   107
Risk management(note 12)                                        128           -
Other                                                            23           -
--------------------------------------------------------------------------------
                                                                260         107
Less: current portion                                           106           -
--------------------------------------------------------------------------------
                                                            $   154     $   107
================================================================================

4.   PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
                                                 2006                             2005
                                              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                   $  31,715    $    9,836    $ 21,879    $ 22,258  $  7,948 $ 14,310
 North Sea                           3,370         1,341       2,029       2,703     1,022    1,681
 Offshore West Africa                1,685           481       1,204       1,547       294    1,253
 Other                                  38            14          24          27        14       13
 Horizon Project                     5,350             -       5,350       2,169         -    2,169
 Midstream                             263            56         207         251        48      203
 Head office                           150            76          74         124        59       65
----------------------------------------------------------------------------------------------------
                                 $  42,571    $   11,804    $ 30,767    $ 29,079  $  9,385 $ 19,694
====================================================================================================
</TABLE>


During the year ended December 31, 2006, the Company capitalized  administrative
overhead of $41 million  (2005 - $41 million,  2004 - $49  million)  relating to
exploration  and  development in the North Sea and Offshore West Africa and $456
million  (2005 - $236  million,  2004 - $35 million)  relating  primarily to the
Horizon Project in North America.

During the year ended  December 31, 2006, the Company  capitalized  $196 million
(2005 -$72 million, 2004 -$nil) in construction period interest costs related to
the Horizon Project.

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

                                                             2006         2005
--------------------------------------------------------------------------------
Crude oil and natural gas
 North America                                              $  2,244    $ 1,372
 North Sea                                                        24         28
 Offshore West Africa                                             84        182
 Other                                                            24         13
Horizon Project                                                5,350      2,169
--------------------------------------------------------------------------------
                                                            $  7,726    $ 3,764
================================================================================

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, 2006:

<TABLE>
<CAPTION>
                                                                                          Average
                                                                                          annual
                                                                                          increase
                                   2007           2008        2009        2010     2011   thereafter
----------------------------------------------------------------------------------------------------
<S>                              <C>          <C>           <C>         <C>       <C>           <C>
Crude oil and NGLs
 North America
    WTI at Cushing (US$/bbl)     $   65.73    $    68.82    $  62.42    $  58.37  $  55.20      2.0%
    Hardisty Heavy 12(degree)
      API(C$/bbl)                $   42.98    $    45.02    $  40.74    $  38.03  $  35.90      2.0%
    Edmonton Par (C$/bbl)        $   74.10    $    77.62    $  70.25    $  65.56  $  61.90      2.0%
    North Sea and Offshore
      West Africa
    North Sea Brent (US$/bbl)    $   63.73    $    66.78    $  60.34    $  56.24  $  53.04      2.0%
----------------------------------------------------------------------------------------------------
 Natural gas
 North America
    Henry Hub Louisiana
      (US$/mmbtu)                $    7.85    $     8.39    $   7.65    $   7.48  $   7.63      2.0%
    AECO (C$/mmbtu)              $    7.72    $     8.59    $   7.74    $   7.55  $   7.72      2.0%
    Huntingdon/Sumas (C$/mmbtu)  $    7.48    $     8.45    $   7.60    $   7.41  $   7.58      2.0%
----------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>

5.   LONG-TERM DEBT

<TABLE>
<CAPTION>
                                                                                                 2006          2005
----------------------------------------------------------------------------------------------------------------------
<S>                                                                                          <C>           <C>
Bank credit facilities
 Bankers' acceptances                                                                        $     6,621   $      122
Medium-term notes
 7.40% unsecured debentures due March 1, 2007                                                        125          125
 4.50% unsecured debentures due January 23, 2013                                                     400            -
 4.95% unsecured debentures due June 1, 2015                                                         400          400
Senior unsecured notes
 Adjustable rate due May 27, 2009 (2006 - US$93 million, 2005 - US$93 million)                       108          108
US dollar debt securities
 7.80% due July 2, 2008 (2006 - US$8 million, 2005 - US$nil)                                           9            -
 6.70% due July 15, 2011 (2006 - US$400 million, 2005 - US$400 million)                              466          467
 5.45% due October 1, 2012 (2006 - US$350 million , 2005 - US$350 million)                           408          408
 4.90% due December 1, 2014 (2006 - US$350 million, 2005 - US$350 million)                           408          408
 6.00% due August 15, 2016 (2006 - US$250 million, 2005 - US$nil)                                    291            -
 7.20% due January 15, 2032 (2006 - US$400 million, 2005 - US$400 million)                           466          467
 6.45% due June 30, 2033 (2006 - US$350 million, 2005 - US$350 million)                              408          408
 5.85% due February 1, 2035 (2006 - US$350 million, 2005 - US$350 million)                           408          408
 6.50% due February 15, 2037 (2006 - US$450 million, 2005 - US$nil)                                  525            -
----------------------------------------------------------------------------------------------------------------------
                                                                                             $    11,043   $    3,321
======================================================================================================================
</TABLE>

BANK CREDIT FACILITIES

As at  December  31,  2006,  the  Company  had in place  unsecured  bank  credit
facilities of $7,809 million, comprised of:

     o    a $100 million demand credit facility;

     o    a $500 million demand credit facility;

     o    a 3-year non-revolving syndicated credit facility of $3,850 million;

     o    a 5-year revolving syndicated credit facility of $1,825 million;

     o    a 5-year revolving syndicated credit facility of $1,500 million; and

     o    a (pound)15  million demand credit  facility  related to the Company's
          North Sea operations.

The revolving  syndicated  credit facilities are fully revolving for a period of
five years maturing June 2011. Both  facilities are extendible  annually for one
year  periods at the mutual  agreement  of the Company and the  lenders.  If the
facilities are not extended,  the full amount of the outstanding principal would
be repayable on the maturity date.

In conjunction  with the closing of the acquisition of ACC (note 2), the Company
executed a $3,850 million,  three-year  non-revolving syndicated credit facility
maturing  in October  2009.  This  facility  is  subject  to certain  prepayment
requirements up to a maximum of $1,500 million.

During 2006, the Company  obtained a $500 million credit  facility  repayable on
demand.

The weighted average interest rate of the bank credit facilities  outstanding at
December 31, 2006, was 4.8% (2005 - 4.0%).

In addition to the outstanding debt, letters of credit and financial  guarantees
aggregating $338 million, including $300 million related to the Horizon Project,
were outstanding at December 31, 2006.

MEDIUM-TERM  NOTES

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.

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.

Subsequent to December 31, 2006,  the 7.40%  unsecured  debentures  due March 1,
2007 were repaid.

SENIOR UNSECURED NOTES

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.

In December 2005,  the Company repaid the US$125 million 7.69% senior  unsecured
notes due December 19, 2005.

<PAGE>

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 August 2006, the Company  issued US$250  million of unsecured  notes maturing
August  2016 and US$450  million of  unsecured  notes  maturing  February  2037,
bearing  interest at 6.00% and 6.50%,  respectively.  Concurrently,  the Company
entered  into  cross-currency  interest-rate  swaps to fix the  Canadian  dollar
interest and principal  repayment  amounts on the US$250  million notes at 5.40%
and C$279 million (note 12).  Proceeds from the  securities  issued were used to
repay bankers' acceptances under the Company's bank credit facilities.

In November  2006,  the US shelf  prospectus,  filed in June 2005, was increased
from US$2,000 million to US$3,000  million,  leaving US$2,300 million  available
for issue in the United States until July 2007.

Subsequently, on March 12, 2007, the Company priced, for settlement on March 19,
2007,  US$2,200  million  of  unsecured  notes  under  the US shelf  prospectus,
comprised of US$1,100  million of unsecured notes maturing May 2017 and US$1,100
million of unsecured  notes maturing March 2038,  bearing  interest at 5.70% and
6.25%,  respectively.  Concurrently,  the Company  entered  into  cross-currency
interest-rate  swaps to fix the Canadian dollar interest and principal repayment
amounts on US$1,100 million of unsecured notes due May 2017 at 5.10% and C$1,287
million.  The Company also entered into a cross-currency  interest-rate  swap to
fix the Canadian  dollar  interest  and  principal  repayment  amounts on US$550
million  of  unsecured  notes due March  2038 at 5.76%  and C$644  million.  Net
proceeds on the debt issue will be used to repay  outstanding  amounts under the
Company's bank credit facilities.

REQUIRED DEBT REPAYMENTS

Required debt repayments are as follows:

 Year                                                                 Repayment
--------------------------------------------------------------------------------
 2007                                                                   $   161
 2008                                                                   $    45
 2009                                                                   $ 3,876
 2010                                                                   $     -
 2011                                                                   $   466
 Thereafter                                                             $ 3,713
--------------------------------------------------------------------------------

No debt  repayments  are reflected for $2,782  million of revolving  bank credit
facilities due to the extendable nature of the facilities.

6. OTHER LONG-TERM LIABILITIES
                                                              2006        2005
--------------------------------------------------------------------------------
Asset retirement obligations                                 $ 1,166    $ 1,112
Stock-based compensation                                         744        891
Risk management (note 12)                                          -        885
Other                                                             94         17
--------------------------------------------------------------------------------
                                                               2,004      2,905
Less: current portion                                            611      1,471
--------------------------------------------------------------------------------
                                                             $ 1,393    $ 1,434
================================================================================

ASSET RETIREMENT OBLIGATIONS

At December 31, 2006, 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  $4,497  million  (2005 - $3,325
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  6.7%.  A
reconciliation of the discounted asset retirement obligations is as follows:

                                                  2006        2005       2004
--------------------------------------------------------------------------------
Asset retirement obligations
Balance - beginning of year                   $    1,112    $  1,119    $   897
 Liabilities incurred                                 26          47         53
 Liabilities acquired (note 2)                        56           -        286
 Liabilities settled                                 (75)        (46)       (32)
 Asset retirement obligation accretion                68          69         51
 Revision of estimates                               (21)        (56)       (86)
 Foreign exchange                                      -         (21)       (50)
--------------------------------------------------------------------------------
Balance - end of year                         $    1,166    $  1,112    $ 1,119
================================================================================

<PAGE>

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  twelve  month  period  if  all  vested  options  are
surrendered for cash settlement.

                                                  2006        2005       2004
--------------------------------------------------------------------------------
Stock-based compensation
Balance - beginning of year                   $      891    $    323    $   171
 Stock-based compensation                            139         723        249
 Cash payment for options surrendered               (264)       (227)       (80)
 Transferred to common shares                       (101)        (29)       (38)
 Capitalized to Horizon Project                       79         101         21
--------------------------------------------------------------------------------
Balance - end of year                                744         891        323
Less: current portion of stock-based
   compensation                                      611         629        243
--------------------------------------------------------------------------------
                                              $      133    $    262    $    80
================================================================================

7. EMPLOYEE FUTURE BENEFITS

In connection with the  acquisition of ACC, the Company  assumed  obligations to
provide  defined   contribution   pension  benefits  to  certain  ACC  employees
continuing  their  employment with the Company,  and defined benefit pension and
other  post-retirement  benefits to former ACC employees,  under  registered and
unregistered pension plans.

The  estimated  future  cost of  providing  defined  benefit  pension  and other
post-retirement benefits to former ACC employees is actuarially determined using
management's  best  estimates of  demographic  and  financial  assumptions.  The
discount rate of 5% used to determine accrued benefit  obligations is based on a
year end market rate of interest for  high-quality  debt  instruments  with cash
flows that match the timing and amount of  expected  benefit  payments.  Company
contributions to the defined contribution plan are expensed as incurred.

The benefit  obligation  under the registered  pension plan at December 31, 2006
was $29  million.  As required by  government  regulations,  the Company has set
aside funds with an independent trustee to meet these benefit obligations. As at
December  31,  2006,  these plan  assets had a fair  value of $54  million.  The
unregistered  pension  plans are unfunded and have a benefit  obligation  of $15
million at December 31, 2006.

8. TAXES

TAXES OTHER THAN INCOME TAX

                                                  2006        2005       2004
--------------------------------------------------------------------------------
Current petroleum revenue tax                 $      196    $    181    $   190
Deferred petroleum revenue tax                        37          (9)       (45)
Provincial capital taxes and surcharges               23          22         20
--------------------------------------------------------------------------------
                                              $      256    $    194    $   165
================================================================================

INCOME TAX

The provision for income tax is as follows:

                                                  2006        2005       2004
--------------------------------------------------------------------------------
Current income tax
 Current income tax - North America           $      143    $     99    $   101
 Current income tax - North Sea                       30         155          2
 Current income tax -Offshore West Africa             49          32         13
--------------------------------------------------------------------------------
                                                     222         286        116
Future income tax                                    652         353        474
--------------------------------------------------------------------------------
Income tax                                    $      874    $    639    $   590
================================================================================

<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:

                                                  2006        2005       2004
--------------------------------------------------------------------------------
Canadian statutory income tax rate                  34.9%       38.0%      39.3%
--------------------------------------------------------------------------------
Income tax provision at statutory rate        $    1,275    $    716    $   849
Effect on income taxes of:
 Non-deductible portion of Canadian
    crown payments                                   131         309        221
 Canadian resource allowance                        (129)       (293)      (270)
 Large Corporations Tax                              (16)         16         11
 Deductible UK petroleum revenue tax                 (82)        (65)       (57)
 Foreign tax rate differentials                       92          (1)       (31)
 North America income tax rate changes              (438)        (19)       (66)
 UK income tax rate changes                          110           -          -
 Cote d'Ivoire income tax rate changes               (67)          -          -
 Non-taxable portion of foreign exchange               5         (15)       (36)
 Attributed Canadian Royalty Income                  (27)        (21)        (4)
 Other                                                20          12        (27)
--------------------------------------------------------------------------------
Income tax                                    $      874    $    639    $   590
================================================================================

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

                                                               2006       2005
--------------------------------------------------------------------------------
Future income tax liabilities
 Property, plant and equipment                              $  6,088    $ 3,960
 Timing of partnership items                                   1,394      1,646
 Unrealized foreign exchange gain on
   long-term debt                                                 93        112
 Risk management activities                                       40          -
 Other                                                            13         31
Future income tax assets
 Asset retirement obligations                                   (487)      (384)
 Capital loss carryforwards                                      (85)       (79)
 Attributed Canadian Royalty Income                                -        (75)
 Stock-based compensation                                       (232)      (300)
 Risk management activities                                        -       (304)
Deferred petroleum revenue tax                                   (24)       (59)
--------------------------------------------------------------------------------
Net future income tax liability                                6,800      4,548
Less: current portion future income tax asset                   (163)      (487)
--------------------------------------------------------------------------------
Future income tax liability                                 $  6,963    $ 5,035
================================================================================

During 2006,  income tax rate changes  resulted in a reduction of future  income
tax liabilities of approximately  $438 million in North America,  an increase of
future income tax liabilities of approximately  $110 million in the UK North Sea
and a reduction of future income tax liabilities of approximately $67 million in
Cote d'Ivoire.

During 2005,  North America  income tax rate changes  resulted in a reduction of
future income tax liabilities of approximately $19 million.

During 2004,  North America  income tax rate changes  resulted in a reduction of
future income tax liabilities of approximately $66 million.

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.

<PAGE>

9.   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.

ISSUED
<TABLE>
<CAPTION>

                                                                           2006                         2005
----------------------------------------------------------------------------------------------------------------------
                                                                Number of                    Number of
                                                                  Shares                       Shares
Common shares                                                   (thousands)        Amount     (thousands)      Amount
----------------------------------------------------------------------------------------------------------------------

<S>                                                               <C>       <C>                  <C>       <C>
Balance - beginning of year                                       536,348   $      2,442         536,361   $    2,408
Issued upon exercise of stock options                               2,040             21             837            9
Previously recognized liability on stock options
 exercised for common shares                                            -            101               -           29
Purchase of common shares under Normal Course Issuer Bid             (485)            (2)           (850)          (4)
----------------------------------------------------------------------------------------------------------------------
Balance - end of year                                             537,903   $      2,562         536,348   $    2,442
======================================================================================================================
</TABLE>

NORMAL COURSE ISSUER BID

During 2006, the Company purchased 485,000 common shares for cancellation  (2005
- 850,000 common shares,  2004 - 1,746,800 common shares) at an average price of
$57.33 per common share (2005 - $53.29 per common share, 2004 -$19.00 per common
share), for a total cost of $28 million (2005 - $45 million, 2004 -$33 million).
Retained  earnings  was reduced by $26 million  (2005 - $41  million,  2004 -$26
million),  representing  the excess of the purchase  price of the common  shares
over their average carrying value.

In January 2007,  the Company  renewed its Normal Course Issuer Bid to purchase,
through the  facilities  of the Toronto  Stock  Exchange  and the New York Stock
Exchange,  during the  12-month  period  beginning  January  24, 2007 and ending
January 23, 2008, up to 26,941,730 common shares or 5% of the outstanding common
shares of the Company then  outstanding on the date of the  announcement.  As at
March 15, 2007,  the Company had not purchased any  additional  shares under the
Normal Course Issuer Bid.

DIVIDEND POLICY

The Company has paid regular  quarterly  dividends in January,  April,  July and
October of each year since 2001. The dividend policy undergoes a periodic review
by the Board of Directors and is subject to change.

In March  2007,  the Board of  Directors  set the  Company's  regular  quarterly
dividend  at $0.085 per common  share  (2006 - $0.075 per common  share,  2005 -
$0.059 per common share).

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 were restated to retroactively reflect the share split.

STOCK OPTIONS

The  Company's  Option Plan provides for granting of stock options to employees.
Stock options  granted under the Option Plan have terms ranging from five to 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 provides the holder the choice to purchase one common share
of the Company at the stated  exercise  price or receive a cash payment equal to
the  difference  between the stated  exercise  price and the market price of the
Company's common shares on the date of surrender.

The following table summarizes information relating to stock options outstanding
at December 31, 2006 and 2005:

<TABLE>
<CAPTION>
                                                                         2006                           2005
-----------------------------------------------------------------------------------------------------------------------
                                                                                 Weighted                      Weighted
                                                                  Stock          Average          Stock        average
                                                                 Options         Exercise        options       exercise
                                                               (thousands)        Price         (thousands)     price
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>      <C>                   <C>      <C>
Outstanding - beginning of year                                    30,510   $      17.79          32,522   $    12.37
Granted                                                            13,084   $      59.61           7,959   $    32.51
Exercised for common shares                                        (2,040)  $      10.67            (837)  $     9.81
Surrendered for cash settlement                                    (5,180)  $      12.60          (7,523)  $    10.49
Forfeited                                                          (1,949)  $      37.51          (1,611)  $    19.36
-----------------------------------------------------------------------------------------------------------------------
Outstanding - end of year                                          34,425   $      33.77          30,510   $    17.79
-----------------------------------------------------------------------------------------------------------------------
Exercisable - end of year                                           9,177   $      14.73           8,677   $    11.21
=======================================================================================================================
</TABLE>

<PAGE>

The range of exercise  prices of stock options  outstanding  and  exercisable at
December 31, 2006 is as follows:


<PAGE>

<TABLE>
<CAPTION>

                                                             Stock Options             Stock Options
                                                             Outstanding                 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>
$9.63 - $9.99                                       4,672        0.76      $  9.71      3,603       $  9.74

$10.00 - $19.99                                     9,807        2.20      $ 14.68     4,202        $ 13.78
$20.00 - $29.99                                     5,099        3.34      $ 25.41       957        $ 25.00
$30.00 - $39.99                                     1,227        3.79      $ 33.23       175        $ 33.24
$40.00 - $49.99                                       686        5.02      $ 46.50        69        $ 43.84
$50.00 - $59.99                                     7,033        4.81      $ 57.85       166        $ 55.14
$60.00 - $69.14                                     5,901        4.27      $ 61.70         5        $ 61.60
-------------------------------------------------------------------------------------------------------------
                                                   34,425        3.17      $ 33.77     9,177        $ 14.73
=============================================================================================================
</TABLE>

10. FOREIGN CURRENCY TRANSLATION ADJUSTMENT

The foreign currency  translation  adjustment  represents the unrealized loss on
the Company's net investment in self-sustaining  foreign operations.  Commencing
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.

                                                               2006       2005
--------------------------------------------------------------------------------
Balance - beginning of year                                 $     (9)   $    (6)
Unrealized loss on translation of net investment                  (4)       (12)
Hedge of net investment with US dollar denominated
  debt, net of tax                                                 -          9
--------------------------------------------------------------------------------
Balance - end of year                                       $    (13)   $    (9)
================================================================================

11. NET EARNINGS PER COMMON SHARE

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

(thousands of shares)                             2006        2005       2004(1)
--------------------------------------------------------------------------------
Weighted average common shares outstanding
   - basic                                       537,339     536,650    536,223
Assumed settlement of preferred securities
   with common shares(2)                               -       1,775      4,461
Weighted average common shares
   outstanding - diluted                         537,339     538,425    540,684
--------------------------------------------------------------------------------
Net earnings                                  $    2,524    $  1,050    $ 1,405
Interest on preferred securities, net of tax(2)        -           4          5
Revaluation of preferred securities,
   net of tax (2)                                      -          (2)        (4)
--------------------------------------------------------------------------------
Diluted net earnings                          $    2,524    $  1,052    $ 1,406
--------------------------------------------------------------------------------
Net earnings per common share
 Basic                                        $     4.70    $   1.96    $  2.62
 Diluted                                      $     4.70    $   1.95    $  2.60
================================================================================

(1)  Restated to reflect two-for-one share split in May 2005.
(2)  The preferred securities were redeemed in September 2005.

<PAGE>

12. 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, 2006 and 2005,  the estimated  fair values of  non-designated
financial derivatives were comprised as follows:

<TABLE>
<CAPTION>

                                                         2006                  2005
------------------------------------------------------------------------------------------
                                                Risk                     Risk
                                              Management               Management
                                               Mark-to-      Deferred   Mark-to-  Deferred
Asset (liability)                               Market       Revenue     Market    Revenue
------------------------------------------------------------------------------------------
<S>                                           <C>           <C>         <C>      <C>
Balance - beginning of year                   $     (877)   $     (8)   $    66  $    (26)
Net  cost  of  outstanding  put options              455           -        190         -
Net change in fair value of  outstanding
   derivative financial instruments                1,005           -       (943)        -
Amortization   of  deferred revenue                    -           8          -        18
------------------------------------------------------------------------------------------
                                                     583           -       (687)       (8)
Add: put premium financing obligations (1)          (455)          -       (190)        -
------------------------------------------------------------------------------------------
Balance - end of year                                128           -       (877)       (8)
Less: current portion                                 88           -       (834)       (8)
------------------------------------------------------------------------------------------
                                              $       40    $      -    $   (43) $      -
==========================================================================================
</TABLE>

(1)  The Company has  negotiated  payment of put option  premiums  with  various
     counter-parties at the time of actual settlement of the respective options.
     These  obligations  have been  reflected in the net risk  management  asset
     (liability).

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

                                                 2006         2005       2004
--------------------------------------------------------------------------------
Net realized risk management loss             $    1,325    $  1,027    $   474
Net unrealized risk management (gain) loss        (1,013)        925        (40)
--------------------------------------------------------------------------------
                                              $      312    $  1,952    $   434
================================================================================

As at December 31, 2006,  the net  unrecognized  asset  related to the estimated
fair values of derivative  financial  instruments  designated as hedges was $222
million (December 31, 2005 - net unrecognized liability of $990 million).

FINANCIAL CONTRACTS

The  Company's  financial  instruments  recognized in the  consolidated  balance
sheets  consist  of cash and cash  equivalents,  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 and the differences may be material.

The carrying value of cash and cash equivalents,  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:

                                          2006                     2005
--------------------------------------------------------------------------------
                                  Carrying      Fair        Carrying      Fair
Asset (liability)                  Value        Value        Value       Value
--------------------------------------------------------------------------------
Derivative financial instruments $     583    $      805    $   (687)   $(1,700)
Fixed rate notes                 $  (4,410)   $   (4,434)   $ (3,199)   $(3,367)
================================================================================

<PAGE>

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  intended  for  trading or other  speculative
purposes.  The following summarizes  instruments  outstanding as at December 31,
2006:

<TABLE>
<CAPTION>
                             Remaining term        Volume        Average price         Index
-------------------------------------------------------------------------------------------------------
<S>                       <C>                   <C>            <C>                     <C>
Crude oil
Crude oil price collars   Jan 2007 - Dec 2007   15,000 bbl/d   US$50.00 - US$66.25     Mayan Heavy
                          Jan 2007 - Dec 2007   50,000 bbl/d   US$60.00 - US$71.49     WTI
                          Jan 2007 - Dec 2007   100,000 bbl/d  US$60.00 - US$78.11     WTI
                          Jan 2007 - Dec 2007   50,000 bbl/d   US$65.00 - US$84.52     WTI
                          Jan 2008 - Dec 2008   50,000 bbl/d   US$60.00 - US$76.05     WTI
                          Jan 2008 - Dec 2008   50,000 bbl/d   US$60.00 - US$76.98     WTI
Crude oil puts (1)        Jan 2007 - Dec 2007   100,000 bbl/d  US$45.00                WTI
                          Jan 2007 - Dec 2007   100,000 bbl/d  US$60.00                WTI
                          Jan 2008 - Dec 2008   50,000 bbl/d   US$55.00                WTI
Brent differential swaps  Jan 2007 - Dec 2007   50,000 bbl/d   US$1.34                 WTI/Dated Brent
-------------------------------------------------------------------------------------------------------
</TABLE>

The cost of outstanding put options and their respective years of settlement are
as follows:

                                                              2007        2008
--------------------------------------------------------------------------------
Cost (1) ($ millions)                                        US$ 331     US$ 59
--------------------------------------------------------------------------------

(1)  Subsequent  to December  31,  2006,  the Company  unwound  23,000  bbl/d of
     US$60.00 WTI put options for the period February 2007 to December 2007, for
     cash  consideration  of US$40 million.

<TABLE>
<CAPTION>
                             Remaining term        Volume        Average price         Index
-------------------------------------------------------------------------------------------------------
<S>                       <C>                     <C>                    <C>                     <C>
Natural gas
AECO collars              Jan 2007 - Mar 2007     100,000 GJ/d           C$7.00 - C$11.63        AECO
                          Jan 2007 - Mar 2007     200,000 GJ/d           C$7.25 - C$8.38         AECO
                          Jan 2007 - Mar 2007     162,500 GJ/d           C$7.25 - C$9.48         AECO
                          Jan 2007 - Mar 2007     162,500 GJ/d           C$7.50 - C$8.94         AECO
                          Jan 2007 - Mar 2007     300,000 GJ/d           C$7.50 - C$18.77        AECO
                          Jan 2007 - Mar 2007     400,000 GJ/d           C$8.50 - C$11.22        AECO
                          Jan 2007 - Dec 2007      60,000 GJ/d           C$8.00 - C$8.79         AECO
                          Apr 2007 - Oct 2007     500,000 GJ/d           C$6.00 - C$10.13        AECO
                          Apr 2007 - Oct 2007     500,000 GJ/d           C$7.00 - C$8.24         AECO
                          Nov 2007 - Mar 2008     400,000 GJ/d           C$7.00 - C$14.08        AECO
                          Nov 2007 - Mar 2008     500,000 GJ/d           C$7.50 - C$10.81        AECO
-------------------------------------------------------------------------------------------------------
</TABLE>

Commodity  related  derivative  financial  instruments  designated  as hedges at
December 31, 2006, were all classified as cash flow hedges.

The  Company's  outstanding  derivatives  will be settled  monthly  based on the
applicable index pricing for the respective contract month.

In addition to the financial  derivatives  noted above, the Company also entered
into natural gas physical  sales  contracts for 325,000 GJ/d at an average fixed
price of C$9.17 per GJ at AECO for the period  January to March 2007 and 300,000
GJ/d at an average  fixed  price of C$7.33  per GJ at AECO for the period  April
2007 to October 2007.

As at December 31, 2006, the net unrealized  loss related to the  de-designation
of commodity  cash flow hedges was $41  million.  This  unrealized  loss will be
recognized in earnings in 2007.

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 fioating rate  long-term  debt.
The Company  enters into  interest  rate swap  agreements to manage its fixed to
fioating  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, 2006,  the
Company had the following interest rate swap contracts outstanding:

<TABLE>
<CAPTION>

                                                          Amount
                                   Remaining Term       ($ millions)      Fixed Rate      Floating Rate
--------------------------------------------------------------------------------------------------------
<S>                            <C>                        <C>                <C>        <C>
Interest rate
Swaps - fixed to floating      Jan 2007 - Oct 2012         US$350            5.45%      LIBOR (1) + 0.81%
                               Jan 2007 - Dec 2014         US$350            4.90%      LIBOR (1) + 0.38%
Swaps - floating to fixed      Jan 2007 - Mar 2007           C$2             7.36%      CDOR (2)
--------------------------------------------------------------------------------------------------------
</TABLE>

(1)  London Interbank Offered Rate
(2)  Canadian Deposit Overnight Rate

<PAGE>

Interest rate related derivative financial  instruments  designated as hedges at
December 31, 2006, 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.  The  Company  enters into
cross-currency  swap  agreements  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 contracts 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 10). At December 31, 2006,
the Company had the following cross-currency swap contracts outstanding:

                                     Amount     Exchange    Interest   Interest
               Remaining Term     ($ Millions) Rate(US$/C$) Rate(US$)  Rate(C$)
--------------------------------------------------------------------------------
Currency
Swaps         Jan 2007 - Aug 2016    US$250      1.116        6.00%      5.40%
--------------------------------------------------------------------------------

Cross-currency  related derivative financial instruments designated as hedges at
December 31, 2006, were all classified as cash flow hedges.

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 only entering into sales contracts with 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 nonperformance by
counterparties to derivative financial instruments; however, the Company manages
this credit risk by only entering into  agreements  with highly rated  financial
institutions and other entities.  At December 31, 2006, the Company had net risk
management  assets of $161  million  with  specific  counterparties  related  to
derivative financial instruments.

13. COMMITMENTS AND CONTINGENCIES

The Company has committed to certain payments as follows:

                                   2007    2008   2009   2010   2011  Thereafter
--------------------------------------------------------------------------------
Product transportation
    and pipeline (1)              $  213  $ 193  $ 134  $ 123  $  99     $1,042
Offshore equipment operating
   leases (2)                     $   77  $  52  $  52  $  52  $  50     $  131
Offshore drilling                 $   73  $  83  $  12  $  12  $   4     $    4
Asset retirement obligations (3)  $    3  $   3  $   3  $   4  $   4     $4,480
Office leases                     $   26  $  32  $  33  $  34  $  22     $    -
Electricity and other             $   51  $  10  $  17  $  18  $   1     $    -
--------------------------------------------------------------------------------

(1)  The Company has 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, the annual toll payments  before  operating costs will be
     approximately $35 million.

(2)  Offshore equipment  operating leases are primarily comprised of obligations
     related to  fioating  production,  storage and  offtake  vessels  ("FPSO").
     During 2006,  the Company  entered into an agreement to lease an additional
     FPSO  commencing  in  2008,  in  connection   with  the  planned   offshore
     development in Gabon,  Offshore West Africa.  The new FPSO lease  agreement
     contains cancellation  provisions at the option of the Company,  subject to
     escalating  termination  payments  throughout  2007 to a maximum  of US$395
     million.

(3)  Amounts represent management's estimate of the future undiscounted payments
     to settle  asset  retirement  obligations  related to resource  properties,
     facilities,  and production  platforms,  based on current  legislation  and
     industry operating practices.  Amounts disclosed for the period 2007 - 2011
     represent  the minimum  required  expenditures  to meet these  obligations.
     Actual  expenditures  in any  particular  year  may  exceed  these  minimum
     amounts.


In 2005, the Board of Directors  approved the construction  costs for Phase 1 of
the  Horizon  Project,  with an  approved  budget  of $6.8  billion.  Cumulative
construction spending to December 31, 2006 was approximately $4.0 billion. Final
construction  costs for  Phase 1 may  differ  from the  approved  budget  due to
changes  in the final  scope and timing of  completion  of the  project,  and/or
inflationary cost pressures.

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.

<PAGE>

14.  SUPPLEMENTAL  DISCLOSURE  OF CASH  FLOW INFORMATION

Changes in non-cash working capital were as follows:

                                                 2006          2005       2004
--------------------------------------------------------------------------------
(Increase) decrease in non-cash
   working capital
Accounts receivable and other                 $     (116)   $   (498)   $  (329)
Accounts payable                                     157         196         39
Accrued liabilities                                 (582)        716        194
--------------------------------------------------------------------------------
Net change in non-cash working capital        $     (541)   $    414    $   (96)
--------------------------------------------------------------------------------
Relating to:
Operating activities                          $     (679)   $   (147)   $   (14)
Financing activities                                  37          19          6
Investing activities                                 101         542        (88)
--------------------------------------------------------------------------------
                                              $     (541)   $    414    $   (96)
--------------------------------------------------------------------------------


Other cash flow information:                     2006          2005       2004
--------------------------------------------------------------------------------
Interest paid                                 $      262    $    200    $   192
Taxes paid                                    $      703    $    430    $   218
================================================================================

15. 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.

<PAGE>

<TABLE>
<CAPTION>

                                                             Crude Oil and Natural Gas
------------------------------------------------------------------------------------------------------------------------------
                                                  North America                North Sea               Offshore West Africa
------------------------------------------------------------------------------------------------------------------------------
                                              2006     2005     2004     2006     2005     2004    2006       2005      2004
------------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>      <C>      <C>      <C>       <C>     <C>       <C>       <C>       <C>
Segmented revenue                           $  9,066 $  8,955 $  6,701 $  1,616  $ 1,659 $  1,317  $    950  $    485  $   222
Less: royalties                               (1,203)  (1,350)  (1,003)      (3)      (3)      (2)      (39)      (13)      (6)
------------------------------------------------------------------------------------------------------------------------------
Revenue, net of royalties                      7,863    7,605    5,698    1,613    1,656    1,315       911       472       216
------------------------------------------------------------------------------------------------------------------------------
Segmented expenses
Production                                     1,436    1,211      976      390      379      370       106        53       36
Transportation and blending                    1,465    1,310      978       15       20       32         1         -        -
Depletion, depreciation and amortization       1,897    1,595    1,444      297      306      265       189       104       53
Asset retirement obligation accretion             35       34       28       31       34       22         2         1        1
Realized risk management activities            1,022      870      362      303      157      112         -         -        -
------------------------------------------------------------------------------------------------------------------------------
Total segmented expenses                       5,855    5,020    3,788    1,036      896      801       298       158       90
------------------------------------------------------------------------------------------------------------------------------
Segmented earnings before the following     $  2,008 $  2,585 $  1,910 $    577  $   760  $   514  $    613  $    314  $   126
==============================================================================================================================
Non-segmented expenses
Administration
Stock-based compensation
Interest, net
Unrealized risk management activities
Foreign exchange loss (gain)
------------------------------------------------------------------------------------------------------------------------------
Total non-segmented expenses
------------------------------------------------------------------------------------------------------------------------------
Earnings before taxes
Taxes other than income tax
Current income tax
Future income tax
------------------------------------------------------------------------------------------------------------------------------
Net earnings
==============================================================================================================================
</TABLE>

<PAGE>

<TABLE>
<CAPTION>
                                                                              Inter-segment
                                                    Midstream              elimination and other             Total
------------------------------------------------------------------------------------------------------------------------------
                                              2006     2005     2004     2006     2005     2004    2006       2005      2004
------------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>      <C>      <C>      <C>       <C>     <C>       <C>      <C>      <C>
Segmented revenue                           $     72  $    77  $    68 $    (61) $   (46) $   (39) $ 11,643 $  11,130 $  8,269
Less: royalties                                    -        -        -        -        -        -    (1,245)   (1,366)  (1,011)
------------------------------------------------------------------------------------------------------------------------------
Revenue, net of royalties                         72       77       68       (61)    (46)     (39)   10,398     9,764    7,258
------------------------------------------------------------------------------------------------------------------------------
Segmented expenses
Production                                        23       24       20       (6)      (4)      (2)    1,949     1,663    1,400
Transportation and blending                        -        -        -      (38)     (37)     (38)    1,443     1,293      972
Depletion, depreciation and amortization           8        8        7        -        -        -     2,391     2,013    1,769
Asset retirement obligation accretion              -        -        -        -        -        -        68        69       51
Realized risk management activities                -        -        -        -        -        -     1,325     1,027      474
------------------------------------------------------------------------------------------------------------------------------
Total segmented expenses                          31       32       27      (44)     (41)     (40)    7,176     6,065    4,666
------------------------------------------------------------------------------------------------------------------------------
Segmented earnings before the following     $     41  $    45  $    41 $    (17) $    (5)  $    1     3,222     3,699    2,592
------------------------------------------------------------------------------------------------------------------------------
Non-segmented expenses
Administration                                                                                          180       151      125
Stock-based compensation                                                                                139       723      249
Interest, net                                                                                           140       149      189
Unrealized risk management activities                                                                (1,013)      925      (40)
Foreign exchange loss (gain)                                                                            122      (132)     (91)
------------------------------------------------------------------------------------------------------------------------------
Total non-segmented expense                                                                            (432)    1,816      432
------------------------------------------------------------------------------------------------------------------------------
Earnings before taxes                                                                                 3,654     1,883    2,160
Taxes other than income tax                                                                             256       194      165
Current income tax                                                                                      222       286      116
Future income tax                                                                                       652       353      474
------------------------------------------------------------------------------------------------------------------------------
Net earnings                                                                                       $  2,524 $   1,050 $  1,405
==============================================================================================================================

</TABLE>

CAPITAL EXPENDITURES

<TABLE>
<CAPTION>
                                                             2006                                    2005
------------------------------------------------------------------------------------------------------------------------------
                                                           Non-cash                                 Non-cash
                                                             and                                       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                                 $ 7,936         $ 1,521      $ 9,457       $ 2,530         $ (22)    $ 2,508
North Sea                                         646             (14)         632           387          (136)        251
Offshore West Africa                              134               1          135           439            27         466
Other                                              11               -           11             5             -           5
------------------------------------------------------------------------------------------------------------------------------
                                                8,727           1,508       10,235         3,361          (131)      3,230
Horizon Project (2)                             3,185               -        3,185         1,499             -       1,499
Midstream                                          12               -           12             4             -           4
Head office                                        26               -           26            22             -          22
------------------------------------------------------------------------------------------------------------------------------
                                             $ 11,950         $ 1,508     $ 13,458       $ 4,886        $ (131)    $ 4,755
==============================================================================================================================
</TABLE>

(1)  Asset retirement obligations, future income tax adjustments on non-tax base
     assets, and other fair value adjustments.
(2)  Cash expenditures for the Horizon Project also include capitalized interest
     and stock-based compensation.

<PAGE>

Segmented property, plant and equipment, net               2006          2005
--------------------------------------------------------------------------------
Crude oil and natural gas
  North America                                         $ 21,879       $ 14,310
  North Sea                                                2,029          1,681
  Offshore West Africa                                     1,204          1,253
  Other                                                       24             13
Horizon Project                                            5,350          2,169
Midstream                                                    207            203
Head office                                                   74             65
--------------------------------------------------------------------------------
                                                        $ 30,767       $ 19,694
================================================================================

Segmented assets                                          2006           2005
--------------------------------------------------------------------------------
Crude oil and natural gas
  North America                                         $ 23,670       $ 15,939
  North Sea                                                2,248          1,950
  Offshore West Africa                                     1,323          1,371
  Other                                                       46             30
Horizon Project                                            5,444          2,239
Midstream                                                    355            258
Head office                                                   74             65
--------------------------------------------------------------------------------
                                                        $ 33,160       $ 21,852
================================================================================


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

The Company's consolidated financial statements have been prepared in accordance
with Canadian GAAP.  These principles  conform in all material  respects with US
GAAP except for those noted  below.  Certain  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:


(millions of Canadian dollars,
except per common share amounts)            Notes    2006      2005      2004
--------------------------------------------------------------------------------
Net earnings - Canadian GAAP                       $ 2,524    $ 1,050   $ 1,405
Adjustments
Depletion, net of tax of $1 million
   (2005 -$3 million, 2004 -$2 million)    (A,C)         2          4         4
Stock-based compensation, net of tax
   of $18 million (2005 -$nil, 2004 -$nil)   (B)       (40)         -         -
Derivative financial instruments and hedging
   activities, net of tax of $15 million
   (2005 -$11 million, 2004 -$7 million)     (C)       117        (19)       (9)
Capitalized interest, net of tax of $nil
   (2005 -$nil, 2004 -$11 million)           (D)         -          -        16
--------------------------------------------------------------------------------
Net earnings before cumulative effect of
   change in accounting policy - US GAAP             2,603      1,035     1,416
Cumulative effect of change in accounting
    policy, net of tax of $3 million
   (2005 -$nil,2004 -$nil)                   (B)        (8)         -         -
--------------------------------------------------------------------------------
Net earnings - US GAAP                             $ 2,595    $ 1,035   $ 1,416
--------------------------------------------------------------------------------
Net earnings before cumulative effect of
   change in accounting policy - US GAAP
   per common share
     Basic                                         $  4.84    $  1.93   $  2.64
     Diluted                                 (F)   $  4.77    $  1.88   $  2.57
--------------------------------------------------------------------------------
Net earnings - US GAAP per common share
     Basic                                         $  4.83    $  1.93   $  2.64
     Diluted                                 (F)   $  4.75    $  1.88   $  2.57
================================================================================

Comprehensive income under US GAAP would be as follows:

(millions of Canadian dollars)              Notes    2006      2005      2004
--------------------------------------------------------------------------------
Net earnings - US GAAP                             $ 2,595    $ 1,035   $ 1,416
Derivative financial instruments and
  hedging activities, net of tax of
  $394 million (2005 -$312 million;
  2004 -$3 million)                          (C)       805       (635)        8
Foreign currency translation adjustment,
  net of tax of $nil (2005 -$2 million,
  2004 -$4 million)                          (E)        (4)        (3)       (9)
--------------------------------------------------------------------------------
Comprehensive income                               $ 3,396      $ 397   $ 1,415
================================================================================

<PAGE>

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

                                                             2006
--------------------------------------------------------------------------------
                                                  Canadian  Increase
(millions of Canadian dollars)              Notes   GAAP   (Decrease)   US GAAP
--------------------------------------------------------------------------------
Current assets                               (C)  $  2,239     $  131  $  2,370
Property, plant and equipment          (A,B,C,D)    30,767         89    30,856
Other long-term assets                       (C)       154         29       183
--------------------------------------------------------------------------------
                                                  $ 33,160     $  249  $ 33,409
--------------------------------------------------------------------------------
Current liabilities                          (B)  $  3,071     $   30  $  3,101
Long-term debt                               (C)    11,043        (26)   11,017
Other long-term liabilities                  (B)     1,393         20     1,413
Future income tax                      (A,B,C,D)     6,963         21     6,984
Share capital                                        2,562          -     2,562
Retained earnings                                    8,141         45     8,186
Foreign currency translation adjustment      (E)       (13)        13         -
Accumulated other comprehensive income     (C,E)         -        146       146
--------------------------------------------------------------------------------
                                                  $ 33,160     $  249  $ 33,409
================================================================================

                                                             2005
--------------------------------------------------------------------------------
                                                  Canadian  Increase
(millions of Canadian dollars)              Notes   GAAP   (Decrease)   US GAAP
--------------------------------------------------------------------------------
Current assets                               (C)  $  2,051     $  338  $  2,389
Property, plant and equipment              (A,D)    19,694        (20)   19,674
Other long-term assets                                 107          -       107
--------------------------------------------------------------------------------
                                                  $ 21,852     $  318  $ 22,170
--------------------------------------------------------------------------------
Current liabilities                          (C)  $  3,825     $1,005  $  4,830
Long-term debt                               (C)     3,321        (18)    3,303
Other long-term liabilities                  (C)     1,434          8     1,442
Future income tax                        (A,C,D)     5,035         (5)    5,030
Share capital                                        2,442          -     2,442
Retained earnings                                    5,804        (26)    5,778
Foreign currency translation adjustment      (E)        (9)         9         -
Accumulated other comprehensive income     (C,E)         -       (655)     (655)
--------------------------------------------------------------------------------
                                                  $ 21,852      $ 318  $ 22,170
================================================================================

NOTES:

(A)  Under Canadian full cost accounting  rules,  costs capitalized in each cost
     centre  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%.  Capitalized  costs and future net revenues are
     determined on a net of tax basis. These differences in applying the ceiling
     test  to  prior  years  resulted  in  the  recognition  of a  ceiling  test
     impairment under US GAAP, decreasing property, plant and equipment.

     For the year ended  December  31,  2006,  US GAAP net  earnings  would have
     increased  by $3 million  (2005 - $4 million,  2004 - $4  million),  net of
     income  taxes of $2  million  (2005 - $3  million,  2004 - $2  million)  to
     reflect the impact of lower depletion charges.

(B)  The Company  accounts  for its  stock-based  compensation  liability  under
     Canadian GAAP using the intrinsic value method,  as described in note 1(O).
     Under US GAAP,  effective  January 1, 2006,  the Company would have adopted
     Financial  Accounting  Standards  Board  Statement  ("FAS")  123(R),  which
     requires companies to account for all stock-based  compensation liabilities
     using the fair value method,  where fair value is measured  using an option
     pricing  model.  The Company uses the Black Scholes option pricing model to
     determine the fair value of its stock-based  compensation  liability for US
     GAAP purposes.  The previous US GAAP standard,  FAS 123, required companies
     to account for cash settled stock-based  compensation liabilities using the
     intrinsic  value method.  For the year ended  December 31, 2006 US GAAP net
     earnings  would have  decreased by $48 million,  net of income taxes of $21
     million, including the cumulative effect of the change in accounting policy
     of $8 million,  net of income taxes of $3 million.  There was no difference
     from Canadian GAAP prior to 2006.

(C)  The  Company  accounts  for  its  derivative  financial  instruments  under
     Canadian  GAAP as described in note 1(P).  For US GAAP  purposes,  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

<PAGE>

     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 comprehensive  income 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 are based on a  combination  of third
     party valuations and internally derived valuations.  The Company uses these
     valuations to estimate the fair values of the underlying physical commodity
     contracts.

     For the year ended  December 31, 2006,  assets would have increased by $160
     million  (2005  -$338  million),  liabilities  would have  decreased  by $9
     million  (2005  -  increased  by  $997  million),   and  accumulated  other
     comprehensive income would have increased by $159 million (2005 - decreased
     by  $646  million)  as a  result  of  recording  all  derivative  financial
     instruments at fair value in accordance with US GAAP.

     The  net  earnings   associated   with   realized  and   unrealized   hedge
     ineffectiveness  on  derivative  contracts  designated  as cash flow hedges
     during  the year would have been $29  million,  net of income  taxes of $15
     million  (2005 - loss of $19  million,  net of income taxes of $11 million;
     2004 - loss of $9 million, net of income taxes of $7 million).  The company
     estimates that $122 million of after-tax hedging gains will be reclassified
     from  accumulated  other  comprehensive  income to current period  earnings
     within  the next  twelve  month  period  as a result  of  forecasted  sales
     occurring.

     Under Canadian GAAP, the Company hedged the foreign  currency  component of
     the US dollar purchase price of ACC using derivative financial  instruments
     formally  designated  as cash  flow  hedges.  Under  US GAAP,  the  foreign
     currency component of a business  combination is not eligible for cash flow
     hedging,  and therefore,  the $88 million  after-tax gain on the derivative
     financial  instruments and related depletion expense of $1 million,  net of
     income taxes of $1 million, would have been included in net earnings.

     Accordingly,  for the year ended  December  31,  2006 US GAAP net  earnings
     would have  increased in total by $117 million,  net of income taxes of $15
     million (2005 - decreased net earnings of $19 million,  net of income taxes
     of $11 million;  2004 - decreased net earnings of $9 million, net of income
     taxes  of $7  million)  to  reflect  the  impact  of  derivative  financial
     instruments.

(D)  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  would  have  been  capitalized  to the  costs  of
     construction  beginning in 2004.  For the year ended December 31, 2004, $27
     million would have been capitalized to property, plant and equipment for US
     GAAP.

(E)  Under US GAAP,  exchange losses of $4 million,  net of income taxes of $nil
     (2005 -$3 million, net of income taxes of $2 million; 2004 -$9 million, net
     of  income  taxes  of  $4  million)   arising  from  the   translation   of
     self-sustaining   foreign   operations   would   have  been   included   in
     comprehensive income.

(F)  Under  Canadian  GAAP,  the Company is not  required  to include  potential
     common  shares  related  to stock  options  in the  calculation  of diluted
     earnings per share since the Company has recorded the potential  settlement
     of the stock  options as a liability.  Under US GAAP FAS 128  "Earnings per
     Share",  the Company would have included potential common shares related to
     stock options in the  calculation  of diluted  earnings per share.  For the
     year ended  December 31, 2006,  an additional  8,762,000  shares would have
     been included in the calculation of diluted  earnings per share for US GAAP
     (2005 - 13,593,000 additional shares, 2004 - 10,111,000 additional shares).

(G)  Recently issued accounting standards under US GAAP:

     UNCERTAIN TAX POSITIONS

     In July 2006, the FASB issued Interpretation ("FIN") No. 48 "Accounting for
     Uncertainty  in Tax  Positions - an  Interpretation  of FASB  Statement No.
     109",  effective for fiscal years beginning after December 15, 2006. FIN 48
     prescribes  thresholds  for  recognizing  the  benefits  of  uncertain  tax
     positions  in the  financial  statements.  It  also  provides  guidance  on
     derecognition,  classification,  interest  and  penalties,  disclosure  and
     transition.  The Company is currently assessing the impact of FIN 48 on its
     consolidated financial statements.

<PAGE>

TEN-YEAR REVIEW

<TABLE>
<CAPTION>

Years ended December 31             2006      2005      2004      2003      2002      2001      2000      1999      1998      1997
----------------------------------------------------------------------------------------------------------------------------------
FINANCIAL INFORMATION
(Cdn $ millions, except
per share amounts)
----------------------------------------------------------------------------------------------------------------------------------
<S>                              <C>       <C>       <C>      <C>       <C>       <C>        <C>       <C>       <C>      <C>
Net earnings                        2,524     1,050     1,405    1,403       539       639        758       213        31      104
  Per share - basic (1)          $   4.70  $   1.96  $   2.62 $   2.62  $   1.06  $   1.32     $ 1.62  $   0.51  $   0.08 $   0.26
Cash flow from operations (2)       4,932     5,021     3,769    3,160     2,254     1,920      1,884       724       444      503
  Per share - basic (1)          $   9.18  $   9.36  $   7.03 $   5.88  $   4.41  $   3.96   $   4.04  $   1.74  $   1.12 $   1.28
----------------------------------------------------------------------------------------------------------------------------------

Capital expenditures, net of
  dispositions(including
  business combinations)           12,025     4,932     4,633    2,506     4,069     1,885      2,823     1,901       610    1,119
----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet information
Working capital(deficiency)surplus   (832)   (1,774)     (652)    (505)      (14)       (6)       (77)       36        58      (19)
 Property, plant and equipment,
  net                              30,767    19,694    17,064   13,714    12,934     8,766      7,439     4,679     3,135    2,831
Total assets                       33,160    21,852    18,372   14,643    13,793     9,290      8,051     4,976     3,329    3,016
Long-term debt                     11,043     3,321     3,538    2,748     4,200     2,788      2,573     2,157     1,426    1,136
Shareholders' equity               10,690     8,237     7,324    6,006     4,754     3,928      3,297     1,962     1,317    1,250
----------------------------------------------------------------------------------------------------------------------------------

SHARE INFORMATION
Common shares outstanding
  (thousands)                     537,903   536,348   536,361  534,926   535,104   484,804    489,116   445,816   399,236  395,276
Weighted average shares
  outstanding (thousands)         537,339   536,650   536,223  536,940   511,532   485,200    466,804   415,624   397,324  392,168
Dividends declared
  per common share               $   0.30  $   0.24  $   0.20 $   0.15  $      -  $   0.13   $   0.10   $     -  $      - $      -
----------------------------------------------------------------------------------------------------------------------------------
Trading statistics (1)
TSX-C$
Trading volume (thousands)        508,935   637,992   606,024  590,702   619,316   534,976    567,412   430,460   410,440  402,152
Share Price ($/share)
  High                           $  73.91  $  62.00  $  27.58 $  16.81  $  13.64  $  13.09   $  14.05  $   9.65  $   7.88 $  11.06
  Low                            $  45.49  $  24.28  $  15.96 $  11.30  $   9.40  $   8.98   $   7.45  $   4.95  $   4.56 $   7.23
  Close                          $  62.15  $  57.63  $  25.63 $  16.34  $  11.70  $   9.58   $  10.38  $   8.81  $   5.75 $   7.65
NYSE -US$
Trading volume (thousands)        401,909   251,554   125,468   46,916    31,864    20,764      3,172         -         -        -
Share Price ($/share)
  High                          $   64.38 $   54.05 $   22.37 $  12.85  $   8.72  $   8.63   $   9.46  $      -  $      - $      -
  Low                           $   40.29 $   19.74 $   11.94 $   7.32  $   5.89  $   5.70   $   6.19  $      -  $      - $      -
  Close                         $   53.23 $   49.62 $   21.39 $  12.61  $   7.42  $   6.10   $   6.88  $      -  $      - $      -
----------------------------------------------------------------------------------------------------------------------------------

RATIOS
Debt to book capitalization (3)      50.8%     28.7%     33.8%    32.8%     47.1%     41.7%      44.0%     52.4%     52.0%    47.6%
Return on average common
  shareholders' equity,
  after tax(3)                       26.9%     14.3%     21.4%     25.6%    13.0%     17.7%      28.8%     13.0%      2.4%     8.8%
Daily production before royalties
  per thousand common shares
  (boe/d)(1)                         10.8      10.3       9.6      8.5       8.2       7.4        6.6       5.0       4.7      4.5
Conventional proved and probable
  reserves per common share
  (boe)(1)(4)                         6.4       4.8       4.3      4.0       3.3       3.1        2.9       2.4       1.9      1.7
Net asset value per common
  share(1)(5)                   $   56.41 $   60.44 $   33.13 $  23.35  $  19.57  $  16.88   $  20.54  $  12.33  $   8.08 $   6.80
==================================================================================================================================
</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
     basedonnet  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 60,  "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 2006,  $75/acre
     for all years prior, less long-term debt and existing asset liabilities and
     adjusted for working capital. See reserves disclosures on pages 37 to 41.


<PAGE>

<TABLE>
<CAPTION>
Years ended December 31            2006      2005      2004      2003      2002      2001      2000      1999      1998      1997
----------------------------------------------------------------------------------------------------------------------------------
OPERATING INFORMATION
Conventional crude oil and NGLs (mmbbl)
----------------------------------------------------------------------------------------------------------------------------------
<S>                                 <C>       <C>       <C>      <C>         <C>       <C>        <C>       <C>       <C>      <C>
Company gross proved reserves
(before royalties)
    North America                   1,043       785       695      672       665       644        643       554       284      257
    North Sea                         299       290       303      222       203        83        102         -         -        -
    Offshore West Africa              145       148       125       106       94        61         36         -         -        -
----------------------------------------------------------------------------------------------------------------------------------
                                    1,487     1,223     1,123    1,000       962       788        781       554       284      257
----------------------------------------------------------------------------------------------------------------------------------
Company gross proved and probable
  reserves (before royalties)
    North America                   1,753     1,154       992      977       742       740        731       640       380      329
    North Sea                         421       417       415      317       277       106        134         -         -        -
    Offshore West Africa              223       230       214      187       162       111         46         -         -        -
----------------------------------------------------------------------------------------------------------------------------------
                                    2,397     1,801     1,621    1,481     1,181       957        911       640       380      329
----------------------------------------------------------------------------------------------------------------------------------
Conventional Natural gas (bcf)
----------------------------------------------------------------------------------------------------------------------------------
Company gross proved reserves
  (before royalties)
    North America                   4,507     3,378     3,202    3,006     3,048     2,566      2,360     2,183     1,901    1,716
    North Sea                          37        29        27       62        71        94         91         -         -        -
    Offshore West Africa               69        83        81       86        90        69         65         -         -        -
----------------------------------------------------------------------------------------------------------------------------------
                                    4,613     3,490     3,310    3,154     3,209     2,729      2,516     2,183     1,901    1,716
----------------------------------------------------------------------------------------------------------------------------------
Company gross proved and probable
  reserves (before royalties)
   North America                    5,898     4,372     4,100    3,611     3,450     2,915      2,762     2,547     2,211    2,078
   North Sea                           93        69        57      101        89       118        114         -         -        -
   Offshore West Africa               121       127       102      111       120        96         84         -         -        -
----------------------------------------------------------------------------------------------------------------------------------
                                    6,112     4,568     4,259    3,823     3,659     3,129      2,960     2,547     2,211    2,078
----------------------------------------------------------------------------------------------------------------------------------
Total proved reserves
(before royalties) (mmboe)          2,256     1,804     1,674    1,526     1,497     1,243      1,200       918       601      543
----------------------------------------------------------------------------------------------------------------------------------
Total proved and probable reserves
  (before royalties) (mmboe)        3,416     2,562     2,330    2,118     1,791     1,479      1,404     1,065       749      675
----------------------------------------------------------------------------------------------------------------------------------
Oil Sands, mining (mmbbl)
----------------------------------------------------------------------------------------------------------------------------------
Gross proved and probable reserves
  (before royalties)
   Bitumen                          3,530     3,430         -        -         -         -          -         -         -        -
   Synthetic crude oil (1)          2,962     2,878         -        -         -         -          -         -         -        -
----------------------------------------------------------------------------------------------------------------------------------
Daily production (before royalties)
----------------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs (mbbl/d)
    North America                     235       222       206      175       169       167        155        87        76       71
    North Sea                          60        68        65       57        39        36         17         -         -        -
    Offshore West Africa               37        23        12       10         7         3          2         -         -        -
----------------------------------------------------------------------------------------------------------------------------------
                                      332       313       283      242       215       206        174        87        76       71
----------------------------------------------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
   North America                    1,468     1,416     1,330    1,245     1,204       906        793       721       673      626
   North Sea                           15        19        50       46        27        12          1         -         -        -
   Offshore West Africa                 9         4         8        8         1         -          -         -         -        -
----------------------------------------------------------------------------------------------------------------------------------
                                    1,492     1,439     1,388    1,299     1,232       918        794       721       673      626
----------------------------------------------------------------------------------------------------------------------------------
Total production
  (before royalties) (mboe/d)         581       553       514      459       421       359        306       207       188      175
----------------------------------------------------------------------------------------------------------------------------------

Product Pricing
----------------------------------------------------------------------------------------------------------------------------------
Average crude oil
  and NGLs price ($/bbl)            53.65     46.86     37.99    32.66     31.22     23.45      31.89     22.26     11.98    18.99
Average natural
  gas price ($/mcf)                  6.72      8.57      6.50     6.21      3.77      5.45       4.92      2.52      2.11     1.97
==================================================================================================================================
</TABLE>

(1)  SCO reserves are based upon upgrading of the bitumen reserves. The reserves
     shown for bitumen and SCO are not additive.


<PAGE>


M A N A G E M E N T ' S   D I S C U S S I O N   &   A N A L Y S I S

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.  For
additional information refer to "Risks and Uncertainties" on page 64.

Disclosure related to future commodity pricing,  production volumes, royalties,
capital   expenditures  and  other  2007  guidance  provided   throughout  this
Management's Discussion and Analysis, including the information provided in the
"Outlook" section on pages 69 and 70, constitutes forward looking statements as
described above.

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 probably 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 ("MD&A") 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 net asset
value.  These financial measures are not defined by Canadian 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 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, 2006. 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 16 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  2006  financial
results  compared to 2005 and 2004,  unless otherwise  indicated.  In addition,
this discussion details the Company's capital program and outlook for 2007.

<PAGE>

Certain  figures  related  to the  presentation  of gross  revenues  and  gross
transportation  and  blending  expense  provided  for  prior  years  have  been
reclassified to conform to the presentation adopted in 2006.

Additional  information  relating to the Company,  including its quarterly MD&A
for the  year  and  three  months  ended  December  31,  2006  and  its  Annual
Information Form for the year ended December 31, 2006, is available on SEDAR at
www.sedar.com.

This MD&A is dated March 15, 2007.

ABBREVIATIONS

ACC ..............................................Anadarko Canada Corporation
AECO ..................................Alberta natural gas reference location
AIF ..................................................Annual Information Form
API .............................................American Petroleum Institute
ARO .............................................Asset retirement obligations
BBL ...................................................................barrel
BBL/D ........................................................barrels per day
BOE ................................................barrels of oil equivalent
BOE/D ......................................barrels of oil equivalent per day
BRENT ............................................................Dated Brent
C$ ..........................................................Canadian dollars
FPSO .........................Floating Production, Storage and Offtake Vessel
GAAP ................................Generally accepted accounting principles
GJ..................................................................gigajoule
HEAVY  DIFFERENTIAL ....................Heavy crude oil differential from WTI
HORIZON  PROJECT ...................................Horizon Oil Sands Project
MCF ......................................................thousand cubic feet
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
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 strives to
meet this objective by having a defined growth and 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 allocates its capital by maintaining:

    o   Balance among its products, namely natural gas, light/medium 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 financing and maintenance of 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 0 degrees  API oil,  but  receives  medium
    quality crude netbacks due to low production costs and low royalty rates.

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

    o   Blending  various  crude oil  streams  with  diluents  to  create  more
        attractive feedstock;

    o   Supporting and  participating in pipeline  expansions or new additions;
        and

    o   Supporting  and  participating  in  projects  that  will  increase  the
        conversion capacity for heavy crude oil.

Operational  discipline  and  cost  control  are  central  to the  Company.  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  dominating  core  areas  and by
maintaining high working interests in its properties.

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

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

Highlights for the year ended December 31, 2006 are as follows:

    o   Achieved record levels of net earnings;

    o   Achieved record crude oil and NGLs and natural gas production;

    o   Achieved its revised annual production  guidance for crude oil and NGLs
        and natural gas;

    o   Completed the acquisition of ACC for net cash  consideration  of $4,641
        million;

    o   Completed 57% of Phase 1 construction of the Horizon Project;

    o   Completed  all major 2006  milestones  on the  Horizon  Project  before
        winter's onset;

<PAGE>

    o   Achieved  full  recovery of the Company's  capital  investments  in the
        Primrose North and South Fields;

    o   Received Gabonese  Government  approval of its development plan for the
        Olowi PSC offshore Gabon and received  Board of Directors  sanction for
        development in November 2006;

    o   Delivered first oil from West Espoir and completed a successful  infill
        drilling campaign at East Espoir in the Company's  Offshore West Africa
        geographic segment; and

    o   Purchased  485,000  common  shares for a cost of $28 million  under the
        Company's Normal Course Issuer Bid.

<TABLE>
<CAPTION>
NET EARNING AND CASH FLOW FROM OPERATIONS
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)                                 2006            2005            2004
-------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>             <C>             <C>
Revenue, before royalties (1)                                             $ 11,643        $ 11,130        $  8,269
Net earnings                                                              $  2,524        $  1,050        $  1,405
Per common share
     - basic                                                              $   4.70        $   1.96        $   2.62
     - diluted                                                            $   4.70        $   1.95        $   2.60
Adjusted net earnings from operations (2)                                 $  1,664        $  2,034        $  1,405
Per common share
     - basic                                                              $   3.10        $   3.79        $   2.62
     - diluted                                                            $   3.10        $   3.78        $   2.60
Cash flow from operations (3)                                             $  4,932        $  5,021        $  3,769
Per common share
     - basic                                                              $   9.18        $   9.36        $   7.03
     - diluted                                                            $   9.18        $   9.33        $   6.98
Dividends declared per common share                                       $   0.30        $  0.236        $  0.200
Total assets                                                              $ 33,160        $ 21,852        $ 18,372
Total long-term liabilities                                               $ 19,399        $  9,790        $  9,196
Capital expenditures, net of dispositions                                 $ 12,025        $  4,932        $  4,633
===================================================================================================================
</TABLE>
(1) Blending costs previously netted against gross revenues in prior years have
    been reclassified to  transportation  and blending expense to conform to the
    presentation adopted in 2006.
(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)                                                                  2006            2005            2004
-------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>             <C>             <C>
Net earnings as reported                                                  $  2,524        $  1,050        $  1,405
Stock-based compensation, net of tax (a)                                        95             481             168
Unrealized risk management (gain) loss, net of tax (b)                        (674)            607             (27)
Unrealized foreign exchange loss (gain), net of tax (c)                        114             (85)            (75)
Effect of statutory tax rate changes on future income tax
liabilities (d)                                                               (395)            (19)            (66)
--------------------------------------------------------------------------------------------------------------------
Adjusted net earnings from operations                                       $   1,664     $    2,034     $    1,405
====================================================================================================================
</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, or
    are capitalized to the Horizon Project.
(b) Derivative  financial  instruments not designated as hedges are recorded at
    fair value on the 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  consolidated
    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.  Income tax rate changes
    during 2006  resulted in a reduction of future  income tax  liabilities  of
    approximately  $438 million in North America,  an increase of future income
    tax  liabilities  of  approximately  $110 million in the UK North Sea and a
    reduction of future income tax  liabilities of approximately $67 million in
    Offshore  West  Africa.  Jurisdictional  income  tax rate  changes in North
    America in 2005 resulted in a reduction of future income tax liabilities of
    $19 million (2004 -$66 million reduction).

<PAGE>

(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)                                                                  2006            2005            2004
-------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>             <C>             <C>
Net earnings                                                              $  2,524        $  1,050        $  1,405
Non-cash items:
    Depletion, depreciation and amortization                                 2,391           2,013           1,769
    Asset retirement obligation accretion                                       68              69              51
    Stock-based compensation                                                   139             723             249
    Unrealized risk management activities                                   (1,013)            925             (40)
    Unrealized  foreign  exchange loss (gain)                                  134            (103)            (94)
    Deferred  petroleum  revenue tax expense (recovery)                         37              (9)            (45)
    Future income tax                                                          652             353             474
-------------------------------------------------------------------------------------------------------------------
Cash flow from operations                                                  $ 4,932         $ 5,021         $ 3,769
===================================================================================================================
</TABLE>

In 2006, the Company reported record net earnings of $2,524 million compared to
net earnings of $1,050  million in 2005 (2004 - $1,405  million).  Net earnings
for the year ended December 31, 2006 included  unrealized  after-tax  income of
$860 million  related to the effects of risk management  activities,  statutory
tax rate  changes on future  income tax  liabilities,  fluctuations  in foreign
exchange  rates  and  stock-based   compensation  expense  (2005  -  unrealized
after-tax  expenses  of $984  million;  2004 - $nil).  Excluding  these  items,
adjusted  net earnings  from  operations  for the year ended  December 31, 2006
decreased to $1,664 million from $2,034 million in 2005 (2004 - $1,405 million)
primarily  due to  decreased  natural  gas  pricing,  increased  realized  risk
management  losses,  increased  production  expense  and  increased  depletion,
depreciation and amortization  expense,  and the impact of a stronger  Canadian
dollar  relative  to the US dollar.  These  factors  were  partially  offset by
stronger  benchmark  crude oil  pricing  and  increased  crude oil and NGLs and
natural gas sales volumes.

Operating  results in 2006 were impacted by the acquisition of ACC completed in
November  2006. The Company  completed the  acquisition of ACC, a subsidiary of
Anadarko  Petroleum  Corporation,  for net cash consideration of $4,641 million
including  working capital and other  adjustments.  Substantially  all of ACC's
land and  production  base is located in Western Canada and consists of natural
gas weighted assets.  The operating  results of ACC have been consolidated with
the results of the Company  effective  November 2006. Total production from the
ACC  properties  averaged  approximately  67,600  boe/d  for the two  months of
November and December,  while natural gas  production  from the ACC  properties
averaged approximately 354 mmcf/d.

The Company  expects that  consolidated  net earnings  will continue to reflect
significant  volatility  due to  the  impact  of  risk  management  activities,
stock-based compensation expense and fluctuations in foreign exchange rates.

The  Company's  commodity  hedging  program  reduces the risk of  volatility in
commodity  price markets and supports the  Company's  cash flow for its capital
expenditure  program throughout the Horizon Project  construction  period. This
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 expected production and
up to 25% of  production  expected  in months 25 to 48. For the purpose of this
program,  the  purchase  of crude oil put  options is in  addition to the above
parameters. In accordance with the policy,  approximately 65% of expected crude
oil volumes and  approximately  75% of expected  natural gas volumes  have been
hedged for 2007.  In addition,  77,000 bbl/d of crude oil volumes are protected
by put options for 2007 at a strike price of US$60.00  per barrel.  The Company
is extending  its hedge  program into 2008 whereby  150,000  bbl/d of crude oil
volumes have been hedged  (100,000 bbl/d of price collars with a US$60.00 floor
and 50,000 bbl/d of put options  with a US$55.00  strike  price).  In addition,
900,000 GJ/d of natural gas volumes  have been hedged  through the use of price
collars for the first  quarter of 2008  (400,000 GJ/d with a floor of $7.00 and
500,000 GJ/d with a floor of $7.50).

As effective as the Company's hedges are against reference  commodity prices, a
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, the unrealized risk management asset reflects, at December
31, 2006, the implied price  differentials  for the  non-designated  hedges for
future  periods.  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, 2006.

Due to the  changes  in crude oil and  natural  gas  forward  pricing,  and the
reversal of prior year unrealized losses, the Company recorded a net unrealized
gain  of  $1,013  million  ($674  million  after-tax)  on its  risk  management
activities for the year ended December 31, 2006 (2005 -$925 million  unrealized
loss, $607 million  after-tax;  2004 -$40 million  unrealized gain, $27 million
after-tax).  Mark-to-market  unrealized  gains  and  losses do not  impact  the
Company's current cash flow or its ability to finance ongoing capital programs.
The Company  continues to believe that its risk  management  program  meets its
objective of securing  funding for its capital  projects and does not intend to
alter its current  strategy of obtaining  price certainty for its crude oil and
natural gas sales.

<PAGE>

The Company also  recorded a $139 million ($95 million  after-tax)  stock-based
compensation  expense for the year ended  December 31, 2006 in connection  with
the 8% increase in the  Company's  share price for the year ended  December 31,
2006 (Company's  share price as at:  December 31, 2006 - C$62.15;  December 31,
2005 - C$57.63;  December 31, 2004 - C$25.63;  December 31, 2003 - C$16.34). As
required by GAAP,  the Company  records a liability for potential cash payments
to settle its  outstanding  employee  stock  options,  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  at each  balance  sheet date to reflect the changes in the market
price of the Company's  common shares and the options  exercised or surrendered
in the year, with the net change recognized in earnings, or capitalized as part
of  the  Horizon  Project  during  the  construction  period.  The  stock-based
compensation  liability reflected the Company's potential cash liability should
all the vested options be surrendered  for a cash payout at the market price on
December 31, 2006. In years when  substantial  share price changes  occur,  the
Company's  net  earnings  are subject to  significant  volatility.  The Company
utilizes its stock-based compensation plan to attract and retain employees in a
competitive environment. All employees participate in this plan.

Cash flow from  operations  for the year  ended  December  31,  2006  decreased
slightly to $4,932  million ($9.18 per common share) from $5,021 million ($9.36
per common  share) in 2005 (2004 - $3,769  million or $7.03 per common  share).
The decrease was  primarily  due to  decreased  natural gas pricing,  increased
realized risk management losses, increased production expense and the impact of
a stronger  Canadian  dollar  relative  to the US dollar.  These  factors  were
partially  offset by stronger  benchmark  crude oil pricing and increased sales
volumes.

In 2006,  the  Company's  average  sales  price  per bbl of crude  oil and NGLs
increased  to $53.65  per bbl from  $46.86  per bbl in 2005  (2004 - $37.99 per
bbl). The Company's  average  natural gas price decreased to $6.72 per mcf from
$8.57 per mcf in 2005 (2004 - $6.50 per mcf).

Total production of crude oil and NGLs before  royalties  increased to a record
331,998 bbl/d from 313,168 bbl/d in 2005 (2004 - 282,489  bbl/d).  The increase
in crude oil and NGLs production  primarily reflected increased production from
the Company's Primrose thermal projects,  the positive results from the Pelican
Lake waterflood project,  the acquisition of ACC,  development of West and East
Espoir and the full year's impact of  production  from the Baobab Field located
offshore Cote d'Ivoire. Production from the Baobab Field commenced August 2005.

Total natural gas production  before  royalties  increased to 1,492 mmcf/d from
1,439  mmcf/d in 2005  (2004 - 1,388  mmcf/d).  The  increase  in  natural  gas
production  primarily reflected  additional natural gas production from the ACC
acquisition.  The increase was partially offset by the production  decrease due
to the effects of the  Company's  strategic  reduction  in natural gas drilling
activity and increased  North  America crude oil drilling,  made in response to
sustained low natural gas prices and inflationary cost pressures.

Total crude oil and NGLs and natural gas production  volumes  before  royalties
increased to 580,724 boe/d from 552,960 boe/d in 2005 (2004 - 513,835 boe/d).

<TABLE>
<CAPTION>
OPERATING HIGHLIGHTS                                                           2006            2005           2004
------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>            <C>            <C>
Crude oil and NGLs ($/bbl) (1)
Sales price (2)                                                            $  53.65       $   46.85      $  37.99
Royalties                                                                      4.48            3.97          3.16
Production expense                                                            12.29           11.17         10.05
------------------------------------------------------------------------------------------------------------------
Netback                                                                    $  36.88       $   31.72      $  24.78
------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2)                                                            $   6.72       $    8.57      $   6.50
Royalties                                                                      1.29            1.75          1.35
Production expense                                                             0.82            0.73          0.67
------------------------------------------------------------------------------------------------------------------
Netback                                                                    $   4.61       $    6.09      $   4.48
------------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent ($/boe) (1)
Sales price (2)                                                            $  47.92       $   48.77      $  38.45
Royalties                                                                      5.89            6.82          5.37
Production expense                                                             9.14            8.21          7.35
------------------------------------------------------------------------------------------------------------------
Netback                                                                    $  32.89       $   33.74      $  25.73
==================================================================================================================
</TABLE>
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of  transportation  and blending  costs and excluding  risk  management
    activities.

<PAGE>

SUMMARY OF QUARTERLY RESULTS

The  following  is a summary of the  Company's  quarterly  results for the most
recently completed quarters:

<TABLE>
<CAPTION>
($ millions, except per common share amounts)
-----------------------------------------------------------------------------------------------------------------------
2006                                                        TOTAL       DEC 31        SEP 30       JUN 30       MAR 31
-----------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>          <C>          <C>           <C>          <C>
Revenue, before royalties (1)                            $ 11,643     $  2,826     $   3,108     $  3,041     $  2,668
Net earnings                                             $  2,524     $    313     $   1,116     $  1,038     $     57
Net earnings per common share
    - basic                                              $   4.70     $   0.58     $    2.08     $   1.93     $   0.11
    - diluted                                            $   4.70     $   0.58     $    2.08     $   1.93     $   0.11
-----------------------------------------------------------------------------------------------------------------------
<CAPTION>
2005                                                        TOTAL       DEC 31        SEP 30       JUN 30     MAR 31(2)
-----------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>          <C>          <C>           <C>          <C>
Revenue, before royalties (1)                            $ 11,130     $  3,319     $   3,163     $  2,420     $  2,228
Net earnings (loss)                                      $  1,050     $  1,104     $     151     $    219     $   (424)
Net earnings (loss) per common share
    - basic                                              $   1.96     $   2.06     $    0.28     $   0.41     $  (0.79)
    - diluted                                            $   1.95     $   2.06     $    0.28     $   0.41     $  (0.79)
=======================================================================================================================
</TABLE>
(1) Blending  costs  previously  netted against gross revenues in prior periods
    have  been  reclassified  to  transportation  expense  to  conform  to  the
    presentation adopted in the fourth quarter of 2006.
(2) Restated to reflect two-for-one share split in May 2005.

The Company's quarterly  consolidated  revenues increased 27% to $2,826 million
in the fourth quarter of 2006 from $2,228 million in the first quarter of 2005.
Quarterly  revenues during 2006 primarily  reflected  increased world benchmark
crude  oil  prices  and  increased  crude  oil and NGLs and  natural  gas sales
volumes,  partially offset by decreased natural gas prices.  Quarterly revenues
during 2005 primarily reflected increased world benchmark crude oil and natural
gas prices and increased crude oil and NGLs and natural gas sales volumes.

    o   Crude oil prices  reflected  demand growth and continuing  geopolitical
        uncertainties.  Hurricane  activity  in the Gulf of Mexico in the third
        quarter of 2005 further  contributed to increased world benchmark crude
        oil pricing.  As a result,  the Company's  realized  crude oil and NGLs
        price  increased  from C$39.81 per bbl for the first quarter of 2005 to
        C$47.27 per bbl for the fourth  quarter of 2006.  Realized  natural gas
        prices  decreased in 2006 from 2005 primarily due to decreased  heating
        demand during the winter months and decreased cooling demand during the
        summer  months.  The  Company's  realized  natural gas price  decreased
        slightly  from  C$6.68 per mcf for the first  quarter of 2005 to C$6.66
        per mcf for the fourth quarter of 2006

    o   A stronger  Canadian dollar reduced the Canadian dollar sales price the
        Company received for its crude oil sales, as crude oil prices are based
        on US dollar denominated  benchmarks.  The US / Canadian dollar average
        exchange  rate  increased  from 0.8152 for the first quarter of 2005 to
        0.8781 for the fourth quarter of 2006.

    o   Crude oil and NGLs and natural gas sales volumes increased in 2006 over
        2005. The increase in crude oil and NGLs production from 2005 primarily
        reflected  increased  production  from the Company's  Primrose  thermal
        projects,  the  positive  results  from  the  Pelican  Lake  waterflood
        project,  additional  production  volumes  from  the  ACC  acquisition,
        development  of West and East  Espoir  and the full  year's  impact  of
        production  from the  Baobab  Field  located  offshore  Cote  d'Ivoire.
        Production from the Baobab Field commenced August 2005. The increase in
        natural gas production from 2005 primarily reflected additional natural
        gas  production  from the ACC  acquisition.  The increase was partially
        offset by  production  decreases  due to the  effects of the  Company's
        strategic  reduction  in natural gas drilling  activity  and  increased
        North  America  crude oil  drilling,  made in response to sustained low
        natural gas prices and  inflationary  cost pressures.  In total,  daily
        production  increased  from 530,316  boe/d day in the first  quarter of
        2005 to 613,764 boe/d for the fourth quarter of 2006.

In addition to commodity prices and sales volumes,  quarterly net earnings were
impacted by:

    o   Increased  production  expense primarily due to the ACC acquisition and
        industry-wide inflationary cost pressures.

    o   Increased  depletion,  depreciation and amortization  expense primarily
        due to increased  finding and development  costs  associated with crude
        oil and natural gas  exploration in North America,  a higher  depletion
        base due to the acquisition of ACC and increased estimated future costs
        to develop the Company's proved undeveloped reserves.

    o   Unrealized expense  (recovery) due to the  mark-to-market  treatment of
        the Company's stock-based compensation liability.

    o   Unrealized  gains and losses from the  mark-to-market  treatment of the
        Company's   commodity   price  hedges  not  designated  as  hedges  for
        accounting purposes.

    o   Unrealized  foreign exchange gains and losses due to the fluctuation of
        the Canadian dollar in relation to the US dollar with respect to the US
        dollar  debt and working  capital in North  America  denominated  in US
        dollars,  as well as the  re-measurement of North Sea future income tax
        liabilities denominated in UK pounds sterling.

    o   Jurisdictional  corporate tax rate changes substantively enacted in the
        period.

<PAGE>

<TABLE>
<CAPTION>
BUSINESS ENVIRONMENT
(Yearly average)                                             2006           2005            2004
-------------------------------------------------------------------------------------------------
<S>                                                     <C>           <C>            <C>
WTI benchmark price (US$/bbl) (1)                       $   66.25     $    56.61     $     41.43
Dated Brent benchmark price (US$/bbl)                   $   65.18     $    54.45     $     38.28
Differential to LLB blend (US$/bbl)                     $   21.69     $    20.83     $     13.44
Differential to LLB blend as a % of WTI                       33%            37%             32%
Condensate benchmark price (US$/bbl)                    $   66.24     $    57.25     $     41.62
NYMEX benchmark price (US$/mmbtu)                       $    7.26     $     8.56     $      6.09
AECO benchmark price (C$/GJ)                            $    6.62     $     8.05     $      6.43
US/Canadian dollar average exchange rate (US$)          $  0.8818     $   0.8253     $    0.7683
=================================================================================================
</TABLE>
(1) Refers to West Texas  Intermediate  crude oil prices per barrel at Cushing,
    Oklahoma.

COMMODITY PRICES

World benchmark crude oil prices increased during the first part of 2006 due to
ongoing  demand  growth  and  geopolitical   uncertainties.   However,  pricing
significantly   declined  later  in  the  year,  reflecting  higher  crude  oil
inventories.  In December 2006, WTI averaged US$62.09 per bbl, a decline of 21%
from the record high of US$78.40  per bbl  reached in July 2006.  WTI  averaged
US$66.25  per bbl in 2006,  an increase of 17%  compared to US$56.61 per bbl in
2005 (2004 - US$41.43 per bbl).

The Company's  realized crude oil price  increased from 2005 as a result of the
increased WTI price and the narrower Heavy  Differential.  Heavy  Differentials
averaged 33% for 2006  compared to 37% for 2005 (2004 - 32%).  The narrowing of
the Heavy Differentials from 2005 was primarily due to reduced  availability of
imported grades from Venezuela and Mexico, reduced Canadian production of heavy
crude oil and the removal of logistical constraints in accessing new markets in
the US  Gulf  Coast  due to the  Pegasus  and  Spearhead  pipelines  commencing
operations during 2006. The increase in realized crude oil prices from 2005 was
partially  offset by the negative  impact of a  strengthening  Canadian  dollar
relative to the US dollar. A strengthening Canadian dollar reduces the Canadian
dollar sales price the Company  receives for its crude oil sales,  as crude oil
prices are based on US dollar denominated benchmarks.

The  Company  anticipates  continued  volatility  in the crude oil  markets  as
inventory levels remain high and given the unpredictable nature of geopolitical
events.

Brent  averaged  US$65.18  per bbl in 2006,  an  increase  of 20%  compared  to
US$54.45 per bbl in 2005 (2004 - US$38.28 per bbl).  Crude oil sales  contracts
for the  Company's  North Sea and Offshore  West Africa  segments are typically
based on Brent  pricing,  which has  benefited  from strong  European and Asian
demand in 2006.

NYMEX natural gas prices averaged  US$7.26 per mmbtu in 2006, a decrease of 15%
from  US$8.56 per mmbtu in 2005 (2004 - US$6.09 per  mmbtu).  AECO  natural gas
pricing in 2006  decreased 18% from 2005 to average C$6.62 per GJ. The decrease
in natural gas pricing in 2006 from 2005 reflected the impact of  exceptionally
mild winter  weather and  reduced  heating  demand,  relatively  stable  summer
weather and reduced cooling demand,  and the continuing  impact of high natural
gas inventory levels.

The Company  anticipates a challenging  natural gas pricing  environment in the
near term given the high storage  levels.  Longer term natural gas pricing will
continue to be largely weather dependent.

OPERATING AND CAPITAL COSTS

Strong  commodity  prices in recent years have resulted in increased demand and
costs for oilfield services worldwide. This has lead to inflationary production
and capital cost pressures  throughout the North American crude oil and natural
gas  industry,  particularly  related to natural gas drilling  activity and oil
sands  developments.  The strong commodity price  environment has also impacted
costs in  international  basins.  Specifically,  the high  demand for  offshore
drilling rigs continues and securing rigs on commercially  acceptable  terms is
an ongoing challenge.

The  oil and gas  industry  is also  experiencing  cost  pressures  related  to
increasingly  stringent  environmental  regulations,  both in North America and
internationally.  In addition,  environmental regulations in Canada intended to
reduce  greenhouse gas emissions are pending and the impact of the  legislation
is uncertain at this time.

These  increased cost  pressures and  environmental  regulations  may adversely
impact the Company's  future net earnings,  cash flow and increase the costs of
capital projects.

<TABLE>
<CAPTION>
REVENUE, BEFORE ROYALTIES
ANALYSIS OF CHANGES IN REVENUE, BEFORE ROYALTIES

                                               Changes due to                               Changes due to
($ millions)              2004    Volumes      Prices      Other        2005    Volumes     Prices        Other         2006
------------------------------------------------------------------------------------------------------------------------------
<S>                    <C>        <C>          <C>         <C>      <C>         <C>         <C>           <C>       <C>
North America
Crude oil
 and NGLs (1)          $ 3,300    $   170      $   847     $   -    $  4,317    $   198     $    747      $   -     $  5,262
Natural gas              3,401        208        1,029         -       4,638        168       (1,002)         -        3,804
------------------------------------------------------------------------------------------------------------------------------
                         6,701        378        1,876         -       8,955        366         (255)         -        9,066
------------------------------------------------------------------------------------------------------------------------------
North Sea
Crude oil and NGLs       1,223         31          382         -       1,636       (168)         132          -        1,600
Natural gas                 94        (59)         (12)        -          23         (4)          (3)         -           16
------------------------------------------------------------------------------------------------------------------------------
                         1,317        (28)         370         -       1,659       (172)         129          -        1,616
------------------------------------------------------------------------------------------------------------------------------
Offshore West Africa
Crude oil and NGLs         208        182           86         -         476        344          111          -          931
Natural gas                 14         (6)           1         -           9         12           (2)         -           19
------------------------------------------------------------------------------------------------------------------------------
                           222        176           87         -         485        356          109          -          950
------------------------------------------------------------------------------------------------------------------------------
Subtotal
Crude oil and NGLs       4,731        383        1,315         -       6,429        374          990          -        7,793
Natural Gas              3,509        143        1,018         -       4,670        176       (1,007)         -        3,839
------------------------------------------------------------------------------------------------------------------------------
                         8,240        526        2,333         -      11,099        550          (17)         -       11,632
------------------------------------------------------------------------------------------------------------------------------
Midstream                   68          -            -         9          77          -            -         (5)          72
------------------------------------------------------------------------------------------------------------------------------
Intersegment
eliminations
 and other (2)             (39)         -            -        (7)        (46)         -            -        (15)         (61)
------------------------------------------------------------------------------------------------------------------------------
Total                  $ 8,269    $   526      $ 2,333     $   2    $ 11,130    $   550     $    (17)     $ (20)    $ 11,643
==============================================================================================================================
</TABLE>
(1) Blending costs previously netted against gross revenues in prior years have
    been reclassified to  transportation  and blending expense to conform to the
    presentation adopted in 2006.
(2) Eliminates primarily internal transportation and electricity charges.

Revenue  increased 5% to $11,643  million in 2006 from $11,130  million in 2005
(2004 - $8,269 million).  The increase was primarily due to increased crude oil
and NGLs and  natural gas sales  volumes in North  America  and  Offshore  West
Africa and increased  realized crude oil and NGLs prices,  partially  offset by
decreased realized natural gas prices.

In 2006,  22% of the Company's  crude oil and natural gas revenue was generated
outside of North America (2005 - 19%; 2004 - 19%).  North Sea accounted for 14%
of crude oil and  natural  gas  revenue in 2006 (2005 - 15%;  2004 - 16%),  and
Offshore  West Africa  accounted for 8% of crude oil and natural gas revenue in
2006 (2005 - 4%; 2004 - 3%).

<TABLE>
<CAPTION>
ANALYSIS OF PRODUCT PRICES (1)
                                                                                   2006               2005               2004
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>               <C>                <C>
Crude oil and NGLs ($/bbl) (2)
North America                                                                 $   46.52         $    39.62         $    33.16
North Sea                                                                     $   72.62         $    66.57         $    51.37
Offshore West Africa                                                          $   67.99         $    59.91         $    49.05
Company average                                                               $   53.65         $    46.86         $    37.99
------------------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf) (2)
North America                                                                 $    6.77         $     8.65         $     6.61
North Sea                                                                     $    2.66         $     3.17         $     3.73
Offshore West Africa                                                          $    5.37         $     5.91         $     5.25
Company average                                                               $    6.72         $     8.57         $     6.50
------------------------------------------------------------------------------------------------------------------------------
Company average ($/boe) (2)                                                   $   47.92         $    48.77         $    38.45
------------------------------------------------------------------------------------------------------------------------------
Percentage of revenue (excluding midstream revenue)
Crude oil and NGLs                                                                   64%                54%                54%
Natural gas                                                                          36%                46%                46%
==============================================================================================================================
</TABLE>
(1) Net of  transportation  and blending  costs and excluding  risk  management
    activities.
(2) Amounts expressed on a per unit basis are based on sales volumes.

Realized  crude oil and NGLs prices  increased 14% to average $53.65 per bbl in
2006 from  $46.86 per bbl in 2005 (2004 - $37.99 per bbl).  The  increase  from
2005 was due to  increased  benchmark  crude oil prices  and a  narrower  Heavy
Differential, partially offset by the impact of a stronger Canadian dollar.

The Company's realized natural gas price decreased 22% to average $6.72 per mcf
in 2006 from  $8.57 per mcf in 2005 (2004 - $6.50 per mcf),  reflecting  record
levels of natural gas inventory in North  America,  primarily due to the impact
of  exceptionally  mild winter weather in 2006 that reduced  heating demand and
relatively stable summer weather that reduced cooling demand.

<PAGE>

NORTH AMERICA

North America realized crude oil prices increased 17% to average $46.52 per bbl
in 2006 from $39.62 per bbl in 2005 (2004 - $33.16 per bbl).  The increase from
2005 was due to  increased  benchmark  crude oil prices  and a  narrower  Heavy
Differential, partially offset by the impact of a stronger Canadian dollar.

In North  America,  the Company  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  markets,  and  working  with
refiners to add incremental heavy crude oil conversion  capacity.  During 2006,
the Company contributed  approximately  136,000 bbl/d of heavy crude oil blends
to the Western  Canadian Select ("WCS")  stream.  The Company also continues to
work with refiners to advance expansion of heavy crude oil conversion capacity,
and is working with pipeline  companies to develop new capacity to the Canadian
West  Coast  and the US Gulf  Coast  where  crude oil  cargos  can be sold on a
world-wide basis. With a view to expanding markets for its heavy crude oil, the
Company has  committed  to 25,000  bbl/d of  capacity on the Pegasus  Pipeline,
which carries crude oil to the Gulf of Mexico.  The Pegasus Pipeline is made up
of a series of segments  extending from Patoka,  Illinois to Nederland,  Texas,
near the Gulf  Coast.  The  Company's  first  sales from the  Pegasus  Pipeline
occurred in April 2006.  The Company  also  entered into an agreement to supply
25,000 bbl/d of heavy crude oil  production  to a new  merchant  upgrader to be
constructed in Alberta. The agreement is for a period of five years, with first
deliveries  anticipated to occur in 2010 upon completion of construction of the
facilities.

North America  realized  natural gas prices  decreased 22% to average $6.77 per
mcf in 2006 from $8.65 per mcf in 2005 (2004 - $6.61 per mcf), primarily due to
reduced seasonal heating demand and reduced summer cooling demand in 2006.

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

                                            2006           2005           2004
-------------------------------------------------------------------------------
Wellhead price (1) (2)
Light crude oil and NGLs (C$/bbl)       $  63.09       $  58.41       $  45.90
Pelican Lake crude oil (C$/bbl)         $  45.02       $  38.39       $  32.12
Primary heavy crude oil (C$/bbl)        $  41.35       $  33.53       $  28.99
Thermal heavy crude oil (C$/bbl)        $  40.98       $  32.29       $  29.00
Natural gas (C$/mcf)                    $   6.77       $   8.65       $   6.61
===============================================================================
(1) Net of  transportation  and blending  costs and excluding  risk  management
    activities.
(2) Amounts expressed on a per unit basis are based on sales volumes.

NORTH SEA

North Sea realized  crude oil prices  increased 9% to average $72.62 per bbl in
2006 from  $66.57  per bbl 2005 (2004 - $51.37 per bbl).  The  increase  in the
realized  crude oil price from 2005 was due  primarily  to the impact of strong
European  and  Asian  demand  on  Brent  pricing,   partially   offset  by  the
strengthening Canadian dollar in 2006 compared to 2005.

OFFSHORE WEST AFRICA

Offshore West Africa realized crude oil prices  increased 13% to average $67.99
per bbl in 2006  from  $59.91  per bbl in 2005  (2004 - $49.05  per  bbl).  The
increase in the  realized  crude oil price from 2005 was due  primarily  to the
impact of strong European and Asian demand on Brent pricing,  partially  offset
by the strengthening Canadian dollar in 2006 compared to 2005.

CRUDE OIL INVENTORY VOLUMES

The Company recognizes revenue on its crude oil production when title transfers
to the customer and delivery has taken place. The related  cumulative crude oil
inventory volumes by segment,  which have not been recognized in revenue,  were
as follows:

(bbl)                                                        2006         2005
-------------------------------------------------------------------------------
North America, related to pipeline fill                 1,097,526      484,157
North Sea, related to timing of liftings                  910,796      747,141
Offshore West Africa, related to timing of liftings       113,774      412,841
-------------------------------------------------------------------------------
                                                        2,122,096    1,644,139
===============================================================================

In 2006,  approximately  478,000 barrels of crude oil produced in the Company's
North America and international operations were added to inventory and excluded
from results of operations,  decreasing  cash flow from operations for the year
by approximately $7 million.

<PAGE>

<TABLE>
<CAPTION>
ANALYSIS OF DAILY PRODUCTION, BEFORE ROYALTIES

                                                             2006          2005           2004
-----------------------------------------------------------------------------------------------
<S>                                                       <C>           <C>            <C>
Crude oil and NGLs (bbl/d)
North America                                             235,253       221,669        206,225
North Sea                                                  60,056        68,593         64,706
Offshore West Africa                                       36,689        22,906         11,558
-----------------------------------------------------------------------------------------------
                                                          331,998       313,168        282,489
-----------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
North America                                               1,468         1,416          1,330
North Sea                                                      15            19             50
Offshore West Africa                                            9             4              8
-----------------------------------------------------------------------------------------------
                                                            1,492         1,439          1,388
-----------------------------------------------------------------------------------------------
Total barrels of oil equivalent (boe/d)                   580,724       552,960        513,835
-----------------------------------------------------------------------------------------------

Product mix
Light crude oil and NGLs                                       26%           26%            24%
Pelican Lake crude oil                                          5%            4%             4%
Primary heavy crude oil                                        16%           17%            19%
Thermal heavy crude oil                                        11%           10%             8%
Natural gas                                                    42%           43%            45%
================================================================================================

DAILY PRODUCTION, NET OF ROYALTIES                           2006          2005            2004
-----------------------------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America                                             205,382       191,751        180,011
North Sea                                                  59,940        68,487         64,598
Offshore West Africa                                       35,212        22,293         11,221
-----------------------------------------------------------------------------------------------
                                                          300,534       282,531        255,830
-----------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
North America                                               1,185         1,125          1,048
North Sea                                                      15            18             50
Offshore West Africa                                            9             4              7
-----------------------------------------------------------------------------------------------
                                                            1,209         1,147          1,105
-----------------------------------------------------------------------------------------------
Total barrels of oil equivalent (boe/d)                   502,024       473,742        440,022
===============================================================================================
</TABLE>

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/medium  crude oil and NGLs, Pelican Lake crude oil, primary
heavy crude oil and thermal heavy crude oil.

Total production of crude oil and NGLs before royalties increased 6% to 331,998
bbl/d from 313,168 bbl/d in 2005 (2004 - 282,489 bbl/d).  The increase in crude
oil and NGLs  production  from 2005  reflected  increased  production  from the
Company's Primrose thermal projects, the positive results from the Pelican Lake
waterflood  project,  additional  production  volumes from the ACC acquisition,
development  of West and East Espoir and the full year's  impact of  production
from the Baobab Field  located  offshore  Cote  d'Ivoire.  Production  from the
Baobab Field commenced  August 2005. Crude oil and NGLs production for 2006 was
in line with the Company's revised guidance of 325,000 to 336,000 bbl/d.

Natural gas  production  continues to represent the Company's  largest  product
offering.  Total natural gas production before royalties  increased 4% to 1,492
mmcf/d from 1,439 mmcf/d in 2005 (2004 - 1,388 mmcf/d). The increase in natural
gas production from 2005 primarily reflected  additional natural gas production
from the ACC  acquisition.  The increase  was  partially  offset by  production
decreases  due to the impact of the  Company's  decision to reduce  natural gas
drilling  activity in 2006, made in response to  inflationary  costs in Western
Canada.  Natural gas production for 2006 was at the bottom end of the Company's
revised guidance of 1,492 to 1,501 mmcf/d.

In 2007, annual production is forecasted to average between 315,000 and 360,000
bbl/d of crude oil and NGLs and between 1,594 and 1,664 mmcf/d of natural gas.

NORTH AMERICA

North  America crude oil and NGLs  production  in 2006  increased 6% to average
235,253 bbl/d from 221,669 bbl/d in 2005 (2004 - 206,225  bbl/d).  The increase
in  production  from 2005 was primarily  due to increased  production  from the
Company's Primrose thermal projects, the positive results from the Pelican Lake
waterflood project and the ACC acquisition.

North  America  natural gas  production  in 2006  increased 4% to average 1,468
mmcf/d from 1,416 mmcf/d in 2005 (2004 - 1,330 mmcf/d). The increase in natural
gas production  from 2005 reflected the ACC  acquisition,  partially  offset by
production  declines  due to the  Company's  decision  to  reduce  natural  gas
drilling  activity.  The ACC acquisition was completed in November with results
included  from  that  date.  To date,  the ACC  properties  are  performing  as
expected.

<PAGE>

NORTH SEA

North Sea crude oil production in 2006 was 60,056 bbl/d, a decrease of 12% from
68,593 bbl/d in 2005 (2004 - 64,706 bbl/d).  Production  levels in 2006 were in
line  with   expectations,   reflecting  the  production   effects  of  planned
maintenance shutdowns in the second half of 2006.

OFFSHORE WEST AFRICA

Offshore West Africa crude oil production in 2006 increased 60% to 36,689 bbl/d
from 22,906 bbl/d in 2005 (2004 - 11,558  bbl/d).  The  increase  from 2005 was
primarily due to the impact of a full year's  production from the Baobab Field,
first crude oil from West Espoir and a successful  infill drilling  campaign at
East Espoir.  The increase was partially  offset by continuing  challenges with
sand and solids  production at the Baobab Field that resulted in the shut in of
5 production  wells.  The Company does not plan to recomplete these wells until
such time as a deepwater rig can be secured on commercially acceptable terms.

<TABLE>
<CAPTION>
ROYALTIES
                                                    2006            2005           2004
----------------------------------------------------------------------------------------
<S>                                             <C>           <C>            <C>
Crude oil and NGLs ($/bbl) (1)
North America                                   $   5.86      $     5.37     $     4.21
North Sea                                       $   0.13      $     0.10     $     0.08
Offshore West Africa                            $   2.81      $     1.62     $     1.43
Company average                                 $   4.48      $     3.97     $     3.16
----------------------------------------------------------------------------------------
Natural gas ($/mcf) (1)
North America                                   $   1.31      $     1.78     $     1.40
North Sea                                       $     -       $       -      $        -
Offshore West Africa                            $   0.22      $     0.16     $     0.15
Company average                                 $   1.29      $     1.75     $     1.35
----------------------------------------------------------------------------------------
Company average ($/boe) (1)                     $   5.89      $     6.82     $     5.37
----------------------------------------------------------------------------------------
Percentage of revenue (2)
Crude oil and NGLs                                     8%              8%             8%
Natural gas                                           19%              20%           21%
Boe                                                   12%              14%           14%
==========================================================================================
</TABLE>
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of  transportation  and blending  costs and excluding  risk  management
    activities.

NORTH AMERICA

Crown  Royalties on a  significant  portion of North America crude oil and NGLs
production  falls under the oil sands  royalty  regime and is  calculated  on a
project by project  basis as a  percentage  of gross  revenue  less  operating,
capital and abandonment costs ("net profit"). Royalties are calculated as 1% of
gross  revenues  until the  Company's  capital  investments  in the  applicable
project are fully recovered,  at which time the royalty increases to 25% of net
profit.

Crude oil and NGLs royalties increased in 2006 primarily due to increased crude
oil prices and the full recovery of the Company's  capital  investments  in the
Primrose  North and  South  Fields in the  second  half of the year.  Upon full
recovery,  Crown royalty rates on the Primrose North and South Fields increased
from 1% of gross revenue to 25% of net profit. North America crude oil and NGLs
royalties per bbl are anticipated to be 14% to 16% of gross revenue in 2007, an
increase from 13% in 2006 (2005 - 14%; 2004 - 13%).

Natural gas royalties per mcf  decreased  from 2005  primarily due to decreased
benchmark natural gas prices.  Benchmark natural gas prices decreased primarily
in response to reduced  demand and  increased  storage  levels.  North  America
natural gas royalties per mcf are anticipated to be 21% to 23% of gross revenue
in 2007, an increase from 19% in 2006 (2005 - 21%; 2004 - 21%).

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.

OFFSHORE WEST AFRICA

Offshore  West  Africa  production  is  governed  by the  terms of the  various
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.  These  revenues  are
reported as sales  revenue.  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.  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.  The  Company's
capital  investments  in the Espoir  Field are  expected to be fully  recovered
early in 2007,  increasing royalty rates and current income taxes in accordance
with the PSCs.  The Company's  capital  investments in the Baobab Field are now
not expected to be fully recovered until  approximately 2012 due to the ongoing
production   curtailments   resulting   from   limitations   to   sand   screen
effectiveness.

<PAGE>

In  connection  with  corporate  income  tax  rate  reductions  enacted  by the
Government  of Cote  d'Ivoire  during the year that were  effective  January 1,
2006,   royalty  rates  as  a  percentage  of  gross  revenue   increased  from
approximately 3% in 2005 to  approximately 4% in 2006. As a result,  production
volumes  net of  royalties  decreased  approximately  2% in 2006 from 2005,  in
accordance  with the terms of the PSC's.  Royalty rates in 2007 are anticipated
to be 13% to 15% of gross revenue due to the  Company's  expected full recovery
of its capital investments in the Espoir Field.

PRODUCTION EXPENSE
                                            2006           2005           2004
-------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
North America                          $   11.73     $    10.49     $     8.94
North Sea                              $   17.57     $    14.94     $    14.03
Offshore West Africa                   $    7.45     $     6.50     $     7.59
Company average                        $   12.29     $    11.17     $    10.05
-------------------------------------------------------------------------------
Natural gas ($/mcf) (1)
North America                          $   0.81      $     0.71     $     0.62
North Sea                              $   1.40      $     2.44     $     2.07
Offshore West Africa                   $   1.19      $     1.05     $     1.33
Company average                        $   0.82      $     0.73     $     0.67
-------------------------------------------------------------------------------
Company average ($/boe) (1)            $   9.14      $     8.21     $     7.35
===============================================================================
(1)  Amounts expressed on a per unit basis are based on sales volumes.

NORTH AMERICA

North America crude oil and NGLs  production  expense in 2006  increased 12% to
$11.73 per bbl from $10.49 per bbl in 2005 (2004 -$8.94 per bbl).  The increase
in production  expense from 2005 was  primarily due to increased  industry wide
service  costs and  increased  cyclic  steaming  costs related to the Company's
thermal crude oil projects, due to the timing of secondary steaming cycles.

North America natural gas production expense in 2006 increased 14% to $0.81 per
mcf from $0.71 per mcf in 2005 (2004 - $0.62 per mcf),  due to  increased  cost
pressures.

Production  expense  per boe in 2007 is  anticipated  to  continue  to  reflect
industry wide inflationary cost pressures.

NORTH SEA

North Sea crude oil  production  expense  increased  on a per barrel basis from
2005  due  to  planned  maintenance  shutdowns,  varying  sales  volumes  on  a
relatively fixed cost base and the timing of liftings from various fields.

OFFSHORE WEST AFRICA

Offshore  West  Africa  crude oil  production  expense  on a per  barrel  basis
increased from 2005 primarily due to continuing  operating challenges with sand
and solids resulting in decreased production volumes at Baobab, on a relatively
fixed operating cost base.

MIDSTREAM

($ millions)                                2006           2005         2004
-------------------------------------------------------------------------------
Revenue                                  $    72        $    77       $    68
Production expense                            23             24            20
-------------------------------------------------------------------------------
Midstream cash flow                           49             53            48
Depreciation                                   8              8             7
-------------------------------------------------------------------------------
Segment earnings before taxes            $    41        $    45       $    41
===============================================================================

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.


<PAGE>

DEPLETION, DEPRECIATION AND AMORTIZATION (1)

($ millions, except per boe amounts)(2)     2006            2005         2004
------------------------------------------------------------------------------
North America                            $ 1,897         $ 1,595     $  1,444
North Sea                                    297             306          265
Offshore West Africa                         189             104           53
-------------------------------------------------------------------------------
Expense                                  $ 2,383         $ 2,005     $  1,762
 $/boe                                   $ 11.27         $ 10.02     $   9.37
===============================================================================
(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") expense in 2006 increased 19%
to $2,383  million  from $2,005  million in 2005 (2004 - $1,762  million).  The
increase  in DD&A  expense  in total  and on a boe  basis in 2006 from 2005 was
primarily as a result of increased  production  combined with overall increases
in finding  and  development  costs  associated  with crude oil and natural gas
exploration in North America, a higher depletion base due to the acquisition of
ACC,  and  increased  estimated  future costs to develop the  Company's  proved
undeveloped reserves.

ASSET RETIREMENT OBLIGATION ACCRETION

($ millions, except per boe amounts)(1)       2006          2005         2004
------------------------------------------------------------------------------
North America                              $    35       $    34      $    28
North Sea                                       31            34           22
Offshore West Africa                             2             1            1
------------------------------------------------------------------------------
Expense                                    $    68       $    69      $    51
 $/boe                                     $  0.32       $  0.34      $  0.27
==============================================================================
(1)  Amounts expressed on a per unit basis are based on sales volumes.

Accretion  expense is the increase in the carrying amount of the ARO due to the
passage of time. ARO accretion expense was comparable to 2005.

ADMINISTRATION EXPENSE

($ millions, except per boe amounts)(1)        2006         2005         2004
------------------------------------------------------------------------------
Net expense                                 $   180      $   151       $  125
    $/boe                                   $  0.85      $  0.75       $ 0.66
==============================================================================
(1)  Amounts expressed on a per unit basis are based on sales volumes.

Net  administration  expense in 2006 increased in total and on a boe basis from
2005  primarily  due to increased  insurance  premiums,  increased  staffing and
administrative costs, costs associated with the integration of ACC, and overall
inflationary cost pressures.

STOCK-BASED COMPENSATION

($ millions)                                   2006         2005         2004
------------------------------------------------------------------------------
Stock-based compensation expense             $  139       $  723       $  249
==============================================================================

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 $139  million  ($95  million  after-tax)  stock-based
compensation  expense during 2006 in connection with the 8% appreciation in the
Company's  share  price  (December  31,  2006 - C$62.15;  December  31,  2005 -
C$57.63; December 31, 2004 - C$25.63; December 31, 2003 - C$16.34). 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  (2006 - $79  million;
2005  -  $101  million;  2004  - $21  million).  The  stock-based  compensation
liability  reflected  the Company's  potential  cash  liability  should all the
vested options be surrendered for a cash payout at the market price on December
31, 2006. In periods when substantial stock price changes occur, the Company is
subject to significant earnings volatility.

For the year ended  December 31, 2006,  the Company paid $264 million for stock
options surrendered for cash settlement (December 31, 2005 - $227 million; 2004
- $80 million).

<PAGE>

<TABLE>
<CAPTION>
INTEREST EXPENSE

($ millions, except per boe amounts and interest rates)(1)        2006         2005         2004
--------------------------------------------------------------------------------------------------
<S>                                                             <C>          <C>          <C>
Interest expense, gross                                         $  336       $  221       $  189
Less: capitalized interest, Horizon Project                        196           72            -
--------------------------------------------------------------------------------------------------
Interest expense, net                                           $  140       $  149       $  189
$/boe                                                           $ 0.66       $ 0.74       $ 1.01
Average effective interst rate                                    5.7%          5.6%        5.2%
==================================================================================================
</TABLE>
(1)  Amounts expressed on a per unit basis are based on sales volumes.

Gross  interest  expense  increased  from 2005  primarily due to increased debt
levels associated with the ACC acquisition and the financing of Horizon Project
capital  expenditures.  The increase was partially  offset by the impact of the
strengthening   Canadian  dollar,  which  decreased  interest  expense  on  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 intended for trading or  speculative  purposes.
Changes in fair value of derivative  financial  instruments formally 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  formally
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 derivative financial instruments  designated
as 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.  Realized gains or losses on these contracts are
included in risk management activities. Unrealized gains or losses on commodity
price  contracts  not formally  documented  as hedges are also 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  formally  designated  as hedges are  included in interest
expense.  Gains or losses on  non-designated  interest rate swap  contracts are
included in risk management activities.

The Company  enters into  cross-currency  swap  agreements  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  the  foreign  exchange  component  of all  cross-currency  swap
contracts are included in risk  management  activities.  Gains or losses on the
interest  component of 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  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  transactions are 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 derivative  financial  instruments  that have not been accounted
for as hedges are recognized in net earnings immediately.

($ millions)                                      2006        2005        2004
-------------------------------------------------------------------------------
Realized loss (gain)
Crude oil and NGLs financial instruments      $  1,395     $   753     $   501
Natural gas financial instruments                  (70)        283           5
Interest rate swaps                                  -          (9)        (32)
-------------------------------------------------------------------------------
                                              $  1,325     $ 1,027     $   474
-------------------------------------------------------------------------------
Unrealized (gain) loss
Crude oil and NGLs financial instruments      $   (736)    $   847     $   (47)
Natural gas financial instruments                 (260)         77           -
Interest rate and currency swaps                   (17)          1           7
-------------------------------------------------------------------------------
                                              $ (1,013)    $   925     $   (40)
-------------------------------------------------------------------------------
TOTAL                                         $    312     $ 1,952     $   434
===============================================================================

<PAGE>

The  realized  losses  (gains) from crude oil and NGLs and natural gas financial
instruments  decreased  (increased)  the Company's  average  realized prices as
follows:

                                               2006         2005         2004
------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)             $  11.57      $  6.68      $  4.85

Natural gas ($/mcf) (1)                    $  (0.13)     $  0.54      $  0.01
==============================================================================
(1)  Amounts expressed on a per unit basis are based on sales volumes.

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

($ millions, except interest rates)            2006         2005         2004
-------------------------------------------------------------------------------
Interest expense as reported                 $  140       $  149       $  189

Less: realized risk management gain               -           (9)         (32)
-------------------------------------------------------------------------------
                                             $ 140        $ 140        $  157
Average effective interest rate                5.7%         5.2%          4.4%
===============================================================================

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,  the unrealized risk management asset reflected
at December 31 2006,  the implied price  differentials  for the  non-designated
hedges for future  years.  Due to changes in crude oil and  natural gas forward
pricing and the reversal of prior year unrealized  losses, the Company recorded
a net unrealized  gain of $1,013  million ($674 million  after-tax) on its risk
management  activities  in 2006 (2005 - a $925 million  unrealized  loss,  $607
million  after-tax;  2004 - a $40 million  unrealized  gain, $27 million after-
tax).

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, 2006.

In addition to the net risk management asset recognized on the balance sheet at
December 31, 2006,  the net  unrecognized  asset related to the estimated  fair
values of  derivative  financial  instruments  designated  as  hedges  was $222
million (December 31, 2005 - net unrecognized liability of $990 million).

Details relating to outstanding  derivative  financial  instruments at December
31, 2006 are disclosed in note 12 to the Company's audited annual  consolidated
financial statements as at December 31, 2006.

Effective  January 1, 2007,  the Company  will adopt new  accounting  standards
relating  to the  accounting  for  and  disclosure  of  financial  instruments.
Accordingly,   the  Company  will  record  all  of  its  derivative   financial
instruments on the balance sheet at fair value,  including those  designated as
hedges. Designated hedges are currently not recognized on the balance sheet but
are  disclosed  in the  notes to the  consolidated  financial  statements.  The
estimated effects on the Company's  consolidated balance sheet are discussed in
further detail on page 68 of this MD&A.

FOREIGN EXCHANGE

($ millions)                                  2006           2005         2004
------------------------------------------------------------------------------
Realized foreign exchange (gain) loss      $   (12)      $    (29)     $     3
Unrealized foreign exchange loss (gain)         134          (103)         (94)
------------------------------------------------------------------------------
Total                                      $    122      $   (132)     $   (91)
==============================================================================

The Company's  operating 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 decreased
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
increased  revenue  from  the  sale  of the  Company's  production.  Production
expenses are 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.

The realized  foreign exchange loss in 2006 was primarily the result of foreign
exchange rate  fluctuations on working capital items  denominated in US dollars
or UK  pounds  sterling.  The  unrealized  foreign  exchange  gain in 2006  was
primarily  related to the fluctuation of the Canadian dollar in relation to the
US dollar  with  respect  to the US dollar  debt and  working  capital in North
America  denominated in US dollars,  as well as the re-measurement of North Sea
future income tax liabilities  denominated in UK pounds sterling.  The Canadian
dollar ended the year at  US$0.8581  compared to US$0.8577 at December 31, 2005
(December 31, 2004 - US$0.8308).

<PAGE>

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.

TAXES

($ millions, except income tax rates)   2006            2005            2004
-------------------------------------------------------------------------------
Taxes other than income tax
Current                              $   219         $   203        $   210
Deferred                                  37              (9)           (45)
-------------------------------------------------------------------------------
Total                                $   256         $   194        $   165
-------------------------------------------------------------------------------

Current income tax
North America                        $   143         $    99        $   101
North Sea                                 30             155              2
Offshore West Africa                      49              32             13
-------------------------------------------------------------------------------
Total                                $   222         $   286        $   116
-------------------------------------------------------------------------------

Future income tax                    $   652         $   353        $   474
Effective income tax rate               25.7%(1)        37.8%(2)       29.6%(3)
===============================================================================
(1)  Includes the effect of the following:
     o  a charge of $110 million related to the increased  supplementary charge
        on oil and gas profits in the UK North Sea, substantively enacted early
        in 2006.
     o  a  recovery  of $438  million  due to  Canadian  Federal,  Alberta  and
        Saskatchewan corporate income tax rate reductions enacted in 2006.
     o  a recovery of $67 million due to Offshore West Africa  corporate income
        tax rate reductions enacted late in 2006.
(2) Includes  the effect of a $19 million  recovery  due to a British  Columbia
    corporate tax rate reduction enacted in 2005.
(3) Includes the effect of a $66 million  recovery due to an Alberta  corporate
    tax rate reduction enacted in 2004.

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 primarily  generated  through  partnerships,  with the related income
taxes payable in a future period.  North America current income taxes have been
provided  on the basis of the  corporate  structure  and  available  income tax
deductions  and will vary  depending  upon the  nature  and  amount of  capital
expenditures incurred in Canada in any particular year.

Income tax rate changes  during 2006  resulted in a reduction of future  income
tax liabilities of approximately $438 million in North America,  an increase of
future income tax liabilities of approximately $110 million in the UK North Sea
and a reduction of future income tax liabilities of  approximately  $67 million
in Cote d'Ivoire.

During 2005,  North America income tax rate changes  resulted in a reduction of
future income tax liabilities of approximately $19 million.

During 2004,  North America income tax rate changes  resulted in a reduction of
future income tax liabilities of approximately $66 million.

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.
As a result in 2007,  crown royalties will be fully  deductible and the Company
will no longer be eligible for resource allowance in 2007 and future years.

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

<TABLE>
<CAPTION>
($ millions, except income tax rates)                       2006         2005           2004
---------------------------------------------------------------------------------------------
<S>                                                   <C>             <C>           <C>
Income tax as reported
Current income tax                                    $      222      $   286       $    116
Future income tax expense                                    652          353            474
---------------------------------------------------------------------------------------------
                                                             874          639            590
---------------------------------------------------------------------------------------------
Provincial corporate tax rate reductions                     161           19             66
Canadian Federal and foreign corporate tax rate
reductions                                                   234            -              -
---------------------------------------------------------------------------------------------
Total                                                 $    1,269      $   658       $    656
Expected effective income tax rate before
non-recurring benefits                                      37.3%        39.0%          32.9%
=============================================================================================
</TABLE>

The effective income tax rate for 2006 decreased  slightly from 2005 due to the
effects  of the  phased  elimination  of the  resource  allowance,  the  phased
deductibility of crown royalties and foreign jurisdictional  corporate tax rate
changes  substantively  enacted  during the year.  In 2007,  based on  budgeted
prices and the current  availability  of tax pools,  the Company  expects to be
cash taxable in Canada in the amount of $45 million to $75 million.

<PAGE>

<TABLE>
<CAPTION>
NET CAPITAL EXPENDITURES (1)

($ millions)                                                         2006        2005         2004
----------------------------------------------------------------------------------------------------
<S>                                                              <C>          <C>          <C>
Expenditures on property, plant and equipment
Net property acquisitions (dispositions) (2)                     $  4,733     $  (320)     $ 1,835
Land acquisition and retention                                        210         254          120
Seismic evaluations                                                   130         132           89
Well drilling, completion and equipping                             2,340       2,000        1,394
Pipeline and production facilities                                  1,314       1,295          821
----------------------------------------------------------------------------------------------------
Total net reserve replacement expenditures                          8,727       3,361        4,259
----------------------------------------------------------------------------------------------------
Horizon Project
 Phase 1 construction costs (3)                                     2,768       1,249            -
 Phases 2 and 3 costs                                                  79           -            -
 Capitalized interest, stock-based compensation and other (3)         338         250          291
----------------------------------------------------------------------------------------------------
Total Horizon Project                                               3,185       1,499          291
----------------------------------------------------------------------------------------------------
Midstream                                                              12           4           16
Abandonments (4)                                                       75          46           32
Head office                                                            26          22           35
----------------------------------------------------------------------------------------------------
Total net capital expenditures                                   $ 12,025     $ 4,932      $ 4,633
====================================================================================================
By segment
North America                                                    $  7,936     $ 2,530      $ 3,355
North Sea                                                             646         387          608
Offshore West Africa                                                  134         439          295
Other                                                                  11           5            1
Horizon Project                                                     3,185       1,499          291
Midstream                                                              12           4           16
Abandonments (4)                                                       75          46           32
Head office                                                            26          22           35
----------------------------------------------------------------------------------------------------
TOTAL                                                            $ 12,025     $ 4,932      $ 4,633
====================================================================================================
</TABLE>

(1) Net  capital  expenditures  do not  include  non-cash  property,  plant and
    equipment additions or disposals.
(2) Includes Business Combinations.
(3) Certain  prior  period  amounts  have been  reclassified  with  respect  to
    stock-based compensation costs.
(4) Abandonments  represent expenditures to settle AROs 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  concentrates  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  in 2006 were  $12,025  million  compared  to $4,932
million in 2005 (2004 - $4,633 million).  The increase primarily  reflected the
$4,641(1)  million  acquisition  of ACC  (including  working  capital and other
adjustments)  and  continued  progress on the Company's  larger,  future growth
projects,  most notably the Horizon Project.  Excluding the ACC acquisition and
the Horizon  Project,  net  capital  expenditures  were $4,085  million in 2006
compared to $3,433  million in 2005,  reflecting  the impact of $320 million in
net  property  dispositions  in 2005,  and overall  industry-wide  inflationary
pressures in 2006.  During 2006, the Company drilled a total of 1,738 net wells
consisting  of 641 natural gas wells,  603 crude oil wells,  375  stratigraphic
test and service wells, and 119 wells that were dry. The 375 stratigraphic test
and service wells include 163  stratigraphic  test wells related to the Horizon
Project.  This  compared  to 1,882 net wells  drilled in 2005 (2004 - 1,449 net
wells). The Company achieved an overall success rate of 91% in 2006,  excluding
the stratigraphic test and service wells (2005 -93% and 2004 -91%).

(1)  The  preliminary  allocation of the ACC purchase price to assets  acquired
     and liabilities assumed based on their fair values was as follows:

-------------------------------------------------------------------------------
        Property, plant and equipment                                $  6,249
        Less - future income taxes                                     (1,438)
             - asset retirement costs                                     (56)
-------------------------------------------------------------------------------
        Consideration for crude oil and natural gas properties          4,755
        Non-cash working capital deficit assumed and other               (105)
        Long-term debt assumed                                             (9)
-------------------------------------------------------------------------------
Net purchase price - cash consideration                             $   4,641
===============================================================================

<PAGE>

NORTH AMERICA

North America, including the Horizon Project and the ACC acquisition, accounted
for  approximately  94% of the total  capital  expenditures  for the year ended
December 31, 2006 compared to approximately 83% in 2005 (2004 - 80%).

During  2006,  the Company  targeted 732 net natural gas wells,  including  181
wells in Northeast British  Columbia,  262 wells in the Northern Plains region,
177 wells in Northwest  Alberta,  and 112 wells in the Southern  Plains region.
The Company also targeted 619 net crude oil wells during the year. The majority
of these wells were  concentrated  in the Company's  crude oil Northern  Plains
region where 292 heavy crude oil wells, 144 Pelican Lake crude oil wells, and 8
light crude oil wells were drilled. Another 114 wells targeting light crude oil
were drilled  outside the Northern Plains as well as 61 thermal crude oil wells
in the Company's In-Situ Oil Sands area.

Due to significant  changes in relative  commodity prices between crude oil and
natural  gas, the Company has taken the  opportunity  to access its large crude
oil drilling  inventory to maximize  value in both the short and long term.  To
optimize  netbacks in the short term,  the  Company  will  continue to focus on
drilling  crude oil wells in 2007 and,  accordingly,  will  reduce  natural gas
drilling  activity to manage overall  capital  spending.  Deferred  natural gas
wells will be retained in the Company's prospect inventory, and will be drilled
as natural gas commodity prices improve. Drilling on ACC acquired lands will be
optimized as part of the overall capital program.

As part of the  development  of the  Company's  In-Situ Oil Sands  Assets,  the
Company is continuing to develop its Primrose thermal  projects.  At the end of
2006, the Company had drilled 186 stratigraphic  test and observation wells and
61 thermal oil wells.  With first  steaming  for the Primrose  North  expansion
commencing November 2005, overall Primrose thermal production in 2006 increased
to  approximately  64,000 bbl/d from 53,000 bbl/d in 2005.  Initial steaming of
the projects was completed late in 2006.

In November of 2005,  the Company  announced a phased  expansion of its In-Situ
Oil Sands  assets.  The next phase of this  development  is the  Primrose  East
expansion,  a new facility  located 15  kilometers  from the existing  Primrose
South  steam  plant and 25  kilometers  from the Wolf Lake  central  processing
facility.  This phase of the  expansion  is  anticipated  to add an  additional
40,000  bbl/d and  received  Board of  Director's  sanction  in 2006.  Detailed
engineering  and  procurement is currently  underway.  The Company  anticipates
receiving regulatory approval for Primrose East in the first half of 2007, with
drilling  and  construction  planned to begin in the second  half of 2007,  and
production expected to commence in 2009.

The next phase of the Company's In-Situ Oil Sands assets expansion is the Kirby
project  located 120 km north of the existing  Primrose  facilities.  The Kirby
project is anticipated to add an additional 30,000 bbl/d of production  growth.
The Company is targeting to file its formal  regulatory  application  documents
for this project in the second half of 2007.  First  steaming is anticipated to
begin in 2011.

Development  of new  acreage  and  secondary  recovery  conversion  projects at
Pelican Lake  continued as expected  through  2006.  Drilling  consisted of 144
horizontal wells, with plans to drill 132 additional  horizontal wells in 2007.
The response  from the polymer flood pilot  continues to be positive.  Based on
the  results  of the  pilot,  the  Company  commenced  the  installation  of 12
additional  polymer  skids in 2006 as part of the  approval  of the  commercial
polymer flood project.  Pelican Lake production averaged  approximately  30,000
bbl/d in 2006.

Originally  announced in the fall of 2005,  the scoping  study for the proposed
Canadian Natural  Upgrader,  outside of the Horizon  Project,  continued during
2006 and into early 2007.  The terms of reference  for this study  involved the
evaluation of product  alternatives,  location,  technology,  gasification  and
integration with existing assets using the same disciplined  approach  utilized
in the Horizon  Project.  The next steps in this process would include a Design
Basis Memorandum  ("DBM") and Engineering  Design  Specification  ("EDS") which
would be required to be completed prior to construction  and sanctioning of the
project by the Board of Directors.

Based upon the results of the scoping study,  which identified growing concerns
relating to  increased  environmental  costs for  upgraders  located in Canada,
inflationary capital cost pressures and a narrowing Heavy Differential in North
America,  the  Company  has,  at this point in time,  deferred  the DBM and EDS
pending  clarification  on the cost of future  environmental  legislation and a
more stable cost environment.

In 2007, the Company's  overall drilling  activity in North America is expected
to  comprise  approximately  423  natural  gas  wells  and 813  crude oil wells
excluding stratigraphic and service wells.

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 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.  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.

The Horizon Project  continued on schedule and on budget with  construction 57%
complete  at year end.  The  project  status  as at  December  31,  2006 was as
follows:

    o   Detailed engineering was 94% complete;

    o   Over $5.1 billion in purchase orders and contracts have been awarded to
        date;


<PAGE>

    o   Several  key  mechanical   contracts,   including  general   mechanical
        contracts for the hydrotreater and cogeneration areas, were awarded;

    o   Set 333 pipe rack modules,  essentially forming the core infrastructure
        of the plant;

    o   Mine overburden removal was approximately 35% complete; and

    o   Site preparation and underground infrastructure was completed.

In 2005, the Board of Directors of the Company approved the construction  costs
for Phase 1 of the Horizon  Project,  with an approved  budget of $6.8 billion.
Cumulative  construction  spending to December 31, 2006 was approximately  $4.0
billion.  Final  construction  costs for Phase 1 may differ  from the  approved
budget  due to  changes  in the final  scope and  timing of  completion  of the
project, and/or inflationary cost pressures.

NORTH SEA

In 2006,  the Company  continued with its planned  program of infill  drilling,
recompletions,  workovers and  waterflood  optimizations.  During 2006, 9.2 net
wells were drilled with an additional 4 net wells drilling at year end.

The  development  of the  Lyell  Field  progressed  during  the  year  with the
completion of construction,  installation and tie-in of subsea  infrastructure.
Tranche 1 of the Lyell Field development  comprises the drilling of 4 net wells
and the  workover  of 2  existing  wells.  Production  from the Lyell  Field is
expected to be at full capacity in the second half of 2007.

During  2006,  construction  of  the  Columba  E Raw  Water  Injection  project
continued. The project consists of 2 injection wells.

OFFSHORE WEST AFRICA

During 2006, 5.8 net wells were drilled with 1 well drilling at year-end.

First crude oil from West Espoir  commenced from 3 wells brought on-line during
2006. Late in the year 2 water injector wells were added.  The West Espoir area
development  drilling will continue until 2008 with producer and injector wells
being brought on-line as they are completed.

The Company purchased a 90% interest in the Olowi PSC offshore Gabon in October
2005, received Government approval of its development plan for this acquisition
early in 2006 and received  Board  sanction for  development  in November 2006.
Development plans include a FPSO handling input from 4 shallow-water  producing
platforms.  Late in 2006 the Company signed a lease agreement for a FPSO with a
primary term of ten years, commencing 2008.

<TABLE>
<CAPTION>
LIQUIDITY AND CAPITAL RESOURCES

($ millions, except ratios)                                                2006          2005         2004
-----------------------------------------------------------------------------------------------------------
<S>                                                                    <C>           <C>          <C>
Working capital deficit (1)                                            $    832      $  1,774     $    652
Long-term debt                                                         $ 11,043      $  3,321     $  3,538
-----------------------------------------------------------------------------------------------------------
Shareholders' equity
Share capital                                                          $  2,562      $  2,442     $  2,408
Retained earnings                                                         8,141         5,804        4,922
Foreign currency translation adjustment                                     (13)           (9)          (6)
-----------------------------------------------------------------------------------------------------------
Total                                                                  $ 10,690      $  8,237     $  7,324
-----------------------------------------------------------------------------------------------------------
Debt to book capitalization (2)                                            50.8%         28.7%        33.8%
Debt to market capitalization                                              24.8%          9.7%        21.4%
After tax return on average common shareholders' equity (3)                26.9%         14.3%        21.4%
After tax return on average capital employed (4)                           17.2%         10.4%        15.3%
===========================================================================================================
</TABLE>
(1) Calculated as current assets less current liabilities.
(2) Calculated  as current  and  long-term  debt;  divided by the book value of
    common shareholders' equity plus current and long-term debt.
(3) Calculated as net earnings for the year as a percentage  of average  common
    shareholders' equity for the year.
(4) 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, 2006  consisted  primarily of
cash flow from  operations,  available  credit  facilities  and  access to debt
capital markets. 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 also  dependent upon
these factors,  as well as 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 on commercially  acceptable terms, will
be sufficient to sustain its  operations and support its growth  strategy.  The
Company's  current debt  ratings are BBB (high) with a negative  trend by DBRS,
Baa2 with a stable outlook by Moody's  Investor  Services,  Inc. and BBB with a
stable outlook by Standard and Poors Corporation.

At December  31,  2006,  the Company had undrawn bank lines of credit of $1,115
million.  Details  related to the Company's  credit  facilities  outstanding at
December  31, 2006 are  disclosed  in note 5 to the  Company's  audited  annual
consolidated financial statements.

<PAGE>

At December 31, 2006, the Company's  working  capital  deficit was $832 million
and included the current portion of the stock-based  compensation  liability of
$611  million  and the  current  portion  of the net  mark-to-market  asset for
non-designated risk management financial derivative instruments of $88 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, 2006.

The Company  believes it has the necessary  financial  capacity to complete the
Horizon Project, while at the same time not compromising 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,  2006,  such  as  Baobab,  Primrose  and  West  Espoir,  and  the
acquisition of ACC, are anticipated to provide  identified growth in production
volumes in 2007 through 2009, and generate  incremental  free cash flows during
this period.

Primarily due to the  additional  debt issued to complete the ACC  acquisition,
long-term debt increased to $11,043 million at December 31, 2006,  resulting in
a debt to book capitalization  level of 50.8% as at December 31, 2006 (December
31, 2005 - 28.7%).  While this ratio is above the 35% to 45% range  targeted by
management, the Company remains committed to maintaining a strong balance sheet
and flexible  capital  structure,  and expects its debt to book  capitalization
ratio to be near the midpoint of the range in 2008.  While the Company believes
that its balance sheet has the strength and  flexibility to accommodate the ACC
acquisition,  to ensure balance sheet  strength going forward,  the Company has
hedged a significant  portion of its natural gas and crude oil  production  for
2007 and 2008 at prices that protect  investment  returns.  In the future,  the
Company  may also  consider  the  divestiture  of  non-strategic  and  non-core
properties to gain additional balance sheet flexibility.

The  Company's  commodity  hedging  program  reduces the risk of  volatility in
commodity  price markets and supports the  Company's  cash flow for its capital
expenditure  program throughout the Horizon Project  construction  period. This
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 expected production and
up to 25% of  production  expected  in months 25 to 48. For the purpose of this
program,  the  purchase  of crude oil put  options is in  addition to the above
parameters. In accordance with the policy,  approximately 65% of expected crude
oil volumes and  approximately  75% of expected  natural gas volumes  have been
hedged for 2007.  In addition,  77,000 bbl/d of crude oil volumes are protected
by put options for 2007 at a strike price of US$60.00  per barrel.  The Company
is extending  its hedge  program into 2008 whereby  150,000  bbl/d of crude oil
volumes have been hedged  (100,000 bbl/d of price collars with a US$60.00 floor
and 50,000 bbl/d of put options  with a US$55.00  strike  price).  In addition,
900,000 GJ/d of natural gas volumes  have been hedged  through the use of price
collars for the first  quarter of 2008  (400,000 GJ/d with a floor of $7.00 and
500,000 GJ/d with a floor of $7.50).

In  addition  to the  strategic  location  of the assets that ACC brings to the
Company,  this acquisition allows the Company to further high grade its project
inventory and focus capital  expenditures  in the current  highly  inflationary
service  market.  As a result of the  acquisition,  the Company has reduced its
2007  conventional  crude oil and natural gas  capital  budget by $900  million
compared to 2006 capital spending,  while maintaining the capital  expenditures
to complete Phase I of the Horizon Project.

LONG-TERM DEBT

The  Company's  long-term  debt of $11,043  million at  December  31,  2006 was
comprised of drawings under its bank credit facilities and debt issuances under
medium and long-term unsecured notes.

BANK CREDIT FACILITIES

As at  December  31,  2006 the  Company  had in  place  unsecured  bank  credit
facilities of $7,809 million, comprised of:

    o   a $100 million demand credit facility;
    o   a $500 million demand credit facility;
    o   a 3-year non-revolving syndicated credit facility of $3,850 million;
    o   a 5-year revolving syndicated credit facility of $1,825 million;
    o   a 5-year revolving syndicated credit facility of $1,500 million; and
    o   a (pound)15  million  demand credit  facility  related to the Company's
        North Sea operations.

The revolving  syndicated credit facilities are fully revolving for a period of
five years maturing June 2011. Both facilities are extendible  annually for one
year periods at the mutual  agreement  of the Company and the  lenders.  If the
facilities are not extended, the full amount of the outstanding principal would
be repayable on the maturity date.

<PAGE>

In conjunction with the closing of the acquisition of ACC, the Company executed
a $3,850 million,  three-year non-revolving syndicated credit facility maturing
in October 2009. This facility is subject to certain prepayment requirements up
to a maximum of $1,500 million.

During 2006, the Company  obtained a $500 million credit facility  repayable on
demand.

The weighted average interest rate of the bank credit facilities outstanding at
December 31, 2006, was 4.8% (2005 - 4.0%).

In addition to the outstanding debt, letters of credit and financial guarantees
aggregating  $338  million,  including  $300  million  related  to the  Horizon
Project, were outstanding at December 31, 2006.

MEDIUM-TERM NOTES

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.

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.

Subsequent to December 31, 2006,  the 7.40%  unsecured  debentures due March 1,
2007 were repaid.

SENIOR UNSECURED NOTES

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.

In December 2005, the Company repaid the US$125 million 7.69% senior  unsecured
notes due December 19, 2005.

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 August 2006, the Company  issued US$250 million of unsecured  notes maturing
August 2016 and US$450  million of  unsecured  notes  maturing  February  2037,
bearing interest at 6.00% and 6.50%,  respectively.  Concurrently,  the Company
entered into  cross-currency  interest-rate  swaps to fix the  Canadian  dollar
interest and principal  repayment  amounts on the US$250 million notes at 5.40%
and C$279  million.  Proceeds  from the  securities  issued  were used to repay
bankers' acceptances under the Company's bank credit facilities.

In November  2006, the US shelf  prospectus,  filed in June 2005, was increased
from US$2,000 million to US$3,000  million,  leaving US$2,300 million available
for issue in the United States until July 2007.

Subsequently,  on March 12, 2007, the Company  priced,  for settlement on March
19, 2007,  US$2,200  million of unsecured notes under the US shelf  prospectus,
comprised of US$1,100 million of unsecured notes maturing May 2017 and US$1,100
million of unsecured notes maturing March 2038,  bearing  interest at 5.70% and
6.25%,  respectively.  Concurrently,  the Company  entered into  cross-currency
interest-rate swaps to fix the Canadian dollar interest and principal repayment
amounts  on  US$1,100  million  of  unsecured  notes  due May 2017 at 5.10% and
C$1,287 million.  The Company also entered into a cross-currency  interest-rate
swap to fix the Canadian  dollar  interest and principal  repayment  amounts on
US$550  million of unsecured  notes due March 2038 at 5.76% and C$644  million.
Net proceeds on the debt issue will be used to repay outstanding  amounts under
the Company's bank credit facilities.

SHARE CAPITAL

As at December 31, 2006, there were 537,903,000  common shares  outstanding and
34,425,000  stock options  outstanding.  As at March 13, 2007,  the Company had
538,970,000 common shares outstanding and 31,098,000 stock options outstanding.

During 2006, the Company purchased 485,000 common shares for cancellation (2005
- 850,000 common  shares;  2004 - 873,400 common shares) at an average price of
$57.33 per common  share  (2005 - $53.29 per common  share;  2004  -$38.01  per
common share),  for a total cost of $28 million (2005 - $45 million;  2004 -$33
million) pursuant to the Normal Course Issuer Bids previously filed.

In January 2007, the Company  renewed its Normal Course Issuer Bid to purchase,
through the  facilities  of the Toronto  Stock  Exchange and the New York Stock
Exchange,  during the  12-month  period  beginning  January 24, 2007 and ending
January 23,  2008,  up to  26,941,730  common  shares or 5% of the  outstanding
common shares of the Company then outstanding on the date of the  announcement.
As at March 15, 2007, the Company had not purchased any additional shares under
the Normal Course Issuer Bid.

In March 2007,  the  Company's  Board of Directors  approved an increase in the
annual  dividend  paid by the Company to $0.34 per common  share for 2007.  The
increase  represented  a 13%  increase  from the  prior  year,  recognizes  the
stability of the Company's  cash flow,  and provides a return to  Shareholders.
This is the seventh consecutive year in which the Company has paid dividends

<PAGE>

and the sixth  consecutive year of an increase in the distribution  paid to its
Shareholders.  The dividend policy  undergoes a periodic review by the Board of
Directors and is subject to change. In February 2006, an increase in the annual
dividend  paid by the Company was  approved to $0.30 per common share for 2006.
The increase represented a 27% increase from the prior year.

COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS

In the  normal  course of  business,  the  Company  has  entered  into  various
commitments that will have an impact on the Company's future operations.  These
commitments  primarily relate to debt repayments,  operating leases relating to
office space and offshore  FPSOs and drilling rigs,  and firm  commitments  for
gathering,  processing  and  transmission  services,  as well  as  expenditures
relating to AROs. As at December 31, 2006,  no entities have been  consolidated
under the  Canadian  Institute  of Chartered  Accountants  Handbook  Accounting
Guideline 15,  "Consolidation  of Variable  Interest  Entities".  The following
table summarizes the Company's commitments as at December 31, 2006:

<TABLE>
<CAPTION>
($ millions)                                   2007         2008          2009          2010          2011    Thereafter
-------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>          <C>          <C>            <C>           <C>          <C>
Product transportation and pipeline (1)     $   213      $   193      $    134       $   123       $    99      $  1,042
Offshore equipment opeating leases (2)      $    77      $    52      $     52       $    52       $    50      $    131
Offshore drilling                           $    73      $    83      $     12       $    12       $     4      $      4
Asset retirement obligations (3)            $     3      $     3      $      3       $     4       $     4      $  4,480
Long-term debt (4)                          $   161      $    45      $  3,876       $     -       $   466      $  3,713
Office Leases                               $    26      $    32      $     33       $    34       $    22      $      -
Electricity and other                       $    51      $    10      $     17       $    18       $     1      $      -
=========================================================================================================================
</TABLE>
(1) 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) Offshore equipment  operating leases are primarily comprised of obligations
    related to FPSOs.  During  2006,  the Company  entered into an agreement to
    lease an additional FPSO commencing in 2008, in connection with the planned
    offshore  development  in Gabon,  Offshore West Africa.  The new FPSO lease
    agreement  contains  cancellation  provisions at the option of the Company,
    subject to escalating  termination payments throughout 2007 to a maximum of
    US$395 million.
(3) Amounts represent management's estimate of the future undiscounted payments
    to settle AROs related to resource properties,  facilities,  and production
    platforms,  based on current legislation and industry operating  practices.
    Amounts disclosed for the period 2007 - 2011 represent the minimum required
    expenditures  to  meet  these  obligations.   Actual  expenditures  in  any
    particular year may exceed these minimum amounts.
(4) The long-term debt represents principal repayments only. No debt repayments
    are reflected for $2,782 million of revolving bank credit  facilities due to
    the extendable nature of the facilities.

In 2005, the Board of Directors of the Company approved the construction  costs
for Phase 1 of the Horizon  Project,  with an approved  budget of $6.8 billion.
Cumulative  construction  spending to December 31, 2006 was approximately  $4.0
billion.  Final  construction  costs for Phase 1 may differ  from the  approved
budget  due to  changes  in the final  scope and  timing of  completion  of the
project, and/or inflationary cost pressures.

LEGAL PROCEEDINGS

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,  2006,  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,  as well as 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 the  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 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 its
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.

<PAGE>

For the year  ended  December  31,  2006,  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, 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  proved and probable 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
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  reserves  disclosure is contained in the  supplementary oil and gas
information  of this Annual  Report and in the  Company's  most  recent  Annual
Information Form.

(1) Conventional  crude oil, NGLs and natural gas includes all of the Company's
    light/medium,  heavy,  and thermal crude oil, natural gas, coal bed methane
    and natural gas liquids  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.

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, AROs 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   Operating  hazards and other  difficulties  inherent in the exploration
        for and production and sale of crude oil and natural gas;

    o   Success of exploration and development activities;

    o   Timing and  success of  integrating  the  business  and  operations  of
        acquired companies;

    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   Geopolitical  risks  associated  with changing  governmental  policies,
        social   instability  and  other  political,   economic  or  diplomatic
        developments in the Company's international operations; and

    o   Other circumstances affecting revenue and expenses.

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 only entering
into sales contracts and financial  derivatives  with 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.

<PAGE>

ENVIRONMENT

The crude oil and natural gas industry is experiencing incremental increases in
costs related to  environmental  regulation,  particularly in North America and
the North Sea.  Existing and expected  legislation and regulations will require
the  Company to  address  and  mitigate  the  effect of its  activities  on the
environment.   This  will  include   dismantling   production   facilities  and
remediating  damage caused by the disposal or release of specified  substances.
Increasingly  stringent laws and  regulations may have an adverse effect on the
Company's future net earnings and cash flow from operations.

The  Company's  associated  risk  management  strategies  focus on working with
legislators  and  regulators  to  ensure  that  any  new or  revised  policies,
legislation or regulations  properly reflect a balanced approach to sustainable
development.  Specific  measures in  response  to  existing or new  legislation
include a focus on the Company's energy efficiency,  air emissions  management,
released water  quality,  reduced fresh water use and the  minimization  of the
impact on the  landscape.  The  Company's  strategy  employs  an  Environmental
Management  Plan (the  "Plan"),  a detailed  copy of which is presented to, and
reviewed by, the Board of Directors annually.  The Plan is updated quarterly at
the Directors' meetings.

The Company's Plan and operating  guidelines  focus on minimizing the impact of
operations  while  meeting  regulatory   requirements  and  internal  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:

    1   Using  water-based,  environmentally  friendly  drilling  muds whenever
        possible;

    2   Implementing  cost effective ways of reducing  greenhouse gas emissions
        per unit of production;

    3   Exercising  care with respect to all waste produced  through  effective
        waste management plans; and

    4   Minimizing   produced  water  volumes  onshore  and  offshore   through
        cost-effective measures.

In  2006,  the  Company's  capital   expenditures   included  $75  million  for
abandonment  expenditures,  an  increase  from $46  million in 2005 (2004 - $32
million).

The Company's estimated undiscounted ARO at December 31, 2006 was as follows:

Estimated ARO, undiscounted ($ millions)                   2006           2005
-------------------------------------------------------------------------------
North America                                         $   2,826      $   2,050
North Sea                                                 1,543          1,185
Offshore West Africa                                        128             90
-------------------------------------------------------------------------------
                                                          4,497          3,325
North Sea PRT recovery                                     (625)         (370)
-------------------------------------------------------------------------------
                                                      $   3,872      $   2,955
===============================================================================

The  estimate of the ARO is based on  estimates  of future costs to abandon and
restore the wells,  production  facilities and offshore  production  platforms.
Factors that affect costs include number of wells  drilled,  well depth and the
specific   environmental   legislation.   The  estimated  costs  are  based  on
engineering   estimates   using  current  costs  in  accordance   with  present
legislation  and industry  operating  practice.  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. The future  abandonment costs incurred in the North Sea are
expected to result in an estimated  PRT  recovery of $625 million  (2005 - $370
million,  2004 - $600 million), as abandonment costs are an allowable deduction
in determining PRT and may be carried back to reclaim PRT previously  paid. The
expected PRT recovery reduces the Company's net abandonment liability to $3,872
million (2005 - $2,955 million).

<PAGE>

GREENHOUSE GAS AND OTHER AIR EMISSIONS

The Company is  concurrently  working with  legislators  and  regulators on the
design of new greenhouse gas emission laws and  regulations  and is pursuing an
integrated  emissions  reduction  strategy,  to ensure  the  Company is able to
comply with existing and future emission reductions  requirements.  The Company
continues to develop  strategies that will enable it to deal with the risks and
opportunities  associated with new climate change  policies.  In addition,  the
Company is working with relevant parties to ensure that new policies  encourage
innovation,  energy  efficiency,  targeted  research and development  while not
impacting competitiveness.

The Company continues to work with Canadian Federal and Provincial  governments
on the  regulatory  framework for  greenhouse  gases for larger  emitters.  The
Company is actively promoting a harmonized regulatory framework between the two
levels of  government.  Both levels of government  have indicated that existing
legislation  will be  amended  in  2007  to  create  further  requirements  for
reporting emissions,  facility-based  emission intensity targets and regulatory
compliance. Compliance with emission intensity targets is expected for 2008 and
possibly a part of 2007 for larger facilities in Alberta.

Issues  to be  resolved  include,  but are  not  limited  to:  the  outcome  of
discussions  between  the  Federal and  Provincial  Governments,  the impact of
implementing  legislation,  the  allocations  of  reduction  obligations  among
industry sectors and international developments.

Any required  reductions  in the  greenhouse  gases  emitted from the Company's
operations  could  increase  capital   expenditures  and  operating   expenses,
especially  those  related  to the  Horizon  Project  and the  Company's  other
existing and planned large oil sands projects.  This may have an adverse effect
on the Company's net earnings and cash flow from operations.

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 reported  results of 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,  substantially all
of 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 increased  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 proved and probable crude oil and natural gas reserves.
In 2006, 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 proved reserve estimates 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.

<PAGE>

ASSET RETIREMENT OBLIGATIONS

Under CICA Handbook Section 3110, Asset Retirement Obligations,  the Company is
required  to  recognize  a  liability  for the  future  retirement  obligations
associated with its 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.

The estimated fair values of ARO 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 ARO is  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 ARO is estimated  by  discounting
the  expected  future  cash  flows to settle the ARO at the  Company's  average
credit-adjusted risk-free interest rate, which is currently 6.7%. In subsequent
periods, the ARO 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  ARO,  timing  of cash  flows  to  settle  the
obligation  and future  inflation  rates could result in gains or losses on the
final settlement of the ARO.

An ARO is not  recognized  for assets with an  indeterminate  useful life (e.g.
pipeline assets) because an amount cannot be reasonably determined.  An ARO for
these  assets will be recorded in the first  period in which the lives of these
assets are determinable.

INCOME TAXES

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 as of the
consolidated  balance sheet date.  Accounting for income taxes is an inherently
complex  process that  requires  management  to interpret  frequently  changing
regulations (e.g.  changing income tax rates) and make certain  judgements with
respect to the  application  of tax law. These  interpretations  and judgements
impact the current and future income tax  provisions,  future income tax assets
and liabilities and net earnings.

RISK MANAGEMENT ACTIVITIES

The  Company  utilizes  various  instruments  to manage  its  commodity  price,
currency  and  interest  rate   exposures.   These   derivative  and  financial
instruments are not intended for trading or speculative purposes.

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.  The cash settlement amount of
the derivative  financial  instruments may vary  materially  depending upon the
underlying  crude oil and natural gas prices at the time of final settlement of
the derivative financial instruments, as compared to their mark-to-market value
at December 31, 2006.

Effective  January 1, 2007,  the Company  will adopt new  accounting  standards
relating to the  accounting for and  disclosure of financial  instruments.  The
estimated effects on the Company's  consolidated balance sheet are discussed in
further detail on page 68 of this MD&A.

PURCHASE PRICE ALLOCATIONS

The costs of business  combinations and asset acquisitions are allocated to the
underlying  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 amounts 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
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 price
forecasts among 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.

<PAGE>

CONTROL ENVIRONMENT

The Company's  management,  including the President and Chief Operating Officer
and the Chief Financial Officer and Senior Vice-President,  Finance,  evaluated
the  effectiveness  of  disclosure  controls and  procedures as at December 31,
2006,  and concluded that  disclosure  controls and procedures are effective to
ensure that  information  required to be disclosed by the Company in its annual
filings and other  reports  filed with  securities  regulatory  authorities  in
Canada and the United States is recorded,  processed,  summarized  and reported
within the time periods  specified  and such  information  is  accumulated  and
communicated to allow timely decisions regarding required disclosures.

The President and Chief Operating  Officer and the Chief Financial  Officer and
Senior Vice-President, Finance also performed an assessment of internal control
over  financial  reporting as at December 31, 2006, and concluded that internal
control over financial reporting is effective.  Further,  there were no changes
in the Company's  internal  control over financial  reporting  during 2006 that
have  materially  affected,  or are  reasonably  likely to  materially  affect,
internal controls over financial reporting.

While the Company  believes that its  disclosure  controls and  procedures  and
internal  controls  over  financial  reporting  provide a  reasonable  level of
assurance  that they are  effective,  it recognizes  that all internal  control
systems have inherent  limitations.  Because of its inherent  limitations,  the
Company's  internal  control  system may not  prevent or detect  misstatements.
Also,  projections  of any  evaluation of  effectiveness  to future periods are
subject to the risk that controls may become  inadequate  because of changes in
conditions,  or that the degree of  compliance  with the policies or procedures
may deteriorate.

NEW ACCOUNTING STANDARDS

Effective  January 1, 2007, the Company will adopt the following new accounting
standards   relating  to  the   accounting  for  and  disclosure  of  financial
instruments:

    o   Section  1530  -  "Comprehensive  Income"  introduces  the  concept  of
        comprehensive  income to  Canadian  GAAP.  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.

        Foreign currency translation adjustment,  which is currently a separate
        component  of  shareholders'  equity,  will  be  recorded  as  part  of
        accumulated other comprehensive income.

    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
        will be restated only for the foreign currency translation adjustment.

    o   Section 3855 - "Financial  Instruments - Recognition  and  Measurement"
        prescribes when a financial asset, financial liability, or nonfinancial
        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.

        The  Company  will  add  all   transaction   costs  that  are  directly
        attributable  to the  acquisition  or  issue  of a  financial  asset or
        financial  liability  to the  fair  value  of the  financial  asset  or
        financial  liability.  These  adjustments  were previously  recorded in
        deferred  charges.  Transaction  costs  added to the fair  value of the
        financial  asset or financial  liability  will be  amortized  using the
        effective interest method.

    o   Section  3865 - "Hedges"  replaces  Accounting  Guideline 13 - "Hedging
        Relationships"  and EIC 128 - "Accounting  for Trading,  Speculative or
        Non-Hedging  Derivative Financial  Instruments" and specifies how hedge
        accounting is to be applied and what  disclosures  are  necessary  when
        hedge accounting is applied.

        Adoption of this standard will require the Company to record all of its
        derivative  financial  instruments  on the balance sheet at fair value,
        including those designated as hedges.  Designated  hedges are currently
        not  recognized  on the balance sheet but are disclosed in the notes to
        the financial  statements.  The  adjustment to recognize the designated
        hedges on the balance  sheet will be recorded as an  adjustment  to the
        opening balance of retained earnings or accumulated other comprehensive
        income, as appropriate.

        Subsequently,  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.

Adoption of these  standards will have the following  estimated  effects on the
Company's consolidated balance sheet as at January 1, 2007:

($ millions)
-------------------------------------------------------------------------------
Decrease future income tax asset                                      $   (62)
Increase current portion of other long-term assets                    $   193
Decrease other long-term assets                                       $   (16)
Decrease long-term debt                                               $   (72)
Increase future income tax liability                                  $    18
Increase retained earnings                                            $    10
Increase foreign currency translation adjustment                      $    13
Increase accumulated other comprehensive income                       $   146
===============================================================================
<PAGE>

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 2007 to average between 315,000 bbl/d
and  360,000  bbl/d of crude oil and NGLs and  between  1,594  mmcf/d and 1,664
mmcf/d of natural gas.

The forecasted  capital  expenditures  in 2007 are currently  expected to be as
follows:

($ millions)                                                      2007 Forecast
-------------------------------------------------------------------------------
North America natural gas                                            $   1,111
North America crude oil and NGLs                                         1,350
North Sea                                                                  521
Offshore West Africa                                                       114
Property acquisitions and midstream                                         16
-------------------------------------------------------------------------------
                                                                         3,112
Horizon Project Phase 1 construction (1)                                 2,610
Capitalized interest and other items                                       397
Horizon Project Phases 2/3 engineering                                     109
Canadian Natural Upgrader engineering                                        5
-------------------------------------------------------------------------------
Total                                                                $   6,233
===============================================================================
(1) Forecast to be in the range of $2,410 million to $2,810  million,  the final
    level  of  expenditure  will be  dependent  upon  the  ability  of  certain
    contractors  to advance  portions of their  efforts  from 2008 into 2007 as
    well as the extent of any  realized  cost  pressures  on  certain  isolated
    portions of the Horizon Project.

NORTH AMERICA NATURAL GAS

The 2007 North  America  natural gas  drilling  program is  highlighted  by the
high-grading of the Company's natural gas asset base,  including the properties
acquired through the ACC acquisition, as follows:

(number of wells)                                                 2007 Forecast
-------------------------------------------------------------------------------
Northeast British Columbia                                                  58
Northwest Alberta                                                          123
Northern Plains                                                            172
Southern Plains                                                             70
-------------------------------------------------------------------------------
Total                                                                      423
===============================================================================

NORTH AMERICA CRUDE OIL AND NGLS

The 2007 North America crude oil drilling  program is  highlighted by continued
development  of its  Primrose  thermal  projects,  Pelican  Lake,  and a strong
conventional heavy program, as follows:

(number of wells)                                                 2007 Forecast
-------------------------------------------------------------------------------
Conventional heavy crude oil                                               369
Thermal heavy crude oil                                                     58
Light crude oil                                                            107
Pelican Lake crude oil                                                     132
-------------------------------------------------------------------------------
Total                                                                      666
===============================================================================

The  Company  has   reduced   forecasted   natural  gas  capital  for  2007  by
approximately  40% from 2006 levels due to the shift in capital  allocation  to
higher  return crude oil projects in the near term.  Allocation  of natural gas
capital  between  existing and newly acquired ACC lands will be the result of a
high-grading process focusing on the highest return projects. No changes to the
long-term natural gas plans of the Company are being contemplated.

The  Company  continues  the  disciplined  development  of its heavy  crude oil
resources.  Crude oil  capital  has been  maintained  with  2006  levels as the
Company  continues to develop  long-term  production growth projects at Pelican
Lake and in-situ oilsands at Primrose and Kirby.

THE HORIZON PROJECT

The final level of capital expenditure on the Horizon Project will be dependent
upon the  ability of certain of the  contractors  to advance  portions of their
efforts  from 2008  into  2007,  as well as the  extent  of any  realized  cost
pressures on certain isolated portions of the project.

The 2007 capital  forecast for the Horizon  Project  targets the  completion of
most major plants with the commissioning process to be substantially  underway.
The Ore Preparation  Plant and Tailings Systems are targeted to be mechanically
complete and ready to commission

<PAGE>

with the majority of utilities and offsite systems operational. The Upgrader is
targeted to be nearing completion, with half of the related plants completed. A
total of 156 stratigraphic test wells are targeted to be drilled on the Horizon
Project leases during 2007.

NORTH SEA

The 2007  capital  forecast  for the North Sea  includes  drilling 7.4 producer
wells and 7.2 service wells. The development of the Lyell Field is targeted for
completion in late 2007.

OFFSHORE WEST AFRICA

The 2007  capital  forecast  for  Offshore  West Africa  includes  drilling 3.0
producer wells and 1.2 service well at West Espoir.

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 2006,  and is not  necessarily  indicative of future  results.  Each
separate line item in the sensitivity  analysis shows the effect of a change in
that variable only; all other variables are held constant.

<TABLE>
<CAPTION>
                                                  CASH FLOW         CASH FLOW
                                                       FROM              FROM            NET                NET
                                                 OPERATIONS        OPERATIONS       EARNINGS           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                 $    116        $      0.22       $     81      $      0.15
   Including financial derivatives                 $ 26-110        $ 0.05-0.21       $  20-77      $ 0.04-0.14
Natural gas - AECO C$0.10/mcf (2)
   Excluding financial derivatives                 $     26        $      0.05       $     14      $      0.03
   Including financial derivatives                 $    1-8        $ 0.00-0.02       $    2-4      $ 0.00-0.01
Volume changes
Crude oil - 10,000 bbl/d                           $     98        $      0.18       $     44      $      0.08
Natural gas - 10 mmcf/d                            $     17        $      0.03       $      6      $      0.01
Foreign currency rate change
$0.01 change in C$ in relation to US$ (2)
Excluding financial derivatives                    $  80-82        $      0.15       $  23-24      $      0.04
Interest rate change - 1%                          $     48        $      0.09       $     48      $      0.09
=================================================================================================================
</TABLE>
(1) The  sensitivities  are calculated based on 2006 fourth quarter results and
    exclude mark-to-market gains (losses) on risk management activities.
(2) For  details  of  financial  instruments  in place,  refer to note 12 to the
    Company's audited annual  consolidated  financial  statements as at December
    31, 2006.

<TABLE>
<CAPTION>
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES

                                                     Q1         Q2         Q3         Q4       2006       2005        2004
---------------------------------------------------------------------------------------------------------------------------
<S>                                             <C>        <C>        <C>        <C>        <C>        <C>         <C>
Crude oil and NGLs (bbl/d)
North America                                   222,955    234,780    233,440    249,565    235,253    221,669     206,225
North Sea                                        60,802     63,703     53,988     61,786     60,056     68,593      64,706
Offshore West Africa                             39,905     40,369     34,237     32,354     36,689     22,906      11,558
---------------------------------------------------------------------------------------------------------------------------
Total                                           323,662    338,852    321,665    343,705    331,998    313,168     282,489
---------------------------------------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
North America                                     1,411      1,448      1,416      1,594      1,468      1,416       1,330
North Sea                                            17         17         11         16         15         19          50
Offshore West Africa                                  8         10         10         10          9          4           8
---------------------------------------------------------------------------------------------------------------------------
Total                                             1,436      1,475      1,437      1,620      1,492      1,439       1,388
---------------------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent (boe/d)
North America                                   458,158    476,143    469,440    515,313    479,891    457,695     427,936
North Sea                                        63,589     66,426     55,790     64,490     62,558     71,651      73,093
Offshore West Africa                             41,280     42,042     35,922     33,961     38,275     23,614      12,806
---------------------------------------------------------------------------------------------------------------------------
Total                                           563,027    584,611    561,152    613,764    580,724    552,960     513,835
===========================================================================================================================
</TABLE>

<PAGE>

<TABLE>
<CAPTION>
PER UNIT RESULTS (1)
                                           Q1           Q2            Q3           Q4       2006           2005         2004
------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>          <C>           <C>          <C>        <C>            <C>          <C>
Crude oil and NGLs ($/bbl)
Sales price (2)                      $  43.79     $  60.05      $  62.55     $  47.27   $  53.65       $  46.86     $  37.99
Royalties                                3.48         5.14          5.11         4.10       4.48           3.97         3.16
Production expense                      11.33        11.92         13.47        12.32      12.29          11.17        10.05
------------------------------------------------------------------------------------------------------------------------------
Netback                              $  28.98     $  42.99      $  43.97     $  30.85   $  36.88       $  31.72     $  24.78
------------------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (2)                      $   8.30     $   6.16      $   5.83     $   6.66   $   6.72       $   8.57     $   6.50
Royalties                                1.70         1.11          1.11         1.26       1.29           1.75         1.35
Production expense                       0.80         0.80          0.84         0.86       0.82           0.73         0.67
------------------------------------------------------------------------------------------------------------------------------
Netback                              $   5.80     $   4.25      $   3.88     $   4.54   $   4.61       $   6.09     $   4.48
------------------------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent ($/boe)
Sales price (2)                      $  46.30     $  50.36      $  51.21     $  43.91   $  47.92       $  48.77     $  38.45
Royalties                                6.44         5.80          5.75         5.62       5.89           6.82         5.37
Production expense                       8.46         8.85         10.01         9.16       9.14           8.21         7.35
------------------------------------------------------------------------------------------------------------------------------
Netback                              $  31.40     $  35.71      $  35.45     $  29.13   $  32.89       $  33.74     $  25.73
==============================================================================================================================
</TABLE>
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of  transportation  and blending  costs and excluding  risk  management
    activities.

NETBACK ANALYSIS

($/boe) (1)                                     2006         2005          2004
-------------------------------------------------------------------------------
Sales price (2)                              $ 47.92     $  48.77     $  38.45
Royalties                                       5.89         6.82         5.37
Production expense (3)                          9.14         8.21         7.35
-------------------------------------------------------------------------------
Netback                                        32.89        33.74        25.73
Midstream contribution (3)                     (0.23)       (0.26)       (0.26)
Administration (4)                              0.85         0.75         0.66
Interest, net                                   0.66         0.74         1.01
Realized risk management activities             6.27         5.13         2.52
Realized foreign exchange (gain) loss          (0.06)       (0.15)        0.02
Taxes other than income tax - current           1.04         1.01         1.12
Current income tax - North America              0.68         0.50         0.53
Current income tax - North Sea                  0.14         0.77         0.01
Current income tax - Offshore West Africa       0.23         0.17         0.07
-------------------------------------------------------------------------------
Cash flow                                    $ 23.31     $  25.08     $  20.05
===============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of  transportation  and blending  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     2006 TOTAL     2005 Total
------------------------------------------------------------------------------------------------------------------------
<S>                                    <C>            <C>          <C>          <C>            <C>                <C>
TSX-C$
Trading volume (thousands)               134,487        129,036      127,022      118,390        508,935        637,992
Share price ($/share)
High                                   $   73.91      $   72.70    $   63.30    $   63.50      $   73.91      $   62.00
Low                                    $   57.75      $   50.78    $   47.28    $   45.49      $   45.49      $   24.28
Close                                  $   64.90      $   61.72    $   50.94    $   62.15      $   62.15      $   57.63
Market capitalization
 at December 31 ($ millions)                                                                   $  33,431      $  30,910
------------------------------------------------------------------------------------------------------------------------
Shares outstanding (thousands)                                                                   537,903        536,348
------------------------------------------------------------------------------------------------------------------------
NYSE - US$
Trading volume (thousands)                78,836        102,472      101,438      119,163        401,909        251,554
Share price ($/share)
High                                   $   64.38      $   63.93    $   56.68    $   55.48      $   64.38      $   54.05
Low                                    $   49.62      $   45.67    $   42.38    $   40.29      $   40.29      $   19.74
Close                                  $   55.39      $   55.38    $   45.58    $   53.23      $   53.23      $   49.62
Market capitalization at
 December 31 ($ millions)                                                                      $  28,633      $  26,614
------------------------------------------------------------------------------------------------------------------------
Shares outstanding (thousands)                                                                   537,903        536,348
========================================================================================================================
</TABLE>

<PAGE>


MANAGEMENT'S REPORT


The accompanying  consolidated  financial  statements and all other information
contained elsewhere in this annual report are the responsibility of management.
The  consolidated  financial  statements  have been  prepared by  management in
accordance with the accounting  policies  described in the accompanying  notes.
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  presented  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  and recorded,  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 audit and provide their  independent  audit
opinions on the following:

    o   the  Company's  consolidated  financial  statements  as at December 31,
        2006;

    o   the  effectiveness  of the Company's  internal  control over  financial
        reporting as at December 31, 2006; and

    o   management's   assessment  of  the  Company's   internal  control  over
        financial reporting as at December 31, 2006.

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,  which is  comprised  of  non-management  directors.  The  Audit
Committee meets with management and the independent  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                 Chief Financial Officer &               Vice President, Finance & Accounting
Operating Officer                 Senior Vice-President, Finance
</TABLE>

March 15, 2007
Calgary, Alberta, Canada

<PAGE>


MANAGEMENT'S ASSESSMENT OF INTERNAL
CONTROL OVER FINANCIAL REPORTING


Management is responsible for  establishing and maintaining  adequate  internal
control over financial reporting for the Company as defined in Rule 15(d)-15(f)
under the United States Securities Exchange Act of 1934, as amended.

Management,  together with the Company's  President and Chief Operating Officer
and the Company's Chief Financial Officer and Senior  Vice-President,  Finance,
performed an  assessment  of the  Company's  internal  control  over  financial
reporting  based on the criteria  established in Internal  Control - Integrated
Framework  issued by the Committee of Sponsoring  Organizations of the Treadway
Commission (COSO).

Based on the assessment,  management, together with the Company's President and
Chief Operating  Officer and the Company's  Chief Financial  Officer and Senior
Vice-President, Finance, has concluded that the Company's internal control over
financial reporting is effective as at December 31, 2006. Management recognizes
that all internal  control  systems have inherent  limitations.  Because of its
inherent limitations, internal control over financial reporting may not prevent
or detect misstatements.  Also,  projections of any evaluation of effectiveness
to future  periods are subject to the risk that controls may become  inadequate
because of changes in  conditions,  or that the degree of  compliance  with the
policies or procedures may deteriorate.

Management's  assessment of the effectiveness of the Company's internal control
over  financial  reporting  as at  December  31,  2006,  has  been  audited  by
PricewaterhouseCoopers  LLP,  independent  auditors,  as stated in their report
presented with the audited consolidated financial statements.



/s/ Steve W. Laut                             /s/ Douglas A. Proll
---------------------                         ----------------------------
Steve W. Laut                                 Douglas A. Proll, CA
President & Chief Operating Officer           Chief Financial Officer &
                                              Senior Vice-President, Finance
March 15, 2007
Calgary, Alberta, Canada



<PAGE>

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


To the Shareholders of Canadian Natural Resources Limited

We have completed an integrated audit of the consolidated  financial statements
and internal  control over financial  reporting of Canadian  Natural  Resources
Limited (the  "Company") as of December 31, 2006 and audits of its December 31,
2005 and December 31, 2004  consolidated  financial  statements.  Our opinions,
based on our audits, are presented below.

CONSOLIDATED FINANCIAL STATEMENTS

We have audited the accompanying  consolidated balance sheets of the Company as
of December  31,  2006 and  December  31,  2005,  and the related  consolidated
statements of earnings,  retained earnings and cash flows for each of the three
years in the period ended December 31, 2006. These 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 audit of the Company's financial statements as of December 31,
2006 and for the year then ended in accordance with Canadian generally accepted
auditing standards and the standards of the Public Company Accounting Oversight
Board  (United  States).  We conducted  our audits of the  Company's  financial
statements  as of December 31, 2005 and for each of the two years in the period
ended December 31, 2005 in accordance with Canadian generally accepted auditing
standards.  Those standards require that we plan and perform an audit to obtain
reasonable  assurance  about  whether  the  financial  statements  are  free of
material misstatement.  An audit of financial statements includes examining, on
a test basis,  evidence supporting the amounts and disclosures in the financial
statements.  A financial statement audit also includes assessing the accounting
principles  used and significant  estimates made by management,  and evaluating
the overall financial statement presentation.

In our opinion, the consolidated financial statements referred to above present
fairly, in all material  respects,  the financial position of the Company as of
December 31, 2006 and December 31, 2005 and the results of its  operations  and
its cash flows for each of the three  years in the period  ended  December  31,
2006 in accordance with Canadian generally accepted accounting principles.

INTERNAL CONTROL OVER FINANCIAL REPORTING

We have also  audited  management's  assessment,  included in the  accompanying
management's assessment of internal control over financial reporting,  that the
Company maintained  effective  internal control over financial  reporting as of
December  31,  2006,   based  on  criteria   established  in  Internal  Control
-Integrated  Framework  issued by the Committee of Sponsoring  Organizations of
the Treadway  Commission  (COSO).  The Company's  management is responsible for
maintaining  effective  internal  control over financial  reporting and for its
assessment of the  effectiveness of internal control over financial  reporting.
Our responsibility is to express opinions on management's assessment and on the
effectiveness of the Company's internal control over financial  reporting based
on our audit.

We  conducted  our  audit of  internal  control  over  financial  reporting  in
accordance with the standards of the Public Company Accounting  Oversight Board
(United States).  Those standards require that we plan and perform the audit to
obtain  reasonable  assurance  about whether  effective  internal  control over
financial  reporting  was  maintained  in all  material  respects.  An audit of
internal control over financial  reporting  includes obtaining an understanding
of  internal  control  over  financial   reporting,   evaluating   management's
assessment,  testing and evaluating the design and operating  effectiveness  of
internal control, and performing such other procedures as we consider necessary
in the circumstances. We believe that our audit provides a reasonable basis for
our opinions.

A company's internal control over financial  reporting is a process designed to
provide reasonable  assurance  regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally  accepted  accounting  principles.  A company's internal control
over  financial  reporting  includes  those  policies and  procedures  that (i)
pertain to the  maintenance of records that, in reasonable  detail,  accurately
and fairly  reflect  the  transactions  and  dispositions  of the assets of the
company;  (ii) provide  reasonable  assurance that transactions are recorded as
necessary to permit  preparation  of financial  statements in  accordance  with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company;  and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of the  company's  assets  that could have a material  effect on the  financial
statements.

Because of its inherent limitations,  internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness  to future  periods  are  subject to the risk that  controls  may
become  inadequate  because  of changes  in  conditions,  or that the degree of
compliance with the policies or procedures may deteriorate.

In our opinion,  management's  assessment that the Company maintained effective
internal  control  over  financial  reporting as of December 31, 2006 is fairly
stated,  in all material  respects,  based on criteria  established in Internal
Control  --  Integrated  Framework  issued  by the  COSO.  Furthermore,  in our
opinion, the Company maintained,  in all material respects,  effective internal
control  over  financial  reporting  as of December  31, 2006 based on criteria
established in Internal Control -- Integrated Framework issued by the COSO.



/s/ PricewaterhouseCoopers LLP

Chartered Accountants
Calgary, Alberta, Canada

March 15, 2007



<PAGE>

                             ADDITIONAL DISCLOSURE

DISCLOSURE CONTROLS AND PROCEDURES

As of the end of the  registrant's  fiscal year ended  December  31,  2006,  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  management  with  the  participation  of  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  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.


MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The required disclosure is included in the "Management Report" that accompanies
the Registrant's Management's Discussion and Analysis for the fiscal year ended
December 31, 2006, filed as part of this Annual Report on Form 40-F.


ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM

The required  disclosure is included in the "Auditors' Report" that accompanies
the Registrant's Management's Discussion and Analysis for the fiscal year ended
December 31, 2006, filed as part of this Annual Report on Form 40-F.


CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING

During  the fiscal  year  ended  December  31,  2006,  there were no changes in
Canadian  Natural's  internal  controls  over  financial  reporting  that  have
materially  affected,  or are reasonably likely to materially affect,  Canadian
Natural'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
rules of the New York Stock Exchange.

<PAGE>

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 officer,  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 amendments,  waivers
or implicit waivers to the Code of Ethics in whole or in part were asked for or
granted to any director, senior officer or employee in 2006.

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, 2006 and December 31, 2005, for
professional  services  rendered by PwC for the audit of its internal  controls
and 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 not to exceed  C$3,126,287 for 2006 and were
C$1,227,835 for 2005.

         AUDIT-RELATED FEES: The aggregate fees billed for each of the last two
fiscal  years of Canadian  Natural,  ending  December 31, 2006 and December 31,
2005, for audit-related  services by PwC consisting of debt covenant compliance
and Crown  Royalty  Statements,  were not to exceed  $121,353 for 2006 and were
$266,923 for 2005.  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, 2006 and December 31, 2005, 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 2006 were not to exceed $134,025 for 2006 and were $39,331
for 2005.  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, 2006 and December 31,
2005 for other  services were not to exceed $9,516 for 2006 and were $7,290 for
2005.  The fees for other  services paid in 2006 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

                                       2
<PAGE>

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 2006.


                                       3
<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 63 of Canadian Natural's Management's Discussion
and Analysis of Financial  Condition and Results of  Operations  for the fiscal
year ended December 31, 2006,  filed herewith,  under the caption  "Commitments
and Off Balance Sheet Arrangements".

CONTRACTUAL OBLIGATIONS


COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS

In the normal  course of  business,  Canadian  Natural has entered into various
commitments that will have an impact on Canadian  Natural's future  operations.
These  commitments  primarily  relate  to  debt  repayments,  operating  leases
relating  to  office  space and  offshore  FPSOs and  drilling  rigs,  and firm
commitments for gathering,  processing and  transmission  services,  as well as
expenditures relating to asset retirement obligations. As at December 31, 2006,
no  entities  were  consolidated  under the  Canadian  Institute  of  Chartered
Accountants  Handbook  Accounting  Guideline  15,  "Consolidation  of  Variable
Interest   Entities".   The  following  table  summarizes   Canadian  Natural's
commitments as at December 31, 2006:

<TABLE>
<CAPTION>
($ millions)                                 2007       2008         2009       2010        2011    Thereafter
--------------------------------------------------------------------------------------------------------------
<S>                                    <C>          <C>         <C>         <C>         <C>         <C>
Product transportation and
   pipeline (1)                        $      213   $    193    $     134   $     123   $     99    $    1,042
Offshore equipment operating
   leases (2)                          $       77   $     52    $      52   $      52   $     50    $      131
Offshore drilling                      $       73   $     83    $      12   $      12   $      4    $        4
Asset retirement obligations (3)       $        3   $      3    $       3   $       4   $      4    $    4,480
Long-term debt (4)                     $      161   $     45    $   3,876   $       -   $    466    $    3,713
Office leases                          $       26   $     32    $      33   $      34   $     22    $        -
Electricity and other                  $       51   $     10    $      17   $      18   $      1    $        -
==============================================================================================================
</TABLE>
(1)  CANADIAN NATURAL 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 CANADIAN NATURAL'S OPTION.
     DURING THE INITIAL TERM,  ANNUAL TOLL PAYMENTS BEFORE OPERATING COSTS WILL
     BE APPROXIMATELY $35 MILLION.
(2)  OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF OBLIGATIONS
     RELATED TO FPSOS.  DURING 2006, CANADIAN NATURAL ENTERED INTO AN AGREEMENT
     TO LEASE AN ADDITIONAL  FPSO  COMMENCING  IN 2008, IN CONNECTION  WITH THE
     PLANNED OFFSHORE DEVELOPMENT IN GABON,  OFFSHORE WEST AFRICA. THE NEW FPSO
     LEASE AGREEMENT CONTAINS CANCELLATION PROVISIONS AT THE OPTION OF CANADIAN
     NATURAL,  SUBJECT TO ESCALATING  TERMINATION PAYMENTS THROUGHOUT 2007 TO A
     MAXIMUM OF US$395 MILLION.
(3)  AMOUNTS  REPRESENT   MANAGEMENT'S  ESTIMATE  OF  THE  FUTURE  UNDISCOUNTED
     PAYMENTS  TO SETTLE  ASSET  RETIREMENT  OBLIGATIONS  RELATED  TO  RESOURCE
     PROPERTIES,   FACILITIES,  AND  PRODUCTION  PLATFORMS,  BASED  ON  CURRENT
     LEGISLATION AND INDUSTRY  OPERATING  PRACTICES.  AMOUNTS DISCLOSED FOR THE
     PERIOD 2007 - 2011  REPRESENT THE MINIMUM  REQUIRED  EXPENDITURES  TO MEET
     THESE OBLIGATIONS.  ACTUAL  EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED
     THESE MINIMUM AMOUNTS.
(4)  THE  LONG-TERM  DEBT  REPRESENTS   PRINCIPAL   REPAYMENTS  ONLY.  NO  DEBT
     REPAYMENTS  ARE  REFLECTED  FOR $2,782  MILLION OF  REVOLVING  BANK CREDIT
     FACILITIES DUE TO THE EXTENDABLE NATURE OF THE FACILITIES.

In 2005, the Board of Directors of Canadian  Natural  approved the construction
costs for  Phase 1 of the  Horizon  Project,  with an  approved  budget of $6.8
billion.   Cumulative   construction   spending  to   December   31,  2006  was
approximately  $4.0 billion.  Final  construction  costs for Phase 1 may differ
from the  approved  budget  due to  changes  in the final  scope and  timing of
completion of the project, and/or inflationary cost pressures.

<PAGE>

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.

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, 2006,  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

                                       2
<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

Canadian  Natural 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.



                                       3
<PAGE>

                                   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 28th day of March, 2007.

                                       CANADIAN NATURAL RESOURCES LIMITED


                                       By:  /s/ Steve W. Laut
                                            -----------------------------
                                            Name:  Steve W. Laut
                                            Title: President and Chief
                                                   Operating Officer




                                       4
<PAGE>

Documents filed as part of this report:

                                 EXHIBIT INDEX

EXHIBIT NO. DESCRIPTION


1.       Supplementary Oil & Gas Information for the fiscal year ended December
         31, 2006.

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 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 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 GLJ Petroleum Consultants, independent petroleum engineering
         consultants.