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                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549

                                    FORM 40-F

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

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


For the fiscal year ended December 31, 2007   Commission File Number: 333-146056

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

                                 ALBERTA, CANADA
        (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.
          539,728,829 Common Shares outstanding as of December 31, 2007

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

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. 333-146056) under the Securities Act of 1933.

<PAGE>

All dollar amounts in this Annual Report on Form 40-F are expressed in Canadian
dollars. As of March 26, 2008, the noon buying rate for Canadian Dollars as
expressed by the Federal Reserve Bank of New York was US$1.0180 equals C$ 1.00.

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, 2007.

     B. AUDITED ANNUAL FINANCIAL STATEMENTS

        Canadian  Natural's audited  consolidated  financial  statements for the
        years ended December 31, 2007 and 2006,  including the auditor's  report
        with respect  thereto.  For a  reconciliation  of important  differences
        between  Canadian  and  United  States  generally  accepted   accounting
        principles,  see  Note 17 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, 2007.

SUPPLEMENTARY OIL & GAS INFORMATION

For Canadian Natural's Supplementary Oil & Gas Information for the year ended
December 31, 20007, see Exhibit 1 of this Annual Report on Form 40-F.

<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 27, 2008

<PAGE>

                                TABLE OF CONTENTS

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

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

RISK FACTORS..................................................................7

REGULATORY MATTERS...........................................................10

ENVIRONMENTAL MATTERS........................................................11

THE COMPANY..................................................................13

GENERAL DEVELOPMENT OF THE BUSINESS..........................................14

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

A.   PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES...............17

         DRILLING ACTIVITY...................................................18
         PRODUCING CRUDE OIL AND NATURAL GAS WELLS...........................19
         NORTHEAST BRITISH COLUMBIA..........................................19
         NORTHWEST ALBERTA...................................................20
         NORTHERN PLAINS.....................................................21
         SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN..........................23
         HORIZON OIL SANDS PROJECT...........................................24
         UNITED KINGDOM NORTH SEA............................................26
         OFFSHORE WEST AFRICA................................................27
         COTE D'IVOIRE.......................................................27
         GABON...............................................................28

B.   CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES...................29

C.   RECONCILIATION OF CHANGES IN NET CONVENTIONAL RESERVES..................34

D.   OIL SANDS MINING DISCLOSURE.............................................35

E.   CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION..............................42

F.   HISTORICAL DRILLING ACTIVITY BY PRODUCT.................................47

G.   NET CAPITAL EXPENDITURES................................................47

H.   UNDEVELOPED ACREAGE.....................................................49

I.   DEVELOPED ACREAGE.......................................................49

SELECTED FINANCIAL INFORMATION...............................................50

CAPITAL STRUCTURE............................................................51

MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES.....................52

DIVIDEND HISTORY.............................................................53

TRANSFER AGENTS AND REGISTRAR................................................53



CANADIAN NATURAL RESOURCES LIMITED                                            1
<PAGE>


DIRECTORS AND OFFICERS.......................................................54

CONFLICTS OF INTEREST........................................................59

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS...................59

AUDIT COMMITTEE INFORMATION..................................................60

LEGAL PROCEEDINGS............................................................61

MATERIAL CONTRACTS...........................................................61

INTERESTS OF EXPERTS.........................................................61

ADDITIONAL INFORMATION.......................................................61

SCHEDULE "A" REPORT ON RESERVES DATA.........................................62

SCHEDULE "B" REPORT OF MANAGEMENT AND DIRECTORS..............................65

SCHEDULE "C" CHARTER OF THE AUDIT COMMITTEE..................................67




2                                            CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

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 US gallons

"BCF" means one billion cubic feet

"BBL/D" means barrels per day

"BOE" means barrel of oil equivalent

"BOE/D" means barrel of oil equivalent per day

"CO2" means carbon dioxide

"CO2E" means carbon dioxide equivalents

"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 coal bed 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 unproved  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

CANADIAN NATURAL RESOURCES LIMITED                                            3
<PAGE>

"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

"SCO" means synthetic light crude oil

"SEC" means United States Securities and Exchange Commission

"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

"US" means United States

"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


4                                             CANADIAN NATURAL RESOURCES LIMITED
<PAGE>


SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain  statements  in  this  document  or  documents  incorporated  herein  by
reference  constitute  forward-looking  statements or information  (collectively
referred  to herein as  "forward-looking  statements")  within  the  meaning  of
applicable securities legislation.  Forward-looking statements can be identified
by the words "believe",  "anticipate",  "expect", "plan", "estimate",  "target",
"continue",  "could" "intend", "may", "potential",  "predict", "should", "will",
"objective",  "project",  "forecast",  "goal", "guidance",  "outlook",  "effort"
"seeks", "schedule" or expressions of a similar nature suggesting future outcome
or statements regarding an outlook. Statements relating to "reserves" are deemed
to be forward-looking statements as they involve the implied assessment based on
certain estimates and assumptions that the reserves  described can be profitably
produced in the future. There are numerous  uncertainties inherent in estimating
quantities of proved crude oil and natural gas reserves and in projecting future
rates of production and the timing of development expenditures. The total amount
or timing of actual future  production may vary  significantly  from reserve and
production estimates. In addition, these statements are not guarantees of future
performance  and are  subject to certain  risks and the reader  should not place
undue reliance on these forward-looking  statements as there can be no assurance
that the  plans,  initiatives  or  expectations  upon  which they are based will
occur.

The forward-looking statements are based on current expectations,  estimates and
projections  about Canadian  Natural  Resources  Limited (the "Company") and the
industry  in which the  Company  operates,  which speak only as of the date such
statements  were made or as of the date of the report or  document in which they
are  contained  and are subject to known and unknown  risks,  uncertainties  and
other factors that could cause the actual  results,  performance or achievements
of the Company 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;  volatility  of and  assumptions  regarding  crude oil and natural gas
prices;  fluctuations in currency and interest  rates;  assumptions on which the
Company's  current guidance is based;  economic  conditions in the countries and
regions in which the Company conducts business; political uncertainty, including
actions of or against  terrorists,  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 Company's  defense of lawsuits;  availability  and cost of
seismic,  drilling  and  other  equipment;   ability  of  the  Company  and  its
subsidiaries   to  complete  its  capital   programs;   the  Company's  and  its
subsidiaries'  ability  to  secure  adequate  transportation  for its  products;
unexpected difficulties in mining, extracting or upgrading the Company's bitumen
products;  potential  delays or changes in plans with respect to  exploration or
development projects or capital expenditures;  ability of the Company to attract
the  necessary  labour  required  to build  its  thermal  and oil  sands  mining
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;  the Company's and its  subsidiaries'  success of exploration  and
development  activities  and their  ability to replace and expand  crude oil and
natural  gas  reserves;  timing and  success of  integrating  the  business  and
operations of acquired  companies;  production  levels;  imprecision  of reserve
estimates and estimates of recoverable quantities of crude oil, bitumen, natural
gas and liquids not  currently  classified  as proved;  actions by  governmental
authorities; government regulations and the expenditures required to comply with
them (especially safety and environmental laws and regulations and the impact of
climate change  initiatives on capital and operating  costs);  asset  retirement
obligations;  the  adequacy  of the  Company's  provision  for taxes;  and other
circumstances  affecting  revenues and  expenses.  Certain of these  factors are
discussed  in more  detail  under the  heading  "Risk  Factors".  The  Company's
operations  have been,  and at times in the future may be affected by  political
developments  and by federal,  provincial and local laws and regulations such as
restrictions  on  production,  changes  in taxes,  royalties  and other  amounts
payable  to  governments  or  governmental  agencies,  price or  gathering  rate
controls and environmental  protection regulations.  Should one or more of these
risks or uncertainties  materialize,  or should any of the Company's assumptions
prove  incorrect,  actual  results  may vary in  material  respects  from  those
projected in the forward-looking  statements.  The impact of any one factor on a
particular  forward-looking statement is not determinable with certainty as such
factors are  interdependent  upon other  factors,  and the  Company's  course of
action  would  depend  upon  its  assessment  of  the  future   considering  all
information then available.

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


CANADIAN NATURAL RESOURCES LIMITED                                            5
<PAGE>

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, 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, 2007, 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,  NGLs and natural gas  reserves  and
prepare Evaluation  Reports on these reserves.  Conventional crude oil, NGLs and
natural gas includes  all of the  Company's  light/medium,  primary  heavy,  and
thermal crude oil,  natural gas, coal bed methane and NGLs  activities.  It does
not include the Company's oil sands mining assets. Conventional crude oil, NGLs,
and  natural  gas  reserves,  net of  royalties,  are  estimated  using  royalty
regulations in effect as of December 31, 2007. Similarly,  bitumen and synthetic
crude oil  reserves,  net of  royalties,  relating to surface  mineable oil sand
projects are estimated  using royalty  regulations  in effect as of December 31,
2007. Royalty changes proposed by the Government of Alberta will be incorporated
in the  reserves  evaluation  should  they be  enacted.  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  three  principal
differences  between the two standards.  The first is 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. 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 third is the
requirement to disclose a gross reserve reconciliation (before the consideration
of royalties). The Company discloses its reserve reconciliation net of royalties
in adherence to SEC requirements.

For the  year  ended  December  31,  2007,  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 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  proved and  probable  crude oil,  NGLs and
natural gas reserves.

The Company annually discloses 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 voluntary  additional  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.

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.


6                                             CANADIAN NATURAL RESOURCES LIMITED
<PAGE>


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,
including  liquefied  natural gas. Any  substantial  or extended  decline in the
prices of crude oil or natural gas could  result in a delay or  cancellation  of
existing or future drilling, development or construction programs or curtailment
in   production   at  some   properties   or  resulting   unutilized   long-term
transportation commitments, all of which could have a material adverse effect on
Canadian Natural's revenues, net earnings 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  26% of the Company's  2007  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.
Increasingly  stringent laws and  regulations  may have an adverse effect on the
Company's future net earnings and cash flow from operations.


CANADIAN NATURAL RESOURCES LIMITED                                           7

<PAGE>

GREENHOUSE GAS AND OTHER AIR EMISSIONS

The Company is  concurrently  working with  legislators  and  regulators as they
develop and  implement new GHG emission laws and  regulations.  Internally,  the
Company is pursuing an integrated  emissions reduction strategy,  to ensure that
it 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 GHG and air emissions 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.

In  Canada,   the  Federal  government  has  indicated  its  intent  to  develop
regulations that would be in effect in 2010 to address industrial GHG emissions.
The Federal Government has also outlined national and sectoral reduction targets
for several categories of air pollutants.  In Alberta, GHG regulations came into
effect July 1, 2007,  affecting  facilities emitting more than 100 kilotonnes of
CO2e annually.  Two Canadian Natural facilities,  the Primrose/Wolf Lake in-situ
heavy oil and the Hays sour gas plant,  are captured under the  regulations.  In
the UK,  greenhouse gas regulations have been in effect since 2005. During Phase
1 (2005-2007) of the UK National  Allocation Plan the Company operated below its
CO2  allocation.  For Phase 2 (2008-2012)  the Company's CO2 allocation has been
decreased  below the  Company's  estimated  current  operations  emissions.  The
Company  continues  to  focus  on  implementing   reduction  programs  based  on
efficiency audits of its major facilities to reduce CO2 emissions and on trading
mechanisms to ensure compliance with any requirement now in effect.

There are a number of  unresolved  issues in relation  to  Canadian  Federal and
Provincial GHG regulatory requirements.  Key among them is an appropriate common
facility emission threshold,  availability and duration of compliance mechanisms
and  resolution  of  federal/provincial  harmonization  agreements.  The Company
continues to pursue GHG emission  reduction  initiatives  including solution gas
conservation,  CO2 capture and sequestration in oil sands tailings,  CO2 capture
and storage in association  with enhanced oil recovery and  participation  in an
industry initiative to promote an integrated CO2 capture and storage network.

The  additional  requirements  of enacted or  proposed  GHG  legislation  on the
Company's  operations will 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.

Air  pollutant  standards  and  guidelines  are being  developed  federally  and
provincially and the Company is participating in these discussions.  Ambient air
quality and sector based reductions in air emissions are being reviewed. Through
participation of the Company and the industry with stakeholders, guidelines have
been developed that adopt a structured  process to emission  reductions  that is
commensurate with technological development and operational requirements.

NEED TO REPLACE RESERVES

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

COMPETITION IN ENERGY INDUSTRY

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


8                                             CANADIAN NATURAL RESOURCES LIMITED
<PAGE>


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 Canada or the
United States.

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


CANADIAN NATURAL RESOURCES LIMITED                                            9
<PAGE>


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.

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, transportation, 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 crude oil, NGLs 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.

On October 25, 2007 the Province of Alberta issued the framework of its proposed
changes to the  Alberta  crude oil and natural  gas  royalty  regime,  effective
January 1, 2009. The Company is currently  awaiting  finalization of the royalty
implementation regulations,  however it expects that its 2009 and future Alberta
royalty  payments will increase as a result of the proposed  royalty changes and
that its level of activity in Alberta in aggregate  will be reduced from what it
otherwise would have been in the absence of such royalty changes.

In addition to government royalties, the Company is currently subject to federal
and provincial income taxes in Canada at a combined rate of approximately 32.53%
after allowable deductions.

During 2007,  the Canadian  Federal  Government  enacted income tax rate changes
which reduce the Federal corporate income tax rate over the next five years from
21% in 2007 to 15% in 2012.


10                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>


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% charged on crude oil
and  natural  gas  profits.  Approvals  granted on or after  March 16,  1993 are
exempted  from  PRT and  government  royalties.  Profits  for PRT  purposes  are
calculated on a  field-by-field  basis by deducting  field  operating  costs and
field  development  costs from  production and third-party  tariff  revenue.  In
addition,  certain statutory allowances are available,  which may reduce the PRT
payable.

The  Company  is  subject  to UK  Corporation  Tax  ("CT") on its UK  profits as
adjusted for CT purposes.  PRT paid is deductible for CT purposes.  The CT rate,
which became  effective April 1, 1999, was set at 30%. 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%,  charged  on the  same  profits  as
calculated for "normal" CT but excluding any deduction for financing  costs, was
added to the current  30% CT charge.  Also the  deduction  for  expenditures  on
capital  items  was  changed  from 25% per  annum to 100% 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. In August 2006,  the  Government of Cote
d'lvoire  announced a reduction in the rate of Corporate  Income Tax from 35% to
27%,  effective  January 1, 2006.  Effective  January 1, 2008, the Government of
Cote d'lvoire announced a further corporate income tax rate reduction to 25%.

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.

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  internal  environmental  compliance  audit  and  inspection  program  of its
operating  facilities;  a 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; a due diligence program related to groundwater  monitoring;
an active program  related to preventing and reclaiming  spill sites; a solution
gas reduction  and  conservation  program;  a program to replace the majority of
fresh water for steaming with  brackish  water;  environmental  planning for all
projects to assess impacts and to implement avoidance,  and mitigation programs;
reporting for environmental  liabilities;  a program to optimize efficiencies at
the Company's operating facilities; and continued evaluation of new technologies
to reduce  environmental  impacts.  The Company has also  established  stringent
operating standards in four areas: using water-based,  environmentally  friendly
drilling muds whenever  possible;  implementing  cost effective ways of reducing

CANADIAN NATURAL RESOURCES LIMITED                                            11
<PAGE>

GHG per unit of production;  exercising  care with respect to all waste produced
through effective waste management plans; and minimizing  produced water volumes
onshore  and  offshore  through   cost-effective   measures.   Canadian  Natural
participates  in  both  the  Canadian  federal  and  provincial   regulated  GHG
emissions.  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  the
Companies  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 the
Company's  environmental  work  plan  and are  operated  within  all  regulatory
standards  and  guidelines.  The Company  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 2007 the  Company  completed  approximately  115 gas
conservation  projects,  resulting in a reduction of 1.28 million tonnes/year of
CO2e.  Over the past five  years the  Company  has spent  over $116  million  to
conserve the  equivalent of over 6.4 million  tonnes of CO2e. In heavy crude oil
production  Canadian Natural is evaluating tank heater efficiencies 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.  These programs also influence and 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 CO2 capture and the sequestration of CO2 in oils sands tailings.

In its North Sea  operations  the  Company  continues  to focus on  implementing
reduction  programs  based on  efficiency  audits of its major  facilities.  The
Produced Water  Re-injection  trial on Ninian Central continued  throughout 2007
during which time  approximately 1.5 million cubic meters of produced water were
re-injected to the reservoir.  This resulted in  approximately  16 tonnes of oil
not being  discharged  to sea, a reduction of  approximately  10%. The trial has
been very successful and will continue through 2008 as a permanent installation.

The costs incurred by the Company for compliance with environmental matters and
site restoration is approximately 3% of the total exploration and development
expenditures incurred by the Company in each of the years ended December 31,
2007, 2006 and 2005.

For  2007,  the  Company's  capital   expenditures   included  $71  million  for
abandonment expenditures (2006 - $75 million; 2005 - $46 million).

The Company's estimated undiscounted ARO at December 31, 2007 was as follows:


Estimated ARO, undiscounted ($millions)              2007               2006
--------------------------------------------------------------------------------
North America                               $       3,038   $          2,826
North Sea                                           1,286              1,543
Offshore West Africa                                  102                128
                                                    4,426              4,497
--------------------------------------------------------------------------------
North Sea PRT recovery                               (555)              (625)
--------------------------------------------------------------------------------
                                            $       3,871   $          3,872
================================================================================

The estimate of 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  $555  million  (2006 - $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 undiscounted  abandonment  liability to $3,871 million
(2006 - $3,872 million).

12                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>


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.

On January 1, 2008 Ranger Oil  (International)  Ltd.,  764968  Alberta Inc., CNR
International   (Norway)   Limited,   Renata  Resources  Inc.  and  the  Company
amalgamated  pursuant to the BUSINESS  CORPORATIONS ACT (Alberta) under the name
Canadian Natural Resources Limited.

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
    CNR Petro Resources Limited                             Alberta
    Horizon Construction Management Ltd.                    Alberta

Canadian Natural,  as the managing partner and CNR (ECHO) Resources Inc. are the
partners of Canadian Natural Resources, a general partnership. Canadian Natural,
as the  managing  partner,  CNR (ECHO)  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 CNR Petro Resources Limited 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% 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% partnership
interest.  Canadian Natural,  as the managing partner,  and CNR (ECHO) 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.

CANADIAN NATURAL RESOURCES LIMITED                                           13
<PAGE>

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, 2007 the Company had 3,461 permanent employees in
North America and 334 permanent employees in its international operations.

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.  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.  Phase 1 production is targeted to begin in the
third  quarter  2008  ramping up to 110,000  bbl/d of SCO.  The  Company is also
developing   various  cost   effective   options  for  execution  of  additional
construction on Phases 2/3. These phases have been further  subdivided into four
distinct tranches that will target production  expansion to 232,000 bbl/d of SCO
by 2013.

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 39 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
3.0  billion  barrels of gross lease  proved and  probable  synthetic  crude oil
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
scheduled to be fully  operational  by third quarter 2008 to coincide with first
production at the Horizon 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 and
pursuant to an agreement, the trust units were sold to an underwriting group for
a net gain of approximately $11 million.

On June 1, 2005,  the  Company  issued $400  million of 10 year 4.95%  unsecured
notes  maturing  June 1, 2015  pursuant to a short form shelf  prospectus  dated
August 1, 2003 for the issuance of medium term notes in Canada.

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  $400  million of 4.50%  unsecured  notes
maturing  January  23,  2013  pursuant  to a  short  form  Canadian  base  shelf
prospectus dated August 29, 2005.


CANADIAN NATURAL RESOURCES LIMITED                                            14
<PAGE>

On August 17, 2006,  the Company issued US$250 million of 10 year 6.0% unsecured
notes  maturing  August 15, 2016 and US$450  million of 30 year 6.50%  unsecured
notes  maturing  February  15,  2037  pursuant  to a US 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.  At the time,  the  assets  produced  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 included  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. In March 2007 $1,500  million of the
credit facility was repaid, reducing the facility to $2,350 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%
unsecured  notes  maturing  May 15, 2017 and  US$1,100  million of 30 year 6.25%
unsecured  notes  maturing March 15, 2038 pursuant to a US short form base shelf
prospectus dated November 27, 2006.

During 2007,  the Company  completed  67  transactions  in the normal  course to
acquire  additional  interests  in crude oil and  natural  gas  properties.  The
aggregate net expenditure of the transactions was $70.9 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 33 transactions to dispose of
non-core operated and non-operated properties for proceeds of $109.9 million.

On December 18, 2007 the Company  issued $400 million of 3 year 5.50%  unsecured
notes  maturing  December 17, 2010 pursuant to a Canadian  short form base shelf
prospectus dated September 25, 2007.

On January 17, 2008, the Company issued US$400 million of 5 year 5.15% unsecured
notes maturing February 1, 2013, US$400 million of 10 year 5.90% unsecured notes
maturing  February 1, 2018 and US$400 million of 31 year 6.75%  unsecured  notes
maturing  February  1, 2039  pursuant  to a US short form base shelf  prospectus
dated September 25, 2007.


CANADIAN NATURAL RESOURCES LIMITED                                            15
<PAGE>


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 45% of 2007  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 23% of 2007 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 26% of 2007 production.  Other heavy crude
oil, which accounts for 6% of 2007 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 and polymer 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 targeted to deliver
approximately 37 years of synthetic crude oil production.

With  approximately  12.7 million net acres of core  undeveloped  land base, the
Company  believes it has  sufficient  project  portfolios in each of the product
offerings to provide growth for the next several years.


16                                            CANADIAN NATURAL RESOURCES LIMITED
<PAGE>


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, 2007. The information  reflects the working
interests owned by the Company. FPSO's, included under major infrastructure, are
leased by the Company under varying terms.

<TABLE>
<CAPTION>
                                      2007 Average Daily                Year Ended         Major Infrastructure
                                       Production Rates                Dec 31, 2007         As at Dec 31, 2007
---------------------------------------------------------------------------------------------------------------
Region                                                                                               Batteries/
                                                                         Undeveloped      Compressors & Plants/
                                  Crude oil & NGLs       Natural gas         acreage                 Platforms/
                                           (mbbl)             (mmcf)     (thousands)                       FPSO
---------------------------------------------------------------------------------------------------------------
<S>                               <C>                    <C>           <C>                 <C>

NORTH AMERICA
     Northeast British Columbia                7.0               430           2,401                   1/11/-/-
     Northwest Alberta                        17.0               596           1,489                   -/14/-/-
     Northern Plains                         201.4               418           7,109                   12/6/-/-
     Southern Plains                          12.7               196             925                    -/3/-/-
     Southeast Saskatchewan                    8.4                 2             121                    -/-/-/-
     Non-core regions                          0.3                 1             109                    -/-/-/-
     Horizon Oil Sands                           -                 -             115                    -/-/-/-
---------------------------------------------------------------------------------------------------------------
INTERNATIONAL
     North Sea UK Sector                      55.9                13             287                    -/-/5/1
     Offshore West Africa
          Cote d'Ivoire                       28.5                12              55                    -/-/-/2
          Gabon                                  -                 -             151                    -/-/-/-
     Non-core regions
          South Africa                           -                 -           4,002                    -/-/-/-
---------------------------------------------------------------------------------------------------------------
TOTAL                                        331.2             1,668          16,764                  13/34/5/3
---------------------------------------------------------------------------------------------------------------
</TABLE>

CANADIAN NATURAL RESOURCES LIMITED                                            17
<PAGE>


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, 2007 by geographic region:

<TABLE>
<CAPTION>
                                                                         2007
------------------------------------------------------------------------------------------------------------------------------
                                          Net exploratory                                  Net development
                                Productive        Dry holes     Total            Productive        Dry holes            Total
------------------------------------------------------------------------------------------------------------------------------
<S>                             <C>               <C>           <C>             <C>                <C>                  <C>
CANADA
   Northeast British Columbia         7.0             6.0         13.0                  38.0             10.1             48.1
   Northwest Alberta                 17.4             3.8         21.2                  94.2              8.9            103.1
   Northern Plains                   48.5            19.4         67.9                 571.5             42.4            613.9
   Southern Plains                   14.4             1.0         15.4                 152.2              0.6            152.8
   Southeast Saskatchewan             1.0               -          1.0                  23.0              0.4             23.4
   Non-core regions                     -               -            -                     -                -                -
NORTH SEA UK SECTOR                     -               -            -                   3.7                -              3.7
OFFSHORE WEST AFRICA
    Cote d'Ivoire                       -               -            -                   4.1                -              4.1
------------------------------------------------------------------------------------------------------------------------------
TOTAL                                88.3            30.2        118.5                 886.7             62.4            949.1
==============================================================================================================================

<CAPTION>
                                                                        2006
------------------------------------------------------------------------------------------------------------------------------
                                          Net exploratory                                  Net development
                                Productive        Dry holes     Total           Productive         Dry holes            Total
------------------------------------------------------------------------------------------------------------------------------
<S>                             <C>               <C>           <C>             <C>                <C>                  <C>
CANADA
  Northeast British Columbia         17.2             5.6         22.8                158.9              14.1            173.0
  Northwest Alberta                  17.7             9.5         27.2                149.6              14.6            164.2
  Northern Plains                   104.1            28.2        132.3                598.5              36.1            634.6
  Southern Plains                    31.8             8.4         40.2                 78.6               1.0             79.6
  Southeast Saskatchewan                -               -            -                 72.7               2.0             74.7
  Non-core regions                    0.6               -          0.6                  2.7                 -              2.7
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
==============================================================================================================================

<CAPTION>
                                                                         2005
------------------------------------------------------------------------------------------------------------------------------
                                          Net exploratory                                  Net development
                                Productive       Dry holes      Total           Productive        Dry holes          Total
------------------------------------------------------------------------------------------------------------------------------
<S>                             <C>               <C>           <C>             <C>                <C>                  <C>
CANADA
  Northeast British Columbia         32.1             7.2         39.3                 179.9             21.1            201.0
  Northwest Alberta                  29.9             9.0         38.9                 135.2              7.3            142.5
  Northern Plains                    63.5            11.5         75.0                 671.4             51.9            723.3
  Southern Plains                    50.6             5.0         55.6                 294.9              2.0            296.9
  Southeast Saskatchewan              1.0               -          1.0                  43.0                -             43.0
  Non-core regions                      -               -            -                   0.3                -              0.3
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
==============================================================================================================================
</TABLE>

18                                            CANADIAN NATURAL RESOURCES LIMITED
<PAGE>


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, 2007:

<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 British Columbia     1,541.0           1,294.1             232.0            194.5           1,773.0           1,488.6
    Northwest Alberta              2,125.0           1,636.7             561.0            315.5           2,686.0           1,952.2
    Northern Plains                3,908.0           3,081.6           6,277.0          5,379.8          10,185.0           8,461.4
    Southern Plains                7,320.0           6,136.6           1,154.0          1,025.7           8,474.0           7,162.3
    Southeast Saskatchewan             5.0               2.8           1,518.0            952.9           1,523.0             955.6
    Non-core regions                 122.0              34.9              70.0             21.7             192.0              56.6
UNITED STATES                          5.0               0.6               3.0              0.5               8.0               1.1
NORTH SEA UK SECTOR                    2.0               0.1             108.0             91.3             110.0              91.4
OFFSHORE WEST AFRICA
    Cote d'Ivoire                        -                 -              21.0             12.3              21.0              12.3
-----------------------------------------------------------------------------------------------------------------------------------
Total                             15,028.0          12,187.4           9,944.0          7,994.2          24,972.0          20,181.5
===================================================================================================================================
</TABLE>

Any 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]




Significant geological variation extends throughout the productive reservoirs in
this region,  producing light crude oil, NGLs and natural gas. The Company holds
working  interests  ranging  up to 100% and  averaging  73% in  4,711,958  gross
(3,430,948 net) acres of producing and undeveloped land in the region.

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  shale gas plays. The 2006 acquisition of ACC
significantly  increased the Company's asset base in Northeast  British Columbia
with the  addition of the ACC  properties  in Adsett,  Caribou and Fort 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.

CANADIAN NATURAL RESOURCES LIMITED                                            19
<PAGE>

Natural gas production  from the region  averaged 430 mmcf/d in 2007 compared to
the average of 408 mmcf/d in 2006.  Crude oil and NGLs  production was steady at
7,000 bbl/d in 2007, from an average of 6,700 bbl/d in 2006.

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
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  2007,  the Company  drilled 2.9 (2006 - 12.9) net crude oil wells,  42.1
(2006 - 163.2) net natural gas wells, 0.0 (2006 - 0.0) net stratigraphic/service
wells and 16.1  (2006 - 19.7) net dry  wells on its lands in this  region  for a
total of 61.1 (2006 - 195.8) net wells.  The Company held an average 81% working
interest in these wells.

NORTHWEST ALBERTA

                               [GRAPHIC OMITTED]




The Company  holds  working  interests  ranging up to 100% and  averaging 73% in
3,193,607 gross  (2,338,858 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  provide  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.

Natural gas production  from the region  averaged 596 mmcf/d in 2007 compared to
an average of 454 mmcf/d in 2006.  Crude oil and NGLs  production  increased  to
17,000 bbl/d in 2007 from 15,000 bbl/d in 2006.

During 2007,  the Company  drilled 13.0 (2006 - 14.5) net crude oil wells,  98.5
(2006 - 152.8) net natural gas wells, 1.5 (2006 - 0.0) net stratigraphic/service
wells,  and 12.8  (2006 - 24.1) net dry wells on its lands in this  region for a
total of 125.8 (2006 - 191.4) net wells. The Company held an average 74% working
interest in these wells.

20                                           CANADIAN NATURAL RESOURCES LIMITED

<PAGE>


NORTHERN PLAINS

                               [GRAPHIC OMITTED]




The Company  holds  working  interests  ranging up to 100% and  averaging 85% in
12,098,317 gross (10,318,670 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 418 mmcf/d in 2007 compared to 437 mmcf/d in 2006.
Crude oil and NGLs  production  from this region  increased to 201,400  bbl/d in
2007 up from 194,500  bbl/d in 2006.  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 2007 the  Company  made a  strategic
decision  to reduce  natural gas  drilling in Western  Canada as a result of low
natural pas prices and increase drilling in crude oil areas such as the Northern
Plains area.

Natural  gas in this  region is  produced  from  shallow,  low-risk,  multi-zone
prospects and more recently from the Horseshoe  Canyon 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 in 2008 to determine the economic viability of this play.

In the area near Lloydminster,  Alberta,  reserves of heavy crude oil (averaging
12(0)-14(0)  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% 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.


CANADIAN NATURAL RESOURCES LIMITED                                            21
<PAGE>


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% interest
in the ECHO Pipeline system, a crude oil transportation  pipeline;  and, in 2001
the Company  acquired the remaining  50%. 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  57,000 bbl/d of
hot,  unblended crude oil to sales  facilities at Hardisty,  Alberta and in 2003
its capacity was expanded to handle up to 72,000 bbl/d. The ECHO Pipeline system
is a high  temperature,  insulated  pipeline that eliminates the requirement for
field condensate blending. The pipeline enables the Company to transport its own
production  volumes  at a  reduced  operating  cost as well as earn  third-party
transportation  revenue.  This  transportation  control  enhances the  Company's
ability to control the full spectrum of costs  associated  with the  development
and marketing of its heavy crude oil.

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(0)-11(0) 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 80,000 bbl/d of crude oil which expanded to
119,500 bbl/d in 2007. The Company also holds a 50% 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 1999,  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 began in
2007, with the first oil production  targeted to commence in 2009. A mature SAGD
heavy oil project in which the Company holds a 50% interest is also in operation
in the  Saskatchewan  portion of this region.  In December 2006 Canadian Natural
issued a Public Disclosure Document outlining the proposed  development plan for
the Kirby In-Situ Oil Sands Project located approximately 85 km northeast of Lac
La Biche.  The Regulatory  application for Kirby was submitted in September 2007
outlining the Company's plan to build a 45,000 bbl/d in-situ oil sands project.

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  14(0)-17(0)  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% 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 5%
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.


22                                            CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

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. The commercial expansion of
this EOR technology  continues with 70 polymer injection wells at year end 2007.
Pelican Lake production averaged approximately 34,000 bbl/d in 2007.

During 2007, the Company drilled 524.4 (2006 - 484.0) net crude oil wells,  95.6
(2006  -  218.6)   net   natural   gas   wells,   145.8   (2006  -  206.9)   net
stratigraphic/service wells, and 61.8 (2006 - 64.3) net dry wells for a total of
827.6 (2006 - 973.8) net wells. The Company's  average working interest in these
wells was 92%.

SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN


                               [GRAPHIC OMITTED]


In the Southern Plains area, the Company holds interests  ranging up to 100% and
averaging  82% in  2,917,066  gross  (2,379,552  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.

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  12,700
bbl/d of crude oil and NGLs in 2007  compared to 10,500  bbl/d in 2006.  Natural
gas  production  amounted  to 196  mmcf/d  in 2007  compared  to the 165  mmcf/d
averaged in 2006.

During  2007,  the  Company  drilled a total of 19.1  (2006 - 6.2) net crude oil
wells, 147.5 (2006 - 104.2) net natural gas wells, 1.0 (2006 - 0.0) net
stratigraphic/service wells and 1.6 (2006 - 9.4) net dry wells in this region
for a total of 169.2 (2006 - 119.8) net wells. The Company's average working
interest in these wells was 79%.

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% and
averaging 82% in 220,266 gross (181,691 net) acres of producing and  undeveloped
lands in the region.


CANADIAN NATURAL RESOURCES LIMITED                                           23
<PAGE>

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 2007  compared  to  8,400  bbl/d in  2006.  Natural  gas  production
averaged 2 mmcf/d in 2007 (2006 - 3 mmcf/d).

The Company drilled 24.0 (2006 - 72.7) net crude oil wells, 0.0 (2006 - 0.0) net
natural gas well, 4.0 (2006 - 0.0) net stratigraphic/service wells and 0.4 (2006
- 2.0) net dry wells in this  region in 2007,  for a total of 28.4 (2006 - 74.7)
net wells. The Company's average working interest in these wells is 84%.

HORIZON OIL SANDS PROJECT


                               [GRAPHIC OMITTED]


Canadian  Natural owns a 100% working interest in its Athabasca Oil Sands leases
in Northern Alberta,  of which a portion (being lease 18) is subject to a 5% 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 SCO, and associated 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 Project, which has two aspects,  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  2013.  Phase 1 production  is targeted to begin in the third quarter of
2008 ramping up to 110,000 bbl/d of SCO.  Subsequent  expansion  through  Phases
2/3, which is further broken down into a series of four Tranches, is expected to
increase production to 232,000 bbl/d of SCO out to 2013. These targeted rates of
production  represent  nominal design capacity.  Construction of some components
and portions of facilities for the future expansions have already been completed
and certain  major long lead  equipment  for Phases 2/3 was ordered in 2006 with
deliveries  to site  expected in 2008.  Canadian  Natural  will seek to maximize
resource  recovery  and  overall  production  through  ongoing  optimization  of
operations.


24                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

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 Phases 2/3.

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  2007,  Canadian
Natural's  Horizon  Project  team,  consisted of 925 permanent  employees  which
consisted of 661 project staff  personnel and 264  operations  personnel to fill
63% of the projected project and operations team position requirements.

Horizon Project Phase 1 construction costs were  approximately  $2.74 billion in
2007 and cumulative  expenditures were  approximately  $6.76 billion through the
end of 2007. Phase 1 construction  capital is budgeted to be approximately  $1.7
billion to $1.9  billion in 2008,  representing  a cost to  completion  forecast
range  of 25% to 28% over the  original  $6.8  billion  estimate.  In  addition,
capital  expenditures of $439 million are budgeted for Tranche 2 development and
construction in 2008.  These  expenditures  are direct project costs only and do
not include capitalized interest, stock based compensation or lease evaluation.

During 2007, the Company drilled 98.0 (2006 - 163.0) stratigraphic test wells to
further delineate the ore body and confirm resource quality and quantity.


CANADIAN NATURAL RESOURCES LIMITED                                           25
<PAGE>


UNITED KINGDOM NORTH SEA


                               [GRAPHIC OMITTED]


The Company's wholly owned subsidiary CNR International (U.K.) Limited, formerly
Ranger Oil (U.K.)  Limited,  has  operated in the North Sea for 30 years and has
developed  a  significant  database,   extensive  operating  experience  and  an
experienced  staff.  The Company  owns  interests  ranging from 7% up to 100% in
478,061 gross (374,720 net) acres of producing and  non-producing  properties in
the UK sector of the North Sea. In 2007, the Company  produced from 16 crude oil
fields.

The northerly  fields are centered around the Ninian Field where the Company has
an 87.1% 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% to 100%. 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 licences 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 2007 the Company  acquired a 58.7% working interest in
the abandoned  Hutton Field,  increasing its working  interest in this currently
non-producing Field to 66.5%.

In the central  portion of the North Sea, in 2003,  the  Company  increased  its
equity in the Banff Field to 87.6% and took over as  operator.  The Company also
owns a 45.7% 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% working  interest in T-block  (comprising the
Tiffany,  Toni and Thelma  Fields)  and 68.7% to 75.3%  interests  in the Fields
known as B-block (comprising  Balmoral,  Stirling and Glamis).  The Company took
over as operator of these fields.  In 2007 the Company disposed of its interests
in the B Block Fields.

The Company  receives  tariff revenue from other field owners for the processing
of  crude  oil  and  natural  gas  through  some of the  processing  facilities.
Opportunities  for further  long-reach  well  development on adjacent fields are
provided by the existing processing facilities.

During 2007,  production to the Company from this region averaged  approximately
55,900 bbl/d of crude oil (2006 - 60,100 bbl/d). Natural gas production averaged
13.0 mmcf/d in 2007 (2006 - 15.0 mmcf/d).

During 2007 the Company drilled 3.7 (2006 - 7.4) net crude oil wells,  3.5 (2006
- 1.8) net  stratigraphic/service  wells  and 0.0  (2006 - 0.0) net dry wells in
this  region for a total of 7.2 (2006 - 9.2) net wells.  The  Company's  average
working interest in these wells is 90%.


26                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

OFFSHORE WEST AFRICA


                               [GRAPHIC OMITTED]


With the purchase of Ranger in 2000, the Company acquired  interests in areas of
crude oil and natural gas exploration and development offshore Cote d'Ivoire and
Angola, West Africa. 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% interest
in a production sharing agreement for the block.

The Company also has a 100% 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% operating interest. The
Espoir Field is located in water depths  ranging from 100 to 700 meters.  During
the 1980s,  the Espoir Field produced  approximately 31 million barrels of crude
oil by natural depletion prior to  relinquishment  by the previous  licencees in
1988. The government of Cote d'Ivoire approved a development plan to recover the
remaining   reserves  and  the  Company  will  continue  its   exploitation  and
development of the field.  The first phase of development of East Espoir,  which
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  approximately 24,000 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.
Development  drilling at West Espoir continued throughout 2007 and was completed
in early 2008.

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  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.


CANADIAN NATURAL RESOURCES LIMITED                                            27
<PAGE>


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% interest. The well encountered
hydrocarbons  at a rate of 6,700  bbl/d of crude oil. A second test well in 2002
also produced hydrocarbons at a rate in excess of 10,000 bbl/d of crude oil. 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 30,000 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 led to five
of the ten production  wells being shut in by the end of the year,  resulting in
approximately 15,500 bbl/d of net production capacity being shut in. The Company
has secured a deepwater  rig,  expected  in mid-year  2008,  that is expected to
enable the Company to execute its plan to return certain of the shut-in wells to
production over the course of 2008 and 2009.

To date  political  unrest which has occurred from time to time 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 2007, Company production averaged approximately 28,500 bbl/d of crude oil
(2006- 36,700 bbl/d).  Company natural gas production amounted to 12.1 mmcf/d in
2007 (2006 - 9.5 mmcf/d).

In 2007, the Company  drilled 4.1 (2006 - 4.1) net crude oil wells,  0.6 (2006 -
1.7) net  stratigraphic/service  wells  and 0.0 (2006 - 0.0) net dry wells for a
total of 4.7 (2006 - 5.8) net wells.  The Company's  average working interest in
these wells is 59%.

GABON


                               [GRAPHIC OMITTED]


In late 2005, the Company acquired permit No. G4-187  comprising a 90% operating
interest in the production  sharing agreement for the block containing the Olowi
Field.  The field is 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. 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  will target the western flank of the structure where the oil is
located  as a rim  below a large gas cap.  Major  contracts  covering  the FPSO,
platforms,   flowlines   and  the  drilling  rig  were  awarded  in  late  2006.
Construction  is underway and first oil is targeted for late 2008. It is planned
that in total 28 horizontal  production wells plus one gas injector well will be
drilled.  Crude oil production  will rely on gas cap expansion  supplemented  by
re-injection  of the produced  solution  gas.  Production is expected to ramp up
during 2009 to a plateau rate of approximately 20,000 bbl/d net to the Company.


28                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

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

For the year ended December 31, 2007, 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,  NGLs and natural gas  reserves  and
prepare Evaluation  Reports on these reserves.  Conventional crude oil, NGLs and
natural gas includes  all of the  Company's  light/medium,  primary  heavy,  and
thermal crude oil,  natural gas, coal bed methane and NGLs  activities.  It does
not include the Company's oil sands mining assets. Conventional crude oil, NGLs,
and  natural  gas  reserves,  net of  royalties,  are  estimated  using  royalty
regulations in effect as of December 31, 2007. Similarly,  bitumen and synthetic
crude oil  reserves,  net of  royalties,  relating to surface  mineable oil sand
projects are estimated  using royalty  regulations  in effect as of December 31,
2007. Royalty changes proposed by the Government of Alberta will be incorporated
in the  reserves  evaluation  should  they be  enacted.  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  three  principal
differences  between the two standards.  The first is 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. 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 third is the
requirement to disclose a gross reserve reconciliation (before the consideration
of royalties). The Company discloses its reserve reconciliation net of royalties
in adherence to SEC requirements.

The Company annually discloses 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 voluntary  additional  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 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, NGLs and natural gas reserves.

The following  tables  summarize the  evaluations of  conventional  reserves and
estimated net present values of these reserves at December 31, 2007.

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.


29                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

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

<TABLE>
<CAPTION>
                                                                         Constant Prices and Costs
--------------------------------------------------------------------------------------------------------------------------------
                                                       Crude oil & NGLs (mmbbl)                     Natural gas (bcf)
                                                 Total proved         Total proved &      Total proved         Total proved &
                                                     reserves      probable reserves          reserves      probable reserves
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>                    <C>               <C>                    <C>
NORTH AMERICA
    Canada                                                920                  1,545             3,519                  4,600
    United States                                          --                     --                 2                      2
INTERNATIONAL
    United Kingdom                                        310                    405                81                    113
    Cote d'Ivoire                                         110                    166                64                     88
    Gabon                                                  18                     20                --                     --
--------------------------------------------------------------------------------------------------------------------------------
TOTAL                                                   1,358                  2,136             3,666                  4,803
================================================================================================================================
</TABLE>


CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES

<TABLE>
<CAPTION>
                                                                          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                                 828                    736             3,454                  2,842
Proved undeveloped reserves                               715                    622               981                    824
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES                                   1,543                  1,358             4,435                  3,666
TOTAL PROVED & PROBABLE RESERVES                        2,430                  2,136             5,804                  4,803
================================================================================================================================
</TABLE>


ESTIMATED NET PRESENT VALUE

<TABLE>
<CAPTION>
                                                                          Constant Prices and Costs
--------------------------------------------------------------------------------------------------------------------------------
                                                  Undiscounted                                 Discounted at:
($ millions)                                                                     10%               15%                    20%
--------------------------------------------------------------------------------------------------------------------------------
<S>                                              <C>               <C>                    <C>               <C>
Proved developed reserves                        $     42,653      $          25,767      $     21,924      $          19,229
Proved undeveloped reserves                      $     22,986      $           8,810      $      6,082      $           4,340
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES                            $     65,639      $          34,577      $     28,006      $          23,569
TOTAL PROVED & PROBABLE RESERVES                 $     94,316      $          44,286      $     34,604      $          28,331
================================================================================================================================
</TABLE>


30                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>


CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES

<TABLE>
<CAPTION>
                                                                                 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                                 814                    730             3,464                  2,850
Proved undeveloped reserves                               721                    626               982                    822
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES                                   1,535                  1,356             4,446                  3,672
TOTAL PROVED & PROBABLE RESERVES                        2,426                  2,129             5,817                  4,810
================================================================================================================================
</TABLE>


ESTIMATED NET PRESENT VALUES

<TABLE>
<CAPTION>
                                                                      Forecast Prices and Costs
--------------------------------------------------------------------------------------------------------------------------------
                                                  Undiscounted                                 Discounted at:
($ millions)                                                                     10%               15%                    20%
--------------------------------------------------------------------------------------------------------------------------------
<S>                                              <C>               <C>                    <C>               <C>
Proved developed reserves                        $     39,393      $          25,013      $     21,501      $          18,984
Proved undeveloped reserves                      $     26,455      $           9,494      $      6,478      $           4,594
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES                            $     65,848      $          34,507      $     27,979      $          23,578
TOTAL PROVED & PROBABLE RESERVES                 $    104,860      $          46,364      $     35,860      $          29,208
================================================================================================================================
</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.


CANADIAN NATURAL RESOURCES LIMITED                                            31

<PAGE>

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%
     probability that the quantities actually recovered will equal or exceed the
     stated  values.  The Company has  elected to disclose  proved and  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 and
     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.

9.   The constant  price and cost case assumes that prices in effect at year-end
     2007 adjusted for quality and  transportation as well as the 2007 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 2008 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$1.01/C$1.00):

                                   Natural gas
     ---------------------------------------------------------------------------
                       Company
                       average        Henry Hub                      Huntingdon/
                         price        Louisiana            AECO            Sumas
     (Year)           (C$/mcf)      (US$/mmbtu)      (C$/mmbtu)       (C$/mmbtu)
     ---------------------------------------------------------------------------
     2007                 6.48             6.80            6.52             6.96
     ===========================================================================



                                Crude oil & NGLs
     ---------------------------------------------------------------------------
                      Company                  Hardisty
                      average         WTI @       Heavy    Edmonton    North Sea
                        price    Cushing(1)   12(0) API      Par(2)        Brent
     (Year)          (C$/bbl)     (US$/bbl)    (C$/bbl)    (C$/bbl)    (US$/bbl)
     ---------------------------------------------------------------------------
     2007               62.87         96.00       41.70       93.44        96.02
     ===========================================================================

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

     (2)  "Edmonton  Par" refers to the price of light gravity  (40(0) 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 2% per year.  Future crude oil, NGLs and
     natural gas price forecasts were based on Sproule's December 31, 2007 crude
     oil, NGLs and natural gas pricing model.


32                                           CANADIAN NATURAL RESOURCES LIMITED

<PAGE>


The Company's weighted average crude oil and NGLs price and the weighted average
natural  gas price in the 2007  evaluation  were $62.87 per barrel and $6.48 per
mcf  respectively.  The crude oil and  natural gas  forecast  prices used in the
Evaluation Reports are as follows:

                                   Natural gas
     ---------------------------------------------------------------------------
                       Company
                       average        Henry Hub                      Huntingdon/
                         price        Louisiana            AECO            Sumas
     (Year)           (C$/mcf)      (US$/mmbtu)      (C$/mmbtu)       (C$/mmbtu)
     ---------------------------------------------------------------------------
     2008                 6.37             7.56            6.51             6.51
     2009                 7.07             8.27            7.22             7.22
     2010                 7.50             8.74            7.69             7.69
     2011                 7.49             8.75            7.70             7.70
     2012                 7.41             8.66            7.61             7.61
     2013                 7.45             8.83            7.78             7.78
     2014                 7.65             9.01            7.96             7.96
     2015                 7.84             9.19            8.14             8.14
     2016                 8.04             9.37            8.32             8.32
     2017                 8.25             9.56            8.51             8.51
     2018                 8.44             9.75            8.68             8.68
     ===========================================================================


                                Crude oil & NGLs
     ---------------------------------------------------------------------------
                      Company                  Hardisty
                      average         WTI @       Heavy    Edmonton    North Sea
                        price    Cushing(1)   12(0) API      Par(2)        Brent
     (Year)          (C$/bbl)     (US$/bbl)    (C$/bbl)    (C$/bbl)    (US$/bbl)
     ---------------------------------------------------------------------------
     2008               65.51         89.61       54.67       88.17        87.61
     2009               63.58         86.01       52.42       84.54        83.97
     2010               61.86         84.65       51.56       83.16        82.57
     2011               60.76         82.77       50.38       81.26        80.65
     2012               60.90         82.26       50.05       80.73        80.10
     2013               63.20         82.81       50.38       81.25        80.60
     2014               63.53         84.46       51.39       82.88        82.21
     2015               63.96         86.15       52.42       84.55        83.85
     2016               65.04         87.87       53.47       86.25        85.53
     2017               66.86         89.63       54.55       87.98        87.24
     2018               67.43         91.42       55.64       89.74        88.99
     ===========================================================================

     Note: Foreign exchange rate used was US$1.00/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.

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


                                           Proved            Proved & probable
                                   Forecast     Constant    Forecast    Constant
                                      price        price       price       price
($ millions)                           case         case        case        case
--------------------------------------------------------------------------------
2008                                  1,642        1,632       1,851       1,841
2009                                  2,200        2,095       2,520       2,418
2010                                  1,092        1,023       1,482       1,408
2011                                    803          733       1,398       1,293
2012                                    945          836       1,540       1,388
2013                                    594          508       1,086         961
2014                                    338          286         653         570
2015                                    332          275         768         655
2016                                    339          253         587         472
2017                                    218          178         436         361
2018                                    201          160         350         285
2019                                    272          210         485         387
Thereafter                            1,927        1,274       3,324       2,225
================================================================================

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.


CANADIAN NATURAL RESOURCES LIMITED                                            33

<PAGE>

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.

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, DEC 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, DEC 31, 2006                      887        299         130       1,316   |   3,705         37          56       3,798
-------------------------------------------------------------------------------------|-------------------------------------------
Extensions & discoveries                     30         --          --          30   |     134         --          --         134
Infill drilling                              10          6          --          16   |     124          3          --         127
Improved recovery                             3         --          --           3   |       8         --          --           8
Property purchases                            1         --          --           1   |      12         --          --          12
Property disposals                           --         (3)         --          (3)  |      --         --          --          --
Production                                  (77)       (20)        (10)       (107)  |    (503)        (5)         (4)       (512)
Revisions of prior estimates                 66         28           8         102   |      41         46          12          99
-------------------------------------------------------------------------------------|-------------------------------------------
RESERVES, DEC 31, 2007                      920        310         128       1,358   |   3,521         81          64       3,666
-------------------------------------------------------------------------------------|-------------------------------------------
                                                                                     |
PROVED AND PROBABLE RESERVES                                                         |
-------------------------------------------------------------------------------------|-------------------------------------------
RESERVES, DEC 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, DEC 31, 2006                    1,502        422         195       2,119   |   4,857         93          99       5,049
-------------------------------------------------------------------------------------|-------------------------------------------
Extensions & discoveries                     41         --          --          41   |     177         --          --         177
Infill drilling                              52          6          --          58   |     163          3          --         166
Improved recovery                             4         --          --           4   |       8         --          --           8
Property purchases                            2          6          --           8   |      17          1          --          18
Property disposals                           --         (3)         --          (3)  |      (1)        --          --          (1)
Production                                  (77)       (20)        (10)       (107)  |    (503)        (5)         (4)       (512)
Revisions of prior estimates                 21         (6)          1          16   |    (116)        21          (7)       (102)
-------------------------------------------------------------------------------------|-------------------------------------------
RESERVES, DEC 31, 2007                    1,545        405         186       2,136   |   4,602        113          88       4,803
=====================================================================================|===========================================
</TABLE>


34                                           CANADIAN NATURAL RESOURCES LIMITED

<PAGE>

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  2007  Annual  Report  under  "Supplementary  Oil  and Gas
Information" on pages 97 to 101 and is incorporated herein by reference.

D.   OIL SANDS MINING DISCLOSURE

INTRODUCTION

Canadian Natural holds a 100% working interest in its Athabasca Oil Sands leases
in Northern Alberta, of which a portion (being lease 18), is subject to a 5% 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.  Synthetic  crude oil  production is
targeted  for the third  quarter  of 2008  ramping  up to  110,000  bbl/d and is
targeted to reach 232,000 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, was retained to evaluate 100%
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  approximately  3.0 billion barrels of
synthetic crude oil with a production life of 39 years.

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

CANADIAN NATURAL RESOURCES LIMITED                                            35


<PAGE>


FIGURE 1 - LOCATION OF THE HORIZON OIL SANDS PROJECT


                               [GRAPHIC OMITTED]


TABLE 1 - CANADIAN NATURAL ATHABASCA REGION OIL SAND LEASES

Short                    Official                         Lease             Area
lease                       lease                        expiry               in
name                       number                       date(1)         hectares
--------------------------------------------------------------------------------
Lease 18                727912T18        Continued Producing(2)          19,988
Lease 10               7400120010             December 14, 2015           3,840
Lease 25               7401050025                  May 17, 2016           1,536
Lease 11               7400120011             December 14, 2015             518
Lease 12               7400120012             December 14, 2015           9,216
Lease 13               7400120013             December 14, 2015              69
Lease 15               7400120015             December 14, 2015           1,536
Lease 19               7402050019                  May 30, 2017           5,120
Lease 20               7402050020                  May 30, 2017             768
Lease 6                7597050T06                   May 6, 2012           2,584
Lease 7                7597050T07                   May 6, 2012           1,144
================================================================================

(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.

36                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

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).

As of year-end 2007, key  development  achievements  associated with the Horizon
Project were as follows:

|X|  Phase 1 work progress is 90% complete.

|X|  Mine overburden has removed 49.9 million bank cubic meters of material.


CANADIAN NATURAL RESOURCES LIMITED                                            37
<PAGE>

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

38                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

FIGURE 2 - GENERAL STRATIGRAPHY OF THE HORIZON OIL SANDS PROJECT


                               [GRAPHIC OMITTED]


HORIZON OIL SANDS PROJECT MINING RESERVES

For the year ended December 31, 2007, the Company  retained GLJ to evaluate 100%
of Phase 1 to Phase 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 evaluated in 2007  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
39 years of projected production 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.


CANADIAN NATURAL RESOURCES LIMITED                                            39
<PAGE>

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


                                [GRAPHIC OMITTED]



40                                            CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

FIGURE 4 - HORIZON OIL SANDS PROJECT CORE HOLE COVERAGE


                               [GRAPHIC OMITTED]




CANADIAN NATURAL RESOURCES LIMITED                                            41
<PAGE>

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, 2007:

                                        Constant Prices
--------------------------------------------------------------------------------
                                    Bitumen                 Synthetic crude oil
                                    (mmbbl)                     (1) (mmbbl)
                              Gross                         Gross
                            Lease (2)        Net           Lease (2)         Net
--------------------------------------------------------------------------------
Total proved
   reserves                  2,385         1,995            1,956          1,761
Total Proved and
   probable reserves         3,525         2,969            2,958          2,680
================================================================================

(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,  NGLs  and  natural  gas
production  and  revenues  received  for  the  last  three  financial  years  is
summarized in the following tables:

                                                     Year Ended Dec 31
                                            2007           2006           2005
--------------------------------------------------------------------------------
Daily production, before
 royalties
   Crude oil and NGLs (bbl/d)              331,232        331,998        313,168
   Natural gas (mmcf/d)                      1,668          1,492          1,439
--------------------------------------------------------------------------------
Annual production, before
 royalties
   Crude oil and NGLs (mbbl)               120,900        121,179        114,306
   Natural gas (bcf)                           609            545            525
================================================================================


42                                            CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

NETBACKS

INFORMATION BY QUARTER

<TABLE>
<CAPTION>

                                                     2007
-------------------------------------------------------------------------------------
                                                                                 YEAR
                                   Q1          Q2          Q3          Q4       ENDED
-------------------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION
 VOLUMES, BEFORE ROYALTIES

<S>                           <C>         <C>         <C>         <C>         <C>
Crude oil and
  NGLs (bbl/d)                327,001     327,494     333,062     337,240     331,232
Natural gas (mmcf/d)            1,717       1,722       1,647       1,589       1,668
-------------------------------------------------------------------------------------

PRODUCT NETBACKS
Crude oil and
  NGLs ($/bbl)
   Sales price (1)          $   51.71   $   53.74   $   58.10   $   58.03   $   55.45
   Royalties                     4.92        5.46        6.65        6.66        5.94
   Production
     expenses                   13.81       15.01       13.13       11.53       13.34
-------------------------------------------------------------------------------------
   NETBACK                  $   32.98   $   33.27   $   38.32   $   39.84   $   36.17
-------------------------------------------------------------------------------------

Natural gas ($/mcf)
   Sales price (1)          $    7.74   $    7.44   $    5.87   $    6.28   $    6.85
   Royalties                     1.48        1.10        0.89        0.94        1.11
   Production
     expenses                    0.97        0.89        0.88        0.91        0.91
-------------------------------------------------------------------------------------
   NETBACK                  $    5.29   $    5.45   $    4.10   $    4.43   $    4.83
-------------------------------------------------------------------------------------

CRUDE OIL AND NGLS
  NETBACKS BY TYPE
Light/Pelican Lake/
  NGLs ($/bbl)
   Sales price (1)          $   60.19   $   64.10   $   67.34   $   72.62   $   65.99
   Royalties                     4.89        5.87        7.24        8.34        6.57
   Production
     expenses                   13.85       14.91       14.40       12.64       13.95
-------------------------------------------------------------------------------------
   NETBACK                  $   41.45   $   43.32   $   45.70   $   51.64   $   45.47
-------------------------------------------------------------------------------------

Heavy crude
  oil ($/bbl)
   Sales price (1)          $   41.24   $   41.85   $   48.10   $   43.06   $   43.66
   Royalties                     4.96        4.98        6.00        4.95        5.23
   Production
     expenses                   13.76       15.12       11.75       10.38       12.66
-------------------------------------------------------------------------------------
   NETBACK                  $   22.52   $   21.75   $   30.35   $   27.73   $   25.77
=====================================================================================

<CAPTION>
                                                     2006
-------------------------------------------------------------------------------------
                                                                                 YEAR
                                   Q1          Q2          Q3          Q4       ENDED
-------------------------------------------------------------------------------------
<S>                           <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
Natural gas (mmcf/d)            1,436       1,475       1,437       1,620       1,492
-------------------------------------------------------------------------------------

PRODUCT NETBACKS
Crude oil and
  NGLs ($/bbl)
   Sales price (1)          $   43.79   $   60.05   $   62.55   $   47.27   $   53.65
   Royalties                     3.48        5.14        5.11        4.10        4.48
   Production
     expenses                   11.33       11.92       13.47       12.32       12.29
-------------------------------------------------------------------------------------
   NETBACK                  $   28.98   $   42.99   $   43.97   $   30.85   $   36.88
-------------------------------------------------------------------------------------

Natural gas ($/mcf)
   Sales price (1)          $    8.30   $    6.16   $    5.83   $    6.66   $    6.72
   Royalties                     1.70        1.11        1.11        1.26        1.29
   Production
     expenses                    0.80        0.80        0.84        0.86        0.82
-------------------------------------------------------------------------------------
   NETBACK                  $    5.80   $    4.25   $    3.88   $    4.54   $    4.61
-------------------------------------------------------------------------------------

CRUDE OIL AND NGLS
  NETBACKS BY TYPE
Light/Pelican Lake/
  NGLs ($/bbl)
   Sales price (1)          $   58.28   $   69.02   $   71.65   $   57.68   $   64.33
   Royalties                     4.65        5.53        5.39        4.39        5.00
   Production
     expenses                   11.15       11.18       14.12       12.99       12.42
-------------------------------------------------------------------------------------
   NETBACK                  $   42.48   $   52.31   $   52.14   $   40.30   $   46.91
-------------------------------------------------------------------------------------

Heavy crude
  oil ($/bbl)
   Sales price (1)          $   25.22   $   50.08   $   51.38   $   36.11   $   41.20
   Royalties                     1.98        4.71        4.76        3.78        3.88
   Production
     expenses                   11.55       12.73       12.67       11.60       12.15
-------------------------------------------------------------------------------------
   NETBACK                  $   11.69   $   32.64   $   33.95   $   20.73   $   25.17
=====================================================================================
</TABLE>

NOTE:  PELICAN LAKE CRUDE OIL HAS AN API OF 14(0) TO 17(0),  BUT RECEIVES MEDIUM
QUALITY CRUDE  NETBACKS DUE TO LOWER  PRODUCTION  COSTS AND LOWER ROYALTY RATES.

(1) Net of  transportation  and blending  costs and  excluding  risk  management
activities.


CANADIAN NATURAL RESOURCES LIMITED                                            43
<PAGE>

NETBACKS

INFORMATION BY QUARTER

<TABLE>
<CAPTION>
                                                        2005
                                                                                Year
                                  Q1          Q2          Q3          Q4       Ended
------------------------------------------------------------------------------------
<S>                           <C>         <C>         <C>         <C>         <C>
AVERAGE DAILY PRODUCTION VOLUMES
Crude oil and NGLs
  (bbl/d)                     287,803     289,064     334,724     340,268    313,168
Natural gas (mmcf/d)            1,455       1,454       1,423       1,423      1,439
------------------------------------------------------------------------------------

PRODUCT NETBACKS
  Crude oil and NGLs ($/bbl)
   Sales price (1)          $   39.81   $   42.51   $   57.35   $   46.38   $  46.86
   Royalties                     3.39        3.33        5.11        3.89       3.97
   Production
     expenses                   11.30       11.66       11.48       10.33      11.17

------------------------------------------------------------------------------------
   Netback                  $   25.12   $   27.52   $   40.76   $   32.16   $  31.72
------------------------------------------------------------------------------------
   Natural gas ($/mcf)
   Sales price (1)          $    6.68   $    7.33   $    8.61   $   11.67   $   8.57
   Royalties                     1.30        1.48        1.93        2.30       1.75
   Production
     expenses                    0.69        0.71        0.76        0.76       0.73
------------------------------------------------------------------------------------
   Netback                  $    4.69   $    5.14   $    5.92   $    8.61   $   6.09
------------------------------------------------------------------------------------

CRUDE OIL AND NGLS NETBACKS BY TYPE
Light/Pelican Lake/
  NGLs ($/bbl)
   Sales price (1)          $   53.14   $   56.85   $   66.81   $    8.87   $  59.16
   Royalties                     5.20        4.55        5.50        4.40       4.90
   Production
     expenses                   11.58       12.28       11.47        8.90      10.93
------------------------------------------------------------------------------------
   Netback                  $   36.36   $   40.02   $   49.84   $   45.57   $  43.33
------------------------------------------------------------------------------------
   Heavy crude oil ($/bbl)
   Sales price (1)          $   25.21   $   27.82   $   47.25   $   30.27   $  33.09
   Royalties                     1.41        2.07        4.83        3.08       2.92
   Production
     expenses                   11.00       11.03       11.50       12.18      11.44
------------------------------------------------------------------------------------
   Netback                  $   12.80   $   14.72   $   30.92   $   15.01   $  18.73
=====================================================================================
</TABLE>

NOTE: PELICAN LAKE CRUDE OIL HAS AN API OF 14(0) TO 17(0), BUT RECEIVES MEDIUM
QUALITY CRUDE NETBACKS DUE TO LOWER PRODUCTION COSTS AND LOWER ROYALTY RATES.
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.


44                                           CANADIAN NATURAL RESOURCES LIMITED

<PAGE>

<TABLE>
<CAPTION>
                                               2007
                                                                                 YEAR
                               Q1          Q2         Q3          Q4            ENDED
-------------------------------------------------------------------------------------
<S>                            <C>          <C>         <C>         <C>         <C>
SEGMENTED
NORTH AMERICA PRODUCT
  NETBACKS
Light/Pelican Lake/NGLs
  ($/bbl)
   Sales price (1)          $   54.13   $   56.06   $   60.26   $   63.94   $   58.66
   Royalties                     8.84        9.22       11.55       12.56       10.57
   Production
     expenses                   11.74       12.11       11.58       10.82       11.56
-------------------------------------------------------------------------------------
   NETBACK                  $   33.55   $   34.73   $   37.13   $   40.56   $   36.53
-------------------------------------------------------------------------------------
Heavy crude oil ($/bbl)
   Sales price (1)          $   41.24   $   41.85   $   48.10   $   43.06   $   43.66
   Royalties                     4.96        4.98        6.00        4.95        5.23
   Production
     expenses                   13.76       15.12       11.75       10.38       12.66
-------------------------------------------------------------------------------------
   NETBACK                  $   22.52   $   21.75   $   30.35   $   27.73   $   25.77
-------------------------------------------------------------------------------------
Natural gas ($/mcf)
   Sales price (1)          $    7.79   $    7.47   $    5.88   $    6.31$       6.87
   Royalties                     1.50        1.11        0.90        0.95        1.12
   Production
     expenses                    0.95        0.87        0.87        0.90        0.90
-------------------------------------------------------------------------------------
   NETBACK                  $    5.34   $    5.49   $    4.11   $    4.46   $    4.85
-------------------------------------------------------------------------------------

NORTH SEA PRODUCT NETBACKS
Light crude oil ($/bbl)
   Sales price (1)          $   68.83   $   73.18   $   77.55   $   83.44   $   74.99
   Royalties                     0.13        0.13        0.14        0.19        0.14
   Production
     expenses                   18.57       22.11       23.61       18.95       20.78
-------------------------------------------------------------------------------------
   NETBACK                  $   50.13   $   50.94   $   53.80   $   64.30   $   54.07
-------------------------------------------------------------------------------------


Natural Gas ($/mcf)
   Sales price (1)          $    4.49   $    3.92   $    5.26   $    3.62   $    4.26
   Royalties                       --          --          --          --          --
   Production
     expenses                    2.58        2.26        2.29        1.50        2.17
-------------------------------------------------------------------------------------
   NETBACK                  $    1.91   $    1.66   $    2.97   $    2.12$       2.09
-------------------------------------------------------------------------------------

OFFSHORE WEST AFRICA PRODUCT
  NETBACKS
Light crude oil ($/bbl)
   Sales price (1)          $   58.60   $   72.84   $   70.52   $   81.89   $   71.68
   Royalties                     3.70        7.12        6.81        7.59        6.40
   Production
     expenses                    8.93        7.98        7.00        9.32        8.32
  ------------------------------------------------------------------------------------
   NETBACK                  $   45.97   $   57.74   $   56.71   $   64.98   $   56.96
-------------------------------------------------------------------------------------

  Natural gas ($/mcf)
   Sales price (1)          $    5.97   $    6.22   $    5.31   $    5.49   $    5.68
   Royalties                     0.38        0.59        0.51        0.52        0.51
   Production
     expenses                    1.48        1.10        1.39        1.89        1.48
  ------------------------------------------------------------------------------------
   NETBACK                  $    4.11   $    4.53   $    3.41   $    3.08   $    3.69
======================================================================================
</TABLE>


<TABLE>
<CAPTION>
                                                   2006
                                                                                 Year
                                   Q1          Q2          Q3          Q4       Ended
-----------------------------------------------------------------------------------
<S>                            <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
   Royalties                     8.98       10.87       10.86        7.80        9.59
   Production
     expenses                    9.86        9.75       10.81       13.18       10.93
  -----------------------------------------------------------------------------------
   NETBACK                  $   29.99   $   43.73   $   43.48   $   27.49   $   36.00
-------------------------------------------------------------------------------------

Heavy crude oil ($/bbl)
   Sales price (1)          $   25.22   $   50.08   $   51.38   $   36.11   $   41.20
   Royalties                     1.98        4.71        4.76        3.78        3.88
   Production
     expenses                   11.55       12.73       12.67       11.60       12.15
  -----------------------------------------------------------------------------------
   NETBACK                  $   11.69   $   32.64   $   33.95   $   20.73   $   25.17
-------------------------------------------------------------------------------------

Natural gas ($/mcf)
   Sales price (1)          $    8.39   $    6.21   $    5.86   $    6.70   $    6.77
   Royalties                     1.73        1.13        1.12        1.29        1.31
   Production
     expenses                    0.79        0.79        0.83        0.84        0.81
  -----------------------------------------------------------------------------------
   NETBACK                  $    5.87   $    4.29   $    3.91   $    4.57   $    4.65
-------------------------------------------------------------------------------------

NORTH SEA PRODUCT NETBACKS
Light crude oil ($/bbl)
   Sales price (1)          $   68.05   $   73.19   $   78.68   $   67.72   $   72.62
   Royalties                     0.12        0.17        0.11        0.14        0.13
   Production
     expenses                   16.85       17.18       20.28       14.76       17.57
  ------------------------------------------------------------------------------------
   NETBACK                  $   51.08   $   55.84   $   58.29   $   52.82   $   54.92
-------------------------------------------------------------------------------------

Natural Gas ($/mcf)
   Sales price (1)          $    2.38   $    2.33   $    2.38   $    3.48   $    2.66
   Royalties                       --          --          --          --          --
   Production
     expenses                    1.26        1.47        1.30        1.54        1.40
  -----------------------------------------------------------------------------------
   NETBACK                  $    1.12   $    0.86   $    1.08   $    1.94   $    1.26
-------------------------------------------------------------------------------------

OFFSHORE WEST AFRICA PRODUCT
  NETBACKS
Light crude oil ($/bbl)
   Sales price (1)          $   65.23   $   72.97   $   70.59   $   63.50   $   67.99
   Royalties                     1.55        1.87        4.89        3.02        2.81
   Production
     expenses                    6.08        5.61        7.97       10.05        7.45
  -----------------------------------------------------------------------------------
   NETBACK                  $   57.60   $   65.49   $   57.73   $   50.43   $   57.73
-------------------------------------------------------------------------------------

Natural gas ($/mcf)
   Sales price (1)          $    5.59   $    5.30   $    4.97   $    5.72   $    5.37
   Royalties                     0.13        0.14        0.34        0.27        0.22
   Production
     expenses                    1.00        0.36        1.39        2.01        1.19
  -----------------------------------------------------------------------------------
   NETBACK                  $    4.46   $    4.80   $    3.24   $    3.44   $    3.96
=====================================================================================
</TABLE>

NOTE: PELICAN LAKE CRUDE OIL HAS AN API OF 14(0) TO 17(0), BUT RECEIVES MEDIUM
QUALITY CRUDE NETBACKS DUE TO LOWER PRODUCTION COSTS AND LOWER ROYALTY RATES.
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.

CANADIAN NATURAL RESOURCES LIMITED                                            45
<PAGE>

<TABLE>
<CAPTION>
                                                           2005
                                                                                Year
                              Q1            Q2          Q3           Q4        Ended
--------------------------------------------------------------------------------------
<S>                         <C>         <C>         <C>         <C>         <C>
SEGMENTED
NORTH AMERICA PRODUCT NETBACKS
Light/Pelican Lake/NGLs ($/bbl)
   Sales price (1)          $   45.80   $   49.78   $   61.21   $   52.10   $   52.35
   Royalties                    10.64        8.77       11.49        9.62       10.13
   Production
     expenses                    8.30        8.40        9.27        8.60        8.65
-------------------------------------------------------------------------------------
   NETBACK                  $   26.86   $   32.61   $   40.45   $   33.88   $   33.57
-------------------------------------------------------------------------------------

Heavy Crude Oil ($/bbl)
   Sales price (1)          $   25.21   $   27.82   $   47.25   $   30.27   $   33.09
   Royalties                     1.41        2.07        4.83        3.08        2.92
   Production
     expenses                   11.00       11.03       11.50       12.18       11.44
-------------------------------------------------------------------------------------
   NETBACK                  $   12.80   $   14.72   $   30.92   $   15.01   $   18.73
-------------------------------------------------------------------------------------

Natural gas ($/mcf)
   Sales price (1)          $    6.73   $    7.38   $    8.69   $   11.79   $    8.65
   Royalties                     1.33        1.50        1.96        2.34        1.78
   Production
     expenses                    0.66        0.68        0.74        0.74        0.71
-------------------------------------------------------------------------------------
   NETBACK                  $    4.74   $    5.20   $    5.99   $    8.71   $    6.16
-------------------------------------------------------------------------------------

NORTH SEA PRODUCT NETBACKS
Light crude oil ($/bbl)
   Sales price (1)          $   59.56   $   64.81   $   74.46   $   66.88   $   66.57
   Royalties                     0.05        0.11        0.12        0.14        0.10
   Production
     expenses                   14.91       17.41       15.15       12.11       14.94
-------------------------------------------------------------------------------------
   NETBACK                  $   44.60   $   47.29   $   59.19   $   54.63   $   51.53
-------------------------------------------------------------------------------------

Natural gas ($/mcf)
   Sales price (1)          $    3.52   $    3.07   $    2.64   $    3.40   $    3.17
   Royalties                       --          --          --          --          --
   Production
     expenses                    2.52        2.92        2.30        1.96        2.44
-------------------------------------------------------------------------------------
   NETBACK                  $    1.00   $    0.15   $    0.34   $    1.44   $    0.73
-------------------------------------------------------------------------------------

OFFSHORE WEST AFRICA PRODUCT
  NETBACKS
Light crude oil ($/bbl)
   Sales price (1)          $   62.34   $   58.24   $   59.09   $   60.19   $   59.91
   Royalties                     1.90        1.81        1.54        1.57        1.62
   Production
     expenses                   11.43        8.47        5.81        5.62        6.50
-------------------------------------------------------------------------------------
   NETBACK                  $   49.01   $   47.96   $   51.74   $   53.00   $   51.79
-------------------------------------------------------------------------------------

Natural gas ($/mcf)
   Sales price (1)          $    7.67   $    6.88   $    5.52   $    5.13   $    5.91
   Royalties                     0.23        0.21        0.13        0.14        0.16
   Production
     expenses                    1.25        1.37        1.09        0.80        1.05
-------------------------------------------------------------------------------------
   NETBACK                  $    6.19   $    5.30   $    4.30   $    4.19   $    4.70
=====================================================================================
</TABLE>

NOTE: PELICAN LAKE CRUDE OIL HAS AN API OF 14(0) TO 17(0), BUT RECEIVES MEDIUM
QUALITY CRUDE NETBACKS DUE TO LOWER PRODUCTION COSTS AND LOWER ROYALTY RATES.
(1) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.

46                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

F.   HISTORICAL DRILLING ACTIVITY BY PRODUCT

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

                                                    Year Ended Dec 31
                                                2007                 2006
--------------------------------------------------------------------------------
                                         GROSS        NET      Gross       Net
--------------------------------------------------------------------------------
Natural gas                                478        383        855       641

Crude oil                                  655        592        666       603

Service/Stratigraphic                      256        254        376       375

Dry holes                                  107         93        133       119
--------------------------------------------------------------------------------
Total                                    1,496      1,322      2,030     1,738
--------------------------------------------------------------------------------
Total success rate (excluding
 service and stratigraphic
 test wells)                                          91%                   91%
================================================================================


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.

                                                        Year Ended Dec 31
($ millions)                                        2007                2006
-------------------------------------------------------------------------------
Net property (dispositions)
   aquisitions (1)                      $            (39)       $      4,733
Land acquisition and retention                        95                 210
Seismic evaluations                                  124                 130
Well drilling, completion and equipping            1,642               2,340
Production and related facilities                  1,205               1,314
-------------------------------------------------------------------------------
Total net reserve replacement
   expenditures                                    3,027               8,727
-------------------------------------------------------------------------------
Horizon Project:
   Phase 1 construction costs                      2,740               2,768
   Phase 2/3 costs                                   124                  79
   Capitalized interest, stock-based
       compensation and other                        437                 338
-------------------------------------------------------------------------------
Total Horizon Project                              3,301               3,185
-------------------------------------------------------------------------------
Midstream                                              6                  12
Abandonments ((2))                                    71                  75
Head office                                           20                  26
-------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES          $          6,425              12,025
================================================================================


CANADIAN NATURAL RESOURCES LIMITED                                           47

<PAGE>

CAPITAL EXPENDITURES BY QUARTER

<TABLE>
<CAPTION>
                                                       2007 Three Months Ended
($ millions)                                     Mar 31    Jun 30     Sep 30   Dec 31
----------------------------------------------------------------------------------------
<S>                                               <C>     <C>        <C>         <C>
Net property acquisitions (dispositions) (1)    $    46  $     15 $       7  $    (107)
Land acquisition and retention                       29        22        29         15
Seismic evaluation                                   50        34        23         17
Well drilling, completion and equipping             714       288       299        341
Production and related facilities                   334       243       238        390
----------------------------------------------------------------------------------------
Total net reserve replacement expenditures        1,173       602       596        656
----------------------------------------------------------------------------------------
Horizon Project:
     Phase 1 construction costs                     674       704       671        691
     Phase 2/3 costs                                 44        19        28         33
     Capitalized interest, stock-based
     compensation and other                          91       118       120        108
----------------------------------------------------------------------------------------
Total Horizon Project                               809       841       819        832
----------------------------------------------------------------------------------------
Midstream                                             2      --           2          2
Abandonments ((2))                                   20        13        22         16
Head office                                           5         4         3          8
----------------------------------------------------------------------------------------
Total net capital expenditures                  $ 2,009  $  1,460 $   1,442  $   1,514
========================================================================================
</TABLE>


CAPITAL EXPENDITURES BY QUARTER

<TABLE>
<CAPTION>
                                                       2006 Three Months Ended
($ millions)                                     Mar 31    Jun 30     Sep 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
Production and related facilities                   500       233       270        311
----------------------------------------------------------------------------------------
Total net reserve replacement expenditures        1,599       747       843      5,538
----------------------------------------------------------------------------------------
Horizon Project
     Phase 1 construction costs                     616       680       727        745
     Phase 2/3 costs                                  1         6        18         54
     Capitalized interest, stock-based
     compensation and other                          69        96        39        134
----------------------------------------------------------------------------------------
Total Horizon Project                               686       782       784        933
----------------------------------------------------------------------------------------
Midstream                                             3         6         2          1
Abandonments ((2))                                   15        17        24         19
Head office                                           6         6         8          6
----------------------------------------------------------------------------------------
Total net capital expenditures                  $ 2,309   $ 1,558   $ 1,661    $ 6,497
========================================================================================
(1)  INCLUDES BUSINESS COMBINATIONS.
(2)  ABANDONMENTS REPRESENT EXPENDITURES TO SETTLE ASSET RETIREMENT OBLIGATIONS
     AND HAVE BEEN REFLECTED AS CAPITAL EXPENDITURES IN THIS TABLE.
</TABLE>


48                                            CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

H.   UNDEVELOPED ACREAGE

The following table summarizes the Company's working interest holdings in core
region undeveloped acreage as at December 31, 2007:

(thousands)                                    Gross Acres            Net Acres
--------------------------------------------------------------------------------
North America
   Alberta                                         10,563                 9,001
   British Columbia                                 3,317                 2,373
   Saskatchewan                                       890                   775
   Manitoba                                            11                    11
--------------------------------------------------------------------------------
North Sea
   United Kingdom                                     356                   287
--------------------------------------------------------------------------------
Offshore West Africa
   Cote d'Ivoire                                       95                    55
   Gabon                                              152                   151
--------------------------------------------------------------------------------
Total                                              15,384                12,653
================================================================================


I.   DEVELOPED ACREAGE

The following table summarizes the Company's working interest holdings in core
region developed acreage as at December 31, 2007:

(thousands)                                    Gross Acres            Net Acres
--------------------------------------------------------------------------------
North America
   Alberta                                         6,081                  4,805
   British Columbia                                1,357                  1,024
   Saskatchewan                                      812                    590
   Manitoba                                            5                      5
--------------------------------------------------------------------------------
North Sea
   United Kingdom                                    122                     88
--------------------------------------------------------------------------------
Offshore West Africa
  Cote d'Ivoire                                        7                      4
--------------------------------------------------------------------------------
Total                                              8,384                  6,516
================================================================================


CANADIAN NATURAL RESOURCES LIMITED                                           49
<PAGE>

SELECTED FINANCIAL INFORMATION

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

                                                         Year Ended Dec 31
($ millions, except per share information)         2007                    2006
--------------------------------------------------------------------------------
Revenues(1)(net of royalties)                     $   11,152         $   10,398
Cash flow from operations                         $    6,198         $    4,932
Per common share - basic                          $    11.49         $     9.18
                 - diluted                        $    11.49         $     9.18
Net earnings                                      $    2,608         $    2,524
Per common share - basic                          $     4.84         $     4.70
                 - diluted                        $     4.84         $     4.70
Total assets                                      $   36,114         $   33,160
Total long-term debt                              $   10,940         $   11,043
================================================================================




                                                   2007 Three Months Ended
($ millions, except per share
      information)                      Mar 31      Jun 30    Sep 30     Dec 31
-------------------------------------------------------------------------------
Revenues (net of  royalties)         $   2,742   $   2,821 $   2,732  $   2,857
Net earnings                         $     269   $     841 $     700  $     798
Per common share - basic and diluted $    0.50   $    1.56 $    1.30  $    1.48
================================================================================




                                                   2006 Three Months Ended
($ millions, except per share
information)                            Mar 31      Jun 30    Sep 30     Dec 31
--------------------------------------------------------------------------------
Revenues (1) (net of royalties)      $   2,352   $   2,739 $   2,798  $   2,509
Net (loss) earnings                  $      57   $   1,038 $   1,116  $     313
Per common share - basic and diluted $    0.11   $    1.93 $    2.08  $    0.58
--------------------------------------------------------------------------------
(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.


50                                            CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

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
("Moody's"),  "BBB" with a stable  outlook by Standard & Poor's ("S&P") and "BBB
(high)" with a negative trend by DBRS Limited ("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.

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.


CANADIAN NATURAL RESOURCES LIMITED                                            51
<PAGE>

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.

            2007 Monthly Historical Trading on Toronto Stock Exchange
Month                                High        Low       Close  Volume Traded
--------------------------------------------------------------------------------
   January                         $ 62.60     $ 52.45   $  58.84   47,395,230
   February                        $ 61.19     $ 57.62   $  58.73   34,356,234
   March                           $ 65.50     $ 57.01   $  63.75   35,412,762
   April                           $ 68.54     $ 63.71   $  66.14   24,726,552
   May                             $ 72.31     $ 65.48   $  71.09   30,970,877
   June                            $ 74.99     $ 67.01   $  70.78   38,391,312
   July                            $ 77.80     $ 70.04   $  73.21   29,655,617
   August                          $ 73.52     $ 65.43   $  72.19   37,051,383
   September                       $ 80.02     $ 71.25   $  75.56   34,242,541
   October                         $ 78.98     $ 71.05   $  78.56   44,953,346
   November                        $ 79.91     $ 64.50   $  64.92   46,778,688
   December                        $ 73.72     $ 64.24   $  72.58   25,099,487
================================================================================

On January 20, 2005, the Company announced its intention to make a Normal Course
Issuer Bid through the  facilities of TSX and the NYSE,  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% 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 TSX 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% 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 TSX 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% of the 538,834,606  common shares of the
Company  outstanding  on January 15, 2007.  No shares were  purchased  under the
program. The Company has decided not to renew the Normal Course Issuer Bid until
subsequent to the completion of Phase 1 of the Horizon Project.


52                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

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  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.

                                          2007            2006            2005
--------------------------------------------------------------------------------
Cash dividends declared per
   common share                      $    0.34       $    0.30        $    0.24
================================================================================


In February  2008 the Board of  Directors  approved an 18%  increase in the 2008
quarterly  dividend  from  $0.085  per common  share to $0.10 per common  share,
effective with the April 1, 2008 payment.

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.


CANADIAN NATURAL RESOURCES LIMITED                                            53
<PAGE>

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>
NAME                          POSITION PRESENTLY HELD        PRINCIPAL OCCUPATION DURING PAST 5 YEARS
-------------------------------------------------------------------------------------------------------------------------------
<S>                           <C>                      <C>
Catherine M. Best             Director (2)(4)          Executive Vice-President,  Risk Management and Chief Financial Officer
Calgary, Alberta              (age 54)                 of the Calgary  Health  Region,  a fully  integrated  publicly  funded
Canada                                                 health care system,  from 2002 to present;  Vice-President,  Corporate
                                                       Services and Chief Financial Officer of the Calgary Health Region from
                                                       February  2000 to 2002;  prior  thereto with Ernst & Young since 1980,
                                                       most  recently as a Corporate  Audit  Partner  from 1991 to 2000.  Has
                                                       served  continuously as a director of the Company since November 2003.
                                                       Currently  serving on the board of directors  of Enbridge  Income Fund
                                                       and Superior Plus Income Fund.

N. Murray Edwards             Vice-Chairman and        President,  Edco  Financial  Holdings Ltd. (a private  management  and
Calgary/Banff, Alberta        Director(3)              consulting  company).  Has served  continuously  as a director  of the
Canada                        (age 48)                 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,  The Exchange  Group  (business  consulting  firm based in
Winnipeg, Manitoba            (age 65)                 Winnipeg,  Manitoba).  Prior  thereto,  served as Premier of  Manitoba
Canada                                                 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)  since May
Atlanta, Georgia              (age 58)                 2001;  prior thereto  United States  Ambassador to Canada.  Has served
USA                                                    continuously  as a director of the Company  since May 2002.  Currently
                                                       serving on the board of directors of Abitibi  Bowater  Inc.;  Canadian
                                                       National Railway Company; 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 director of the
Calgary, Alberta              Director                 Company since June 1982.
Canada                        (age 62)

Steve W. Laut                 President and Chief      President  and Chief  Operating  Officer of the  Company  since  April
Calgary, Alberta              Operating Officer and    2005. Prior thereto Executive Vice-President,  Operations 2001 to 2003
Canada                        Director                 and most recently  Chief  Operating  Officer 2003 to 2005.  Has served
                              (age 50)                 continuously as a director of the Company since August 2006.


Keith A.J. MacPhail           Director (3)(5)          Chairman,  President and Chief  Executive  Officer,  Bonavista  Energy
Calgary, Alberta              (age 51)                 Trust since November 1997 and Chairman,  NuVista Energy Ltd since July
Canada                                                 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 director of the
Calgary, Alberta              (age 62)                 Company since January 1989.
Canada
</TABLE>


54                                            CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

<TABLE>
<CAPTION>
NAME                          POSITION PRESENTLY HELD        PRINCIPAL OCCUPATION DURING PAST 5 YEARS
-------------------------------------------------------------------------------------------------------------------------------
<S>                           <C>                      <C>
Norman F. McIntyre            Director (3)(4)(5)       An independent  businessman.  Prior thereto Executive  Vice-President,
Calgary, Alberta              (age 62)                 Petro-Canada   from  1995  to  2002  and  most   recently   President,
Canada                                                 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 Petro Andina Resources Inc.

Frank J. McKenna              Director (1)(4)          Deputy Chair,  TD Bank Financial  Group.  Prior thereto Premier of New
Cap Pele, New Brunswick       (age 60)                 Brunswick  from 1987 to 1997;  Counsel  to  Atlantic  Canada  law firm
Canada                                                 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.

James S. Palmer, C.M.,        Director (3)(4)(5)       Chairman  and a Partner of Burnet,  Duckworth & Palmer LLP (law firm).
A. O. E., Q.C.                (age 79)                 Has served  continuously  as a director of the Company since May 1997.
Calgary, Alberta                                       Currently  serving on the board of  directors  of  Magellan  Aerospace
Canada                                                 Corporation.

Dr. Eldon R. Smith, OC, M.D.  Director (4)(5)          President  of Eldon R. Smith &  Associates  Ltd.,  and he is  Emeritus
Calgary, Alberta              (age 68)                 Professor  and  Former  Dean,  Faculty  of  Medicine,   University  of
Canada                                                 Calgary.  Has served  continuously  as a director of the Company since
                                                       May 1997.  Currently  serving  on the board of  directors  of  Vasogen
                                                       Inc.,   Sernova  Corp.;   Aston  Hill   Financial;   and   Ventripoint
                                                       Diagnostics Inc.

David A. Tuer                 Director (1)(2)(3)       Chairman,  Calgary  Health  Region since  October  2001 and  Executive
Calgary, Alberta              (age 58)                 Vice-Chairman  BA Energy Inc. from April 2005 to February 2008.  Prior
Canada                                                 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 Daylight Resources Trust;  Xtreme Coil Drilling Corp.;
                                                       Canadian Phoenix  Resources and,  Altalink  Management LLP., a private
                                                       limited partnership.

Real M. Cusson                Senior Vice-President,   Officer of the Company.
Calgary, Alberta              Marketing
Canada                        (age 57)

Real J. H. Doucet             Senior Vice-President,   Officer of the Company.
Calgary, Alberta              Oil Sands
Canada                        (age 55)

Allen M. Knight               Senior Vice-President,   Officer of the Company.
Calgary, Alberta              International &
Canada                        Corporate Development
                              (age 58)

Tim S. McKay                  Senior Vice-President,   Officer of the Company.
Calgary, Alberta              Operations
Canada                        (age 46)

Douglas A. Proll              Chief Financial Officer  Officer of the Company.
Calgary, Alberta              and Senior
Canada                        Vice-President, Finance
                              (age 57)
</TABLE>


CANADIAN NATURAL RESOURCES LIMITED                                            55
<PAGE>

<TABLE>
<CAPTION>
NAME                          POSITION PRESENTLY HELD        PRINCIPAL OCCUPATION DURING PAST 5 YEARS
-------------------------------------------------------------------------------------------------------------------------------
<S>                           <C>                      <C>
Lyle G. Stevens               Senior Vice-President,   Officer of the Company.
Calgary, Alberta              Exploitation
Canada                        (age 53)

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 55)

Jeffrey J. Bergeson           Vice-President,          Officer of the  Company  since May 2007;  prior  thereto  Exploitation
Calgary, Alberta              Exploitation West        Manager of the Company until May 2007.
Canada                        (age 51)

Corey B. Bieber               Vice-President, Finance  Officer of the Company since April 2005;  prior  thereto  Treasurer of
Calgary, Alberta              and Investor Relations   the Company March 2001 to July 2002;  Director,  Investor Relations of
Canada                        (age 44)                 Canada the Company from July 2002 to April 2005 and most recently
                                                       Vice-President, Investor Relations April 2005 to February 2007.

Mary-Jo E. Case               Vice-President,          Officer of the Company.
Calgary, Alberta              Land
Canada                        (age 49)

William R. Clapperton         Vice-President,          Officer of the Company.
Calgary, Alberta              Regulatory, Stakeholder
Canada                        and Environmental
                              Affairs
                              (age 45)

James F. Corson               Vice-President,          Officer  of  the   Company   since   January   2007;   prior   thereto
Calgary, Alberta              Human Resources,         Vice-President,  Human  Resources of Qatar  Petroleum Corp. from March
Canada                        Horizon                  1997 to July  2005 and most  recently  Director  Human  Resources  and
                              (age 57)                 Stakeholder Relations of the Company from July 2005 to 2007.

Randall S. Davis              Vice-President,          Officer  of the  Company  since  July  2004;  prior  thereto  Manager,
Calgary, Alberta              Finance and Accounting   Financial Reporting of the Company to July 2002;  Financial Controller
Canada                        (age 41)                 of the  Company  from  July  2002  to  July  2004  and  most  recently
                                                       Vice-President Financial Accounting and Controls July 2004 to February
                                                       2007.


Allan E. Frankiw              Vice-President,          Officer  of the  Company  since  March  2007;  prior  thereto  Manager
Calgary, Alberta              Production, Central      Midstream for Anadarko Canada  Corporation from November 1998 to March
Canada                        (age 51)                 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.

Jerome W. Harvey              Vice-President,          Officer of the  Company  since  April  2004;  prior  thereto  Manager,
Calgary, Alberta              Commercial Operations    Commercial Operations.
Canada                        (age 54)

Peter J. Janson               Vice-President,          Officer of the Company since  December 2004;  prior thereto  Director,
Calgary, Alberta              Engineering Integration  Production  Planning  and  Control  at Suncor  Oil Sands to June 2000,
Canada                        (age 50)                 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.
</TABLE>


56                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

<TABLE>
<CAPTION>
NAME                          POSITION PRESENTLY HELD        PRINCIPAL OCCUPATION DURING PAST 5 YEARS
-------------------------------------------------------------------------------------------------------------------------------
<S>                           <C>                      <C>
Philip A. Keele               Vice-President,          Officer of the Company since December 2004; prior thereto Mine Manager
Calgary, Alberta              Mining,                  at Fording Coal Limited to February  2001,  Chief Mine Engineer of the
Canada                        Project Horizon          Company  February 2001 to September  2002 and most recently  Director,
                              Oil Sands                Mine Engineering of the Company from September 2002 to December 2004.
                              (age 48)

Cameron S. Kramer             Vice-President,          Officer of the Company.
Calgary, Alberta              Development Operations
Canada                        (age 40)

Leon Miura                    Vice-President,          Officer  of  the  Company  since  August  2003;   prior  thereto  held
Calgary, Alberta              Upgrading                progressively  senior  positions at  Petroleos de Venezuela  including
                              (age 53)                 Canada 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.

S. John Parr                  Vice-President,          Officer of the  Company  since April 2004;  prior  thereto  Production
Calgary, Alberta              Production, East         Engineer,  NE Gas of the  Company  to July 2001,  Manager,  Production
Canada                        (age 46)                 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.

David A. Payne                Vice-President,          Officer of the Company since October 2004; prior thereto  Exploitation
Calgary, Alberta              Exploitation, Central    Manager,  Thermal  Heavy  of  the  Company  to  July  2000,  Director,
Canada                        (age 46)                 Exploitation  of  CNR  International  (U.K.)  Limited  a  wholly-owned
                                                       subsidiary of the Company from July 2000 to August 2003,  Exploitation
                                                       Manager, Technical Projects of the Company from August 2003 to October
                                                       2004,  Vice-President,  Exploitation,  West from October 2004 to April
                                                       2007, and most recently  Vice-President,  Exploitation,  East from May
                                                       2007 to February 2008.

William R. Peterson           Vice-President,          Officer of the  Company  since April 2004;  prior  thereto  Production
Calgary, Alberta              Production, West         Manager, West of the Company.
Canada                        (age 41)

John C. Puckering             Vice President,          Officer  of the  Company  since  April  2004;  prior  thereto  General
Calgary, Alberta              Site Development         Manager DCL  Construction  Inc. to November 2001,  President of 960925
Canada                        (age 61)                 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,          Officer of the Company  since January  2007;  prior  thereto  Manager,
Calgary,  Alberta             Human  Resources         Human Resources of the Company 2000 to 2005 and most recently Director
Canada                        (age 51)                 Human Resources 2005 to January 2007.


Joy P. Romero                 Vice President,          Officer of the  Company  since  March  2008;  prior  thereto  Manager,
Calgary, Alberta              Bitumen Production       Bitumen  Production  Process of the Company  January 2001 to September
Canada                        (age  51)                2002 and most recently  Director,  Bitumen  Production  Process of the
                                                       Company from September 2002 to March 2008.

Sheldon L. Schroeder          Vice-President,          Officer of the Company since April 2004;  prior thereto  engineer with
Fort McMurray, Alberta        Project Control          729248  Alberta  Ltd.  to June 2001,  Project  Control  Manager of the
Canada                        (age 40)                 Company from June 2001 to September  2002 and most recently  Director,
                                                       Project Control of the Company from September 2002 to April 2004.
</TABLE>

CANADIAN NATURAL RESOURCES LIMITED                                           57
<PAGE>

<TABLE>
<CAPTION>
NAME                          POSITION PRESENTLY HELD        PRINCIPAL OCCUPATION DURING PAST 5 YEARS
-------------------------------------------------------------------------------------------------------------------------------
<S>                           <C>                      <C>

Kendall W. Stagg              Vice-President,          Officer of the Company  since  October  2004;  prior  thereto  Cardium
Calgary, Alberta              Exploration, West        Geophysicist of the Company to April 2001,  Chief  Geophysicist of the
Canada                        (age 46)                 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,          Officer of the Company since November 2006;  prior thereto  Operations
Calgary, Alberta              Field Operations         Superintendent  of the  Company  April  1997 to  April  2003  and most
Canada                        (age 50)                 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  Manager
Calgary, Alberta              Information and          Information  and  Corporate  Services of the Company  January  2000 to
Canada                        Corporate Services       July 2006.
                              (age 48)

Domenic Torriero              Vice-President,          Officer  of  the  Company   since   November   2006;   prior   thereto
Calgary, Alberta              Exploration, Central     Vice-President  Geology and Geophysics of Petrovera  Resources Limited
Canada                        (age 43)                 January 1999 to March 2004 and most  recently  Exploration  Manager of
                                                       the Company March 2004 to November 2006.

Grant M. Williams             Vice-President,          Officer  of  the  Company  since  March  2007;   prior  thereto  Chief
Calgary, Alberta              Exploration, East        Geophysicist  of the  Company  October  1999 to October  2003 and most
Canada                        (age 50)                 recently Manager, Exploration Heavy Oil of the Company October 2003 to
                                                       April 2007.


Daryl G. Youck                Vice-President,          Officer of the Company since  February  2008;  prior thereto  Manager,
Calgary, Alberta              Exploitation, East       Exploitation of the Company July 2002 to February 2008.
Canada                        (age 39)

Lynn M. Zeidler               Vice-President,          Officer  of  the  Company  since  August  2003;   prior  thereto  held
Calgary, Alberta              Utilities and Offsites   progressively  senior  positions at Shell Canada Limited  including on
Canada                        and Horizon Construc-    secondment from Shell Canada Limited as Manager-Tier 1  Implementation
                              tion Management          at Sable  Offshore  Energy  Inc to  September  2000 and most  recently
                              (age 51)                 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 58)
Canada
------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1)  MEMBER OF THE NOMINATING AND CORPORATE GOVERNANCE COMMITTEE
(2)  MEMBER OF THE AUDIT COMMITTEE
(3)  MEMBER OF THE RESERVES COMMITTEE
(4)  MEMBER OF THE COMPENSATION COMMITTEE
(5)  MEMBER OF THE HEALTH, SAFETY, AND ENVIRONMENTAL COMMITTEE

All  directors  stand for election at each Annual  General  Meeting of Canadian
Natural shareholders. All of the current directors were elected to the Board at
the last  annual  general and special  meeting of  shareholders  held on May 3,
2007.  All of the current  directors  are  standing  for election at the Annual
General Meeting of Shareholders scheduled for May 8, 2008.

As at December 31, 2007, the directors and officers of the Company, as a group,
beneficially  owned or controlled or directed,  directly or indirectly,  in the
aggregate,   approximately   4%  of  the  total   outstanding   common   shares
(approximately  5% after the exercise of options  held by them  pursuant to the
Company's stock option plan).

58                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

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 is reasonably expected to materially affect the Company.


CANADIAN NATURAL RESOURCES LIMITED                                           59
<PAGE>

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  Multilateral  Instrument 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.

AUDITOR SERVICE FEES

The Audit Committee of the Board of Directors in 2007 approved  specified audit
and non-audit services to be performed by  PricewaterhouseCoopers  ("PwC"). The
services provided include:  (i) the annual audit of the Corporation's  internal
controls and December 31, 2007 consolidated  financial  statements  included in
the  Annual  Information  Form  and Form  40-F,  reviews  of the  Corporation's
quarterly unaudited 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  including debt covenant  compliance and
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.

Fees accrued to PwC are shown in the table below.

Auditor service                                     2007                  2006
-------------------------------------------------------------------------------
Audit fees                              $      2,729,315    $        3,126,287
Audit related fees                               164,000               121,353
Tax related fees                                 154,459               134,025
All other fees                                     9,440                 9,516
-------------------------------------------------------------------------------
                                        $      3,057,214    $        3,391,181
===============================================================================

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

60                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

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

The Company's auditors are  PricewaterhouseCoopers  LLP, Chartered Accountants,
who have prepared an  independent  auditors'  report dated February 26, 2008 in
respect of the Company's  consolidated  financial  statements with accompanying
notes as at and for the three years ended  December 31, 2007 and the  Company's
internal   control   over   financial   reporting  as  at  December  31,  2007.
PricewaterhouseCoopers  LLP has advised that they are independent  with respect
to the Company within the meaning of the Rules of  Professional  Conduct of the
Institute  of  Chartered  Accountants  of  Alberta  and  the  rules  of  the US
Securities and Exchange Commission.

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
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 General
Meeting and  Information  Circular dated March 19, 2008 in connection  with the
Annual General Meeting of Shareholders of Canadian Natural to be held on May 8,
2008  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, 2007 found on pages 39 to 68, 69 to 96
and 97 to 101  respectively,  of the 2007  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



CANADIAN NATURAL RESOURCES LIMITED                                           61
<PAGE>


                                  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, 2007.
     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, 2007 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, 2007 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, 2007.

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

3.   We carried out our evaluation in accordance  with standards set out in the
     Canadian Oil and Gas Evaluation  Handbook (the "COGE  Handbook")  prepared
     jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter)
     and the Canadian  Institute of Mining,  Metallurgy & Petroleum  (Petroleum
     Society)  with the  necessary  modifications  to reflect  definitions  and
     standards  under the U.S.  Financial  Accounting  Standards Board policies
     (the "FASB Standards") and the legal  requirements of the U.S.  Securities
     and Exchange Commission ("SEC Requirements").

4.   Those  standards  require that we plan and perform an evaluation to obtain
     reasonable  assurance as to whether the reserves data are free of material
     misstatement.  An evaluation also includes  assessing whether the reserves
     data are in accordance with principles and definitions as outlined above.

5.   The  following  table  sets  forth  the  estimated  net  present  value of
     conventional  reserves  (before  deduction of income taxes)  attributed to
     proved  conventional  crude oil, NGL and natural gas reserves  quantities,
     estimated using constant prices and costs and calculated  using a discount
     rate of 10  percent,  included  in the  reserves  data of the  Corporation
     evaluated  by us for the year ended  December  31, 2007 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:


62                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

<TABLE>
<CAPTION>
------------------------------------------------------------------------------|-----------------------------------------------
                                                                              |   NET PRESENT VALUES OF CONVENTIONAL RESERVES
                                                                              |
INDEPENDENT                                             LOCATION OF RESERVES  |  (BEFORE INCOME TAXES, 10% DISCOUNT RATE)
QUALIFIED RESERVES    DESCRIPTION AND PREPARATION DATE  COUNTRY OR FOREIGN    |  ($ MILLIONS)
EVALUATOR OR AUDITOR  OF EVALUATION REPORT              (GEOGRAPHIC AREA)     |   AUDITED   EVALUATED    REVIEWED       TOTAL
------------------------------------------------------------------------------|-----------------------------------------------
<S>                   <C>                               <C>                       <C>       <C>          <C>          <C>
Sproule Associates    Sproule Evaluated the                                   |
Ltd.                  P&NG Reserves as reported                               |
                      February 11th, 2008.              Canada, USA           |        $0    $22,325           $0     $22,325
------------------------------------------------------------------------------|-----------------------------------------------
Ryder Scott Company   Ryder Scott Evaluated the                               |
                      P&NG Reserves  as   reported      United Kingdom and    |
                      February 11th, 2008.              Offshore West Africa  |        $0    $12,253           $0     $12,253
                                                                              |
------------------------------------------------------ -----------------------|-----------------------------------------------
  TOTALS                                                                      |        $0    $34,578           $0     $34,578
------------------------------------------------------------------------------|-----------------------------------------------

</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, 2007. GLJ Petroleum  Consultants  ("GLJ"), an
independent  qualified  reserves  evaluator,   was  retained  by  the  Reserves
Committee  of  Canadian  Natural's  Board of  Directors  to  evaluate  reserves
associated with the Horizon Project incorporating both the mining and upgrading
projects.  These  reserves were  evaluated  under SEC Industry  Guide 7 and are
disclosed separately from the Company's  conventional crude oil and natural gas
activities.

6.   In our opinion,  the reserves data  respectively  evaluated by us have, in
     all material respects, been determined and are in accordance with the COGE
     Handbook  as  modified  by the FASB  Standards  and SEC  requirements.  We
     express no opinion on the reserves data that we reviewed but did not audit
     or evaluate.

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

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.


CANADIAN NATURAL RESOURCES LIMITED                                           63
<PAGE>


Executed as to our report referred to above:

         February 11th, 2008

         SPROULE ASSOCIATES LIMITED
         CALGARY, ALBERTA, CANADA

         ORIGINAL SIGNED BY:

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

         ORIGINAL SIGNED BY:

         /s/ Doug Ho
         ---------------------------
         Doug Ho, P.Eng.
         Vice-President, Unconventional

         ORIGINAL SIGNED BY:

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


         RYDER SCOTT COMPANY
         CALGARY, ALBERTA, CANADA


         ORIGINAL SIGNED BY:

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


         GLJ PETROLEUM CONSULTANTS
         CALGARY, ALBERTA, CANADA


         ORIGINAL SIGNED BY:

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


64                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>


                                  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,  2007 using  constant
              prices and costs;

      (ii)    the related estimated net present value; and

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

(b)   (i)     both proved, and proved and probable conventional crude oil, NGLs
              and natural gas reserve  quantities  estimated as at December 31,
              2007 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, 2007.

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

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

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


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

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

(b)   the  filing  of  the  reports  of  the  independent   qualified  reserves
      evaluators on the reserves data; and

(c)   the content and filing of this report.

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



CANADIAN NATURAL RESOURCES LIMITED                                           65
<PAGE>


ORIGINAL SIGNED BY:

Steve W. Laut
President and Chief Operating Officer


ORIGINAL SIGNED BY:

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

ORIGINAL SIGNED BY:

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


ORIGINAL SIGNED BY:

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




Dated this 26th day of February, 2008
Calgary, Alberta


66                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>


                                  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.  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 "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

CANADIAN NATURAL RESOURCES LIMITED                                           67
<PAGE>

      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;

      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;


68                                           CANADIAN NATURAL RESOURCES LIMITED
<PAGE>

      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 :

                  (a)  all critical accounting policies and practices used;
                  (b)  all  alternative  treatments  of  financial  information
                       within GAAP that have been  discussed  with  management,
                       ramifications  of the  use of  such  treatments  and the
                       treatment preferred by the independent auditor;
                  (c)  other  material  written   communications   between  the
                       independent auditor and management;

           (ii)   scope and quality of the audit work performed;

           (iii)  adequacy  of  the   Corporation's   financial   and  auditing
                  personnel;

           (iv)   cooperation received from the Corporation's  personnel during
                  the audit;

           (v)    internal resources used;

           (vi)   significant  transactions  outside of the normal  business of
                  the Corporation;

           (vii)  significant  proposed  adjustments  and  recommendations  for
                  improving internal accounting controls, accounting principles
                  or management systems;

           (viii) the non-audit services provided by the independent  auditors;
                  and,

           (ix)   consider  the  independent   auditor's  judgments  about  the
                  quality and  appropriateness of the Corporation's  accounting
                  principles  and critical  accounting  estimates as applied in
                  its financial reporting; and,

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

      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;

      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.


CANADIAN NATURAL RESOURCES LIMITED                                           69
<PAGE>


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  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.



70                                           CANADIAN NATURAL RESOURCES LIMITED


<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, 2007. 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.



(signed) Steve W. Laut                        (signed) Douglas A. Proll


STEVE W. LAUT                                 DOUGLAS A. PROLL, CA
President & Chief Operating Officer           Chief Financial Officer &
                                              Senior Vice President, Finance



February 26, 2008
Calgary, Alberta, Canada


<PAGE>

[GRAPHIC OMITTED]
[LOGO - PRICEWATERHOUSECOOPERS LLP]
                                                |
                                                |  PRICEWATERHOUSECOOPERS LLP
                                                |  CHARTERED ACCOUNTANTS
                                                |  111 5 Avenue SW, Suite 3100
                                                |  Calgary, Alberta
                                                |  Canada T2P 5L3
                                                |  Telephone +1 (403) 509 7500
                                                |  Facsimile +1 (403) 781 1825
INDEPENDENT AUDITORS' REPORT                    |


To the Shareholders of Canadian Natural Resources Limited

We have completed  integrated audits of the consolidated  financial  statements
and internal  control over financial  reporting of Canadian  Natural  Resources
Limited  (the  "Company")  as at December 31, 2007 and 2006 and an audit of its
2005 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
at December  31,  2007 and  December  31,  2006,  and the related  consolidated
statements of earnings,  shareholders'  equity,  comprehensive  income and cash
flows for each of the years in the three year period  ended  December 31, 2007.
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 audits of the Company's  financial  statements as at December
31,  2007  and for  each of the  years in the two  year  period  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 audit of the Company's  financial  statements  for the year 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.  We  believe  that our audits
provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present
fairly, in all material  respects,  the financial position of the Company as at
December 31, 2007 and December 31, 2006 and the results of its  operations  and
its cash flows for each of the years in the three year  period  ended  December
31, 2007 in accordance with Canadian generally accepted accounting principles.

INTERNAL CONTROL OVER FINANCIAL REPORTING

We have also audited the Company's internal control over financial reporting as
at December  31,  2007,  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
included in the accompanying  management's  assessment of internal control over
financial  reporting.  Our  responsibility  is to  express  an  opinion  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,  assessing  the risk  that a
material  weakness  exists,  testing and  evaluating  the design and  operating
effectiveness  of internal  control based on the assessed  risk, and performing
such other procedures as we consider necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.

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

                                                                              2
<PAGE>

[GRAPHIC OMITTED]
[LOGO - PRICEWATERHOUSECOOPERS LLP]


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,  the Company  maintained,  in all material respects,  effective
internal  control  over  financial  reporting  as at December 31, 2007 based on
criteria  established in Internal Control -- Integrated Framework issued by the
COSO.


(signed) PricewaterhouseCoopers LLP


Chartered Accountants
Calgary, Alberta, Canada
February 26, 2008



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

In the United States,  reporting standards for auditors require the addition of
an  explanatory  paragraph  (following the opinion  paragraph)  when there is a
change in accounting principles that has a material effect on the comparability
of  the  Company's  consolidated  financial  statements,  such  as  the  change
described in Note 2 to the consolidated financial statements. Our report to the
shareholders  dated February 26, 2008 is expressed in accordance  with Canadian
reporting  standards  which do not  require  a  reference  to such a change  in
accounting  principles  in the  Auditors'  report  when the change is  properly
accounted  for  and  adequately   disclosed  in  the   consolidated   financial
statements.


(signed) PricewaterhouseCoopers LLP

Chartered Accountants
Calgary, Alberta, Canada
February 26, 2008



                                                                              3
<PAGE>

<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS

As at December 31
(millions of Canadian dollars)                                                 2007               2006
==========================================================================================================
<S>                                                                       <C>                <C>
ASSETS
CURRENT ASSETS
   Cash and cash equivalents                                              $      21          $      23
   Accounts receivable and other                                              1,662              1,947
   Future income tax (note 8)                                                   480                163
   Current portion of other long-term assets (note 3)                            18                106
----------------------------------------------------------------------------------------------------------
                                                                              2,181              2,239
PROPERTY, PLANT AND EQUIPMENT (note 4)                                       33,902             30,767
OTHER LONG-TERM ASSETS (note 3)                                                  31                154
----------------------------------------------------------------------------------------------------------
                                                                          $  36,114          $  33,160
==========================================================================================================

LIABILITIES
CURRENT LIABILITIES
   Accounts payable                                                             379                842
   Accrued liabilities                                                        1,567              1,618
   Current portion of other long-term liabilities (note 6)                    1,617                611
----------------------------------------------------------------------------------------------------------
                                                                              3,563              3,071
LONG-TERM DEBT (note 5)                                                      10,940             11,043
OTHER LONG-TERM LIABILITIES (note 6)                                          1,561              1,393
FUTURE INCOME TAX (note 8)                                                    6,729              6,963
----------------------------------------------------------------------------------------------------------
                                                                             22,793             22,470
----------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
SHARE CAPITAL (note 9)                                                        2,674              2,562
RETAINED EARNINGS                                                            10,575              8,141
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (note 10)                          72                (13)
----------------------------------------------------------------------------------------------------------
                                                                             13,321             10,690
----------------------------------------------------------------------------------------------------------
                                                                          $  36,114          $  33,160
==========================================================================================================
COMMITMENTS AND CONTINGENCIES (NOTE 13)
</TABLE>


Approved by the Board of Directors:


(signed) Catherine M. Best                     (signed) N. Murray Edwards

CATHERINE M. BEST                              N. MURRAY EDWARDS
Chair of the Audit Committee                   Vice-Chairman of the Board
and Director                                   of Directors and Director


                                                                              4
<PAGE>

<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF EARNINGS

For the years ended December 31
(millions of Canadian dollars, except per common share amounts)                       2007              2006              2005
================================================================================================================================
<S>                                                                             <C>               <C>               <C>
REVENUE                                                                         $   12,543        $   11,643        $   11,130
Less: royalties                                                                     (1,391)           (1,245)           (1,366)
--------------------------------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES                                                           11,152            10,398             9,764
--------------------------------------------------------------------------------------------------------------------------------
EXPENSES
Production                                                                           2,184             1,949             1,663
Transportation and blending                                                          1,570             1,443             1,293
Depletion, depreciation and amortization                                             2,863             2,391             2,013
Asset retirement obligation accretion (note 6)                                          70                68                69
Administration                                                                         208               180               151
Stock-based compensation (note 6)                                                      193               139               723
Interest, net                                                                          276               140               149
Risk management activities (note 12)                                                 1,562               312             1,952
Foreign exchange (gain) loss                                                          (471)              122              (132)
--------------------------------------------------------------------------------------------------------------------------------
                                                                                     8,455             6,744             7,881
--------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES                                                                2,697             3,654             1,883
Taxes other than income tax (note 8)                                                   165               256               194
Current income tax expense (note 8)                                                    380               222               286
Future income tax (recovery) expense (note 8)                                         (456)              652               353
--------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS                                                                    $    2,608        $    2,524        $    1,050
================================================================================================================================
NET EARNINGS PER COMMON SHARE (note 11)
   Basic                                                                        $     4.84        $     4.70        $     1.96
   Diluted                                                                      $     4.84        $     4.70        $     1.95
================================================================================================================================
</TABLE>

                                                                              5
<PAGE>

<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

For the years ended December 31
(millions of Canadian dollars)                                                        2007              2006              2005
===============================================================================================================================
<S>                                                                             <C>               <C>                <C>
SHARE CAPITAL
Balance - beginning of year                                                     $    2,562        $    2,442         $   2,408
Issued upon exercise of stock options                                                   21                21                 9
Previously recognized liability on stock options exercised for common shares            91               101                29
Purchase of common shares under Normal Course Issuer Bid                                 -                (2)               (4)
-------------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                                                2,674             2,562             2,442
-------------------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance - beginning of year, as originally reported                                  8,141             5,804             4,922
Transition adjustment on adoption of financial instruments standards (note 2)           10                 -                 -
-------------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year, as restated                                             8,151             5,804             4,922
Net earnings                                                                         2,608             2,524             1,050
Dividends on common shares (note 9)                                                   (184)             (161)             (127)
Purchase of common shares under Normal Course Issuer Bid                                 -               (26)              (41)
-------------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                                               10,575             8,141             5,804
-------------------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (note 2)
Balance - beginning of year                                                            (13)               (9)               (6)
Transition adjustment on adoption of financial instruments standards                   159                 -                 -
-------------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year, after effect of transition adjustment                     146                (9)               (6)
Other comprehensive loss, net of taxes                                                 (74)               (4)               (3)
-------------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                                                   72               (13)               (9)
-------------------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY                                                            $   13,321        $   10,690         $   8,237
===============================================================================================================================

<CAPTION>
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the years ended December 31
(millions of Canadian dollars)                                                       2007               2006              2005
===============================================================================================================================
<S>                                                                             <C>               <C>                <C>
NET EARNINGS                                                                    $    2,608        $    2,524         $   1,050
-------------------------------------------------------------------------------------------------------------------------------
    NET CHANGE IN DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW
       HEDGES
       Unrealized income during the year, net of taxes of $6 million
              (2006 - $nil, 2005 - $nil)                                                38                 -                 -
       Reclassification to net earnings, net of taxes of $45 million
              (2006 - $nil, 2005 - $nil)                                               (96)                -                 -
-------------------------------------------------------------------------------------------------------------------------------
                                                                                       (58)                -                 -
-------------------------------------------------------------------------------------------------------------------------------
    FOREIGN CURRENCY TRANSLATION ADJUSTMENT
       Translation of net investment                                                   (16)               (4)              (12)
       Hedge of net investment, net of taxes                                             -                 -                 9
-------------------------------------------------------------------------------------------------------------------------------
                                                                                       (16)               (4)               (3)
-------------------------------------------------------------------------------------------------------------------------------
OTHER COMPREHENSIVE LOSS, NET OF TAXES                                                 (74)               (4)               (3)
-------------------------------------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME                                                            $    2,534        $    2,520         $   1,047
===============================================================================================================================
</TABLE>

                                                                              6
<PAGE>

<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31
(millions of Canadian dollars)                                                        2007              2006              2005
=================================================================================================================================
<S>                                                                             <C>              <C>           <C>
OPERATING ACTIVITIES
Net earnings                                                                    $    2,608       $     2,524   $         1,050
Non-cash items
   Depletion, depreciation and amortization                                          2,863             2,391             2,013
   Asset retirement obligation accretion                                                70                68                69
   Stock-based compensation                                                            193               139               723
   Unrealized risk management loss (gain)                                            1,400            (1,013)              925
   Unrealized foreign exchange (gain) loss                                            (524)              134              (103)
   Deferred petroleum revenue tax expense (recovery)                                    44                37                (9)
   Future income tax (recovery) expense                                               (456)              652               353
Deferred charges and other                                                              38                (2)              (31)
Abandonment expenditures                                                               (71)              (75)              (46)
Net change in non-cash working capital (note 14)                                      (346)             (679)             (147)
---------------------------------------------------------------------------------------------------------------------------------
                                                                                     5,819             4,176             4,797
---------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
(Repayment) issue of bank credit facilities, net                                    (1,925)            6,499              (435)
Issue of medium-term notes                                                             273               400               400
Repayment of senior unsecured notes                                                    (33)                -              (194)
Issue of US dollar debt securities                                                   2,553               788                 -
Repayment of preferred securities                                                        -                 -              (107)
Issue of common shares on exercise of stock options                                     21                21                 9
Dividends on common shares                                                            (178)             (153)             (121)
Purchase of common shares                                                                -               (28)              (45)
Net change in non-cash working capital (note 14)                                         8                37                19
---------------------------------------------------------------------------------------------------------------------------------
                                                                                       719             7,564              (474)
---------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant and equipment                                       (6,464)           (7,266)           (5,340)
Net proceeds on sale of property, plant and equipment                                  110                71               454
---------------------------------------------------------------------------------------------------------------------------------
Net expenditures on property, plant and equipment                                  (6,354)            (7,195)           (4,886)
Acquisition of Anadarko Canada Corporation (note 15)                                     -            (4,641)                -
Net proceeds on sale of other assets                                                     -                 -                11
Net change in non-cash working capital (note 14)                                      (186)              101               542
---------------------------------------------------------------------------------------------------------------------------------
                                                                                    (6,540)          (11,735)           (4,333)
---------------------------------------------------------------------------------------------------------------------------------
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS                                        (2)                5               (10)
CASH AND CASH EQUIVALENTS - BEGINNING OF YEAR                                           23                18                28
---------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS - END OF YEAR                                         $       21       $        23   $            18
=================================================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (NOTE 14)
</TABLE>

                                                                              7
<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  conventional crude
oil and natural gas operations are focused in North America, largely in Western
Canada;  the United  Kingdom ("UK") portion of the North Sea; and Cote d'Ivoire
and Gabon, Offshore West Africa.

Within Western Canada,  the Company is developing its Horizon Oil Sands Project
(the  "Horizon  Project")  in a  series  of  staged  development  phases.  Each
development  phase  ("Phase")  is planned to result in  incremental  production
capacity.  The  Horizon  Project is  designed  to produce  synthetic  crude oil
through bitumen mining and upgrading operations.

Also within Western Canada, the Company maintains certain midstream  activities
that include 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
17.

Significant accounting policies are summarized as follows:

(A) PRINCIPLES OF CONSOLIDATION
The consolidated  financial  statements include the accounts of the Company and
all of its 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  impairment  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.  All of the  Company's
reserve estimates are evaluated annually by independent  engineering firms. The
imprecise  nature of reserves  estimates  makes it likely that the reserve base
and the related future cash flows will be revised over time as additional  data
becomes  available.  As a result,  reserve estimates are subject to measurement
uncertainty and the impact of differences  between actual and estimated amounts
on the consolidated financial statements of future periods could be material.

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

The  calculation  of income  taxes  requires  judgment in applying tax laws and
regulations,  estimating  the timing of  temporary  difference  reversals,  and
estimating  the  realizability  of future tax assets.  These  estimates  impact
current  and  future   income  tax  assets  and   liabilities,   and   expenses
(recoveries).

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.

                                                                              8
<PAGE>

(D) PROPERTY, PLANT AND EQUIPMENT
CONVENTIONAL CRUDE OIL AND NATURAL GAS
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  of  certain  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 a gain or loss except where such dispositions result in a change
in the depletion rate of the specific cost centre of 20% or more.

OIL SANDS MINING OPERATIONS AND UPGRADING OPERATIONS
The Company's  Horizon  Project  constitutes  mining  operations  and upgrading
operations and  accordingly,  capitalized  costs related to the Horizon Project
are accounted for separately from the Company's Canadian conventional crude oil
and natural gas costs. Capitalized costs for mining activities include property
acquisition,  construction and development costs.  Construction and development
costs  are  capitalized  separately  to  each  Phase  of the  Horizon  Project.
Construction  and development for a particular  Phase of the Horizon Project is
considered complete once the Phase is ready for its intended use. Costs related
to major maintenance  turnaround activities will be deferred and amortized on a
straight-line  basis over the period to the next  scheduled  major  maintenance
turnaround.

MIDSTREAM AND OTHER
The Company capitalizes all costs that expand the capacity or extend the useful
life of the assets.

(E) OVERBURDEN REMOVAL COSTS
Overburden  removal costs incurred  during  development of the Horizon  Project
mine are capitalized to property, plant and equipment. Overburden removal costs
incurred during  production of the Horizon Project mine will be included in the
cost of inventory produced, unless the overburden removal activity has resulted
in a  betterment  of the  mineral  property,  in which  case the costs  will be
capitalized to property,  plant and equipment.  Capitalized  overburden removal
costs will be  amortized  over the life of the mining  reserves  that  directly
benefited from the overburden removal activity.

(F) CAPITALIZED INTEREST
The  Company  capitalizes  construction  period  interest  based on the Horizon
Project  costs  incurred  and  the  Company's   cost  of  borrowing.   Interest
capitalization  on a particular Phase ceases once construction is substantially
complete and this Phase of the Horizon  Project is  available  for its intended
use. The Company continues to capitalize a portion of interest costs related to
subsequent on-going Phases of the Horizon Project.

(G) LEASES
Contractual  arrangements that meet the definition of a lease are accounted for
as capital  leases or operating  leases as  appropriate.  Leases that  transfer
substantially  all of the  benefits  and risks of  ownership to the Company are
accounted  for as  capital  leases  and are  recorded  as  property,  plant and
equipment with an offsetting  liability.  All other leases are accounted for as
operating leases and lease costs are expensed as incurred.

(H) DEPLETION, DEPRECIATION AND AMORTIZATION
CONVENTIONAL CRUDE OIL AND NATURAL GAS
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  conventional  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 expense 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.

                                                                              9
<PAGE>

OIL SANDS MINING OPERATIONS AND UPGRADING OPERATIONS
Upon commencement of operations for the Horizon Project, mine-related costs and
costs of the upgrader  located on the Horizon Project site will be amortized on
the  unit-of-production  method  based on the  estimated  proved  and  probable
reserves of the Horizon  Project or the productive  capacity,  as  appropriate.
Moveable  mine-related  equipment is depreciated on a straight-line  basis over
its estimated useful life.

The Company reviews the carrying amount of the Horizon Project  relative to its
recoverable  amount if  circumstances  or events  indicate  impairment may have
occurred.  The recoverable  amount is calculated as the undiscounted  cash flow
from the Horizon Project assets using proved and probable reserves and expected
future prices and costs. If the carrying amount exceeds the recoverable amount,
an impairment  loss is recognized in depletion equal to the amount by which the
carrying  amount of the assets exceeds fair value.  Fair value is calculated as
the cash flow from the Horizon  Project using proved and probable  reserves and
expected future prices and costs, discounted at a risk-free interest rate.

MIDSTREAM AND OTHER
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.

Other capital assets are amortized on a declining balance basis.

(I) ASSET RETIREMENT OBLIGATIONS
The Company  provides for future asset  retirement  obligations on its resource
properties,  facilities, production platforms, gathering systems, and oil sands
mining operations and tailings ponds 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  Horizon  Project  upgrader and related  infrastructure  and its
midstream 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.

(J) 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 accumulated  other  comprehensive  income
(loss) 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. Gains or losses on translation of integrated foreign operations
and foreign  currency  balances are included in the  consolidated  statement of
earnings.


                                                                             10
<PAGE>

(K) 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.

(L) 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.

(M) 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 oil and profit oil. Cost recovery oil allows the Company to
recover its capital and  production  costs and the costs carried by the Company
on behalf of the Government  State Oil Company.  Profit oil 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 oil  attributable  to the  Company's  equity  interest is  allocated  to
royalty  expense and current income tax expense in accordance with the terms of
the PSCs.

(N) PETROLEUM REVENUE TAX
The  Company  accounts  for  the  UK  petroleum  revenue  tax  ("PRT")  by  the
life-of-the-field  method.  The total  future  liability  or recovery of PRT is
estimated  using proved and  probable  reserves  and  anticipated  future 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.

(O) 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.  Accordingly,  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,  timing and
amount of capital expenditures incurred in Canada in any particular year.

(P) 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 a 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  capitalized
during the construction  period in the case of the Horizon Project.  When stock
options  are  surrendered  for  cash,  the cash  settlement  paid  reduces  the
outstanding liability. When stock options are exercised for common shares under
the Option Plan,  consideration paid by employees and any previously recognized
liability associated with the stock options are recorded as share capital.

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

                                                                             11
<PAGE>

(Q) FINANCIAL INSTRUMENTS
The Company  classifies  its  financial  instruments  into one of the following
categories as defined by the CICA Handbook:  held-for-trading  financial assets
and financial liabilities, held-to-maturity investments, loans and receivables,
available-for-sale  financial  assets,  and other  financial  liabilities.  All
financial  instruments  are  required  to be  measured at fair value on initial
recognition.   Measurement   in   subsequent   periods  is   dependent  on  the
classification of the financial instrument.

Held-for-trading  financial instruments are subsequently measured at fair value
with  changes  in fair value  recognized  in net  earnings.  Available-for-sale
financial assets are  subsequently  measured at fair value with changes in fair
value  recognized  in  other  comprehensive  income,  net  of  tax.  All  other
categories of financial  instruments  are measured at amortized  cost using the
effective interest method.

Cash and cash equivalents are classified as  held-for-trading  and are measured
at fair value.  Accounts  receivable are  classified as loans and  receivables.
Accounts  payable,  accrued  liabilities  and long-term  debt are classified as
other financial liabilities.  Although the Company does not intend to trade its
derivative  financial  instruments,  risk management assets and liabilities are
classified as  held-for-trading  for accounting  purposes unless  designated as
hedges.

Transaction costs that are directly attributable to the acquisition or issue of
a financial  asset or  financial  liability  and  original  issue  discounts on
long-term  debt  have  been  included  in the  carrying  value  of the  related
financial  asset or liability  and are amortized to  consolidated  net earnings
over the life of the financial instrument using the effective interest method.

(R) 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.

Effective January 1, 2007, all derivative financial  instruments are recognized
at estimated fair value on the consolidated balance sheet at each balance sheet
date. The estimated fair value of derivative  instruments  has been  determined
based on  appropriate  internal  valuation  methodologies  and/or  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
these differences may be material.

The Company formally  documents all derivative  financial  instruments that are
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  periodically  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. The effective portion of changes in
the fair value of derivative  commodity price contracts designated as cash flow
hedges  is  initially   recognized  in  other   comprehensive   income  and  is
reclassified to risk management  activities in consolidated net earnings in the
same  period or  periods  in which the crude oil or  natural  gas is sold.  The
ineffective portion of changes in the fair value of these designated  contracts
is immediately  recognized in risk management  activities in  consolidated  net
earnings. All changes in the fair value of non-designated crude oil and natural
gas commodity price  contracts are recognized in risk management  activities in
consolidated net earnings.

The Company  enters into  interest  rate swap  contracts to manage its fixed to
floating  interest rate mix on certain of its 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.  Changes in
the fair value of interest rate swap contracts  designated as fair value hedges
and  corresponding  changes in the fair value of the hedged  long-term debt are
included in interest expense in consolidated net earnings.  Changes in the fair
value of  non-designated  interest  rate swap  contracts  are  included in risk
management activities in consolidated net earnings.

Cross currency swap contracts are periodically used to manage currency exposure
on US dollar  denominated  long-term  debt.  The cross  currency swap contracts
require the  periodic  exchange of  payments  with the  exchange at maturity of
notional principal amounts on which the payments are based. Changes in the fair
value of the  foreign  exchange  component  of cross  currency  swap  contracts
designated as cash flow hedges are included in foreign exchange in consolidated
net  earnings.  The  effective  portion  of  changes  in the fair  value of the
interest rate  component of cross  currency swap  contracts  designated as cash
flow  hedges  is  initially  included  in  other  comprehensive  income  and is
reclassified to interest  expense when realized,  with the ineffective  portion
recognized in risk management activities in consolidated net earnings.  Changes
in the fair value of non-designated  cross currency swap contracts are included
in risk management activities in consolidated net earnings.

                                                                             12
<PAGE>

Gains or losses on the  termination  of  financial  instruments  that have been
designated  as  cash  flow  hedges  are  deferred   under   accumulated   other
comprehensive  income on the  consolidated  balance  sheets and amortized  into
consolidated net earnings in the period in which the underlying  hedged item 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 consolidated
net earnings.  Gains or losses on the termination of financial instruments that
have not been designated as hedges are recognized in consolidated  net earnings
immediately.

Embedded derivatives are derivatives that are included in a non-derivative host
contract.  Embedded  derivatives are recorded at fair value separately from the
host contract when their economic characteristics and risks are not clearly and
closely related to the host contract.

(S) COMPREHENSIVE INCOME
Comprehensive  income is  comprised  of the  Company's  net  earnings and other
comprehensive income. Other comprehensive income includes the effective portion
of changes in the fair value of derivative financial instruments  designated as
cash flow hedges and foreign currency  translation  gains and losses on the net
investment in self-sustaining foreign operations. Other comprehensive income is
shown net of related income taxes.

(T) 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.

(U) RECENTLY ISSUED ACCOUNTING STANDARDS UNDER CANADIAN GAAP
Effective  January 1, 2008,  the  Company  will adopt the  following  three new
accounting standards issued by the CICA:

CAPITAL DISCLOSURES
  o   Section 1535 - "Capital  Disclosures" requires entities to disclose their
      objectives,  policies  and  processes  for managing  capital,  as well as
      quantitative data about capital. The section also requires the disclosure
      of any externally-imposed  capital requirements and compliance with those
      requirements.  The section does not define  capital.  The section affects
      disclosures  only  and will  not  impact  the  Company's  accounting  for
      capital.

INVENTORIES
  o   Section 3031 - "Inventories"  replaces  Section 3030 - "Inventories"  and
      establishes  new standards for the measurement of cost of inventories and
      expands  disclosure  requirements  for  inventories.   Adoption  of  this
      standard is not  anticipated  to have a material  impact on the Company's
      financial statements.

FINANCIAL INSTRUMENTS
  o   Section  3862 - "Financial  Instruments  -  Disclosure"  and Section 3863
      "Financial  Instruments - Presentation" replace Section 3861 - "Financial
      Instruments  -  Disclosure  and  Presentation".   Section  3862  enhances
      disclosure  requirements  concerning  risks and requires  disclosures  of
      quantitative and qualitative disclosures about exposures to risks arising
      from financial instruments. Section 3863 carries forward the presentation
      requirements   from  Section  3861  unchanged.   These  standards  affect
      disclosures  only  and will  not  impact  the  Company's  accounting  for
      financial instruments.

In  addition,  the  following  standard  was  issued  during  2008  and will be
effective for the  Company's  year  beginning on January 1, 2009,  with earlier
adoption permitted:

GOODWILL AND INTANGIBLE ASSETS
  o   Section 3064 - "Goodwill and Intangible  Assets"  replaces Section 3062 -
      "Goodwill and Other  Intangible  Assets" and Section 3450 - "Research and
      Development  Costs".  In  addition,  EIC-27 - "Revenue  and  Expenditures
      during the  Pre-Operating  Period" has been  withdrawn.  The new standard
      addresses  when  an  internally  generated  intangible  asset  meets  the
      definition  of an asset.  Adoption  of the new  standard  may  impact the
      Company's  capitalization  of certain  costs during the  development  and
      start-up of large development projects.

(V) COMPARATIVE FIGURES
Certain  prior  year  figures  have  been   reclassified   to  conform  to  the
presentation adopted in 2007.

                                                                             13
<PAGE>

2. CHANGE IN ACCOUNTING POLICY

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

  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  transactions
      with  owners.  The foreign  currency  translation  adjustment,  which was
      previously a separate component of shareholders'  equity, is now 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.

  o   Section 3855 - "Financial  Instruments  -  Recognition  and  Measurement"
      prescribes when a financial asset, financial liability,  or non-financial
      derivative  should  be  recognized  on the  balance  sheet as well as its
      measurement amount.

  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  these  standards  required  the  Company  to  record  all  of its
derivative  financial  instruments on the balance sheet at estimated fair value
as at January 1, 2007, including those designated as hedges. Designated hedges,
other than cross currency swaps,  were previously not recognized on the balance
sheet  but  were  disclosed  in the  notes  to the  financial  statements.  The
adjustment to recognize all designated hedges on the balance sheet was recorded
as an adjustment  to the opening  balance of retained  earnings or  accumulated
other comprehensive income, as appropriate.

With the  exception  of the  foreign  currency  translation  adjustment,  these
standards  were adopted  prospectively;  accordingly,  comparative  amounts for
prior  periods  have not been  restated.  The  reclassification  of the foreign
currency  translation  adjustment  to other  comprehensive  income was  applied
retroactively with prior period restatement.

The effects of adopting  these  standards on the opening  balance sheet were as
follows:

                                                               JANUARY 1, 2007
===============================================================================
Increased current portion of other long-term assets (1)      $             193
Decreased other long-term assets (2)                         $             (16)
Decreased long-term debt (3)                                 $             (72)
Increased retained earnings (4)                              $              10
Increased foreign currency translation adjustment (5)        $              13
Increased accumulated other comprehensive income (6)         $             146
Decreased current portion of future income tax asset (7)     $             (62)
Increased future income tax liability (7)                    $              18
===============================================================================
(1)   RELATES TO THE  RECOGNITION  OF THE CURRENT  PORTION OF THE FAIR VALUE OF
      DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(2)   RELATES TO THE RECOGNITION OF THE LONG-TERM  PORTION OF THE FAIR VALUE OF
      DERIVATIVE FINANCIAL  INSTRUMENTS  DESIGNATED AS CASH FLOW AND FAIR VALUE
      HEDGES, AS WELL AS THE RECLASSIFICATION OF TRANSACTION COSTS AND ORIGINAL
      ISSUE DISCOUNTS FROM DEFERRED CHARGES TO LONG-TERM DEBT.
(3)   RELATES  TO THE FAIR VALUE  IMPACT OF  DERIVATIVE  FINANCIAL  INSTRUMENTS
      DESIGNATED  AS FAIR  VALUE  HEDGES,  AS WELL AS THE  RECLASSIFICATION  OF
      TRANSACTION COSTS AND ORIGINAL ISSUE DISCOUNTS.
(4)   RELATES TO THE IMPACT ON ADOPTION OF THE  MEASUREMENT OF  INEFFECTIVENESS
      ON DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(5)   RELATES TO THE RETROACTIVE  RESTATEMENT OF FOREIGN  CURRENCY  TRANSLATION
      ADJUSTMENT TO ACCUMULATED OTHER COMPREHENSIVE INCOME.
(6)   RELATES TO THE  RECOGNITION OF  ACCUMULATED  OTHER  COMPREHENSIVE  INCOME
      ARISING FROM THE  MEASUREMENT OF  EFFECTIVENESS  ON DERIVATIVE  FINANCIAL
      INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(7)   RELATES TO THE FUTURE INCOME TAX IMPACTS OF THE ABOVE NOTED ADJUSTMENTS.

                                                                             14
<PAGE>

3. OTHER LONG-TERM ASSETS

<TABLE>
<CAPTION>
                                                                                                              2007          2006
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                      <C>           <C>
Deferred charges                                                                                         $      28     $     109
Risk management (note 12)                                                                                        -           128
Other                                                                                                           21            23
----------------------------------------------------------------------------------------------------------------------------------
                                                                                                                49           260
Less: current portion                                                                                           18           106
----------------------------------------------------------------------------------------------------------------------------------
                                                                                                         $      31     $     154
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

4. PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
                                                        2007                                                  2006
                                                 ACCUMULATED                                           Accumulated
                                               DEPLETION AND                                         depletion and
                                    COST        DEPRECIATION            NET             Cost          depreciation           Net
==================================================================================================================================
<S>                            <C>                 <C>            <C>              <C>                   <C>           <C>
Conventional crude oil
    and natural gas
  North America                $  34,195           $  12,162      $  22,033        $  31,715             $   9,836     $  21,879
  North Sea                        3,174               1,446          1,728            3,370                 1,341         2,029
  Offshore West Africa             1,833                 645          1,188            1,685                   481         1,204
  Other                               39                  14             25               38                    14            24
Horizon Project                    8,651                   -          8,651            5,350                     -         5,350
Midstream                            269                  64            205              263                    56           207
Head office                          170                  98             72              150                    76            74
----------------------------------------------------------------------------------------------------------------------------------
                               $  48,331           $  14,429      $  33,902        $  42,571             $  11,804     $  30,767
==================================================================================================================================
</TABLE>

During the year ended December 31, 2007, the Company capitalized administrative
overhead of $47 million  (2006 - $41 million,  2005 - $41 million)  relating to
exploration  and development in the North Sea and Offshore West Africa and $312
million (2006 - $255 million,  2005 - $134 million)  relating  primarily to the
Horizon Project in North America.

During the year ended December 31, 2007, the Company  capitalized  $356 million
(2006 - $196 million, 2005 - $72 million) 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:

<TABLE>
<CAPTION>
                                                                                                              2007          2006
==================================================================================================================================
<S>                                                                                                      <C>            <C>
Conventional crude oil and natural gas
  North America                                                                                          $   2,259      $  2,244
  North Sea                                                                                                     10            24
  Offshore West Africa                                                                                         138            84
  Other                                                                                                         25            24
Horizon Project                                                                                              8,651         5,350
----------------------------------------------------------------------------------------------------------------------------------
                                                                                                         $  11,083      $  7,726
==================================================================================================================================
</TABLE>

                                                                             15
<PAGE>

The  Company  has  used  the  following   estimated   benchmark  future  prices
("escalated pricing") in its full cost ceiling tests for conventional crude oil
and natural gas  activities  prepared in accordance  with Canadian  GAAP, as at
December 31, 2007:

<TABLE>
<CAPTION>
                                                                                                                        Average
                                                                                                                         annual
                                                                                                                       increase
                                                       2008           2009          2010          2011        2012   thereafter
================================================================================================================================
<S>                   <C>                         <C>            <C>           <C>           <C>          <C>              <C>
CRUDE OIL AND NGLS
North America
   WTI at Cushing (US$/bbl)                       $   89.61      $   86.01     $   84.65     $   82.77    $  82.26         2.0%
   Hardisty Heavy 12(degree) API (C$/bbl)         $   54.67      $   52.42     $   51.56     $   50.38    $  50.05         2.0%
   Edmonton Par (C$/bbl)                          $   88.17      $   84.54     $   83.16     $   81.26    $  80.73         2.0%
North Sea and Offshore West Africa
   North Sea Brent (US$/bbl)                      $   87.61      $   83.97     $   82.57     $   80.65    $  80.10         2.0%
--------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS
North America
   Henry Hub Louisiana  (US$/mmbtu)               $    7.56      $    8.27     $    8.74     $    8.75    $   8.66         2.0%
   AECO (C$/mmbtu)                                $    6.51      $    7.22     $    7.69     $    7.70    $   7.61         2.3%
   Huntingdon/Sumas (C$/mmbtu)                    $    6.51      $    7.22     $    7.69     $    7.70    $   7.61         2.3%
================================================================================================================================
</TABLE>



                                                                             16
<PAGE>

5. LONG-TERM DEBT

<TABLE>
<CAPTION>
                                                                                                            2007            2006
=================================================================================================================================
<S>                                                                                                    <C>            <C>
CANADIAN DOLLAR DENOMINATED DEBT
Bank credit facilities
   Bankers' acceptances                                                                                $   4,696      $    6,621
Medium-term notes
   7.40% unsecured debentures repaid March 1, 2007                                                             -             125
   5.50% unsecured debentures due December 17, 2010                                                          400               -
   4.50% unsecured debentures due January 23, 2013                                                           400             400
   4.95% unsecured debentures due June 1, 2015                                                               400             400
---------------------------------------------------------------------------------------------------------------------------------
                                                                                                           5,896           7,546
---------------------------------------------------------------------------------------------------------------------------------
US DOLLAR DENOMINATED DEBT
Senior unsecured notes
   Adjustable rate due May 27, 2009 (2007 - US$62 million, 2006 - US$93 million)                              61             108
US dollar debt securities
   7.80% due July 2, 2008 (2007 - US$8 million, 2006 - US$8 million)                                           8               9
   6.70% due July 15, 2011 (2007 - US$400 million, 2006 - US$400 million)                                    395             466
   5.45% due October 1, 2012 (2007 - US$350 million, 2006 - US$350 million)                                  346             408
   4.90% due December 1, 2014 (2007 - US$350 million, 2006 - US$350 million)                                 346             408
   6.00% due August 15, 2016 (2007 - US$250 million, 2006 - US$250 million)                                  247             291
   5.70% due May 15, 2017 (2007 - US$1,100 million, 2006 - US$nil)                                         1,087               -
   7.20% due January 15, 2032 (2007 - US$400 million, 2006 - US$400 million)                                 395             466
   6.45% due June 30, 2033 (2007 - US$350 million, 2006 - US$350 million)                                    346             408
   5.85% due February 1, 2035 (2007 - US$350 million, 2006 - US$350 million)                                 346             408
   6.50% due February 15, 2037 (2007 - US$450 million, 2006 - US$450 million)                                445             525
   6.25% due March 15, 2038 (2007 - US$1,100 million, 2006 - US$nil)                                       1,087               -
Less - original issue discount on senior unsecured notes and US dollar debt securities (1)                   (23)              -
---------------------------------------------------------------------------------------------------------------------------------
                                                                                                           5,086           3,497
Change in fair value of interest rate swaps on US dollar debt securities (2)                                   9               -
---------------------------------------------------------------------------------------------------------------------------------
                                                                                                           5,095           3,497
---------------------------------------------------------------------------------------------------------------------------------
Long-term debt before transaction costs                                                                   10,991          11,043
Less - transaction costs (1) (3)                                                                             (51)              -
---------------------------------------------------------------------------------------------------------------------------------
                                                                                                       $  10,940      $   11,043
=================================================================================================================================
</TABLE>
(1)   EFFECTIVE JANUARY 1, 2007, THE COMPANY HAS INCLUDED  UNAMORTIZED ORIGINAL
      ISSUE  DISCOUNTS  AND  DIRECTLY  ATTRIBUTABLE  TRANSACTION  COSTS  IN THE
      CARRYING VALUE OF THE OUTSTANDING DEBT.
(2)   THE CARRYING VALUES OF US$350 MILLION OF 5.45% NOTES DUE OCTOBER 2012 AND
      US$350  MILLION OF 4.90% NOTES DUE DECEMBER 2014 HAVE BEEN ADJUSTED BY $9
      MILLION TO REFLECT THE FAIR VALUE IMPACT OF HEDGE ACCOUNTING.
(3)   TRANSACTION COSTS PRIMARILY REPRESENT UNDERWRITING COMMISSIONS CHARGED AS
      A PERCENTAGE  OF THE RELATED  DEBT  OFFERINGS,  AS WELL AS LEGAL,  RATING
      AGENCY AND OTHER PROFESSIONAL FEES.

BANK CREDIT FACILITIES
As at  December  31,  2007,  the  Company  had in place  unsecured  bank credit
facilities of $6,209 million, comprised of:

  o   a $100 million demand credit facility;
  o   a non-revolving  syndicated  credit  facility of $2,350 million  maturing
      October 2009;
  o   a revolving  syndicated  credit facility of $2,230 million  maturing June
      2012;
  o   a revolving  syndicated  credit facility of $1,500 million  maturing June
      2012; and
  o   a (pound)15 million demand credit facility related to the Company's North
      Sea operations.

                                                                             17
<PAGE>

During 2007, one of the revolving  syndicated  credit  facilities was increased
from $1,825 million to $2,230 million and a $500 million demand credit facility
was terminated.  The revolving  syndicated credit facilities were also extended
and now mature June 2012. 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  Anadarko  Canada
Corporation  ("ACC") in November 2006 (note 15), the Company  executed a $3,850
million,  non-revolving syndicated credit facility maturing in October 2009. In
March 2007, $1,500 million was repaid, reducing the facility to $2,350 million.

The weighted average interest rate of the bank credit facilities outstanding at
December 31, 2007, was 5.2% (2006 - 4.8%).

In addition to the outstanding debt, letters of credit and financial guarantees
aggregating  $345  million,  including  $300  million  related  to the  Horizon
Project, were outstanding at December 31, 2007.

MEDIUM-TERM NOTES
In December 2007,  the Company issued $400 million of unsecured  notes maturing
December 2010,  bearing interest at 5.50%.  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 $2,600  million
remaining on its  outstanding  $3,000  million base shelf  prospectus  filed in
September 2007 that allows for the issue of  medium-term  notes in Canada until
October 2009. If issued,  these  securities will bear interest as determined at
the date of issuance.

During 2007, $125 million of the 7.40%  unsecured  debentures due March 1, 2007
were repaid.

In 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.

SENIOR UNSECURED NOTES
The adjustable rate senior unsecured notes bear interest at 6.54%,  with annual
principal  repayments  of US$31  million  due in May 2008 and May 2009.  During
2007, US$31 million of the senior unsecured notes were repaid.

US DOLLAR DEBT SECURITIES
In March  2007,  the  Company  issued  US$2,200  million  of  unsecured  notes,
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
swaps to fix the Canadian  dollar interest and principal  repayment  amounts on
the  entire  US$1,100  million  of  unsecured  notes  due May 2017 at 5.10% and
C$1,287  million (note 12). The Company also entered into a cross currency 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 (note 12).
Proceeds from the  securities  issued were used to repay  bankers'  acceptances
under the Company's bank credit facilities.

During 2007, the Company de-designated the portion of the US dollar denominated
debt  previously   hedged  against  its  net  investment  in  US  dollar  based
self-sustaining foreign operations.  Accordingly,  all foreign exchange (gains)
losses  arising  each period on US dollar  denominated  long-term  debt are now
recognized in the consolidated statement of earnings.

In 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  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 September  2007, the Company filed a base shelf  prospectus  that allows for
the issue of up to US$3,000  million of debt  securities  in the United  States
until October 2009.

Subsequent  to December  31,  2007,  the  Company  issued  US$1,200  million of
unsecured  notes  under  this US base  shelf  prospectus,  comprised  of US$400
million of 5.15%  unsecured  notes due February  2013,  US$400 million of 5.90%
unsecured  notes due February 2018, and US$400 million of 6.75% unsecured notes
due  February  2039.  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 US$1,800 million remaining on its outstanding
US$3,000 million base shelf prospectus.  If issued,  these securities will bear
interest as determined at the date of issuance.

                                                                             18
<PAGE>

REQUIRED DEBT REPAYMENTS
Required debt repayments are as follows:

<TABLE>
<CAPTION>
Year                                                                                                                Repayment
==============================================================================================================================
<C>                                                                                                             <C>
2008                                                                                                            $          39
2009                                                                                                            $       2,361
2010                                                                                                            $         400
2011                                                                                                            $         395
2012                                                                                                            $         346
Thereafter                                                                                                      $       5,098
==============================================================================================================================
</TABLE>

No debt  repayments  are reflected for $2,366  million of revolving bank credit
facilities due to the extendable nature of the facilities.

6. OTHER LONG-TERM LIABILITIES

<TABLE>
<CAPTION>
                                                                                                       2007              2006
==============================================================================================================================
<S>                                                                                            <C>               <C>
Asset retirement obligations                                                                   $      1,074      $      1,166
Stock-based compensation                                                                                529               744
Risk management (note 12)                                                                             1,474                 -
Other                                                                                                   101                94
------------------------------------------------------------------------------------------------------------------------------
                                                                                                      3,178             2,004
Less: current portion                                                                                 1,617               611
------------------------------------------------------------------------------------------------------------------------------
                                                                                               $      1,561      $      1,393
==============================================================================================================================
</TABLE>

ASSET RETIREMENT OBLIGATIONS
At December 31, 2007,  the  Company's  total  estimated  undiscounted  costs to
settle its asset retirement obligations were approximately $4,426 million (2006
- $4,497 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 a weighted average credit adjusted  risk-free interest rate of
6.6% (2006 - 6.7%;  2005 - 6.8%).  A  reconciliation  of the  discounted  asset
retirement obligations is as follows:

<TABLE>
<CAPTION>
                                                                                       2007             2006             2005
==============================================================================================================================
<S>                                                                              <C>              <C>              <C>
Asset retirement obligations
Balance - beginning of year                                                      $    1,166       $    1,112       $    1,119
   Liabilities incurred                                                                  21               26               47
   Liabilities (disposed) acquired (note 15)                                            (65)              56                -
   Liabilities settled                                                                  (71)             (75)             (46)
   Asset retirement obligation accretion                                                 70               68               69
   Revision of estimates                                                                 35              (21)             (56)
   Foreign exchange                                                                     (82)               -              (21)
------------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                                            $    1,074       $    1,166       $    1,112
==============================================================================================================================
</TABLE>


                                                                             19
<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.

<TABLE>
<CAPTION>
                                                                                       2007              2006              2005
================================================================================================================================
<S>                                                                             <C>                 <C>              <C>
Stock-based compensation
Balance - beginning of year                                                     $       744         $     891        $      323
   Stock-based compensation                                                             193               139               723
   Cash payment for options surrendered                                                (375)             (264)             (227)
   Transferred to common shares                                                         (91)             (101)              (29)
   Capitalized to Horizon Project                                                        58                79               101
--------------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                                                   529               744               891
Less: current portion of stock-based compensation                                       390               611               629
--------------------------------------------------------------------------------------------------------------------------------
                                                                                $       139         $     133        $      262
================================================================================================================================
</TABLE>

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  5.5%  (2006  - 5.0%)  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, 2007
was $32 million  (2006 - $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,  2007,  these plan assets had a fair
value of $47 million (2006 - $54 million).  The  unregistered  pension plan and
other  post-retirement  benefits are unfunded and have a benefit  obligation of
$10 million at December 31, 2007 (2006 - $15 million).

8. TAXES

TAXES OTHER THAN INCOME TAX

<TABLE>
<CAPTION>
                                                                                       2007              2006              2005
================================================================================================================================
<S>                                                                             <C>                <C>             <C>
Current petroleum revenue tax expense                                           $        97        $      196       $       181
Deferred petroleum revenue tax expense (recovery)                                        44                37                (9)
Provincial capital taxes and surcharges                                                  24                23                22
--------------------------------------------------------------------------------------------------------------------------------
                                                                                $       165        $      256       $       194
================================================================================================================================
</TABLE>

INCOME TAX
The provision for income tax is as follows:

<TABLE>
<CAPTION>
                                                                                       2007              2006              2005
================================================================================================================================
<S>                                                                             <C>                <C>             <C>
   Current income tax - North America                                           $        96        $      143       $        99
   Current income tax - North Sea                                                       210                30               155
   Current income tax - Offshore West Africa                                             74                49                32
--------------------------------------------------------------------------------------------------------------------------------
Current income tax expense                                                              380               222               286
Future income tax (recovery) expense                                                   (456)              652               353
--------------------------------------------------------------------------------------------------------------------------------
Income tax (recovery) expense                                                   $       (76)       $      874       $       639
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                                                             20
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                       2007              2006              2005
================================================================================================================================
<S>                                                                             <C>                <C>              <C>
Canadian statutory income tax rate                                                    32.5%             34.9%             38.0%
--------------------------------------------------------------------------------------------------------------------------------
Income tax provision at statutory rate                                          $       877        $    1,275       $       716
Effect on income taxes of:
   Non-deductible portion of Canadian crown payments                                      -               131               309
   Canadian resource allowance                                                            -              (129)             (293)
   Deductible UK petroleum revenue tax                                                  (71)              (82)              (65)
   Foreign tax rate differentials                                                        79                92                (1)
   North America income tax rate and other legislative changes                         (864)             (438)              (19)
   UK income tax rate changes                                                             -               110                 -
   Cote d'Ivoire income tax rate changes                                                  -               (67)                -
   Non-taxable portion of foreign exchange (gain) loss                                  (96)                5               (15)
   Other                                                                                 (1)              (23)                7
--------------------------------------------------------------------------------------------------------------------------------
Income tax (recovery) expense                                                   $       (76)       $      874       $       639
================================================================================================================================
</TABLE>

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

<TABLE>
<CAPTION>
                                                                                                         2007              2006
================================================================================================================================
<S>                                                                                                <C>              <C>
Future income tax liabilities
   Property, plant and equipment                                                                   $    5,695       $     6,088
   Timing of partnership items                                                                          1,288             1,394
   Unrealized foreign exchange gain on long-term debt                                                     199                93
   Unrealized risk management activities                                                                    -                40
   Other                                                                                                   55                13
Future income tax assets
   Asset retirement obligations                                                                          (380)             (487)
   Loss carryforwards for income tax                                                                     (104)              (85)
   Stock-based compensation                                                                              (125)             (232)
   Unrealized risk management activities                                                                 (399)                -
Deferred petroleum revenue tax                                                                             20               (24)
--------------------------------------------------------------------------------------------------------------------------------
Net future income tax liability                                                                         6,249             6,800
Less: current portion future income tax asset                                                            (480)             (163)
--------------------------------------------------------------------------------------------------------------------------------
Future income tax liability                                                                        $    6,729       $     6,963
================================================================================================================================
</TABLE>

During  2007,  enacted  or  substantively  enacted  income  tax rate and  other
legislative changes resulted in a reduction of future income tax liabilities of
approximately $864 million in North America.  As a result of the enacted income
tax rate  changes,  the  Canadian  federal  corporate  income  tax rate will be
reduced over the next five years from 21% in 2007 to 15% in 2012.

During 2006,  enacted 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,  enacted income tax rate changes resulted in a reduction of future
income tax liabilities of approximately $19 million in North America.

                                                                             21
<PAGE>

During 2003, the Canadian Federal Government enacted  legislation to change the
taxation of resource income.  The legislation  reduced 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 was phased out
and a deduction for actual crown royalties paid was phased in. As a result,  in
2007  crown  royalties  were  fully  deductible  and the  Company  is no longer
eligible for the resource allowance.

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.

<TABLE>
<CAPTION>
ISSUED
                                                                                   2007                         2006
                                                                              NUMBER OF                    Number of
                                                                                 SHARES                       shares
COMMON SHARES                                                               (THOUSANDS)       AMOUNT     (thousands)       Amount
==================================================================================================================================
<S>                                                                            <C>             <C>           <C>            <C>
Balance - beginning of year                                                    537,903      $  2,562         536,348     $  2,442
Issued upon exercise of stock options                                            1,826            21           2,040           21
Previously recognized liability on stock options exercised for common
    shares                                                                           -            91               -          101
Purchase of common shares under Normal Course Issuer Bid                             -             -            (485)          (2)
----------------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                                          539,729      $  2,674         537,903     $  2,562
==================================================================================================================================
</TABLE>

NORMAL COURSE ISSUER BID
During 2007,  the Company did not purchase any common  shares for  cancellation
pursuant to the Normal Course  Issuer Bid  previously  filed,  for the 12-month
period  beginning  January  24,  2007 and  ending on January  23,  2008 (2006 -
485,000  common shares were  purchased at an average price of $57.33 per common
share for a total  cost of $28  million,  2005 -  850,000  common  shares  were
purchased  at an average  price of $53.29 per common  share for a total cost of
$45 million). The Company has not renewed the Normal Course Issuer Bid in 2008.

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 February  2008, the Board of Directors set the Company's  regular  quarterly
dividend  at $0.10 per common  share  (2007 - $0.085 per common  share,  2006 -
$0.075 per common share).

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 of the option.

                                                                             22
<PAGE>

The  following  table   summarizes   information   relating  to  stock  options
outstanding at December 31, 2007 and 2006:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                                                            2007                                          2006
                                            STOCK OPTIONS         WEIGHTED AVERAGE         Stock options         Weighted average
                                              (thousands)           EXERCISE PRICE           (thousands)           exercise price
----------------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>                    <C>                     <C>                   <C>
Outstanding - beginning of year                    34,431              $     33.77                30,510              $     17.79
Granted                                             7,502              $     70.03                13,090              $     59.61
Surrendered for cash settlement                    (7,249)             $     16.10                (5,180)             $     12.60
Exercised for common shares                        (1,826)             $     11.71                (2,040)             $     10.67
Forfeited                                          (2,199)             $     46.46                (1,949)             $     37.51
----------------------------------------------------------------------------------------------------------------------------------
Outstanding - end of year                          30,659              $     47.23                34,431              $     33.77
----------------------------------------------------------------------------------------------------------------------------------
Exercisable - end of year                           7,640              $     30.00                 9,177              $     14.73
==================================================================================================================================
</TABLE>

The range of exercise  prices of stock options  outstanding  and exercisable at
December 31, 2007 were as follows:

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
                                                   STOCK OPTIONS OUTSTANDING                       STOCK OPTIONS EXERCISABLE
----------------------------------------------------------------------------------------------------------------------------------
                                                                WEIGHTED
                                          STOCK OPTIONS          AVERAGE          WEIGHTED       STOCK OPTIONS
                                            OUTSTANDING   REMAINING TERM           AVERAGE         EXERCISABLE   WEIGHTED AVERAGE
RANGE OF EXERCISE PRICES                    (thousands)          (years)    EXERCISE PRICE         (thousands)     EXERCISE PRICE
----------------------------------------------------------------------------------------------------------------------------------
<C>                                       <C>              <C>              <C>                  <C>              <C>
$9.63 - $9.99                                       935             0.06         $    9.63                 935        $      9.63
$10.00 - $19.99                                   5,510             1.38         $   15.50               2,886        $     14.66
$20.00 - $29.99                                   3,946             2.32         $   25.47               1,187        $     25.25
$30.00 - $39.99                                   1,012             2.72         $   33.25                 278        $     33.28
$40.00 - $49.99                                     573             4.06         $   46.79                 133        $     45.87
$50.00 - $59.99                                   5,980             3.76         $   57.99               1,168        $     57.81
$60.00 - $69.99                                   5,762             4.16         $   61.59               1,053        $     61.75
$70.00 - $73.35                                   6,941             5.16         $   70.72                   -        $         -
----------------------------------------------------------------------------------------------------------------------------------
                                                 30,659             3.40         $   47.23               7,640        $     30.00
==================================================================================================================================
</TABLE>

10. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive  income (loss), net of taxes,
were as follows:

<TABLE>
<CAPTION>
                                                                                                    2007                     2006
==================================================================================================================================
<S>                                                                                             <C>                     <C>
Derivative financial instruments designated as cash flow hedges                                 $    101                $        -
Foreign currency translation adjustment                                                              (29)                     (13)
----------------------------------------------------------------------------------------------------------------------------------
                                                                                                $     72                $     (13)
==================================================================================================================================
</TABLE>

During the next 12 months,  $22 million is expected to be  reclassified  to net
earnings from accumulated other comprehensive income.


                                                                             23
<PAGE>

11. NET EARNINGS PER COMMON SHARE

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

<TABLE>
<CAPTION>
(thousands of shares)                                                             2007                 2006                 2005
=================================================================================================================================
<S>                                                                       <C>                   <C>                  <C>
Weighted average common shares outstanding - basic                             539,336              537,339              536,650
Assumed settlement of preferred securities with common shares (1)                    -                    -                1,775
---------------------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding - diluted                           539,336              537,339              538,425
=================================================================================================================================
Net earnings                                                              $      2,608          $     2,524          $     1,050
Interest on preferred securities, net of taxes(1)                                    -                    -                    4
Revaluation of preferred securities, net of taxes(1)                                 -                    -                   (2)
---------------------------------------------------------------------------------------------------------------------------------
Diluted net earnings                                                      $      2,608          $     2,524          $     1,052
=================================================================================================================================
Net earnings per common share
   Basic                                                                  $       4.84          $      4.70          $      1.96
   Diluted                                                                $       4.84          $      4.70          $      1.95
=================================================================================================================================
</TABLE>
(1)   THE PREFERRED SECURITIES WERE REDEEMED IN SEPTEMBER 2005.

12. FINANCIAL INSTRUMENTS

RISK MANAGEMENT
The Company  uses  derivative  financial  instruments  to manage its  commodity
price, foreign currency and interest rate exposures. These derivative financial
instruments  are entered into solely for hedging  purposes and are not intended
for trading or other speculative purposes.

Commencing  January  1,  2007,  the  Company  recorded  all of  its  derivative
financial  instruments  on the  balance  sheet at fair value,  including  those
designated  as hedges.  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.

The estimated fair values of derivative financial instruments recognized in the
risk management asset (liability) were comprised as follows:

<TABLE>
<CAPTION>
                                                                             2007                              2006
--------------------------------------------------------------------------------------------------------------------------------
                                                                                  RISK                 Risk
                                                                            MANAGEMENT           management           Deferred
ASSET (LIABILITY)                                                       MARK-TO-MARKET       mark-to-market            revenue
================================================================================================================================
<S>                                                                       <C>                  <C>                   <C>
Balance - beginning of year                                               $        128         $       (877)         $      (8)
Retained earnings effect of adoption of financial instruments
   standards (note 2)                                                               14                    -                  -
Net cost of outstanding put options                                                 58                  455                  -
Net change in fair value of outstanding derivative financial
   instruments attributable to:
     - Risk management activities                                               (1,400)               1,005                  -
     - Interest expense                                                              9                    -                  -
     - Foreign exchange                                                           (350)                   -                  -
     - Other comprehensive income                                                  125                    -                  -
Amortization of deferred revenue                                                     -                    -                  8
--------------------------------------------------------------------------------------------------------------------------------
                                                                                (1,416)                 583                  -
Add: put premium financing obligations (1)                                         (58)                 (455)                -
--------------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                                           (1,474)                 128                  -
Less: current  portion                                                          (1,227)                  88                  -
--------------------------------------------------------------------------------------------------------------------------------
                                                                         $        (247)        $         40          $       -
================================================================================================================================
</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).

                                                                             24
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                   2007                2006                 2005
=================================================================================================================================
<S>                                                                      <C>                   <C>                  <C>
Net realized risk management loss                                        $          162        $      1,325         $      1,027
Net unrealized risk management loss (gain)                                        1,400              (1,013)                 925
---------------------------------------------------------------------------------------------------------------------------------
                                                                         $        1,562        $        312         $      1,952
=================================================================================================================================
</TABLE>

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,  and long-term debt.
The  carrying  value of these  financial  instruments  approximates  their fair
value, except as noted below.

<TABLE>
<CAPTION>
                                                                     2007                                       2006
(LIABILITY) ASSET                                CARRYING VALUE              FAIR VALUE         Carrying value         Fair value
==================================================================================================================================
<S>                                            <C>                      <C>                  <C>                  <C>
Derivative financial instruments               $        (1,416)         $       (1,416)      $             583    $           805
Fixed rate notes                               $        (6,318)         $       (6,259)      $          (4,410)   $        (4,434)
================================================================ === ===== ============= ====== =============== ==================
</TABLE>

The estimated fair values of these financial  instruments  have been determined
based on the Company's assessment of available market information,  appropriate
internal valuation methodologies and/or 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.

COMMODITY PRICE RISK MANAGEMENT

As  at  December  31,  2007,  the  Company  had  the  following  net  financial
derivatives outstanding to manage its commodity price exposures:

<TABLE>
<CAPTION>
                                              REMAINING TERM              VOLUME        WEIGHTED AVERAGE PRICE              INDEX
==================================================================================================================================
<S>                                      <C>                        <C>                 <C>                            <C>
CRUDE OIL
Crude oil price collars (1)              Jan 2008 - Mar 2008        50,000 bbl/d           US$60.00 - US$80.06                WTI
                                         Jan 2008 - Jun 2008        25,000 bbl/d           US$60.00 - US$80.44                WTI
                                         Apr 2008 - Sep 2008        25,000 bbl/d           US$60.00 - US$80.46                WTI
                                         Jul 2008 - Sep 2008        25,000 bbl/d          US$70.00 - US$123.75                WTI
                                         Oct 2008 - Dec 2008        25,000 bbl/d          US$70.00 - US$112.63                WTI
                                         Jan 2008 - Dec 2008        20,000 bbl/d           US$50.00 - US$65.53        Mayan Heavy
                                         Jan 2008 - Dec 2008        50,000 bbl/d           US$60.00 - US$75.22                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                           Jan 2008 - Dec 2008        50,000 bbl/d                      US$55.00                WTI
==================================================================================================================================
</TABLE>
(1)   SUBSEQUENT TO DECEMBER 31, 2007, THE COMPANY ENTERED INTO 25,000 BBL/D OF
      US$70.00 - US$111.56 WTI COLLARS FOR THE PERIOD JANUARY TO DECEMBER 2009.

The cost of outstanding put options of US$59 million will be settled in 2008.

<TABLE>
<CAPTION>
                                              REMAINING TERM              VOLUME        WEIGHTED AVERAGE PRICE              INDEX
==================================================================================================================================
<S>                                      <C>                        <C>                 <C>                            <C>
NATURAL GAS
AECO price collars                       Jan 2008 - Mar 2008        400,000 GJ/d           C$7.00   -  C$14.08               AECO
                                         Jan 2008 - 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, 2007, were all classified as cash flow hedges.

The Company's  outstanding  commodity financial  derivatives are expected to be
settled  monthly  based on the  applicable  index  pricing  for the  respective
contract month.

As at  December  31,  2007,  the net  pre-tax  unrealized  loss  related to the
de-designation  of  commodity  cash flow  hedges  was $15  million  (2006 - $41
million). This unrealized loss will be recognized in net earnings in 2008.

                                                                             25
<PAGE>

INTEREST RATE RISK MANAGEMENT
The Company is exposed to interest rate price risk on its fixed rate  long-term
debt and to interest rate cash flow risk on its floating rate  long-term  debt.
The Company  enters into interest  rate swap  agreements to manage its fixed to
floating  interest rate mix on long-term debt. The interest rate swap contracts
require the periodic  exchange of payments without the exchange of the notional
principal  amounts on which the payments are based.  At December 31, 2007,  the
Company had the following interest rate swap contracts outstanding:

<TABLE>
<CAPTION>
                                             REMAINING TERM        AMOUNT ($ millions)      FIXED RATE           FLOATING RATE
===============================================================================================================================
<S>                                     <C>                                  <C>             <C>            <C>
INTEREST RATE
Swaps - fixed to floating               Jan 2008 - Oct 2012                    US$350            5.45%      LIBOR (1)  + 0.81%
                                        Jan 2008 - Dec 2014                    US$350            4.90%      LIBOR (1)  + 0.38%
===============================================================================================================================
</TABLE>
(1) LONDON INTERBANK OFFERED RATE

All interest rate related derivative financial instruments designated as hedges
at December 31, 2007, were 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. At December 31, 2007, the
Company had the following cross currency swap contracts outstanding:

<TABLE>
<CAPTION>
                                                                    AMOUNT      EXCHANGE RATE    INTEREST RATE      INTEREST RATE
                                           REMAINING TERM     ($ millions)           (US$/C$)            (US$)               (C$)
==================================================================================================================================
<S>                                   <C>                      <C>              <C>              <C>                <C>
CURRENCY
Swaps                                 Jan 2008 - Aug 2016           US$250              1.116            6.00%              5.40%
                                      Jan 2008 - May 2017         US$1,100              1.170            5.70%              5.10%
                                      Jan 2008 - Mar 2038           US$550              1.170            6.25%              5.76%
==================================================================================================================================
</TABLE>

All cross  currency  related  derivative  financial  instruments  designated as
hedges at December 31, 2007, were 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
these risks by  reviewing  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 entering into  agreements  with  substantially  all
investment  grade financial  institutions  and other entities.  At December 31,
2007, the Company had net risk management  assets of $20 million  (December 31,
2006 -  $161  million)  with  specific  counterparties  related  to  derivative
financial instruments.



                                                                             26
<PAGE>

13. COMMITMENTS AND CONTINGENCIES

The Company has committed to certain payments as follows:

<TABLE>
<CAPTION>
                                                  2008            2009           2010           2011         2012       Thereafter
===================================================================================================================================
<S>                                         <C>             <C>            <C>            <C>            <C>          <C>
Product transportation and pipeline         $      232      $      151     $      137     $      109     $     91     $        972
Offshore equipment operating lease (1)      $      114      $      129     $      113     $      111     $     90     $        387
Offshore drilling (2) (3)                   $      267      $      185     $       39     $        -     $      -     $          -
Asset retirement obligations (4)            $       33      $        4     $        5     $        4     $      4     $      4,376
Office leases                               $       26      $       28     $       28     $       22     $      3     $          -
Electricity and other                       $      166      $      173     $       25     $        4     $      -     $          -
===================================================================================================================================
</TABLE>
(1)   OFFSHORE   EQUIPMENT   OPERATING   LEASES  ARE  PRIMARILY   COMPRISED  OF
      OBLIGATIONS RELATED TO FLOATING  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.  DURING THE INITIAL
      TERM,  THE TOTAL ANNUAL  PAYMENTS FOR THE GABON FPSO ARE  ESTIMATED TO BE
      US$50 MILLION.
(2)   DURING 2007, THE COMPANY  ENTERED INTO A ONE-YEAR  AGREEMENT FOR OFFSHORE
      DRILLING SERVICES RELATED TO THE BAOBAB FIELD IN COTE D'IVOIRE,  OFFSHORE
      WEST AFRICA.  THE AGREEMENT IS SCHEDULED TO COMMENCE IN 2008,  SUBJECT TO
      RIG AVAILABILITY. ESTIMATED TOTAL PAYMENTS OF US$100 MILLION, AFTER JOINT
      VENTURE  RECOVERIES,  HAVE BEEN  INCLUDED  IN THIS  TABLE FOR THE  PERIOD
      2008-2009.
(3)   DURING 2007, THE COMPANY AWARDED CONTRACTS FOR A DRILLING RIG AND FOR THE
      CONSTRUCTION OF WELLHEAD  TOWERS IN CONNECTION WITH THE PLANNED  OFFSHORE
      DEVELOPMENT IN GABON,  OFFSHORE WEST AFRICA.  ESTIMATED TOTAL PAYMENTS OF
      US$393 MILLION HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD 2008-2010.
(4)   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 2008 - 2012 REPRESENT THE MINIMUM  REQUIRED  EXPENDITURES  TO MEET
      THESE OBLIGATIONS.  ACTUAL EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED
      THESE MINIMUM AMOUNTS.

In  addition  to  the  amounts   disclosed  above,  the  Company  has  budgeted
construction  costs of  approximately  $1.7  billion to $1.9  billion  for 2008
related to the planned completion of Phase 1 of the Horizon Project.

The Company is defendant  and plaintiff in a number of legal actions that arise
in the  normal  course of  business.  In  addition,  the  Company is subject to
certain  contractor  construction  claims related to the Horizon  Project.  The
Company  believes that any liabilities  that might arise pertaining to any such
matters  would  not  have  a  material  effect  on its  consolidated  financial
position.

14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Changes in non-cash working capital were as follows:

<TABLE>
<CAPTION>
                                                                        2007                   2006                 2005
==========================================================================================================================
<S>                                                              <C>                 <C>                   <C>
(Increase) decrease in non-cash working capital
Accounts receivable and other                                    $       334         $         (116)       $         (498)
Accounts payable                                                        (456)                   157                   196
Accrued liabilities                                                     (402)                  (582)                  716
--------------------------------------------------------------------------------------------------------------------------
Net change in non-cash working capital                           $      (524)         $        (541)       $          414
--------------------------------------------------------------------------------------------------------------------------
Relating to:
Operating activities                                             $      (346)         $        (679)       $         (147)
Financing activities                                                       8                     37                    19
Investing activities                                                    (186)                   101                   542
--------------------------------------------------------------------------------------------------------------------------
                                                                 $      (524)         $        (541)       $          414
<CAPTION>
==========================================================================================================================

Other cash flow information:                                            2007                   2006                  2005
==========================================================================================================================
<S>                                                              <C>                  <C>                  <C>
Interest paid                                                    $       556          $         262        $          200
Taxes paid                                                       $       418          $         703        $          430
==========================================================================================================================
</TABLE>

                                                                             27
<PAGE>

15. BUSINESS COMBINATIONS
ANADARKO CANADA CORPORATION

In November  2006, the Company  completed the  acquisition of all of the issued
and  outstanding  common  shares 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 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 allocation of the net purchase price to assets  acquired
and liabilities assumed based on their fair values was as follows:

                                                               November 2, 2006
================================================================================
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 PURCHASE PRICE.




                                                                              28
<PAGE>

16. SEGMENTED INFORMATION
The Company's  conventional  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 conventional crude oil, natural gas liquids and natural gas.

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

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

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

Inter-segment  eliminations  include  internal  transportation  and electricity
charges.

<TABLE>
<CAPTION>
                                                          CONVENTIONAL CRUDE OIL AND NATURAL GAS
                              -----------------------------------------------------------------------------------------------------
                                        NORTH AMERICA                     NORTH SEA                    OFFSHORE WEST AFRICA
                                 2007        2006        2005        2007       2006        2005       2007       2006        2005
===================================================================================================================================
<S>                          <C>         <C>         <C>         <C>        <C>         <C>         <C>         <C>         <C>
SEGMENTED REVENUE            $ 10,149    $  9,066    $  8,955    $  1,597   $  1,616    $  1,659    $   776     $  950      $  485
Less: royalties                (1,318)     (1,203)     (1,350)         (3)        (3)         (3)       (70)       (39)        (13)
-----------------------------------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES       8,831       7,863       7,605       1,594      1,613       1,656        706        911         472
-----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production                      1,642       1,436       1,211         432        390         379         94        106          53
Transportation and
   blending                     1,595       1,465       1,310          16         15          20          1          1           -
Depletion, depreciation
   and amortization             2,350       1,897       1,595         340        297         306        165        189         104
Asset retirement
   obligation accretion            38          35          34          30         31          34          2          2           1
Realized risk management
   activities                     129       1,022         870          33        303         157          -          -           -
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES        5,754       5,855       5,020         851      1,036         896        262        298         158
-----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS BEFORE    $  3,077    $  2,008    $  2,585    $    743   $    577    $    760    $   444     $  613      $  314
   THE FOLLOWING
-----------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration
Stock-based compensation
Interest, net
Unrealized risk management activities
Foreign exchange (gain) loss
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED EXPENSES
-----------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES
Taxes other than income tax
Current income tax expense
Future income tax (recovery) expense
-----------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS
===================================================================================================================================
</TABLE>




                                                                              29
<PAGE>

<TABLE>
<CAPTION>
                                                                            INTER-SEGMENT
                                          MIDSTREAM                      ELIMINATION AND OTHER                   TOTAL
                             ------------------------------------------------------------------------------------------------------
                                 2007       2006        2005        2007       2006       2005        2007        2006        2005
===================================================================================================================================
<S>                          <C>         <C>        <C>         <C>         <C>        <C>        <C>         <C>         <C>
SEGMENTED REVENUE            $     74    $    72    $     77    $    (53)   $   (61)   $   (46)   $ 12,543    $ 11,643    $ 11,130
Less: royalties                     -          -           -           -          -          -      (1,391)     (1,245)     (1,366)
-----------------------------------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES          74         72          77         (53)       (61)       (46)     11,152      10,398       9,764
-----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production                         22         23          24          (6)        (6)        (4)      2,184       1,949       1,663
Transportation and blending         -          -           -         (42)       (38)       (37)      1,570       1,443       1,293
Depletion, depreciation
   and amortization                 8          8           8           -          -          -       2,863       2,391       2,013
Asset retirement
   obligation accretion             -          -           -           -          -          -          70          68          69
Realized risk management
   activities                       -          -           -           -          -          -         162       1,325       1,027
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES           30         31          32         (48)       (44)       (41)      6,849       7,176       6,065
-----------------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS BEFORE    $     44    $    41    $     45    $     (5)   $   (17)   $    (5)   $  4,303    $  3,222    $  3,699
   THE FOLLOWING
-----------------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration                                                                                         208         180         151
Stock-based compensation                                                                               193         139         723
Interest, net                                                                                          276         140         149
Unrealized risk management activities                                                                1,400      (1,013)        925
Foreign exchange (gain) loss                                                                          (471)        122        (132)
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED EXPENSES                                                                          1,606       (432)      1,816
-----------------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE TAXES                                                                                2,697       3,654       1,883
Taxes other than income tax                                                                            165         256         194
Current income tax expense                                                                             380         222         286
Future income tax (recovery) expense                                                                  (456)        652         353
-----------------------------------------------------------------------------------------------------------------------------------
NET EARNINGS                                                                                      $  2,608    $  2,524    $  1,050
===================================================================================================================================

<CAPTION>
CAPITAL EXPENDITURES

                                                   2007                                                      2006
                                              NON CASH/FAIR                                         Non cash/fair
                                      NET             VALUE     CAPITALIZED                Net              value     Capitalized
                             EXPENDITURES        CHANGES(1)           COSTS       expenditures         changes(1)           costs
==================================================================================================================================
<S>                          <C>                 <C>             <C>                <C>                <C>              <C>
Conventional crude oil
and natural gas
   North America             $      2,428        $       52      $    2,480         $    7,936         $    1,521       $   9,457
   North Sea                          439               (77)            362                646                (14)            632
   Offshore West
     Africa                           159               (11)            148                134                  1             135
   Other                                1                 -               1                 11                  -              11
----------------------------------------------------------------------------------------------------------------------------------
                                    3,027               (36)          2,991              8,727              1,508          10,235
Horizon Project (2)                 3,301                 -           3,301              3,185                  -           3,185
Midstream                               6                 -               6                 12                  -              12
Head office                            20                 -              20                 26                  -              26
----------------------------------------------------------------------------------------------------------------------------------
                             $      6,354        $      (36)     $    6,318         $   11,950         $    1,508       $  13,458
==================================================================================================================================
</TABLE>
(1)   ASSET  RETIREMENT  OBLIGATIONS,  FUTURE INCOME TAX ADJUSTMENTS  RELATED TO
      DIFFERENCES  BETWEEN  CARRYING  VALUE AND TAX VALUE,  AND OTHER FAIR VALUE
      ADJUSTMENTS.
(2)   NET EXPENDITURES FOR THE HORIZON PROJECT ALSO INCLUDE CAPITALIZED INTEREST
      AND STOCK-BASED COMPENSATION.



                                                                              30
<PAGE>

<TABLE>
<CAPTION>
SEGMENTED ASSETS
                                                                                                     2007                   2006
=================================================================================================================================
<S>                                                                                         <C>                      <C>
Conventional crude oil and natural gas
   North America                                                                            $      23,617            $    23,670
   North Sea                                                                                        1,957                  2,248
   Offshore West Africa                                                                             1,354                  1,323
   Other                                                                                               41                     46
Horizon Project                                                                                     8,740                  5,444
Midstream                                                                                             333                    355
Head office                                                                                            72                     74
---------------------------------------------------------------------------------------------------------------------------------
                                                                                            $      36,114            $    33,160
=================================================================================================================================
</TABLE>

17.  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:

<TABLE>
<CAPTION>
(millions of Canadian dollars, except per common share amounts)       Notes            2007               2006              2005
=================================================================================================================================
<S>                                                                 <C>           <C>                <C>               <C>
Net earnings - Canadian GAAP                                                      $   2,608          $   2,524         $   1,050
Adjustments
Depletion, net of taxes of $1 million
   (2006 - $1 million, 2005 - $3 million)                             (A,D)             (10)                 2                 4
Stock-based compensation, net of taxes of $3
   million (2006 - $18 million, 2005 - $nil)                            (B)             (22)               (40)                -
Future income taxes                                                     (H)            (234)                 -                 -
Derivative financial instruments and hedging
   activities, net of taxes of $nil
   (2006 - $15 million, 2005 - $11 million)                           (C,D)               -                117               (19)
---------------------------------------------------------------------------------------------------------------------------------
Net earnings before cumulative effect of change in
   accounting policy - US GAAP                                                        2,342              2,603             1,035
Cumulative effect of change in accounting policy,
   net of taxes of $nil (2006 - $3 million, 2005 -
   $nil)                                                                (B)               -                 (8)                -
---------------------------------------------------------------------------------------------------------------------------------
Net earnings - US GAAP                                                            $   2,342          $   2,595         $   1,035
=================================================================================================================================
Net earnings before cumulative effect of change in
   accounting policy - US GAAP per common share
         Basic                                                                    $    4.34          $    4.84         $    1.93
         Diluted                                                        (F)       $    4.32          $    4.77         $    1.88
=================================================================================================================================
Net earnings - US GAAP per common share
         Basic                                                                    $    4.34          $    4.83         $    1.93
         Diluted                                                        (F)       $    4.32          $    4.75         $    1.88
=================================================================================================================================


<CAPTION>
Comprehensive income under US GAAP would be as follows:

(millions of Canadian dollars)                                         Notes           2007               2006             2005
================================================================================================================================
<S>                                                                 <C>           <C>                <C>               <C>
Comprehensive income - Canadian GAAP                                              $   2,534          $   2,520         $  1,047
US GAAP earnings adjustments                                                           (266)                71              (15)
Derivative financial instruments and hedging
  activities, net of taxes of $nil (2006 - $394
  million; 2005 - $312 million)                                        (C,D)              -                805             (635)
--------------------------------------------------------------------------------------------------------------------------------
Comprehensive income - US GAAP                                                    $   2,268          $   3,396         $    397
================================================================================================================================
</TABLE>


                                                                             31
<PAGE>

The components of accumulated other comprehensive  income under US GAAP, net of
taxes, would be as follows:

<TABLE>
<CAPTION>
                                                                                                          2007              2006
=================================================================================================================================
<S>                                                                                                     <C>               <C>
Derivative financial instruments designated as cash flow hedges                                            101               159
Foreign currency translation adjustment                                                                    (29)              (13)
---------------------------------------------------------------------------------------------------------------------------------
Accumulated other comprehensive income                                                                      72               146
=================================================================================================================================
</TABLE>

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

<TABLE>
<CAPTION>
                                                                                                   2007
(millions of Canadian dollars)                              Notes       CANADIAN GAAP      INCREASE (DECREASE)            US GAAP
==================================================================================================================================
<S>                                                 <C>                 <C>                      <C>                 <C>
Current assets                                                                  2,181                        -              2,181
Property, plant and equipment                           (A,B,D,E)              33,902                       91             33,993
Other long-term assets                                        (I)                  31                       51                 82
----------------------------------------------------------------------------------------------------------------------------------
                                                                               36,114                      142             36,256
----------------------------------------------------------------------------------------------------------------------------------
Current liabilities                                           (B)               3,563                       66              3,629
Long-term debt                                                (I)              10,940                       51             10,991
Other long-term liabilities                                   (B)               1,561                       20              1,581
Future income tax                                     (A,B,D,E,H)               6,729                      236              6,965
Share capital                                                                   2,674                        -              2,674
Retained earnings                                                              10,575                     (231)            10,344
Accumulated other comprehensive income                                             72                        -                 72
----------------------------------------------------------------------------------------------------------------------------------
                                                                               36,114                      142             36,256
==================================================================================================================================

<CAPTION>
                                                                                              2006
(millions of Canadian dollars)                              Notes        Canadian GAAP   Increase (Decrease)              US GAAP
==================================================================================================================================
<S>                                                 <C>                 <C>                      <C>                 <C>
Current assets                                                (C)                2,239                   131                2,370
Property, plant and equipment                           (A,B,D,E)               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,E)                6,963                    21                6,984
Share capital                                                                    2,562                     -                2,562
Retained earnings                                                                8,141                    45                8,186
Accumulated other comprehensive (loss) income                 (C)                  (13)                  159                  146
----------------------------------------------------------------------------------------------------------------------------------
                                                                                33,160                   249               33,409
==================================================================================================================================
</TABLE>



                                                                             32
<PAGE>

NOTES:

(A)   Under  Canadian full cost  accounting  rules,  costs  capitalized in each
      country 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, 2007,  US GAAP net earnings  would have
      decreased by $4 million (2006 - increased by $3 million, 2005 - increased
      by $4  million),  net of income  taxes of $8 million  (2006 - $2 million,
      2005 - $3 million) to reflect the impact of lower depletion charges.  The
      2007 income tax effect includes the effect of enacted Canadian income tax
      rate changes on this item.

(B)   The Company  accounts for its  stock-based  compensation  liability under
      Canadian  GAAP using the  intrinsic  value  method,  as described in note
      1(P).  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, 2007, US GAAP net earnings  would have decreased by $22 million (2006
      - $48  million),  net of income taxes of $3 million  (2006 - $21 million,
      including the cumulative  effect of the change in accounting policy of $8
      million,  net of income taxes of $3 million).  The 2007 income tax effect
      includes the effect of enacted  Canadian  income tax rate changes on this
      item. There was no difference from Canadian GAAP prior to 2006.

(C)   Effective  January 1, 2007, the Company adopted new accounting  standards
      for  financial   instruments  as  described  in  note  2.  The  Company's
      accounting  policies for financial  instruments  under  Canadian GAAP are
      described  in notes  1(Q) and 1(R).  After  adopting  the new  standards,
      Canadian GAAP is  substantially  harmonized with US GAAP as prescribed by
      FAS 133,  "Accounting  for Derivative  Financial  Instruments and Hedging
      Activities,"  as amended by FAS 138 and FAS 149. Prior to adoption of the
      new accounting  policies,  for the year ended  December 31, 2006,  assets
      would have increased by $160 million, liabilities would have decreased by
      $9  million,  and  accumulated  other  comprehensive  income  would  have
      increased  by $159  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 ended December 31, 2006 would have been $29 million,  net
      of income taxes of $15 million (2005 - loss of $19 million, net of income
      taxes of $11 million).

(D)   During 2006, 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,  for the  year  ended
      December  31,  2006,  the $88 million  after-tax  gain on the  derivative
      financial  instruments would have been included in net earnings.  For the
      year  ended  December  31,  2007,  US GAAP net  earnings  would have been
      decreased by $6 million  (2006 - $1  million),  net of income taxes of $7
      million  (2006 - $1 million),  to reflect the impact of higher  depletion
      charges.  The 2007  income  tax  effect  includes  the  effect of enacted
      Canadian income tax rate changes on this item.

(E)   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. As a result of applying US GAAP,
      an additional $27 million would have been capitalized to property,  plant
      and equipment in 2004.


                                                                             33
<PAGE>

(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 as 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, 2007, an additional  3,376,000  shares would
      have been included in the  calculation of diluted  earnings per share for
      US GAAP (2006 - 8,762,000 additional shares, 2005 - 13,593,000 additional
      shares).

(G)   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 adoption of this standard did not result in a reconciling
      item under US GAAP.

(H)   Under  Canadian  GAAP,  the effects of income tax changes are  recognized
      when the changes are considered substantively enacted. Under US GAAP, the
      income tax changes would not be recognized  until the changes are enacted
      into law. For the year ended December 31, 2007, the  differences  between
      substantively enacted and enacted tax legislation results in a difference
      in timing of the recognition of a $234 million future tax recovery.

(I)   Effective  January 1, 2007,  under  Canadian  GAAP,  debt issue  costs on
      long-term  debt must be  included  in the  carrying  value of the related
      debt.  Under US GAAP,  these items must be recorded as a deferred charge.
      Application  of  US  GAAP  would  have  resulted  in  the  balance  sheet
      reclassification  of $51 million of debt issue costs from  long-term debt
      to  deferred  charges in 2007.  There were no GAAP  differences  prior to
      2007.

(J)   US GAAP - RECENTLY ISSUED ACCOUNTING STANDARDS

      In  September  2006,  the FASB issued FAS 157 "Fair  Value  Measurements"
      effective  for fiscal  years  beginning  after  November  15,  2007.  The
      implementation date was subsequently  delayed until years beginning on or
      after November 15, 2008 except for non financial assets and non financial
      liabilities  that  are  recognized  or  disclosed  at fair  value  in the
      financial  statements on a recurring basis (at least  annually).  FAS 157
      standardizes  the  meaning of "Fair  Value" in all FASB  statements  that
      refer  to  fair   value  and   expands   disclosures   about  fair  value
      measurements. The Company is currently assessing the impact this standard
      has on its consolidated financial statements.

      In  February  2007,  the FASB  issued FAS 159 "The Fair Value  Option for
      Financial  Assets and Financial  Liabilities"  effective for fiscal years
      beginning  after November 15, 2007. FAS 159 allows entities to carry most
      financial instruments at fair value, even if existing standards would not
      require this. The Company is currently assessing the impact this standard
      has on its consolidated financial statements.

      In December  2007,  the FASB issued FAS 141(R)  "Business  Combinations",
      which  replaces  FAS 141  effective  for  fiscal  years  beginning  after
      December 15, 2008. FAS 141(R)  retains the purchase  method of accounting
      and  requires  assets  acquired  and  liabilities  assumed  in a business
      combination to be measured at fair value at the date of acquisition.  The
      standard also requires  acquisition-related costs and restructuring costs
      to be recognized separately from the business combination.  This standard
      is to be applied prospectively to all business combinations subsequent to
      the  effective  date and  does  not  require  restatement  of  previously
      completed business combinations.



                                                                             34


<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS


SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain  statements  in this  document  or  documents  incorporated  herein  by
reference constitute  forward-looking  statements or information  (collectively
referred  to herein as  "forward-looking  statements")  within  the  meaning of
applicable securities legislation. Forward-looking statements can be identified
by the words "believe",  "anticipate",  "expect", "plan", "estimate", "target",
"continue", "could", "intend", "may", "potential", "predict", "should", "will",
"objective",  "project",  "forecast", "goal", "guidance",  "outlook", "effort",
"seeks",  "schedule"  or  expressions  of a similar  nature  suggesting  future
outcome or  statements  regarding  an outlook.  Disclosure  related to expected
future  commodity  pricing,  production  volumes,  royalties,  operating costs,
capital   expenditures  and  other  2008  guidance  provided   throughout  this
Management's  Discussion  and  Analysis  ("MD&A"),  including  the  information
provided in the "Outlook" section,  constitutes  forward-looking statements. In
addition,  statements  relating to "reserves" are deemed to be  forward-looking
statements as they involve the implied  assessment  based on certain  estimates
and assumptions that the reserves  described can be profitably  produced in the
future. There are numerous  uncertainties  inherent in estimating quantities of
proved  crude oil and natural gas reserves  and in  projecting  future rates of
production  and the timing of  development  expenditures.  The total  amount or
timing of actual  future  production  may vary  significantly  from reserve and
production estimates.

These  statements are not guarantees of future  performance  and are subject to
certain  risks  and the  reader  should  not  place  undue  reliance  on  these
forward-looking  statements  as  there  can be no  assurance  that  the  plans,
initiatives or expectations upon which they are based will occur.

The forward-looking statements are based on current expectations, estimates and
projections  about Canadian Natural  Resources  Limited (the "Company") and the
industry  in which the Company  operates,  which speak only as of the date such
statements  were made or as of the date of the report or document in which they
are contained,  and are subject to known and unknown risks,  uncertainties  and
other factors that could cause the actual results,  performance or achievements
of the Company 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;  volatility of and  assumptions  regarding  crude oil and natural gas
prices;  fluctuations in currency and interest rates;  assumptions on which the
Company's current guidance is based;  economic  conditions in the countries and
regions  in  which  the  Company  conducts  business;   political  uncertainty,
including actions of or against terrorists,  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  Company's  defense  of  lawsuits;
availability and cost of seismic, drilling and other equipment;  ability of the
Company and its  subsidiaries to complete its capital  programs;  the Company's
and  its  subsidiaries'  ability  to  secure  adequate  transportation  for its
products;  unexpected  difficulties  in mining,  extracting  or  upgrading  the
Company's bitumen  products;  potential delays or changes in plans with respect
to exploration or development projects or capital expenditures;  ability of the
Company to attract the necessary  labour  required to build its thermal and oil
sands mining 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; the Company's and its subsidiaries' success
of  exploration  and  development  activities  and their ability to replace and
expand crude oil and natural gas  reserves;  timing and success of  integrating
the  business  and  operations  of  acquired   companies;   production  levels;
imprecision  of reserve  estimates and estimates of  recoverable  quantities of
crude oil, bitumen, natural gas and liquids not currently classified as proved;
actions  by   governmental   authorities;   government   regulations   and  the
expenditures  required to comply with them (especially safety and environmental
laws and  regulations  and the impact of climate change  initiatives on capital
and  operating  costs);  asset  retirement  obligations;  the  adequacy  of the
Company's provision for taxes; and other  circumstances  affecting revenues and
expenses.  The Company's  operations  have been, and at times in the future may
be,  affected by political  developments  and by federal,  provincial and local
laws and  regulations  such as  restrictions  on production,  changes in taxes,
royalties and other amounts  payable to governments or  governmental  agencies,
price or gathering  rate  controls and  environmental  protection  regulations.
Should one or more of these risks or uncertainties  materialize,  or should any
of the  Company's  assumptions  prove  incorrect,  actual  results  may vary in
material respects from those projected in the forward-looking  statements.  The
impact  of any one  factor on a  particular  forward-looking  statement  is not
determinable  with  certainty  as such  factors are  interdependent  upon other
factors, and the Company's course of action would depend upon its assessment of
the  future   considering  all  information  then  available.   For  additional
information refer to the "Risks and Uncertainties" section of this MD&A.

Readers are  cautioned  that the  foregoing  list of  important  factors is not
exhaustive. Unpredictable or unknown factors not discussed in this report could
also have material adverse effects on forward-looking statements.  Although the
Company  believes  that  the  expectations   conveyed  by  the  forward-looking
statements are reasonable based on information available to it on the date such
forward-looking  statements  are made, no assurances  can be given as to future

                                                                              1
<PAGE>

results,  levels of activity and achievements.  All subsequent  forward-looking
statements,  whether  written or oral,  attributable  to the Company or persons
acting  on its  behalf  are  expressly  qualified  in their  entirety  by these
cautionary  statements.  Except as  required  by law,  the  Company  assumes no
obligation  to  update  forward-looking   statements  should  circumstances  or
Management's estimates or opinions change.

SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES

Management's  Discussion and Analysis includes references to financial measures
commonly used in the crude oil and natural gas industry, such as cash flow from
operations,  adjusted net earnings from  operations and 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.


                                                                              2
<PAGE>

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, 2007. 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 17 to the  consolidated  financial  statements.
All dollar amounts are referenced in Canadian  dollars,  except where otherwise
noted.  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 wellhead. Production volumes are the
Company's interest before royalties,  and realized prices exclude the effect of
risk management  activities and transportation and blending costs, except where
otherwise noted. The following  discussion and analysis refers primarily to the
Company's 2007 financial  results  compared to 2006 and 2005,  unless otherwise
indicated.  In addition,  this MD&A details the Company's  capital  program and
outlook for 2008.

Additional  information  relating to the Company,  including its quarterly MD&A
for the  year  and  three  months  ended  December  31,  2007  and  its  Annual
Information Form for the year ended December 31, 2007, is available on SEDAR at
www.sedar.com.

This MD&A is dated February 26, 2008.

ABBREVIATIONS

ACC                   Anadarko Canada Corporation
AECO                  Alberta natural gas reference location
API                   Specific  gravity  measured  in degrees  on the  American
                      Petroleum Institute scale
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
CO2                   Carbon dioxide
CO2e                  Carbon dioxide equivalents
CICA                  Canadian Institute of Chartered Accountants
FPSO                  Floating Production, Storage and Offtake Vessel
GAAP                  Generally accepted accounting principles
GHG                   Greenhouse gas
GJ                    gigajoule
HEAVY DIFFERENTIAL    Heavy crude oil differential from WTI
HORIZON PROJECT       Horizon Oil Sands Project LLB Lloyd Blend
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                   United States Securities and Exchange Commission
TSX                   Toronto Stock Exchange
UK                    United Kingdom
US                    United States
US$                   United States dollars
WTI                   West Texas Intermediate

                                                                              3
<PAGE>

OBJECTIVE AND STRATEGY

The Company's  objectives are 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/or  acquisition of new reserves.  The Company strives
to meet the  objectives 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 value. 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 and terms of debt financing and maintenance of a
     strong balance sheet.

(1)  DISCOUNTED  VALUE OF CONVENTIONAL  CRUDE OIL AND NATURAL GAS RESERVES PLUS
     VALUE OF UNDEVELOPED LAND, LESS NET DEBT.
(2)  PELICAN LAKE CRUDE OIL IS 14-17(0) API OIL, WHICH RECEIVES  MEDIUM QUALITY
     CRUDE NETBACKS DUE TO LOWER PRODUCTION COSTS AND LOWER 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 and/or new additions;
     and

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

Operational  discipline  and  cost  control  are  central  to the  Company.  By
consistently  controlling  costs  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 and operator status 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 Horizon Project construction period.

Strategic accretive  acquisitions like the acquisition of ACC in 2006 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.

Highlights for the year ended December 31, 2007 are as follows:

o    Achieved  record  levels  of net  earnings,  adjusted  net  earnings  from
     operations and cash flow;

o    Achieved record natural gas production;

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

o    Completed 90% of Phase 1 work progress of the Horizon Project; and

o    Increased dividends per common share.

                                                                              4
<PAGE>

NET EARNINGS AND CASH FLOW FROM OPERATIONS

<TABLE>
<CAPTION>
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)             2007            2006         2005
============================================================================================
<S>                                              <C>             <C>            <C>
Revenue, before royalties                        $     12,543    $     11,643   $    11,130
Net earnings                                     $      2,608    $      2,524   $     1,050
     Per common share      - basic               $       4.84    $       4.70   $      1.96
                           - diluted             $       4.84    $       4.70   $      1.95
Adjusted net earnings from operations (1)        $      2,406    $      1,664   $     2,034
     Per common share      - basic               $       4.46    $       3.10   $      3.79
                           - diluted             $       4.46    $       3.10   $      3.78
Cash flow from operations (2)                    $      6,198    $      4,932   $     5,021
     Per common share      - basic               $      11.49    $       9.18   $      9.36
                           - diluted             $      11.49    $       9.18   $      9.33
Dividends declared per common share              $       0.34    $       0.30   $     0.236
Total assets                                     $     36,114    $     33,160   $    21,852
Total long-term liabilities                      $     19,230    $     19,399   $     9,790
Capital expenditures, net of dispositions        $      6,425    $     12,025   $     4,932
============================================================================================
</TABLE>
(1)  ADJUSTED  NET  EARNINGS  FROM  OPERATIONS  IS  A  NON-GAAP   MEASURE  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 RECONCILIATION  "ADJUSTED NET EARNINGS FROM
     OPERATIONS"  BELOW  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.

(2)  CASH FLOW FROM  OPERATIONS  IS A  NON-GAAP  MEASURE  THAT  REPRESENTS  NET
     EARNINGS  ADJUSTED FOR NON-CASH ITEMS BEFORE WORKING CAPITAL  ADJUSTMENTS.
     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.  THE
     RECONCILIATION  "CASH FLOW FROM  OPERATIONS"  BELOW  LISTS THE  EFFECTS OF
     CERTAIN  NON-CASH  ITEMS  THAT ARE  INCLUDED  IN THE  COMPANY'S  FINANCIAL
     RESULTS.  CASH FLOW  FROM  OPERATIONS  MAY NOT BE  COMPARABLE  TO  SIMILAR
     MEASURES PRESENTED BY OTHER COMPANIES.

<TABLE>
<CAPTION>
  ADJUSTED NET EARNINGS FROM OPERATIONS
  ($ MILLIONS)                                                           2007          2006            2005
  ==========================================================================================================
<S>                                                              <C>           <C>           <C>
  NET EARNINGS AS REPORTED                                       $      2,608  $      2,524  $        1,050
  STOCK-BASED COMPENSATION EXPENSE, NET OF TAX (a)                        134            95             481
  UNREALIZED RISK MANAGEMENT LOSS (GAIN), NET OF TAX (b)                  977          (674)            607
  UNREALIZED FOREIGN EXCHANGE (GAIN) LOSS, NET OF TAX (c)                (449)          114             (85)
  EFFECT OF STATUTORY TAX RATE AND OTHER LEGISLATIVE CHANGES
      ON FUTURE INCOME TAX LIABILITIES (d)                               (864)         (395)            (19)
  ----------------------------------------------------------------------------------------------------------
  ADJUSTED NET EARNINGS FROM OPERATIONS                          $      2,406  $      1,664  $        2,034
  ==========================================================================================================
</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 ARE RECOGNIZED IN NET EARNINGS
         OR  ARE  CAPITALIZED  AS  PART  OF  THE  HORIZON  PROJECT  DURING  THE
         CONSTRUCTION PERIOD.

  (b)    DERIVATIVE  FINANCIAL  INSTRUMENTS  ARE  RECORDED AT FAIR VALUE ON THE
         BALANCE  SHEET,  WITH CHANGES IN FAIR VALUE OF  NON-DESIGNATED  HEDGES
         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,  OFFSET BY THE IMPACT OF CROSS CURRENCY SWAPS, AND ARE
         IMMEDIATELY RECOGNIZED IN NET EARNINGS.

  (d)    ALL SUBSTANTIVELY  ENACTED  ADJUSTMENTS IN APPLICABLE INCOME TAX RATES
         AND OTHER  LEGISLATIVE  CHANGES 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 AND  OTHER  LEGISLATIVE
         CHANGES  DURING  2007  RESULTED IN A  REDUCTION  OF FUTURE  INCOME TAX
         LIABILITIES OF APPROXIMATELY $864 MILLION IN NORTH AMERICA. INCOME TAX
         RATE CHANGES  DURING 2006 RESULTED IN AN INCREASE OF FUTURE INCOME TAX
         LIABILITIES  OF  APPROXIMATELY  $110  MILLION  IN  THE  NORTH  SEA,  A
         REDUCTION  OF  APPROXIMATELY  $438  MILLION  IN NORTH  AMERICA,  AND A
         REDUCTION OF APPROXIMATELY $67 MILLION IN OFFSHORE WEST AFRICA. INCOME
         TAX RATE CHANGES  DURING 2005 RESULTED IN A REDUCTION OF FUTURE INCOME
         TAX LIABILITIES OF APPROXIMATELY $19 MILLION IN NORTH AMERICA.

                                                                              5
<PAGE>

<TABLE>
<CAPTION>
  CASH FLOW FROM OPERATIONS
  ($ MILLIONS)                                                       2007         2006          2005
  ===================================================================================================
<S>                                                           <C>          <C>          <C>
  NET EARNINGS                                                $     2,608  $     2,524  $      1,050
  NON-CASH ITEMS:
       DEPLETION, DEPRECIATION AND AMORTIZATION                     2,863        2,391         2,013
       ASSET RETIREMENT OBLIGATION ACCRETION                           70           68            69
       STOCK-BASED COMPENSATION EXPENSE                               193          139           723
       UNREALIZED RISK MANAGEMENT LOSS (GAIN)                       1,400       (1,013)          925
       UNREALIZED FOREIGN EXCHANGE (GAIN) LOSS                       (524)         134          (103)
       DEFERRED PETROLEUM REVENUE TAX EXPENSE (RECOVERY)               44           37            (9)
       FUTURE INCOME TAX (RECOVERY) EXPENSE                          (456)         652           353
  ---------------------------------------------------------------------------------------------------
  CASH FLOW FROM OPERATIONS                                   $     6,198  $     4,932  $      5,021
  ===================================================================================================
</TABLE>

For 2007, the Company  reported net earnings of $2,608 million  compared to net
earnings of $2,524 million for 2006 (2005 - $1,050  million).  Net earnings for
the year ended  December 31, 2007 included net unrealized  after-tax  income of
$202 million related to the effects of risk management activities, fluctuations
in foreign exchange rates,  stock-based  compensation expense and the impact of
statutory  tax  rate  and  other  legislative  changes  on  future  income  tax
liabilities (2006 - net unrealized after-tax income of $860 million; 2005 - net
unrealized after-tax expenses of $984 million). Excluding these items, adjusted
net earnings from  operations for the year ended December 31, 2007 increased to
$2,406 million from $1,664 million for 2006 (2005 - $2,034  million)  primarily
due to higher realized pricing,  lower realized risk management losses,  higher
North  America  crude oil and NGLs and  natural  gas sales  volumes,  and lower
income tax expense.  These factors were partially  offset by higher  production
expense,  higher  depletion,  depreciation  and  amortization  expense,  higher
interest  expense,  and the impact of the stronger  Canadian dollar relative to
the US dollar.

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
expenditures  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  estimated  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 budgeted crude oil volumes are
hedged for 2008 and  approximately  53% of  budgeted  natural  gas  volumes are
hedged for the first  quarter of 2008.  Subsequent  to December 31,  2007,  the
Company  hedged  25,000  bbl/d of crude oil  volumes for 2009 using WTI collars
with a US$70.00 floor.

The  Company's  outstanding  commodity  related  financial  derivatives  as  at
December 31, 2007 are detailed in the "Liquidity and Capital Resources" section
of this MD&A.

As  disclosed in note 2 to the  Company's  consolidated  financial  statements,
commencing January 1, 2007 all derivative financial  instruments are recognized
at fair value on the  consolidated  balance  sheet at each  reporting  date. As
effective as the Company's  hedges are against  reference  commodity  prices, a
substantial portion of the derivative financial instruments entered into by the
Company have not been formally  designated as hedges for accounting purposes or
do not meet the  requirements  for hedge accounting under GAAP due to currency,
product quality and location  differentials (the "non-designated  hedges"). The
change in the fair value of the  non-designated  hedges is based on  prevailing
forward  commodity  prices in effect at the end of each reporting period and is
reflected in risk management activities in consolidated net earnings.  The cash
settlement amount of the risk management  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, 2007.

Due to the  changes  in crude  oil and  natural  gas  forward  pricing  and the
reversal of prior-year  unrealized gains and losses, the Company recorded a net
unrealized  loss of $1,400  million ($977  million  after-tax) on its commodity
risk management  activities for the year ended December 31, 2007 (2006 - $1,013
million unrealized gain, $674 million after-tax; 2005 - $925 million unrealized
loss, $607 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.  For further  details,  refer to the "Risk
Management Activities" section of this MD&A.

                                                                              6
<PAGE>

The Company also recorded a $193 million ($134 million  after-tax)  stock-based
compensation  expense as a result of the 17%  increase in the  Company's  share
price for the year  ended  December  31,  2007  (Company's  share  price as at:
December  31, 2007 - $72.58;  December  31, 2006 - $62.15;  December 31, 2005 -
$57.63; December 31, 2004 - $25.63). As required by GAAP, the Company records a
liability for potential cash payments to settle its outstanding  employee stock
options  each  reporting  period 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
reporting  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 net earnings,  or  capitalized as part of the Horizon
Project during the construction period. The stock-based  compensation liability
at December 31, 2007 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, 2007. 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, 2007  increased to
$6,198 million  ($11.49 per common share) from $4,932 million ($9.18 per common
share) for 2006 (2005 - $5,021 million;  $9.36 per common share).  The increase
was  primarily  due to higher North  America crude oil and NGLs and natural gas
sales volumes,  higher  realized  pricing,  and lower realized risk  management
losses.  These  factors were  partially  offset by higher  production  expense,
higher   interest  costs,   higher  current  taxes,   and  the  impact  of  the
strengthening of the Canadian dollar relative to the US dollar.

For  2007,  the  Company's  average  sales  price per bbl of crude oil and NGLs
increased  to $55.45  per bbl from  $53.65  per bbl in 2006  (2005 - $46.86 per
bbl). The Company's  average  natural gas price increased to $6.85 per mcf from
$6.72 per mcf for 2006 (2005 - $8.57 per mcf).

Total production of crude oil and NGLs before royalties decreased marginally to
331,232 bbl/d from 331,998 bbl/d for 2006 (2005 - 313,168 bbl/d).  The decrease
in crude oil and NGLs production  primarily  reflected lower  production in the
North  Sea due to the  timing  of  planned  maintenance  activities  and  lower
production  from the Baobab Field in Offshore West Africa,  offset by increased
production in North America including  increased  production from the Company's
Primrose  thermal  projects,  the  results  from the  Pelican  Lake  waterflood
project, and the acquisition of ACC in 2006.

Total natural gas production  before  royalties  increased to 1,668 mmcf/d from
1,492  mmcf/d for 2006  (2005 - 1,439  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  declines in
2007 due to the Company's strategic reduction in natural gas drilling activity.

Total crude oil and NGLs and natural gas production  volumes  before  royalties
increased to 609,206 boe/d from 580,724 boe/d for 2006 (2005 - 552,960 boe/d).

OPERATING HIGHLIGHTS
                                                     2007       2006       2005
================================================================================
CRUDE OIL AND NGLS ($/BBL) (1)
Sales price (2)                                 $   55.45  $   53.65  $   46.86
Royalties                                            5.94       4.48       3.97
Production expense                                  13.34      12.29      11.17
-------------------------------------------------------------------------------
Netback                                         $   36.17  $   36.88  $   31.72
-------------------------------------------------------------------------------
NATURAL GAS ($/MCF) (1)
Sales price (2)                                 $    6.85  $    6.72  $    8.57
Royalties                                            1.11       1.29       1.75
Production expense                                   0.91       0.82       0.73
-------------------------------------------------------------------------------
Netback                                         $    4.83  $    4.61  $    6.09
-------------------------------------------------------------------------------
BARRELS OF OIL EQUIVALENT ($/BOE) (1)
Sales price (2)                                 $   49.05  $   47.92  $   48.77
Royalties                                            6.26       5.89       6.82
Production expense                                   9.75       9.14       8.21
-------------------------------------------------------------------------------
Netback                                         $   33.04  $   32.89  $   33.74
===============================================================================
(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.

                                                                              7
<PAGE>

SUMMARY OF QUARTERLY RESULTS
The  following is a summary of the  Company's  quarterly  results for the eight
most recently completed quarters:

<TABLE>
($ millions, except per common share amounts)
2007                                       TOTAL    DEC 31    SEP 30    JUN 30    MAR 31
=========================================================================================
<S>                                      <C>       <C>       <C>       <C>       <C>
Revenue, before royalties                $12,543   $ 3,200   $ 3,073   $ 3,152   $ 3,118
Net earnings                             $ 2,608   $   798   $   700   $   841   $   269
Net earnings per common share
         - basic and diluted             $  4.84   $  1.48   $  1.30   $  1.56   $  0.50
-----------------------------------------------------------------------------------------

2006                                       Total    Dec 31    Sep 30    Jun 30    Mar 31
-----------------------------------------------------------------------------------------
Revenue, before royalties                $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 and diluted             $  4.70   $  0.58   $  2.08   $  1.93   $  0.11
=========================================================================================
</TABLE>

The Company's quarterly consolidated revenues increased 20% to $3,200 million
for the fourth quarter of 2007 from $2,668 million for the first quarter of
2006. Net earnings fluctuated from $57 million for the first quarter of 2006 to
$798 million for the fourth quarter of 2007. Net earnings over the eight most
recently completed quarters generally reflected fluctuations in realized crude
oil and natural gas prices, fluctuations in sales volumes, the impact of
mark-to-market accounting of financial instruments, higher depletion,
depreciation and amortization charges, and adjustments to future income tax
liabilities due to statutory tax rate and other legislative changes. More
specifically, volatility in quarterly net earnings was primarily due to:

o    Crude oil pricing

     Crude  oil  prices   reflected  demand  growth,   continued   geopolitical
     uncertainties and fluctuations in the Heavy Differential in North America.
     The Company's  realized  crude oil and NGLs price  increased to $58.03 per
     bbl for the  fourth  quarter  of 2007  from  $43.79  per bbl for the first
     quarter  of 2006.  The  Heavy  Differential  averaged  38% for the  fourth
     quarter of 2007 compared to 45% for the first quarter of 2006.

o    Natural gas pricing

     Natural gas prices primarily reflected  fluctuations in demand for natural
     gas and high inventory  storage levels as a result of seasonality,  milder
     overall weather  experienced during 2007 and 2006, and increased liquefied
     natural  gas  imports  into the US  during  the  first  half of 2007.  The
     Company's  realized  natural gas price  decreased to $6.28 per mcf for the
     fourth quarter of 2007 from $8.30 per mcf for the first quarter of 2006.

o    Crude oil and NGLs sales volumes

     Crude oil and NGLs sales volumes primarily reflected increased  production
     from the Company's Primrose thermal projects, the results from the Pelican
     Lake  water  and  polymer  flood  projects,  development  of West and East
     Espoir, and additional sales volumes from the ACC acquisition completed in
     the fourth quarter of 2006. Total crude oil and NGLs production  increased
     to 337,240 bbl/d for the fourth quarter of 2007 from 323,662 bbl/d for the
     first quarter of 2006.

o    Natural gas sales volumes

     Natural  gas sales  volumes  primarily  reflected  additional  natural gas
     volumes  as a  result  of the ACC  acquisition  and  internally  generated
     growth. The increases were partially offset by production  declines due to
     the Company's strategic reduction in natural gas drilling activity.  Total
     natural gas production increased to 1,589 mmcf/d for the fourth quarter of
     2007 from 1,436 mmcf/d for the first quarter of 2006.

o    Foreign exchange rates

     A general  strengthening  of the Canadian dollar relative to the US dollar
     has  decreased the realized  price the Company  received for its crude oil
     and  natural  gas sales,  as sales  prices are based  predominately  on US
     dollar  denominated  benchmarks.  Similarly,  unrealized  foreign exchange
     gains and losses were recorded with respect to US dollar  denominated debt
     balances and the re-measurement of North Sea future income tax liabilities
     denominated in UK pounds  sterling to US dollars,  offset by the impact of
     cross  currency  swaps.  The US / Canadian  dollar  average  exchange rate
     increased to US$1.0193 for the fourth  quarter of 2007 from  US$0.8660 for
     the  first  quarter  of 2006.  The US dollar / UK pound  sterling  average
     exchange rate  increased to US$2.0451 for the fourth  quarter of 2007 from
     US$1.7532 for the first quarter of 2006.

                                                                              8
<PAGE>

o    Risk management

     Net  earnings  have  fluctuated  due to the  recognition  of realized  and
     unrealized gains and losses from the  mark-to-market of the Company's risk
     management activities.

o    Changes in income tax expense

     Income tax expense and recovery  fluctuations  include  statutory tax rate
     and other  legislative  changes  enacted or  substantively  enacted in the
     various  periods.  Income tax rate and other  legislative  changes reduced
     future  income tax  liabilities  by $864 million for 2007 and $395 million
     for 2006.

o    Stock-based compensation

     Net  earnings  have  fluctuated  due to the  recognition  of realized  and
     unrealized   expenses  and  recoveries  from  the  mark-to-market  of  the
     Company's stock-based  compensation  liability.  Stock-based  compensation
     expense reflected fluctuations in the Company's share price over the eight
     most recently completed quarters.  The Company's share price increased 26%
     to $72.58 per share at December 31, 2007 from $57.63 per share at December
     31, 2005.

o    Production expense

     Production expense has fluctuated company wide primarily due to production
     growth and industry-wide inflationary cost pressures in all segments.

o    Depletion, depreciation and amortization

     Depletion,  depreciation and amortization  expense has increased primarily
     due to overall  increases in finding and development costs associated with
     crude oil and natural gas exploration, increased estimated future costs to
     develop the Company's proved undeveloped reserves,  and a higher depletion
     base in North America  related to the ACC  acquisition,  together with the
     impact of higher sales volumes.

<TABLE>
<CAPTION>
BUSINESS ENVIRONMENT
(Yearly average)                                                2007          2006          2005
=================================================================================================
<S>                                                      <C>           <C>           <C>
WTI benchmark price (US$/bbl)                            $     72.40   $     66.25   $     56.61
Dated Brent benchmark price (US$/bbl)                    $     72.59   $     65.18   $     54.45
Differential to LLB blend (US$/bbl)                      $     23.05   $     21.69   $     20.83
LLB blend differential from WTI (%)                              32%           33%           37%
Condensate benchmark price (US$/bbl)                     $     72.88   $     66.24   $     57.25
NYMEX benchmark price (US$/mmbtu)                        $      6.92   $      7.26   $      8.56
AECO benchmark price (C$/GJ)                             $      6.26   $      6.62   $      8.05
US / Canadian dollar average exchange rate               $    0.9304   $    0.8818   $    0.8253
US / Canadian dollar year end exchange rate              $    1.0120   $    0.8581   $    0.8577
=================================================================================================
</TABLE>

COMMODITY PRICES

Substantially all of the Company's crude oil and natural gas production is sold
based  directly or indirectly  on US dollar  benchmark  pricing.  Specifically,
crude oil is  marketed  based on WTI and Brent  indices.  Canadian  natural gas
pricing is primarily based on NYMEX and AECO reference  pricing.  As pricing is
based on US dollar  benchmarks,  the price the Company  ultimately  receives in
Canadian  dollars  fluctuates with changes in the US / Canadian dollar exchange
rate. Accordingly,  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  results in  increased  revenue  from the sale of the
Company's production.  The average value of the Canadian dollar strengthened 6%
in 2007 compared to 2006.

Increases in WTI pricing in 2007  reflected  continued  strong demand for crude
oil and continued geopolitical events resulting in increased market uncertainty
and price volatility.  In December 2007, WTI averaged US$91.74 per bbl, down 8%
from the record high of US$99.29 per bbl reached in November 2007. WTI averaged
US$72.40  per bbl for 2007,  an increase of 9% compared to US$66.25 per bbl for
2006 (2005 - US$56.61 per bbl).

Brent  averaged  US$72.59  per bbl for 2007,  an  increase  of 11%  compared to
US$65.18 per bbl for 2006 (2005 - US$54.45 per bbl).  Crude oil sales contracts
for the  Company's  North Sea and Offshore  West Africa  segments are typically
based on Brent  pricing,  which  continued to benefit from strong  European and
Asian demand in 2007.

                                                                              9
<PAGE>

The Company's  realized crude oil price  increased from 2006 as a result of the
increased WTI and Brent pricing and the narrower Heavy Differential,  offset by
the impact of a strengthening  Canadian dollar. The Heavy Differential averaged
32% for  2007,  which was  comparable  to 33% for 2006  (2005 - 37%).  Realized
prices continued to be adversely impacted by the stronger Canadian dollar.

The  Company  anticipates   continued  volatility  in  the  crude  oil  pricing
benchmarks due to the unpredictable nature of geopolitical events and potential
unplanned  refinery outages.  The Heavy Differential is expected to continue to
reflect seasonal demand fluctuations and refinery cracking margins.

NYMEX natural gas prices averaged  US$6.92 per mmbtu for 2007, a decrease of 5%
from  US$7.26 per mmbtu for 2006 (2005 - US$8.56 per mmbtu).  AECO  natural gas
pricing for 2007 decreased 5% to average $6.26 per GJ from $6.62 per GJ in 2006
(2005 - $8.05  per GJ).  Fluctuations  in  natural  gas  prices  from 2006 were
primarily  related to lower overall demand  resulting from the milder  weather,
reduced economic  activity in the US, and higher liquefied  natural gas imports
into the US during  the first half of 2007.  Natural  gas  inventory  levels in
North  America  during  2007  continued  to remain  high due to  stable  annual
production levels in the US that more than offset production declines in Canada
from reduced drilling activity.

OPERATING, ROYALTY AND CAPITAL COSTS

Strong  commodity  prices in recent years have resulted in increased demand and
costs for oilfield services worldwide.  This has led to inflationary  operating
and capital cost  pressures  throughout the North America crude oil and natural
gas  industry,  particularly  related  to  drilling  activities  and oil  sands
developments. The strong commodity price environment has also impacted costs in
international  basins,  due in  large  part to the  high  demand  for  offshore
drilling rigs.

The crude oil and natural  gas  industry is also  experiencing  cost  pressures
related   to   environmental   regulations,   both   in   North   America   and
internationally.  In Canada, the Federal government has indicated its intent to
develop  regulations that would be in effect in 2010 to address  industrial GHG
emissions.  The Federal  Government  has also  outlined  national  and sectoral
reduction  targets for several  categories of air pollutants.  In Alberta,  GHG
regulations came into effect July 1, 2007,  affecting  facilities emitting more
than 100 kilotonnes of CO2 annually.  In the UK, GHG  regulations  have been in
effect since 2005.  The Company has  strategies  in place to ensure  compliance
with any  requirements  currently in effect.  The  additional  requirements  of
enacted and proposed GHG legislation will add to the cost of executing projects
company wide. For additional  details,  refer to the  "Greenhouse Gas and Other
Air Emissions" section of this MD&A.

In 2007, the Province of Alberta issued certain details of its proposed changes
to the Alberta crude oil and natural gas royalty regime,  effective  January 1,
2009. These proposed changes include:

o    The implementation of a sliding scale for oil sands royalties ranging from
     1% to 9% on a  gross  revenue  basis  pre-payout  and  25% to 40% on a net
     revenue basis post-payout depending on benchmark crude oil pricing; and

o    New royalty formulas for  conventional  crude oil and natural gas that are
     to operate on sliding  scales  ranging up to 50%  determined  by commodity
     prices and well productivity.

The Company is currently  awaiting  finalization of the royalty  implementation
regulations,  however  it  expects  that its 2009 and  future  Alberta  royalty
payments will increase as a result of the proposed royalty changes and that its
level of  activity  in  Alberta  in  aggregate  will be  reduced  from  what it
otherwise would have been in the absence of such royalty changes.


                                                                             10
<PAGE>

<TABLE>
<CAPTION>
ANALYSIS OF CHANGES IN REVENUE, BEFORE ROYALTIES AND RISK MANAGEMENT ACTIVITIES

                                              Changes                                         CHANGES
                                               due to                                          DUE TO
($ millions)            2005      Volumes      Prices       Other        2006     VOLUMES      PRICES      OTHER       2007
============================================================================================================================
<S>                  <C>         <C>         <C>         <C>         <C>         <C>         <C>        <C>        <C>
NORTH AMERICA
Crude Oil and
  NGLs               $  4,317    $    198    $    747    $      -    $  5,262    $    298    $    287   $      -   $  5,847
Natural Gas             4,638         168      (1,002)          -       3,804         452          46          -      4,302
----------------------------------------------------------------------------------------------------------------------------
                        8,955         366        (255)          -       9,066         750         333          -     10,149
----------------------------------------------------------------------------------------------------------------------------
NORTH SEA
Crude oil and
  NGLs                  1,636        (168)        132           -       1,600        (107)         82          -      1,575
Natural gas                23          (4)         (3)          -          16          (2)          8          -         22
----------------------------------------------------------------------------------------------------------------------------
                        1,659        (172)        129           -       1,616        (109)         90          -      1,597
----------------------------------------------------------------------------------------------------------------------------
OFFSHORE WEST
AFRICA
Crude oil and
  NGLs                    476         344         111           -         931        (216)         36          -        751
Natural gas                 9          12          (2)          -          19           5           1          -         25
----------------------------------------------------------------------------------------------------------------------------
                          485         356         109           -         950        (211)         37          -        776
----------------------------------------------------------------------------------------------------------------------------
SUBTOTAL
Crude oil and
  NGLs                  6,429         374         990           -       7,793         (25)        405          -      8,173
Natural gas             4,670         176      (1,007)          -       3,839         455          55          -      4,349
----------------------------------------------------------------------------------------------------------------------------
                       11,099         550         (17)          -      11,632         430         460          -     12,522
MIDSTREAM                  77           -           -          (5)         72           -           -          2         74
INTERSEGMENT
  ELIMINATIONS
  AND OTHER (1)           (46)          -           -         (15)        (61)          -           -          8        (53)
----------------------------------------------------------------------------------------------------------------------------
TOTAL                $ 11,130    $    550    $    (17)   $    (20)   $ 11,643    $    430    $    460   $     10   $ 12,543
============================================================================================================================
</TABLE>
(1)  ELIMINATES PRIMARILY INTERNAL TRANSPORTATION AND ELECTRICITY CHARGES.

Revenue  increased 8% to $12,543 million for 2007 from $11,643 million for 2006
(2005 - $11,130 million). The increase was primarily due to increased crude oil
and NGLs and natural gas sales volumes in North America and increased  realized
crude oil and NGLs and natural gas prices company wide.

For 2007, 19% of the Company's  crude oil and natural gas revenue was generated
outside of North America (2006 - 22%; 2005 - 19%).  North Sea accounted for 13%
of crude oil and natural gas  revenue  for 2007 (2006 - 14%;  2005 - 15%),  and
Offshore West Africa  accounted for 6% of crude oil and natural gas revenue for
2007 (2006 - 8%; 2005 - 4%).

                                                                             11
<PAGE>

<TABLE>
<CAPTION>
ANALYSIS OF PRODUCT PRICES

                                                                          2007       2006        2005
======================================================================================================
<S>                                                                 <C>         <C>        <C>
CRUDE OIL AND NGLS ($/bbl) (1) (2)
North America                                                       $    49.16  $   46.52  $    39.62
North Sea                                                           $    74.99  $   72.62  $    66.57
Offshore West Africa                                                $    71.68  $   67.99  $    59.91
Company average                                                     $    55.45  $   53.65  $    46.86

NATURAL GAS ($/mcf) (1) (2)
North America                                                       $     6.87  $    6.77  $     8.65
North Sea                                                           $     4.26  $    2.66  $     3.17
Offshore West Africa                                                $     5.68  $    5.37  $     5.91
Company average                                                     $     6.85  $    6.72  $     8.57

COMPANY AVERAGE ($/boe) (1) (2)                                     $    49.05  $   47.92  $    48.77

PERCENTAGE OF GROSS REVENUE (2)  (excluding midstream revenue)
Crude oil and NGLs                                                         62%        64%         54%
Natural gas                                                                38%        36%         46%
======================================================================================================
</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.

Realized  crude oil and NGLs prices  increased 3% to average $55.45 per bbl for
2007 from $53.65 per bbl for 2006 (2005 - $46.86 per bbl).  The  increase  from
2006 was due to increased  benchmark  crude oil prices and a slightly  narrower
Heavy  Differential,  largely  offset by the  impact of the  stronger  Canadian
dollar.

The Company's  realized natural gas price increased 2% to average $6.85 per mcf
for 2007 from  $6.72 per mcf for 2006 (2005 - $8.57 per mcf).  Fluctuations  in
natural  gas  prices  from 2006 were  primarily  related  to the impact of both
weather and storage levels.

NORTH AMERICA

North America  realized crude oil prices increased 6% to average $49.16 per bbl
for 2007 from  $46.52 per bbl for 2006 (2005 - $39.62  per bbl).  The  increase
from 2006 was due to  increased  benchmark  crude  oil  prices  and a  slightly
narrower  Heavy  Differential,  largely  offset by the  impact of the  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 2007,
the Company contributed  approximately  140,000 bbl/d of heavy crude oil blends
to the Western Canadian Select stream.

North America realized  natural gas prices increased  slightly to average $6.87
per mcf for 2007 from $6.77 per mcf for 2006 (2005 - $8.65 per mcf),  primarily
related to the impact of weather and storage levels.

Comparisons of the prices received for the Company's  North America  production
by product type were as follows:

<TABLE>
                                                                  2007         2006         2005
=================================================================================================
<S>                                                        <C>          <C>          <C>
Wellhead Price (1) (2)
         Light / medium crude oil and NGLs (C$/bbl)        $     66.24  $     63.09  $     58.41
         Pelican Lake crude oil (C$/bbl)                   $     46.29  $     45.02  $     38.39
         Primary heavy crude oil (C$/bbl)                  $     43.77  $     41.35  $     33.53
         Thermal heavy crude oil (C$/bbl)                  $     43.49  $     40.98  $     32.29
                  Natural gas (C$/mcf)                     $      6.87  $      6.77  $      8.65
=================================================================================================
</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.  NORTH
     SEA

                                                                             12
<PAGE>

North Sea realized crude oil prices  increased 3% to average $74.99 per bbl for
2007 from $72.62 per bbl for 2006 (2005 - $66.57 per bbl).  Realized  crude oil
prices in the North Sea during  2007  continued  to benefit  from the impact of
strong  European  and  Asian  demand,  partially  offset  by the  impact of the
stronger Canadian dollar.

OFFSHORE WEST AFRICA

Offshore West Africa  realized crude oil prices  increased 5% to average $71.68
per bbl for 2007 from  $67.99 per bbl for 2006 (2005 - $59.91 per bbl).  As all
revenue in Offshore West Africa is currently  recognized  on a liftings  basis,
realized crude oil prices per barrel in any particular  period are dependant on
the frequency and timing of liftings of each field, as well as the terms of the
related  sales  contracts.  Realized  crude oil prices in Offshore  West Africa
during 2007  continued to benefit from the impact of strong  European and Asian
demand, partially offset by the impact of the stronger Canadian dollar.

CRUDE OIL INVENTORY VOLUMES

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

<TABLE>
(bbl)                                                           2007        2006        2005
============================================================================================
<S>                                                        <C>         <C>           <C>
North America, related to pipeline fill                    1,097,526   1,097,526     484,157
North Sea, related to timing of liftings                   1,032,723     910,796     747,141
Offshore West Africa, related to timing of liftings            8,578     113,774     412,841
--------------------------------------------------------------------------------------------
                                                           2,138,827   2,122,096   1,644,139
============================================================================================
</TABLE>

In 2007, net production of  approximately  17,000 barrels of crude oil produced
in  the  Company's  international  operations  was  deferred  and  included  in
inventory  at  December  31,  2007,  reducing  cash  flow  from  operations  by
approximately $9 million.

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

                                                                 2007       2006       2005
============================================================================================
<S>                                                           <C>        <C>        <C>
CRUDE OIL AND NGLS (bbl/d)
North America                                                 246,779    235,253    221,669
North Sea                                                      55,933     60,056     68,593
Offshore West Africa                                           28,520     36,689     22,906
--------------------------------------------------------------------------------------------
                                                              331,232    331,998    313,168
--------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America                                                   1,643      1,468      1,416
North Sea                                                          13         15         19
Offshore West Africa                                               12          9          4
--------------------------------------------------------------------------------------------
                                                                1,668      1,492      1,439
--------------------------------------------------------------------------------------------
TOTAL BARRELS OF OIL EQUIVALENT (boe/d)                       609,206    580,724    552,960
--------------------------------------------------------------------------------------------
PRODUCT MIX
Light crude oil and NGLs                                           23%        26%        26%
Pelican Lake crude oil                                              6%         5%         4%
Primary heavy crude oil                                            15%        16%        17%
Thermal heavy crude oil                                            11%        11%        10%
Natural gas                                                        45%        42%        43%
============================================================================================
</TABLE>

                                                                             13
<PAGE>

<TABLE>
<CAPTION>
DAILY PRODUCTION, NET OF ROYALTIES

                                                                   2007      2006      2005
============================================================================================
<S>                                                             <C>       <C>       <C>
CRUDE OIL AND NGLS (bbl/d)
North America                                                   210,769   205,382   191,751
North Sea                                                        55,825    59,940    68,487
Offshore West Africa                                             26,012    35,212    22,293
--------------------------------------------------------------------------------------------
                                                                292,606   300,534   282,531
--------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America                                                     1,378     1,185     1,125
North Sea                                                            13        15        18
Offshore West Africa                                                 11         9         4
--------------------------------------------------------------------------------------------
                                                                  1,402     1,209     1,147
--------------------------------------------------------------------------------------------
TOTAL BARRELS OF OIL EQUIVALENT (boe/d)                         526,193   502,024   473,742
============================================================================================
</TABLE>

Daily production and per barrel  statistics are presented  throughout this MD&A
on a "before  royalty" or "gross"  basis.  Production on an "after  royalty" or
"net" basis is also presented.

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 decreased marginally to
331,232 bbl/d for 2007 from 331,998 bbl/d for 2006 (2005 - 313,168 bbl/d).  The
decrease in crude oil and NGLs production  from 2006 primarily  reflected lower
production in the North Sea due to the timing of planned maintenance activities
and reduced production from the Baobab Field in Offshore West Africa, offset by
increased  production in North America.  Crude oil and NGLs production for 2007
was within the Company's guidance.

Natural gas  production  continues to represent the Company's  largest  product
offering,  accounting for 45% of the Company's total production.  Total natural
gas  production  before  royalties  increased 12% to 1,668 mmcf/d for 2007 from
1,492  mmcf/d for 2006  (2005 - 1,439  mmcf/d).  The  increase  in natural  gas
production from 2006 primarily reflected additional natural gas production from
the  ACC  acquisition,  partially  offset  by  production  declines  due to the
Company's  strategic  reduction in natural gas drilling  activity.  Natural gas
production for 2007 was within the Company's guidance.

For 2008,  annual  production  is  forecasted  to average  between  316,000 and
366,000  bbl/d of crude oil and NGLs and  between  1,429  and  1,513  mmcf/d of
natural gas.

NORTH AMERICA

North America crude oil and NGLs  production  for 2007  increased 5% to average
246,779 bbl/d from 235,253 bbl/d for 2006 (2005 - 221,669 bbl/d).  The increase
in production  from 2006 was primarily due to the results from the Pelican Lake
project,  the cyclic nature of the Company's  thermal  production,  and the ACC
acquisition.

North America  natural gas  production  for 2007 increased 12% to average 1,643
mmcf/d  from 1,468  mmcf/d  for 2006 (2005 - 1,416  mmcf/d).  The  increase  in
natural gas production  from 2006 reflected the impact of the ACC  acquisition,
partially offset by production  declines in 2007 due to the Company's strategic
decision to reduce natural gas drilling activity.

NORTH SEA

North Sea crude oil production for 2007 was 55,933 bbl/d, a decrease of 7% from
60,056  bbl/d for 2006  (2005 - 68,593  bbl/d)  due to the  timing  of  planned
maintenance activities,  lower than anticipated production from the Lyell Field
development and water  injection  problems  experienced  during the year at the
Ninian  Field.  The Ninian water  injection  issues were resolved in the fourth
quarter of 2007.

                                                                             14
<PAGE>

OFFSHORE WEST AFRICA

Offshore  West Africa crude oil  production  for 2007  decreased  22% to 28,520
bbl/d from 36,689 bbl/d for 2006 (2005 - 22,906  bbl/d).  Production  decreased
from 2006 due to continued  challenges with sand production at the Baobab Field
where 5 of 10  production  wells  remain  shut in. The  Company  has  secured a
deepwater  rig,  expected in mid-year  2008,  that should enable the Company to
execute its plan to return certain of the shut-in wells to production  over the
course of 2008 and 2009. At the Espoir Fields, production delivered in 2007 was
in line with expectations,  reflecting the successful execution of the drilling
campaign at the West Espoir Field.

<TABLE>
<CAPTION>
ROYALTIES

                                                       2007         2006         2005
======================================================================================
<S>                                              <C>          <C>          <C>
CRUDE OIL AND NGLS ($/bbl) (1)
North America                                    $     7.19   $     5.86   $     5.37
North Sea                                        $     0.14   $     0.13   $     0.10
Offshore West Africa                             $     6.40   $     2.81   $     1.62
Company average                                  $     5.94   $     4.48   $     3.97
--------------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
North America                                    $     1.12   $     1.31   $     1.78
North Sea                                        $        -   $        -   $        -
Offshore West Africa                             $     0.51   $     0.22   $     0.16
Company average                                  $     1.11   $     1.29   $     1.75
--------------------------------------------------------------------------------------
COMPANY AVERAGE ($/boe) (1)                      $     6.26   $     5.89   $     6.82
--------------------------------------------------------------------------------------
PERCENTAGE OF REVENUE (2)
Crude oil and NGLs                                      11%           8%           8%
Natural gas                                             16%          19%          20%
Boe                                                     13%          12%          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  fall under the oil sands  royalty  regime and are  calculated  on a
project by project  basis as a  percentage  of gross  revenue  less  operating,
capital  and  abandonment  costs  ("net  profit").  For 2008 and  prior  years,
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.  Effective  January 1, 2009,  proposed
changes to the Alberta royalty regime include the  implementation  of a sliding
scale for oil sands  royalties  ranging from 1% to 9% on a gross  revenue basis
pre-payout  and 25% to 40% on a net  revenue  basis  post-payout  depending  on
benchmark crude oil pricing.

Crude oil and NGLs  royalties  for 2007  continued to reflect  strong  realized
crude oil prices and the impact of the full recovery of the  Company's  capital
investments in the Primrose North and South Fields in 2006. Upon full recovery,
Crown royalty rates on the Primrose North and South Fields increased from 1% of
gross revenue to 25% of revenue less operating,  capital and abandonment costs.
North America crude oil and NGLs  royalties per bbl are  anticipated to average
14% to 16% of gross  revenue for 2008,  comparable to 15% for 2007 (2006 - 13%;
2005 - 14%).

Natural gas royalties per mcf generally  fluctuate  with natural gas prices and
well productivity.  Natural gas royalties per mcf decreased from 2006 primarily
due to decreased  benchmark  natural gas prices and the impact of certain other
adjustments.  North America  natural gas royalties per mcf are  anticipated  to
average  17% to 20% of gross  revenue for 2008,  an increase  from 16% for 2007
(2006 - 19%; 2005 - 21%).

Effective January 1, 2009, proposed new royalty formulas for conventional crude
oil  and  natural  gas are to  operate  on  sliding  scales  ranging  up to 50%
determined by commodity prices and well productivity.

NORTH SEA

North Sea government  royalties on crude oil were eliminated  effective January
1, 2003.  The  remaining  royalty is a gross  overriding  royalty on the Ninian
Field.

                                                                             15
<PAGE>

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 oil and profit oil. Cost recovery oil allows the Company to
recover its capital and  production  costs and the costs carried by the Company
on behalf of the Government  State Oil Company.  Profit oil 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 oil attributable to the Company's  equity interest is allocated  between
royalty expense and current income tax expense in accordance with the PSCs. The
Company's  capital  investments  in the Espoir  Fields were fully  recovered in
early 2007,  increasing  royalty  rates and current  income taxes in accordance
with the terms of the PSCs.

Royalty rates as a percentage  of revenue  averaged  approximately  9% for 2007
compared to 4% for 2006 (2005 - 3%).  The  increase in royalty  rates from 2006
was due to the Company's full recovery of its capital  investment in the Espoir
Fields  in  2007  and  the  resulting  increase  in  profit  oil on  which  the
Government's  entitlement  is based.  Offshore  West Africa  royalty  rates are
anticipated to average 12% to 17% of gross revenue for 2008.

<TABLE>
<CAPTION>
PRODUCTION EXPENSE

                                                        2007            2006           2005
============================================================================================
<S>                                              <C>             <C>            <C>
CRUDE OIL AND NGLS ($/bbl) (1)
North America                                    $     12.26     $     11.73    $     10.49
North Sea                                        $     20.78     $     17.57    $     14.94
Offshore West Africa                             $      8.32     $      7.45    $      6.50
Company average                                  $     13.34     $     12.29    $     11.17
--------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
North America                                    $      0.90     $      0.81    $      0.71
North Sea                                        $      2.17     $      1.40    $      2.44
Offshore West Africa                             $      1.48     $      1.19    $      1.05
Company average                                  $      0.91     $      0.82    $      0.73
--------------------------------------------------------------------------------------------
COMPANY AVERAGE ($/boe) (1)                      $      9.75     $      9.14    $      8.21
============================================================================================
</TABLE>
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

NORTH AMERICA

North America crude oil and NGLs  production  expense for 2007  increased 5% to
$12.26  per bbl from  $11.73  per bbl for 2006  (2005 - $10.49  per  bbl).  The
increase  in  production  expense  from  2006 was  primarily  due to  increased
industry-wide  cost  pressures and a continuing  upward trend in property taxes
and lease rentals.  During the second half of 2007, costs decreased as a result
of the timing of primary steam  cycles,  lower cost of natural gas fuel for the
Company's thermal  operations,  and higher  production  volumes in both Pelican
Lake and Primrose production areas, where a large portion of costs are fixed in
nature.

North America  natural gas  production  expense for 2007 increased 11% to $0.90
per mcf from $0.81 per mcf for 2006 (2005 - $0.71 per mcf).  This  increase was
primarily  due to  industry-wide  cost  pressures  in 2006 and  early  2007,  a
continuing  upward trend in property  taxes and lease  rentals,  as well as the
Company's  strategic  reduction  in natural gas drilling  activity,  decreasing
natural gas sales throughout 2007 and increasing  production expense per mcf on
the fixed cost portion of production costs.

Production  expense per boe for 2008 is  anticipated to increase as a result of
an overall  reduction in budgeted volumes for 2008, while fixed costs,  such as
property taxes and lease rentals, continue to escalate.

NORTH SEA

North Sea crude oil  production  expense  increased  on a per barrel basis from
2006 due to planned  maintenance  shutdowns,  varying  production  volumes on a
relatively fixed cost base, the timing of liftings from various fields, and the
impact of the stronger Canadian dollar.

                                                                             17
<PAGE>

OFFSHORE WEST AFRICA

Offshore  West  Africa  crude oil  production  expense  on a per  barrel  basis
increased  from  2006  primarily  due to the  impact  of  continuing  operating
challenges  with sand  production at the Baobab  Field,  resulting in decreased
production  volumes on a  relatively  fixed  operating  cost  base.  Production
expense was positively impacted by the impact of the stronger Canadian dollar.

MIDSTREAM

($ millions)                                           2007      2006      2005
================================================================================
Revenue                                             $    74   $    72   $    77
Production expense                                       22        23        24
--------------------------------------------------------------------------------
Midstream cash flow                                      52        49        53
Depreciation                                              8         8         8
--------------------------------------------------------------------------------
Segment earnings before taxes                       $    44   $    41   $    45
================================================================================

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.

DEPLETION, DEPRECIATION AND AMORTIZATION (1)

($ millions, except per boe amounts) (2)           2007        2006        2005
================================================================================
North America                                 $   2,350   $   1,897   $   1,595
North Sea                                     $     340   $     297   $     306
Offshore West Africa                          $     165   $     189   $     104
--------------------------------------------------------------------------------
Expense                                       $   2,855   $   2,383   $   2,005
  $/boe                                       $   12.84   $   11.27   $   10.02
================================================================================
(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 for 2007 increased
20% to $2,855 million from $2,383 million for 2006 (2005 - $2,005 million). The
increase  in DD&A  expense  in total  and on a boe  basis in 2007 from 2006 was
primarily due to overall  increases in finding and development costs associated
with crude oil and natural gas exploration, increased estimated future costs to
develop the Company's proved undeveloped reserves,  and a higher depletion base
in North America  related to the ACC  acquisition,  together with the impact of
higher sales volumes. The increase in DD&A expense in 2007 was partially offset
in the North  Sea and  Offshore  West  Africa  by the  impact  of the  stronger
Canadian dollar relative to the US dollar.

ASSET RETIREMENT OBLIGATION ACCRETION

($ millions, except per boe amounts) (1)             2007       2006       2005
================================================================================
North America                                    $     38   $     35   $     34
North Sea                                        $     30   $     31   $     34
Offshore West Africa                             $      2   $      2   $      1
--------------------------------------------------------------------------------
Expense ($ millions)                             $     70   $     68   $     69
  $/boe                                          $   0.32   $   0.32   $   0.34
================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

Asset retirement  obligation  accretion expense  represents the increase in the
carrying amount of the asset retirement  obligation due to the passage of time.
Accretion expense was comparable to 2006.

                                                                             17
<PAGE>

ADMINISTRATION EXPENSE

($ millions, except per boe amounts) (1)             2007       2006       2005
================================================================================
Net expense ($ millions)                         $    208   $    180   $    151
  $/boe                                          $   0.93   $   0.85   $   0.75
================================================================================
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

Net administration  expense for 2007 increased in total and on a boe basis from
2006 primarily due to increased staffing and  administrative  costs and overall
inflationary cost pressures.

STOCK-BASED COMPENSATION

($ millions)                                      2007         2006        2005
================================================================================
Stock-based compensation expense             $     193    $     139   $     723
================================================================================

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 $193  million  ($134  million  after-tax)  stock-based
compensation expense during 2007 in connection with the 17% appreciation in the
Company's  share  price  (December  31,  2007 - C$72.58;  December  31,  2006 -
C$62.15; December 31, 2005 - C$57.63; December 31, 2004 - C$25.63). 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 at each reporting  date 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. For the year
ended  December 31, 2007,  the Company  capitalized  $58 million in stock-based
compensation  as part of the Horizon  Project (2006 - $79 million;  2005 - $101
million). The stock-based compensation liability at December 31, 2007 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,  2007.  In
periods when  substantial  stock price changes occur, the Company is subject to
significant earnings volatility.

For the year ended  December 31, 2007,  the Company paid $375 million for stock
options  surrendered  for cash  settlement  (2006 - $264  million;  2005 - $227
million).

<TABLE>
<CAPTION>
INTEREST EXPENSE

($ millions, except per boe amounts and interest rates) (1)      2007        2006        2005
==============================================================================================
<S>                                                          <C>         <C>         <C>
Interest expense, gross                                      $    632    $    336    $    221
Less: capitalized interest, Horizon Project                       356         196          72
----------------------------------------------------------------------------------------------
Interest expense, net                                        $    276    $    140    $    149
  $/boe                                                      $   1.24    $   0.66    $   0.74
Average effective interest rate                                  5.5%        5.7%        5.6%
==============================================================================================
</TABLE>
(1)  AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

Gross  interest  expense  increased  from 2006  primarily due to increased debt
levels  associated  with the ACC  acquisition  and the  on-going  financing  of
Horizon Project capital expenditures.

The Company's average effective  interest rate for 2007 reflected the impact of
the stronger Canadian dollar,  offset by higher cost US dollar denominated debt
issued in March 2007 and the impact of higher  short-term  lending rates on the
Company's floating rate debt due to credit market uncertainty.

In 2008,  upon  commencement  of operations of Phase 1 of the Horizon  Project,
interest  capitalization will cease on this Phase,  increasing interest expense
accordingly.

                                                                             18
<PAGE>

RISK MANAGEMENT ACTIVITIES

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

Commencing January 1, 2007, the Company adopted new accounting standards issued
by the  CICA  relating  to the  accounting  for  and  disclosure  of  financial
instruments and comprehensive income.

Adoption  of  these  standards  required  the  Company  to  record  all  of its
derivative  financial  instruments on the balance sheet at estimated fair value
as at January 1, 2007, including those designated as hedges. Designated hedges,
other than cross currency swaps,  were previously not recognized on the balance
sheet  but  were  disclosed  in the  notes  to the  financial  statements.  The
adjustment to recognize the designated hedges on the balance sheet was recorded
as an adjustment  to the opening  balance of retained  earnings or  accumulated
other comprehensive income, as appropriate.

With the  exception  of the  foreign  currency  translation  adjustment,  these
standards  were adopted  prospectively;  accordingly,  comparative  amounts for
prior  periods  have not been  restated.  The  reclassification  of the foreign
currency  translation  adjustment  to other  comprehensive  income was  applied
retroactively with prior period restatement.

The effects of adopting  these  standards on the opening  balance sheet were as
follows:

<TABLE>
($ millions)                                                          JANUARY 1, 2007
======================================================================================
<S>                                                                 <C>
Increased current portion of other long-term assets (1)             $             193
Decreased other long-term assets (2)                                $             (16)
Decreased long-term debt (3)                                        $             (72)
Increased retained earnings (4)                                     $              10
Increased foreign currency translation adjustment (5)               $              13
Increased accumulated other comprehensive income (6)                $             146
Decreased current portion of future income tax asset (7)            $             (62)
Increased future income tax liability (7)                           $              18
======================================================================================
</TABLE>
(1)  RELATES TO THE  RECOGNITION  OF THE  CURRENT  PORTION OF THE FAIR VALUE OF
     DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(2)  RELATES TO THE  RECOGNITION OF THE LONG-TERM  PORTION OF THE FAIR VALUE OF
     DERIVATIVE  FINANCIAL  INSTRUMENTS  DESIGNATED AS CASH FLOW AND FAIR VALUE
     HEDGES, AS WELL AS THE  RECLASSIFICATION OF TRANSACTION COSTS AND ORIGINAL
     ISSUE DISCOUNTS FROM DEFERRED CHARGES TO LONG-TERM DEBT.
(3)  RELATES  TO THE FAIR  VALUE  IMPACT OF  DERIVATIVE  FINANCIAL  INSTRUMENTS
     DESIGNATED  AS FAIR  VALUE  HEDGES,  AS WELL  AS THE  RECLASSIFICATION  OF
     TRANSACTION COSTS AND ORIGINAL ISSUE DISCOUNTS.
(4)  RELATES TO THE IMPACT ON ADOPTION OF THE MEASUREMENT OF INEFFECTIVENESS ON
     DERIVATIVE FINANCIAL INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(5)  RELATES TO THE  RETROACTIVE  RESTATEMENT OF FOREIGN  CURRENCY  TRANSLATION
     ADJUSTMENT TO ACCUMULATED OTHER COMPREHENSIVE INCOME.
(6)  RELATES TO THE  RECOGNITION  OF  ACCUMULATED  OTHER  COMPREHENSIVE  INCOME
     ARISING FROM THE  MEASUREMENT  OF  EFFECTIVENESS  ON DERIVATIVE  FINANCIAL
     INSTRUMENTS DESIGNATED AS CASH FLOW HEDGES.
(7)  RELATES TO THE FUTURE INCOME TAX IMPACTS OF THE ABOVE NOTED ADJUSTMENTS.

Effective January 1, 2007, all derivative financial  instruments are recognized
at estimated fair value on the consolidated balance sheet at each balance sheet
date. The estimated  fair value of derivative  financial  instruments  has been
determined based on appropriate  internal valuation  methodologies and/or 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 these differences may be material.

The Company formally  documents all derivative  financial  instruments that are
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  periodically  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. The effective portion of changes in
the fair value of derivative  commodity price contracts designated as cash flow
hedges  is  initially   recognized  in  other   comprehensive   income  and  is
reclassified to risk management  activities in consolidated net earnings in the
same  period or  periods  in which the crude oil or  natural  gas is sold.  The
ineffective portion of changes in the fair value of these designated  contracts

                                                                             19
<PAGE>

is immediately  recognized in risk management  activities in  consolidated  net
earnings. All changes in the fair value of non-designated crude oil and natural
gas commodity price  contracts are recognized in risk management  activities in
consolidated net earnings.

The Company  enters into  interest  rate swap  contracts to manage its fixed to
floating  interest rate mix on certain of its 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.  Changes in
the fair value of interest rate swap contracts  designated as fair value hedges
and  corresponding  changes in the fair value of the hedged  long-term debt are
included in interest expense in consolidated net earnings.  Changes in the fair
value of  non-designated  interest  rate swap  contracts  are  included in risk
management activities in consolidated net earnings.

Cross currency swap contracts are periodically used to manage currency exposure
on US dollar  denominated  long-term  debt.  The cross  currency swap contracts
require the  periodic  exchange of  payments  with the  exchange at maturity of
notional principal amounts on which the payments are based. Changes in the fair
value of the  foreign  exchange  component  of cross  currency  swap  contracts
designated as cash flow hedges are included in foreign exchange in consolidated
net  earnings.  The  effective  portion  of  changes  in the fair  value of the
interest rate  component of cross  currency swap  contracts  designated as cash
flow  hedges  is  initially  included  in  other  comprehensive  income  and is
reclassified to interest  expense when realized,  with the ineffective  portion
immediately  recognized  in risk  management  activities  in  consolidated  net
earnings.  Changes  in the fair value of  non-designated  cross  currency  swap
contracts  are  included in risk  management  activities  in  consolidated  net
earnings.

Gains or losses on the  termination  of  financial  instruments  that have been
designated  as  cash  flow  hedges  are  deferred   under   accumulated   other
comprehensive  income on the  consolidated  balance  sheets and amortized  into
consolidated net earnings in the period in which the underlying  hedged item 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 consolidated
net earnings.  Gains or losses on the termination of financial instruments that
have not been designated as hedges are recognized in consolidated  net earnings
immediately.

Embedded derivatives are derivatives that are included in a non-derivative host
contract.  Embedded  derivatives are recorded at fair value separately from the
host contract when their economic characteristics and risks are not clearly and
closely related to the host contract.

Transaction costs that are directly attributable to the acquisition or issue of
a financial  asset or  financial  liability  and  original  issue  discounts on
long-term  debt  have  been  included  in the  carrying  value  of the  related
financial  asset or liability  and are amortized to  consolidated  net earnings
over the life of the financial instrument using the effective interest method.

<TABLE>
<CAPTION>
RISK MANAGEMENT ACTIVITIES

($ millions)                                               2007          2006         2005
===========================================================================================
<S>                                                   <C>          <C>           <C>
REALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments              $     505    $    1,395    $     753
Natural gas financial instruments                          (343)          (70)         283
Interest rate swaps                                           -             -           (9)
-------------------------------------------------------------------------------------------
                                                      $     162    $    1,325    $   1,027
-------------------------------------------------------------------------------------------
UNREALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments              $   1,244    $     (736)   $     847
Natural gas financial instruments                           156          (260)          77
Interest rate and cross-currency swaps                        -           (17)           1
-------------------------------------------------------------------------------------------
                                                      $   1,400    $   (1,013)   $     925
-------------------------------------------------------------------------------------------
TOTAL                                                 $   1,562    $      312    $   1,952
===========================================================================================
</TABLE>
The realized  losses  (gains) from crude oil and NGLs and natural gas financial
instruments  would have decreased  (increased) the Company's  average  realized
prices as follows:

<TABLE>
                                                          2007          2006       2005
-------------------------------------------------------------------------------------------
<S>                                                   <C>          <C>           <C>
Crude oil and NGLs ($/bbl) (1)                        $    4.18    $    11.57    $    6.68
Natural gas ($/mcf) (1)                               $   (0.56)   $    (0.13)   $    0.54
===========================================================================================
</TABLE>
(1)  AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

                                                                             20
<PAGE>

Complete  details related to outstanding  derivative  financial  instruments at
December  31,  2007  are  disclosed  in note 12 to the  Company's  consolidated
financial  statements.  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).

As effective as the Company's hedges are against reference  commodity prices, a
substantial portion of the commodity derivative  financial  instruments entered
into by the Company have not been formally  designated as hedges for accounting
purposes or do not meet the requirements for hedge accounting under GAAP due to
currency,  product  quality and  location  differentials  (the  "non-designated
hedges"). The change in the fair value of the non-designated hedges is based on
prevailing  forward  commodity  prices in  effect at the end of each  reporting
period and is reflected  in risk  management  activities  in  consolidated  net
earnings.  The  cash  settlement  amount  of  the  risk  management  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, 2007. Due to changes in the crude oil and natural gas forward pricing,  and
the reversal of prior period unrealized gains and losses,  the Company recorded
a net  unrealized  loss of  $1,400  million  ($977  million  after-tax)  on its
commodity risk management activities for the year ended December 31, 2007 (2006
- $1,013 million unrealized gain, $674 million  after-tax;  2005 - $925 million
unrealized loss, $607 million after-tax).

FOREIGN EXCHANGE

($ millions)                                        2007       2006        2005
================================================================================
Realized foreign exchange loss (gain)           $     53    $   (12)   $    (29)
Unrealized foreign exchange (gain) loss             (524)       134        (103)
--------------------------------------------------------------------------------
Total                                           $   (471)   $   122    $   (132)
================================================================================

The Company's  North Sea operations are classified as  self-sustaining  for the
purposes  of  foreign  currency  translation.  The  North  Sea  operations  are
initially  measured in US dollars and then translated to Canadian dollars using
the current rate method,  whereby assets and  liabilities  are translated  into
Canadian  dollars  using the exchange rate in effect at the balance sheet date,
while  revenue and expenses are  translated  into  Canadian  dollars  using the
monthly average exchange rate.  Foreign currency gains or losses arising on the
translation of non-US dollar  monetary  assets and  liabilities are included in
net  earnings  while  subsequent  gains or losses  arising  on  translation  to
Canadian dollars are deferred and included in accumulated  other  comprehensive
income.

The  Company's  Offshore  West Africa  foreign  operations  are  classified  as
integrated  for the purposes of foreign  currency  translation.  Offshore  West
Africa foreign  operations and foreign currency  transactions and balances held
in North  America are  directly  translated  into  Canadian  dollars  using the
temporal  method,  whereby  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.  Revenue
and expenses are translated to Canadian dollars at the monthly average exchange
rates.  All  related  foreign  exchange  gains or losses  are  included  in net
earnings.

As a result of foreign currency  translation,  the Company's  operating results
are affected by the  fluctuations  in 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 results in increased
revenue from the sale of the Company's  production.  Production expenses in the
North Sea are subject to foreign  currency  fluctuations  due to changes in the
exchange  rate of the UK pound  sterling  to the US  dollar,  while  production
expenses in Offshore West Africa are subject to foreign  currency  fluctuations
due to changes in the exchange  rate of the  Canadian  dollar to the US dollar.
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 net unrealized  foreign exchange gain in 2007 was primarily  related to the
strengthening  of the Canadian dollar in relation to the US dollar with respect
to the US dollar debt,  partially  offset by an unrealized loss of $350 million
related to the impact of the cross  currency  swaps.  The net realized  foreign
exchange loss for 2007 was primarily due to the result of foreign exchange rate
fluctuations on settlement of working  capital items  denominated in US dollars
or UK pounds  sterling.  The Canadian  dollar ended the year above  parity,  at
US$1.0120  compared to  US$0.8581  at December  31, 2006  (December  31, 2005 -
US$0.8577).

During 2007, the Company de-designated the portion of the US dollar denominated
debt  previously   hedged  against  its  net  investment  in  US  dollar  based
self-sustaining foreign operations.  Accordingly,  all foreign exchange (gains)
losses  arising  each period on US dollar  denominated  long-term  debt are now
recognized in the consolidated statement of earnings.

                                                                             21
<PAGE>

<TABLE>
<CAPTION>
TAXES

($ millions, except income tax rates)                                     2007        2006       2005
======================================================================================================
<S>                                                                    <C>         <C>        <C>
TAXES OTHER THAN INCOME TAX
Current                                                                $   121     $   219    $   203
Deferred                                                                    44          37         (9)
------------------------------------------------------------------------------------------------------
                                                                       $   165     $   256    $   194
------------------------------------------------------------------------------------------------------

CURRENT INCOME TAX
North America                                                          $    96     $   143    $    99
North Sea                                                                  210          30        155
Offshore West Africa                                                        74          49         32
------------------------------------------------------------------------------------------------------
                                                                           380         222        286
FUTURE INCOME TAX                                                         (456)        652        353
------------------------------------------------------------------------------------------------------
                                                                           (76)        874        639
Income tax and other legislative changes (1) (2) (3)                       864         395         19
------------------------------------------------------------------------------------------------------
                                                                       $   788     $ 1,269    $   658
------------------------------------------------------------------------------------------------------
EFFECTIVE INCOME TAX RATE BEFORE INCOME TAX RATE AND OTHER
    LEGISLATIVE CHANGES                                                  31.1%       37.3%      39.0%
======================================================================================================
</TABLE>
(1)  INCLUDES THE EFFECT OF ONE TIME RECOVERIES OF $864 MILLION DUE TO CANADIAN
     FEDERAL INCOME TAX RATE REDUCTIONS AND OTHER  LEGISLATIVE  CHANGES ENACTED
     OR SUBSTANTIVELY ENACTED DURING 2007.

(2)  INCLUDES THE EFFECT OF THE FOLLOWING:

     o  A  ONE  TIME  EXPENSE  OF  $110  MILLION   RELATED  TO  THE   INCREASED
        SUPPLEMENTARY  CHARGE  ON OIL  AND GAS  PROFITS  IN THE UK  NORTH  SEA,
        ENACTED IN 2006.

     o  A ONE TIME  RECOVERY OF $438 MILLION DUE TO CANADIAN  FEDERAL,  ALBERTA
        AND SASKATCHEWAN CORPORATE INCOME TAX RATE REDUCTIONS ENACTED IN 2006.

     o  A ONE  TIME  RECOVERY  OF $67  MILLION  DUE  TO  OFFSHORE  WEST  AFRICA
        CORPORATE INCOME TAX RATE REDUCTIONS ENACTED IN 2006.

(3)  INCLUDES THE EFFECT OF A ONE TIME RECOVERY OF $19 MILLION DUE TO A BRITISH
     COLUMBIA CORPORATE INCOME TAX RATE REDUCTION ENACTED IN 2005.

Taxes other than income tax primarily  includes current and deferred  petroleum
revenue tax ("PRT").  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,  timing  and  amount of
capital expenditures  incurred in Canada in any particular year. In particular,
current  taxes in a  specific  year are  sensitive  to the  timing  of when the
Horizon  Project  capital  expenditures  are deductible for Canadian income tax
purposes.

During 2007, the Canadian Federal Government  enacted or substantively  enacted
income tax rate and other  legislative  changes,  resulting  in a reduction  of
future income tax liabilities of approximately $864 million. As a result of the
enacted income tax rate changes,  the federal corporate income tax rate will be
reduced over the next five years from 21% in 2007 to 15% in 2012.

During 2006,  enacted 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,  enacted  income tax rate changes in North  America  resulted in a
reduction of future income tax liabilities of approximately $19 million.

During 2003, the Canadian Federal Government enacted  legislation to change the
taxation of resource income.  The legislation  reduced 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 was phased out
and a deduction for actual crown royalties paid was phased in. As a result,  in
2007  crown  royalties  were  fully  deductible  and the  Company  is no longer
eligible for the resource allowance.

                                                                             22
<PAGE>

The  Company's  consolidated  effective  income  tax rate for 2007 was  reduced
primarily due to income tax rate reductions  enacted in Canada during the year,
the effects of the non-taxable  portion of unrealized foreign exchange gains on
US  dollar  debt,  net of  unrealized  losses  on  cross  currency  swaps,  and
adjustments  to future tax expense in Canada  related to the final  phase-in of
deductibility of crown royalties and the elimination of the resource  allowance
deduction  in  2007.  For  2008,  based  on  budgeted  prices  and the  current
availability of tax pools,  the Company expects to be cash taxable in Canada in
the amount of $75 million to $150 million.

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

($ millions)                                                   2007         2006       2005
============================================================================================
<S>                                                       <C>         <C>         <C>
EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT
Net property (dispositions) acquisitions (2)              $     (39)  $    4,733  $    (320)
Land acquisition and retention                                   95          210        254
Seismic evaluations                                             124          130        132
Well drilling, completion and equipping                       1,642        2,340      2,000
Production and related facilities                             1,205        1,314      1,295
--------------------------------------------------------------------------------------------
TOTAL NET RESERVE REPLACEMENT EXPENDITURES                    3,027        8,727      3,361
--------------------------------------------------------------------------------------------
Horizon Project:
   Phase 1 construction costs                                 2,740        2,768      1,249
   Phases 2/3 costs                                             124           79          -
   Capitalized interest, stock-based compensation and
     other                                                      437          338        250
--------------------------------------------------------------------------------------------
Total Horizon Project                                         3,301        3,185      1,499
--------------------------------------------------------------------------------------------
Midstream                                                         6           12          4
Abandonments (3)                                                 71           75         46
Head office                                                      20           26         22
--------------------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES                            $   6,425   $   12,025  $   4,932
--------------------------------------------------------------------------------------------
BY SEGMENT
North America                                             $   2,428   $    7,936  $   2,530
North Sea                                                       439          646        387
Offshore West Africa                                            159          134        439
Other                                                             1           11          5
Horizon Project                                               3,301        3,185      1,499
Midstream                                                         6           12          4
Abandonments (3)                                                 71           75         46
Head office                                                      20           26         22
--------------------------------------------------------------------------------------------
Total                                                     $   6,425   $   12,025  $   4,932
============================================================================================
</TABLE>
(1)  NET  CAPITAL  EXPENDITURES  EXCLUDE  ADJUSTMENTS  RELATED  TO  DIFFERENCES
     BETWEEN CARRYING VALUE AND TAX VALUE.
(2)  INCLUDES BUSINESS COMBINATIONS.
(3)  ABANDONMENTS  REPRESENT EXPENDITURES TO SETTLE ARO AND HAVE BEEN REFLECTED
     AS CAPITAL EXPENDITURES IN THIS TABLE.


                                                                             23
<PAGE>

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,  reducing overall exploration risk. By dominating  infrastructure,  the
Company is able to maximize utilization of its production  facilities,  thereby
increasing control over production costs.

Net  capital  expenditures  for 2007 were  $6,425  million  compared to $12,025
million for 2006 (2005 - $4,932 million).  Excluding the ACC  acquisition,  net
capital expenditures were $7,270 million for 2006. Capital expenditures in 2007
reflected  the  continued  progress  on the  Company's  larger,  future  growth
projects,  most notably the Horizon Project, as well as continued industry-wide
inflationary pressures, offset by the effects of an overall strategic reduction
in the North America natural gas drilling program.

During 2007, the Company  drilled a total of 1,322 net wells  consisting of 383
natural  gas wells,  592 crude oil wells,  254  stratigraphic  test and service
wells, and 93 wells that were dry. This compared to 1,738 net wells drilled for
2006 (2005 - 1,882 net wells).  The Company achieved an overall success rate of
91% for 2007,  excluding the stratigraphic  test and service wells (2006 - 91%;
2005 - 93%).

NORTH AMERICA

North America,  including the Horizon Project,  accounted for approximately 91%
of the total capital expenditures for the year ended December 31, 2007 compared
to approximately 93% for 2006 (2005 - 83%).

During 2007, the Company targeted 450 net natural gas wells, including 58 wells
in Northeast  British  Columbia,  133 wells in the Northern Plains region,  110
wells in Northwest  Alberta,  and 149 wells in the Southern Plains region.  The
Company also targeted 610 net crude oil wells during the year.  The majority of
these wells were concentrated in the Company's crude oil Northern Plains region
where 362 primary heavy crude oil wells,  127 Pelican Lake crude oil wells,  55
thermal crude oil wells and 6 light crude oil wells were drilled.  In addition,
60 wells  targeting  light crude oil were drilled  outside the Northern  Plains
region.

Due to significant  changes in relative  commodity prices between crude oil and
natural gas,  the Company has  continued to access its large crude oil drilling
inventory to maximize value in both the short and long term. As a result of the
Company's  focus on  drilling  crude oil wells in 2007,  natural  gas  drilling
activities were reduced to manage overall capital  spending.  Deferred  natural
gas well  locations  have been  retained in the Company's  prospect  inventory.
Drilling on ACC acquired  lands was  optimized  as part of the overall  capital
program.

In November of 2005,  the Company  announced a phased  expansion of its In-Situ
Oil Sands  Assets.  As part of the  development,  the Company is  continuing to
develop its Primrose  thermal  projects.  During 2007, the Company  drilled 135
stratigraphic  test wells and  observation  wells,  2 water source wells and 55
thermal  oil  wells.   Overall  Primrose   thermal   production  for  2007  was
approximately 64,000 bbl/d (2006 - 64,000 bbl/d).

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,  is anticipated to add approximately 40,000 bbl/d
when  complete.  The  Primrose  East  Expansion  received  Board of  Directors'
sanction in 2006 and the Alberta Energy and Utilities Board regulatory approval
in early 2007. Drilling and construction are currently underway, and production
is targeted to commence in 2009.

The next phase of the Company's In-Situ Oil Sands Assets expansion is the Kirby
project located 120 kilometers north of the existing Primrose  facilities.  The
Kirby project is  anticipated  to add an additional  45,000 bbl/d of production
growth. During 2007, the Company filed a combined application and Environmental
Impact  Assessment  for this project with Alberta  Environment  and the Alberta
Energy and Utilities Board.  Final corporate sanction and project scope will be
impacted by environmental regulations and their associated costs.

Development of new pads and secondary recovery  conversion  projects at Pelican
Lake  continued  as  expected   throughout  2007.  Drilling  consisted  of  125
horizontal crude oil wells, with plans to drill 105 additional horizontal crude
oil wells in 2008.  The  response  from the water and  polymer  flood  projects
continues to be positive. Pelican Lake production averaged approximately 34,000
bbl/d in 2007 (2006 - 30,000 bbl/d).

Due to 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 Design Basis  memorandum and Engineering  Design  Specification of

                                                                             24
<PAGE>

the  Canadian  Natural  Upgrader,  outside  of  the  Horizon  Project,  pending
clarification on the cost of future environmental legislation and a more stable
cost environment.

For 2008, the Company's  overall drilling activity in North America is expected
to  comprise  approximately  314  natural  gas wells  and 526 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
targeted to commence in the third  quarter of 2008 ramping up to 110,000  bbl/d
of 34(degree) API SCO.

Work progress on the Horizon  Project was 90% complete at year end. The project
status as at December 31, 2007 was as follows:

o    Overall detailed engineering 98.5% complete and substantially  complete in
     most areas;

o    Overall procurement 99% complete with over $5.6 billion in purchase orders
     and contracts awarded;

o    Commenced receipt and site assembly of Mine Operations  equipment (Shovels
     and Heavy Haul Trucks);

o    Overall construction progress 85% complete;

o    Mine overburden  removal  approximately  72% complete and 0.6 million bank
     cubic meters ahead of schedule;

o    Main  Control  Room  Distributed  Control  Systems  equipment  powered and
     tested;

o    Commissioned 260kV Transmission Line and turned over to operations;

o    Commissioned Raw Water Pumphouse and turned over to operations;

o    Completed reformer erection in Hydrogen Plant;

o    Completed installation and pre-commissioning of CPI Separator Building;

o    Completed the closure of Dyke 10 (external tailings pond) in Mining;

o    Completed  erection of Crushing  Plants and  conveyors in Ore  Preparation
     Area;

o    Completed Primary Separation Cells in Extraction; and

o    Completed construction of Main Laboratory.

The Company has budgeted  construction  costs of approximately  $1.7 billion to
$1.9  billion  for 2008  related to the  planned  completion  of Phase 1 of the
Horizon Project.

NORTH SEA

In 2007,  the Company  continued with its planned  program of infill  drilling,
recompletions, workovers and waterflood optimizations, and the execution of its
long-term  facilities  strategy.  During  2007,  7.2 net  wells  were  drilled,
including 3.5 net water injectors, with an additional 1.6 net wells drilling at
year end.

Commissioning  of the Columba E Raw Water  Injection  project was  successfully
completed on time and on budget  during 2007 and 2 water  injection  wells were
delivered,  allowing water injection into the reservoir to commence.  Injection
rates  delivered  were below  expectation  due to lower  reservoir  quality.  A
detailed  technical  evaluation  has been carried out and is being  executed to
deliver required injection rates under sustained fracture conditions.

During  2007,  the  subsea  project  to bring  gas lift to the Kyle  Field  was
successfully completed,  delivering above expectation production at the Banff /
Kyle hub.

The development of the Lyell Field continued  during the year with 2 production
wells coming on stream  through the existing  infrastructure.  Production  from
these initial Lyell wells was below  expectation and future  development  plans
are being  re-evaluated as a result. The Company remains committed to unlocking
the remaining development potential at the Lyell Field with a phased approach.

At the Ninian Field, the Company continued to execute its long-term  facilities
strategy,  with  investment  in the Ninian  South  platform  infrastructure  in
particular.  In addition,  infill locations were successfully  developed,  with
production  delivery  from  these  wells in line with  expectations,  and water
injection capacity was successfully increased.

                                                                             25
<PAGE>

In December 2007, the Company completed the sale of its working interest in the
B-Block, comprising the Balmoral, Stirling, and Glamis Fields.

OFFSHORE WEST AFRICA

During 2007, 4.7 net wells were drilled with 0.6 wells drilling at year end.

Development  drilling on West Espoir  continued  during 2007 with 5  additional
production wells and 2 additional injector wells added. West Espoir development
drilling was completed in early 2008, on budget and on time.

During 2007, the Company  awarded a contract for the upgrade of the Espoir FPSO
in order to increase the throughput handling  capability of the vessel.  Design
and procurement work commenced during the year.  Production volumes will not be
significantly  impacted during the installation work,  scheduled to complete in
late 2009. Gross fluids processing  capacity will increase from 50,000 bbl/d to
70,000 bbl/d, with natural gas handling  capacity  increasing from 55 mmcf/d to
75 mmcf/d upon completion of the project.

At the 90%  owned  and  operated  Olowi  Field in  offshore  Gabon,  all  major
construction  contracts  have been awarded,  and  construction  of the wellhead
towers and the FPSO is  ongoing.  The  project  is on  schedule  with  drilling
targeted to commence in the second quarter of 2008 and first crude oil targeted
in late 2008. Olowi  production is targeted to plateau at approximately  20,000
bbl/d, net to the Company.

<TABLE>
<CAPTION>
LIQUIDITY AND CAPITAL RESOURCES

($ millions, except ratios)                                          2007           2006          2005
=======================================================================================================
<S>                                                            <C>            <C>            <C>
Working capital deficit (1)                                    $    1,382     $      832     $   1,774
Long-term debt (2)                                             $   10,940     $   11,043     $   3,321
-------------------------------------------------------------------------------------------------------

Shareholders' equity
Share capital                                                  $    2,674     $    2,562     $   2,442
Retained earnings                                                  10,575          8,141         5,804
Accumulated other comprehensive income (loss)                          72           (13)            (9)
-------------------------------------------------------------------------------------------------------
Total                                                          $   13,321     $   10,690     $   8,237
-------------------------------------------------------------------------------------------------------

Debt to book capitalization (2) (3)                                   45%            51%           29%
Debt to market capitalization (2) (4)                                 22%            25%           10%
After tax return on average common shareholders'
  equity (5)                                                          22%            27%           14%
After tax return on average capital employed (2) (6)                  12%            17%           10%
=======================================================================================================
</TABLE>
(1) CALCULATED AS CURRENT ASSETS LESS CURRENT LIABILITIES.
(2)  LONG-TERM DEBT AT DECEMBER 31, 2007 IS STATED AT ITS CARRYING  VALUE,  NET
     OF FAIR VALUE ADJUSTMENTS, ORIGINAL ISSUE DISCOUNTS AND TRANSACTION COSTS.
     AMOUNTS FOR PERIODS  PRIOR TO JANUARY 1, 2007 WERE NOT  ADJUSTED FOR THESE
     ITEMS.
(3)  CALCULATED  AS  LONG-TERM  DEBT;  DIVIDED  BY THE  BOOK  VALUE  OF  COMMON
     SHAREHOLDERS' EQUITY PLUS LONG-TERM DEBT.
(4)  CALCULATED  AS  LONG-TERM  DEBT;  DIVIDED  BY THE  MARKET  VALUE OF COMMON
     SHAREHOLDERS' EQUITY PLUS LONG-TERM DEBT.
(5)  CALCULATED AS NET EARNINGS FOR THE YEAR; AS A PERCENTAGE OF AVERAGE COMMON
     SHAREHOLDERS' EQUITY FOR THE YEAR.
(6)  CALCULATED AS NET EARNINGS PLUS AFTER-TAX  INTEREST  EXPENSE FOR THE YEAR;
     AS A PERCENTAGE OF AVERAGE CAPITAL  EMPLOYED.  AVERAGE CAPITAL EMPLOYED IS
     THE  AVERAGE  SHAREHOLDERS'  EQUITY  AND  LONG-TERM  DEBT  FOR  THE  YEAR,
     INCLUDING  $7,001  MILLION  IN  AVERAGE  CAPITAL  EMPLOYED  RELATED TO THE
     HORIZON PROJECT (2006 - $3,760 MILLION; 2005 - $1,421 MILLION).

The Company's  capital  resources at December 31, 2007  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
multi-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
Limited, Baa2 with a stable outlook by Moody's Investors Service and BBB with a
stable  outlook by  Standard  & Poor's.  The  Company  does not have any direct
exposure to asset-backed commercial paper.

                                                                             26
<PAGE>

At December  31,  2007,  the Company had undrawn bank lines of credit of $1,442
million.  Details related to the Company's  long-term debt at December 31, 2007
are disclosed in note 5 to the Company's audited annual consolidated  financial
statements.  Subsequent to December 31, 2007,  the Company  issued an aggregate
US$1,200 million of unsecured notes.  Proceeds from the securities  issued were
used to repay bankers' acceptances under the Company's bank credit facilities.

At December 31, 2007, the Company's  working capital deficit was $1,382 million
and included the current portion of the stock-based  compensation  liability of
$390 million and the current  portion of the net  mark-to-market  liability for
risk  management  derivative  financial  instruments  of  $1,227  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  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, 2007.

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.

Long-term debt was $10,940 million at December 31, 2007, resulting in a debt to
book  capitalization  level of 45% as at December 31, 2007 (December 31, 2006 -
51%).  While this ratio is at the high end of 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 late  2008.  While the  Company
believes that it has the balance  sheet  strength and  flexibility  to complete
Phase  1 of  the  Horizon  Project,  as  well  as  its  other  planned  capital
expenditure programs, the Company has hedged a significant portion of its crude
oil and  natural gas  production  for 2008 at prices  that  protect  investment
returns.  In the future,  the  Company may also  consider  the  divestiture  of
certain  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
expenditures  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  estimated  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 are
hedged for 2008 and  approximately  53% of  expected  natural  gas  volumes are
hedged for the first  quarter of 2008.  Subsequent  to December 31,  2007,  the
Company  hedged  25,000  bbl/d of crude oil  volumes for 2009 using WTI collars
with a US$70.00 floor.


                                                                             27
<PAGE>

The Company has the  following  commodity  related  net  financial  derivatives
outstanding as at December 31, 2007:

<TABLE>
                                          REMAINING TERM           VOLUME     WEIGHTED AVERAGE PRICE           INDEX
=====================================================================================================================
<S>                                  <C>                     <C>               <C>                       <C>
CRUDE OIL
Crude oil price collars (1)          Jan 2008 - Mar 2008     50,000 bbl/d        US$60.00 - US$80.06             WTI
                                     Jan 2008 - Jun 2008     25,000 bbl/d        US$60.00 - US$80.44             WTI
                                     Apr 2008 - Sep 2008     25,000 bbl/d        US$60.00 - US$80.46             WTI
                                     Jul 2008 - Sep 2008     25,000 bbl/d       US$70.00 - US$123.75             WTI
                                     Oct 2008 - Dec 2008     25,000 bbl/d       US$70.00 - US$112.63             WTI
                                     Jan 2008 - Dec 2008     20,000 bbl/d        US$50.00 - US$65.53     Mayan Heavy
                                     Jan 2008 - Dec 2008     50,000 bbl/d        US$60.00 - US$75.22             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                       Jan 2008 - Dec 2008     50,000 bbl/d                   US$55.00             WTI

NATURAL GAS
AECO price collars                   Jan 2008 - Mar 2008     400,000 GJ/d        C$7.00   -  C$14.08            AECO
                                     Jan 2008 - Mar 2008     500,000 GJ/d        C$7.50   -  C$10.81            AECO
=====================================================================================================================
</TABLE>
(1)  SUBSEQUENT TO DECEMBER 31, 2007, THE COMPANY  ENTERED INTO 25,000 BBL/D OF
     US$70.00 - US$111.56 WTI COLLARS FOR THE PERIOD JANUARY TO DECEMBER 2009.

The Company's  outstanding  commodity financial  derivatives are expected to be
settled  monthly  based on the  applicable  index  pricing  for the  respective
contract month.

LONG-TERM DEBT

The  Company's  long-term  debt of $10,940  million at  December  31,  2007 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,  2007,  the  Company  had in place  unsecured  bank credit
facilities of $6,209 million, comprised of:

o    a $100 million demand credit facility;

o    a  non-revolving  syndicated  credit  facility of $2,350 million  maturing
     October 2009;

o    a revolving  syndicated  credit  facility of $2,230 million  maturing June
     2012;

o    a revolving  syndicated  credit  facility of $1,500 million  maturing June
     2012; and

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

During 2007, one of the revolving  syndicated  credit  facilities was increased
from $1,825 million to $2,230 million and a $500 million demand credit facility
was terminated.  The revolving  syndicated credit facilities were also extended
and now mature June 2012. 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 in November 2006, the
Company  executed a $3,850 million,  non-revolving  syndicated  credit facility
maturing in October 2009. In March 2007,  $1,500  million was repaid,  reducing
the facility to $2,350 million.

In addition to the outstanding debt, letters of credit and financial guarantees
aggregating  $345  million,  including  $300  million  related  to the  Horizon
Project, were outstanding at December 31, 2007.

MEDIUM-TERM NOTES

In December 2007,  the Company issued $400 million of unsecured  notes maturing
December 2010,  bearing interest at 5.50%.  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 $2,600  million
remaining on its  outstanding  $3,000  million base shelf  prospectus  filed in
September 2007 that allows for the issue of  medium-term  notes in Canada until
October 2009. If issued,  these  securities will bear interest as determined at
the date of issuance.

During 2007, $125 million of the 7.40%  unsecured  debentures due March 1, 2007
were repaid.

                                                                             28
<PAGE>

In 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.

SENIOR UNSECURED NOTES

The adjustable rate senior unsecured notes bear interest at 6.54%,  with annual
principal  repayments  of US$31  million  due in May 2008 and May 2009.  During
2007, US$31 million of the senior unsecured notes were repaid.

US DOLLAR DEBT SECURITIES

In March  2007,  the  Company  issued  US$2,200  million  of  unsecured  notes,
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
swaps to fix the Canadian  dollar interest and principal  repayment  amounts on
the  entire  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 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.  Proceeds from the
securities  issued were used to repay bankers'  acceptances under the Company's
bank credit facilities.

During 2007, the Company de-designated the portion of its US dollar denominated
debt  previously   hedged  against  its  net  investment  in  US  dollar  based
self-sustaining foreign operations.  Accordingly,  all foreign exchange (gains)
losses  arising  each period on US dollar  denominated  long-term  debt are now
recognized in the consolidated statement of earnings.

In 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  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 September  2007, the Company filed a base shelf  prospectus  that allows for
the issue of up to US$3,000  million of debt  securities  in the United  States
until October 2009.

Subsequent  to December  31,  2007,  the  Company  issued  US$1,200  million of
unsecured  notes  under  this US base  shelf  prospectus,  comprised  of US$400
million of 5.15%  unsecured  notes due February  2013,  US$400 million of 5.90%
unsecured  notes due February 2018, and US$400 million of 6.75% unsecured notes
due  February  2039.  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 US$1,800 million remaining on its outstanding
US$3,000 million base shelf prospectus.  If issued,  these securities will bear
interest as determined at the date of issuance.

SHARE CAPITAL

As at December 31, 2007, there were 539,729,000  common shares  outstanding and
30,659,000 stock options outstanding.  As at February 26, 2008, the Company had
540,252,000 common shares outstanding and 29,173,000 stock options outstanding.

During 2007,  the Company did not purchase any common  shares for  cancellation
pursuant to the Normal  Course  Issuer Bid  previously  filed for the  12-month
period  beginning  January 24, 2007 and ending January 23, 2008 (2006 - 485,000
common shares were purchased at an average price of $57.33 per common share for
a total cost of $28 million;  2005 - 850,000 common shares were purchased at an
average price of $53.29 per common share for a total cost of $45 million).  The
Company has decided not to renew the Normal Course Issuer Bid until  subsequent
to the completion of Phase 1 of the Horizon Project.

In February 2008, the Company's Board of Directors  approved an increase in the
annual  dividend  paid by the Company to $0.40 per common  share for 2008.  The
increase  represents  an 18%  increase  from the  prior  year,  recognizes  the
stability of the Company's  cash flow,  and provides a return to  Shareholders.
This is the eighth consecutive year in which the Company has paid dividends and
the seventh  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 March 2007,  an increase in the annual
dividend  paid by the Company was  approved to $0.34 per common share for 2007.
The increase represented a 13% increase from 2006.

                                                                             29
<PAGE>

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
offshore  FPSOs,  drilling  rigs and office  space;  and firm  commitments  for
gathering,  processing  and  transmission  services;  as well  as  expenditures
relating to ARO. As at December 31, 2007, no entities were  consolidated  under
CICA Handbook  Accounting  Guideline 15,  "Consolidation  of Variable  Interest
Entities".  The following  table  summarizes  the Company's  commitments  as at
December 31, 2007:

<TABLE>
($ millions)                                     2008         2009       2010      2011      2012   Thereafter
===============================================================================================================
<S>                                          <C>         <C>          <C>       <C>       <C>       <C>
Product transportation and pipeline          $    232    $     151    $   137   $   109   $    91   $      972
Offshore equipment operating lease (1)       $    114    $     129    $   113   $   111   $    90   $      387
Offshore drilling (2) (3)                    $    267    $     185    $    39   $     -   $     -   $        -
Asset retirement obligations (4)             $     33    $       4    $     5   $     4   $     4   $    4,376
Long-term debt (5)                           $     39    $   2,361    $   400   $   395   $   346   $    5,098
Interest expense (6)                         $    612    $     590    $   487   $   465   $   374   $    4,338
Office lease                                 $     26    $      28    $    28   $    22   $     3   $        -
Electricity and other                        $    166    $     173    $    25   $     4   $     -   $        -
===============================================================================================================
</TABLE>
(1)  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.  DURING THE
     INITIAL TERM,  THE TOTAL ANNUAL  PAYMENTS FOR THE GABON FPSO ARE ESTIMATED
     TO BE US$50 MILLION.
(2)  DURING 2007,  THE COMPANY  ENTERED INTO A ONE-YEAR  AGREEMENT FOR OFFSHORE
     DRILLING  SERVICES RELATED TO THE BAOBAB FIELD IN COTE D'IVOIRE,  OFFSHORE
     WEST AFRICA.  THE  AGREEMENT IS SCHEDULED TO COMMENCE IN 2008,  SUBJECT TO
     RIG AVAILABILITY.  ESTIMATED TOTAL PAYMENTS OF US$100 MILLION, AFTER JOINT
     VENTURE RECOVERIES, HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD 2008 -
     2009.
(3)  DURING 2007, THE COMPANY AWARDED  CONTRACTS FOR A DRILLING RIG AND FOR THE
     CONSTRUCTION OF WELLHEAD  TOWERS IN CONNECTION  WITH THE PLANNED  OFFSHORE
     DEVELOPMENT IN GABON,  OFFSHORE WEST AFRICA.  ESTIMATED  TOTAL PAYMENTS OF
     US$393  MILLION  HAVE BEEN  INCLUDED  IN THIS TABLE FOR THE PERIOD  2008 -
     2010.
(4)  AMOUNTS  REPRESENT   MANAGEMENT'S  ESTIMATE  OF  THE  FUTURE  UNDISCOUNTED
     PAYMENTS  TO SETTLE ARO RELATED TO RESOURCE  PROPERTIES,  FACILITIES,  AND
     PRODUCTION PLATFORMS,  BASED ON CURRENT LEGISLATION AND INDUSTRY OPERATING
     PRACTICES.  AMOUNTS  DISCLOSED  FOR THE PERIOD 2008 - 2012  REPRESENT  THE
     MINIMUM   REQUIRED   EXPENDITURES  TO  MEET  THESE   OBLIGATIONS.   ACTUAL
     EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED THESE MINIMUM AMOUNTS.
(5)  THE  LONG-TERM  DEBT  REPRESENTS  PRINCIPAL  REPAYMENTS  ONLY AND DOES NOT
     REFLECT FAIR VALUE  ADJUSTMENTS,  ORIGINAL ISSUE  DISCOUNTS OR TRANSACTION
     COSTS.  NO DEBT  REPAYMENTS  ARE REFLECTED FOR $2,366 MILLION OF REVOLVING
     BANK CREDIT FACILITIES DUE TO THE EXTENDABLE NATURE OF THE FACILITIES.
(6)  INTEREST   EXPENSE   AMOUNTS   REPRESENT  THE  SCHEDULED   FIXED-RATE  AND
     VARIABLE-RATE  CASH  PAYMENTS  RELATED  TO  LONG-TERM  DEBT.  INTEREST  ON
     VARIABLE-RATE  LONG-TERM DEBT WAS ESTIMATED BASED UPON PREVAILING INTEREST
     RATES AS OF DECEMBER 31, 2007.

In  addition  to  the  amounts   disclosed  above,  the  Company  has  budgeted
construction  costs of  approximately  $1.7  billion to $1.9  billion  for 2008
related to the planned completion of Phase 1 of the Horizon Project.

LEGAL PROCEEDINGS

The Company is defendant  and plaintiff in a number of legal actions that arise
in the  normal  course of  business.  In  addition,  the  Company is subject to
certain  contractor  construction  claims related to the Horizon  Project.  The
Company  believes that any liabilities  that might arise pertaining to any such
matters  would  not  have  a  material  effect  on its  consolidated  financial
position.

                                                                             30
<PAGE>

RESERVES

For  the  year  ended  December  31,  2007,  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, NGLs and natural
gas reserves(1) (3) 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 three
principal  differences between the two standards.  The first is 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. 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 third is the requirement to disclose a gross reserve reconciliation (before
the   consideration   of   royalties).   The  Company   discloses  its  reserve
reconciliation net of royalties in adherence to SEC requirements.

The  Company   annually   discloses  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 its 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 Annual Information Form.

For the year  ended  December  31,  2007,  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 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,  NGLs and  natural  gas
reserves as well as the Company's quantity of oil sands mining reserves.

Additional  reserves  disclosure is annually disclosed in the supplementary oil
and gas information of the Company's Annual Report.

(1)  CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS INCLUDES ALL OF THE COMPANY'S
     LIGHT/MEDIUM,  PRIMARY HEAVY, AND THERMAL CRUDE OIL, NATURAL GAS, COAL BED
     METHANE AND NGLS  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.

(3)  CONVENTIONAL CRUDE OIL, NGLS, AND NATURAL GAS RESERVES,  NET OF ROYALTIES,
     ARE ESTIMATED USING ROYALTY REGULATIONS IN EFFECT AS OF DECEMBER 31, 2007.
     SIMILARLY,  BITUMEN AND SYNTHETIC  CRUDE OIL  RESERVES,  NET OF ROYALTIES,
     RELATING TO SURFACE MINEABLE OIL SAND PROJECTS ARE ESTIMATED USING ROYALTY
     REGULATIONS IN EFFECT AS OF DECEMBER 31, 2007. ROYALTY CHANGES PROPOSED BY
     THE GOVERNMENT OF ALBERTA WILL BE INCORPORATED IN THE RESERVES  EVALUATION
     SHOULD THEY BE ENACTED.


                                                                             31
<PAGE>

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  into  synthetic  crude oil.  These  inherent  risks
include, but are not limited to, the following items:

o   Economic risk of finding,  producing and replacing 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, ARO and depletion rates;
o   Prevailing prices of crude oil and natural gas;
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 on commercially acceptable terms;
o   Foreign exchange risk due to fluctuating exchange rates on the Company's US
    dollar  denominated  debt  and as the  majority  of sales  are  based in US
    dollars;
o   Environmental  impact risk  associated  with  exploration  and  development
    activities,  including  GHG;
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 operations; and
o   Other circumstances affecting revenue and expenses.

The Company  uses a variety of means to help  mitigate  and/or  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 areas with
high working interests and by assuming operatorship of key facilities.  Product
mix is  diversified,  consisting  of the  production  of  natural  gas  and the
production  of  crude  oil  of  various  grades.   The  Company  believes  this
diversification  reduces  price risk when compared  with  over-leverage  to one
commodity.  Accounts  receivable from the sale of crude oil and natural gas are
mainly with customers in the crude oil and natural gas industry and are subject
to normal industry credit risks. 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.  Derivative 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 risk by entering into
financial  derivatives  with entities  which are  substantially  all investment
grade.  The  arrangements  and  policies  concerning  the  Company's  financial
instruments  are  under  constant  review  and may  change  depending  upon the
prevailing market conditions.

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 Annual Information Form.

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.  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"). Details of the Plan and the results are presented
to, and reviewed by, the Board of Directors quarterly.

                                                                             32
<PAGE>

The Company's Plan and operating  guidelines  focus on minimizing the impact of
operations  while  meeting   regulatory   requirements,   regional   management
frameworks, industry operating standards and guidelines, and internal corporate
standards.  The  Company,  as part of this Plan,  has  implemented  a proactive
program that includes:

o   An 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;
o   A program to replace the majority of fresh water for steaming with brackish
    water;
o   Environmental  planning for all projects to assess impacts and to implement
    avoidance, and mitigation programs;
o   Reporting for environmental liabilities;
o   A program to optimize  efficiencies at the Company's operating  facilities;
    and
o   Continued evaluation of new technologies to reduce environmental impacts.

The Company has also established stringent operating standards in four areas:

o   Using   water-based,   environmentally   friendly  drilling  muds  whenever
    possible;
o   Implementing  cost  effective  ways of reducing GHG  emissions  per unit of
    production;
o   Exercising care with respect to all waste produced through  effective waste
    management plans; and
o   Minimizing   produced   water   volumes   onshore  and   offshore   through
    cost-effective measures.

For  2007,  the  Company's  capital  expenditures   included  $71  million  for
abandonment expenditures (2006 - $75 million; 2005 - $46 million).

The Company's estimated undiscounted ARO at December 31, 2007 was as follows:

Estimated ARO, undiscounted ($ millions)                     2007         2006
================================================================================
North America                                         $     3,038   $     2,826
North Sea                                                   1,286         1,543
Offshore West Africa                                          102           128
--------------------------------------------------------------------------------
                                                            4,426         4,497
North Sea PRT recovery                                       (555)         (625)
--------------------------------------------------------------------------------
                                                      $     3,871   $     3,872
================================================================================

The  estimate  of 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 $555 million  (2006 - $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  undiscounted  abandonment
liability to $3,871 million (2006 - $3,872 million).

GREENHOUSE GAS AND OTHER AIR EMISSIONS

The Company is  concurrently  working with  legislators  and regulators as they
develop and implement new GHG emission laws and  regulations.  Internally,  the
Company is pursuing an integrated emissions reduction strategy,  to ensure that
it 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 GHG and air emissions 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.

In  Canada,  the  Federal  government  has  indicated  its  intent  to  develop
regulations  that  would  be in  effect  in  2010  to  address  industrial  GHG
emissions.  The Federal  Government  has also  outlined  national  and sectoral
reduction  targets for several  categories of air pollutants.  In Alberta,  GHG
regulations came into effect July 1, 2007,  affecting  facilities emitting more

                                                                             33
<PAGE>

than 100 kilotonnes of CO2e annually.  In the UK, GHG regulations  have been in
effect since 2005.  The Company has  strategies  in place to ensure  compliance
with any requirements currently in effect.

There are a number of  unresolved  issues in relation  to Canadian  Federal and
Provincial  GHG  regulatory  requirements.  Key  among  them is an  appropriate
facility   emission   threshold,   availability   and  duration  of  compliance
mechanisms, and resolution of federal/provincial  harmonization agreements. The
Company  continues  to pursue  GHG  emission  reduction  initiatives  including
solution gas conservation, CO2 capture and sequestration in oil sands tailings,
CO2  capture  and  storage in  association  with  enhanced  oil  recovery,  and
participation  in an industry  initiative to promote an integrated  CO2 capture
and storage network.

The  additional  requirements  of enacted or proposed  GHG  legislation  on the
Company's operations will 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.

Air  pollutant  standards  and  guidelines  are being  developed  federally and
provincially and the Company is participating in these discussions. Ambient air
quality  and sector  based  reductions  in air  emissions  are being  reviewed.
Through  participation  of the  Company  and the  industry  with  stakeholders,
guidelines  have been  developed  that adopt a  structured  process to emission
reductions that is commensurate with technological  development and operational
requirements.

CRITICAL ACCOUNTING ESTIMATES

The  preparation  of  financial   statements   requires  the  Company  to  make
judgements,  assumptions  and estimates in the  application of GAAP that have a
significant  impact on the  financial  results of the Company.  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 a
gain or loss except where such dispositions result in a change in the depletion
rate  of the  specific  cost  centre  of  20% or  more.  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.

                                                                             34
<PAGE>

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 2007, 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,  estimated 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 either 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.

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.

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 are  capitalized  as part of the cost of
associated  capital assets and are amortized to expense through  depletion over
the life of the asset.  The fair value of the 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 6.6%. 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 and the Horizon Project  upgrader and related  infrastructure)
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  between 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 a complex
process that  requires  management  to interpret  frequently  changing laws and
regulations (e.g.  changing income tax rates) and make certain  judgements with
respect to the  application  of tax law,  estimating  the  timing of  temporary
difference  reversals,  and estimating the  realizability of tax assets.  These
interpretations  and  judgements  impact  the  current  and  future  income tax
provisions, future income tax assets and liabilities and net earnings.


                                                                             35
<PAGE>

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.

Effective  January 1, 2007, the Company  adopted the new  accounting  standards
relating to the  accounting for and  disclosure of financial  instruments.  The
effects of adopting these standards on the Company's  opening balance sheet are
discussed in further detail in the "Risk Management Activities" section of this
MD&A. All  derivative  financial  instruments  are recognized at estimated fair
value  on the  consolidated  balance  sheet at each  balance  sheet  date.  The
estimated fair value of derivative  instruments  has been  determined  based on
appropriate  internal valuation  methodologies  and/or 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  these
differences may be material.

PURCHASE PRICE ALLOCATIONS

The  purchase  prices  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.

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,
2007,  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, 2007, 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 2007 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.


                                                                             36
<PAGE>

NEW ACCOUNTING STANDARDS

Effective  January 1, 2008,  the  Company  will adopt the  following  three new
accounting standards issued by the CICA:

CAPITAL DISCLOSURES
   o    Section  1535 - "Capital  Disclosures"  requires  entities  to disclose
        their objectives,  policies and processes for managing capital, as well
        as  quantitative  data about  capital.  The section  also  requires the
        disclosure  of  any   externally-imposed   capital   requirements   and
        compliance  with  those  requirements.  The  section  does  not  define
        capital.  The section affects  disclosures only and will not impact the
        Company's accounting for capital.

INVENTORIES
   o    Section 3031 - "Inventories"  replaces Section 3030 - "Inventories" and
        establishes  new standards for the  measurement  of cost of inventories
        and expands disclosure  requirements for inventories.  Adoption of this
        standard is not  anticipated to have a material impact on the Company's
        financial statements.

FINANCIAL INSTRUMENTS
   o    Section 3862 - "Financial  Instruments -  Disclosure"  and Section 3863
        "Financial   Instruments  -   Presentation"   replace  Section  3861  -
        "Financial  Instruments - Disclosure  and  Presentation".  Section 3862
        enhances   disclosure   requirements   concerning  risks  and  requires
        disclosures of quantitative and qualitative disclosures about exposures
        to risks  arising  from  financial  instruments.  Section  3863 carries
        forward the  presentation  requirements  from Section  3861  unchanged.
        These  standards  affect  disclosures  only  and will  not  impact  the
        Company's accounting for financial instruments.

In  addition,  the  following  standard  was  issued  during  2008  and will be
effective for the  Company's  year  beginning on January 1, 2009,  with earlier
adoption permitted:

GOODWILL AND INTANGIBLE ASSETS
   o    Section 3064 - "Goodwill and Intangible Assets" replaces Section 3062 -
        "Goodwill and Other Intangible Assets" and Section 3450 - "Research and
        Development  Costs." In addition,  EIC-27 - "Revenue  and  Expenditures
        during the Pre-Operating  Period" has been withdrawn.  The new standard
        addresses  when an  internally  generated  intangible  asset  meets the
        definition  of an asset.  Adoption of the new  standard  may impact the
        Company's  capitalization  of certain costs during the  development and
        start-up of large development projects.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

The CICA has  confirmed  that  Canadian  GAAP  will be  replaced  in full  with
International Financial Reporting Standards as promulgated by the International
Accounting Standards Board effective January 1, 2011.


                                                                             37
<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
create shareholder value. Annual budgets are developed,  scrutinized throughout
the year and revised if necessary in the context of targeted  financial ratios,
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 2008 to average between 316,000 bbl/d and 366,000
bbl/d of crude  oil and NGLs and  between  1,429  mmcf/d  and  1,513  mmcf/d of
natural gas.

The forecasted  capital  expenditures  in 2008 are currently  expected to be as
follows:

<TABLE>
($ millions)                                                            2008 Forecast
======================================================================================
<S>                                                              <C>
CONVENTIONAL CRUDE OIL AND NATURAL GAS
    North America natural gas                                    $                617
    North America crude oil and NGLs                                            1,075
    North Sea                                                                     231
    Offshore West Africa                                                          458
    Property acquisitions, dispositions and midstream                             390
--------------------------------------------------------------------------------------
                                                                 $              2,771
--------------------------------------------------------------------------------------
HORIZON PROJECT
    Phase 1 - Construction (1)                                   $      1,750 - 1,950
    Phase 1 - Operating inventory and capital inventory                           109
    Phase 1 - Commissioning costs                                                 184
    Phase 2/3 - Tranche 2                                                         439
    Sustaining costs                                                               19
    Capitalized interest and other costs                                          381
--------------------------------------------------------------------------------------
                                                                 $      2,882 - 3,082
--------------------------------------------------------------------------------------
TOTAL                                                            $      5,653 - 5,853
======================================================================================
</TABLE>
(1)  REVISED FORECASTED CAPITAL EXPENDITURES.

NORTH AMERICA NATURAL GAS

The 2008 North  America  natural gas  drilling  program is  highlighted  by the
continued high-grading of the Company's natural gas asset base as follows:

<TABLE>
(Number of wells)                                                       2008 Forecast
======================================================================================
<S>                                                                     <C>
Coal bed methane and shallow natural gas                                          161
Conventional natural gas                                                          104
Cardium natural gas                                                                14
Deep natural gas                                                                   32
Foothills natural gas                                                               3
--------------------------------------------------------------------------------------
Total                                                                             314
======================================================================================
</TABLE>

The Company has reduced 2008 natural gas drilling in Alberta due to the
anticipated future impact of royalty changes effective 2009.

                                                                             38
<PAGE>

NORTH AMERICA CRUDE OIL AND NGLS

The 2008 North America crude oil drilling  program is  highlighted by continued
development  of the  Primrose  thermal  projects,  Pelican  Lake,  and a strong
conventional primary heavy program, as follows:

<TABLE>
(Number of wells)                                                       2008 Forecast
======================================================================================
<S>                                                                     <C>
Conventional primary heavy crude oil                                              311
Thermal heavy crude oil                                                            32
Light crude oil                                                                    78
Pelican Lake crude oil                                                            105
--------------------------------------------------------------------------------------
Total                                                                             526
======================================================================================
</TABLE>

HORIZON PROJECT

The Horizon  Project is targeting first crude oil in the third quarter of 2008.
Phase 1 construction  capital is budgeted to be  approximately  $1.7 billion to
$1.9 billion in 2008,  representing a cost to completion  forecast range of 25%
to 28% over the original $6.8 billion estimate.

NORTH SEA

The 2008 capital  forecast  for the North Sea includes  drilling 4 net platform
wells while continuing the successful workover and recompletion program.

OFFSHORE WEST AFRICA

The 2008 capital  forecast for Offshore West Africa  includes  re-completing  2
wells at Baobab and targeted first oil at Olowi in late 2008.

SENSITIVITY ANALYSIS

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 2007,  excluding  mark-to-market  gains (losses) on risk  management
activities,  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>
                                                            CASH FLOW
                                           CASH FLOW             FROM                             NET
                                                FROM       OPERATIONS             NET        EARNINGS
                                          OPERATIONS      (PER COMMON        EARNINGS     (PER COMMON
                                        ($ MILLIONS)    SHARE, BASIC)    ($ MILLIONS)   SHARE, BASIC)
======================================================================================================
<S>                                     <C>            <C>               <C>             <C>
PRICE CHANGES
Crude oil - WTI US$1.00/bbl (1)
   Excluding financial derivatives      $         96   $         0.18    $         70    $       0.13
   Including financial derivatives      $         21   $         0.04    $         17    $       0.03
Natural gas - AECO C$0.10/mcf (1)
   Excluding financial derivatives      $         41   $         0.08    $         29    $       0.05
   Including financial derivatives      $         33   $         0.06    $         23    $       0.04
VOLUME CHANGES
Crude oil - 10,000 bbl/d                $        132   $         0.25    $         70    $       0.13
Natural gas - 10 mmcf/d                 $         16   $         0.03    $          6    $       0.01
FOREIGN CURRENCY RATE CHANGE
$0.01 change in US$ (1)
Including financial derivatives         $    73 - 74   $  0.13 - 0.14    $    31 - 32    $       0.06
INTEREST RATE CHANGE - 1%               $         38   $         0.07    $         38    $       0.07
======================================================================================================
</TABLE>
(1)  FOR DETAILS OF  FINANCIAL  INSTRUMENTS  IN PLACE,  REFER TO NOTE 12 TO THE
     COMPANY'S AUDITED ANNUAL CONSOLIDATED  FINANCIAL STATEMENTS AS AT DECEMBER
     31, 2007.

                                                                             39
<PAGE>

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

                                 Q1          Q2          Q3          Q4        2007        2006        2005
============================================================================================================
<S>                         <C>         <C>         <C>         <C>         <C>         <C>         <C>
CRUDE OIL AND NGLS
(BBL/D)
North America               237,489     240,420     252,095     256,843     246,779     235,253     221,669
North Sea                    61,869      57,286      52,013      52,709      55,933      60,056      68,593
Offshore West
  Africa                     27,643      29,788      28,954      27,688      28,520      36,689      22,906
------------------------------------------------------------------------------------------------------------
Total                       327,001     327,494     333,062     337,240     331,232     331,998     313,168
------------------------------------------------------------------------------------------------------------
NATURAL GAS (MMCF/D)
North America                 1,694       1,696       1,622       1,562       1,643       1,468       1,416
North Sea                        15          15          10          13          13          15          19
Offshore West
  Africa                          8          11          15          14          12           9           4
------------------------------------------------------------------------------------------------------------
Total                         1,717       1,722       1,647       1,589       1,668       1,492       1,439
------------------------------------------------------------------------------------------------------------
BARRELS OF OIL
EQUIVALENT (BOE/D)
North America               519,700     523,037     522,427     517,101     520,564     479,891     457,695
North Sea                    64,370      59,758      53,597      54,825      58,099      62,558      71,651
Offshore West
  Africa                     29,044      31,666      31,460      29,982      30,543      38,275      23,614
------------------------------------------------------------------------------------------------------------
Total                       613,114     614,461     607,484     601,908     609,206     580,724     552,960
============================================================================================================

PER UNIT RESULTS (1)

                                 Q1          Q2          Q3          Q4        2007        2006        2005
============================================================================================================
CRUDE OIL AND NGLS
($/BBL)
Sales price (2)           $   51.71   $   53.74   $   58.10   $   58.03   $   55.45   $   53.65   $   46.86
Royalties                      4.92        5.46        6.65        6.66        5.94        4.48        3.97
Production
  expense                     13.81       15.01       13.13       11.53       13.34       12.29       11.17
------------------------------------------------------------------------------------------------------------
Netback                   $   32.98   $   33.27   $   38.32   $   39.84   $   36.17   $   36.88   $   31.72
------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/MCF)
Sales price (2)           $    7.74   $    7.44   $    5.87   $    6.28   $    6.85   $    6.72   $    8.57
Royalties                      1.48        1.10        0.89        0.94        1.11        1.29        1.75
Production
  expense                      0.97        0.89        0.88        0.91        0.91        0.82        0.73
------------------------------------------------------------------------------------------------------------
Netback                   $    5.29   $    5.45   $    4.10   $    4.43   $    4.83   $    4.61   $    6.09
------------------------------------------------------------------------------------------------------------
BARRELS OF OIL
EQUIVALENT ($/BOE)
Sales price (2)           $   49.32   $   49.70   $   47.96   $   49.23   $   49.05   $   47.92   $   48.77
Royalties                      6.76        5.99        6.07        6.21        6.26        5.89        6.82
Production
  expense                     10.10       10.44        9.62        8.85        9.75        9.14        8.21
------------------------------------------------------------------------------------------------------------
Netback                   $   32.46   $   33.27   $   32.27   $   34.17   $   33.04   $   32.89   $   33.74
============================================================================================================
</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.

                                                                             40
<PAGE>

<TABLE>
<CAPTION>
NETBACK ANALYSIS

($/boe) (1)                                                                            2007           2006         2005
=========================================================================================================================
<S>                                                                               <C>           <C>          <C>
Sales price (2)                                                                   $    49.05    $    47.92   $    48.77
Royalties                                                                               6.26          5.89         6.82
Production expense (3)                                                                  9.75          9.14         8.21
-------------------------------------------------------------------------------------------------------------------------
NETBACK                                                                                33.04         32.89        33.74
Midstream contribution (3)                                                             (0.23)        (0.23)       (0.26)
Administration                                                                          0.93          0.85         0.75
Interest, net                                                                           1.24          0.66         0.74
Realized risk management loss                                                           0.73          6.27         5.13
Realized foreign exchange loss (gain)                                                   0.24         (0.06)       (0.15)
Taxes other than income tax - current                                                   0.54          1.04         1.01
Current income tax - North America                                                      0.43          0.68         0.50
Current income tax - North Sea                                                          0.95          0.14         0.77
Current income tax - Offshore West Africa                                               0.33          0.23         0.17
-------------------------------------------------------------------------------------------------------------------------
CASH FLOW                                                                         $    27.88    $    23.31   $    25.08
=========================================================================================================================
</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.
(3)  EXCLUDING INTER-SEGMENT ELIMINATIONS.


<TABLE>
<CAPTION>
TRADING AND SHARE STATISTICS

                                                 Q1           Q2            Q3            Q4          2007          2006
=========================================================================================================================
<S>                                     <C>           <C>          <C>           <C>           <C>           <C>
TSX - C$
Trading Volume (thousands)                  117,164       94,089       100,950       116,831       429,034       508,935
Share Price ($/share)
High                                    $     65.50   $    74.99   $     80.02   $     79.91   $     80.02   $     73.91
Low                                     $     52.45   $    63.71   $     65.43   $     64.24   $     52.45   $     45.49
Close                                   $     63.75   $    70.78   $     75.56   $     72.58   $     72.58   $     62.15
Market capitalization as at
   December 31 ($ millions)                                                                    $    39,174   $    33,431
Shares outstanding
  (thousands)                                                                                      539,729       537,903
-------------------------------------------------------------------------------------------------------------------------
NYSE - US$
Trading Volume (thousands)                  128,543       93,086       118,315       146,322       486,266       401,909
Share Price ($/share)
High                                    $     56.62   $    69.97   $     78.90   $     87.17   $     87.17   $     64.38
Low                                     $     44.56   $    55.07   $     60.70   $     63.52   $     44.56   $     40.29
Close                                   $     55.19   $    66.35   $     75.75   $     73.14   $     73.14   $     53.23
Market Capitalization as at
   December 31($ millions)                                                                     $    39,476   $    28,633
Shares outstanding
  (thousands)                                                                                      539,729       537,903
=========================================================================================================================
</TABLE>


                                                                             41

<PAGE>


                              ADDITIONAL DISCLOSURE

DISCLOSURE CONTROLS AND PROCEDURES


As of the end of the  registrant's  fiscal  year ended  December  31,  2007,  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  principal  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 ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING

The required disclosure is included in the "Management's  Assessment of Internal
Control Over Financial  Reporting" that accompanies  Canadian  Natural's audited
consolidated  financial  statements for the fiscal year ended December 31, 2007,
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
Canadian Natural's audited consolidated financial statements for the fiscal year
ended December 31, 2007, 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,  2007,  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.

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

<PAGE>

trading in Canadian  Natural's  shares and is  designed to ensure that  Canadian
Natural's business is consistently conducted in a 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.  In 2007 the  Nominating and
Corporate  Governance  Committee reviewed and recommended to the Board revisions
relating to  clarification  on insider  trading,  communication  and disclosure,
communication  with electronic  mediums,  Staff  participating in government and
political  activities,  and Canadian Natural's Human Rights Statement which were
subsequently approved by the Board of Directors.

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, 2007 and  December  31,  2006,  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 $2,729,315 for 2007 and were $3,126,287 for 2006.

AUDIT-RELATED FEES

The  aggregate  fees  billed for each of the last two fiscal  years of  Canadian
Natural,  ending  December 31, 2007 and December  31,  2006,  for  audit-related
services by PwC including debt covenant compliance and Crown Royalty Statements,
were  $164,000 for 2007 and were  $121,353 for 2006.  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, 2007 and December  31,  2006,  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
2007 were $154,459 for 2007 and were $134,025 for 2006. 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, 2007 and December 31, 2006 for other services were
$9,440 for 2007 and were $9,516 for 2006.  The fees for other  services  paid in
2007 related to accessing resource materials through PwC's accounting literature
library. Canadian Natural's Audit Committee approved all of the noted services.

<PAGE>

AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES

The Audit  Committee's  duties  and  responsibilities  include  the  review  and
approval of fees to be paid to the independent auditors, scope and timing of the
audit and other related services rendered by the independent auditors. The Audit
Committee also reviews and approves the independent auditor's annual audit plan,
including scope,  staffing,  locations and reliance upon management and internal
audit department prior to the commencement of the audit and reviews and approves
proposed non-audit services to be provided by the independent  auditors,  except
those non-audit  services  prohibited by legislation.  Canadian  Natural did not
rely on the de minimis exemption provided by paragraph (c)(7)(i)(c) of Rule 2.01
of Regulation S-X in 2007.

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 60 of Canadian Natural's Management's  Discussion
and Analysis of Financial  Condition  and Results of  Operations  for the fiscal
year ended December 31, 2007, filed herewith, under the caption "Commitments and
Off Balance Sheet Arrangements".

CONTRACTUAL OBLIGATIONS

In the normal  course of  business,  Canadian  Natural has entered  into various
commitments that will have an impact on its future operations. These commitments
primarily  relate to debt  repayments;  operating  leases  relating  to Floating
Production,  Storage and Offsite  vessels  ("FPSOs"),  drilling  rigs and office
space; and firm commitments for gathering, processing and transmission services;
as well as expenditures relating to asset retirement  obligations ("ARO"). As at
December 31, 2007, no entities were consolidated under CICA Handbook  Accounting
Guideline 15, "Consolidation of Variable Interest Entities". The following table
summarizes Canadian Natural's commitments as at December 31, 2007:

<TABLE>

($ millions)                          2008          2009          2010      2011         2012        Thereafter
-----------------------------------------------------------------------------------------------------------------
<S>                                  <C>           <C>           <C>        <C>          <C>         <C>

Product transportation and pipeline   $    232     $      151    $   137    $    109     $     91    $        972
Offshore equipment operating lease    $    114     $      129    $   113    $    111     $     90    $        387
   (1)
Offshore drilling (2) (3)             $    267     $      185    $    39    $      -     $      -    $          -
Asset retirement obligations (4)      $     33     $        4    $     5    $      4     $      4    $      4,376
Long-term debt (5)                    $     39     $    2,361    $   400    $    395     $    346    $      5,098
Interest expense (6)                  $    612     $      590    $   487    $    465     $    374    $      4,338
Office lease                          $     26     $       28    $    28    $     22     $      3    $          -
                                      $    166     $      173         25    $      4     $      -    $          -
Electricity and other
=================================================================================================================
</TABLE>

(1)   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.  DURING THE
      INITIAL TERM,  THE TOTAL ANNUAL  PAYMENTS FOR THE GABON FPSO ARE ESTIMATED
      TO BE US$50 MILLION.

(2)   DURING  2007,  CANADIAN  NATURAL  ENTERED  INTO A ONE-YEAR  AGREEMENT  FOR
      OFFSHORE  DRILLING  SERVICES RELATED TO THE BAOBAB FIELD IN COTE D'IVOIRE,
      OFFSHORE  WEST  AFRICA.  THE  AGREEMENT  IS SCHEDULED TO COMMENCE IN 2008,
      SUBJECT TO RIG  AVAILABILITY.  ESTIMATED TOTAL PAYMENTS OF US$100 MILLION,
      AFTER JOINT VENTURE  RECOVERIES,  HAVE BEEN INCLUDED IN THIS TABLE FOR THE
      PERIOD 2008 - 2009.

(3)   DURING 2007, CANADIAN NATURAL AWARDED CONTRACTS FOR A DRILLING RIG AND FOR
      THE  CONSTRUCTION  OF  WELLHEAD  TOWERS  IN  CONNECTION  WITH THE  PLANNED
      OFFSHORE  DEVELOPMENT  IN GABON,  OFFSHORE  WEST AFRICA.  ESTIMATED  TOTAL
      PAYMENTS OF US$393 MILLION HAVE BEEN INCLUDED IN THIS TABLE FOR THE PERIOD
      2008 - 2010.

(4)   AMOUNTS  REPRESENT   MANAGEMENT'S  ESTIMATE  OF  THE  FUTURE  UNDISCOUNTED
      PAYMENTS  TO SETTLE ARO RELATED TO RESOURCE  PROPERTIES,  FACILITIES,  AND
      PRODUCTION PLATFORMS,  BASED ON CURRENT LEGISLATION AND INDUSTRY OPERATING
      PRACTICES.  AMOUNTS  DISCLOSED  FOR THE PERIOD 2008 - 2012  REPRESENT  THE
      MINIMUM   REQUIRED   EXPENDITURES  TO  MEET  THESE   OBLIGATIONS.   ACTUAL
      EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED THESE MINIMUM AMOUNTS.

<PAGE>

(5)   THE  LONG-TERM  DEBT  REPRESENTS  PRINCIPAL  REPAYMENTS  ONLY AND DOES NOT
      REFLECT FAIR VALUE  ADJUSTMENTS,  ORIGINAL ISSUE  DISCOUNTS OR TRANSACTION
      COSTS.  NO DEBT  REPAYMENTS  ARE REFLECTED FOR $2,366 MILLION OF REVOLVING
      BANK CREDIT FACILITIES DUE TO THE EXTENDABLE NATURE OF THE FACILITIES.

(6)   INTEREST   EXPENSE   AMOUNTS   REPRESENT  THE  SCHEDULED   FIXED-RATE  AND
      VARIABLE-RATE  CASH  PAYMENTS  RELATED  TO  LONG-TERM  DEBT.  INTEREST  ON
      VARIABLE-RATE  LONG-TERM DEBT WAS ESTIMATED BASED UPON PREVAILING INTEREST
      RATES AS OF DECEMBER 31, 2007.

In  addition to the  amounts  disclosed  above,  Canadian  Natural has  budgeted
construction  costs of  approximately  $1.7  billion  to $1.9  billion  for 2008
related to the planned completion of Phase 1 of the Horizon Oil Sands Project.

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,  2007,  which  forms  part of this Form  40-F.  The Annual
Information  Form is also available  through the System for Electronic  Document
and Analysis and Retrieval (SEDAR) at WWW.SEDAR.COM.

<PAGE>

                  UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

UNDERTAKING

Canadian  Natural  undertakes  to make  available,  in person  or by  telephone,
representatives  to respond to inquiries  made by the Commission  staff,  and to
furnish promptly,  when requested to do so by the Commission staff,  information
relating to: the securities  registered pursuant to Form 40-F; the securities in
relation to which the  obligation  to file an annual report on Form 40-F arises;
or transactions in said securities.

CONSENT TO SERVICE OF PROCESS

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.

<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 27th day of March, 2008.

                                     CANADIAN NATURAL RESOURCES LIMITED


                                     By:   /S/ STEVE W. LAUT
                                          -------------------------
                                          Name:  Steve W. Laut
                                          Title: President and Chief
                                                 Operating Officer

<PAGE>


Documents filed as part of this report:

                                  EXHIBIT INDEX

EXHIBIT NO. DESCRIPTION


1.   Supplementary  Oil & Gas Information for the fiscal year ended December 31,
     2007.

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   Ltd.,   independent   petroleum
     engineering consultants.