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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, 2008  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.
          540,991,318 COMMON SHARES OUTSTANDING AS OF DECEMBER 31, 2008

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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.

All dollar  amounts in this Annual Report on Form 40-F are expressed in Canadian
dollars.  As of March 26,  2009,  the noon buying rate for  Canadian  Dollars as
expressed by the Bank of Canada was US$0.8110 equals C$ 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, 2008.

          B. AUDITED ANNUAL FINANCIAL STATEMENTS

          Canadian Natural's audited  consolidated  financial statements for the
          years ended December 31, 2008 and 2007, 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 18 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, 2008.

SUPPLEMENTARY OIL & GAS INFORMATION

For Canadian  Natural's  Supplementary  Oil & Gas Information for the year ended
December 31, 2008, see Exhibit 1 of this Annual Report on Form 40-F.


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<PAGE>


               [CANADIAN NATURAL RESOURCES LIMITED LOGO OMITTED]













                            ANNUAL INFORMATION FORM

                      FOR THE YEAR ENDED DECEMBER 31, 2008

                                 MARCH 25, 2009


<PAGE>

                               TABLE OF CONTENTS

DEFINITIONS....................................................................4

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS..............................6

RISK FACTORS...................................................................8

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

REGULATORY MATTERS............................................................13

THE COMPANY...................................................................14

GENERAL DEVELOPMENT OF THE BUSINESS...........................................15

DESCRIPTION OF THE BUSINESS...................................................17

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

         Daily Production and Infrastructure..................................18
         Developed and Undeveloped Acreage....................................19
         Drilling Activity....................................................20
         Producing Crude Oil and Natural Gas Wells............................23
         Northeast British Columbia...........................................23
         Northwest Alberta....................................................24
         Northern Plains......................................................24
         Southern Plains and Southeast Saskatchewan...........................26
         Horizon Oil Sands Project............................................27
         United Kingdom North Sea.............................................33
         Offshore West Africa.................................................34
         Cote d'Ivoire........................................................34
         Gabon................................................................35

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

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

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

E.   NET CAPITAL EXPENDITURES.................................................47

F.   DEVELOPED AND UNDEVELOPED ACREAGE........................................49

SELECTED FINANCIAL INFORMATION................................................49

CAPITAL STRUCTURE.............................................................50

MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES......................51

DIVIDEND HISTORY..............................................................52

TRANSFER AGENTS AND REGISTRAR.................................................52

DIRECTORS AND OFFICERS........................................................53

Canadian Natural Resources Limited                                             2

<PAGE>

CONFLICTS OF INTEREST.........................................................58

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS....................58

AUDIT COMMITTEE INFORMATION...................................................59

LEGAL PROCEEDINGS.............................................................60

MATERIAL CONTRACTS............................................................60

INTERESTS OF EXPERTS..........................................................60

ADDITIONAL INFORMATION........................................................60

SCHEDULE "A" REPORT ON RESERVES DATA..........................................61

SCHEDULE "B" REPORT OF MANAGEMENT AND DIRECTORS...............................64

SCHEDULE "C" CHARTER OF THE AUDIT COMMITTEE...................................66

Canadian Natural Resources Limited                                             3


3                                             Canadian Natural Resources Limited


<PAGE>


DEFINITIONS

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

"API" means the specific gravity measured in degrees on the American  Petroleum
Institute scale

"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 GAAP" means Generally Accepted Accounting Principles in Canada

"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/medium, primary heavy, and thermal heavy crude oil, natural gas, coal bed
methane and NGLs  reserves.  It does not include the Company's oil sands mining
reserves

"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


Canadian Natural Resources Limited                                             4


<PAGE>

"MMCF" means one million cubic feet

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

"NGLS" means natural gas liquids

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

"NET ASSET  VALUE" means the  discounted  value of  conventional  crude oil and
natural gas reserves plus the value of undeveloped land, less net debt

"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

"UK" means the United Kingdom

"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


5                                             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.  Disclosure  related to expected
future  commodity  pricing,  production  volumes,  royalties,  operating costs,
capital  expenditures,  and other guidance  provided  throughout  this document
constitute forward looking statements. Disclosure of plans relating to existing
and future  developments,  including  but not limited to the  Horizon  Project,
Primrose  East,  Pelican Lake,  Gabon  Offshore West Africa,  and the Kirby Oil
Sands Project also constitute forward-looking  statements. This forward-looking
information  is  based on  annual  budgets  and  multi-year  forecasts,  and is
reviewed  and  revised  throughout  the year if  necessary  in the  context  of
targeted financial ratios,  project returns,  product pricing  expectations and
balance in project risk and time horizons.  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
assurances  that the plans,  initiatives  or  expectations  upon which they are
based will occur.

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.

The forward-looking statements are based on current expectations, estimates and
projections  about 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 dependent  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                                             6

<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,  2008,  the  Company  retained  a  qualified
independent  reserves  evaluator,  Sproule Associates Limited  ("Sproule"),  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
reserves include all of the Company's light/medium,  primary heavy, and thermal
heavy crude oil,  natural gas, coal bed methane and NGLs reserves.  They do not
include the Company's oil sands mining  reserves.  The Company has been granted
an exemption  from certain of the  provisions of 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   conventional   crude  oil,   NGLs,  and  natural  gas  reserve
reconciliations net of royalties in adherence to SEC requirements.

For the year  ended  December  31,  2008,  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 and in its
annual Form 40-F  filing  with the SEC.  The Company has elected to provide the
net present  value of these same  conventional  proved  reserves as well as its
conventional  proved and probable  reserves and the net present  value of these
reserves under the same  parameters as additional  voluntary  information.  Net
present values of  conventional  reserves are based upon  discounted cash flows
prior to the  consideration  of income  taxes and  existing  asset  abandonment
liabilities.  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  additional  voluntary
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 both Sproule 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.

7                                             Canadian Natural Resources Limited

<PAGE>

SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES

This Annual Information Form includes references to financial measures commonly
used in the  crude  oil and  natural  gas  industry,  such  as cash  flow  from
operations,  adjusted net earnings from  operations and net asset value.  These
financial measures are not defined by generally accepted accounting  principles
("GAAP")  and  therefore  are  referred to as non-GAAP  measures.  The non-GAAP
measures  used  by the  Company  may  not be  comparable  to  similar  measures
presented  by other  companies.  The Company  uses these  non-GAAP  measures to
evaluate its  performance.  The non-GAAP  measures  should not be considered an
alternative  to  or  more  meaningful  than  net  earnings,  as  determined  in
accordance  with Canadian GAAP, as an indication of the Company's  performance.
The non-GAAP  measures adjusted net earnings from operations and cash flow from
operations  are  reconciled to net earnings,  as determined in accordance  with
Canadian GAAP in the "Financial Highlights" section the Company's MD&A which is
incorporated by reference into this document.

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.  Significant
declines  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,  industrial demand,
prices of alternate sources of energy, and the import of 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,  including but not limited to the Horizon
Project, Primrose East, Pelican Lake, Gabon Offshore West Africa, and the Kirby
Oil Sands Project, or curtailment in production at some properties or result in
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 forecast
prices  decline,  the carrying value of property,  plant and equipment could be
subject to downward revisions, and net earnings could be adversely affected.

Approximately  28% of the Company's 2008  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 quality  difference  and the mix of product  obtained in the
refining process referred to as the "quality  differential".  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  quality  differentials  are
uncertain and a significant increase in the heavy crude oil differentials could
have a material adverse effect on the Company's business.

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.


Canadian Natural Resources Limited                                             8

<PAGE>

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,
royalties,  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.

COMPLETION RISK

Canadian  Natural has a variety of exploration,  development  and  construction
projects  underway  at any given  time.  Project  delays  may result in delayed
revenue receipts and cost overruns may result in projects being uneconomic. The
Company's  ability to complete  projects is dependent  on general  business and
market  conditions  as well as other factors  beyond our control  including the
availability of skilled labour and manpower,  the availability and proximity of
pipeline capacity,  weather,  environmental and regulatory matters,  ability to
access lands, availability of drilling and other equipment, and availability of
processing capacity.

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 related  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
include  integrated oil and natural gas companies and numerous other senior oil
and natural gas companies, some of which may have financial and other resources
greater than the Company.

ACCESS TO SOURCES OF LIQUIDITY

The  ongoing  worldwide  financial  and  economic  events  have  resulted  in a
significant  tightening  of  the  availability  and  cost  of  new  sources  of
liquidity, including bank credit facilities and funds derived from debt capital
markets. The ability of the Company to fund current and future capital projects
and carry out our business plan is dependent on our ability to raise capital in
a timely manner under favourable terms and conditions.

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.


9                                             Canadian Natural Resources Limited

<PAGE>

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,  including any new
regulations  the US may impose to limit  purchases  of crude oil  towards  less
energy  intensive  sources,  may have an adverse effect on the Company's future
net earnings and cash flow from operations.

GREENHOUSE GAS AND OTHER AIR EMISSIONS

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   emissions   threshold,   availability  and  duration  of  compliance
mechanisms and resolution of federal/provincial  harmonization agreements.  The
Company  continues  to pursue GHG  emissions  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.

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 emissions
reductions that is commensurate with technological  development and operational
requirements.

In  Canada,  the  Federal  government  has  indicated  its  intent  to  develop
regulations  that  would  be in  effect  in  2010  to  address  industrial  GHG
emissions;  however future Federal  regulatory  requirements  currently  remain
uncertain.  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 crude oil  facilities  and the Hays sour
natural gas plant, fall under the regulations. In British Columbia, a $10/tonne
carbon tax was implemented  July 1, 2008,  applying to combustion of all fossil
fuels,  increasing  to  $30/tonne  by  July  2012.  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 compliance costs to the
Company  relating  to the  above  regulations  for 2008 are  approximately  $24
million.

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.

HEDGING ACTIVITIES

In response to fluctuations in commodity prices, foreign exchange, and interest
rates,  the Company may utilize various  derivative  financial  instruments and
physical  sales  contracts  to manage  its  exposure  under a  defined  hedging
program.  The terms of these  arrangements may limit the benefit to the Company
of  favourable  changes  in  these  factors  and may  result  in  financial  or
opportunity  loss due to paying  royalties on a reference price which is higher
than the hedged price and counterparty credit risk.

OPERATIONAL RISK

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  and  maintains  a
comprehensive  insurance  program,   however,   Canadian  Natural's  liability,
property  and business  interruption  insurance  may not and possibly  will not
provide adequate coverage in all circumstances.


Canadian Natural Resources Limited                                            10

<PAGE>

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 arrangement for the exploration and development of crude oil
and natural gas properties in Canada and the UK sector of the North Sea differs
distinctly  from its  arrangement  for the exploration and development in other
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 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.

OTHER BUSINESS RISKS

Other business risks relate to the dependency on third party operators for some
of the Company's  assets,  timing and success of  integrating  the business and
operations of acquired companies,  credit risk related to non-payment for sales
contracts  or   non-performance   by  counterparties  to  contracts,   risk  of
litigation,  regulatory  issues,  and risk of increases in government taxes and
changes to the royalty regime. The majority of the Company's assets are held in
one or more corporate  subsidiaries or partnerships.  The results of operations
and ability to service indebtedness,  including debt securities,  are dependent
upon the results of operations of these  subsidiaries and partnerships  and, in
the case of  subsidiaries,  the  payment of funds 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  subsidiary  or
partnership,  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.

ENVIRONMENTAL MATTERS

The  Company  carries  out its  activities  in  compliance  with  all  relevant
regional,  national  and  international  regulations  and  industry  standards.
Environmental  specialists  in Canada and the UK 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.  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  spills 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 environmental 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


11                                            Canadian Natural Resources Limited

<PAGE>

environmental  impacts.  The Company has also established  stringent  operating
standards in four areas:  implementing  cost effective ways of reducing GHG per
unit of production;  exercising care with respect to all waste produced through
effective waste management plans; using water-based,  environmentally  friendly
drilling muds whenever possible;  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 programs.  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.

The Company is concurrently  participating  with certain industry groups who in
turn are working with  legislators  and regulators to develop and implement new
GHG  emissions  laws and  regulations.  Internally,  the Company is pursuing an
integrated  emissions  reduction  strategy.  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.

The  Company  remains  focused  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.
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 2008 the Company  completed  approximately  101 gas
conservation projects, resulting in a reduction of 835,000 tonnes/year of CO2e.
Over the past five years the Company has spent over $89 million to conserve the
equivalent  of over 6.3 million  tonnes of CO2e.  The Company also monitors the
performance of its compressor fleet which is continually modified and optimized
for maximum efficiency.  These programs also influence and direct the Company's
plans for new projects and  facilities.  The Horizon  Project has  incorporated
advancements in technology to further reduce 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. Projects
to reduce GHG emissions  included a flare recovery  pilot study,  change out of
flare purge valves and introduction of water washing on turbines.  The Produced
Water  Re-injection  on Ninian  Central was made permanent in 2008 during which
time approximately 1.36 million cubic meters of produced water were re-injected
to the reservoir.  This resulted in  approximately 18 tonnes of oil in produced
water not being discharged to sea, a reduction of approximately 6%.

For  2008,  the  Company's  capital  expenditures   included  $38  million  for
abandonment expenditures (2007 - $71 million).

The Company's estimated undiscounted ARO at December 31, 2008 was as follows:

                                                           -----------
Estimated ARO, undiscounted ($millions)                    |    2008  |    2007
-----------------------------------------------------------|----------|---------
North America                                              | $ 3,165  | $ 3,038
North Sea                                                  |   1,216  |   1,286
Offshore West Africa                                       |      93  |     102
-----------------------------------------------------------|----------|---------
                                                           |   4,474  |   4,426
North Sea PRT recovery                                     |    (529) |    (555)
-----------------------------------------------------------|----------|---------
                                                           | $ 3,945  | $ 3,871
===========================================================|==========|=========

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
estimated to result in a PRT recovery of $529 million (2007 - $555 million), as
abandonment  costs are an  allowable  deduction in  determining  PRT and may be


Canadian Natural Resources Limited                                            12

<PAGE>

carried back to reclaim PRT previously  paid. The expected PRT recovery reduces
the Company's net undiscounted  abandonment liability to $3,945 million (2007 -
$3,871 million).

REGULATORY MATTERS

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

CANADA

The  petroleum  and natural gas industry in Canada  operates  under  government
legislation and regulations, which govern exploration, development, production,
refining, marketing, 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 are
held under freehold (private ownership) lands.

Conventional  petroleum  and  natural  gas leases  issued by the  provinces  of
Alberta,  Saskatchewan and Manitoba have a primary term from two to five years,
and British Columbia leases/licences  presently have a term of up to ten years.
Those  portions of the leases that are producing or are capable of producing at
the end of the primary  term will  "continue"  for the  productive  life of the
lease.

The   exploration   licences  in  the  Northwest  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 Alberta 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.

The Alberta  Government  implemented its New Royalty  Framework (NRF) effective
January 1,  2009.  The NRF  includes  a number of changes to royalty  rates for
natural gas,  conventional crude oil, and oil sands production.  Under the NRF,
royalties   payable  are  variable   according  to  commodity  prices  and  the
productivity of wells.

The NRF for  conventional  crude oil and natural gas operates  based on sliding
scales ranging up to 50% determined by commodity prices and well productivity.

Government  royalties on a significant  portion of Alberta crude oil 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  were
calculated as 1% of gross  revenues until the Company's  capital  investment in
the  applicable  project  were  fully  recovered,  at which  time  the  royalty
increased to 25% of net profit.  Effective January 1, 2009 the NRF includes 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.

In addition  to  government  royalties,  the  Company is  currently  subject to
federal  and  provincial   income  taxes  in  Canada  at  a  combined  rate  of
approximately 29% after allowable deductions.

During 2007, the Canadian  Federal  Government  enacted income tax rate changes
which  decrease the Federal  corporate  income tax rate over a five year period
from 21% in 2007, 19.5% in 2008, 19% in 2009, to 15% in 2012.


13                                            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.  There is no PRT on  profits  of  decommissioned  fields  subsequently
redeveloped, subject to certain conditions being met.

The  Company  is subject  to UK  Corporation  Tax ("CT") on its UK profits at a
current rate of 30%. PRT paid is  deductible  for CT  purposes.  An  additional
Supplementary Charge Tax ("SCT") of 20% is charged on crude oil and natural gas
profits but excludes any deduction for financing costs. The deduction for crude
oil and natural gas expenditures on capital items is generally 100% in the year
incurred.

OFFSHORE WEST AFRICA

Terms of licences,  including  royalties  and taxes  payable on  production  or
profit sharing arrangements,  vary by country and, in some cases, by concession
within each country.

Development  of the Espoir  Field in Block CI-26 and the Baobab  Field in Block
CI-40,  offshore Cote d'Ivoire,  are subject to Production  Sharing  Agreements
("PSA") that deem tax or royalty  payments to the  Government  are met from the
Government's share of profit oil. The current Corporate Income Tax rate in Cote
d'Ivoire is 25% which is applicable to non PSA income.

The Olowi Field offshore Gabon is also under the terms of a PSA which deems tax
or royalty payments to the Government are met from the Government's share of
profit oil. The current Corporate Income Tax rate is 35% which is applicable to
non PSA income.

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 November 2, 2006,  pursuant to a Purchase  and Sale  Agreement,  the Company
acquired  all of the  outstanding  shares of  Anadarko  Canada  Corporation,  a
subsidiary  of Anadarko  Petroleum  Corporation.  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.  On January 1,
2007, ACC-CNR Resources Corporation and the Company amalgamated pursuant to the
BUSINESS  CORPORATIONS ACT (Alberta) under the name Canadian Natural  Resources
Limited.


Canadian Natural Resources Limited                                            14

<PAGE>

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 and partnerships of the Company,  percentage of
voting securities owned either directly or indirectly,  and their jurisdictions
of incorporation are as follows:

<TABLE>
<CAPTION>
SUBSIDIARY                                                         JURISDICTION OF INCORPORATION        % OWNERSHIP
----------                                                         -----------------------------        -----------
<S>                                                                <C>                                  <C>
CanNat Energy Inc.                                                           Delaware                           100
CNR (ECHO) Resources Inc.                                                    Alberta                            100
CNR International (U. K.) Investments Limited                                England                            100
CNR International (U. K.) Limited                                            England                            100
CNR International Cote d'Ivoire SARL                                         Cote d'Ivoire                      100
CNR International (Olowi) Limited                                            Bahamas                            100
CNR Petro Resources Limited                                                  Alberta                            100
Horizon Construction Management Ltd.                                         Alberta                            100

PARTNERSHIP
Canadian Natural Resources Partnership                                       Alberta                            100
Canadian Natural Resources Northern Alberta Partnership                      Alberta                            100
CNR 2006 Partnership                                                         Alberta                            100
</TABLE>

In  the  ordinary  course  of  business,   Canadian  Natural  restructures  its
subsidiaries  and  partnerships  to  maintain   efficient   operations  and  to
facilitate acquisitions and divestitures.

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

GENERAL DEVELOPMENT OF THE BUSINESS - THREE YEAR HISTORY

2006

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.

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. In February
2009,  $420 million of the credit  facility was repaid reducing the facility to
$1,930 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. 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.

15                                            Canadian Natural Resources Limited

<PAGE>

2007

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.

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.

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.

2008

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.

In the third  quarter  of 2008,  the  Company  committed  120,000  bbl/d to the
Keystone  Pipeline US Gulf Coast  Expansion  for a 20 year  period,  subject to
regulatory  approval.  Concurrently  the Company  entered into a 20 year supply
agreement  with a major US refiner for  100,000  bbl/d of heavy crude oil to US
Gulf Coast refineries, contingent on the completion of the Keystone Pipeline US
Gulf Coast Expansion.

The  Company  entered  into an  agreement  in August  2005 to  obtain  pipeline
transportation  service  for  the  Horizon  Project.  The  initial  term of the
agreement is 25 years,  which  commenced on the in-service  date of November 1,
2008.  The  twinning  of the  existing  Alberta Oil Sands  Pipeline  ("AOSPL"),
resulting  in two  parallel  pipelines,  one of which is  dedicated to Canadian
Natural,  combined with the 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.  In addition
to having the option to renew the agreement for  successive 10 year terms,  the
Company has the right to request incremental  expansion of the Horizon Pipeline
based upon applicable  National Energy Board approved multi pipeline economics.
This agreement  allows the Company to gain access to major sales  pipelines out
of Edmonton for the Company's  synthetic crude oil  transportation  service for
the  Horizon  Project,  while at the same time  providing  significant  quality
benefits associated with being the only shipper on the Horizon Pipeline.

During 2008,  the Company  completed 55  transactions  in the normal  course to
acquire  additional  interests  in crude oil and  natural gas  properties.  The
aggregate net expenditure of the transactions was $381 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 $45 million.

2009

First  synthetic  crude oil production  was achieved at the Horizon  Project on
February 28, 2009. First shipment into the Horizon  Pipeline  occurred on March
18,  2009.  Capital  expenditures  are  expected to be $621 million in 2009 for
remaining Phase 1 construction,  commissioning and inventory costs, as wells as
sustaining capital costs and Tranche 2 expansion.

For 2009, the Company's overall conventional drilling activity in North America
is expected to comprise  approximately  142 natural gas wells and 465 crude oil
wells, excluding  stratigraphic and service wells. The company has reduced 2009
natural gas drilling in Alberta due to the anticipated future impact of royalty
changes  arising under the NRF which became  effective  January 1, 2009 and the
current low prices received for natural gas.  Forecasted  conventional  capital
expenditures   in  North  America  for  2009  are  currently   expected  to  be
approximately $1.7 billion, excluding property acquisitions and dispositions.

The Company's drilling activity in 2009 for the North Sea is expected to be 0.9
net platform wells with focus on building  drilling and workover  inventory for
2010. Capital expenditures are expected to be $141 million.

In Offshore West Africa,  capital  expenditures are expected to be $553 million
in 2009,  including $80 million to complete  Phase 2 development  of the Baobab
Field in Cote d'Ivoire,  where the Company is currently drilling the fourth and
final well which is expected to be completed in the second quarter of 2009.

Canadian Natural Resources Limited                                            16

<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  initiates,  operates and maintains a large  working  interest in a
majority  of  the  prospects  in  which  it  participates.  Canadian  Natural's
objectives are to increase crude oil and natural gas production, reserves, cash
flow and net asset value 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 has a full complement of management, technical and support staff to
pursue  these  objectives.  As at  December  31,  2008 the  Company  had  3,782
permanent  employees  in  North  America  and 350  permanent  employees  in its
international  operations.  Included  in the  North  American  numbers  are the
Horizon Project team, consisting of 1,245 permanent employees.

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,  light/medium crude oil and NGLs, Pelican Lake crude oil (14-17(0)
API oil, which receives  medium quality crude netbacks due to lower  production
costs and lower  royalty  rates),  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 44% of 2008 production. Virtually all of the Company's natural gas and NGLs
production is located in the Canadian  provinces of Alberta,  British  Columbia
and Saskatchewan and is marketed in Canada and the United States.  Light/medium
crude oil and NGLs, representing 22% of 2008 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 28% of 2008 production.  Other heavy crude oil, which
accounts for 6% of 2008  production,  is produced from the Pelican Lake area in
north  Alberta.  This  production  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 primary and
thermal heavy and Pelican Lake crude oil operations.

With  approximately  12.1 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.


17                                            Canadian Natural Resources Limited

<PAGE>

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

DAILY PRODUCTION AND INFRASTRUCTURE

Set forth below is a summary of the  conventional  crude oil,  NGLs and natural
gas  properties as at December 31, 2008. 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>
                                                2008 Average Daily            2007 Average Daily            Major Infrastructure
                                                Production Rates                Production Rates              As at Dec 31, 2008
---------------------------------------------------------------------------------------------------------------------------------
Region                                                                                                                Batteries/
                                         Crude oil &                         Crude oil                     Compressors & Plants/
                                                NGLs    Natural gas             & NGLs   Natural gas                  Platforms/
                                              (mbbl)         (mmcf)             (mbbl)        (mmcf)                       FPSO
---------------------------------------------------------------------------------------------------------------------------------
<S>                                      <C>            <C>                  <C>         <C>                <C>
NORTH AMERICA
     Northeast British Columbia                  5.9            377                7.0           430                   1/10/-/-
     Northwest Alberta                          16.4            531               17.0           596                   -/13/-/-
     Northern Plains                           200.7            382              201.4           418                   11/9/-/-
     Southern Plains                            12.2            177               12.7           196                    -/3/-/-
     Southeast Saskatchewan                      8.4              3                8.4             2                    -/-/-/-
     Non-core regions                            0.2              2                0.3             1                    -/-/-/-
---------------------------------------------------------------------------------------------------------------------------------
INTERNATIONAL
     North Sea UK Sector                        45.3             10               55.9            13                    -/-/5/1
     Offshore West Africa
        Cote d'Ivoire                           26.6             13               28.5            12                    -/-/-/2
        Gabon                                      -              -                  -             -                    -/-/-/-
     Non-core regions
        South Africa                               -              -                  -             -                    -/-/-/-
---------------------------------------------------------------------------------------------------------------------------------
TOTAL                                          315.7          1,495              331.2         1,668                  12/35/5/3
=================================================================================================================================
</TABLE>




Canadian Natural Resources Limited                                            18

<PAGE>


DEVELOPED AND UNDEVELOPED ACREAGE

The following  table  summarizes the Companies  landholdings as at December 31,
2008.

<TABLE>
<CAPTION>
                                                                                                                 Average Working
                                   Developed Acreage       Undeveloped Acreage            Total Acreage                 Interest
-----------------------------------------------------------------------------------------------------------------------------------
Region (thousands of acres)      Gross          Net       Gross            Net         Gross           Net                      %
-----------------------------------------------------------------------------------------------------------------------------------
<S>                              <C>          <C>        <C>           <C>            <C>           <C>                      <C>
NORTH AMERICA
     Northeast British

     Columbia                    1,478        1,107       3,037         2,227          4,515         3,334                     74
     Northwest Alberta           1,205          859       1,808         1,352          3,013         2,211                     73
     Northern Plains             4,126        3,326       7,354         6,452         11,480         9,778                     85
     Southern Plains             1,603        1,251         975           832          2,578         2,083                     81
     Southeast Saskatchewan         89           73         146           130            235           203                     87
       In-Situ Oil Sands            23           23         598           495            621           518                     84
       Horizon Oil Sands             -            -         115           115            115           115                    100
     Non-core regions               23            8       1,276           179          1,299           187                     14
-----------------------------------------------------------------------------------------------------------------------------------
INTERNATIONAL
     North Sea UK Sector           108           74         314           258            422           332                     79
     Offshore West Africa
        Cote d'Ivoire                7            4          95            55            102            59                     58
        Gabon                        -            -         152           137            152           137                     90
     Non-core regions
        South Africa                 -            -       4,002         4,002          4,002         4,002                    100
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL                            8,662        6,725      19,872        16,234         28,534        22,959                     80
===================================================================================================================================

</TABLE>





19                                            Canadian Natural Resources Limited

<PAGE>

DRILLING ACTIVITY

Set forth below is a summary of  conventional  crude oil,  NGLs and natural gas
drilling  activity of the Company for the fiscal year ending  December 31, 2008
by geographic region:

<TABLE>
<CAPTION>

                                                                          2008
----------------------------------------------------------------------------|-----------------------------------------------------
                                              Exploration                   |                     Development
----------------------------------------------------------------------------|-----------------------------------------------------
                             Crude    Natural    Dry      Service/    Total |Crude    Natural       Dry       Service/      Total
                                 Oil      Gas        Stratigraphic          |    Oil       Gas           Stratigraphic
----------------------------------------------------------------------------|-----------------------------------------------------
<S>                             <C>      <C>    <C>  <C>              <C>     <C>       <C>       <C>    <C>               <C>
NORTH AMERICA                                                               |
   Northeast                                                                |
     British Columbia  Gross       -      2.0    2.0             -      4.0 |      -      26.0      4.0              -       30.0
                         Net       -      1.5    1.5             -      3.0 |      -      22.5      1.9              -       24.4
   Northwest Alberta   Gross     1.0     14.0    1.0             -     16.0 |   14.0      62.0      3.0            3.0       82.0
                         Net     0.6     12.6    0.9             -     14.1 |    8.9      54.0      2.6            2.2       67.7
   Northern Plains     Gross    27.0     14.0    5.0             -     46.0 |  583.0     131.0     22.0           33.0      769.0
                         Net    26.3     11.4    5.0             -     42.7 |  557.3      88.4     21.5           32.4      699.6
   Southern Plains     Gross     4.0      6.0    1.0             -     11.0 |   29.0     153.0      1.0              -      183.0
                         Net     4.0      6.0    1.0             -     11.0 |   26.9      72.8      1.0              -      100.7
   Southeast                                                                |
     Saskatchewan      Gross     6.0        -    2.0             -      8.0 |   57.0         -        -            2.0       59.0
                         Net     4.6        -    2.0             -      6.6 |   48.9         -        -            1.7       50.6
   Non-core Regions    Gross       -        -      -             -        - |      -       3.0      2.0              -        5.0
                         Net       -        -      -             -        - |      -       0.1      0.4              -        0.5
----------------------------------------------------------------------------|-----------------------------------------------------
NORTH SEA                                                                   |
UK SECTOR              Gross     1.0        -      -             -      1.0 |    2.0         -      1.0            1.0        4.0
                         Net     0.8        -      -             -      0.8 |    1.6         -      0.8            0.9        3.3
----------------------------------------------------------------------------|-----------------------------------------------------
OFFSHORE               Gross       -        -      -             -        - |    4.0         -        -            2.0        6.0
WEST AFRICA                                                                 |
                         Net       -        -      -             -        - |    2.3         -        -            1.8        4.1
----------------------------------------------------------------------------|-----------------------------------------------------
TOTAL                  GROSS    39.0     36.0   11.0             -     86.0 |  689.0     375.0     33.0           41.0    1,138.0
                         NET    36.3     31.5   10.4             -     78.2 |  645.9     237.8     28.2           39.0      950.9
============================================================================|=====================================================

</TABLE>

Total success rate excluding service and  stratigraphic  test wells for 2008 is
96% (2007 - 91%, 2006 - 91%)




Canadian Natural Resources Limited                                            20

<PAGE>

<TABLE>
<CAPTION>

                                                                          2007
----------------------------------------------------------------------------|-----------------------------------------------------
                                              Exploration                   |                     Development
----------------------------------------------------------------------------|-----------------------------------------------------
                             Crude    Natural    Dry      Service/    Total |Crude    Natural       Dry       Service/      Total
                                 Oil      Gas        Stratigraphic          |    Oil       Gas           Stratigraphic
----------------------------------------------------------------------------|-----------------------------------------------------
<S>                             <C>      <C>    <C>  <C>              <C>     <C>       <C>       <C>    <C>               <C>
NORTH AMERICA                                                               |
   Northeast British                                                        |
     Columbia          Gross       -      7.0      7.0          -       14.0|    3.0     45.0      12.0          -          60.0
                         Net       -      7.0      6.0          -       13.0|    2.9     35.1      10.1          -          48.1
   Northwest Alberta   Gross     1.0     23.0      5.0          -       29.0|   21.0    102.0      14.0        2.0         139.0
                         Net     1.0     16.4      3.8          -       21.2|   12.1     82.1       8.9        1.5         104.6
   Northern Plains     Gross    26.0     31.0     20.0       97.0      174.0|  545.0     82.0      44.0       49.0         720.0
                         Net    23.8     24.7     19.4       97.0      164.9|  500.6     70.9      42.4       48.8         662.7
   Southern Plains     Gross     1.0     14.0      1.0          -       16.0|   19.0    174.0       2.0        1.0         196.0
                         Net     1.0     13.4      1.0          -       15.4|   18.1    134.1       0.6        1.0         153.8
   Southeast                                                                |
     Saskatchewan      Gross     1.0        -        -          -        1.0|   27.0        -       2.0        4.0          33.0
                         Net     1.0        -        -          -        1.0|   23.0        -       0.4        4.0          27.4
   Non-core Regions    Gross       -        -        -          -          -|      -        -         -          -             -
                         Net       -        -        -          -          -|      -        -         -          -             -
----------------------------------------------------------------------------|-----------------------------------------------------
NORTH SEA                                                                   |
UK SECTOR              Gross       -        -        -          -          -|    4.0        -         -        4.0           8.0
                         Net       -        -        -          -          -|    3.7        -         -        3.5           7.2
----------------------------------------------------------------------------|-----------------------------------------------------
OFFSHORE               Gross       -        -        -          -          -|    7.0        -         -        1.0           8.0
WEST AFRICA                                                                 |
                         Net       -        -        -          -          -|    4.1        -         -        0.6           4.7
----------------------------------------------------------------------------|-----------------------------------------------------
TOTAL                  Gross    29.0     75.0     33.0       97.0      234.0|  626.0    403.0      74.0       61.0       1,164.0
                         Net    26.8     61.5     30.2       97.0      215.5|  564.5    322.2      62.4       59.4       1,008.5
============================================================================|=====================================================

</TABLE>




21                                            Canadian Natural Resources Limited

<PAGE>

<TABLE>
<CAPTION>

                                                                          2006
----------------------------------------------------------------------------|-----------------------------------------------------
                                              Exploration                   |                     Development
----------------------------------------------------------------------------|-----------------------------------------------------
                             Crude    Natural    Dry      Service/    Total |Crude    Natural       Dry       Service/      Total
                                 Oil      Gas        Stratigraphic          |    Oil       Gas           Stratigraphic
----------------------------------------------------------------------------|-----------------------------------------------------
<S>                             <C>      <C>    <C>  <C>              <C>     <C>       <C>       <C>    <C>               <C>
NORTH AMERICA                                                               |
   Northeast British                                                        |
     Columbia          Gross     2.0     19.0      6.0              -   27.0|   12.0    166.0      15.0          -          193.0
                         Net     2.0     15.1      5.6              -   22.7|   10.9    148.0      14.1          -          173.0
   Northwest Alberta   Gross     2.0     22.0     10.0              -   34.0|   19.0    165.0      19.0          -          203.0
                         Net     2.0     15.7      9.5              -   27.2|   12.5    137.1      14.6          -          164.2
   Northern Plains     Gross    18.0    110.0     31.0          129.0  288.0|  504.0    175.0      40.0       78.0          797.0
                         Net    13.6     90.6     28.2          128.9  261.3|  470.4    128.1      36.1       78.0          712.6
   Southern Plains     Gross     2.0     34.0      9.0              -   45.0|    6.0    154.0       1.0          -          161.0
                         Net     2.0     29.8      8.4              -   40.2|    4.2     74.4       1.0          -           79.6
   Southeast                                                                |
     Saskatchewan      Gross       -        -        -              -      -|   84.0        -       2.0          -           86.0
                         Net       -        -        -              -      -|   72.7        -       2.0          -           74.7
   Non-core Regions    Gross       -      2.0        -              -    2.0|    2.0      8.0         -        1.0           11.0
                         Net       -      0.6        -              -    0.6|    0.5      2.2         -        1.0            3.7
----------------------------------------------------------------------------|-----------------------------------------------------
NORTH SEA                                                                   |
UK SECTOR              Gross       -        -        -              -      -|    8.0        -         -        2.0           10.0
                         Net       -        -        -              -      -|    7.4        -         -        1.8            9.2
----------------------------------------------------------------------------|-----------------------------------------------------
OFFSHORE               Gross       -        -        -              -      -|    7.0        -         -        3.0           10.0
WEST AFRICA                                                                 |
                         Net       -        -        -              -      -|    4.1        -         -        1.7            5.8
----------------------------------------------------------------------------|-----------------------------------------------------
TOTAL                  Gross    24.0    187.0     56.0          129.0  396.0|  642.0    668.0      77.0       84.0        1,471.0
                         Net    19.6    151.8     51.7          128.9  352.0|  582.7    489.8      67.8       82.5        1,222.8
============================================================================|=====================================================

</TABLE>




Canadian Natural Resources Limited                                            22

<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, 2008:

<TABLE>
<CAPTION>
                                      Natural gas wells                  Crude oil wells                      Total wells
                                   Gross               Net            Gross              Net             Gross               Net
---------------------------------------------------------------------------------------------------------------------------------
<S>                              <C>             <C>                  <C>            <C>                <C>             <C>
NORTH AMERICA
   Northeast British Columbia     1,568           1,297.5               223            191.4             1,791           1,488.9
   Northwest Alberta              2,173           1,696.6               588            334.5             2,761           2,031.1
   Northern Plains                4,057           3,281.8             5,800          5,276.2             9,857           8,558.0
   Southern Plains                7,405           6,236.6             1,169          1,073.3             8,574           7,309.9
   Southeast Saskatchewan             2               2.0             1,239            878.7             1,241             880.7
   Non-core regions                  69              24.2               127             23.8               196              48.0
UNITED STATES                         4               0.4                 2              0.3                 6               0.7
NORTH SEA UK SECTOR                   2               0.1               111             93.8               113              93.9
OFFSHORE WEST AFRICA
   Cote d'Ivoire                      -                 -                23             13.4                23              13.4
---------------------------------------------------------------------------------------------------------------------------------
Total                            15,280          12,539.2             9,282          7,885.4            24,562          20,424.6
=================================================================================================================================
</TABLE>

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

NORTHEAST BRITISH COLUMBIA

[GRAPHIC OMITTED -- Map of Canadian Natural Lands in the NE BC Area]




Significant  geological variation extends throughout the productive  reservoirs
in this region  located  west of the  British  Columbia  and Alberta  border to
Prince George, producing light crude oil, NGLs and natural gas.

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 asset base in this area.
The  southern  portion of this region  encompasses  the  Company's BC Foothills
assets where natural gas is produced from the deep  Mississippian  and Triassic
aged reservoirs in this highly deformed structural area.


23                                            Canadian Natural Resources Limited

<PAGE>

NORTHWEST ALBERTA

[GRAPHIC OMITTED -- Map of Canadian Natural Lands in the NE AB Area]




This region is 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 Rio Alto  Exploration;  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 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.  The south western portion of this region also contains significant
Foothills  assets with natural gas  produced  from the deep  Mississippian  and
Triassic aged reservoirs.

NORTHERN PLAINS

[GRAPHIC OMITTED -- Map of Canadian Natural Lands in the Northern Plains Area]




Canadian Natural Resources Limited                                            24

<PAGE>

This region  extends just south of Edmonton north to Fort McMurray and from the
Northwest  Alberta area 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.

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. Evaluation of the potential production
of CBM from the  Mannville  coals  commenced in 2006 with the drilling of three
horizontal  wells. The three well pilot was deemed not commercial and the wells
were suspended in 2008.

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

The Company's  holdings in this region of primary heavy oil  production are the
result of Crown land  purchases  and  several  acquisitions  including  Sceptre
Resources,  Ranger  Oil  and  Petrovera,  as  well as  acquisitions  from  Koch
Exploration. Included in this area is the 100% owned ECHO Pipeline system which
is a  high  temperature,  insulated  crude  oil  transportation  pipeline  that
eliminates the requirement for field condensate blending.  The pipeline,  which
has a capacity of up to 72,000 bbl/d,  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.

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(Degree)-17(Degree)
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, including the 62% owned and operated
Pelican Lake Pipeline.  The Company holds and controls approximately 75% of the
known  Wabasca  crude oil pool in the Pelican Lake area.  It is  estimated  the
Wabasca pool 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  primary  production on the Company's  developed  leases.  The Company is
using an Enhanced Oil Recovery  ("EOR")  scheme  through both water and polymer
flooding  to  increase  the  ultimate   recoveries  from  the  field.  To  date
approximately  11% of the field has been  converted to waterflood and there are
three  producing  polymer  production  wells and 70  polymer  injection  wells.
Pelican  Lake   production   averaged   approximately   37,000  bbl/d  in  2008
(2007-34,000  bbl/d).  The Company is  continuing to drill and convert wells to
polymer injection in 2009.

Production  from the 100% owned  Primrose  and Wolf Lake  Fields  located  near
Bonnyville,  Alberta  involves  processes  that  utilize  steam to increase the
recovery of the heavy  (10(Degree)-11(Degree)API)  crude oil. The two processes
employed by the Company are Cyclic Steam  Stimulation  (CSS) 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 119,500  bbl/d,  and the 15% Company owned
Cold Lake  Pipeline.  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.  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.  The  Regulatory
application for the Kirby In-Situ Oil Sands Project located approximately 85 km
northeast  of Lac La Biche  was  submitted  in  September  2007  outlining  the
Company's  plan to  build a 45,000  bbl/d  in-situ  oil  sands  project.  Final
corporate  sanction  and  project  scope  will  be  impacted  by  environmental
regulations and their associated costs. Subject to regulatory  approval,  crude
oil  pricing,  and capital  costs,  the Company may proceed  with the  detailed
engineering and design work.


25                                            Canadian Natural Resources Limited

<PAGE>

In 2007 the Company received regulatory approval for 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 Company began construction in 2007 and first oil production was achieved in
late October 2008. The expansion added 40,000 bbl/d of capacity.  Subsequent to
December 31,  2008,  operational  issues on one of the pads caused  steaming to
cease on all well pads  resulting  in the Company  switching  from the steaming
cycle to the  production  cycle  ahead of  schedule.  The Company is working on
rectifying the issue.

SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN

[GRAPHIC OMITTED -- Map of Canadian Natural Lands in the Southern Plans /
Saskatchewan Areas]





The Southern  Plains area is 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  were  augmented  by the  2006
acquisition of ACC.

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 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. This region produces primarily light sour crude oil
from as many as seven productive horizons found at depths up to 2,700 meters.


Canadian Natural Resources Limited                                            26

<PAGE>

HORIZON OIL SANDS PROJECT

[GRAPHIC  OMITTED -- Map of  Canadian  Natural  Lands in the  Horizon Oil Sands
Project]




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.  Figure 1 shows the
location of the Horizon  Project within Alberta and within the region and Table
1 describes the leases the Company holds in the region.

FIGURE 1 - LOCATION OF THE HORIZON OIL SANDS PROJECT

[GRAPHIC OMITTED -- Map of  Horizon Oil Sands Project]
[GRAPHIC OMITTED -- second Map of  Horizon Oil Sands Project]


27                                            Canadian Natural Resources Limited


<PAGE>

<TABLE>
<CAPTION>
TABLE 1 - CANADIAN NATURAL ATHABASCA REGION OIL SAND LEASES

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

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

The leases being  developed for the Horizon  Project are 18, 25, 10, 19 and 20.
The project site is accessible by a private road as well as a private airstrip.

The project  includes  surface oil sands mining,  bitumen  extraction,  bitumen
upgrading and associated infrastructure.  Mining of the oil sands is done using
conventional  truck and shovel  technology.  The ore is then processed  through
extraction and froth treatment facilities to produce bitumen, which is upgraded
on-site into 34 O API SCO. The SCO is transported  from the site by the Horizon
Pipeline to the Edmonton area for distribution.  An on-site  cogeneration plant
provides power and steam for the operation.

In June 2002,  Canadian Natural filed an application for regulatory approval of
the Horizon  Project.  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 the Horizon Project was 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.

Site clearing and pre-construction preparation activities commenced in 2004 and
the Company  received  project  sanction by the Board of  Directors in February
2005, authorizing management to proceed with Phase 1 of the Horizon Project.

First  synthetic  crude oil production was achieved on February 28, 2009.  Full
production  capacity for Phase 1 is 110,000  bbl/d of SCO and is expected to be
achieved in late 2009.

Subsequent  planned  expansion  through Phases 2/3,  further broken down into a
series of four Tranches,  are being  re-profiled in order to attain better cost
management.

Horizon Project Phase 1 construction  costs were  approximately $2.7 billion in
2008 and cumulative  construction  expenditures were approximately $9.5 billion
through  the end of 2008.  In  addition,  $364  million  of  expenditures  were
incurred for commissioning  costs and operating and capital inventory for Phase
1 and capital  expenditures  of $336 million were  incurred for Phases 2 and 3.
Forecasted expenditures of $621 million are expected to be incurred in 2009 for
remaining Phase 1 construction  costs,  commissioning  and inventory  costs, as
well  as  sustaining   capital  costs  and  Tranche  2  expansion.   The  total
construction  cost to  completion  is expected to be 43% over the original $6.8
billion estimate.  These  expenditures are direct project costs only and do not
include capitalized interest, stock based compensation or lease evaluation.

During the fourth quarter 2008, the Company drilled 92 stratigraphic test wells
(2007 - 98, 2006 - 163) to further  delineate the ore body and confirm resource
quality and quantity.


Canadian Natural Resources Limited                                            28

<PAGE>

As of year-end 2008, key development  achievements  associated with the Horizon
Project were as follows:

     o    Phase 1 work progress is 98.9% complete.

     o    Mine  operations  has  removed  87.8  million  bank  cubic  meters of
          overburden material.

REGIONAL AND PROJECT GEOLOGY

Lease 18,  the main oil  sands  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.

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 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 general  stratigraphy  of the
Horizon Project is shown in Figure 2.

FIGURE 2 - GENERAL STRATIGRAPHY OF THE HORIZON OIL SANDS PROJECT

[GRAPHIC OMITTED -- General Stratigraphy]






29                                            Canadian Natural Resources Limited
<PAGE>


OIL SANDS MINING RESERVES

The following table sets out Canadian Natural's net reserves,  after royalties,
of synthetic crude oil from the Horizon Project:

                                                     Constant Prices
                                                 As at December 31, 2008
--------------------------------------------------------------------------------
                                                                    Proved and
                                           Proved Total               Probable
--------------------------------------------------------------------------------
Net reserves, after royalties (mmbbl)
   Synthetic crude oil                          1,946                   2,944
================================================================================

NOTE:  SYNTHETIC CRUDE OIL RESERVES ARE BASED ON THE UPGRADING OF BITUMEN USING
TECHNOLOGIES IMPLEMENTED AT THE HORIZON PROJECT.

For the year ended December 31, 2008, 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 2.9 billion barrels of net proved
and probable  synthetic crude oil reserves shown in the table are produced from
38 years of projected production commencing in 2009.

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 Reserves  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                                            30

<PAGE>


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

[GRAPHIC OMITTED --- map]














31                                            Canadian Natural Resources Limited

<PAGE>


FIGURE 4 - HORIZON OIL SANDS PROJECT CORE HOLE COVERAGE

[GRAPHIC OMITTED -- map]








Canadian Natural Resources Limited                                            32


<PAGE>

UNITED KINGDOM NORTH SEA

[GRAPHIC OMITTED --  map]



Through its wholly owned subsidiary CNR International (U.K.) Limited,  formerly
Ranger Oil (U.K.)  Limited,  the Company has operated in the North Sea for over
30  years  and  has  developed  a  significant  database,  extensive  operating
experience and an  experienced  staff.  In 2008,  the Company  produced from 13
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%.  The Company  also has an
interest in the Strathspey Field and 12 licences covering 20 exploration blocks
and part blocks  surrounding  the Ninian and Murchison  platforms.  The Company
also has a 66.5% working interest in the abandoned Hutton Field.

In the central  portion of the North Sea,  the Company  holds a 87.6%  operated
working  interest  in the Banff  Field and also owns a 45.7%  operated  working
interest in the Kyle Field. Production from the Kyle Field is processed through
the Banff FPSO  facilities  resulting in lower combined  production  costs from
these fields.

The Company holds a 100% operated working  interest in T-block  (comprising the
Tiffany, Toni and Thelma 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 2008 two production wells were completed at Murchison and one production
well was completed at Ninian with an  additional  well in progress at Ninian at
year end.  The  Company  also  drilled one water  injection  well at Ninian and
further increased volumes injected in to the Ninian reservoir.

The Company continued with its planned  investment in its long-term  facilities
and   infrastructure   strategy  and   successfully   carried  our  maintenance
turnarounds  at all five  installations  during  the year.  With the  Murchison
turnaround,  the Company implemented a new control system which has resulted in
improved platform uptime.

In the first quarter 2009, the Company commenced  drilling on Deep Banff a high
temperature,  high pressure,  natural gas  exploration  well.  Upon  successful
discovery the net interest to the Company  increases  from 18% to 37%.  Results
are expected in the second quarter of 2009.


33                                            Canadian Natural Resources Limited

<PAGE>

OFFSHORE WEST AFRICA

COTE D'IVOIRE

[GRAPHIC OMITTED]




The Company owns interests in two exploration licences offshore Cote d'Ivoire.

The Company has a 58.7% operated  interested in the Espoir Field in Block CI-26
which is located in water  depths  ranging  from 100 to 700 meters.  Production
from East Espoir commenced in 2002 and development  drilling of West Espoir was
completed in 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.  Progress on the Facility Upgrade Project
to increase  capacity of the FPSO  continues and is expected to be completed in
third quarter 2009.

The Company also has a 58% interest in the Baobab  Field,  identified  in Block
CI-40, which is eight kilometers south of the Espoir facilities.  Problems with
the  control of sand and solids  production  led to five of the ten  production
wells at Baobab being shut in during 2007. The Company  secured a deepwater rig
that was mobilized in early second  quarter 2008 which enabled work to begin on
the  restoration of the shut-in  production  with three wells being onstream by
year end. A fourth and final well is  expected  to be  completed  in the second
quarter of 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.


Canadian Natural Resources Limited                                            34

<PAGE>

GABON

     [GRAPHIC OMITTED][GRAPHIC OMITTED]




The Company has a permit 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. Delays in construction of the FPSO which arrived on location in February
2009,  have resulted in first oil being expected in the first half of 2009. Two
appraisal  wells and two  production  wells have been  drilled and  development
activity is  continuing.  It is planned that in total 28 horizontal  production
wells plus one gas injector  well will be drilled.  Crude oil  production  will
rely  on a gas cap  expansion  supplemented  by  re-injection  of the  produced
solution  gas.  Production  is  expected  to  ramp  up  to a  plateau  rate  of
approximately 20,000 bbl/d in 2010.



35                                            Canadian Natural Resources Limited


<PAGE>

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

For the year  ended  December  31,  2008,  the  Company  retained  a  qualified
independent  reserves  evaluator,  Sproule Associates Limited  ("Sproule"),  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
reserves include all of the Company's light/medium,  primary heavy, and thermal
heavy crude oil,  natural gas, coal bed methane and NGLs reserves.  They do not
include the Company's oil sands mining  reserves.  The Company has been granted
an exemption  from certain of the  provisions of 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   conventional   crude  oil,   NGLs,  and  natural  gas  reserve
reconciliations 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 and in its
annual Form 40-F  filing  with the SEC.  The Company has elected to provide the
net present  value of these same  conventional  proved  reserves as well as its
conventional  proved and probable  reserves and the net present  value of these
reserves under the same  parameters as additional  voluntary  information.  Net
present values of  conventional  reserves are based upon  discounted cash flows
prior to the  consideration  of income  taxes and  existing  asset  abandonment
liabilities.  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  additional  voluntary
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 Sproule to review the
qualifications  of and  procedures  used by the  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, 2008.

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 MATERIAL.


Canadian Natural Resources Limited                                            36

<PAGE>



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

                                                                               Constant Prices and Costs
-----------------------------------------------------------------------------------------------------------------------------------
                                                 Crude oil & NGLs (mmbbl)                         Natural gas (bcf)
                                                                   Total proved &                                  Total proved &
                                     Total proved reserves      probable reserves   Total proved reserves       probable reserves
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>                        <C>                  <C>                        <C>
NORTH AMERICA
    Canada                                             948                  1,599                   3,521                   4,617
    United States                                        -                      -                       2                       2
INTERNATIONAL
    United Kingdom                                     256                    399                      67                      94
    Cote d'Ivoire                                      124                    170                      94                     131
    Gabon                                               18                     21                       -                       -
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL                                                1,346                  2,189                   3,684                   4,844
===================================================================================================================================
</TABLE>


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

                                                                               Constant Prices and Costs
----------------------------------------------------------------------------------------------------------------------------------
                                                     Crude oil & NGLs (mmbbl)                           Natural gas (bcf)
                                          Company gross                     Net           Company gross                     Net
----------------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                             <C>              <C>                            <C>
Proved developed reserves                            704                     632                   3,271                   2,824
Proved undeveloped reserves                          766                     714                     980                     860
----------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES                              1,470                   1,346                   4,251                   3,684
TOTAL PROVED & PROBABLE RESERVES                   2,371                   2,189                   5,584                   4,844
===================================================================================================================================


<CAPTION>
ESTIMATED NET PRESENT VALUE

                                                                     Constant Prices and Costs
----------------------------------------------------------------------------------------------------------------------------------
                                            Undiscounted                              Discounted at:
($ millions)                                                                  10%                     15%                     20%
----------------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                             <C>                    <C>                      <C>
Proved developed reserves                 $        19,328                  12,987                  11,253                   9,980
Proved undeveloped reserves               $         7,690                   2,200                   1,164                     521
----------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES                     $        27,018                  15,187                  12,417                  10,501
TOTAL PROVED & PROBABLE RESERVES          $        39,216                  19,264                  15,179                  12,484
===================================================================================================================================
</TABLE>

37                                            Canadian Natural Resources Limited


<PAGE>

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

                                                                                   Forecast Prices and Costs
----------------------------------------------------------------------------------------------------------------------------------
                                                           Crude oil & NGLs (mmbbl)                        Natural gas (bcf)
                                                  Company gross                  Net          Company gross                  Net
----------------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                             <C>              <C>                            <C>
Proved developed reserves                                   813                  683                  3,355                2,813
Proved undeveloped reserves                                 750                  604                    985                  827
----------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES                                     1,563                1,287                  4,340                3,640
TOTAL PROVED & PROBABLE RESERVES                          2,430                1,968                  5,702                4,759
===================================================================================================================================

<CAPTION>
ESTIMATED NET PRESENT VALUES

                                                                         Forecast Prices and Costs
----------------------------------------------------------------------------------------------------------------------------------
($ millions)                                             Undiscounted                                  Discounted at:
                                                                                  10%                   15%                   20%
----------------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                             <C>                    <C>                      <C>
Proved developed reserves                   $            46,341   $            25,995  $             21,552  $             18,522
Proved undeveloped reserves                 $            35,554   $            11,992  $              8,096  $              5,744
----------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES                       $            81,895   $            37,987  $             29,648  $             24,266
TOTAL PROVED & PROBABLE RESERVES            $           130,876   $            52,770  $             39,560  $             31,427
===================================================================================================================================
</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                                            38

<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
     2008 adjusted for quality and transportation as well as the 2008 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$0.82/C$1.00):

<TABLE>
<CAPTION>

                                        Natural gas                |                            Crude oil & NGLs
     --------------------------------------------------------------|----------------------------------------------------------------
                 Company                                           |  Company                   Hardisty
                 average    Henry Hub                Huntingdon/   |  average      WTI @           Heavy    Edmonton    North Sea
                   price    Louisiana          AECO        Sumas   |    price  Cushing(1) 12(degree) API      Par(2)        Brent
     (Year)      (C$/mcf)  (US$/mmbtu)    (C$/mmbtu)   (C$/mmbtu)  |  (C$/bbl)   (US$/bbl)       (C$/bbl)    (C$/bbl)    (US$/bbl)
     --------------------------------------------------------------|----------------------------------------------------------------
<S>                 <C>          <C>           <C>          <C>         <C>         <C>            <C>         <C>          <C>
     2008           6.51         5.63          6.34         7.48   |    34.51       44.60          26.11       45.51        41.76
     ==============================================================|================================================================
</TABLE>

     (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(degree) 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.  Costs are
     escalated  at 2% per year.  Future  crude oil,  NGLs and natural gas price
     forecasts  were based on Sproule's  December 31, 2008 crude oil,  NGLs and
     natural gas pricing model.


39                                            Canadian Natural Resources Limited

<PAGE>

     The Company's  weighted  average crude oil and NGLs price and the weighted
     average  natural gas price in the 2008  evaluation  were $34.51 per barrel
     and $6.51 per mcf  respectively.  The crude oil and natural  gas  forecast
     prices used in the Evaluation Reports are as follows:

<TABLE>
<CAPTION>
                                        Natural gas               |                             Crude oil & NGLs
     -------------------------------------------------------------|-----------------------------------------------------------------
                 Company                                          |   Company                   Hardisty
                 average    Henry Hub                Huntingdon/  |   average      WTI @           Heavy    Edmonton    North Sea
                   price    Louisiana          AECO        Sumas  |     price  Cushing(1) 12(degree) API      Par(2)        Brent
     (Year)      (C$/mcf)  (US$/mmbtu)    (C$/mmbtu)   (C$/mmbtu) |   (C$/bbl)   (US$/bbl)       (C$/bbl)    (C$/bbl)    (US$/bbl)
     -------------------------------------------------------------|-----------------------------------------------------------------
<S>                 <C>          <C>           <C>      <C>         <C>        <C>         <C>               <C>          <C>
           2009     6.73         6.30          6.82         6.82        53.07       53.73          47.05         65.35       51.73
           2010     7.46         7.32          7.56         7.56  |     62.06       63.41          54.58         72.78       61.37
           2011     7.74         7.56          7.84         7.84  |     68.50       69.53          59.96         79.95       67.45
           2012     8.26         8.49          8.38         8.38  |     77.12       79.59          67.53         86.57       77.47
           2013     9.07         9.74          9.20         9.20  |     86.07       92.01          74.08         94.97       89.84
           2014     9.26         9.94          9.41         9.41  |     88.99       93.85          75.58         96.89       91.64
           2015     9.46        10.14          9.62         9.62  |     90.95       95.72          77.10         98.85       93.47
           2016     9.67        10.34          9.83         9.83  |     94.64       97.64          78.66        100.84       95.34
           2017     9.88        10.54         10.05        10.05  |     98.04       99.59          80.25        102.88       97.25
           2018    10.08        10.76         10.27        10.27  |     99.21      101.58          81.87        104.96       99.19
           2019    10.32        10.97         10.50        10.50  |    100.38      103.61          83.52        107.08      101.18
      ============================================================|=================================================================
</TABLE>

     NOTE:   FOREIGN   EXCHANGE   RATE  USED  WAS   US$0.80/C$1.00   FOR  2009;
     US$0.85/C$1.00   FOR  2010  AND  2011;   US$0.90/C$1.00   FOR  2012;   AND
     US$0.95/C$1.00 FOR 2013 AND BEYOND.

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:

<TABLE>
<CAPTION>
                                            Proved                                           Proved & probable
       ($ millions)         Forecast price case      Constant price case       Forecast price case             Constant price case
       ----------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                      <C>                       <C>                             <C>
       2009                               1,592                    1,589                     1,841                           1,841
       2010                               1,646                    1,613                     1,938                           1,900
       2011                               1,657                    1,590                     2,168                           2,081
       2012                                 883                      832                     1,409                           1,328
       2013                               1,122                    1,037                     1,709                           1,579
       2014                                 620                      562                       814                             737
       2015                                 390                      346                       566                             503
       2016                                 605                      527                       661                             576
       2017                                 477                      407                       832                             710
       2018                                 286                      239                       544                             455
       2019                                 221                      181                       300                             246
       Thereafter                         1,972                    1,054                     3,428                           2,302
       ============================================================================================================================
</TABLE>

13.  The Evaluation  Reports involved data supplied by the Company with respect
     to quality, heating value and transportation adjustments, interests owned,
     royalties payable, operating costs and contractual commitments.  This data
     was  found  by  Sproule  to be  reasonable  and no  field  inspection  was
     conducted.


Canadian Natural Resources Limited                                            40

<PAGE>


A report on  conventional  reserves  data by Sproule  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  and oil sands mining  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 or oil sands mining
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, 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
-----------------------------------------------------------------------------------|------------------------------------------------
Extensions & discoveries                  51            -           -          51  |       140           -          -          140
Infill drilling                            7            6           4          17  |        46          (1)         6           51
Improved recovery                         10            -           -          10  |         6           -          -            6
Property purchases                         -            -           -           -  |        77           -          -           77
Property disposals                         -            -           -           -  |        (1)          -          -           (1)
Production                              (76)          (17)         (8)       (101) |      (449)         (4)        (4)        (457)
Economic revisions due to prices          28          (81)          8         (45) |       (19)        (56)         6          (69)
Revisions of prior estimates               8           38          10          56  |       202          47         22          271
-----------------------------------------------------------------------------------|------------------------------------------------
RESERVES, DEC 31, 2008                   948          256         142       1,346  |     3,523          67         94        3,684
-----------------------------------------------------------------------------------|------------------------------------------------
                                                                                   |
PROVED AND PROBABLE RESERVES                                                       |
-----------------------------------------------------------------------------------|------------------------------------------------
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
-----------------------------------------------------------------------------------|------------------------------------------------
Extensions & discoveries                  76            -           -          76  |       182           -          -          182
Infill drilling                            9            4           -          13  |        58           (3)        -           55
Improved recovery                         23            -           -          23  |         8           -          -            8
Property purchases                         6            -           -           6  |        93           -          -           93
Property disposals                         -            -           -           -  |        (6)         -          -            (6)
Production                              (76)          (17)         (8)       (101) |      (449)         (4)       (4)         (457)
Economic revisions due to prices         59           (45)         8          22   |       (27)        (63)        8           (82)
Revisions of prior estimates            (43)           52           5          14  |       158          51         39          248
-----------------------------------------------------------------------------------|------------------------------------------------
RESERVES, DEC 31, 2008                 1,599          399         191       2,189  |     4,619          94        131        4,844
===================================================================================|================================================
</TABLE>

NOTE:  Revisions  of prior year  estimates  for 2007 include  revisions  due to
prices.


41                                            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  2008 Annual Report under  "Supplementary  Oil and
Gas Information" on pages 101 to 105 and is incorporated herein by reference.

D.   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
                                         |----------|
                                         |     2008 |        2007        2006
-----------------------------------------|----------|--------------------------
Daily production, before royalties       |          |
   Crude oil and NGLs (bbl/d)            |  315,667 |     331,232     331,998
   Natural gas (mmcf/d)                  |    1,495 |       1,668       1,492
-----------------------------------------|----------|--------------------------
Annual production, before royalties      |          |
   Crude oil and NGLs (mbbl)             |  115,534 |     120,900     121,179
   Natural gas (bcf)                     |      547 |         609         545
=========================================|==========|==========================





Canadian Natural Resources Limited                                            42

<PAGE>

NETBACKS
INFORMATION BY QUARTER

<TABLE>
<CAPTION>

                                                 2008                                                 2007
                                Q1      Q2         Q3       Q4      YEAR ENDED|         Q1      Q2       Q3       Q4    Year Ended
------------------------------------------------------------------------------|----------------------------------------------------
<S>                         <C>        <C>        <C>        <C>       <C>         <C>       <C>      <C>       <C>         <C>
AVERAGE DAILY PRODUCTION                                                      |
VOLUMES, BEFORE ROYALTIES                                                     |
                                                                              |
Crude oil and NGLs                                                            |
(bbl/d)                     327,217 319,077       306,970    309,570   315,667|   327,001   327,494  333,062   337,240     331,232
Natural gas (mmcf/d)         1,538    1,526         1,490      1,427     1,495|     1,717     1,722    1,647     1,589       1,668
------------------------------------------------------------------------------|----------------------------------------------------
                                                                              |
PRODUCT NETBACKS (1)                                                          |
Crude oil and NGLs ($/bbl)                                                    |
   Sales price (2)       $    78.99  $  103.73   $ 102.30  $   45.81  $  82.41|   $ 51.71   $ 53.74  $ 58.10  $  58.03  $    55.45
   Royalties                   8.70      14.82      14.17       4.49     10.48|      4.92      5.46     6.65      6.66        5.94
   Production                                                                 |
     expenses                 14.81      16.39      17.61      16.33     16.26|     13.81     15.01    13.13     11.53       13.34
------------------------------------------------------------------------------|----------------------------------------------------
   NETBACK               $    55.48  $   72.52   $  70.52  $   24.99  $  55.67|   $ 32.98   $ 33.27  $ 38.32  $  39.84  $    36.17
------------------------------------------------------------------------------|----------------------------------------------------
                                                                              |
Natural gas ($/mcf)                                                           |
   Sales price (2)       $     7.77  $    9.89   $   8.82  $    7.03  $   8.39|   $  7.74   $  7.44  $  5.87  $   6.28  $     6.85
   Royalties                   1.35       1.86       1.55       1.08      1.46|      1.48      1.10     0.89      0.94        1.11
   Production                                                                 |
     expenses                  1.03       0.94       1.05       1.06      1.02|      0.97      0.89     0.88      0.91        0.91
------------------------------------------------------------------------------|----------------------------------------------------
   NETBACK               $     5.39  $    7.09   $   6.22  $    4.89  $   5.91|   $  5.29   $  5.45  $  4.10  $   4.43  $     4.83
------------------------------------------------------------------------------|----------------------------------------------------
                                                                              |
CRUDE OIL AND NGLS NETBACKS BY TYPE(1)                                        |
Light/Pelican Lake/NGLs ($/bbl)                                               |
   Sales price (2)       $    89.68  $  114.69   $ 107.33  $   53.16  $  90.88|   $ 60.19   $ 64.10  $ 67.34  $  72.62  $    65.99
   Royalties                  11.43      14.59      15.84       5.71     11.83|      4.89      5.87     7.24      8.34        6.57
   Production                                                                 |
     expenses                 15.09      16.13      17.18      17.92     16.56|     13.85     14.91    14.40     12.64       13.95
------------------------------------------------------------------------------|----------------------------------------------------
   NETBACK               $    63.15  $   83.97   $  74.30  $   29.53  $  62.49|   $ 41.45   $ 43.32  $ 45.70  $  51.64  $    45.47
------------------------------------------------------------------------------|----------------------------------------------------
                                                                              |
Heavy crude oil ($/bbl)                                                       |
   Sales price (2)       $    67.46  $   92.55   $ 97.20   $   38.21  $  73.62|   $ 41.24   $ 41.85  $ 48.10  $  43.06  $    43.66
   Royalties                   5.74      15.05     12.47        3.22      9.08|      4.96      4.98     6.00      4.95        5.23
   Production                                                                 |
     expenses                 14.50      16.65     18.05       14.68     15.95|     13.76     15.12    11.75     10.38       12.66
------------------------------------------------------------------------------|----------------------------------------------------
   NETBACK               $    47.22  $   60.85   $ 66.68   $   20.31  $  48.59|   $ 22.52   $ 21.75  $ 30.35  $  27.73  $    25.77
==============================================================================|====================================================
</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.


43                                            Canadian Natural Resources Limited

<PAGE>

NETBACKS
INFORMATION BY QUARTER

<TABLE>
<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(1)
Crude oil and NGLs ($/bbl)
   Sales price ((2))                                $    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 ((2))                                $     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(1)
   Light/Pelican Lake/NGLs ($/bbl)
   Sales price ((2))                                $    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 ((2))                                $    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>

(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.

Canadian Natural Resources Limited                                            44


<PAGE>

<TABLE>
<CAPTION>
                                              2008                                                        2007
                                                                    YEAR |                                              Year
                              Q1          Q2        Q3       Q4    ENDED |       Q1         Q2       Q3         Q4     Ended
-------------------------------------------------------------------------|---------------------------------------------------
SEGMENTED                                                                |
                                                                         |
NORTH AMERICA PRODUCT NETBACKS((1))                                      |
Light/Pelican Lake/NGLs ($/bbl)                                          |
   Sales price                                                           |
<C>                  <C>         <C>         <C>        <C>      <C>         <C>      <C>       <C>       <C>       <C>
((2))                $    82.25  $   107.38  $  102.17  $  44.21 $  84.00|   $ 54.13  $  56.06  $  60.26  $  63.94  $  58.66
   Royalties              16.40       21.68      21.29      8.80    17.20|      8.84      9.22     11.55     12.56     10.57
   Production                                                            |
     expenses             12.80       13.32      13.17     13.68    13.24|     11.74     12.11     11.58     10.82     11.56
-------------------------------------------------------------------------|---------------------------------------------------
   NETBACK           $    53.05  $    72.38  $   67.70  $  21.73 $  53.72|   $ 33.55  $  34.73  $  37.13  $  40.56  $  36.53
-------------------------------------------------------------------------|---------------------------------------------------
                                                                         |
Heavy crude oil ($/bbl)                                                  |
   Sales price                                                           |
((2))                $    67.46  $    92.55  $   97.20  $  38.21 $  73.62|   $ 41.24  $  41.85  $  48.10  $  43.06  $  43.66
   Royalties               5.74       15.05      12.47      3.22     9.08|      4.96      4.98      6.00      4.95      5.23
   Production                                                            |
     expenses             14.50       16.65      18.05     14.68    15.95|     13.76     15.12     11.75     10.38     12.66
-------------------------------------------------------------------------|---------------------------------------------------
   NETBACK           $    47.22  $    60.85  $   66.68  $  20.31 $  48.59|   $ 22.52  $  21.75  $  30.35  $  27.73  $  25.77
-------------------------------------------------------------------------|---------------------------------------------------
                                                                         |
Natural gas ($/mcf)                                                      |
   Sales price                                                           |
((2))                $     7.74  $     9.89  $    8.76  $   6.94 $   8.41|   $  7.79  $   7.47  $   5.88  $   6.31  $   6.87
   Royalties               1.36        1.88       1.55      1.09     1.47|      1.50      1.11      0.90      0.95      1.12
   Production                                                            |
     expenses              1.01        0.98       1.03      1.04     1.00|      0.95      0.87      0.87      0.90      0.90
-------------------------------------------------------------------------|---------------------------------------------------
   NETBACK           $     5.37  $     7.08  $    6.18  $   4.81 $   5.88|   $  5.34  $   5.49  $   4.11  $   4.46  $   4.85
-------------------------------------------------------------------------|---------------------------------------------------
                                                                         |
NORTH SEA PRODUCT NETBACKS((1))                                          |
Light crude oil ($/bbl)                                                  |
   Sales price                                                           |
((2))                $    99.01  $   129.57  $  109.82  $  63.07 $ 100.31|   $ 68.83  $  73.18  $  77.55  $  83.44  $  74.99
   Royalties               0.91        0.27       0.24      0.12     0.21|      0.13      0.13      0.14      0.19      0.14
   Production                                                            |
     expenses             22.35       25.61      29.21     28.77    26.29|     18.57     22.11     23.61     18.95     20.78
-------------------------------------------------------------------------|---------------------------------------------------
   NETBACK           $    76.47  $   103.69  $   80.37  $  34.18 $  73.81|   $ 50.13  $  50.94  $  53.80  $  64.30  $  54.07
-------------------------------------------------------------------------|---------------------------------------------------
                                                                         |
Natural Gas ($/mcf)                                                      |
   Sales price                                                           |
((2))                $     3.30  $     4.27  $    3.65  $   5.19 $   4.09|   $  4.49  $   3.92  $   5.26  $   3.62  $   4.26
   Royalties                  -           -          -         -        -|         -         -         -         -         -
   Production                                                            |
     expenses              2.33        2.68       3.09      1.96     2.51|      2.58      2.26      2.29      1.50      2.17
-------------------------------------------------------------------------|---------------------------------------------------
   NETBACK           $     0.97  $     1.59  $    0.56  $   3.23 $   1.58|   $  1.91  $   1.66  $   2.97  $   2.12  $   2.09
-------------------------------------------------------------------------|---------------------------------------------------
                                                                         |
OFFSHORE WEST AFRICA PRODUCT NETBACKS((1))                               |
Light crude oil ($/bbl)                                                  |
   Sales price                                                           |
((2))                $    96.31  $   114.56  $  125.71  $  65.80 $  97.96|   $ 58.60  $  72.84  $  70.52  $  81.89  $  71.68
   Royalties              17.43       14.49      26.90      4.71    14.81|      3.70      7.12      6.81      7.59      6.40
   Production                                                            |
     expenses              8.03        9.79       7.74     14.47    10.29|      8.93      7.98      7.00      9.32      8.32
-------------------------------------------------------------------------|---------------------------------------------------
   NETBACK           $    70.85  $    90.28  $   91.07  $  46.62 $  72.86|   $ 45.97  $  57.74  $  56.71  $  64.98  $  56.96
-------------------------------------------------------------------------|---------------------------------------------------
                                                                         |
Natural gas ($/mcf)                                                      |
   Sales price                                                           |
((2))                $     7.89  $     8.97  $   11.18  $  12.54 $  10.03|   $  5.97  $   6.22  $   5.31   $  5.49  $   5.68
   Royalties               1.43        1.13       2.24      1.26     1.52|      0.38      0.59      0.51      0.52      0.51
   Production                                                            |
     expenses              1.25        1.27       1.58      2.51     1.61|      1.48      1.10      1.39      1.89      1.48
-------------------------------------------------------------------------|---------------------------------------------------
   NETBACK           $     5.21  $     6.57  $    7.36  $   8.77 $   6.90|   $  4.11  $   4.53  $   3.41   $  3.08  $   3.69
=========================================================================|===================================================
</TABLE>

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


45                                            Canadian Natural Resources Limited


<PAGE>

<TABLE>
<CAPTION>
                                                                                      2006
                                                                                                                  Year
                                                              Q1            Q2           Q3           Q4         Ended
-----------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>           <C>           <C>          <C>          <C>
SEGMENTED
NORTH AMERICA PRODUCT NETBACKS((1))
Light/Pelican Lake/NGLs ($/bbl)
   Sales price ((2))                                 $     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 ((2))                                 $     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 ((2))                                 $      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((1))
Light crude oil ($/bbl)
   Sales price ((2))                                 $     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 ((2))                                 $      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((1))
Light crude oil ($/bbl)
   Sales price ((2))                                 $     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 ((2))                                 $      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>

(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.


Canadian Natural Resources Limited                                            46

<PAGE>

E.   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.

CAPITAL EXPENDITURES BY YEAR (1)

                                                      Year Ended Dec 31
                                                   |-----------|
($ millions)                                       |    2008   |       2007
---------------------------------------------------|-----------|--------------
Net property acquisitions (dispositions)((2))      |     336   |        (39)
Land acquisition and retention                     |      86   |         95
Seismic evaluations                                |     107   |        124
Well drilling, completion and equipping            |   1,664   |      1,642
Production and related facilities                  |   1,282   |      1,205
---------------------------------------------------|-----------|--------------
Total net reserve replacement expenditures         |   3,475   |      3,027
---------------------------------------------------|-----------|--------------
Horizon Project:                                   |           |
   Phase 1 construction costs                      |   2,732   |      2,740
   Phase 1 operating and capital inventory         |      87   |          -
   Phase 1 commissioning costs                     |     277   |          -
   Phase 2/3 costs                                 |     336   |        124
   Capitalized interest, stock-based               |           |
     compensation and other                        |     480   |        437
---------------------------------------------------|-----------|--------------
Total Horizon Project ((3))                        |   3,912   |      3,301
---------------------------------------------------|-----------|--------------
Midstream                                          |       9   |          6
Abandonments ((4))                                 |      38   |         71
Head office                                        |      17   |         20
---------------------------------------------------|-----------|--------------
TOTAL NET CAPITAL EXPENDITURES                     |   7,451   |      6,425
===================================================|===========|==============


47                                            Canadian Natural Resources Limited

<PAGE>

<TABLE>
<CAPTION>
CAPITAL EXPENDITURES BY QUARTER (1)

                                                                         2008 Three Months Ended
($ millions)                                          Mar 31            Jun 30               Sep 30             Dec 31
-----------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>             <C>                   <C>                <C>
Net property acquisitions (dispositions) ((2))      $    (8)        $     263               $    47            $    34
Land acquisition and retention                           12                24                    32                 18
Seismic evaluation                                       27                18                    40                 22
Well drilling, completion and equipping                 452               286                   421                505
Production and related facilities                       319               270                   311                382
-----------------------------------------------------------------------------------------------------------------------
Total net reserve replacement expenditures              802               861                   851                961
-----------------------------------------------------------------------------------------------------------------------
Horizon Project:
     Phase 1 construction costs                         665               875                   635                557
     Phase 1 operating and capital inventory             41                14                    27                  5
     Phase 1 commissioning costs                         49                34                    84                110
     Phase 2/3 costs                                     77                82                    83                 94
     Capitalized interest, stock-based
     compensation and other                             109               247                    46                 78
-----------------------------------------------------------------------------------------------------------------------
Total Horizon Project ((3))                             941             1,252                   875                844
-----------------------------------------------------------------------------------------------------------------------
Midstream                                                 1                 3                     2                  3
Abandonments ((4))                                        6                 7                    10                 15
Head office                                               3                 4                     6                  4
-----------------------------------------------------------------------------------------------------------------------
Total net capital expenditures                      $  1,753        $    2,127               $ 1,744            $ 1,827
=======================================================================================================================

<CAPTION>
CAPITAL EXPENDITURES BY QUARTER (1)


                                                                        2007 Three Months Ended
($ millions)                                          Mar 31            Jun 30               Sep 30              Dec 31
-----------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>             <C>                   <C>                <C>
Net property acquisitions (dispositions) ((2))      $     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 ((3))                              809               841                  819                 832
-----------------------------------------------------------------------------------------------------------------------
Midstream                                                  2                 -                    2                   2
Abandonments ((4))                                        20                13                   22                  16
Head office                                                5                 4                    3                   8
-----------------------------------------------------------------------------------------------------------------------
Total net capital expenditures                      $  2,009        $    1,460             $  1,442            $  1,514
=======================================================================================================================
</TABLE>

(1)  Net  capital  expenditures  exclude  adjustments  related  to  differences
     between carrying value and tax value, and other fair value adjustments.
(2)  Includes business combinations.
(3)  Net capital  expenditures  for the horizon project also include the impact
     of intersegment  eliminations.
(4)  Abandonments  represent expenditures to settle aro and have been reflected
     as capital expenditures in this table.


Canadian Natural Resources Limited                                            48

<PAGE>

F.   Developed and undeveloped acreage

The following table summarizes the Company's  working interest holdings in core
region developed and undeveloped acreage as at December 31, 2008:

<TABLE>
<CAPTION>
(thousands)                            Developed Acreage            Undeveloped Acreage              Total Acreage
--------------------------------------------------------------------------------------------------------------------------
                                  Gross Acres      Net Acres    Gross Acres     Net Acres      Gross Acres     Net Acres
--------------------------------------------------------------------------------------------------------------------------
<S>                                     <C>            <C>           <C>           <C>          <C>               <C>
North America
   Alberta                              6,249          4,955         10,185         8,675           16,434        13,630
   British Columbia                     1,470          1,100          3,007         2,200            4,477         3,300
   Saskatchewan                           799            578            828           715            1,627         1,293
   Manitoba                                 6              6             13            13               19            19
--------------------------------------------------------------------------------------------------------------------------
North Sea
   United Kingdom                         108             74            314           258              422           332
--------------------------------------------------------------------------------------------------------------------------
Offshore West Africa
   Cote d'Ivoire                            7              4             95            55              102            59
   Gabon                                    -              -            152           137              152           137
--------------------------------------------------------------------------------------------------------------------------
Total                                   8,639          6,717         14,594        12,053           23,233        18,770
==========================================================================================================================
</TABLE>

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 common share information)   |     2008   |       2007
----------------------------------------------------|------------|--------------
Revenues, before royalties                          |  $  16,173 |    $  12,543
Net earnings                                        |  $   4,985 |    $   2,608
Per common share - basic and diluted                |  $    9.22 |    $    4.84
Adjusted net earnings from operations               |  $   3,492 |    $   2,406
Per common share - basic and diluted                |  $    6.46 |    $    4.46
Cash flow from operations                           |  $   6,969 |    $   6,198
Per common share - basic and diluted                |  $   12.89 |    $   11.49
Total assets                                        |  $  42,650 |    $  36,114
Total long-term liabilities                         |  $  20,856 |    $  19,230
----------------------------------------------------|------------|-------------


<TABLE>
<CAPTION>
                                                           2008 Three Months Ended
($ millions, except per common share information)     Mar 31     Jun 30       Sep 30    Dec 31
-----------------------------------------------------------------------------------------------
<S>                                                <C>         <C>         <C>        <C>
Revenues, before royalties                         $   3,967   $  5,112    $   4,583  $  2,511
Net earnings (loss)                                $     727   $   (347)   $   2,835  $  1,770
Per common share - basic and diluted               $    1.35   $  (0.65)   $    5.25  $   3.27
===============================================================================================

</TABLE>

<TABLE>
<CAPTION>
                                                            2007 Three Months Ended
($ millions, except per common share information)     Mar 31     Jun 30      Sep 30     Dec 31
-----------------------------------------------------------------------------------------------
<S>                                                <C>         <C>         <C>        <C>
Revenues, before royalties                         $   3,118   $  3,152    $  3,073   $  3,200
Net earnings                                       $     269   $    841    $    700   $    798
Per common share - basic and diluted               $    0.50   $   1.56    $   1.30   $   1.48
===============================================================================================

</TABLE>


49                                           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 CCC 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  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                                            50

<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.

           2008 Monthly Historical Trading on Toronto Stock Exchange
Month                           High         Low       Close      Volume Traded
-------------------------------------------------------------------------------
   January                     $   75.99   $  58.88   $  64.21      44,123,518
   February                    $   76.00   $  60.17   $  73.76      48,238,701
   March                       $   76.80   $  64.00   $  70.27      42,059,186
   April                       $   88.36   $  68.08   $  85.55      44,070,800
   May                         $  106.87   $  81.50   $  97.24      50,814,542
   June                        $  111.30   $  94.73   $ 100.84      50,132,584
   July                        $  104.83   $  76.30   $  80.01      61,435,116
   August                      $   91.50   $  73.89   $  90.64      50,849,698
   September                   $   89.60   $  64.40   $  73.00      74,621,067
   October                     $   72.89   $  41.40   $  60.82      82,264,616
   November                    $   64.05   $  34.19   $  52.00      72,013,144
   December                    $   49.23   $  36.75   $  48.75      59,114,946
================================================================================

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.


51                                            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 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.

                                               |---------|
                                               |     2008|       2007      2006
-----------------------------------------------|---------|----------------------
                                               |         |
Cash dividends declared per common share       |  $  0.40|    $  0.34  $   0.30
===============================================|=========|======================


In  February  2009 the Board of  Directors  approved a 5%  increase in the 2008
quarterly  dividend  from  $0.10 per common  share to $0.105 per common  share,
effective with the April 1, 2009 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                                            52

<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.  Further detail on the Directors and Named Executive  Officers are
found in the Company's Management Proxy Circular dated March 18, 2009.

<TABLE>
<CAPTION>


NAME                         POSITION PRESENTLY HELD     PRINCIPAL OCCUPATION DURING PAST 5 YEARS
--------------------------------------------------------------------------------------------------------------------
<S>                          <C>                         <C>
Catherine M. Best, FCA       Director (2)(4)             Interim  Chief   Financial   Officer  of  Alberta   Health
Calgary, Alberta             (age 55)                    Services   since   2008   when  the   Alberta   government
Canada                                                   consolidated  all of the health  regions  of the  province
                                                         under one board. Executive Vice-President, Risk Management
                                                         and Chief  Financial  Officer of the Calgary Health Region
                                                         (fully integrated publicly funded health care system) from
                                                         2002 to 2008; 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 and is a  volunteer  member of the Audit
                                                         Committee of the Calgary Exhibition and Stampede.

N. Murray Edwards            Vice-Chairman and           President,   Edco   Financial   Holdings   Ltd.   (private
Calgary/Banff, Alberta       Director (3)                management   and   consulting    company).    Has   served
Canada                       (age 49)                    continuously  as a director of the Company since September
                                                         1988.  Currently  is  Chairman and 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
P.C., O.M.                   (age 66)                    firm).  Has  served  continuously  as a  director  of  the
Winnipeg, Manitoba                                       Company  since  February  2006.  Currently  serving on the
Canada                                                   board of directors of MTS Allstream  Inc.,  Arctic Glacier
                                                         Income Trust,  Exchange Industrial Income Fund, Wellington
                                                         West Capital Inc. and FWS Construction  Inc. and serves as
                                                         Chair  of  Canada's   Security  and  Intelligence   Review
                                                         Committee.

Ambassador Gordon D. Giffin  Director (1)(2)             Senior  Partner,  McKenna  Long & Aldridge  LLP (law firm)
Atlanta, Georgia             (age 59)                    since May 2001. Has served  continuously  as a director of
USA                                                      the  Company  since May  2002.  Currently  serving  on the
                                                         board of directors of Canadian  National  Railway Company,
                                                         Canadian   Imperial  Bank  of  Commerce,   Ontario  Energy
                                                         Savings Corp., and Transalta Corporation.

John G. Langille             Vice-Chairman and Director  Officer  of the  Company.  Has  served  continuously  as a
Calgary, Alberta             (age 63)                    director of the Company since June 1982.
Canada

Steve W. Laut                President and Chief         Officer  of the  Company.  Has  served  continuously  as a
Calgary, Alberta             Operating Officer and       director of the Company since August 2006.
Canada                       Director
                             (age 51)

Keith A.J. MacPhail          Director (3)(5)             Chairman and Chief  Executive  Officer,  Bonavista  Energy
Calgary, Alberta             (age 52)                    Trust (oil and gas energy  trust) since  November 1997 and
Canada                                                   Chairman,   NuVista   Energy   Ltd.   (an   oil   and  gas
                                                         exploration,  development  and  production  company) since
                                                         July 2003.  Has served  continuously  as a director of the
                                                         Company since October 1993. Currently serving on the board
                                                         of directors of Bonavista  Energy Trust and NuVista Energy
                                                         Ltd.

Allan P. Markin, O.C.        Chairman and Director (5)   Chairman  of the  Company.  Has served  continuously  as a
Calgary, Alberta             (age 63)                    director of the Company since January 1989.
Canada

</TABLE>


53                                            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)          Independent    businessman.    Prior   thereto   Executive
Calgary, Alberta             (age 63)                    Vice-President,  Petro-Canada  from  1995 to 2002 and most
Canada                                                   recently President,  Petro-Canada 2002 to 2004. Has served
                                                         continuously as a director of the Company since July 2005.
                                                         Currently  is  Chairman  and is serving on the board of of
                                                         directors of Petro Andina Resources Inc.

Frank J. McKenna, P.C.,      Director (1)(4)             Deputy  Chair,   TD  Bank   Financial   Group   (financial
O.C.,                        (age 61)                    services).  Counsel to  Atlantic  Canada law firm  McInnes
O.N.B., Q.C.                                             Cooper  from  1998 to  2005,  and most  recently  Canadian
Cap Pele, New Brunswick                                  Ambassador  to the United States from 2005 to 2006. He has
Canada                                                   served  continuously  as a director of the  Company  since
                                                         August  2006.  Currently serving on the board of directors
                                                         ofBrookfield Asset Management Inc.

James S. Palmer, C.M.,       Director (3)(4)(5)          Chairman  and a Partner of Burnet,  Duckworth & Palmer LLP
A.O.E., Q.C.                 (age 80)                    (law firm).  Has served  continuously as a director of the
Calgary, Alberta                                         Company since May 1997.  Currently serving on the board of
Canada                                                   directors  of  Magellan   Aerospace   Corporation  and  is
                                                         Director Emeritus of Frontier Oil Corporation.

Dr. Eldon R. Smith, O.C.,    Director (4)(5)             President of Eldon R. Smith & Associates  Ltd.,(a  private
M.D.                         (age 69)                    health care consulting  company),  and Emeritus  Professor
Calgary, Alberta                                         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.,  Aston  Hill  Financial  and
                                                         Ventripoint Diagnostics Inc.

David A. Tuer                Director (1)(2)(3)          Vice-Chairman  and Chief Executive Officer of Marble Point
Calgary, Alberta             (age 59)                    Energy Ltd.  (private  oil and gas  exploration  company);
Canada                                                   Chairman,  Calgary  Health  Region  from  2001 to 2008 and
                                                         Executive  Vice-Chairman BA Energy Inc. from April 2005 to
                                                         February  2008 when it was acquired by its parent  company
                                                         Value  Creations Inc.  through a Plan of  Arrangement  and
                                                         which  until  recently  was  engaged  in the  development,
                                                         building and  operations of a merchant  heavy oil upgrader
                                                         in Northern  Alberta for the purpose of upgrading  bitumen
                                                         and heavy oil  feedstock  into  high-quality  crude  oils.
                                                         Prior  thereto  President,  CEO and a  director  of Hawker
                                                         Resources Inc. from January 2003 to March 2005. Has served
                                                         continuously  as a director of the Company since May 2002.
                                                         Currently  serving on the board of  directors  of 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 58)

Real J. H. Doucet            Senior Vice-President,      Officer of the Company.
Calgary, Alberta             Oil Sands
Canada                       (age 56)

Allen M. Knight              Senior Vice-President,      Officer of the Company.
Calgary, Alberta             International & Corporate
Canada                       Development
                             (age 59)

Tim S. McKay                 Senior Vice-President,      Officer of the Company.
Calgary, Alberta             Operations
Canada                       (age 47)

</TABLE>

Canadian Natural Resources Limited                                            54

<PAGE>

<TABLE>
<CAPTION>


NAME                         POSITION PRESENTLY HELD     PRINCIPAL OCCUPATION DURING PAST 5 YEARS
--------------------------------------------------------------------------------------------------------------------
<S>                          <C>                         <C>
Douglas A. Proll             Chief Financial Officer     Officer of the Company.
Calgary, Alberta             and Senior Vice-President,
Canada                       Finance
                             (age 58)

Lyle G. Stevens              Senior Vice-President,      Officer of the Company.
Calgary, Alberta             Exploitation
Canada                       (age 54)

Jeffrey W. Wilson            Senior Vice-President,      Officer of the Company.
Calgary, Alberta             Exploration
Canada                       (age 56)

Jeffrey J. Bergeson          Vice-President,             Officer  of the  Company  since  May 2007;  prior  thereto
Calgary, Alberta             Exploitation West           Exploitation Manager of the Company.
Canada                       (age 52)

Corey B. Bieber              Vice-President, Finance     Officer of the Company  since April  2005;  prior  thereto
Calgary, Alberta             and Investor Relations      Director,  Investor  Relations  of the  Company  from July
Canada                       (age 45)                    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 50)

William R. Clapperton        Vice-President,             Officer of the Company.
Calgary, Alberta             Regulatory, Stakeholder
Canada                       and Environmental Affairs
                             (age 46)

James F. Corson              Vice-President,             Officer of the Company since  January 2007;  prior thereto
Calgary, Alberta             Human Resources, Horizon    Vice-President,  Human  Resources of Qatar Petroleum Corp.
Canada                       (age 58)                    from  March 1997 to July 2005 and most  recently  Director
                                                         Human  Resources  and Stakeholder Relations of the Company
                                                         from July 2005 to 2007.

Randall S. Davis             Vice-President,             Officer of the  Company  since July  2004;  prior  thereto
Calgary, Alberta             Finance & Accounting        Financial  Controller  of the  Company  from  July 2002 to
Canada                       (age 42)                    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
Calgary, Alberta             Production, Central         Manager  Midstream for Anadarko  Canada  Corporation  from
Canada                       (age 52)                    November  1998  to  March  2005,   Manager   Facilities  &
                                                         Construction  for Anadarko Canada  Corporation  from April
                                                         2005  to  November  2006,  and  most  recently  Production
                                                         Manager,  Edson of the Company from November 2006 to March
                                                         2007.

Peter J. Janson               Vice-President,            Officer of the Company since December 2004;  prior thereto
Calgary, Alberta              Engineering Integration    Director,  Engineering Integration  of  the  Company  from
Canada                        (age 51)                   November 2002 to December 2004.

Philip A. Keele              Vice-President,             Officer of the Company since December 2004;  prior thereto
Calgary, Alberta             Mining,                     Director,  Mine  Engineering of the Company from September
Canada                       Horizon Oil Sands Project   2002 to December 2004.
                             (age 49)

</TABLE>


55                                           Canadian Natural Resources Limited

<PAGE>

<TABLE>
<CAPTION>
NAME                         POSITION PRESENTLY HELD     PRINCIPAL OCCUPATION DURING PAST 5 YEARS
--------------------------------------------------------------------------------------------------------------------
<S>                          <C>                         <C>
Cameron S. Kramer            Vice-President,             Officer of the Company.
Calgary, Alberta             Development Operations
Canada                       (age 41)

Ronald K. Laing              Vice-President, Commercial  Officer of the Company  since March  2009;  prior  thereto
Calgary, Alberta             Operations                  Commercial   Operations   Advisor  of  the  Company   from
Canada                       (age 39)                    November 2003 to April 2004,  and most  recently  Manager,
                                                         Commercial  Operations  of the Company  from April 2004 to
                                                         March 2009.

Leon Miura                   Vice-President,             Officer of the Company.
Calgary, Alberta             Horizon Major Projects
Canada                       (age 54)

Reno G. Laseur               Vice-President,             Officer of the Company  since August 2008;  prior  thereto
Fort McMurray, Alberta       Upgrading                   Operations  Manager,  Upgrading  of the  Company  November
Canada                       (age 53)                    2002  to  October  2007,  and  most  recently   Operations
                                                         Director,  Upgrading  of the Company  from October 2007 to
                                                         August 2008.

S. John Parr                 Vice-President,             Officer of the Company  since  April  2004;  prior thereto
Calgary, Alberta             Production, East            Production Manager,  Heavy Oil  of  th e Company from July
Canada                       (age 47)                    2002 to April 2004.

David A. Payne               Vice-President,             Officer of the Company since  October 2004;  prior thereto
Calgary, Alberta             Exploitation, Central       Exploitation  Manager,  Technical  Projects of the Company
Canada                       (age 47)                    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
Calgary, Alberta             Production, West            Production Manager, West of the Company.
Canada                       (age 42)

Timothy G. Reed              Vice-President,             Officer of the Company since  January 2007;  prior thereto
Calgary, Alberta             Human Resources             Manager,  Human  Resources of the Company 2000 to 2005 and
Canada                       (age 52)                    most recently  Director,  Human  Resources 2005 to January
                                     2007.
Joy P. Romero                Vice President,             Officer of the Company  since March  2008;  prior  thereto
Calgary, Alberta             Bitumen Production          Director,  Bitumen  Production Process of the Company from
Canada                       (age  52)                   September 2002 to March 2008.

Sheldon L. Schroeder         Vice-President,             Officer of the Company  since April  2004;  prior  thereto
Fort McMurray, Alberta       Project Control             Director,  Project  Control of the Company from  September
Canada                       (age 41)                    2002 to April 2004.

Kendall W. Stagg             Vice-President,             Officer of the Company since  October 2004;  prior thereto
Calgary, Alberta             Exploration, West           Manager  Exploration,  B. C. of the Company from June 2002
Canada                       (age 47)                    to September 2004.

Scott G. Stauth              Vice-President,             Officer of the Company since November 2006;  prior thereto
Calgary, Alberta             Field Operations            Manager,  Eastern  Field  Operations  of the Company April
Canada                       (age 51)                    2003 to November 2006.

Stephen C. Suche             Vice-President,             Officer of the  Company  since July  2006;  prior  thereto
Calgary, Alberta             Information and             Manager  Information and Corporate Services of the Company
Canada                       Corporate Services          January 2000 to July 2006.
                             (age 49)
</TABLE>

Canadian Natural Resources Limited                                            56

<PAGE>

<TABLE>
<CAPTION>
NAME                         POSITION PRESENTLY HELD     PRINCIPAL OCCUPATION DURING PAST 5 YEARS
--------------------------------------------------------------------------------------------------------------------
<S>                          <C>                         <C>
Domenic Torriero             Vice-President,             Officer of the Company since November 2006;  prior thereto
Calgary, Alberta             Exploration, Central        Vice-President   Geology  and   Geophysics   of  Petrovera
Canada                       (age 44)                    Resources  Limited  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
Calgary, Alberta             Exploration, East           Manager,  Exploration  Heavy  Oil of the  Company  October
Canada                       (age 51)                    2003 to April 2007.

Daryl G. Youck               Vice-President,             Officer of the Company since February 2008;  prior thereto
Calgary, Alberta             Exploitation, East          Manager,   Exploitation   of  the  Company  July  2002  to
Canada                       (age 40)                    February 2008.

Lynn M. Zeidler              Vice-President,             Officer of the Company.
Calgary, Alberta             Utilities and Services
Canada                       (age 52)

Bruce E. McGrath             Corporate Secretary         Officer of the Company.
Calgary, Alberta             (age 59)
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 meeting of shareholders held on May 8, 2008.

As at December 31, 2008, 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  6% after the exercise of options  held by them  pursuant to the
Company's stock option plan).


57                                            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.  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                                            58




<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  National 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 2008 approved  specified audit
and non-audit services to be performed by  PricewaterhouseCoopers  LLP ("PwC").
The  services  provided  include:  (i) the  annual  audit of the  Corporation's
internal  controls  and  December 31, 2008  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                                 |     2008     |      2007
------------------------------------------------|--------------|---------------
Audit fees                                      | $  2,685,800 |  $  2,729,315
Audit related fees                              |      156,300 |       164,000
Tax related fees                                |       91,500 |       154,459
All other fees                                  |        9,500 |         9,440
------------------------------------------------|--------------|---------------
                                                | $  2,943,100 |  $  3,057,214
================================================|==============|===============


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


59                                            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  March 4, 2009 in
respect of the Company's  consolidated  financial  statements with accompanying
notes as at and for the three years ended  December 31, 2008 and the  Company's
internal   control   over   financial   reporting  as  at  December  31,  2008.
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 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,  Director  nominees  standing for re-election,
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 18, 2009 in connection  with the Annual General Meeting of
Shareholders of Canadian Natural to be held on May 7, 2009 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,
2008  found on pages 40 to 73,  74 to 100 and 101 to 105  respectively,  of the
2008 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                                            60

<PAGE>


                                  SCHEDULE "A"
                                 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, 2008.
     The reserves data consist of the following:

     (a)  (i)   proved   conventional  crude  oil,  NGLs and natural gas reserve
                quantities  estimated  as at December  31,  2008 using  constant
                prices and costs;

          (ii)  the related future net revenue; and

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

     (b)  (i)   both proved, and proved and probable conventional crude oil,NGL
                and natural gas reserve quantities  estimated as at December 31,
                2008 using forecast prices and costs;

          (ii)  the related future net revenue; and,

     (c)  (i)   both  proved,  and  proved  and  probable  synthetic  crude  oil
                reserves and associated bitumen  quantities  relating to surface
                mineable oil sands operations estimated as at December 31, 2008.

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.

     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").

3.   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 in the
     COGE Handbook, the FASB Standards and the SEC Requirements.


61                                            Canadian Natural Resources Limited

<PAGE>


4.   The following  table sets forth the estimated  future net revenue  (before
     deduction of income taxes)  attributed  to proved plus probable  reserves,
     estimated using forecast 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, 2008 and  identifies  the
     respective  portions thereof that we have evaluated and reported on to the
     Corporation's management and board of directors:

<TABLE>
<CAPTION>

     ------------------------------------------------------------------------------------------------------------------------------
     INDEPENDENT
     QUALIFIED
     RESERVES         DESCRIPTION AND                  LOCATION OF RESERVES         NET PRESENT VALUE OF FUTURE NET REVENUE
     EVALUATOR OR     PREPARATION DATE OF              (COUNTRY OR FOREIGN          (BEFORE INCOME TAXES, 10% DISCOUNT RATE)
     AUDITOR          EVALUATION REPORT                 GEOGRAPHIC AREA)            ($MILLIONS)
     ------------------------------------------------------------------------------------------------------------------------------
                                                                                     AUDITED    EVALUATED     REVIEWED       TOTAL
     ------------------------------------------------------------------------------------------------------------------------------
<S>                   <S>                              <S>                           <C>        <C>            <C>        <C>
     Sproule          Sproule Evaluated the P&NG       Canada and USA                    $ 0     $ 40,841          $ 0    $ 40,841
     Associates       Reserves as reported February
     Limited          17th, 2009.
     ------------------------------------------------------------------------------------------------------------------------------
     Sproule          Sproule Evaluated the P&NG       United Kingdom and                $ 0     $ 11,929          $ 0    $ 11,929
     Associates       Reserves as reported February
     Limited          17th, 2009.                      Offshore West Africa
     ------------------------------------------------------------------------------------------------------------------------------
       TOTALS                                                                            $ 0     $ 52,770          $ 0    $ 52,770
     ==============================================================================================================================

</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, 2008.  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
     Corporation's conventional crude oil and natural gas activities.

5.   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.

6.   We have no responsibility to update our reports referred to in paragraph 4
     for events and circumstances  occurring after their respective preparation
     dates.

7.   Because the reserves data are based on judgements regarding future events,
     actual results will vary and the variations may be material.  However, any
     variations   should  be  consistent   with  the  fact  that  reserves  are
     categorized according to the probability of their recovery.


Canadian Natural Resources Limited                                            62

<PAGE>

Executed as to our report referred to above:

         SPROULE ASSOCIATES LIMITED, CALGARY, ALBERTA, CANADA, FEBRUARY 25, 2009

         Original Signed By:

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

         Original Signed By:

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


         Original Signed By:

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

         GLJ PETROLEUM CONSULTANTS, CALGARY, ALBERTA, CANADA, FEBRUARY 24, 2009

         Original Signed By:


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


63                                            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 oil, 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, 2008 using  constant  prices
           and costs;

     (ii)  the related future net revenue; and

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

(b)  (i)   both  proved, and  proved  and  probable  conventional crude oil, NGL
           and natural gas reserve quantities  estimated as at December 31, 2008
           using forecast prices and costs;

     (ii)  the related future net revenue; and,

(c)  (i)  both  proved,  and  proved and  probable synthetic crude oil reserves
          and associated  bitumen  quantities  relating to surface mineable oil
          sands operations estimated as at December 31, 2008.

Sproule Associates Limited and GLJ Petroleum Consultants, both 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 affected the ability of the independent
     qualified  reserves  evaluators to report without  reservation  and in the
     event  of  a  proposal  to  change  the  independent   qualified  reserves
     evaluators,  to  inquire  whether  there  had been  disputes  between  the
     previous independent qualified reserves evaluators and management; 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 oil,
gas and surface mineable oil sands 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 Form
     51-101F1  containing reserves data and other oil, gas and surface mineable
     oil sands information;

(b)  the  filing  of Form  51-101F2  which  is the  report  of the  independent
     qualified reserves evaluators on the reserves data; and

(c)  the content and filing of this report.

Because the reserves data are based on judgments regarding future events,
actual results will vary and the variations may be material. However, any
variations should be consistent with the fact that reserves are categorized
according to the probability of their recovery.


Canadian Natural Resources Limited                                            64

<PAGE>



Original Signed By:


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


Original Signed By:


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


Original Signed By:


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


Original Signed By:


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


Dated this 3rd day of March, 2009
Calgary, Alberta


65                                            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.   Although   the  Audit   Committee   has  the   powers   and
     responsibilities  set  forth  in  this  Charter,  the  role  of the  Audit
     Committee  is  oversight.   The  Audit  Committee's   primary  duties  and
     responsibilities are to:

     1.   ensure that the  Corporation's  management  implemented  an effective
          system of internal controls over financial reporting;

     2.   monitor and  oversee 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,  qualifications  and  performance  of the
          Corporation's  independent  auditors  and  oversee  the  audit of the
          Corporation's financial statements;

     5.   monitor the performance of the internal audit function;

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

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

II.  Audit Committee Composition, Procedures and Organization

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


Canadian Natural Resources Limited                                            66

<PAGE>

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

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

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

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

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

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

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

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

III. Audit Committee Duties and Responsibilities

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

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

          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 implemented
               and is maintaining an effective system of internal controls over
               financial reporting;

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


67                                            Canadian Natural Resources Limited

<PAGE>

          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  review  and  discuss  with  management  and the  independent
               auditors  prior to the annual  audit the  independent  auditor's
               annual audit plan,  including  scope,  staffing,  locations  and
               reliance  upon  management  and internal  audit  department  and
               oversee the audit of the Corporation's financial statements;

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

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

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

               (i)  contents of their report, including :

                    (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.


Canadian Natural Resources Limited                                            68

<PAGE>

          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 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  (including  financial 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 extent to which  recommendations made
               by the internal audit staff or by the independent  auditors have
               been implemented.

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

          a.   to review and discuss with management,  the internal audit group
               and  the  independent  auditors,  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 and discuss with management,  the internal audit group
               and the independent  auditors,  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;


69                                            Canadian Natural Resources Limited

<PAGE>


          d.   to  review  management's  report on 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.


Canadian Natural Resources Limited                                            70



<PAGE>

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

<TABLE>
<CAPTION>
<S>                                                                     <C>
SPECIAL NOTE REGARDING
FORWARD-LOOKING STATEMENTS

     Certain   statements  in  this  document  or  documents            results,  performance or achievements  expressed or implied
     incorporated    herein    by    reference    constitute            by such forward-looking  statements.  Such factors include,
     forward-looking statements or information (collectively            among  others:  general  economic and  business  conditions
     referred  to  herein as  "forward-looking  statements")            which  will,  among  other  things,  impact  demand for and
     within   the   meaning   of    applicable    securities            market prices of the Company's products;  volatility of and
     legislation.    Forward-looking   statements   can   be            assumptions  regarding  crude oil and  natural  gas prices;
     identified  by  the  words   "believe",   "anticipate",            fluctuations in currency and interest rates; assumptions on
     "expect",  "plan",  "estimate",  "target",  "continue",            which the  Company's  current  guidance is based;  economic
     "could",   "intend",  "may",  "potential",   "predict",            conditions  in the  countries  and  regions  in  which  the
     "should", "will", "objective",  "project",  "forecast",            Company conducts business; political uncertainty, including
     "goal",  "guidance",   "outlook",   "effort",  "seeks",            actions of or against terrorists, insurgent groups or other
     "schedule"   or   expressions   of  a  similar   nature            conflict  including   conflict  between  states;   industry
     suggesting  future  outcome or statements  regarding an            capacity;  ability of the Company to implement its business
     outlook.   Disclosure   related  to   expected   future            strategy, including exploration and development activities;
     commodity  pricing,   production  volumes,   royalties,            impact of competition;  the Company's  defense of lawsuits;
     operating  costs,  capital   expenditures,   and  other            availability  and  cost  of  seismic,  drilling  and  other
     guidance   provided    throughout   this   Management's            equipment;  ability of the Company and its  subsidiaries to
     Discussion   and  Analysis   ("MD&A")   including   the            complete   capital   programs;   the   Company's   and  its
     information   in  the   "outlook"   section   and   the            subsidiaries' ability to secure adequate transportation for
     sensitivity    analysis   constitute    forward-looking            its products; unexpected difficulties in mining, extracting
     statements.  Disclosure  of plans  relating to existing            or upgrading  the  Company's  bitumen  products;  potential
     and future  developments,  including but not limited to            delays or changes in plans with respect to  exploration  or
     the Horizon Project, Primrose East, Pelican Lake, Gabon            development  projects or capital  expenditures;  ability of
     Offshore  West Africa,  and the Kirby Oil Sands Project            the Company to attract  the  necessary  labour  required to
     also  constitute   forward-looking   statements.   This            build its thermal and oil sands mining projects;  operating
     forward-looking  information is based on annual budgets            hazards and other difficulties  inherent in the exploration
     and multi-year  forecasts,  and is reviewed and revised            for and  production  and sale of crude oil and natural gas;
     throughout  the year if  necessary  in the  context  of            availability  and cost of financing;  the Company's and its
     targeted  financial  ratios,  project returns,  product            subsidiaries'   success  of  exploration   and  development
     pricing  expectations  and balance in project  risk and            activities  and their  ability to replace and expand  crude
     time horizons.  These  statements are not guarantees of            oil  and  natural  gas  reserves;  timing  and  success  of
     future performance and are subject to certain risks and            integrating   the  business  and   operations  of  acquired
     the reader  should not place  undue  reliance  on these            companies;   production  levels;   imprecision  of  reserve
     forward-looking   statements   as   there   can  be  no            estimates and estimates of recoverable  quantities of crude
     assurances that the plans,  initiatives or expectations            oil,  bitumen,   natural  gas  and  liquids  not  currently
     upon which they are based will occur.                              classified as proved; actions by governmental  authorities;
                                                                        government  regulations  and the  expenditures  required to
     In  addition,  statements  relating to  "reserves"  are            comply with them (especially  safety and environmental laws
     deemed to be forward-looking statements as they involve            and   regulations   and  the  impact  of   climate   change
     the implied  assessment based on certain  estimates and            initiatives   on  capital  and  operating   costs);   asset
     assumptions   that  the  reserves   described   can  be            retirement  obligations;  the  adequacy  of  the  Company's
     profitably  produced in the future.  There are numerous            provision  for  taxes;  and other  circumstances  affecting
     uncertainties  inherent  in  estimating  quantities  of            revenues and expenses.  The Company's operations have been,
     proved  crude  oil  and  natural  gas  reserves  and in            and  in  the  future   may  be,   affected   by   political
     projecting future rates of production and the timing of            developments and by federal,  provincial and local laws and
     development expenditures. The total amount or timing of            regulations such as restrictions on production,  changes in
     actual future  production may vary  significantly  from            taxes,  royalties and other amounts  payable to governments
     reserve and production estimates.                                  or governmental agencies,  price or gathering rate controls
                                                                        and  environmental  protection  regulations.  Should one or
     The  forward-looking  statements  are based on  current            more of these risks or uncertainties materialize, or should
     expectations,  estimates and projections about Canadian            any of the Company's  assumptions  prove incorrect,  actual
     Natural  Resources  Limited  (the  "Company")  and  the            results may vary in material  respects from those projected
     industry  in which the  Company  operates,  which speak            in the  forward-looking  statements.  The impact of any one
     only as of the date such  statements were made or as of            factor on a  particular  forward-looking  statement  is not
     the date of the  report or  document  in which they are            determinable  with  certainty as such factors are dependent
     contained,  and are subject to known and unknown risks,            upon  other  factors,  and the  Company's  course of action
     uncertainties  and other  factors  that could cause the            would depend upon its assessment of the future  considering
     actual  results,  performance  or  achievements  of the            all information then available.  For additional information
     Company  to be  materially  different  from any  future            refer to the  "Risks  and  Uncertainties"  section  of this
                                                                        MD&A.
</TABLE>
40 CANADIAN NATURAL
<PAGE>
<TABLE>
<S>                                                                    <C>
     Readers  are  cautioned  that  the  foregoing  list  of            oil to estimate  relative energy  content.  This conversion
     factors  is not  exhaustive.  Unpredictable  or unknown            may be  misleading,  particularly  when used in  isolation,
     factors not  discussed  in this report  could also have            since  the  6  mcf:1  bbl  ratio  is  based  on  an  energy
     material adverse effects on forward-looking statements.            equivalency  at the burner tip and does not  represent  the
     Although  the Company  believes  that the  expectations            value equivalency at the wellhead.  Production  volumes are
     conveyed   by  the   forward-looking   statements   are            the  Company's  interest  before  royalties,  and  realized
     reasonable based on information  available to it on the            prices are net of  transportation  and  blending  costs and
     date  such  forward-looking  statements  are  made,  no            exclude  the  effect  of risk  management  activities.  The
     assurances can be given as to future results, levels of            following  discussion and analysis refers  primarily to the
     activity    and     achievements.     All    subsequent            Company's 2008 financial results compared to 2007 and 2006,
     forward-looking  statements,  whether  written or oral,            unless otherwise indicated.  In addition, this MD&A details
     attributable  to the  Company or persons  acting on its            the Company's capital program and outlook for 2009.
     behalf are  expressly  qualified  in their  entirety by
     these cautionary statements. Except as required by law,            Additional  information relating to the Company,  including
     the   Company   assumes   no   obligation   to   update            its  quarterly  MD&A for the year and  three  months  ended
     forward-looking   statements  should  circumstances  or            December 31, 2008 and its Annual  Information  Form for the
     Management's estimates or opinions change.                         year ended  December  31,  2008,  is  available on SEDAR at
                                                                        www.sedar.com.
SPECIAL NOTE REGARDING
NON-GAAP FINANCIAL MEASURES                                             This MD&A is dated March 4, 2009.

     Management's    Discussion   and   Analysis    includes            ABBREVIATIONS
     references to financial  measures  commonly used in the
     crude oil and  natural gas  industry,  such as adjusted              ACC .................Anadarko Canada Corporation
     net earnings from operations, cash flow from operations              AECO ................Alberta natural gas reference
     and net asset value.  These financial  measures are not                                   location
     defined by generally accepted accounting  principles in              API .................Specific gravity measured in degrees
     Canada  ("GAAP")  and  therefore  are  referred  to  as                                   on the American Petroleum Institute
     non-GAAP  measures.  The non-GAAP  measures used by the                                   scale
     Company  may  not be  comparable  to  similar  measures              ARO .................Asset retirement obligations
     presented  by other  companies.  The Company uses these              bbl .................barrels
     non-GAAP  measures to  evaluate  its  performance.  The              bbl/d ...............barrels per day
     non-GAAP   measures   should  not  be   considered   an              bcf .................billion cubic feet
     alternative to or more meaningful than net earnings, as              boe .................barrels of oil equivalent
     determined  in  accordance  with  Canadian  GAAP, as an              boe/d ...............barrels of oil equivalent per day
     indication of the Company's  performance.  The non-GAAP              Brent ...............Dated Brent
     measures adjusted net earnings from operations and cash              C$ ..................Canadian dollars
     flow from operations are reconciled to net earnings, as              CICA ................Canadian Institute of Chartered
     determined  in accordance  with  Canadian  GAAP, in the                                   Accountants
     "Financial   Highlights"  section  of  this  MD&A.  The              CO2 .................Carbon dioxide
     Company also presents certain non-GAAP financial ratios              CO2e ................Carbon dioxide equivalents
     and their  derivation  in the  "Liquidity  and  Capital              Canadian GAAP .......Generally accepted accounting
     Resources" section of this MD&A.                                                          principles in Canada
                                                                          FPSO ................Floating Production, Storage and
MANAGEMENT'S DISCUSSION AND ANALYSIS                                                           Offtake Vessel
                                                                          GHG .................Greenhouse Gas
     Management's  Discussion  and Analysis of the financial              GJ ..................gigajoules
     condition  and  results of  operations  of the  Company              GJ/d ................gigajoules per day
     should  be  read  in  conjunction  with  the  Company's              Heavy
     audited  consolidated  financial statements and related              Differential ........Heavy crude oil differential from
     notes  for  the  year  ended  December  31,  2008.  The                                   WTI
     consolidated financial statements have been prepared in              Horizon Project .....Horizon Oil Sands Project
     accordance   with   generally    accepted    accounting              LIBOR ...............London Interbank Offered Rate
     principles    in   Canada    ("Canadian    GAAP").    A              mcf .................thousand cubic feet
     reconciliation  of Canadian GAAP to generally  accepted              mmbbl ...............million barrels
     accounting  principles in the United States ("US GAAP")              mmbtu ...............million British thermal units
     is  included in note 18 to the  consolidated  financial              mmcf/d ..............million cubic feet per day
     statements.   All  dollar  amounts  are  referenced  in              NGLs ................Natural gas liquids
     Canadian  dollars,  except where otherwise  noted.  The              NYMEX ...............New York Mercantile Exchange
     calculation  of  barrels of oil  equivalent  ("boe") is              NYSE ................New York Stock Exchange
     based on a conversion  ratio of six thousand cubic feet              PRT .................Petroleum Revenue Tax
     ("mcf") of natural  gas to one barrel  ("bbl") of crude              SCO .................Synthetic light crude oil
                                                                          SEC .................United States Securities and
                                                                                               Exchange Commission
                                                                          TSX .................Toronto Stock Exchange
                                                                          UK ..................United Kingdom
                                                                          US ..................United States
                                                                          US GAAP .............Generally accepted accounting
                                                                                               principles in the United States
                                                                          US$ .................United States dollars
                                                                          WCS .................Western Canadian Select
                                                                          WTI .................West Texas Intermediate
</TABLE>
                                                             CANADIAN NATURAL 41
<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  these  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  fundamental to the Company.
      By consistently  controlling costs throughout all cycles of the industry,
      the Company believes 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  a strong  balance  sheet and
      flexible  capital  structure.  The  Company  believes  it has  built  the
      necessary  financial  capacity  to complete  all of its growth  projects,
      including the Horizon Project and its conventional  crude oil and natural
      gas  opportunities.  Additionally,  the Company's risk  management  hedge
      program  reduces the risk of volatility in commodity  prices and supports
      the Company's cash flow for its capital expenditures programs.

      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, 2008 include the following:
      o     Achieved record levels of net earnings,  adjusted net earnings from
            operations, and cash flow from operations;
      o     Achieved annual crude oil and natural gas production guidance;
      o     Completed the  construction  of and achieved first  production from
            the Primrose East Expansion;
      o     Completed  drilling and brought  three wells back on  production at
            the Baobab Field, Cote d'Ivoire;
      o     Development  continued  on the Olowi Field in  offshore  Gabon with
            first oil targeted for Spring 2009;
      o     Substantially  completed  construction  of  Phase 1 of the  Horizon
            Project; and
      o     Increased dividends per common share.

NET EARNINGS AND CASH FLOW FROM OPERATIONS
Financial Highlights

<TABLE>
      ($ millions, except per common share amounts)                    2008|        2007         2006
---------------------------------------------------------------------------|-------------------------
      <S>                                                        <C>          <C>         <C>
     Revenue, before royalties                                   $   16,173|  $   12,543  $    11,643
     Net earnings                                                $    4,985|  $    2,608  $     2,524
        Per common share - basic and diluted                     $     9.22|  $     4.84  $      4.70
     Adjusted net earnings from operations(1)                    $    3,492|  $    2,406  $     1,664
        Per common share - basic and diluted                     $     6.46|  $     4.46  $      3.10
     Cash flow from operations (2)                               $    6,969|  $    6,198  $     4,932
        Per common share - basic and diluted                     $    12.89|  $    11.49  $      9.18
     Dividends declared per common share                         $     0.40|  $     0.34  $      0.30
     Total assets                                                $   42,650|  $   36,114  $    33,160
     Total long-term liabilities                                 $   20,856|  $   19,230  $    19,399
     Capital expenditures, net of dispositions                   $    7,451|  $    6,425  $    12,025
===========================================================================|=========================
 </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"  presented 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"  presented  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.


42  CANADIAN NATURAL
<PAGE>

Adjusted Net Earnings from Operations

<TABLE>
      ($ millions)                                                   2008 |      2007        2006
--------------------------------------------------------------------------|-----------------------
      <S>                                                        <C>          <C>        <C>
      Net earnings as reported                                   $  4,985 |   $  2,608   $  2,524
      Stock-based compensation (recovery) expense, net of             (38)|        134         95
      tax(a)                                                              |
      Unrealized risk management (gain) loss, net of tax(b)        (2,112)|        977       (674)
      Unrealized foreign exchange loss (gain), net of tax(c)          698 |       (449)       114
      Effect of statutory tax rate and other legislative              (41)|       (864)      (395)
      changes on future income tax liabilities(d)                         |
--------------------------------------------------------------------------|-----------------------
      Adjusted net earnings from operations                      $  3,492 |   $  2,406   $  1,664
==================================================================================================
</TABLE>

      (a)   The  Company's  employee  stock  option  plan  provides  for a cash
            payment  option.  Accordingly,  the intrinsic  value of 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
            recognized in 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
            swap hedges, and are recognized in net earnings.
      (d)   All  substantively  enacted or 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 and other  legislative
            changes  is  recorded  in  net  earnings   during  the  period  the
            legislation is  substantively  enacted or enacted.  Income tax rate
            changes  during 2008  resulted in a reduction of future  income tax
            liabilities of  approximately  $19 million in North America and $22
            million in Cote d'Ivoire, Offshore West Africa. 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
            Cote d'Ivoire, Offshore West Africa.


Cash Flow from Operations
<TABLE>
      ($ millions)                                                2008 |           2007        2006
-----------------------------------------------------------------------|------------------------------
      <S>                                                <C>                  <C>         <C>
     Net earnings                                        $       4,985 |      $   2,608    $  2,524
     Non-cash items:                                                   |
        Depletion, depreciation and amortization                 2,683 |          2,863       2,391
        Asset retirement obligation accretion                       71 |             70          68
        Stock-based compensation (recovery) expense                (52)|            193         139
        Unrealized risk management (gain) loss                  (3,090)|          1,400      (1,013)
        Unrealized foreign exchange loss (gain)                    832 |           (524)        134
        Deferred petroleum revenue tax (recovery)                      |
        expense                                                    (67)|             44          37
        Future income tax expense (recovery)                     1,607 |           (456)        652
-----------------------------------------------------------------------|------------------------------
     Cash flow from operations                           $       6,969 |      $   6,198    $  4,932
======================================================================================================
</TABLE>

      For 2008, the Company reported net earnings of $4,985 million compared to
      net  earnings  of $2,608  million for 2007 (2006 - $2,524  million).  Net
      earnings  for the year ended  December 31, 2008  included net  unrealized
      after-tax  income  of  $1,493  million  related  to the  effects  of risk
      management  activities,  changes in foreign  exchange rates,  stock-based
      compensation,  and the impact of statutory tax rate and other legislative
      changes on future income tax  liabilities  (2007 - $202  million;  2006 -
      $860  million).   Excluding  these  items,  adjusted  net  earnings  from
      operations  for the year ended  December  31,  2008  increased  to $3,492
      million from $2,406  million for 2007 (2006 - $1,664  million)  primarily
      due  to  the  impact  of  higher  realized   pricing,   lower  depletion,
      depreciation   and   amortization   expense,   and  lower   interest  and
      administration  expense.  These factors were  partially  offset by higher
      realized risk management losses,  higher royalty and production  expense,
      lower  sales  volumes,  and the impact of the  stronger  Canadian  dollar
      relative to the US dollar during the first half of 2008.

      The  impacts  of  unrealized  risk  management  activities,   stock-based
      compensation  and  changes  in foreign  exchange  rates are  expected  to
      continue to contribute to  significant  volatility  in  consolidated  net
      earnings and are  discussed  in detail in the  relevant  sections of this
      MD&A.

      Cash flow from  operations for the year ended December 31, 2008 increased
      to $6,969 million  ($12.89 per common share) from $6,198 million  ($11.49
      per  common  share)  for 2007  (2006 - $4,932  million;  $9.18 per common
      share).  The increase was primarily due to the impact of higher  realized
      pricing and lower interest and administration  expense,  partially offset
      by higher realized risk management losses,  higher royalty and production
      expense,  higher current income tax expense, lower sales volumes, and the
      impact of the stronger  Canadian  dollar relative to the US dollar during
      the first half of 2008.


      For 2008, the Company's average sales price per bbl of crude oil and NGLs
      increased  to $82.41  per bbl from  $55.45 per bbl in 2007 (2006 - $53.65
      per bbl). The Company's  average natural gas price increased to $8.39 per
      mcf from $6.85 per mcf for 2007 (2006 - $6.72 per mcf).

      Total  production  of crude oil and NGLs before  royalties  decreased  to
      315,667  bbl/d from 331,232  bbl/d for 2007 (2006 - 331,998  bbl/d).  The
      decrease  in crude oil and NGLs  production  was  primarily  due to lower
      production in the North Sea and Offshore West Africa due to the timing of
      field  turnarounds,  the sale of the  Company's  working  interest in the
      B-Block  Fields late in 2007,  and the impact of the shut in of a portion
      of the Baobab Field  production,  and in North  America due to the cyclic
      nature of the Company's thermal production.

                                                             CANADIAN NATURAL 43

<PAGE>

      Total natural gas production  before royalties  decreased to 1,495 mmcf/d
      from 1,668 mmcf/d for 2007 (2006 - 1,492 mmcf/d). The decrease in natural
      gas production primarily reflected natural production declines due to the
      Company's  strategic  reduction in natural gas drilling activity in North
      America.

      Total  crude  oil and NGLs and  natural  gas  production  volumes  before
      royalties  decreased to 564,845 boe/d from 609,206 boe/d for 2007 (2006 -
      580,724  boe/d).  Total  production  for 2008 was  within  the  Company's
      previously issued guidance.

Operating highlights
                                               2008|          2007         2006
---------------------------------------------------|---------------------------
   Crude oil and NGLs ($/bbl)(1)                   |
   Sales price(2)                         $   82.41|    $    55.45   $    53.65
   Royalties                                  10.48|          5.94         4.48
   Production expense                         16.26|         13.34        12.29
---------------------------------------------------|---------------------------
  Netback                                 $   55.67|    $    36.17   $    36.88
---------------------------------------------------|---------------------------
   Natural gas ($/mcf)(1)                          |
   Sales price(2)                         $    8.39|    $     6.85   $     6.72
   Royalties                                   1.46|          1.11         1.29
   Production expense                          1.02|          0.91         0.82
---------------------------------------------------|---------------------------
   Netback                                $    5.91|    $     4.83   $     4.61
---------------------------------------------------|---------------------------
   Barrels of oil equivalent ($/boe)(1)            |
   Sales price(2)                         $   68.62|    $    49.05   $    47.92
   Royalties                                   9.78|          6.26         5.89
   Production expense                         11.79|          9.75         9.14
---------------------------------------------------|---------------------------
   Netback                                $   47.05|    $    33.04   $    32.89
===============================================================================
      (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.

SUMMARY OF QUARTERLY RESULTS

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

      ($ millions, except per common share amounts)
<TABLE>
       2008                                 Total            Dec 31       Sep 30       Jun 30        Mar 31
------------------------------------------------------------------------------------------------------------
<S>                                         <C>            <C>          <C>        <C>          <C>
     Revenue, before royalties              $     16,173   $  2,511     $  4,583   $    5,112   $     3,967
     Net earnings (loss)                    $      4,985   $  1,770     $  2,835   $     (347)  $       727
     Net earnings (loss) per common
     share
        - basic and diluted                 $       9.22   $   3.27     $   5.25   $    (0.65)  $      1.35
------------------------------------------------------------------------------------------------------------
     2007                                          Total     Dec 31       Sep 30       Jun 30        Mar 31
------------------------------------------------------------------------------------------------------------
     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
=============================================================================================================
</TABLE>

      Net  earnings  (loss)  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  derivative   financial   instruments   and   stock-based
      compensation,  fluctuations in depletion,  depreciation  and amortization
      charges and foreign  exchange rates, 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   fluctuating  demand,   geopolitical
            uncertainties  and fluctuations in the Heavy  Differential in North
            America.

     o     Natural gas pricing
            Natural gas prices  primarily  reflected  seasonal  fluctuations in
            both the demand  for  natural  gas and  inventory  storage  levels,
            fluctuations  in  liquefied  natural gas  imports  into the US, and
            increased shale gas production in the US.

      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, and
            development  of the Espoir Field.  Crude oil and NGLs sales volumes
            also reflected  fluctuations  in production  from the North Sea and
            Offshore  West  Africa due to timing of  liftings  and  maintenance
            activities and the impact of the shut in of a portion of the Baobab
            Field production.

 44  CANADIAN NATURAL
<PAGE>

      o     Natural gas sales volumes
            Natural gas sales volumes primarily  reflected  production declines
            due to the  Company's  strategic  decision  to reduce  natural  gas
            drilling activity in North America due to the allocation of capital
            to higher  return crude oil  projects,  as well as natural  decline
            rates.

      o     Foreign exchange rates
            Fluctuations  in the  Canadian  dollar  relative  to the US  dollar
            impacted 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 and the  re-measurement of North Sea future income
            tax  liabilities  denominated in UK pounds  sterling to US dollars,
            partially offset by the impact of cross currency swap hedges.

      o     Risk management
            Net  earnings  (loss) have  fluctuated  due to the  recognition  of
            realized and  unrealized  gains and losses from the  mark-to-market
            and  subsequent   settlement  of  the  Company's  risk   management
            activities.

      o     Changes in income tax expense
            Fluctuations in income tax expense (recovery) include statutory tax
            rate and other legislative changes substantively enacted or enacted
            in the various periods.

      o     Stock-based compensation
            Net  earnings  (loss)  have  fluctuated  due to the  mark-to-market
            movements  of the  Company's  stock-based  compensation  liability.
            Stock-based  compensation expense (recovery) reflected fluctuations
            in the Company's share price over the eight most recently completed
            quarters.

      o     Production expense
            Production expense has fluctuated company wide primarily due to the
            impact of the demand for services,  industry-wide inflationary cost
            pressures   experienced   in  prior   quarters  in  all   segments,
            fluctuations  in product mix, and the impact of seasonal costs that
            are dependent on weather.

      o     Depletion, depreciation and amortization
            Depletion, depreciation and amortization expense has fluctuated due
            to  changes  in  sales  volumes,   finding  and  development  costs
            associated  with  crude  oil  and  natural  gas  exploration,   and
            estimated future costs to develop the Company's proved  undeveloped
            reserves.


BUSINESS ENVIRONMENT

<TABLE>
<CAPTION>
   (Yearly average)                                       2008 |               2007               2006
---------------------------------------------------------------|--------------------------------------
<S>                       <C>                    <C>               <C>                <C>
   WTI benchmark price (US$/bbl)                 $       99.65 |   $          72.40   $          66.25
   Dated Brent benchmark price (US$/bbl)         $       96.99 |   $          72.59   $          65.18
   WCS blend differential from WTI                             |
   (US$/bbl)(1)                                  $       20.03 |   $          23.25   $          21.53
   WCS blend differential from WTI (%)(1)                   20%|                 32%                32%
   Condensate benchmark price (US$/bbl)          $      100.10 |   $          72.88   $          66.24
   NYMEX benchmark price (US$/mmbtu)             $        8.95 |   $           6.92   $           7.26
   AECO benchmark price (C$/GJ)                  $        7.71 |   $           6.26   $           6.62
   US / Canadian dollar average exchange rate    $      0.9381 |   $         0.9304   $         0.8818
   US / Canadian dollar year end exchange rate   $      0.8166 |   $         1.0120   $         0.8581
======================================================================================================
</TABLE>

      (1)   Beginning   in  2008,   the  Company  has   quantified   the  Heavy
            Differential  using the WCS blend as the  heavy  crude oil  marker.
            Prior period amounts have been reclassified.

Commodity Prices

      Substantially all of the Company's  production is sold based on US dollar
      benchmark pricing.  Specifically,  crude oil is marketed based on WTI and
      Brent indices. Canadian natural gas pricing is primarily based on Alberta
      AECO reference pricing, which is derived from the NYMEX reference pricing
      and adjusted for its basis or location differential to the NYMEX delivery
      point at Henry Hub. The Company's realized price is also highly sensitive
      to  fluctuations  in foreign  exchange  rates.  The average  value of the
      Canadian  dollar in  relation to the US dollar  fluctuated  significantly
      throughout 2008, with a high of approximately  $1.03 in February 2008 and
      a low of approximately $0.77 in December 2008.

      The overall  increase in WTI pricing in 2008 reflected  strong demand for
      crude oil and tight supply  during the first half of 2008,  followed by a
      significant  decrease in demand as a result of  worldwide  financial  and
      economic  events during the fourth  quarter of the year.  WTI pricing was
      also impacted by ongoing geopolitical  uncertainty resulting in increased
      market  volatility.  For 2008, WTI averaged US$99.65 per bbl, an increase
      of 38%  compared to US$72.40  per bbl for 2007 (2006 - US$66.25 per bbl).
      WTI  reached a high of  US$147.27  per bbl on July 11,  2008 and a low of
      US$32.40 per bbl on December 19, 2008.

      Brent averaged  US$96.99 per bbl for 2008, an increase of 34% compared to
      US$72.59  per bbl for 2007  (2006 -  US$65.18  per bbl).  Crude oil sales
      contracts for the North Sea and Offshore West Africa are typically  based
      on Brent  pricing,  which was also  impacted by worldwide  financial  and
      economic events late in the year.

                                                             CANADIAN NATURAL 45

<PAGE>

      The Company's  realized crude oil prices  benefited from strong commodity
      pricing during most of the year and a favorable Heavy  Differential.  The
      Heavy Differential averaged 20% of WTI for 2008, compared to 32% for 2007
      (2006 - 32%). As the worldwide  demand for diesel remained strong and the
      refinery  cracking margins were relatively  weak, the Heavy  Differential
      continued to remain strong, despite the falling benchmark pricing late in
      2008.

      The Company  anticipates  continued  volatility  in the crude oil pricing
      benchmarks due to the unpredictable  nature of supply and demand factors,
      geopolitical  events  and the global  economic  slowdown  resulting  from
      worldwide  financial  and  economic  events.  The Heavy  Differential  is
      expected to continue to reflect seasonal demand fluctuations and refinery
      cracking margins.

      NYMEX natural gas prices averaged US$8.95 per mmbtu for 2008, an increase
      of 29% from  US$6.92 per mmbtu for 2007 (2006 - US$7.26  per mmbtu).  The
      Alberta based AECO natural gas pricing for 2008  increased 23% to average
      $7.71 per GJ from $6.26 per GJ in 2007 (2006 - $6.62 per GJ).  During the
      first half of 2008,  the demand and pricing for natural gas were tracking
      with oil pricing and general economic activity. During the second half of
      the year, natural gas pricing decreased due to a significant  increase in
      production from shale gas reservoirs in the US and a significant  decline
      in  industrial  demand  caused by the onset of  worldwide  financial  and
      economic events.

Operating, Royalty and Capital Costs

      Strong  commodity  prices over the last  several  years have  resulted in
      increased  demand  for  oilfield  services  worldwide.  This  has  led to
      inflationary  operating and capital cost  pressures  throughout the crude
      oil and natural gas industry, particularly related to drilling activities
      and oil sands developments.

     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;  however future Federal  regulatory  requirements
     remain  uncertain.  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 of the
     Company's  facilities,  the  Primrose/Wolf  Lake  in-situ  heavy  crude oil
     facilities and the Hays sour natural gas plant, fall under the regulations.
     Commencing July 1, 2008, the British  Columbia carbon tax is being assessed
     at  $10/tonne  of CO2e on fuel  consumed  in the  province,  increasing  to
     $30/tonne by July 1, 2012. In the UK, GHG  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 to reduce CO2
     emissions  at its major  facilities  and on  trading  mechanisms  to ensure
     compliance with requirements now in effect.

      Continued   cost   pressures   and  the  final   outcome  of  changes  to
      environmental  regulations may adversely  impact the Company's future net
      earnings,  cash flow and capital projects.  For additional details, refer
      to the "Greenhouse Gas and Other Air Emissions" section of this MD&A.

      The Alberta  Government  implemented  its New Royalty  Framework  ("NRF")
      effective  January  1,  2009.  The NRF  includes  a number of  changes to
      royalty  rates for natural  gas,  conventional  crude oil,  and oil sands
      production.  Under the NRF, royalties payable vary according to commodity
      prices and the  productivity  of wells.  Leading up to the  January  2009
      implementation   of  the  NRF,  the  Alberta   Government   made  several
      adjustments  to the  originally  proposed  formula to address  unintended
      consequences.  These  adjustments  affect  royalties  payable for certain
      natural gas and crude oil production wells. For additional details, refer
      to the "Royalties" section of this MD&A.

 46  CANADIAN NATURAL

<PAGE>

ANALYSIS OF CHANGES IN REVENUE, BEFORE ROYALTIES AND RISK MANAGEMENT ACTIVITIES

<TABLE>
<CAPTION>
                                            Changes due to                                          Changes due to
---------------------------------------------------------------------------------------------------------------------------
($ millions)            2006    Volumes   Prices  Other         2007   Volumes       Prices       Other             2008
---------------------------------------------------------------------------------------------------------------------------
North America
<S>                <C>         <C>        <C>      <C>     <C>       <C>          <C>                <C>      <C>
Crude oil and      $   5,262   $    298   $  287   $  -    $   5,847  $    (49)    $  3,013      $    -       $    8,811
NGLs
Natural gas            3,804        452       46      -        4,302      (531)         914           -            4,685
---------------------------------------------------------------------------------------------------------------------------
                       9,066        750      333      -       10,149      (580)       3,927           -           13,496
---------------------------------------------------------------------------------------------------------------------------
North Sea
Crude oil and          1,600       (107)      82      -        1,575      (334)         512           -            1,753
NGLs
Natural gas               16         (2)       8      -           22        (5)          (1)          -               16
---------------------------------------------------------------------------------------------------------------------------
                       1,616       (109)      90      -        1,597      (339)         511           -            1,769
---------------------------------------------------------------------------------------------------------------------------
Offshore West
Africa
Crude oil and            931       (216)      36      -          751      (136)         280           -              895
NGLs
Natural gas               19          5        1      -           25         5           19           -               49
---------------------------------------------------------------------------------------------------------------------------
                         950       (211)      37      -          776      (131)         299           -              944
---------------------------------------------------------------------------------------------------------------------------
Subtotal
Crude oil and          7,793        (25)     405      -        8,173      (519)       3,805           -           11,459
NGLs
Natural gas            3,839        455       55      -        4,349      (531)         932           -            4,750
---------------------------------------------------------------------------------------------------------------------------
                      11,632        430      460      -       12,522    (1,050)       4,737           -           16,209
---------------------------------------------------------------------------------------------------------------------------
Midstream                 72          -        -      2           74         -            -           3               77
Intersegment             (61)         -        -      8         (53)         -            -         (60)            (113)
   eliminations
   and other(1)
---------------------------------------------------------------------------------------------------------------------------
Total              $  11,643   $    430   $  460   $ 10    $  12,543  $ (1,050)    $   4,737     $  (57)      $   16,173
===========================================================================================================================

</TABLE>
     (1)   Eliminates primarily internal transportation,  electricity charges,
           and natural gas sales.

     Revenue increased 29% to $16,173 million for 2008 from $12,543 million for
     2007 (2006 - $11,643 million). The increase was primarily due to increased
     realized crude oil and NGLs and natural gas prices company-wide.

     For 2008,  17% of the  Company's  crude oil and  natural  gas  revenue was
     generated  outside of North America  (2007 - 19%;  2006 - 22%).  North Sea
     accounted  for 11% of crude oil and  natural  gas revenue for 2008 (2007 -
     13%; 2006 - 14%),  and Offshore West Africa  accounted for 6% of crude oil
     and natural gas revenue for 2008 (2007 - 6%; 2006 - 8%).

ANALYSIS OF PRODUCT PRICES
<TABLE>
<CAPTION>
                                                            2008 |          2007            2006
-----------------------------------------------------------------|---------------------------------
<S>                                                  <C>              <C>             <C>
     Crude oil and NGLs ($/bbl) (1) (2)                          |
     North America                                   $     77.42 |     $     49.16    $      46.52
     North Sea                                       $    100.31 |     $     74.99    $      72.62
     Offshore West Africa                            $     97.96 |     $     71.68    $      67.99
     Company average                                 $     82.41 |     $     55.45    $      53.65
     Natural gas ($/mcf) (1) (2)                                 |
-----------------------------------------------------------------|---------------------------------
     North America                                   $      8.41 |     $      6.87    $       6.77
     North Sea                                       $      4.09 |     $      4.26    $       2.66
     Offshore West Africa                            $     10.03 |     $      5.68    $       5.37
     Company average                                 $      8.39 |     $      6.85    $       6.72
-----------------------------------------------------------------|---------------------------------
     Company average ($/boe) (1) (2)                 $     68.62 |     $     49.05    $      47.92
-----------------------------------------------------------------|---------------------------------
     Percentage of gross revenue (2) (excluding                  |
        midstream revenue)                                       |
     Crude oil and NGLs                                      68% |              62%             64%
     Natural gas                                             32% |              38%             36%
-----------------------------------------------------------------|---------------------------------
</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 49% to average  $82.41 per
      bbl for 2008 from  $55.45 per bbl for 2007  (2006 - $53.65 per bbl).  The
      increase in 2008 was primarily a result of higher WTI and Brent benchmark
      crude  oil  prices  during  most  of  the  year  and  a  narrower   Heavy
      Differential,  partially  offset by the impact of the  stronger  Canadian
      dollar relative to the US dollar during the first half of 2008.

      The Company's  realized  natural gas price increased 22% to average $8.39
      per mcf for 2008 from $6.85 per mcf for 2007 (2006 - $6.72 per mcf).  The
      increase in 2008 was primarily a result of increased benchmark prices due
      to increased  industrial  demand and lower liquefied  natural gas imports
      into the US in the first half of 2008,  partially offset by a significant
      reduction in industrial  demand late in the year as a result of worldwide
      financial and economic  events,  and the impact of higher  storage levels
      due to increased shale gas production in the US.

                                                            CANADIAN NATURAL  47

<PAGE>

--------------------------------------------------------------------------------
CANADIAN NATURAL  2008 ANNUAL REPORT
--------------------------------------------------------------------------------

North America

     North America  realized  crude oil prices  increased 57% to average $77.42
     per bbl for 2008 from $49.16 per bbl for 2007 (2006 - $46.52 per bbl). The
     increase in 2008 was due to increased WTI benchmark pricing and a narrower
     Heavy Differential,  partially offset by the impact of the strong Canadian
     dollar during the first half of 2008.

     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 2008, the Company contributed  approximately
     150,000 bbl/d of heavy crude oil blends to the WCS stream. The Company has
     entered into a 20 year transportation  agreement to commit to ship 120,000
     bbl/d of heavy  sour  crude oil on the  proposed  500,000  bbl/d  Keystone
     Pipeline US Gulf Coast  expansion  from  Hardisty,  Alberta to the US Gulf
     Coast.  Contemporaneously,  the Company  also entered into a 20 year crude
     oil purchase and sales agreement to sell 100,000 bbl/d of heavy sour crude
     oil to a major US refiner. Deliveries under the agreements are expected to
     commence in 2012 upon completion of the pipeline expansion and are subject
     to Keystone's receipt of regulatory approval of the pipeline expansion.

     North America  realized  natural gas prices increased 22% to average $8.41
     per mcf for 2008  from  $6.87  per mcf for 2007  (2006 - $6.77  per  mcf),
     primarily related to fluctuations in benchmark prices due 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:

                                               2008|          2007          2006
---------------------------------------------------|----------------------------
                                                   |
     Wellhead Price (1) (2)                        |
        Light/medium crude oil                     |
             and NGLs (C$/bbl)             $  89.04|    $    66.24    $    63.09
        Pelican Lake crude oil (C$/bbl)    $  76.91|    $    46.29    $    45.02
        Primary heavy crude oil (C$/bbl)   $  74.91|    $    43.77    $    41.35
        Thermal heavy crude oil (C$/bbl)   $  71.89|    $    43.49    $    40.98
        Natural gas (C$/mcf)               $   8.41|    $     6.87    $     6.77
===================================================|============================
      (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 Sea
     North Sea realized crude oil prices  increased 34% to average  $100.31 per
     bbl for 2008  from  $74.99  per bbl for  2007  (2006 -  $72.62  per  bbl).
     Realized crude oil prices per bbl in any  particular  period are dependant
     on the terms of the various sales  contracts,  the frequency and timing of
     liftings of each  field,  and  prevailing  crude oil prices at the time of
     lifting.  Realized crude oil prices in the North Sea during 2008 benefited
     from the increased Brent benchmark pricing, partially offset by the impact
     of the strong Canadian dollar during the first half of 2008.

Offshore West Africa
     Offshore West Africa  realized  crude oil prices  increased 37% to average
     $97.96  per bbl for 2008 from  $71.68  per bbl for 2007 (2006 - $67.99 per
     bbl).  Realized  crude oil  prices  per bbl in any  particular  period are
     dependant on the terms of the various sales  contracts,  the frequency and
     timing of liftings of each field,  and prevailing  crude oil prices at the
     time of lifting.  Realized crude oil prices in Offshore West Africa during
     2008  benefited  from the increased  Brent  benchmark  pricing,  partially
     offset by the impact of the strong  Canadian  dollar during the first half
     of 2008.

ANALYSIS OF DAILY PRODUCTION PRODUCTION, BEFORE ROYALTIES
                                           2008 |          2007        2006
------------------------------------------------|--------------------------
     Crude oil and NGLs (bbl/d)                 |
     North America                      243,826 |       246,779     235,253
     North Sea                           45,274 |        55,933      60,056
     Offshore West Africa                26,567 |        28,520      36,689
------------------------------------------------|--------------------------
                                        315,667 |       331,232     331,998
----------------------------------------------- |--------------------------
     Natural gas (mmcf/d)                       |
     North America                        1,472 |         1,643       1,468
     North Sea                               10 |            13          15
     Offshore West Africa                    13 |            12           9
------------------------------------------------|--------------------------
                                          1,495 |         1,668       1,492
------------------------------------------------|--------------------------
     Total barrels of oil                       |
       equivalent (boe/d)               564,845 |       609,206     580,724
------------------------------------------------|--------------------------
     Product mix
     Light/medium crude oil and NGLs         22%|           23%         26%
     Pelican Lake crude oil                   6%|            6%          5%
     Primary heavy crude oil                 16%|           15%         16%
     Thermal heavy crude oil                 12%|           11%         11%
     Natural gas                             44%|           45%         42%
================================================|==========================

48  CANADIAN NATURAL
<PAGE>

Daily Production, Net of Royalties
                                            2008|        2007         2006
------------------------------------------------|---------------------------
     Crude oil and NGLs (bbl/d)                 |
     North America                       207,933|     210,769     205,382
     North Sea                            45,182|      55,825      59,940
     Offshore West Africa                 22,641|      26,012      35,212
------------------------------------------------|---------------------------
                                         275,756|     292,606     300,534
------------------------------------------------|---------------------------
     Natural gas (mmcf/d)                       |
     North America                         1,225|       1,378       1,185
     North Sea                                10|          13          15
     Offshore West Africa                     11|          11           9
------------------------------------------------|---------------------------
                                           1,246|       1,402       1,209
------------------------------------------------|---------------------------
     Total barrels of oil                       |
       equivalent (boe/d)                483,541|     526,193     502,024
================================================|===========================

     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  averaged  564,845  boe/d for 2008,  a 7% decrease  from
     609,206 boe/d for 2007 (2006 - 580,724 boe/d).

     Total  production of crude oil and NGLs before  royalties  decreased 5% to
     315,667 bbl/d for 2008 from 331,232 bbl/d for 2007 (2006 - 331,998 bbl/d).
     The  decrease  in  crude  oil and  NGLs  production  from  2007  primarily
     reflected  lower  production in the North Sea and Offshore West Africa due
     to the timing of field  turnarounds and the sale of the Company's  working
     interest in the B-Block  Fields late in 2007,  and in North America due to
     the cyclic nature of the Company's thermal production.  Crude oil and NGLs
     production for 2008 was within the Company's previously issued guidance of
     313,000 to 318,000 bbl/d.

     Natural gas  production  continued  to  represent  the  Company's  largest
     product offering,  accounting for 44% of the Company's total production in
     2008. Total natural gas production before royalties decreased 10% to 1,495
     mmcf/d for 2008 from 1,668  mmcf/d  for 2007  (2006 - 1,492  mmcf/d).  The
     decrease in natural gas production from 2007 primarily  reflected  natural
     production  declines  due to the  Company's  strategic  decision to reduce
     natural  gas  drilling  activity  to  focus on  higher  return  crude  oil
     projects.  Natural  gas  production  for 2008  was  within  the  Company's
     previously issued guidance of 1,492 to 1,506 mmcf/d.

     For 2009,  revised  annual  production is  forecasted  to average  between
     331,000  and  399,000  bbl/d of crude oil and NGLs and  between  1,272 and
     1,328 mmcf/d of natural gas.

North America
     North  America  crude oil and NGLs  production  for 2008  decreased  1% to
     average  243,826 bbl/d from 246,779 bbl/d for 2007 (2006 - 235,253 bbl/d).
     The  decrease  in  production  from 2007 was  primarily  due to the cyclic
     nature of the Company's thermal production.

     North America  natural gas  production  for 2008  decreased 10% to average
     1,472  mmcf/d  from  1,643  mmcf/d  for 2007  (2006 - 1,468  mmcf/d).  The
     decrease in natural gas production from 2007 reflected production declines
     due to the  Company's  strategic  decision to reduce  natural gas drilling
     activity to focus on higher return crude oil projects.

North Sea
     North Sea crude oil  production  for 2008 was 45,274 bbl/d,  a decrease of
     19% from  55,933  bbl/d for 2007 (2006 - 60,056  bbl/d)  due to  increased
     planned  maintenance,  the sale of the Company's  working  interest in the
     B-Block Fields late in 2007,  expected  production  declines and delays in
     development projects.

Offshore West Africa
     Offshore West Africa crude oil  production  for 2008 decreased 7% to 26,567
     bbl/d  from  28,520  bbl/d  for  2007  (2006 -  36,689  bbl/d).  Production
     decreased in 2008 due to expected production declines,  partially offset by
     a full year of production at the recently completed West Espoir development
     and  restoration  of certain of the shut-in  production at the Baobab Field
     during the fourth quarter of 2008.
                                                            CANADIAN NATURAL  49
<PAGE>

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 volumes by segment, which have not been recognized in revenue, were as
     follows:

<TABLE>
<CAPTION>
     (bbl)                                                              2008|           2007            2006
----------------------------------------------------------------------------|---------------------------------
<S>                                                                  <C>           <C>             <C>
     North America, related to pipeline fill                         761,351|      1,097,526       1,097,526
     North Sea, related to timing of liftings                        558,904|      1,032,723         910,796
     Offshore West Africa, related to timing of liftings             609,444|          8,578         113,774
----------------------------------------------------------------------------|---------------------------------
                                                                   1,929,699|      2,138,827       2,122,096
============================================================================|=================================
</TABLE>

     During 2008, the North America pipeline fill was reduced,  increasing cash
     flow from operations by approximately $18 million.

     In addition,  during 2008, net production of approximately 127,000 barrels
     of crude  oil  produced  in the  Company's  international  operations  was
     deferred and  included in inventory at December 31, 2008.  Notwithstanding
     the overall increase in inventory,  cash flow from operations increased by
     approximately  $5 million,  as the  increase in cash flow from  additional
     sales  volumes in the North Sea more than offset the decrease in cash flow
     from lower  sales  volumes in  Offshore  West  Africa due to the timing of
     liftings.



ROYALTIES
                                              2008|          2007         2006
--------------------------------------------------|---------------------------
         Crude oil and NGLs ($/bbl) (1)
         North America                  $  11.99  |     $    7.19      $  5.86
         North Sea                      $   0.21  |     $    0.14      $  0.13
         Offshore West Africa           $  14.81  |     $    6.40      $  2.81
         Company average                $  10.48  |     $    5.94      $  4.48
--------------------------------------------------|---------------------------
     Natural gas ($/mcf) (1)                      |
         North America                  $   1.47  |     $    1.12      $  1.31
         Offshore West Africa           $   1.52  |     $    0.51      $  0.22
         Company average                $   1.46  |     $    1.11      $  1.29
         Company average ($/boe) (1)    $   9.78  |     $    6.26      $  5.89
--------------------------------------------------|----------------------------
     Percentage of revenue (2)                    |
         Crude oil and NGLs                   13% |            11%           8%
         Natural gas                          17% |            16%          19%
         Boe                                  14% |            13%          12%
--------------------------------------------------|----------------------------
     (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
     Government  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 were  calculated as 1% of gross revenues until the
     Company's  capital  investments  in  the  applicable  project  were  fully
     recovered,  at which  time the  royalty  increased  to 25% of net  profit.
     Effective January 1, 2009, changes to the Alberta royalty regime under the
     NRF 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.

     In addition, effective January 1, 2009, new royalty formulas under the NRF
     for  conventional  crude oil and  natural  gas are to  operate  on sliding
     scales  ranging  up to  50%,  determined  by  commodity  prices  and  well
     productivity.

     Crude oil and NGLs royalties for 2008 continued to reflect strong realized
     crude oil prices and averaged approximately 15% of gross revenues for 2008
     and 2007 (2006 - 13%).  North America crude oil and NGLs royalties per bbl
     are anticipated to average 10% to 15% of gross revenue for 2009.

     Natural gas royalties per mcf generally  fluctuate with natural gas prices
     and well productivity. Natural gas royalties averaged approximately 18% of
     gross  revenues for 2008 compared to 16% for 2007 (2006 - 19%),  primarily
     due to increased  benchmark natural gas prices.  North America natural gas
     royalties per mcf are  anticipated  to average 14% to 18% of gross revenue
     for 2009.

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.

Offshore West Africa
     Offshore  West  Africa  production  in both  Cote  d'Ivoire  and  Gabon 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  Companies.  Profit  oil is  allocated  to the joint
     venture  partners in accordance with their  respective  equity  interests,
     after a portion has been

50  CANADIAN NATURAL
<PAGE>

     allocated  to the  Governments.  The  Governments'  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 in Cote d'Ivoire 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  15% for
     2008  compared to 9% for 2007 (2006 - 4%). The  increase in royalty  rates
     from 2007 was due to the  impact of 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. The increase
     was  compounded  by the  impact  of the  reduction  in the  Cote  d'Ivoire
     corporate  income tax rate enacted early in 2008,  which had the effect of
     increasing  the  allocation  of the  Government's  share of profit  oil to
     royalties.  Offshore West Africa royalty rates are  anticipated to average
     6% to 10% of gross revenue for 2009,  reflecting a lower price environment
     and the Espoir Field contributing a lower proportion of the total Offshore
     West Africa production.

PRODUCTION EXPENSE
                                                  2008|         2007      2006
 -----------------------------------------------------|------------------------
       Crude oil and NGLs ($/bbl) (1)                 |
       North America                        $    14.96|    $   12.26    $ 11.73
       North Sea                            $    26.29|    $   20.78    $ 17.57
       Offshore West Africa                 $    10.29|    $    8.32    $  7.45
       Company average                      $    16.26|    $   13.34    $ 12.29
------------------------------------------------------|------------------------
       Natural gas ($/mcf) (1)                        |
       North America                        $     1.00|    $    0.90    $  0.81
       North Sea                            $     2.51|    $    2.17    $  1.40
       Offshore West Africa                 $     1.61|    $    1.48    $  1.19
       Company average                      $     1.02|    $    0.91    $  0.82
------------------------------------------------------|------------------------
     Company average ($/boe) (1)            $    11.79|    $    9.75    $  9.14
======================================================|========================
     (1)    Amounts expressed on a per unit basis are based on sales volumes.

North America

     North America crude oil and NGLs production expense for 2008 increased 22%
     to $14.96  per bbl from  $12.26  per bbl for 2007 (2006 - $11.73 per bbl).
     The  increase  in  production  expense  per bbl from 2007 was  primarily a
     result  of the  higher  cost of  natural  gas for fuel  for the  Company's
     thermal  operations  and  increased  property  tax and  power  costs.  The
     increase  was also a result of the impact of lower  production  volumes on
     the fixed cost portion of production costs.

     North America  natural gas  production  expense for 2008  increased 11% to
     $1.00  per mcf from  $0.90 per mcf for 2007  (2006 - $0.81  per mcf).  The
     increase in production expense per mcf from 2007 was primarily a result of
     the  Company's  strategic  reduction  in natural  gas  drilling  activity,
     decreasing   natural  gas  production   throughout   2008  and  increasing
     production expense per mcf on the fixed cost portion of production costs.

     Production expense per boe for 2009 is anticipated to increase as a result
     of an overall  reduction in budgeted  volumes for 2009, while fixed costs,
     such as property  taxes and lease  rentals,  are forecasted to continue to
     escalate.

North Sea
     North Sea crude oil  production  expense  increased  on a per barrel basis
     from 2007 primarily due to lower production  volumes on a relatively fixed
     operating cost base as well as due to higher planned maintenance costs.

Offshore West Africa
     Offshore  West Africa  crude oil  production  expense  increased  on a per
     barrel  basis from 2007  primarily  due to lower  production  volumes on a
     relatively fixed operating cost base.

MIDSTREAM

     ($ millions)                              2008|         2007          2006
---------------------------------------------------|---------------------------
     Revenue                           $         77|  $        74  $         72
     Production expense                          25|           22            23
---------------------------------------------------|---------------------------
     Midstream cash flow                         52|           52            49
     Depreciation                                 8|            8             8
---------------------------------------------------|---------------------------
     Segment earnings before taxes     $         44|  $        44  $         41
--------------------------------------------------------------------------------

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

                                                            CANADIAN NATURAL  51
<PAGE>

DEPLETION, DEPRECIATION AND AMORTIZATION (1)

     ($ millions, except per boe amounts) (2)       2008|       2007       2006
--------------------------------------------------------|-----------------------
     North America (3)                           $ 2,226|    $ 2,350    $ 1,897
     North Sea                                       317|        340        297
     Offshore West Africa                            132|        165        189
--------------------------------------------------------|-----------------------
     Expense                                     $ 2,675|    $ 2,855    $ 2,383
     $/boe                                       $ 12.97|    $ 12.84    $ 11.27
========================================================|======================
     (1)  DD&A excludes depreciation on midstream assets.
     (2)  Amounts expressed on a per unit basis are based on sales volumes.
     (3)  Amounts  include the impact of intersegment  eliminations.  Depletion,
          Depreciation and  Amortization  ("DD&A") expense for 2008 decreased 6%
          to  $2,675  million  from  $2,855  million  for  2007  (2006 -  $2,383
          million), primarily due to the impact of lower sales volumes.

ASSET RETIREMENT OBLIGATION ACCRETION

     ($ millions, except per boe amounts) (1)       2008|       2007       2006
--------------------------------------------------------|-----------------------
     North America                                $   42|     $   38   $     35
     North Sea                                        27|         30         31
     Offshore West Africa                              2|          2          2
--------------------------------------------------------|-----------------------
     Expense                                      $   71|     $   70   $     68
     $/boe                                        $ 0.34|     $ 0.32   $   0.32
========================================================|=======================
     (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 in 2008 was comparable to 2007.

ADMINISTRATION EXPENSE

     ($ millions, except per boe amounts) (1)        2008|      2007       2006
---------------------------------------------------------|----------------------
     Expense                                      $   180|    $  208    $   180
     $/boe                                        $  0.87|    $ 0.93    $  0.85
=========================================================|======================
     (1)    Amounts expressed on a per unit basis are based on sales volumes.

     Administration  expense  for 2008  decreased  from  2007  primarily  due to
     decreased  staffing  costs,  including costs related to the Company's share
     bonus program, as well as due to decreased office lease costs.

STOCK-BASED COMPENSATION

     ($ millions)                                   2008 |      2007       2006
---------------------------------------------------------|----------------------
     (Recovery) expense                         $    (52)|  $    193  $     139
=========================================================|======================

     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 as 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 $52 million  ($38  million  after-tax)  stock-based
     compensation  recovery  during 2008 due to a 33% decrease in the  Company's
     share  price for the year ended  December  31,  2008  (December  31, 2008 -
     C$48.75; December 31, 2007 - C$72.58; December 31, 2006 - C$62.15; December
     31, 2005 - C$57.63),  offset by the impact of normal course graded  vesting
     of  options  granted  in prior  periods  and the  impact of vested  options
     exercised or surrendered during the year. As required by Canadian 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
     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 during the construction period in the case of the
     Horizon Project. For the year ended December 31, 2008, the Company recorded
     a $23 million recovery on previously capitalized  stock-based  compensation
     on the Horizon Project (2007 - $58 million capitalized;  2006 - $79 million
     capitalized).

     The stock-based  compensation  liability  reflected the Company's potential
     cash  liability  should all the vested  options be  surrendered  for a cash
     payout  at  the  market  price  on  December  31,  2008.  In  periods  when
     substantial  stock price changes occur, the Company's  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.

52  CANADIAN NATURAL
<PAGE>


     For the year ended  December  31,  2008,  the Company paid $207 million for
     stock options surrendered for cash settlement (2007 - $375 million;  2006 -
     $264 million).

INTEREST EXPENSE

     ($ millions, except per boe amounts and        2008 |      2007       2006
     interest rates) (1)                                 |
---------------------------------------------------------|----------------------
     Expense, gross                               $  609 |  $    632    $   336
     Less: capitalized interest, Horizon Project     481 |       356        196
---------------------------------------------------------|----------------------
     Expense, net                                 $  128 |  $    276    $   140
     $/boe                                        $ 0.62 |  $   1.24    $  0.66
---------------------------------------------------------|----------------------
     Average effective interest rate                 5.1%|       5.5%       5.7%
=========================================================|=====================
     (1)    Amounts expressed on a per unit basis are based on sales volumes.

     Gross interest expense and the Company's  average  effective  interest rate
     decreased  from 2007  primarily  due to a decrease in short term  borrowing
     rates during the last half of 2008 and the impact of the stronger  Canadian
     dollar during the first half of 2008.

     On commencement of operations of Phase 1 of the Horizon  Project,  interest
     capitalization  will cease on this Phase and interest expense will increase
     accordingly.

RISK MANAGEMENT ACTIVITIES

     The Company utilizes various derivative financial instruments to manage its
     commodity price,  currency and interest rate exposures.  The Company's risk
     management program is not used for speculative purposes.

     ($ millions)                                   2008 |     2007       2006
---------------------------------------------------------|----------------------
     Crude oil and NGLs financial instruments    $ 2,020 |  $   505   $  1,395
     Natural gas financial instruments               (21)|    (343)        (70)
     Foreign currency contracts                     (139)|        -          -
---------------------------------------------------------|----------------------
     Realized loss                               $ 1,860 |  $   162   $  1,325
---------------------------------------------------------|----------------------
     Crude oil and NGLs financial instruments    $(3,104)|  $ 1,244   $   (736)
     Natural gas financial instruments                16 |      156       (260)
     Foreign currency contracts                       (2)|        -        (17)
---------------------------------------------------------|----------------------
     Unrealized (gain) loss                      $(3,090)|  $ 1,400   $ (1,013)
---------------------------------------------------------|----------------------
     Net (gain) loss                             $(1,230)|  $ 1,562   $    312
=========================================================|======================

     The net  realized  loss (gain)  from crude oil and  natural  gas  financial
     instruments would have decreased (increased) the Company's average realized
     prices as follows:

                                                    2008 |      2007       2006
---------------------------------------------------------|----------------------
     Crude oil and NGLs ($/bbl) (1)              $ 17.45 |   $  4.18   $  11.57
     Natural gas ($/mcf) (1)                     $ (0.04)|   $ (0.56)  $  (0.13)
=========================================================|======================
     (1)    Amounts expressed on a per unit basis are based on sales volumes.

     Complete details related to  outstanding  derivative financial  instruments
     at December 31, 2008 are disclosed in note 13 to the Company's consolidated
     financial statements.

     The commodity derivative financial  instruments  currently outstanding have
     not been designated as hedges for accounting purposes (the  "non-designated
     hedges").  The  fair  value  of  these  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 commodity derivative financial
     instruments may vary materially depending upon the underlying crude oil and
     natural  gas prices at the time of final  settlement,  as compared to their
     mark-to-market value at December 31, 2008.

     Due to  changes  in crude  oil and  natural  gas  forward  pricing  and the
     reversal of prior period unrealized gains and losses,  the Company recorded
     a net unrealized gain of $3,090 million  ($2,112 million  after-tax) on its
     risk  management  activities  for the year ended  December 31, 2008 (2007 -
     $1,400  million  unrealized  loss,  $977 million  after-tax;  2006 - $1,013
     million unrealized gain, $674 million after-tax).

FOREIGN EXCHANGE

     ($ millions)                                   2008|       2007       2006
--------------------------------------------------------|-----------------------
     Net realized (gain) loss                    $ (114)|    $    53   $    (12)
     Net unrealized loss (gain) (1)                 832 |       (524)       134
--------------------------------------------------------|-----------------------
     Net loss (gain)                             $  718 |    $  (471)  $    122
========================================================|=======================

     (1)  Amounts are reported net of the effect of cross currency swap hedges.

                                                            CANADIAN NATURAL  53
<PAGE>

     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.

     During 2008,  the Company  determined  that its operations in Offshore West
     Africa were now operationally  and financially  independent and the current
     rate method of translation was prospectively adopted for translation of the
     financial  statements  of the  Offshore  West  African  subsidiaries  as at
     December 31, 2008. Prior to this determination, the Company's Offshore West
     Africa foreign operations were classified as integrated for the purposes of
     foreign currency translation, and accordingly, Offshore West Africa foreign
     operations  and foreign  currency  transactions  and balances held in North
     America were directly  translated into Canadian  dollars using the temporal
     method.  All related foreign  exchange gains or losses were 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 and future income tax  liabilities 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.  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 loss in 2008 was primarily  related to
     the  weakening  of the  Canadian  dollar in  relation to the US dollar with
     respect to the US dollar  denominated debt,  partially offset by the impact
     of  the   re-measurement   of  North  Sea  future  income  tax  liabilities
     denominated  in UK  pounds  sterling  to US  dollars.  Included  in the net
     unrealized loss for the year ended December 31, 2008 was an unrealized gain
     of $449 million  related to the impact of cross  currency swap hedges.  The
     net realized foreign exchange gain for 2008 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 and the repayment of
     US dollar denominated debt. The Canadian dollar ended the year at US$0.8166
     compared to US$1.0120 at December 31, 2007 (December 31, 2006 - US$0.8581).

TAXES

     ($ millions, except income tax rates)          2008 |      2007      2006
---------------------------------------------------------|----------------------
     Current                                     $   245 |   $   121   $   219
     Deferred                                        (67)|        44        37
---------------------------------------------------------|----------------------
     Taxes other than income tax                 $   178 |   $   165   $   256
---------------------------------------------------------|----------------------
     North America                               $    33 |   $    96   $   143
     North Sea                                       340 |       210        30
     Offshore West Africa                            128 |        74        49
---------------------------------------------------------|----------------------
     Current income tax                              501 |       380       222
     Future income tax                             1,607 |      (456)       652
---------------------------------------------------------|----------------------
                                                   2,108 |       (76)       874
     Income tax rate and other legislative change     41 |       864        395
     (1) (2) (3)                                         |
---------------------------------------------------------|----------------------
                                                 $ 2,149 |   $   788   $  1,269
---------------------------------------------------------|----------------------
     Effective income tax rate before income tax         |
        and other legislative changes               30.3%|      31.1%      37.3%
=========================================================|======================
     (1)  Includes  the  effects of one time  recoveries  of $19  million due to
          British Columbia  corporate income tax rate reductions and $22 million
          due  to  Cote   d'Ivoire   corporate   income   tax  rate   reductions
          substantively enacted or enacted during 2008.
     (2)  Includes  the effect of one time  recoveries  of $864  million  due to
          Canadian  Federal  income tax rate  reductions  and other  legislative
          changes substantively enacted or enacted during 2007.
     (3)  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 Cote d'Ivoire, Offshore
               West Africa corporate income tax rate reductions enacted in 2006.

     Taxes other than income tax  primarily  includes  current and deferred PRT,
     which is charged  on certain  fields in the North Sea at the rate of 50% of
     net  operating  income,  after  allowing for certain  deductions  including
     related capital and 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 subsequent  periods.  North America  current  income taxes
     have been provided on the basis of this corporate  structure.  In addition,
     North  America and North Sea current  income  taxes will vary  depending on
     available income tax deductions related to the nature, timing and amount of
     capital expenditures incurred in any particular year.

     For 2009,  based on  budgeted  prices and the current  availability  of tax
     pools, the Company expects to incur current income tax expense in Canada of
     $20  million to $50  million  and in the North Sea of $350  million to $450
     million.

54  CANADIAN NATURAL
<PAGE>

NET CAPITAL EXPENDITURES (1)

     ($ millions)                                   2008|       2007      2006
  ------------------------------------------------------|-----------------------
     Expenditures on property, plant                    |
        and equipment                                   |
     Net property acquisitions                          |
       (dispositions) (2)                        $   336|    $   (39)  $  4,733
     Land acquisition and retention                   86|         95        210
     Seismic evaluations                             107|        124        130
     Well drilling, completion and equipping       1,664|      1,642      2,340
     Production and related facilities             1,282|      1,205      1,314
  ------------------------------------------------------|-----------------------
     Total net reserve replacement expenditures    3,475|      3,027      8,727
  ------------------------------------------------------|-----------------------
     Horizon Project:                                   |
     Phase 1 construction costs                    2,732|       2,740      2,768
     Phase 1 operating and capital inventory          87|          -          -
     Phase 1 commissioning costs                     277|          -          -
     Phases 2/3 costs                                336|        124         79
     Capitalized interest, stock-based                  |
        compensation and other                       480|        437        338
--------------------------------------------------------|-----------------------
     Total Horizon Project (3)                     3,912|      3,301      3,185
--------------------------------------------------------|-----------------------
     Midstream                                         9|          6         12
     Abandonments (4)                                 38|         71         75
     Head office                                      17|         20         26
--------------------------------------------------------|-----------------------
     Total net capital expenditures              $ 7,451|    $ 6,425   $  12,025
--------------------------------------------------------|-----------------------
     By segment                                         |
     North America                               $ 2,344|    $ 2,428   $   7,936
     North Sea                                       319|        439        646
     Offshore West Africa                            811|        159        134
     Other                                             1|          1         11
     Horizon Project                               3,912|      3,301      3,185
     Midstream                                         9|          6         12
     Abandonments (4)                                 38|         71         75
     Head office                                      17|         20         26
--------------------------------------------------------|-----------------------
     Total                                       $ 7,451|    $ 6,425  $  12,025
========================================================|=======================
     (1)  Net capital  expenditures  exclude  adjustments related to differences
          between   carrying   value  and  tax  value,  and  other  fair  value
          adjustments.
     (2)  Includes Business Combinations.
     (3)  Net  expenditures  for the Horizon  Project also include the impact of
          intersegment eliminations.
     (4)  Abandonments  represent  expenditures  to  settle  ARO and  have  been
          reflected as capital expenditures in this table.

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

     Net capital  expenditures  for 2008 were $7,451 million  compared to $6,425
     million for 2007 (2006 - $12,025  million).  Excluding the ACC acquisition,
     net capital expenditures were $7,270 million for 2006. Capital expenditures
     in 2008 primarily reflected the continued progress on the Company's larger,
     future growth projects,  most notably the Horizon  Project,  Primrose East,
     and Gabon,  offset by the effects of an overall strategic  reduction in the
     North America natural gas drilling program.

     During 2008, the Company  drilled a total of 1,121 net wells  consisting of
     269  natural gas wells,  682 crude oil wells,  131  stratigraphic  test and
     service wells, and 39 wells that were dry. This compared to 1,322 net wells
     drilled for 2007 (2006 - 1,738 net wells).  The Company achieved an overall
     success rate of 96% for 2008,  excluding the stratigraphic test and service
     wells (2007 - 91%; 2006 - 91%).

North America
     North America,  excluding the Horizon Project,  accounted for approximately
     32% of the total capital  expenditures for the year ended December 31, 2008
     compared to approximately 39% for 2007 (2006 - 67%).

     During 2008, the Company  targeted 280 net natural gas wells,  including 27
     wells in  Northeast  British  Columbia,  104 wells in the  Northern  Plains
     region, 70 wells in Northwest Alberta,  and 79 wells in the Southern Plains
     region.  The Company also targeted 704 net crude oil wells during the year.
     The majority of these wells were  concentrated  in the Company's  crude oil
     Northern Plains region where 415 primary heavy crude oil wells, 110 Pelican
     Lake crude oil  wells,  74  thermal  crude oil wells and 7 light  crude oil
     wells were drilled. Another 98 wells targeting light crude oil were drilled
     outside the Northern Plains region.

     Due to significant  differences in relative  commodity prices between crude
     oil and natural gas  throughout  most of 2008,  the  Company  continued  to
     access its large crude oil drilling inventory to maximize value in both the
     short and long term. Due to the

                                                            CANADIAN NATURAL  55
<PAGE>

     Company's  focus  on  drilling  crude  oil  wells in 2007 and 2008 and as a
     result of royalty  changes  under the Alberta  NRF,  natural  gas  drilling
     activities have been reduced to manage overall capital  spending.  Deferred
     natural gas well  locations  have been retained in the  Company's  prospect
     inventory.

     As part of the  phased  expansion  of its  In-Situ  Oil Sands  Assets,  the
     Company is  continuing  to develop its Primrose  thermal  projects.  During
     2008, the Company  drilled 74 thermal oil wells, 2 water source wells,  and
     19 stratigraphic test wells and observation wells. Overall Primrose thermal
     production  for 2008 was  approximately  65,000 bbl/d (2007 - 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,  was completed and first steaming commenced in
     September  2008,  with first  production  achieved in the fourth quarter of
     2008.  Subsequent  to December 31, 2008,  operational  issues on one of the
     pads has caused  steaming  to cease on all well pads in the  Primrose  East
     project area and the Company is working on rectifying the issues.

     The next planned phase of the Company's  In-Situ Oil Sands assets expansion
     is the Kirby project located 120 kilometers north of the existing  Primrose
     facilities.  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.  Subject to regulatory  approval,  crude oil pricing, and
     capital costs,  the Company may proceed with the detailed  engineering  and
     design work.

     Development  of new pads and  secondary  recovery  conversion  projects  at
     Pelican Lake continued as expected  throughout 2008.  Drilling consisted of
     110  horizontal  crude  oil  wells,  with  plans  to  drill  58  additional
     horizontal crude oil wells in 2009. The response from the water and polymer
     flood projects continues to be positive.  Pelican Lake production  averaged
     approximately  37,000  bbl/d in 2008  (2007 - 34,000  bbl/d;  2006 - 30,000
     bbl/d).

     For 2009,  the  Company's  overall  drilling  activity in North  America is
     expected to comprise  approximately 142 natural gas wells and 465 crude oil
     wells, excluding stratigraphic and service wells.

Horizon Project
     The Company continued the  construction,  commissioning and staged start up
     of the Horizon  Project,  with first production of synthetic crude oil from
     Phase 1  achieved  February  28,  2009,  representing  a  major  milestone.
     Currently,  the  Company is filling all product  tanks in  preparation  for
     blending and pipeline shipment.

     All major  components have been completed and are fully  operational,  with
     the exception of the Distillate Hydrotreating Plant (Plant 42). The Naphtha
     and  Gas  Oil  Hydrotreaters  (Plants  41 and 43  respectively)  are  fully
     operational and currently capable of producing  approximately 55,000 bbl/d.
     Upon  completion of Plant 42, the focus will be on reaching full production
     capacity of 110,000 bbl/d.  Plant 42 has now been turned over to operations
     for  commissioning  and is targeted to be  operational  by the end of April
     2009, subject to any unforeseen start up issues.

     During the initial  stages of the  ramp-up of  production,  the  production
     volumes  will  fluctuate  on a weekly  basis  until  the end of the  second
     quarter of 2009 when the  Company  expects to see a steady  ramp up to full
     production by the end of 2009.  The Company will work towards full capacity
     throughout  2009 as the plant  continues  to be fine tuned to design  rates
     with a focus on safety and reliability.

     Phase 1 of the Horizon Project was designed, engineered, and constructed in
     an extremely  volatile and  inflationary  business  environment  with final
     construction costs totaling approximately $9.7 billion.  Subsequent planned
     expansion  through  Phases 2/3,  further  broken down into a series of four
     Tranches,  are being  reprofiled  with the goal of  attaining  better  cost
     management.

North Sea
     In 2008, the Company continued with its planned program of infill drilling,
     recompletions, workovers and waterflood optimizations. During 2008, 4.1 net
     wells were drilled,  including 0.9 net water injectors,  with an additional
     1.2 net wells drilling at year end. Specifically, two production wells were
     completed at Murchison  and one  production  well was  completed at Ninian,
     with an additional  production  well in progress at Ninian at year end. The
     Company  also  delivered  one water  injection  well at Ninian and  further
     increased volumes injected into the Ninian reservoir.

     The  Company  continued  with  its  planned  investment  in  its  long-term
     facilities  and  infrastructure   strategy  and  successfully  carried  out
     maintenance  turnarounds at all five installations  during the year. Within
     the Murchison turnaround the Company successfully implemented a new control
     system, which has resulted in improved platform uptime.

Offshore West Africa
     During 2008, 4.1 net wells were drilled with 0.9 net wells drilling at year
     end.

     Development  drilling on West Espoir was completed in early 2008, on budget
     and on time. At the Baobab  Field,  the Company  delivered  three new wells
     from the  drilling  program,  with a fourth well due to be completed in the
     second quarter of 2009.

     At the 90% owned and operated Olowi Field in offshore Gabon,  the Conductor
     Supported  Platform was installed,  construction was completed on the FPSO,
     which arrived on location in February 2009, and  construction  continued on
     the wellhead towers and subsea facilities.  First crude oil is targeted for
     late in the first quarter or early in the second quarter of 2009.

56  CANADIAN NATURAL
<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

     ($ millions, except ratios)                   2008 |      2007       2006
--------------------------------------------------------|----------------------
     Working capital (deficit) (1)             $    392 |  $ (1,382) $    (832)
     Long-term debt (2)(3)                     $ 13,016 |  $ 10,940  $  11,043
     Shareholders' equity                               |
     Share capital                             $  2,768 |  $  2,674  $   2,562
     Retained earnings                           15,344 |    10,575      8,141
     Accumulated other comprehensive income             |
       (loss)                                       262 |        72        (13)
--------------------------------------------------------|----------------------
     Total                                     $ 18,374 |  $ 13,321  $  10,690
--------------------------------------------------------|----------------------
     Debt to book capitalization (3)(4)              41%|        45%        51%
     Debt to market capitalization (3)(5)            33%|        22%        25%
     After tax return on average common                 |
     shareholders' equity (6)                        33%|        22%        27%
     After tax return on average capital                |
        employed (3)(7)                              19%|        12%        17%
========================================================|======================
     (1)  Calculated as current assets less current  liabilities,  excluding the
          current portion of long-term debt.
     (2)  Includes the current  portion of long-term  debt (2008 - $420 million;
          2007 and 2006 - $nil).
     (3)  Long-term debt at December 31, 2008 and 2007 is stated at its carrying
          value,  net of fair value  adjustments,  original issue  discounts and
          transaction costs. Amounts for 2006 were not adjusted for these items.
     (4)  Calculated as current and long-term debt; divided by the book value of
          common shareholders' equity plus current and long-term debt.
     (5)  Calculated as current and long-term debt;  divided by the market value
          of common shareholders' equity plus current and long-term debt.
     (6)  Calculated  as net earnings for the year;  as a percentage  of average
          common shareholders' equity for the year.
     (7)  Calculated as net earnings  plus  after-tax  interest  expense for the
          year; as a percentage of average  capital  employed.  Average  capital
          employed is the average shareholders' equity and current and long-term
          debt for the  year,  including  $10,678  million  in  average  capital
          employed related to the Horizon Project (2007 - $7,001 million; 2006 -
          $3,760 million).

     At December 31, 2008, the Company's capital resources  consisted  primarily
     of cash flow from operations,  available bank 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 bank 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.

     The ongoing  worldwide  financial  and economic  events have  resulted in a
     significant  tightening  of the  availability  and cost of new  sources  of
     liquidity  including  bank credit  facilities  and funds  derived from debt
     capital  markets.  In light of these  credit  challenges,  the  Company has
     undertaken  a  thorough  review  of its  liquidity  sources  as well as its
     exposure to counterparties and has concluded that its capital resources are
     sufficient  to meet  ongoing  short-,  medium- and  long-term  commitments.
     Specifically,   the  Company  continues  to  believe  that  its  internally
     generated cash flow from operations  supported by the implementation of its
     hedge policy, the flexibility of its capital expenditure programs supported
     by its multi-year  financial plans, its existing bank credit facilities and
     its  ability  to raise  new debt on  commercially  acceptable  terms,  will
     provide sufficient liquidity to sustain its operations in the short, medium
     and long  term and  support  its  growth  strategy.  Further,  the  Company
     believes that its  counterparties  currently have the financial capacity to
     settle outstanding obligations in the normal course of business.

     On an ongoing basis, the Company continues to focus on the following areas:

     o    Monitoring cash flow from  operations,  which is the primary source of
          funds;

     o    Reviewing bank credit  facilities and public debt indentures to ensure
          they are in compliance with applicable covenant packages;

     o    Monitoring credit markets, governments,  world banks and the Company's
          bank syndicates to identify associated risks and exposures;

     o    Maintaining an active  commodity risk management  program that manages
          exposure to crude oil and natural  gas price  volatility.  The Company
          believes this is an effective  tool to manage  short- and  medium-term
          changes in spot  commodity  prices.  The  Company  also  monitors  its
          commodity  risk  management  counterparties  to  ensure  they  are  in
          position to settle obligations  within the contractually  agreed terms
          of settlement;

     o    Monitoring exposure to individual  customers,  contractors,  suppliers
          and joint venture  partners on a regular  basis and when  appropriate,
          ensuring  parental  guarantees  or  letters  of credit are in place to
          minimize the impact in the event of default; and

     o    Monitoring the Company's  2009 capital and operating  plans to provide
          the required  flexibility  to deal with  commodity  price  volatility,
          commitments  in respect of capital  and  operating  expenditures,  and
          commitments to retire its non-revolving  bank credit facility maturing
          in October  2009.  The  Company  actively  manages the  allocation  of
          maintenance  and growth  capital to ensure it is expended in a prudent
          and  appropriate  manner.  The  Company  continued  the  construction,
          commissioning  and staged start up of the Horizon Project,  with first
          production of synthetic  crude oil from Phase 1 achieved  February 28,
          2009.

     At December 31, 2008,  the Company had $2,082  million of available  credit
     under  its bank  credit  facilities,  which  together  with  cash flow from
     operating  activities  to be generated in 2009  supported by its  commodity
     risk  management  program and the  ability to  actively  manage the capital
     expenditure  programs,  is  forecasted to be sufficient to repay the $2,350
     million  non-revolving bank credit facility maturing October 2009. Further,
     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.

                                                            CANADIAN NATURAL  57
<PAGE>

     Further  details  related to the Company's  long-term  debt at December 31,
     2008 are  discussed  below and in note 5 to the  Company's  audited  annual
     consolidated financial statements.

     At December 31,  2008,  the  Company's  working  capital was $392  million,
     excluding  the current  portion of long-term  debt and  including  both the
     current  portion  of the  net  mark-to-market  asset  for  risk  management
     derivative financial  instruments of $1,851 million and the current portion
     of the stock-based  compensation  liability of $159 million,  together with
     related future income tax liabilities of $585 million.  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,  as compared to their mark-to-market value
     at December  31,  2008.  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.

     Long-term  debt was $13,016  million at December 31,  2008,  resulting in a
     debt to book capitalization  level of 41% as at December 31, 2008 (December
     31, 2007 - 45%;  December 31, 2006 - 51%).  This ratio is near the midpoint
     of the 35% to 45% range  targeted by  management,  including  the impact of
     capital spending on the Horizon Project.  The Company remains  committed to
     maintaining a strong  balance  sheet and flexible  capital  structure.  The
     Company has hedged a portion of its crude oil and  natural  gas  production
     for 2009 and 2010 at  prices  that  protect  investment  returns  to ensure
     ongoing   balance  sheet   strength  and  the  completion  of  its  capital
     expenditure  programs.  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  prices and  supports  the  Company's  cash flow for its  capital
     expenditures programs.  This program currently allows for the hedging of up
     to 60% of the  near  12  months  budgeted  production  and up to 40% of the
     following  13 to 24 months  estimated  production.  For the purpose of this
     program,  the purchase of crude oil put options is in addition to the above
     parameters.  As at  December  31,  2008,  in  accordance  with the  policy,
     approximately  6% of budgeted  crude oil volumes were hedged using  collars
     for 2009 and  approximately 33% of budgeted natural gas volumes were hedged
     for the first  quarter  of 2009.  In  addition,  92,000  bbl/d of crude oil
     volumes  are  protected  by put  options  for  2009 at a  strike  price  of
     US$100.00 per bbl.

     The  Company  had  the  following  net   commodity   derivative   financial
     instruments outstanding as at December 31, 2008:

<TABLE>
<CAPTION>
                                     Remaining term        Volume         Weighted average price    Index
----------------------------------------------------------------------------------------------------------
<S>                                  <C>                   <C>            <C>                       <C>
     Crude oil
     Crude oil price collars         Jan 2009 - Dec 2009   25,000 bbl/d   US$70.00 - US$111.56      WTI
                                     Apr 2009 - Jun 2009   4,000 bbl/d    US$70.00 - US$90.00       WTI
     Crude oil puts                  Jan 2009 - Dec 2009   92,000 bbl/d   US$100.00                 WTI
                                     ---------------------------------------------------------------------
     Natural gas
     Natural gas price collars(1)    Jan 2009 - Mar 2009   500,000 GJ/d   C$6.00 - C$8.63           AECO
----------------------------------------------------------------------------------------------------------
</TABLE>
     (1)  Subsequent to December 31, 2008, the Company entered into 220,000 GJ/d
          of C$6.00 - C$8.00  natural gas AECO collars for the period January to
          December  2010.

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

     In  addition  to the  financial  derivatives  noted  above,  subsequent  to
     December 31,  2008,  the Company  entered  into natural gas physical  sales
     contracts  for 400,000  GJ/d at an average  fixed price of C$5.29 per GJ at
     AECO for the period April to December 2009.

LONG-TERM DEBT
     The Company's  long-term  debt of $13,016  million at December 31, 2008 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,  2008,  the Company had in place  unsecured  bank credit
     facilities of $6,232 million, comprised of:

     o    a $125 million demand credit facility;
     o    a non-revolving  syndicated credit facility of $2,350 million maturing
          October  2009, as discussed  below;
     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.  Borrowings
     under these  facilities can be made by way of Canadian dollar and US dollar
     bankers' acceptances, and LIBOR, US base rate and Canadian prime loans.

58  CANADIAN NATURAL
<PAGE>

     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 October 2009. In March 2007,  $1,500 million was repaid,
     reducing the facility to $2,350 million.  During 2009, the Company plans to
     fully retire this facility from its existing  borrowing  capacity under its
     other  long-term  bank  credit  facilities,  which were  $2,050  million at
     December  31,  2008,  supported  by cash  flow from  operating  activities,
     including the commodity  risk  management  activities.  In accordance  with
     these plans, and repayments of $420 million made subsequent to December 31,
     2008 on this facility, $420 million has been classified as current.

     In  addition  to the  outstanding  debt,  letters of credit  and  financial
     guarantees aggregating $372 million,  including $300 million related to the
     Horizon Project, were outstanding at December 31, 2008.

Medium-term notes
     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.

     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.

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

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

US Dollar Debt Securities
     In January 2008, the Company  issued  US$1,200  million of unsecured  notes
     under a 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 filed in September 2007 that allows
     for the issue of US dollar  debt  securities  in the  United  States  until
     October 2009. If issued,  these securities will bear interest as determined
     at the date of issuance.

     During 2008, US$8 million of US dollar debt securities were repaid.

     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 2008,  the Company  terminated the interest rate swaps that had been
     designated as a fair value hedge of US$350 million of 5.45% unsecured notes
     due October 2012.  Accordingly,  the Company  ceased  revaluing the related
     debt from the date of termination of the interest rate swaps for subsequent
     changes in fair value. The fair value adjustment of $20 million at the date
     of  termination is being  amortized to interest  expense over the remaining
     term of the debt.

     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 statements of earnings.

SHARE CAPITAL
     As at December 31, 2008, there were 540,991,000  common shares  outstanding
     and 30,962,000 stock options outstanding.  As at March 3, 2009, the Company
     had  541,149,000  common shares  outstanding  and 30,285,000  stock options
     outstanding.

     The Company did not renew the Normal Course Issuer Bid during 2008.  During
     2007  and  2008,  the  Company  did not  purchase  any  common  shares  for
     cancellation  (2006 - 485,000  common  shares were  purchased at an average
     price of $57.33 per common share for a total cost of $28 million).

     In March 2009, the Company's Board of Directors approved an increase in the
     annual dividend paid by the Company to $0.42 per common share for 2009. The
     increase  represents a 5% increase from the prior year. The dividend policy
     undergoes  a periodic  review by the Board of  Directors  and is subject to
     change.  In February  2008, an increase in the annual  dividend paid by the
     Company  was  approved  to $0.40 per common  share for 2008.  The  increase
     represented an 18% increase from 2007.

                                                            CANADIAN NATURAL  59
<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 firm  commitments  for  gathering,
     processing and transmission services; operating leases relating to offshore
     FPSOs,  drilling  rigs and office space;  expenditures  relating to ARO; as
     well as long-term debt and interest  payments.  As at December 31, 2008, 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, 2008:

<TABLE>
<CAPTION>
     ($ millions)                             2009      2010        2011      2012        2013     Thereafter
----------------------------------------------------------------------------------------------------------------
<S>                                     <C>         <C>       <C>         <C>       <C>         <C>
     Product transportation and         $      219  $    184  $      159  $    133  $      124  $        1,175
     pipeline
     Offshore equipment operating       $      175  $    145  $      144  $    116  $      117  $          398
     lease
     Offshore drilling                  $      251  $     62  $        -  $      -  $        -  $            -
     Asset retirement obligations (1)   $        6  $      7  $        6  $      6  $        6  $        4,443
     Long-term debt (2)                 $    2,385  $    400  $      490  $    429  $      890  $        6,707
     Interest expense(3)                $      610  $    565  $      543  $    490  $      428  $        5,992
     Office lease                       $       25  $     29  $       23  $      2  $        2  $            1
     Other                              $      321  $    180  $       17  $     12  $        8  $           19
================================================================================================================
</TABLE>

     (1)  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  2009 - 2013
          represent the minimum required expenditures to meet these obligations.
          Actual  expenditures  in any particular  year may exceed these minimum
          amounts.

     (2)  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 $1,725 million
          of revolving bank credit  facilities  due to the extendable  nature of
          the facilities.

     (3)  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, 2008.


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.

RESERVES
     For the year ended  December  31,  2008,  the Company  retained a qualified
     independent reserves evaluator,  Sproule Associates Limited ("Sproule"), to
     evaluate 100% of the Company's  conventional  proved, as well as proved and
     probable crude oil, NGLs and natural gas reserves(1) and prepare Evaluation
     Reports on these  reserves.  The Company has been granted an exemption from
     certain of the  provisions  of 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 conventional  crude
     oil,  NGLs and natural  gas reserve  reconciliations  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 the  Company's  annual  report and in its
     annual Form 40-F  filing  with the SEC.  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  additional   voluntary
     information, which is disclosed in the Company's Annual Information Form.

     (1)  Conventional  crude oil, NGLs and natural gas reserves  include all of
          the  Company's  light/medium,  primary  heavy,  and thermal crude oil,
          natural gas, coal bed methane and NGLs  reserves.  They do not include
          the Company's oil sands mining reserves.
     (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. Future development costs and associated
          material well abandonment liabilities have been applied.

60  CANADIAN NATURAL
<PAGE>

     The following tables summarize the Company's proved  conventional crude oil
     and natural gas  reserves,  net of  royalties,  as at December 31, 2008 and
     2007:

<TABLE>
<CAPTION>
                                             North                    Offshore
     Crude oil and NGLs (mmbbl)            America     North Sea   West Africa       Total
---------------------------------------------------------------------------------------------
     <S>                                   <C>              <C>         <C>         <C>
     Net conventional proved reserves
     Reserves, December 31, 2007                 920          310          128       1,358
     Extensions and discoveries                   51            -            -          51
     Improved recovery                            17            6            4          27
     Purchases of reserves in place                -            -            -           -
     Sales of reserves in place                    -            -            -           -
     Production                                  (76)         (17)          (8)       (101)
     Economic revisions due to prices             28          (81)           8         (45)
     Revisions of prior estimates                  8           38           10          56
---------------------------------------------------------------------------------------------
     Reserves, December 31, 2008                 948          256          142       1,346
==============================================================================================
</TABLE>

     The  Company's net proved  conventional  crude oil reserves at December 31,
     2008 totaled 1,346 mmbbl.  Approximately  88% of production was replaced by
     reserve  additions during 2008.  Extensions and discoveries  resulting from
     exploration  and  development  activities  amounted to 51 mmbbl,  while net
     positive revisions amounted to 11 mmbbl.


<TABLE>
<CAPTION>
     Natural gas (bcf)                        North                   Offshore      Total
                                            America      North Sea West Africa
--------------------------------------------------------------------------------------------
<S>                                        <C>           <C>       <C>              <C>
     Net conventional proved reserves
     Reserves, December 31, 2007               3,521           81           64       3,666
     Extensions and discoveries                  140            -            -         140
     Improved recovery                            52           (1)           6          57
     Purchases of reserves in place               77            -            -          77
     Sales of reserves in place                   (1)           -            -          (1)
     Production                                 (449)          (4)          (4)       (457)
     Economic revisions due to prices            (19)         (56)           6         (69)
     Revisions of prior estimates                202           47           22         271
---------------------------------------------------------------------------------------------
     Reserves, December 31, 2008               3,523           67           94       3,684
=============================================================================================
</TABLE>

     The Company's net proved conventional  natural gas reserves at December 31,
     2008 totaled 3,684 bcf.  Approximately  104% of production  was replaced by
     reserve  additions during 2008.  Extensions and discoveries  resulting from
     exploration  and  development  activities  amounted  to 140 bcf,  while net
     positive revisions amounted to 202 bcf.

     For the year ended  December  31,  2008,  the Company  retained a qualified
     independent reserves evaluator,  GLJ Petroleum Consultants Ltd. ("GLJ"), to
     evaluate Phase 1 to Phase 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.  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.

     Synthetic crude oil reserves (1)
     Net reserves, after royalties (mmbbl)                   2008|         2007
-----------------------------------------------------------------|--------------
     Proved                                                 1,946|        1,761
     Proved and probable                                    2,944|        2,680
=================================================================|==============
     (1)  SCO reserves are based on the upgrading of bitumen using  technologies
          implemented  at the  Horizon  Project.

     The net proved SCO reserves  increased  by 185 mmbbl,  while net proved and
     probable SCO reserves  increased by 264 mmbbl.  The increases are primarily
     due to a low constant dollar crude oil price,  deferring project payout and
     thereby reducing royalties paid.

     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
     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.

                                                            CANADIAN NATURAL  61
<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 SCO. 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  property loss and business
     interruption  insurance  program  to reduce  risk to an  acceptable  level.
     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 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.  Substantially all of
     the  Company's  accounts  receivables  are due within  normal  trade terms.
     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 is 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.  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.

     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;

62  CANADIAN NATURAL
<PAGE>


     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    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;
     o    Using  water-based,  environmentally  friendly  drilling muds whenever
          possible; and
     o    Minimizing   produced  water  volumes  onshore  and  offshore  through
          cost-effective measures.

     For 2008,  the  Company's  capital  expenditures  included  $38 million for
     abandonment expenditures (2007 - $71 million; 2006 - $75 million).

     The  Company's  estimated  undiscounted  ARO at  December  31,  2008 was as
     follows:

     Estimated ARO, undiscounted ($ millions)               2008 |       2007
-----------------------------------------------------------------|--------------
     North America, including Horizon Project     $        3,165 |   $  3,038
     North Sea                                             1,216 |      1,286
     Offshore West Africa                                     93 |        102
-----------------------------------------------------------------|--------------
                                                           4,474 |      4,426
     North Sea PRT recovery                                 (529)|       (555)
-----------------------------------------------------------------|--------------
                                                  $        3,945 |   $  3,871
=================================================================|==============

     The  estimate of ARO is based on  estimates  of future costs to abandon and
     restore 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  estimated  to result in a PRT  recovery of $529  million
     (2007 - $555 million;  2006 - $625 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  $3,945  million  (2007  -  $3,871
     million).

GREENHOUSE GAS AND OTHER AIR EMISSIONS
     The  Company,  through the  Canadian  Association  of  Petroleum  Producers
     ("CAPP"),  is 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 emissions  reduction  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 of the Company's facilities,
     the Primrose/Wolf Lake in-situ heavy crude oil facilities and the Hays sour
     natural gas plant, fall under the regulations. Commencing July 1, 2008, the
     British  Columbia carbon tax is being assessed at $10/tonne of CO2e on fuel
     consumed in the  province,  increasing to $30/tonne by July 1, 2012. In the
     UK, GHG 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 to reduce CO2 emissions at its major  facilities  and on
     trading mechanisms to ensure compliance with requirements 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
     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

                                                            CANADIAN NATURAL  63
<PAGE>


     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 Company and industry  participation  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 Canadian GAAP
     that have a  significant  impact on the  financial  results of the Company.
     Actual results may differ from those estimates,  and those  differences may
     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  estimated  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 single-day,  year-end prices and costs ("constant  dollar pricing") as
     required by the SEC for US GAAP purposes.

     Under  Canadian  GAAP,  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. No ceiling test  impairments were
     recognized under Canadian GAAP at December 31, 2008, as future net revenues
     exceeded  capitalized  costs.  Under US GAAP, the ceiling test differs from
     Canadian GAAP in that future net revenues from proved reserves are based on
     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  in  the  current  year  resulted  in  the
     recognition of an after-tax  ceiling test  impairment of $6,164 million for
     US GAAP purposes.

     The US GAAP ceiling test is based on constant  dollar pricing and is highly
     sensitive to differences in benchmark pricing and the Heavy Differential in
     effect at year end as  opposed  to  pricing  throughout  the  year.  As the
     Company's crude oil production is weighted  towards heavier grades of crude
     oil,  which  have  historically  traded at lower  prices at year end due to
     normal  seasonality,  constant  dollar  pricing  in  effect  at year end is
     generally not  representative  of average pricing  realized  throughout the
     year. Had the US GAAP ceiling test at December 31, 2008 been prepared using
     average  realized  pricing  throughout  2008,  rather than constant  dollar
     pricing,  and assuming no other changes in reserves,  operating  costs,  or
     future  development  costs, the Company would not have recognized a ceiling
     test impairment loss in the current year for US GAAP purposes.

     The alternate acceptable method of accounting for crude oil and natural gas
     properties  and  equipment  is  the  successful  efforts  method.  A  major
     difference in applying the successful  efforts  method is that  exploratory
     dry holes and geological and geophysical exploration costs would be charged
     against net earnings in the year incurred rather than being  capitalized to
     property, plant and equipment. In addition, under this method, cost centres
     are defined based on reserve  pools rather than by country.  The use of the
     full cost method usually results in higher  capitalized costs and increased
     DD&A rates compared to the successful efforts method.

Crude Oil and Natural Gas Reserves
     The  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  and  amount  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 may also result in
     an impairment  of crude oil and natural gas  property,  plant and equipment
     carrying amounts under the ceiling test.

64  CANADIAN NATURAL
<PAGE>

Asset Retirement Obligations
     Under CICA  Handbook  Section 3110,  "Asset  Retirement  Obligations",  the
     Company is required to  recognize  a  liability  for the future  retirement
     obligations  associated with its property,  plant and equipment.  An ARO is
     recognized  to  the  extent  of a  legal  obligation  associated  with  the
     retirement of a tangible long-lived asset the Company is required to settle
     as a result of an existing or enacted law, statute, ordinance or written or
     oral contract, or by legal construction of a contract under the doctrine of
     promissory  estoppel.  The ARO is based on  estimated  costs,  taking  into
     account the  anticipated  method and extent of restoration  consistent with
     legal  requirements,  technological  advances  and the  possible use of the
     site.  Since these estimates are specific to the sites involved,  there are
     many  individual  assumptions  underlying  the Company's  total ARO amount.
     These individual assumptions can be subject to change.

     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 6.7%. In subsequent periods,  the ARO is adjusted for the passage
     of time and for any  changes  in the  amount or  timing  of the  underlying
     future  cash  flows.  The  estimates  described  impact  earnings by way of
     depletion on the  retirement  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 may 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 or 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.

Risk Management Activities
     The Company utilizes various derivative financial instruments to manage its
     commodity  price,  foreign  currency and  interest  rate  exposures.  These
     financial  instruments are entered into solely for hedging purposes and are
     not used for speculative purposes.

     The  estimated  fair value of  derivative  financial  instruments  has been
     determined based on appropriate  internal  valuation  methodologies  and/or
     third party  indications.  Fair values  determined  using valuation  models
     require the use of  assumptions  concerning the amount and timing of future
     cash flows and  discount  rates.  In  determining  these  assumptions,  the
     Company has relied primarily on external readily  observable  market inputs
     including  quoted  commodity  prices and  volatility,  interest  rate yield
     curves,  and foreign exchange rates. The resulting fair value estimates may
     not  necessarily  be  indicative  of the  amounts  that may 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
     judgements  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  internal  engineers  and  outside
     consultants.  The judgements  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.

                                                            CANADIAN NATURAL  65
<PAGE>

<PAGE>

CONTROL ENVIRONMENT
      The Company's  management,  including  the President and Chief  Operating
      Officer  and the  Chief  Financial  Officer  and  Senior  Vice-President,
      Finance,   evaluated  the   effectiveness  of  disclosure   controls  and
      procedures  as at  December  31,  2008,  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
      the Company's  management to allow timely  decisions  regarding  required
      disclosures.

      The Company's  management,  including  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, 2008,  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 2008 that
      have materially affected,  or are reasonably likely to materially affect,
      internal controls over financial reporting.

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

NEW ACCOUNTING STANDARDS
      Effective  January 1, 2008, the Company adopted the following  accounting
      and disclosure 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 standard also requires
            the disclosure of any externally  imposed capital  requirements and
            compliance  with those  requirements.  The standard does not define
            capital.  This standard affects  disclosure only and did 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  did not 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
            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 did not impact the Company's
            accounting for financial instruments.

      Effective  January 1, 2009,  the  Company  will adopt the  following  new
      accounting standard issued by the CICA:

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  future  capitalization  of
            certain  costs  during  the   development  and  start-up  of  large
            development projects.

INTERNATIONAL FINANCIAL REPORTING STANDARDS
      In February 2008, the CICA's  Accounting  Standards  Board confirmed that
      Canadian  publicly  accountable  enterprises  will be  required  to adopt
      International  Financial  Reporting  Standards ("IFRS") as promulgated by
      the  International  Accounting  Standards  Board  ("IASB")  in  place  of
      Canadian GAAP effective January 1, 2011.

      The  Company  commenced  its  IFRS  conversion  project  in 2008  and has
      established a formal project governance structure. The structure includes
      a Steering Committee,  which consists of senior levels of management from
      finance and accounting, operations and information technology ("IT"). The
      Steering  Committee  provides  regular  updates to the  Company's  Senior
      Management and the Audit Committee of the Board of Directors.



66  CANADIAN NATURAL
<PAGE>

      The Company's IFRS conversion project consists of the following phases:

      o     Phase 1 Diagnostic -  identification  of potential  accounting  and
            reporting differences between Canadian GAAP and IFRS.
      o     Phase 2 Planning - development  of project  governance,  processes,
            resources, budget and timeline.
      o     Phase 3  Policy  Delivery  and  Documentation  -  establishment  of
            accounting policies under IFRS.
      o     Phase 4 Policy  Implementation  -  establishment  of processes  for
            accounting and reporting, IT change requirements, and education.
      o     Phase  5   Sustainment  -  ongoing   compliance   with  IFRS  after
            implementation.

      The Company has completed the Diagnostic phase.  Significant  differences
      were identified in accounting for Property,  Plant & Equipment  ("PP&E"),
      including  exploration  costs,  depletion  and  depreciation,  impairment
      testing,  capitalized  interest and asset retirement  obligations.  Other
      significant   differences   were  noted  in  accounting  for  stock-based
      compensation,  risk management activities,  and income taxes. The Company
      is currently  performing  the necessary  research to develop and document
      IFRS policies to address the major  differences  noted. At this time, the
      impact  on  the  Company's  future  financial  position  and  results  of
      operations is not reasonably determinable.  In addition, IFRS is expected
      to change  prior to adoption in 2011,  and the impact of these  potential
      changes  is not  known.  Included  in the  potential  IFRS  changes is an
      exposure  draft  issued  in  September  2008 by the  IASB  that  proposes
      transition   rules  for  oil  and  gas  companies   following  full  cost
      accounting.  The proposed transition rule would allow full cost companies
      to allocate  their  existing full cost PP&E balances using reserve values
      or  volumes  to  IFRS  compliant  units  of  account  as at the  date  of
      conversion without requiring retroactive adjustment.  The Company intends
      to adopt the transition rule if it is approved.

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 2009 to average  between  331,000 bbl/d and 399,000
      bbl/d of crude oil and NGLs and between  1,272 mmcf/d and 1,328 mmcf/d of
      natural gas.

      The forecasted capital  expenditures in 2009 are currently expected to be
      as follows:

-------------------------------------------------------------------------------
      ($ millions)                                                2009 Forecast
-------------------------------------------------------------------------------
      Conventional crude oil and natural gas
         North America natural gas                             $            589
         North America crude oil and NGLs                                 1,138
         North Sea                                                          141
         Offshore West Africa                                               553
         Property acquisitions, dispositions and midstream                  109
-------------------------------------------------------------------------------
                                                               $          2,530
-------------------------------------------------------------------------------
      Horizon Project
         Phase 1 - Construction                                $            180
         Phase 1 - Operating and capital inventory                           43
         Phase 1 - Commissioning costs                                      183
         Phase 2/3 - Tranche 2                                              121
         Sustaining capital                                                  94
         Capitalized interest and other costs                                41
-------------------------------------------------------------------------------
                                                               $            662
-------------------------------------------------------------------------------
      Total                                                    $          3,192
===============================================================================

North America Natural Gas
      The 2009 North America natural gas drilling program is highlighted by the
      continued  high-grading  of the  Company's  natural  gas  asset  base  as
      follows:

-------------------------------------------------------------------------------
      (Number of wells)                                           2009 Forecast
-------------------------------------------------------------------------------
      Coal bed methane and shallow natural gas                               30
      Conventional natural gas                                               66
      Cardium natural gas                                                     9
      Deep natural gas                                                       37
-------------------------------------------------------------------------------
      Total                                                                 142
===============================================================================

      The Company has reduced  2009  natural gas drilling in Alberta due to the
      anticipated future impact of royalty changes effective January 1, 2009.



                                                          CANADIAN NATURAL   67
<PAGE>

North America Crude Oil and NGLs
      The 2009 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:

-------------------------------------------------------------------------------
      (Number of wells)                                           2009 Forecast
-------------------------------------------------------------------------------
      Conventional primary heavy crude oil                                  317
      Thermal heavy crude oil                                                70
      Light crude oil                                                        20
      Pelican Lake crude oil                                                 58
-------------------------------------------------------------------------------
      Total                                                                 465
===============================================================================

Horizon Project
      During the initial  stages of the ramp-up of  production,  the production
      volumes  will  fluctuate  on a weekly  basis  until the end of the second
      quarter of 2009 when the Company  expects to see a steady ramp up to full
      production capacity of 110,000 bbl/d by the end of 2009. The Company will
      work towards full capacity  throughout  2009 as the plant continues to be
      fine tuned to design rates with a focus on safety and reliability.

North Sea
      The 2009 capital  forecast  for the North Sea  includes  drilling 0.9 net
      platform wells with focus on building drilling and workover inventory for
      2010.

Offshore West Africa
      The 2009  capital  forecast  for  anticipates  spending  $80  million  to
      complete Phase 2 of the development of the Baobab Field in Cote d'Ivoire.
      The Company is  targeting  the fourth well to be  completed in the second
      quarter of 2009.

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  2008,  excluding  mark-to-market  gains
      (losses) on risk management activities and capitalized  interest,  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 with all other variables being held constant.

<TABLE>
<CAPTION>
      -----------------------------------------------------------------------------------------------------------------
                                                       CASH FLOW         CASH FLOW
                                                            FROM              FROM              NET                NET
                                                      OPERATIONS        OPERATIONS         EARNINGS          EARNINGS
                                                                       (per common                        (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            $         112    $         0.21    $          84    $         0.16
        Including financial derivatives            $          66    $         0.12    $          48    $         0.09
      Natural gas - AECO C$0.10/mcf (1)
        Excluding financial derivatives            $          38    $         0.07    $          28    $         0.05
        Including financial derivatives            $          38    $         0.07    $          28    $         0.05
      Volume changes
      Crude oil - 10,000 bbl/d                     $          87    $         0.16    $          38    $         0.07
      Natural gas - 10 mmcf/d                      $          18    $         0.03    $           7    $         0.01
      Foreign currency rate change
      $0.01 change in US$ (1)
      Including financial derivatives              $     89 - 92    $         0.17    $       8 - 9    $         0.02
      Interest rate change - 1%                    $          32    $         0.06    $          32    $         0.06
      -----------------------------------------------------------------------------------------------------------------
</TABLE>
      (1)   For details of financial  instruments in place, refer to note 13 to
            the Company's audited annual consolidated  financial  statements as
            at December 31, 2008.


68   CANADIAN NATURAL
<PAGE>

<TABLE>
<CAPTION>
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
-----------------------------------------------------------------------------------------------------------|-----------------------
                                                 Q1           Q2          Q3           Q4           2008   |     2007         2006
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                         <C>          <C>          <C>          <C>          <C>          <C>          <C>
     Crude oil and NGLs (bbl/d)                                                                            |
     North America                            248,960      245,616      239,973      240,831      243,826  |   246,779      235,253
     North Sea                                 49,568       45,830       42,760       42,991       45,274  |    55,933       60,056
     Offshore West Africa                      28,689       27,631       24,237       25,748       26,567  |    28,520       36,689
-----------------------------------------------------------------------------------------------------------------------------------
     Total                                    327,217      319,077      306,970      309,570      315,667  |   331,232      331,998
-----------------------------------------------------------------------------------------------------------------------------------
     Natural gas (mmcf/d)                                                                                  |
     North America                              1,513        1,501        1,467        1,405        1,472  |     1,643        1,468
     North Sea                                     11           10            9           10           10  |        13           15
     Offshore West Africa                          14           15           14           12           13  |        12            9
-----------------------------------------------------------------------------------------------------------------------------------
     Total                                      1,538        1,526        1,490        1,427        1,495  |     1,668        1,492
-----------------------------------------------------------------------------------------------------------------------------------
     Barrels of oil equivalent                                                                             |
     (boe/d)                                                                                               |
     North America                            501,061      495,836      484,542      475,089      489,081  |   520,564      479,891
     North Sea                                 51,404       47,545       44,309       44,623       46,956  |    58,099       62,558
     Offshore West Africa                      31,023       30,056       26,505       27,687       28,808  |    30,543       38,275
-----------------------------------------------------------------------------------------------------------------------------------
     Total                                    583,488      573,437      555,356      547,399      564,845  |   609,206      580,724
===================================================================================================================================
                                                                                                           |
<CAPTION>
-----------------------------------------------------------------------------------------------------------|-----------------------
PER UNIT RESULTS (1)                        Q1           Q2          Q3           Q4           2008   |     2007         2006
-----------------------------------------------------------------------------------------------------------|-----------------------
<S>                                         <C>          <C>          <C>          <C>          <C>          <C>          <C>
     Crude oil and NGLs ($/bbl)
     Sales price (2)                        $   78.99    $  103.73    $  102.30    $   45.81    $   82.41  | $   55.45    $   53.65
     Royalties                                   8.70        14.82        14.17         4.49        10.48  |      5.94         4.48
     Production expense                         14.81        16.39        17.61        16.33        16.26  |     13.34        12.29
                                                                                                           |
-----------------------------------------------------------------------------------------------------------|-----------------------
     Netback                                $   55.48    $   72.52    $   70.52    $   24.99    $   55.67  | $   36.17    $   36.88
-----------------------------------------------------------------------------------------------------------|-----------------------
     Natural gas ($/mcf)                                                                                   |
     Sales price (2)                        $    7.77    $    9.89    $    8.82    $    7.03    $    8.39  | $    6.85    $    6.72
     Royalties                                   1.35         1.86         1.55         1.08         1.46  |      1.11         1.29
     Production expense                          1.03         0.94         1.05         1.06         1.02  |      0.91         0.82
-----------------------------------------------------------------------------------------------------------|-----------------------
     Netback                                $    5.39    $    7.09    $    6.22    $    4.89    $    5.91  | $    4.83    $    4.61
-----------------------------------------------------------------------------------------------------------|-----------------------
     Barrels of oil equivalent                                                                             |
     ($/boe)                                                                                               |
     Sales price (2)                        $   65.09    $   84.88    $   80.60    $   43.84    $   68.62  | $   49.05    $   47.92
     Royalties                                   8.43        13.26        12.06         5.37         9.78  |      6.26         5.89
     Production expense                         11.02        11.60        12.52        12.05        11.79  |      9.75         9.14
-----------------------------------------------------------------------------------------------------------|----------------------
     Netback                                $   45.64    $   60.02    $   56.02    $   26.42    $   47.05  | $   33.04    $   32.89
===================================================================================================================================
</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.

<TABLE>
<CAPTION>
NETBACK ANALYSIS
---------------------------------------------------------------------------------------------|-------------------------------------
     ($/boe) (1)                                                                    2008     |           2007                 2006
---------------------------------------------------------------------------------------------|-------------------------------------
<S>                                                                             <C>                 <C>                  <C>
     Sales price (2)                                                            $   68.62    |      $   49.05            $   47.92
     Royalties                                                                       9.78    |           6.26                 5.89
     Production expense (3)                                                         11.79    |           9.75                 9.14
---------------------------------------------------------------------------------------------|-------------------------------------
     Netback                                                                        47.05    |          33.04                32.89
     Midstream contribution (3)                                                     (0.25)   |          (0.23)               (0.23)
     Administration                                                                  0.87    |           0.93                 0.85
     Interest, net                                                                   0.62    |           1.24                 0.66
     Realized risk management loss                                                   8.99    |           0.73                 6.27
     Realized foreign exchange loss                                                 (0.55)   |           0.24                (0.06)
     (gain)                                                                                  |
     Taxes other than income tax -                                                   1.18    |           0.54                 1.04
     current                                                                                 |
     Current income tax - North                                                      0.15    |           0.43                 0.68
     America                                                                                 |
     Current income tax - North Sea                                                  1.64    |           0.95                 0.14
     Current income tax - Offshore                                                   0.62    |           0.33                 0.23
     West Africa                                                                             |
-----------------------------------------------------------------------------------------------------------------------------------
     Cash flow                                                                  $   33.78    |      $   27.88            $   23.31
===================================================================================================================================
</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.


                                                          CANADIAN NATURAL   69

<PAGE>

<TABLE>
<CAPTION>
TRADING AND SHARE STATISTICS
-----------------------------------------------------------------------------------------------------------|------------
                                                    Q1           Q2           Q3           Q4         2008 |       2007
-----------------------------------------------------------------------------------------------------------|------------
<S>                                         <C>          <C>          <C>          <C>          <C>          <C>
     TSX - C$                                                                                              |
     Trading Volume (thousands)                134,421      145,018      186,906      213,393      679,738 |    429,034
     Share Price ($/share)                                                                                 |
     High                                  $     76.80   $   111.30   $   104.83   $    72.89   $   111.30 | $    80.02
     Low                                   $     58.88   $    68.08   $    64.40   $    34.19   $    34.19 | $    52.45
     Close                                 $     70.27   $   100.84   $    73.00   $    48.75   $    48.75 | $    72.58
     Market capitalization as at                                                                           |
       December 31 ($ millions)                                                                 $   26,373 | $   39,174
                                                                                                           |
     Shares outstanding (thousands)                                                                540,991 |    539,729
-----------------------------------------------------------------------------------------------------------|------------
     NYSE - US$                                                                                            |
     Trading Volume (thousands)                157,781      190,756      292,659      326,032      967,228 |    486,266
     Share Price ($/share)                                                                                 |
     High                                  $     78.43   $   109.32   $   103.40   $    68.87   $   109.32 | $    87.17
     Low                                   $     57.07   $    66.21   $    61.82   $    26.43   $    26.43 | $    44.56
     Close                                 $     68.26   $   100.25   $    68.46   $    39.98   $    39.98 | $    73.14
     Market capitalization as at                                                                           |
       December 31($ millions)                                                                  $   21,629 | $   39,476
     Shares outstanding (thousands)                                                                540,991 |    539,729
===========================================================================================================|============
</TABLE>



70   CANADIAN NATURAL
<PAGE>
-------------------------------------------------------------------------------
                                         CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------


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

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

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

      PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants,
      has  been  engaged,  as  approved  by a vote of the  shareholders  at the
      Company's most recent Annual General Meeting,  to audit and provide their
      independent audit opinions on the following:

      o     the Company's  consolidated financial statements as at December 31,
            2008; and

      o     the effectiveness of the Company's  internal control over financial
            reporting as at December 31, 2008.

      Their report is presented with the consolidated financial statements.

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


<TABLE>
<S>                            <C>                          <C>
      /s/ Steve W. Laut        /s/ Douglas A. Proll         /s/ Randall S. Davis
      -------------------      -------------------------    -------------------------
      Steve W. Laut            Douglas A. Proll, CA         Randall S. Davis, CA
      PRESIDENT & CHIEF        CHIEF FINANCIAL OFFICER &    VICE-PRESIDENT, FINANCE &
      OPERATING OFFICER        SENIOR VICE-PRESIDENT,       ACCOUNTING
                               FINANCE
</TABLE>

      March 4, 2009
      CALGARY, ALBERTA, CANADA



                                                          CANADIAN NATURAL   71
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M A N A G E M E N T ' S   A S S E S S M E N T   O F   I N T E R N A L
C O N T R O L   O V E R   F I N A N C I A L   R E P O R T I N G

      Management is  responsible  for  establishing  and  maintaining  adequate
      internal  control over financial  reporting for the Company as defined in
      rules 13a-15(f) and 15d-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,  2008.  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.

      Pricewaterhousecoopers LLP, an independent firm of chartered accountants,
      has provided an opinion on the Company's  internal control over financial
      reporting as at December 31, 2008, as stated in their auditors' report.



      /s/ Steve W. Laut                           /s/ Douglas A. Proll
      ------------------------------------        ------------------------------
      Steve W. Laut                               Douglas A. Proll, CA
      PRESIDENT & CHIEF OPERATING OFFICER         CHIEF FINANCIAL OFFICER &
                                                  SENIOR VICE-PRESIDENT, FINANCE

      March 4, 2009
      CALGARY, ALBERTA, CANADA


-------------------------------------------------------------------------------

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



      To the Shareholders of Canadian Natural Resources Limited

      We  have  completed  integrated  audits  of  Canadian  Natural  Resources
      Limited's 2008, 2007, and 2006 consolidated  financial  statements and of
      its internal  control over  financial  reporting as at December 31, 2008.
      Our opinions, based on our audits, are presented below.


CONSOLIDATED FINANCIAL STATEMENTS

      We have audited the accompanying  consolidated balance sheets of Canadian
      Natural  Resources  Limited (the  "Company")  as at December 31, 2008 and
      December 31, 2007, 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,  2008.   These
      consolidated financial statements are the responsibility of the Company's
      management.  Our  responsibility  is  to  express  an  opinion  on  these
      consolidated financial statements based on our audits.

      We  conducted  our  audits  of  the  Company's   consolidated   financial
      statements  in  accordance  with  Canadian  generally  accepted  auditing
      standards and the standards of the public  Company  accounting  oversight
      Board (United States).  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.


72   CANADIAN NATURAL
<PAGE>
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                                            CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------

      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, 2008 and December 31, 2007 and the results of
      its operations and its cash flows for each of the years in the three year
      period ended  December 31, 2008 in  accordance  with  Canadian  generally
      accepted accounting principles.


INTERNAL CONTROL OVER FINANCIAL REPORTING

      We have also audited Canadian Natural Resource Limited's internal control
      over  financial  reporting  as at December  31,  2008,  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  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
      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,
      2008  based  on  criteria  established  in internal  control - integrated
      Framework issued by the COSO.


      /s/PRICEWATERHOUSECOOPERS LLP
      ----------------------------------
      CHARTERED ACCOUNTANTS
      CALGARY, ALBERTA, CANADA
      March 4, 2009


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 changes indicated in the Consolidated Statements
      of  Shareholders'  Equity  and  Comprehensive  Income.  Our report to the
      Shareholders dated March 4, 2009 is expressed in accordance with Canadian
      reporting  standards which do not require a reference to such a change in
      accounting principles in the auditors' report when the change is properly
      accounted  for and  adequately  disclosed in the  consolidated  financial
      statements.


      /s/PRICEWATERHOUSECOOPERS LLP
      ----------------------------------
      CHARTERED ACCOUNTANTS
      CALGARY, ALBERTA, CANADA
      March 4, 2009


                                                          CANADIAN NATURAL   73
<PAGE>

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-------------------------------------------------------------------------------

C O N S O L I D A T E D   B A L A N C E   S H E E T S

<TABLE>
<CAPTION>
     As at December 31                                                                           |
     (millions of Canadian dollars)                                                        2008  |           2007
-------------------------------------------------------------------------------------------------|----------------
<S>                                                                        <C>                <C>
     ASSETS                                                                                      |
     Current assets                                                                              |
        Cash and cash equivalents                                               $            27  | $           21
        Accounts receivable and other                                                     1,514  |          1,662
        Future income tax (note 8)                                                            -  |            480
        Current portion of other long-term assets (note 3)                                1,851  |             18
-------------------------------------------------------------------------------------------------|----------------
                                                                                          3,392  |          2,181
     Property, plant and equipment (note 4)                                              38,966  |         33,902
     Other long-term assets (note 3)                                                        292  |             31
-------------------------------------------------------------------------------------------------|----------------
                                                                                $        42,650  | $       36,114
-------------------------------------------------------------------------------------------------|----------------
     LIABILITIES                                                                                 |
     Current liabilities                                                                         |
        Accounts payable                                                        $           383  | $          379
        Accrued liabilities                                                               1,802  |          1,567
        Future income tax (note 8)                                                          585  |              -
        Current portion of long-term debt (note 5)                                          420  |              -
        Current portion of other long-term liabilities (note 6)                             230  |          1,617
-------------------------------------------------------------------------------------------------|----------------
                                                                                          3,420  |          3,563
     Long-term debt (note 5)                                                             12,596  |         10,940
     Other long-term liabilities (note 6)                                                 1,124  |          1,561
     Future income tax (note 8)                                                           7,136  |          6,729
-------------------------------------------------------------------------------------------------|----------------
                                                                                         24,276  |         22,793
-------------------------------------------------------------------------------------------------|----------------
     SHAREHOLDERS' EQUITY                                                                        |
     Share capital (note 9)                                                               2,768  |          2,674
     Retained earnings                                                                   15,344  |         10,575
     Accumulated other comprehensive income (note 10)                                       262  |             72
-------------------------------------------------------------------------------------------------|----------------
                                                                                         18,374  |         13,321
-------------------------------------------------------------------------------------------------|----------------
                                                                                $        42,650  | $       36,114
=================================================================================================|================
</TABLE>
     Commitments and contingencies (note 14).



     Approved by the Board of Directors:


     /s/Catherine M. Best                        N. Murray Edwards
     -----------------------------------         ------------------------------
     Catherine M. Best                           N. Murray Edwards
     CHAIR OF THE AUDIT COMMITTEE                VICE-CHAIRMAN OF THE BOARD OF
     AND DIRECTOR                                OF DIRECTORS



74   CANADIAN NATURAL
<PAGE>
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                                            CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------

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

<TABLE>
<CAPTION>
     For the years ended December 31                                                       |
     (millions of Canadian dollars, except per common share amounts)                 2008  |         2007          2006
-------------------------------------------------------------------------------------------|-----------------------------
<S>                                                                           <C>             <C>            <C>
     Revenue                                                                  $    16,173  |  $    12,543    $   11,643
     Less: royalties                                                               (2,017) |       (1,391)       (1,245)
-------------------------------------------------------------------------------------------|-----------------------------
     Revenue, net of royalties                                                     14,156  |       11,152        10,398
-------------------------------------------------------------------------------------------|-----------------------------
     Expenses                                                                              |
     Production                                                                     2,451  |        2,184         1,949
     Transportation and blending                                                    1,936  |        1,570         1,443
     Depletion, depreciation and amortization                                       2,683  |        2,863         2,391
     Asset retirement obligation accretion (note 6)                                    71  |           70            68
     Administration                                                                   180  |          208           180
     Stock-based compensation (recovery) expense (note 6)                             (52) |          193           139
     Interest, net                                                                    128  |          276           140
     Risk management activities (note 13)                                          (1,230) |        1,562           312
     Foreign exchange loss (gain)                                                     718  |         (471)          122
-------------------------------------------------------------------------------------------|-----------------------------
                                                                                    6,885  |        8,455         6,744
-------------------------------------------------------------------------------------------|-----------------------------
     Earnings before taxes                                                          7,271  |        2,697         3,654
     Taxes other than income tax (note 8)                                             178  |          165           256
     Current income tax expense (note 8)                                              501  |          380           222
     Future income tax expense (recovery) (note 8)                                  1,607  |         (456)          652
-------------------------------------------------------------------------------------------|-----------------------------
     Net earnings                                                             $     4,985  |  $     2,608    $    2,524
===========================================================================================|=============================
     Net earnings per common share (note 12)                                               |
        Basic and diluted                                                     $      9.22  |  $      4.84    $     4.70
===========================================================================================|=============================
</TABLE>


                                                          CANADIAN NATURAL   75
<PAGE>
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-------------------------------------------------------------------------------

C O N S O L I D A T E D    S T A T E M E N T S   O F
S H A R E H O L D E R S'   E Q U I T Y

<TABLE>
<CAPTION>
     For the years ended December 31                                                       |
     (millions of Canadian dollars)                                                  2008  |         2007          2006
-------------------------------------------------------------------------------------------|-----------------------------
<S>                                                                            <C>            <C>           <C>
     Share capital                                                                         |
     Balance - beginning of year                                               $    2,674  |  $     2,562   $     2,442
     Issued upon exercise of stock options                                             18  |           21            21
     Previously recognized liability on stock options exercised                            |
     for common shares                                                                 76  |           91           101
     Purchase of common shares under Normal Course Issuer Bid                           -  |            -            (2)
-------------------------------------------------------------------------------------------|-----------------------------
     Balance - end of year                                                          2,768  |        2,674         2,562
-------------------------------------------------------------------------------------------|-----------------------------
     Retained earnings                                                                     |
     Balance - beginning of year, as originally reported                           10,575  |        8,141         5,804
     Transition adjustment on adoption of financial instruments                            |
     standards                                                                          -  |           10              -
-------------------------------------------------------------------------------------------|-----------------------------
     Balance - beginning of year, as restated                                      10,575  |        8,151         5,804
     Net earnings                                                                   4,985  |        2,608         2,524
     Dividends on common shares (note 9)                                             (216) |         (184)         (161)
     Purchase of common shares under Normal Course Issuer Bid                           -  |            -           (26)
-------------------------------------------------------------------------------------------|-----------------------------
     Balance - end of year                                                         15,344  |       10,575         8,141
-------------------------------------------------------------------------------------------|-----------------------------
     Accumulated other comprehensive income (loss)                                         |
     Balance - beginning of year                                                       72  |          (13)           (9)
     Transition adjustment on adoption of financial instruments                            |
     standards                                                                          -  |          159              -
-------------------------------------------------------------------------------------------|-----------------------------
     Balance - beginning of year, after effect of transition                               |
     adjustment                                                                        72  |          146            (9)
     Other comprehensive income (loss), net of taxes                                  190  |          (74)           (4)
-------------------------------------------------------------------------------------------|-----------------------------
     Balance - end of year                                                            262  |           72           (13)
-------------------------------------------------------------------------------------------|-----------------------------
     Shareholders' equity                                                      $   18,374  |  $    13,321   $    10,690
===========================================================================================|=============================
</TABLE>

C O N S O L I D A T E D   S T A T E M E N T S   O F
C O M P R E H E N S I V E   I N C O M E

<TABLE>
<CAPTION>
     For the years ended December 31                                                       |
     (millions of Canadian dollars)                                                2008    |         2007          2006
-------------------------------------------------------------------------------------------|-----------------------------
<S>                                                                           <C>              <C>           <C>
     Net earnings                                                             $   4,985    |   $    2,608    $    2,524
-------------------------------------------------------------------------------------------|------------------------------
     Net change in derivative financial instruments  designated                            |
     as cash flow hedges                                                                   |
     Unrealized income during the year,  net of taxes of $1                          30    |           38             -
     million (2007 - $6 million, 2006 - $nil)                                              |
     Reclassification to net earnings,  net of taxes of $6                          (12)   |          (96)            -
     million (2007 - $45 million, 2006 - $nil)                                             |
-------------------------------------------------------------------------------------------|------------------------------
                                                                                     18    |          (58)            -
     Foreign currency translation adjustment                                               |
     Translation of net investment                                                  172    |          (16)           (4)
-------------------------------------------------------------------------------------------|------------------------------
     Other comprehensive income (loss), net of taxes                                190    |          (74)           (4)
-------------------------------------------------------------------------------------------|------------------------------
     Comprehensive income                                                     $   5,175    |   $    2,534    $    2,520
==========================================================================================================================
</TABLE>


76   CANADIAN NATURAL
<PAGE>
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                                            CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------

C O N S O L I D A T E D   S T A T E M E N T S   O F   C A S H   F L O W S

<TABLE>
<CAPTION>
     For the years ended December 31                                       |
     (millions of Canadian dollars)                                  2008  |         2007              2006
     ----------------------------------------------------------------------|---------------------------------
<S>                                                         <C>               <C>              <C>
     Operating activities                                                  |
     Net earnings                                           $       4,985  |  $     2,608      $      2,524
     Non-cash items                                                        |
        Depletion, depreciation and amortization                    2,683  |        2,863             2,391
        Asset retirement obligation accretion                          71  |           70                68
        Stock-based compensation (recovery) expense                   (52) |          193               139
        Unrealized risk management (gain) loss                     (3,090) |        1,400            (1,013)
        Unrealized foreign exchange loss (gain)                       832  |         (524)              134
        Deferred petroleum revenue tax (recovery)                          |
        expense                                                       (67) |           44                37
        Future income tax expense (recovery)                        1,607  |         (456)              652
     Other                                                             25  |           38                (2)
     Abandonment expenditures                                         (38) |          (71)              (75)
     Net change in non-cash working capital (note 15)                (189) |         (346)             (679)
     ----------------------------------------------------------------------|---------------------------------
                                                                    6,767  |        5,819             4,176
     ----------------------------------------------------------------------|---------------------------------
     Financing activities                                                  |
     (Repayment) issue of bank credit facilities, net                (623) |       (1,925)            6,499
     Issue of medium-term notes                                         -  |          273               400
     Repayment of senior unsecured notes                              (31) |          (33)                -
     issue of US dollar debt securities                             1,215  |        2,553               788
     Issue of common shares on exercise of stock options               18  |           21                21
     Dividends on common shares                                      (208) |         (178)             (153)
     Purchase of common shares                                          -  |            -               (28)
     Net change in non-cash working capital (note 15)                  46  |            8                37
     ----------------------------------------------------------------------|---------------------------------
                                                                      417  |          719             7,564
     ----------------------------------------------------------------------|---------------------------------
     Investing activities                                                  |
     Expenditures on property, plant and equipment                 (7,433) |       (6,464)           (7,266)
     Net proceeds on sale of property, plant and                           |
     equipment                                                         20  |          110                71
     ----------------------------------------------------------------------|---------------------------------
     Net expenditures on property, plant and equipment             (7,413) |       (6,354)           (7,195)
     Acquisition of Anadarko Canada Corporation (note 16)               -  |            -            (4,641)
     Net change in non-cash working capital (note 15)                 235  |         (186)              101
     ----------------------------------------------------------------------|---------------------------------
                                                                   (7,178) |       (6,540)          (11,735)
     ----------------------------------------------------------------------|---------------------------------
     Increase (Decrease) In Cash And Cash Equivalents                   6  |           (2)                5
     Cash And Cash Equivalents - Beginning Of Year                     21  |           23                18
     ----------------------------------------------------------------------|---------------------------------
     Cash And Cash Equivalents - End Of Year                $          27  |  $        21      $         23
     ======================================================================|=================================
</TABLE>
     Supplemental disclosure of cash flow information (note 15)



                                                          CANADIAN NATURAL   77
<PAGE>
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-------------------------------------------------------------------------------

N O T E S   T O   T H E   C O N S O L I D A T E D
F I N A N C I A L  S T A T E M E N T S

     (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 in 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
     ("phases"). 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 18.

     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 in  impairment  calculations  are based on estimates of crude
     oil and natural gas  reserves.  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 upward or downward based on updated
     information such as the results of future drilling, testing and production
     levels,  and may be affected by changes in commodity  prices. As a result,
     the  impact  of  differences  between  actual  and  estimated  oil and gas
     reserves  amounts  on the  consolidated  financial  statements  of  future
     periods may 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 may
     be material.

     The  calculation of income taxes  requires  judgement 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 current
     and future income tax expense (recovery).

     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 may result in material changes to deferred amounts.

     The estimation of fair value for derivative financial instruments requires
     the use of assumptions. In determining these assumptions,  the Company has
     relied primarily on external,  readily  observable market inputs including
     quoted  commodity prices and volatility,  interest rate yield curves,  and
     foreign  exchange  rates.  The  resulting  fair  value  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.

(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.


78   CANADIAN NATURAL
<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") issued by the Canadian
     Institute  of  Chartered  Accountants  ("CICA").  Accordingly,  all  costs
     relating to the exploration for and development of conventional  crude oil
     and   natural  gas   reserves   are   capitalized   and   accumulated   in
     country-by-country  cost  centres.  Directly  attributable  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 is comprised of both 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 mining activity
     costs 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  available  for  its  intended  use.   Costs  related  to  major
     maintenance  turnaround  activities will be capitalized 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  benefit 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 of the Horizon  Project ceases once
     this phase is available for its intended use.

(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  whereby  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.  Costs for major development projects, as identified
     by  management,  are not  subject  to  depletion  until the  projects  are
     available  for  their  intended  uses.   Unproved   properties  and  major
     development  projects  are  assessed  periodically  to  determine  whether
     impairment has occurred. When proved reserves are assigned or the value of
     an unproved  property or major  development  project is  considered  to be
     impaired,  the cost of the  property  or the amount of the  impairment  is
     added to costs subject to depletion.  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.

Oil Sands Mining Operations And Upgrading Operations
     Upon  commencement  of operations  for the Horizon  Project,  mine-related
     costs and costs of the upgrader and related  infrastructure located on the
     Horizon  Project site will be amortized on the  unit-of-production  method
     based  on  the  estimated  proved  reserves  of  the  Horizon  Project  or
     productive  capacity,  respectively.  Moveable  mine-related  equipment is
     depreciated on a straight-line basis over its estimated useful life.


                                                          CANADIAN NATURAL   79
<PAGE>

     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 discounted  cash flow
     from the Horizon  Project using proved and probable  reserves and expected
     future prices and costs.

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 statements of earnings.

(K)  REVENUE RECOGNITION AND COSTS OF GOODS SOLD
     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.

     Related  costs of goods sold are comprised of  production;  transportation
     and blending; and depletion, depreciation and amortization expenses. These
     amounts have been separately  presented in the consolidated  statements of
     earnings.

(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 statements 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  respective  Government  State oil
     Companies  (the  "Governments").  Profit  oil is  allocated  to the  joint
     venture  partners in accordance with their  respective  equity  interests,
     after a portion has been allocated to the  Governments.  The  Governments'
     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.


80   CANADIAN NATURAL
<PAGE>

(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  or 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  arising from the  conventional  crude oil and natural gas
     business in Canada is primarily generated through  partnerships,  with the
     related  income taxes payable in subsequent  periods.  Accordingly,  north
     america current and future income taxes have been provided on the basis of
     this corporate structure.

(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,   after   consideration  of  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.

(Q)  FINANCIAL INSTRUMENTS
     The Company classifies its financial instruments into one of the following
     categories:  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 respective 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,   certain  other
     long-term  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 formally
     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 uses derivative financial  instruments to manage its commodity
     price,  foreign  currency and interest  rate  exposures.  These  financial
     instruments are entered into solely for hedging  purposes and are not used
     for speculative purposes.

     Effective  January 1,  2007,  all  derivative  financial  instruments  are
     recognized on the  consolidated  balance sheet at estimated  fair value at
     each balance sheet date. The estimated fair value of derivative  financial
     instruments  is  determined  based  on  appropriate   internal   valuation
     methodologies and/or third party indications. Fair values determined using
     valuation models require the use of assumptions  concerning the amount and
     timing of future cash flows and discount rates.

     The  Company  documents  all  derivative  financial  instruments  that are
     formally  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.


                                                          CANADIAN NATURAL   81
<PAGE>

     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
     formally  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.

     Realized 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.  Realized gains or
     losses on the  termination  of  financial  instruments  that have not been
     designated  as  hedges  are  recognized  in   consolidated   net  earnings
     immediately.

     Upon  termination  of an  interest  rate swap  designated  as a fair value
     hedge,  the interest rate swap is  de-recognized  on the balance sheet and
     the related  long-term  debt hedged is no longer  revalued  for changes in
     fair value. The fair value adjustment on the long-term debt at the date of
     termination  of the interest  rate swap is  amortized to interest  expense
     over the remaining term of the debt.

     Foreign currency forward contracts are periodically used to manage foreign
     currency  cash  management  requirements.  The  foreign  currency  forward
     contracts  involve  the  purchase  or sale of an agreed  upon amount of US
     dollars at a specified future date at forward  exchange rates.  Changes in
     the fair value of the foreign currency  forward  contracts are included in
     risk management activities in consolidated net earnings.

     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 the  calculation  of 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.


82   CANADIAN NATURAL
<PAGE>

(U)  RECENTLY ISSUED ACCOUNTING STANDARDS UNDER CANADIAN GAAP
     Effective  January 1, 2009,  the  Company  will  adopt the  following  new
     accounting standard issued by the CICA:

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.  The adoption of this standard will
          not have a material impact on the Company's financial statements.

(V)  INTERNATIONAL FINANCIAL REPORTING STANDARDS
     In February 2008, the CICA's  accounting  Standards  Board  confirmed that
     Canadian  publicly   accountable   entities  will  be  required  to  adopt
     International Financial Reporting Standards ("IFRS") as promulgated by the
     international  accounting  Standards  Board  in  place  of  Canadian  GAAP
     effective  January  1, 2011.  The  Company is  currently  assessing  which
     accounting  policies  will be  affected  by the  change  to  IFRS  and the
     potential impact of these changes on its financial position and results of
     operations.

(W)  COMPARATIVE FIGURES
     Certain  prior  year  figures  have been  reclassified  to  conform to the
     presentation adopted in 2008.



2.  CHANGES IN ACCOUNTING POLICIES
     Effective   January  1,  2008,  the  Company  adopted  the  following  new
     accounting and disclosure standards issued by the CICA:
     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 standard also requires
          the disclosure of any externally  imposed  capital  requirements  and
          compliance  with those  requirements.  The  standard  does not define
          capital.  This standard  affected  disclosure only and did not impact
          the Company's accounting for capital (note 11).
     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  did not have a  material  impact  on the
          Company's financial statements.
     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
          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 affected  disclosures only and did not impact the Company's
          accounting for financial instruments (note 13).

3.   OTHER LONG-TERM ASSETS

<TABLE>
<CAPTION>
                                                                                       2008  |            2007
     ----------------------------------------------------------------------------------------|-----------------
<S>                        <C>                                                 <C>                 <C>
     Risk management (note 13)                                                 $      2,119  |     $         -
     Other                                                                               24  |              49
     ----------------------------------------------------------------------------------------|-----------------
                                                                                      2,143  |              49
     Less: current portion                                                            1,851  |              18
     ----------------------------------------------------------------------------------------|-----------------
                                                                               $        292  |     $        31
     ========================================================================================|=================
</TABLE>

4.   PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
                                               2008                   |                  2007
     -----------------------------------------------------------------|----------------------------------------
                                   Cost                           Net |     Cost                           Net
                                             Accumulated              |               Accumulated
                                               depletion              |                 depletion
                                                     and              |                       and
                                            depreciation              |              depreciation
     -----------------------------------------------------------------|----------------------------------------
<S>                              <C>              <C>          <C>        <C>              <C>          <C>
     Conventional crude oil                           |
       and  natural gas
       North America           $ 36,532         $ 14,381     $ 22,151 | $ 34,195         $ 12,162     $ 22,033
       North Sea                  4,167            2,119        2,048 |    3,174            1,446        1,728
       Offshore West Africa       2,671              777        1,894 |    1,833              645        1,188
       Other                         40               14           26 |       39               14           25
     Horizon Project             12,573                -       12,573 |    8,651                -        8,651
     Midstream                      278               72          206 |      269               64          205
     Head office                    190              122           68 |      170               98           72
     -----------------------------------------------------------------|----------------------------------------
                               $ 56,451         $ 17,485     $ 38,966 | $ 48,331         $ 14,429     $ 33,902
     =================================================================|========================================
</TABLE>

     During the year ended December 31, 2008, the Company capitalized  directly
     attributable administrative costs of $55 million (2007 - $47 million, 2006
     - $41  million)  in the North Sea and  Offshore  West  Africa,  related to
     exploration and development  and$404 million (2007 - $312 million,  2006 -
     $255  million)  in  North   America,   related  to  the  Horizon   Project
     construction.

     During the year ended  December 31,  2008,  the Company  capitalized  $481
     million (2007 - $356 million,  2006 - $196 million) in construction period
     interest costs related to the Horizon Project.


                                                           CANADIAN NATURAL  83
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                                           2008 |          2007
     -----------------------------------------------------------------------------------------------------------|----------------
<S>                                                                                                  <C>             <C>
     Conventional crude oil and natural gas                                                                     |
        North America                                                                                $    2,271 |    $    2,259
        North Sea                                                                                            12 |            10
        Offshore West Africa                                                                                595 |           138
        Other                                                                                                26 |            25
     Horizon Project                                                                                     12,573 |         8,651
     -----------------------------------------------------------------------------------------------------------|----------------
                                                                                                     $   15,477 |    $   11,083
     ===========================================================================================================|================
</TABLE>

     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, 2008:

<TABLE>
<CAPTION>
                                                                                                                         Average
                                                                                                                          annual
                                                                                                                        increase
                                                       2009         2010         2011         2012         2013       thereafter
     ---------------------------------------------------------------------------------------------------------------------------
<S>                                                <C>         <C>          <C>          <C>          <C>             <C>
     Crude oil and NGLs
     North America
        WTI at cushing (US$/bbl)                   $  53.73    $   63.41    $   69.53    $   79.59    $   92.01             2.0%
        Hardisty Heavy 12(degree) API (C$/bbl)     $  47.05    $   54.58    $   59.96    $   67.53    $   74.08             2.0%
        Edmonton Par (C$/bbl)                      $  65.35    $   72.78    $   79.95    $   86.57    $   94.97             2.0%
     North Sea and Offshore West Africa
        North Sea Brent (US$/bbl)                  $  51.73    $   61.37    $   67.45    $   77.47    $   89.84             2.0%
     ---------------------------------------------------------------------------------------------------------------------------
     Natural gas
     North America
        Henry Hub Louisiana (US$/mmbtu)            $   6.30    $    7.32    $    7.56    $    8.49    $    9.74             2.0%
        AECO (C$/mmbtu)                            $   6.82    $    7.56    $    7.84    $    8.38    $    9.20             2.2%
        Huntingdon/Sumas (C$/mmbtu)                $   6.82    $    7.56    $    7.84    $    8.38    $    9.20             2.2%
     ===========================================================================================================================
</TABLE>


84   CANADIAN NATURAL
<PAGE>

5.   Long-term debt

<TABLE>
<CAPTION>
                                                                                                     2008           2007
     --------------------------------------------------------------------------------------------------------------------
<S>                                                                                                <C>          <C>
     Canadian dollar denominated debt
     Bank credit facilities
        Bankers' acceptances                                                                       $   4,073    $  4,696
     Medium-term notes
        5.50% unsecured debentures due December 17, 2010                                                 400         400
        4.50% unsecured debentures due January 23, 2013                                                  400         400
        4.95% unsecured debentures due June 1, 2015                                                      400         400
     --------------------------------------------------------------------------------------------------------------------
                                                                                                       5,273       5,896
     --------------------------------------------------------------------------------------------------------------------
     US dollar denominated debt
     Senior unsecured notes
        Adjustable rate due May 27, 2009 (2008 - US$31 million, 2007 - US$62 million)                     38          61
     US dollar debt securities
        7.80% due July 2, 2008 (2008 - US$nil, 2007 - US$8 million)                                        -           8
        6.70% due July 15, 2011 (2008 - US$400 million, 2007 - US$400 million)                           490         395
        5.45% due October 1, 2012 (2008 - US$350 million, 2007 - US$350 million)                         429         346
        5.15% due February 1, 2013 (2008 - US$400 million, 2007 - US$nil)                                490           -
        4.90% due December 1, 2014 (2008 - US$350 million, 2007 - US$350 million)                        429         346
        6.00% due August 15, 2016 (2008 - US$250 million, 2007 - US$250 million)                         306         247
        5.70% due May 15, 2017 (2008 - US$1,100 million, 2007 - US$1,100 million)                      1,346       1,087
        5.90% due February 1, 2018 (2008 - US$400 million, 2007 - US$nil)                                490           -
        7.20% due January 15, 2032 (2008 - US$400 million, 2007 - US$400 million)                        490         395
        6.45% due June 30, 2033 (2008 - US$350 million, 2007 - US$350 million)                           429         346
        5.85% due February 1, 2035 (2008 - US$350 million, 2007 - US$350 million)                        429         346
        6.50% due February 15, 2037 (2008 - US$450 million, 2007 - US$450 million)                       551         445
        6.25% due March 15, 2038 (2008 - US$1,100 million, 2006 - US$1,100 million)                    1,346       1,087
        6.75% due February 1, 2039 (2008 - US$400 million, 2007 - US$nil)                                490           -
     Less - original issue discount on senior unsecured notes and US dollar                              (23)        (23)
     debt securities (1)
     --------------------------------------------------------------------------------------------------------------------
                                                                                                       7,730       5,086
     Fair value impact of interest rate swaps on US dollar debt securities (2)                            68           9
     --------------------------------------------------------------------------------------------------------------------
                                                                                                       7,798       5,095
     --------------------------------------------------------------------------------------------------------------------
     Long-term debt before transaction costs                                                          13,071       10,991
     Less: transaction costs (1) (3)                                                                     (55)        (51)
     --------------------------------------------------------------------------------------------------------------------
                                                                                                      13,016       10,940
     Less: current portion                                                                               420           -
     --------------------------------------------------------------------------------------------------------------------
                                                                                                   $  12,596    $  10,940
     ====================================================================================================================
</TABLE>
     (1)  The Company has included  unamortized  original  issue  discounts and
          directly attributable  transaction costs in the carrying value of the
          outstanding debt.
     (2)  The carrying  value 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 $68 million (2007 - $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, 2008,  the Company had in place  unsecured  bank credit
     facilities of $6,232 million, comprised of:

     o    a $125 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  will be  repayable  on the maturity
     date.  Borrowings  under these  facilities  can be made by way of Canadian
     dollar and US dollar  bankers'  acceptances,  and LIBOR,  US Base Rate And
     Canadian Prime Loans.

     In  Conjunction  with the closing of the  acquisition  of  Anadarko  Canada
     Corporation  ("ACC") in November  2006 (note 16),  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.  During 2009, the Company plans to fully retire
     this  facility  from  its  existing  borrowing  capacity  under  its  other
     long-term bank credit facilities, which were $2,050 million at December 31,
     2008,


                                                           CANADIAN NATURAL  85
<PAGE>

     supported by cash flow from operating  activities,  including the commodity
     risk management activities.  In accordance with these plans, and repayments
     of $420 million made subsequent to December 31, 2008 on this facility, $420
     million has been classified as current.

     The  weighted  average  interest  rate  of  the  bank  credit   facilities
     outstanding at December 31, 2008, was 2.2% (2007 - 5.2%).

     In  addition  to the  outstanding  debt,  letters of credit and  financial
     guarantees aggregating $372 million, including $300 million related to the
     Horizon Project, were outstanding at December 31, 2008.

Medium-term Notes
     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.

     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.

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

Senior Unsecured Notes
     The adjustable rate senior  unsecured  notes bear interest at 6.54%,  with
     the final annual  principal  repayment  of US$31  million due in May 2009.
     During 2008, US$31 million of the senior unsecured notes were repaid.

US Dollar Debt Securities
     In January 2008, the Company issued  US$1,200  million of unsecured  notes
     under a 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 filed in September
     2007 that allows for the issue of US dollar debt  securities in the United
     States until October 2009. If issued,  these securities will bear interest
     as determined at the date of issuance.

     During 2008, US$8 million of US dollar debt securities were repaid.

     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 13). 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 13).  Proceeds from the  securities
     issued were used to repay  bankers'  acceptances  under the Company's bank
     credit facilities.

     During 2008, the Company  terminated the interest rate swaps that had been
     designated  as a fair value  hedge of US$350  million  of 5.45%  unsecured
     notes due October  2012.  Accordingly,  the Company  ceased  revaluing the
     related debt from the date of  termination  of the interest rate swaps for
     subsequent changes in fair value. The fair value adjustment of $20 million
     at the date of termination is being amortized to interest expense over the
     remaining term of the debt.

     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  statements  of
     earnings.

Required Debt Repayments
     Required debt repayments are as follows:

     Year                                                             Repayment
     ---------------------------------------------------------------------------
     2009                                                         $       2,385
     2010                                                         $         400
     2011                                                         $         490
     2012                                                         $         429
     2013                                                         $         890
     Thereafter                                                   $       6,707
     ===========================================================================

     No debt  repayments are reflected in the above table for $1,725 million of
     revolving  bank  credit  facilities  due to the  extendable  nature of the
     facilities.  Should the bank credit  facilities  not be extended by mutual
     agreement  of the Company and the  lenders,  the entire  amounts due under
     these facilities would be due in 2012.


86   CANADIAN NATURAL
<PAGE>

6.   OTHER LONG-TERM LIABILITIES

<TABLE>
<CAPTION>
                                                                  2008 |          2007
     ------------------------------------------------------------------|---------------
<S>                                                         <C>             <C>
     Asset retirement obligations                           $    1,064 |    $    1,074
     Stock-based compensation                                      171 |           529
     Risk management (note 13)                                       - |         1,474
     Other                                                         119 |           101
     ------------------------------------------------------------------|---------------
                                                                 1,354 |         3,178
     Less: current portion                                         230 |         1,617
     ------------------------------------------------------------------|---------------
                                                            $    1,124 |    $    1,561
     ==================================================================|===============
</TABLE>

Asset Retirement Obligations
     At December 31, 2008, the Company's total estimated  undiscounted costs to
     settle its asset retirement  obligations were approximately $4,474 million
     (2007 -  $4,426  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  6.7%  (2007  -  6.6%;   2006  -  6.7%).  A
     reconciliation  of  the  discounted  asset  retirement  obligations  is as
     follows:

<TABLE>
<CAPTION>
                                                                  2008 |          2007           2006
     ------------------------------------------------------------------|-------------------------------
<S>                                                         <C>             <C>             <C>
     Balance - beginning of year                            $    1,074 |    $    1,166      $   1,112
        Liabilities incurred                                        18 |            21             26
        Liabilities acquired (note16)                                3 |             -             56
        Liabilities disposed                                         - |           (65)             -
        Liabilities settled                                        (38)|           (71)           (75)
        Asset retirement obligation accretion                       71 |            70             68
        Revision of estimates                                     (156)|            35            (21)
        Foreign exchange                                            92 |           (82)             -
     ------------------------------------------------------------------|-------------------------------
     Balance - end of year                                  $    1,064 |    $    1,074      $   1,166
     ==================================================================|===============================
</TABLE>

Stock-based compensation
     The Company  recognizes a liability for 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>
                                                                  2008 |          2007           2006
     ------------------------------------------------------------------|-------------------------------
<S>                                                         <C>             <C>             <C>
     Balance - beginning of year                            $      529 |    $     744       $      891
        Stock-based compensation                                   (52)|          193              139
        Cash payment for options surrendered                      (207)|         (375)            (264)
        Transferred to common shares                               (76)|          (91)            (101)
        Capitalized to Horizon Project                             (23)|           58               79
     ------------------------------------------------------------------|-------------------------------
     Balance - end of year                                         171 |          529              744
     Less: current portion                                         159 |          390              611
     ------------------------------------------------------------------|-------------------------------
                                                            $       12 |    $     139       $      133
     ==================================================================|===============================
</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 7.0% (2007 - 5.5%) used to  determine
     accrued benefit obligations is based on a year-end market rate of interest
     for  high-quality  debt  instruments with cash flows that match the timing
     and amount of expected  benefit  payments.  Company  contributions  to the
     defined contribution plan are expensed as incurred.

     The benefit  obligation under the registered  pension plan at December 31,
     2008 was $27 million  (2007 - $32  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, 2008,  these plan
     assets  had a  fair  value  of  $34  million  (2007  - $47  million).  The
     unregistered pension plan and other post-retirement  benefits are unfunded
     and have a benefit  obligation  of $9 million at December 31, 2008 (2007 -
     $10 million).


                                                           CANADIAN NATURAL  87

<PAGE>

8.   TAXES

Taxes Other Than Income Tax

<TABLE>
<CAPTION>
                                                                2008 |            2007            2006
     ----------------------------------------------------------------|----------------------------------
<S>                                                       <C>               <C>              <C>
        Current PRT expense                               $      210 |     $        97       $     196
        Deferred PRT (recovery) expense                          (67)|              44              37
        Provincial capital taxes and surcharges                   35 |              24              23
     ----------------------------------------------------------------|----------------------------------
                                                          $      178 |     $       165       $     256
     ================================================================|==================================
</TABLE>

Income Tax

     The provision for income tax is as follows:

<TABLE>
<CAPTION>
                                                                2008 |            2007            2006
     ----------------------------------------------------------------|----------------------------------
<S>                                                       <C>               <C>              <C>
        Current income tax - North America                $       33 |      $       96       $     143
        Current income tax - North Sea                           340 |             210              30
        Current income tax - Offshore West Africa                128 |              74              49
     ----------------------------------------------------------------|----------------------------------
     Current income tax expense                                  501 |             380             222
     Future income tax expense (recovery)                      1,607 |            (456)            652
     ----------------------------------------------------------------|----------------------------------
     Income tax expense (recovery)                        $    2,108 |      $      (76)      $     874
     ================================================================|==================================
</TABLE>


     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>
                                                                2008 |            2007           2006
     ----------------------------------------------------------------|-----------------------------------
<S>                                                       <C>               <C>              <C>
     Canadian statutory income tax rate                         29.8%|            32.5%          34.9%
     ----------------------------------------------------------------|-----------------------------------
     Income tax provision at statutory rate               $    2,166 |      $      877       $  1,275
     Effect on income taxes of:                                      |
        Non-deductible portion of Canadian crown                     |
          payments                                                 - |               -            131
        Canadian resource allowance                                - |               -           (129)
        Deductible UK petroleum revenue tax                      (72)|             (71)           (82)
        Foreign and domestic tax rate differentials               (5)|             (25)             6
        North America income tax rate and other                      |
          legislative changes                                    (19)|            (864)          (438)
        UK income tax rate changes                                 - |               -            110
        Cote d'Ivoire income tax rate changes                    (22)|               -            (67)
        Non-taxable portion of foreign exchange loss                 |
        (gain)                                                   127 |             (96)             5
        Stock options exercised in shares                          6 |              63             35
        Other                                                    (73)|              40             28
     ----------------------------------------------------------------|-----------------------------------
     Income tax expense (recovery)                        $    2,108 |      $      (76)      $    874
     =================================================================|==================================
</TABLE>

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


<TABLE>
<CAPTION>
                                                                                  2008 |           2007
     ----------------------------------------------------------------------------------|-----------------
<S>                                                                         <C>              <C>
     Future income tax liabilities
        Property, plant and equipment                                       $    6,303 |     $    5,695
        Timing of partnership items                                              1,276 |          1,288
        Unrealized foreign exchange gain on long-term debt                          13 |            199
        Unrealized risk management activities                                      651 |              -
        Other                                                                        - |             55
     Future income tax assets                                                          |
        Asset retirement obligations                                              (372)|           (380)
        Loss carryforwards for income tax                                          (62)|           (104)
        Stock-based compensation                                                   (38)|           (125)
        Unrealized risk management activities                                        - |           (399)
        Other                                                                       (7)|              -
     Deferred petroleum revenue tax                                                (43)|             20
     ----------------------------------------------------------------------------------|-----------------
     Net future income tax liability                                             7,721 |          6,249
     Less: current portion of future income tax liability (asset)                  585 |           (480)
     ----------------------------------------------------------------------------------|-----------------
     Future income tax liability                                            $    7,136 |     $    6,729
     ==================================================================================|=================
</TABLE>

     During  2008,  substantively  enacted or enacted  income tax rate  changes
     resulted in a reduction of future income tax liabilities of  approximately
     $19  million in British  Columbia  and  approximately  $22 million in Cote
     d'Ivoire.

     During 2007,  substantively  enacted or enacted  income tax rate and other
     legislative   changes  resulted  in  a  reduction  of  future  income  tax
     liabilities of approximately $864 million in North America.


88   CANADIAN NATURAL
<PAGE>

     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 2003, the Canadian Federal Government enacted  legislation to phase
     in changes to the  taxation of resource  income by 2007.  The  legislation
     reduced  the  corporate  income tax rate on  resource  income to 21%,  the
     deduction for resource allowance was phased out and a deduction for actual
     crown royalties paid was phased in.  Subsequently,  as a result of enacted
     income tax rate changes in 2007, the Canadian Federal corporate income tax
     rate is being reduced from 21% in 2007 to 15% in 2012.

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

                                                      2008                     |          2007
     --------------------------------------------------------------------------|----------------------------------
     Common shares                               Number of              Amount |      Number of            Amount
                                                    shares                     |         shares
                                                (thousands)                    |    (thousands)
     --------------------------------------------------------------------------|----------------------------------
<S>                                                <C>             <C>                  <C>            <C>
     Balance - beginning of year                   539,729         $     2,674 |        537,903        $    2,562
     Issued upon exercise of stock options           1,262                  18 |          1,826                21
     Previously recognized liability on                                        |
        stock options exercised for common shares        -                  76 |              -                91
     --------------------------------------------------------------------------|----------------------------------
     Balance - end of year                         540,991         $     2,768 |        539,729        $    2,674
     ==========================================================================|==================================
</TABLE>

Normal Course Issuer Bid
     The Company did not renew the Normal Course Issuer Bid during 2008. During
     2007 and  2008,  the  Company  did not  purchase  any  common  shares  for
     cancellation  (2006 - 485,000  common shares were  purchased at an average
     price of $57.33 per common share for a total cost of $28 million).

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

     In March 2009, the Board of Directors set the Company's  regular quarterly
     dividend at $0.105 per common share (2008 - $0.10 per common share, 2007 -
     $0.085 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 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.

     The  following  table  summarizes  information  relating to stock  options
     outstanding at December 31, 2008 and 2007:

<TABLE>
<CAPTION>
                                                      2008                     |         2007
     --------------------------------------------------------------------------|----------------------------------
                                                                      Weighted |                         Weighted
                                                     Stock             average |          Stock           average
                                                   options            exercise |        options          exercise
                                                (thousands)              price |     (thousands)            price
     --------------------------------------------------------------------------|----------------------------------
<S>                                               <C>             <C>                  <C>            <C>
     Outstanding - beginning of year                30,659        $      47.23 |         34,431       $     33.77
     Granted                                         7,705        $      53.38 |          7,502       $     70.03
     Surrendered for cash settlement                (3,702)       $      25.60 |         (7,249)      $     16.10
     Exercised for common shares                    (1,262)       $      14.61 |         (1,826)      $     11.71
     Forfeited                                      (2,438)       $      56.56 |         (2,199)      $     46.46
     --------------------------------------------------------------------------|----------------------------------
     Outstanding - end of year                      30,962        $      51.94 |         30,659       $     47.23
     --------------------------------------------------------------------------|----------------------------------
     Exercisable - end of year                       8,809        $      44.58 |          7,640       $     30.00
     ==========================================================================|==================================
</TABLE>


                                                          CANADIAN NATURAL   89
<PAGE>

     The range of exercise prices of stock options  outstanding and exercisable
     at December 31, 2008 was as follows:

<TABLE>
<CAPTION>
                                          Stock options outstanding                    Stock options exercisable
     --------------------------------------------------------------------------------------------------------------
                                                    Weighted
                                         Stock       average         Weighted                Stock         Weighted
                                       options     remaining          average              options          average
                                   outstanding          term         exercise          exercisable         exercise
     Range of exercise prices       (thousands)       (years)           price           (thousands)           price
     ---------------------------------------------------------------------------------------------------------------
<S>                                   <C>            <C>          <C>                     <C>            <C>
     $11.83 - $19.99                     2,909          0.51      $     16.44                1,918       $    16.13
     $20.00 - $29.99                     3,023          1.30      $     25.57                1,454       $    25.42
     $30.00 - $39.99                       865          1.66      $     33.27                  397       $    33.30
     $40.00 - $49.99                     6,845          5.01      $     46.37                  203       $    46.29
     $50.00 - $59.99                     5,001          2.75      $     58.06                1,860       $    57.93
     $60.00 - $69.99                     4,884          3.15      $     61.54                1,762       $    61.60
     $70.00 - $79.99                     6,526          4.20      $     70.76                1,215       $    70.67
     $80.00 - $89.99                         -             -      $         -                    -       $        -
     $90.00 - $92.50                       909          5.53      $     92.50                    -       $        -
     ---------------------------------------------------------------------------------------------------------------
                                        30,962          3.32      $     51.94                8,809       $    44.58
     ===============================================================================================================
</TABLE>


10.  ACCUMULATED OTHER COMPREHENSIVE INCOME

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

<TABLE>
<CAPTION>
                                                                                              2008 |           2007
     ----------------------------------------------------------------------------------------------|-----------------
<S>                                                                                       <C>            <C>
     Derivative financial instruments designated as cash flow hedges                      $    119 |     $      101
     Foreign currency translation adjustment                                                   143 |            (29)
     ----------------------------------------------------------------------------------------------|-----------------
                                                                                          $    262 |     $       72
     ==============================================================================================|=================
</TABLE>

     During the next twelve months,  $19 million is expected to be reclassified
     to net earnings from accumulated other comprehensive income.

     During 2008, the Company  determined  that its operations in Offshore West
     Africa were now operationally and financially  independent and the current
     rate method of  translation  was adopted for  translation of the financial
     statements of the Offshore West African subsidiaries. This change has been
     applied prospectively. The impact of this change was to increase assets by
     $32 million,  decrease  liabilities by $4 million and increase accumulated
     other comprehensive income by $36 million.

11.  CAPITAL DISCLOSURES

     As required by Canadian GAAP,  effective January 1, 2008, the Company must
     provide  certain  disclosures  regarding  its  objectives,   policies  and
     processes for managing  capital,  as well as provide certain  quantitative
     data about capital.  As the Company does not have any  externally  imposed
     regulatory capital requirements,  for the purposes of this disclosure, the
     Company  has  defined  its  capital  to  mean  its   long-term   debt  and
     consolidated shareholders' equity, as determined each reporting date.

     The  Company's  objectives  when  managing  its capital  structure  are to
     maintain financial flexibility and balance to enable the Company to access
     capital  markets to sustain  its  on-going  operations  and to support its
     growth strategies.  The Company primarily monitors capital on the basis of
     an internally  derived non-GAAP financial measure referred to as its "debt
     to book  capitalization  ratio",  which is the arithmetic ratio of current
     and  long-term   debt  divided  by  the  sum  of  the  carrying  value  of
     shareholders'  equity plus current and  long-term  debt.  The Company aims
     over time to maintain its debt to book  capitalization  ratio in the range
     of 35% to 45%. However, the Company may exceed the high end of such target
     range if it is investing in capital projects, undertaking acquisitions, or
     in periods of lower commodity prices. The Company may be below the low end
     of the target range when cash flow from  operating  activities  is greater
     than  current  investment  activities.  The  ratio is  currently  near the
     midpoint  of the  target  range at 41%  including  the  impact of  capital
     spending on the Horizon Project.

     Readers are cautioned that as the debt to book capitalization ratio has no
     defined meaning under GAAP,  this financial  measure may not be comparable
     to similar measures provided by other reporting entities.  Further,  there
     can be no assurances that the Company will continue to use this measure to
     monitor  capital  or will not alter  the  method  of  calculation  of this
     measure at some point in the future.

<TABLE>
<CAPTION>
                                                                                              2008 |          2007
     ----------------------------------------------------------------------------------------------|-----------------
<S>                                                                                    <C>               <C>
     Long-term debt (1)                                                                $    13,016 |     $  10,940
     Total shareholders' equity                                                        $    18,374 |     $  13,321
     Debt to book capitalization                                                               41% |           45%
     ==============================================================================================|=================
</TABLE>
     (1)  Includes the current portion of long-term debt.


90   CANADIAN NATURAL
<PAGE>

12.   NET EARNINGS PER COMMON SHARE

<TABLE>
<CAPTION>
     (thousands of shares)                                                                 2008  |          2007             2006
     --------------------------------------------------------------------------------------------|--------------------------------
<S>                                                                                <C>                <C>             <C>
     Weighted average common shares outstanding - basic and diluted                     540,647  |       539,336          537,339
     Net earnings - basic and diluted                                              $      4,985  |    $    2,608      $     2,524
     Net earnings per common share - basic and diluted                             $       9.22  |    $     4.84      $      4.70
     ============================================================================================|================================
</TABLE>

13.  FINANCIAL INSTRUMENTS

     The carrying values of the Company's financial instruments by category are
     as follows:

<TABLE>
<CAPTION>
                                                                                                            2008
     -----------------------------------------------------------------------------------------------------------------------------
                                                                                      Loans and                             Other
                                                                                    receivables                         financial
                                                                                             at         Held for    liabilities at
                                                                                      amortized       trading at        amortized
     Asset (liability)                                                                     cost       fair value             cost
     -----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>                <C>             <C>
     Cash and cash equivalents                                                     $          -       $       27      $         -
     Accounts receivable                                                                  1,059                -                -
     Risk management                                                                          -            2,119                -
     Accounts payable                                                                         -                -            (383)
     Accrued liabilities                                                                      -                -          (1,802)
     Other long-term liabilities                                                              -                -            (105)
     Long-term debt (1)                                                                       -                -         (13,016)
     -----------------------------------------------------------------------------------------------------------------------------
                                                                                   $      1,059       $    2,146      $  (15,306)
     =============================================================================================================================
</TABLE>
     (1)  Includes the current portion of long-term debt.

<TABLE>
<CAPTION>
                                                                                                            2007
     -----------------------------------------------------------------------------------------------------------------------------
                                                                                      Loans and                             Other
                                                                                    receivables                         financial
                                                                                             at         Held for    liabilities at
                                                                                      amortized       trading at        amortized
     Asset (liability)                                                                     cost       fair value             cost
     -----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>                <C>             <C>
    Cash and cash equivalents                                                      $          -       $       21      $         -
    Accounts receivable                                                                   1,143                -                -
    Accounts payable                                                                          -                -             (379)
    Accrued liabilities                                                                       -                -           (1,567)
    Risk management                                                                           -           (1,474)               -
    Other long-term liabilities                                                               -                -              (86)
    Long-term debt                                                                            -                -          (10,940)
     -----------------------------------------------------------------------------------------------------------------------------
                                                                                   $      1,143       $   (1,453)     $   (12,972)
     =============================================================================================================================
</TABLE>

     The carrying  value of the Company's  financial  instruments  approximates
     their fair value, except for fixed rate long-term debt as noted below:

<TABLE>
<CAPTION>
                                                                                2008            |                2007
     -------------------------------------------------------------------------------------------|---------------------------------
                                                                  Carrying value     Fair value | Carrying value      Fair value
     -------------------------------------------------------------------------------------------|---------------------------------
<S>                            <C>                                <C>                <C>          <C>                 <C>
     Fixed rate long-term debt (1)                                $        8,943     $    7,649 | $        6,244      $    6,259
     ===========================================================================================|=================================
</TABLE>

     (1)  The carrying value 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 $68 million (2007 - $9 million) to reflect the fair value
          impact of hedge accounting.


                                                          CANADIAN NATURAL   91
<PAGE>

Risk Management

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

<TABLE>
<CAPTION>
                                                                                 2008 |                2007
     ---------------------------------------------------------------------------------|---------------------
     Asset (liability)                                                           Risk |                Risk
                                                                           management |          management
                                                                       mark-to-market |      mark-to-market
     ---------------------------------------------------------------------------------|---------------------
<S>                                                                      <C>                   <C>
     Balance - beginning of year                                         $     (1,474)|        $        128
     Retained earnings effect of adoption of financial                                |
     instruments standards                                                          - |                  14
     Net cost of outstanding put options                                          297 |                  58
     Net change in fair value of outstanding derivative                               |
     financial instruments attributable to:                                           |
        Risk management activities                                              3,090 |              (1,400)
        Interest expense                                                           60 |                   9
        Foreign exchange                                                          449 |                (350)
        Other comprehensive income                                                 18 |                 125
        Settlement of interest rate swaps                                         (20)|                   -
     ---------------------------------------------------------------------------------|---------------------
                                                                                2,420 |              (1,416)
     Add:  put premium financing obligations (1)                                 (301)|                 (58)
     ---------------------------------------------------------------------------------|---------------------
     Balance - end of year                                                      2,119 |              (1,474)
     Less:  current portion                                                     1,851 |              (1,227)
     ---------------------------------------------------------------------------------|---------------------
                                                                         $        268 |        $       (247)
     =================================================================================|=====================
</TABLE>
     (1)  The  Company  has  negotiated  payment  of put option  premiums  with
          various  counterparties  at the  time  of  actual  settlement  of the
          respective options.  These obligations have been reflected in the net
          risk management asset (liability).

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

<TABLE>
<CAPTION>
                                                                   2008 |            2007               2006
------------------------------------------------------------------------|------------------------------------
<S>                                                         <C>               <C>              <C>
Net realized risk management loss                           $     1,860 |     $       162      $       1,325
Net unrealized risk management (gain) loss                       (3,090)|           1,400             (1,013)
------------------------------------------------------------------------|------------------------------------
                                                            $    (1,230)|     $     1,562      $         312
========================================================================|====================================
</TABLE>

Financial risk Factors
a)   Market risk
     Market  risk is the risk  that the fair  value or future  cash  flows of a
     financial  instrument will fluctuate  because of changes in market prices.
     The Company's  market risk is comprised of commodity price risk,  interest
     rate risk, and foreign currency exchange risk.

Commodity price risk management
     The Company uses commodity derivative financial  instruments to manage its
     exposure to commodity  price risk  associated  with the sale of its future
     crude oil and natural gas  production.  At December 31, 2008,  the Company
     had the following net  derivative  financial  instruments  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          Jan 2009 - Dec 2009       25,000 bbl/d      US$70.00 - US$111.56      WTI
                                      Apr 2009 - Jun 2009        4,000 bbl/d       US$70.00 - US$90.00      WTI
     -----------------------------------------------------------------------------------------------------------
     Crude oil puts                   Jan 2009 - Dec 2009       92,000 bbl/d                 US$100.00      WTI
     ===========================================================================================================
</TABLE>

     The net cost of outstanding  put options of US$242 million will be settled
     in 2009.

<TABLE>
<CAPTION>
                                           Remaining term             Volume    Weighted average price    Index
     -----------------------------------------------------------------------------------------------------------
<S>                                   <C>                       <C>              <C>                      <C>
     Natural gas
     Natural gas price collars (1)      Jan 2009 - Mar 2009     500,000 GJ/d           C$6.00 - C$8.63      AECO
     ===========================================================================================================
</TABLE>
     (1)  Subsequent  to December  31, 2008,  the Company  entered into 220,000
          GJ/d of  C$6.00 - C$8.00  natural  gas AECO  collars  for the  period
          January to December 2010.

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

     There were no commodity  derivative  financial  instruments  designated as
     hedges at December 31, 2008.

     In  addition  to  the  derivative   financial   instruments  noted  above,
     subsequent  to December  31,  2008,  the Company  entered into natural gas
     physical  sales  contracts  for 400,000 GJ/d at an average  fixed price of
     C$5.29 per GJ at AECO for the period April to December 2009.


92   CANADIAN NATURAL
<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 contracts 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, 2008,  the Company had the  following
     interest rate swap contracts outstanding:

<TABLE>
<CAPTION>
                                                                      Amount        Fixed
                                           Remaining term        ($ millions)        rate        Floating Rate
     -----------------------------------------------------------------------------------------------------------
<S>                                   <C>                       <C>              <C>         <C>
     Interest rate
     Swaps - fixed to floating        Jan 2009 - 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, 2008 were classified as fair value hedges.

Foreign currency exchange rate risk management

     The Company is exposed to foreign  currency  exchange  rate risk in Canada
     primarily related to its US dollar denominated  long-term debt and working
     capital.  The Company is also exposed to foreign  currency  exchange  rate
     risk on transactions conducted in other currencies in its subsidiaries and
     in the carrying value of its  self-sustaining  foreign  subsidiaries.  The
     Company periodically enters into cross currency swap contracts and foreign
     currency forward  contracts to manage known currency exposure on US dollar
     denominated  long-term debt and working  capital.  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. At
     December 31,  2008,  the Company had the  following  cross  currency  swap
     contracts outstanding:

<TABLE>
<CAPTION>
                                                                         Exchange     Interest     Interest
                                                            Amount           rate         rate         rate
                                      Remaining Term    ($millions)       (US$/C$)        (US$)         (C$)
-------------------------------------------------------------------------------------------------------------
<S>                              <C>                     <C>             <C>           <C>         <C>
Cross currency
Swaps                            Jan 2009 - Aug 2016       US$250           1.116        6.00%         5.40%
                                 Jan 2009 - May 2017     US$1,100           1.170        5.70%         5.10%
                                 Jan 2009 - Mar 2038       US$550           1.170        6.25%         5.76%
=============================================================================================================
</TABLE>

     All cross currency swap  derivative  financial  instruments  designated as
     hedges at December 31, 2008 were classified as cash flow hedges.

     In addition to the cross currency swap contracts noted above,  the Company
     periodically utilizes foreign currency forward contracts to manage certain
     foreign currency cash management  requirements.  At December 31, 2008, the
     Company had US$408 million of these contracts  outstanding,  with terms of
     approximately 30 days or less.

Financial instrument sensitivities
     As required by Canadian GAAP,  effective January 1, 2008, the Company must
     provide  certain  quantitative  sensitivities  related  to  its  financial
     instruments,   which  are  prepared  on  a  different   basis  than  those
     sensitivities  currently  disclosed  in  the  Company's  other  continuous
     disclosure  documents.  The  following  table  summarizes  the  annualized
     sensitivities of the Company's net earnings and other comprehensive income
     to changes in the fair value of financial  instruments  outstanding  as at
     December 31, 2008, resulting from changes in the specified variable,  with
     all other variables held constant.  These sensitivities are limited to the
     impact of changes in a specified variable applied to financial instruments
     only and do not  represent  the impact of a change in the  variable on the
     operating  results  of  the  Company  taken  as a  whole.  Further,  these
     sensitivities  are theoretical,  as changes in one variable may contribute
     to changes in  another  variable,  which may  magnify  or  counteract  the
     sensitivities.  In addition,  changes in fair value  generally  can not be
     extrapolated  because the relationship of a change in an assumption to the
     change in fair value may not be linear.

<TABLE>
<CAPTION>
                                                                                            Impact on other
                                                                          Impact on           comprehensive
                                                                       net earnings                  income
     -------------------------------------------------------------------------------------------------------
<S>                                                                   <C>                 <C>
     Commodity price risk
        Increase WTI US$1.00/bbl                                      $         (32)      $               -
        Decrease WTI US$1.00/bbl                                      $          32       $               -
        Increase AECO C$0.10/mcf                                      $          (1)      $               -
        Decrease AECO C$0.10/mcf                                      $           1       $               -
     Interest rate risk
     Increase interest rate 1%                                        $         (32)      $             (27)
        Decrease interest rate 1%                                     $          32       $              33
     Foreign currency exchange rate risk
        Increase exchange rate by US$0.01                             $         (35)      $               -
        Decrease exchange rate by US$0.01                             $          35       $               -
     =======================================================================================================
</TABLE>


                                                          CANADIAN NATURAL   93

<PAGE>

b)   Credit risk

     Credit risk is the risk that a party to a financial  instrument will cause
     a financial loss to the Company by failing to discharge an obligation.

Counterparty credit risk management
     The Company's  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. At December 31, 2008, substantially all of
     the Company's accounts receivables were due within normal trade terms.

     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  counterparties that are substantially all investment grade financial
     institutions and other entities. At December 31, 2008, the Company had net
     risk management assets of $2,119 million (December 31, 2007 - $20 million)
     with specific  counterparties related to derivative financial instruments.
     The Company believes that its counterparties  currently have the financial
     capacity  to  settle  outstanding  obligations  in the  normal  course  of
     business.

c)   Liquidity Risk
     Liquidity risk is the risk that the Company will  encounter  difficulty in
     meeting obligations associated with financial liabilities.

     Management of liquidity  risk requires the Company to maintain  sufficient
     cash and cash equivalents, along with other sources of capital, consisting
     primarily  of  cash  flow  from  operating  activities,  available  credit
     facilities,  and access to debt capital  markets,  to meet  obligations as
     they become due. Due to  fluctuations  in the timing of the receipt and/or
     disbursement of operating cash flows, the Company believes it has adequate
     bank credit facilities to provide liquidity.

     The maturity dates for financial liabilities are as follows:

<TABLE>
<CAPTION>
                                           Less than 1           1 to less           2 to less
                                                  year        than 2 years        than 5 years         Thereafter
------------------------------------------------------------------------------------------------------------------
<S>                                      <C>                 <C>                <C>                 <C>
     Accounts payable                    $         383       $           -      $            -      $           -
     Accrued liabilities                 $       1,802       $           -      $            -      $           -
     Other long-term liabilities         $          86       $          18      $            1      $           -
     Long-term debt (1)                  $       2,385       $         400      $        1,809      $       6,707
==================================================================================================================
</TABLE>

     (1)  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  $1,725
          million of revolving  bank credit  facilities  due to the  extendable
          nature of the facilities.

14.  COMMITMENTS AND CONTINGENCIES

     The Company has committed to certain payments as follows:

<TABLE>
<CAPTION>
                                 2009           2010           2011          2012           2013       thereafter
-----------------------------------------------------------------------------------------------------------------
<S>                          <C>           <C>            <C>            <C>          <C>             <C>
Product transportation
   and pipeline              $    219      $     184      $     159      $    133     $      124      $    1,175
Offshore equipment
   operating leases          $    175      $     145      $     144      $    116     $      117      $      398
Offshore drilling            $    251      $      62      $       -      $      -     $        -      $        -
Asset retirement
   obligations (1)           $      6      $       7      $       6      $      6     $        6      $    4,443
Office leases                $     25      $      29      $      23      $      2     $        2      $        1
Other                        $    321      $     180      $      17      $     12     $        8      $       19
=================================================================================================================
</TABLE>

     (1)  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 2009 - 2013 represent the minimum required expenditures to
          meet these  obligations.  Actual  expenditures in any particular year
          may exceed these minimum amounts.

     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.


94   CANADIAN NATURAL
<PAGE>

15.  SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

     Changes in non-cash working capital were as follows:

<TABLE>
<CAPTION>
                                                                           2008         2007           2006
------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>          <C>            <C>
Decrease (increase) in non-cash working capital
Accounts receivable and other                                        $      111   $      334     $     (116)
Accounts payable                                                             (4)        (456)           157
Accrued liabilities                                                         (15)        (402)          (582)
------------------------------------------------------------------------------------------------------------
Net change in non-cash working capital                               $       92   $     (524)    $     (541)
------------------------------------------------------------------------------------------------------------
Relating to:
Operating activities                                                 $     (189)  $     (346)    $     (679)
Financing activities                                                         46            8             37
Investing activities                                                        235         (186)            101
------------------------------------------------------------------------------------------------------------
                                                                     $       92   $     (524)    $     (541)

============================================================================================================
Other cash flow information:                                               2008         2007           2006
------------------------------------------------------------------------------------------------------------
Interest paid                                                        $      574   $      556     $      262
Taxes paid                                                           $      558   $      418     $      703
============================================================================================================
</TABLE>

16.  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:

<TABLE>
<CAPTION>
                                                                                           November 2, 2006
-------------------------------------------------------------------------------------------------------------
<S>                                                                                        <C>
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
=============================================================================================================
</TABLE>
     (1)  Net cash  consideration  was  reduced by $88  million to reflect  the
          settlement of US dollar forward contracts designated as hedges of the
          ACC purchase price.



                                                          CANADIAN NATURAL   95
<PAGE>

17.  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   include  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  reported  in the  segmented  information  as  other.
     Inter-segment  eliminations include internal  transportation,  electricity
     charges and natural gas sales.

<TABLE>
<CAPTION>
                                                               Conventional Crude Oil and Natural Gas
                        ------------------------------------------------------------------------------------------------------------
                                        North America                          North Sea                       Offshore West Africa
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
                                2008 |      2007        2006        2008 |       2007       2006        2008 |     2007        2006
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
<S>                        <C>         <C>         <C>          <C>          <C>         <C>         <C>        <C>        <C>
     Segmented revenue     $  13,496 | $  10,149   $   9,066    $  1,769 |   $  1,597    $ 1,616     $   944 |  $   776    $    950
     Less: royalties          (1,876)|    (1,318)     (1,203)         (4)|         (3)        (3)       (143)|      (70)        (39)
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
     Revenue, net of                 |                                   |                                   |
     royalties                11,620 |     8,831       7,863       1,765 |      1,594      1,613         801 |      706         911
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
     Segmented                       |                                   |                                   |
     expenses                        |                                   |                                   |
     Production                1,881 |     1,642       1,436         457 |        432        390         102 |       94         106
     Transportation                  |                                   |                                   |
     and blending              1,975 |     1,595       1,465          10 |         16         15           1 |        1           1
     Depletion,                      |                                   |                                   |
       depreciation                  |                                   |                                   |
       and                           |                                   |                                   |
       amortization            2,236 |     2,350       1,897         317 |        340        297         132 |      165         189
     Asset retirement                |                                   |                                   |
       obligation                    |                                   |                                   |
       accretion                  42 |        38          35          27 |         30         31           2 |        2           2
     Realized risk                   |                                   |                                   |
       management                    |                                   |                                   |
       activities              1,861 |       129       1,022         (1) |         33        303           - |        -           -
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
     Total segmented                 |                                   |                                   |
       expenses                7,995 |     5,754       5,855         810 |        851      1,036         237 |      262         298
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
     Segmented                       |                                   |                                   |
       earnings                      |                                   |                                   |
       before the                    |                                   |                                   |
       following            $  3,625 |  $  3,077   $   2,008    $    955 |   $    743    $   577     $   564 |  $   444    $    613
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
     Non-segmented expenses
     Administration
     Stock-based compensation (recovery) expense
     Interest, net
     Unrealized risk management activities
     Foreign exchange loss (gain)
------------------------------------------------------------------------------------------------------------------------------------
     Total non-segmented expenses
------------------------------------------------------------------------------------------------------------------------------------
     Earnings before taxes
     Taxes other than income tax
     Current income tax expense
     Future income tax expense (recovery)
------------------------------------------------------------------------------------------------------------------------------------
     Net earnings
====================================================================================================================================
</TABLE>

Capital Expenditures

<TABLE>
<CAPTION>
                                                        2008                     |                       2007
                                 ------------------------------------------------|----------------------------------------------
                                                      Non cash                   |                     Non cash
                                                      and fair                   |                     and fair
                                           Net           value      Capitalized  |            Net         value     Capitalized
                                   expenditure      changes (1)           costs  |    expenditure    changes (1)          costs
---------------------------------------------------------------------------------|----------------------------------------------
<S>                                <C>              <C>             <C>               <C>            <C>             <C>
     Conventional crude oil and natural gas                                      |
        North America              $     2,344      $       (7)     $     2,337  |    $     2,428    $       52      $    2,480
        North Sea                          319            (127)             192  |            439           (77)            362
        Offshore West                      811               6              817  |            159           (11)            148
        Africa                                                                   |
        Other                                1               -                1  |              1             -               1
---------------------------------------------------------------------------------|----------------------------------------------
                                         3,475            (128)           3,347  |          3,027           (36)          2,991
     Horizon Project (2)                 3,912              10            3,922  |          3,301             -           3,301
     Midstream                               9               -                9  |              6             -               6
     Head office                            17               -               17  |             20             -              20
---------------------------------------------------------------------------------|----------------------------------------------
                                   $     7,413      $     (118)     $     7,295  |    $     6,354    $      (36)     $    6,318
=================================================================================|==============================================
</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,  stock-based  compensation,  and the impact of intersegment
          eliminations.

96   CANADIAN NATURAL
<PAGE>

<TABLE>
<CAPTION>
                                                               Inter-segment
                                                                elimination
                                     Midstream                   and other                                   Total
--------------------------------|--------------------------------|-----------------------------------|--------------------------
                           2008 |      2007      2006       2008 |      2007       2006         2008 |        2007          2006
--------------------------------|--------------------------------|-----------------------------------|--------------------------
<S>                     <C>         <C>        <C>       <C>         <C>         <C>       <C>           <C>           <C>
                        $    77 |   $    74    $   72    $  (113)|   $   (53)    $  (61    $  16,173 |   $  12,543     $  11,643
                              - |         -         -          6 |         -          -       (2,017)|      (1,391)       (1,245)
--------------------------------|--------------------------------|-----------------------------------|--------------------------
                             77 |        74        72       (107)|       (53)       (61)      14,156 |      11,152        10,398
--------------------------------|--------------------------------|-----------------------------------|--------------------------
                             25 |        22        23        (14)|        (6)        (6)       2,451 |       2,184         1,949
                              - |         -         -        (50)|       (42)       (38)       1,936 |       1,570         1,443
                              8 |         8         8        (10)|         -          -        2,683 |       2,863         2,391
                              - |         -         -          - |         -          -           71 |          70            68
                              - |         -         -          - |         -          -        1,860 |         162         1,325
--------------------------------|--------------------------------|-----------------------------------|--------------------------
                             33 |        30        31        (74)|       (48)       (44)       9,001 |       6,849         7,176
--------------------------------|--------------------------------|-----------------------------------|--------------------------
                                |                                |                                   |
                        $    44 |   $    44    $   41    $   (33)|   $    (5)    $  (17)       5,155 |       4,303         3,222
--------------------------------|--------------------------------|-----------------------------------|--------------------------
                                                                                                 180 |         208           180
                                                                                                 (52)|         193           139
                                                                                                 128 |         276           140
                                                                                              (3,090)|       1,400        (1,013)
                                                                                                 718 |        (471)          122
--------------------------------|--------------------------------|-----------------------------------|--------------------------
                                                                                              (2,116)|       1,606          (432)
--------------------------------|--------------------------------|-----------------------------------|--------------------------
                                                                                               7,271 |       2,697         3,654
                                                                                                 178 |         165           256
                                                                                                 501 |         380           222
                                                                                               1,607 |        (456)          652
--------------------------------|--------------------------------|-----------------------------------|--------------------------
                                                                                           $   4,985 |   $   2,608     $   2,524
-----------------------------------------------------------------------------------------------------|--------------------------

<CAPTION>
Segmented Assets
                                                                                                2008 |        2007
-----------------------------------------------------------------------------------------------------|---------------
<S>                                                                                        <C>           <C>
     Conventional crude oil and natural gas
        North America                                                                      $  24,875 |   $  23,617
        North Sea                                                                              2,638 |       1,957
        Offshore West Africa                                                                   2,013 |       1,354
        Other                                                                                     64 |          41
     Horizon Project                                                                          12,677 |       8,740
     Midstream                                                                                   315 |         333
     Head office                                                                                  68 |          72
-----------------------------------------------------------------------------------------------------|---------------
                                                                                           $  42,650 |   $  36,114
=====================================================================================================|===============
</TABLE>

                                                          CANADIAN NATURAL   97
18.  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 (loss) as reported:

<TABLE>
<CAPTION>
     (millions of Canadian dollars, except per common
     share amounts)                                                 Notes           2008 |         2007          2006
-----------------------------------------------------------------------------------------|----------------------------
<S>                                                                <C>         <C>            <C>           <C>
     Net earnings - Canadian GAAP                                              $   4,985 |    $   2,608     $   2,524
     Adjustments                                                                         |
     Depletion, net of taxes of $2,503 million                                           |
        (2007 - $1 million, 2006 - $1 million)                       (A,D)        (6,169)|          (10)            2
     Stock-based compensation, net of taxes of $32                                       |
        million (2007 - $3 million, 2006 - $18 million)                (B)           (76)|          (22)          (40)
     Future income taxes                                               (G)           234 |         (234)             -
     Derivative financial instruments and hedging                                        |
        activities, net of taxes of $nil (2007 - $nil,                                   |
        2006 - $15 million)                                          (C,D)             - |            -           117
-----------------------------------------------------------------------------------------|----------------------------
     Net earnings (loss) before cumulative effect                                 (1,026)|        2,342         2,603
        of change in accounting policy - US GAAP                                         |
     Cumulative effect of change in accounting policy,                                   |
        net of taxes of $nil (2007 - $nil, 2006 - $3                                     |
        million)                                                       (B)             - |            -            (8)
-----------------------------------------------------------------------------------------|----------------------------
     Net earnings (loss) - US GAAP                                             $  (1,026)|    $   2,342     $   2,595
-----------------------------------------------------------------------------------------|----------------------------
     Net earnings (loss) before cumulative effect of change                              |
        in accounting policy - US GAAP per common share                                  |
        Basic                                                                  $   (1.90)|    $    4.34     $    4.84
        Diluted                                                        (F)     $   (1.90)|    $    4.32     $    4.77
-----------------------------------------------------------------------------------------|----------------------------
     Net earnings (loss) - US GAAP per common share                                      |
        Basic                                                                  $   (1.90)|    $    4.34     $    4.83
        Diluted                                                        (F)     $   (1.90)|    $    4.32     $    4.75
=========================================================================================|============================

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

     (millions of Canadian dollars)                                 Notes           2008  |        2007          2006
------------------------------------------------------------------------------------------|---------------------------
<S>                                                                <C>         <C>            <C>           <C>
     Comprehensive income - Canadian GAAP                                      $   5,175  |   $   2,534     $   2,520
     US GAAP earnings adjustments                                                 (6,011) |        (266)           71
     Derivative financial instruments and hedging                                         |
        activities, net of taxes of $nil (2007 - $nil                                     |
        million; 2006 - $394 million)                                  (C)             -  |           -           805
------------------------------------------------------------------------------------------|---------------------------
     Comprehensive income (loss) - US GAAP                                     $    (836) |   $   2,268     $   3,396
==========================================================================================|===========================
</TABLE>

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

<TABLE>
<CAPTION>
                                                                                         2008
----------------------------------------------------------------------------------------------------------------------
                                                                    Notes       Canadian       Increase            US
                                                                                    GAAP      (Decrease)         GAAP
----------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars)
<S>                                                            <C>            <C>             <C>           <C>
Current assets                                                                $    3,392      $       -     $   3,392
Property, plant and equipment                                    (A,B,D,E)        38,966         (8,551)       30,415
Other long-term assets                                                 (H)           292             55           347
----------------------------------------------------------------------------------------------------------------------
                                                                              $   42,650      $  (8,496)    $  34,154
----------------------------------------------------------------------------------------------------------------------
Current liabilities                                                    (B)    $    3,420      $     150     $   3,570
Long-term debt                                                         (H)        12,596             55        12,651
Other long-term liabilities                                            (B)         1,124             15         1,139
Future income tax                                              (A,B,D,E,G)         7,136         (2,474)        4,662
Share capital                                                                      2,768              -         2,768
Retained earnings                                                                 15,344         (6,242)        9,102
Accumulated other comprehensive income                                               262              -           262
----------------------------------------------------------------------------------------------------------------------
                                                                              $   42,650      $  (8,496)    $  34,154
======================================================================================================================
</TABLE>

98   CANADIAN NATURAL
<PAGE>

<TABLE>
<CAPTION>
                                                                                    2007
---------------------------------------------------------------------------------------------------------------------
                                                                           Canadian         Increase              US
     (millions of Canadian dollars)                        Notes               GAAP        (Decrease)           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                                   (H)                31               51              82
---------------------------------------------------------------------------------------------------------------------
                                                                       $     36,114      $       142      $   36,256
---------------------------------------------------------------------------------------------------------------------

     Current liabilities                                      (B)      $      3,563      $        66      $    3,629
     Long-term debt                                           (H)            10,940               51          10,991
     Other long-term liabilities                              (B)             1,561               20           1,581
     Future income tax                                (A,B,D,E,G)             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
=====================================================================================================================
</TABLE>

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") as  described  in note  1(H).  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
          current and prior years  resulted in the  recognition of ceiling test
          impairments  under  US  GAAP,  which  reduced  property,   plant  and
          equipment by $8,697  million in 2008 (2007 - $36 million,  2006 - $40
          million).

          For the year ended December 31, 2008, US GAAP net earnings would have
          decreased by $6,164 million, net of income taxes of $2,501 million to
          reflect the impact of a current  year  ceiling  test  impairment.  In
          addition,  the impact of prior  ceiling test  impairments  would have
          increased US GAAP net earnings by $3 million  (2007 - decreased by $4
          million,  2006 - increased by $3 million),  net of income taxes of $1
          million (2007 - $8 million,  2006 - $2 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,  2008,  US GAAP net
          earnings  would have  decreased  by $76 million  (2007 - $22 million,
          2006 - $48  million),  net of income taxes of $32 million  (2007 - $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.

     (C)  Effective  January  1,  2007,  the  Company  adopted  new  accounting
          standards  for  financial   instruments.   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,  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.  Comprehensive  income would have  increased by
          $805  million  as a result  of  recording  all  derivative  financial
          instruments at fair value in accordance with US GAAP.

     (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, 2008, US GAAP net earnings
          would have been decreased by $8 million (2007 - $6 million, 2006 - $1
          million),  net of income taxes of $3 million (2007 - $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.


                                                          CANADIAN NATURAL   99
<PAGE>

     (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.

     (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,  2008,  no
          additional  shares  would have been  included in the  calculation  of
          diluted  earnings per share for US GAAP as the impact would have been
          anti-dilutive  (2007 - 3,376,000  additional shares, 2006 - 8,762,000
          additional shares).


     (G)  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
          resulted  in a  difference  in  timing of the  recognition  of a $234
          million future income tax recovery.

     (H)  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 $55  million  of debt  issue  costs  from
          long-term  debt to  deferred  charges in 2008  (2007 - $51  million).
          There was no difference from Canadian GAAP prior to 2007.

     (I)  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 adoption of this standard did not result
          in a Canadian and US GAAP reconciling item.

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

     (K)  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.

     (L)  US GAAP - Recently issued accounting standards

          During  2008,  the US  Securities  and  Exchange  Commission  adopted
          revisions  to its oil  and gas  reporting  disclosures  contained  in
          regulation S-K and regulation S-X. These  revisions  change the price
          basis  for  calculating  oil  and  gas  reserves  from a  single-day,
          year-end price to a monthly  average price based on "first day of the
          month" price.  These  revisions  will impact the reserves used in the
          Company's accounting for depletion and its calculation of the ceiling
          test under US GAAP. These revisions are effective for filings made on
          or after January 1, 2010, and will be applied  prospectively  with no
          retroactive restatement.



100  CANADIAN NATURAL
<PAGE>

                              ADDITIONAL DISCLOSURE

DISCLOSURE CONTROLS AND PROCEDURES
----------------------------------

As of the end of the  registrant's  fiscal  year ended  December  31,  2008,  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, 2008,
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, 2008, filed as part of this Annual Report on Form 40-F.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
----------------------------------------------------

During  the  fiscal  year  ended  December  31,  2008,  there were no changes in
Canadian  Natural's   internal  control  over  financial   reporting  that  have
materially  affected,  or are reasonably likely to materially  affect,  Canadian
Natural's internal control 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
trading in Canadian  Natural's  shares and is  designed to ensure that  Canadian


<PAGE>


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.

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, 2008 and  December  31,  2007,  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 $2,685,800 for 2008 and were $2,729,315 for 2007.

AUDIT-RELATED FEES

The  aggregate  fees  billed for each of the last two fiscal  years of  Canadian
Natural,  ending  December 31, 2008 and December  31,  2007,  for  audit-related
services by PwC including debt covenant compliance and Crown Royalty Statements,
were  $156,300 for 2008 and were  $164,000 for 2007.  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, 2008 and December  31,  2007,  for  professional
services rendered by PwC for tax-related services related to expatriate personal
tax compliance as well as other  corporate tax return  matters  provided in 2008
were  $91,500 for 2008 and were  $154,459  for 2007.  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, 2008 and December 31, 2007 for other services were
$9,500 for 2008 and were $9,440 for 2007.  The fees for other  services  paid in
2008 related to accessing resource materials through PwC's accounting literature
library. Canadian Natural's Audit Committee approved all of the noted services.

AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES
----------------------------------------------------

The Audit  Committee's  duties  and  responsibilities  include  the  review  and
approval of fees to be paid to the independent auditors, scope and timing of the
audit and other related services rendered by the independent auditors. The Audit


<PAGE>


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 2008.

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, 2008, filed herewith, under the caption "Commitments and
Off Balance Sheet Arrangements".

CONTRACTUAL OBLIGATIONS
-----------------------

In the  normal  course  of  business,  the  Company  has  entered  into  various
commitments that will have an impact on the Company's future  operations.  These
commitments  primarily relate to firm commitments for gathering,  processing and
transmission  services;  operating  leases relating to offshore FPSOs,  drilling
rigs and office space;  expenditures  relating to ARO; as well as long-term debt
and interest  payments.  As at December 31, 2008, 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, 2008:

<TABLE>
<CAPTION>

($ millions)                              2009    2010      2011     2012     2013   Thereafter
-----------------------------------------------------------------------------------------------
<S>                                    <C>        <C>      <C>     <C>       <C>     <C>
Product transportation and pipeline    $   219    $ 184    $ 159   $   133   $ 124   $    1,175
Offshore equipment operating lease     $   175    $ 145    $ 144   $   116   $ 117   $      398
Offshore drilling                      $   251    $  62    $   -   $     -   $   -   $        -
Asset retirement obligations (1)       $     6    $   7    $   6   $     6   $   6   $    4,443
Long-term debt (2)                     $ 2,385    $ 400    $ 490   $   429   $ 890   $    6,707
Interest expense (3)                   $   610    $ 565    $ 543   $   490   $ 428   $    5,992
Office lease                           $    25    $  29    $  23   $     2   $   2   $        1
Other                                  $   321    $ 180    $  17   $    12   $   8   $       19
===============================================================================================
</TABLE>

(1)  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 2009 - 2013 represent the minimum required
     expenditures  to  meet  these  obligations.   Actual  expenditures  in  any
     particular year may exceed these minimum amounts.

(2)  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 $1,725  million of revolving
     bank credit facilities due to the extendable nature of the facilities.

(3)  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, 2008.

IDENTIFICATION OF THE AUDIT COMMITTEE
-------------------------------------

Canadian   Natural  has  a  separately   designated   standing  audit  committee
established  in  accordance  with section  3(a)(58)(A)  of the Exchange Act. The
members of the Audit  Committee are Messrs.  G. A. Filmon,  G. D. Giffin,  D. A.
Tuer and Ms. C.M. Best, who chairs the Audit Committee.


<PAGE>


NEW YORK STOCK EXCHANGE DISCLOSURE
----------------------------------

Presiding Director at Meetings of Non-Management Directors
----------------------------------------------------------

Canadian Natural schedules  executive sessions at each regularly scheduled Board
of Directors meeting in which Canadian Natural's "non-management  directors" (as
that term is defined in the rules of the New York Stock  Exchange)  meet without
management participation. Mr. G. D. Giffin serves as the presiding director (the
"Presiding  Director")  at such  sessions and in his absence the  non-management
directors appoint a Presiding Director from among the non-management directors.

Communication with Non-Management Directors
-------------------------------------------

Shareholders  may  send  communications  to  Canadian  Natural's  non-management
directors by writing to the Presiding Director, c/o Bruce E. McGrath,  Corporate
Secretary,  Canadian  Natural  Resources  Limited,  2500, 855 - 2nd Street S.W.,
Calgary,  Alberta,  T2P 4J8.  Communications  will be referred to the  Presiding
Director  for  appropriate  action.  The  status  of  all  outstanding  concerns
addressed to the  Presiding  Director will be reported to the Board of Directors
as appropriate.

Corporate Governance Guidelines
-------------------------------

In accordance with Section  303A.09 of the NYSE Listed Company Manual,  Canadian
Natural  has  adopted  a set  of  corporate  governance  guidelines,  which  are
available in print at no charge to any shareholder  who requests them.  Requests
for copies of the corporate governance  guidelines should be made by contacting:
Bruce E. McGrath,  Corporate  Secretary,  Canadian  Natural  Resources  Limited,
2500-855 2nd Street,  S.W.,  Calgary,  Alberta,  Canada T2P 4J8.  The  corporate
governance guidelines are attached as a schedule to the Information Circular for
the Annual General Meeting of Shareholders which is available through the System
for Electronic Document and Analysis and Retrieval (SEDAR) at www.sedar.com.

Board Committee Charters
------------------------

The charters of Canadian  Natural's  Audit  Committee,  Nominating and Corporate
Governance  Committee  and  Compensation  Committee are available in print at no
charge to any  shareholder  who  requests  them.  Requests  for  copies of these
documents should be made by contacting:  Bruce E. McGrath,  Corporate Secretary,
Canadian Natural Resources Limited, 2500-855 2nd Street, S.W., Calgary, Alberta,
Canada T2P 4J8.  The  Charter of  Canadian  Natural's  Audit  Committee  is also
attached as a schedule to Canadian  Natural's  Annual  Information Form for year
ending  December  31,  2008,  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.


                                   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 25th day of March, 2009.

                            CANADIAN NATURAL RESOURCES LIMITED


                            By:  SIGNED "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, 2008.

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 GLJ Petroleum Consultants Ltd.,  independent petroleum
               engineering consultants.



<PAGE>
                                                                      EXHIBIT 1


                     SUPPLEMENTARY OIL & GAS INFORMATION FOR
                     THE FISCAL YEAR ENDED DECEMBER 31, 2008


SUPPLEMENTARY OIL & GAS INFORMATION (unaudited)

This  supplementary  crude  oil and  natural  gas  information  is  provided  in
accordance with the United States Financial Accounting Standards Board Statement
69 ("FAS 69"),  "Disclosures about Oil and Gas Producing Activities",  and where
applicable is reconciled  to the  financial  information  prepared in accordance
with generally accepted accounting principles in the United States ("US GAAP").

NET PROVED CRUDE OIL AND NATURAL GAS RESERVES

The Company retains qualified  independent  reserves  evaluators to evaluate the
Company's proved crude oil and natural gas reserves.

o    For the year ended  December  31, 2008,  the reports by Sproule  Associates
     Limited ("Sproule") covered 100% of the Company's conventional reserves.

o    For the years  ended  December  31,  2007,  2006,  and 2005 the  reports by
     Sproule and Ryder Scott Company covered 100% of the Company's  conventional
     reserves.

Proved crude oil and natural gas reserves are the estimated  quantities of crude
oil,   natural  gas  and  natural  gas  liquids  ("NGLs")  that  geological  and
engineering  data  demonstrate  with  reasonable  certainty to be recoverable in
future  years  from known  reservoirs  under  existing  economic  and  operating
conditions.  Proved  developed  reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.

Estimates of crude oil and natural gas reserves are subject to  uncertainty  and
will change as additional  information regarding producing fields and technology
becomes available and as future economic and operating conditions change.

The  following  table  summarizes  the  Company's  proved and  proved  developed
conventional  crude  oil and  natural  gas  reserves,  net of  royalties,  as at
December 31, 2008, 2007, 2006, and 2005:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
                                                               North                North            Offshore
Crude oil and NGLs (mmbbl)                                   America                  Sea         West Africa            Total
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>                    <C>           <C>                 <C>
Net proved reserves Reserves, December 31, 2005                  694                  290                 134            1,118
Extensions and discoveries                                        53                    3                   -               56
Improved recovery                                                190                   26                   -              216
Purchases of reserves in place                                    26                    -                   -               26
Sales of reserves in place                                         -                    -                   -                -
Production                                                       (75)                 (22)                (13)            (110)
Revisions of prior estimates (1)                                  (1)                   2                   9               10
-------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2006                                      887                  299                 130            1,316
Extensions and discoveries                                        30                    -                   -               30
Improved recovery                                                 13                    6                   -               19
Purchases of reserves in place                                     1                    -                   -                1
Sales of reserves in place                                         -                   (3)                  -               (3)
Production                                                       (77)                 (20)                (10)            (107)
Revisions of prior estimates (1)                                  66                   28                   8              102
-------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2007                                      920                  310                 128            1,358
Extensions and discoveries                                        51                    -                   -               51
Improved recovery                                                 17                    6                   4               27
Purchases of reserves in place                                     -                    -                   -                -
Sales of reserves in place                                         -                    -                   -                -
Production                                                       (76)                 (17)                 (8)            (101)
Economic revisions due to prices                                  28                  (81)                  8              (45)
Revisions of prior estimates                                       8                   38                  10               56
-------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2008                                      948                  256                 142            1,346
===============================================================================================================================
Net proved developed reserves
         December 31, 2005                                       402                  214                  80              696
         December 31, 2006                                       420                  214                  63              697
         December 31, 2007                                       426                  240                  70              736
         December 31, 2008                                       428                   97                 107              632
===============================================================================================================================
</TABLE>
(1)  Revisions of prior estimates for the years ended December 31, 2007 and 2006
     include the impact of economic revisions due to prices.

<PAGE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
                                                                North                North            Offshore
Natural gas (bcf)                                             America                  Sea         West Africa             Total
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>                     <C>           <C>                 <C>
Net proved reserves
Reserves, December 31, 2005                                     2,741                   29                  72             2,842
Extensions and discoveries                                        250                    -                   -               250
Improved recovery                                                  74                    -                   -                74
Purchases of reserves in place                                  1,111                    -                   -             1,111
Sales of reserves in place                                         (1)                   -                   -                (1)
Production                                                       (433)                  (5)                 (3)             (441)
Revisions of prior estimates (1)                                  (37)                  13                 (13)              (37)
---------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2006                                     3,705                   37                  56             3,798
Extensions and discoveries                                        134                    -                   -               134
Improved recovery                                                 132                    3                   -               135
Purchases of reserves in place                                     12                    -                   -                12
Sales of reserves in place                                          -                    -                   -                 -
Production                                                       (503)                  (5)                 (4)             (512)
Revisions of prior estimates (1)                                   41                   46                  12                99
---------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2007                                     3,521                   81                  64             3,666
Extensions and discoveries                                        140                    -                   -               140
Improved recovery                                                  52                   (1)                  6                57
Purchases of reserves in place                                     77                    -                   -                77
Sales of reserves in place                                         (1)                   -                   -                (1)
Production                                                       (449)                  (4)                 (4)             (457)
Economic revisions due to prices                                  (19)                 (56)                  6               (69)
Revisions of prior estimates                                      202                   47                  22               271
---------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2008                                     3,523                   67                  94             3,684
=================================================================================================================================
Net proved developed reserves
         December 31, 2005                                      2,300                   16                  10             2,326
         December 31, 2006                                      2,934                   17                  12             2,963
         December 31, 2007                                      2,731                   58                  53             2,842
         December 31, 2008                                      2,690                   45                  89             2,824
=================================================================================================================================
</TABLE>
(1)  Revisions of prior estimates for the years ended December 31, 2007 and 2006
     include the impact of economic revisions due to prices.

<PAGE>

<TABLE>
<CAPTION>
CAPITALIZED COSTS RELATED TO CRUDE OIL AND NATURAL GAS ACTIVITIES

                                                                          2008
-----------------------------------------------------------------------------------------------------------------------------------
                                            North             North                  Offshore
(millions of Canadian dollars)            America               Sea               West Africa             Other              Total
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>                <C>                <C>                       <C>              <C>
Proved properties                    $     34,386       $     4,155        $            2,076        $       14       $     40,631
Unproved properties                         2,271                12                       595                26              2,904
-----------------------------------------------------------------------------------------------------------------------------------
                                           36,657             4,167                     2,671                40             43,535
Less: accumulated depletion
  and depreciation                        (21,857)           (3,366)                     (777)              (14)           (26,014)
-----------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs                $     14,800       $       801        $            1,894        $       26       $     17,521
===================================================================================================================================

                                                                                  2007
-----------------------------------------------------------------------------------------------------------------------------------
                                            North             North                  Offshore
(millions of Canadian dollars)            America               Sea               West Africa             Other              Total
-----------------------------------------------------------------------------------------------------------------------------------
Proved properties                    $     32,061       $     3,164        $            1,695        $       14       $     36,934
Unproved properties                         2,259                10                       138                25              2,432
-----------------------------------------------------------------------------------------------------------------------------------
                                           34,320             3,174                     1,833                39             39,366
Less: accumulated depletion
  and depreciation                        (12,213)           (1,446)                     (645)              (14)           (14,318)
-----------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs                $     22,107       $     1,728        $            1,188        $       25       $     25,048
===================================================================================================================================

                                                                                  2006
-----------------------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars)              North             North                  Offshore                                Total
                                          America               Sea               West Africa             Other
-----------------------------------------------------------------------------------------------------------------------------------
Proved properties                    $     29,596       $     3,346        $            1,601        $       14       $     34,557
Unproved properties                         2,244                24                        84                24              2,376
-----------------------------------------------------------------------------------------------------------------------------------
                                           31,840             3,370                     1,685                38             36,933
Less: accumulated depletion                (9,878)           (1,341)                     (481)              (14)           (11,714)
  and depreciation
-----------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs                $     21,962       $     2,029        $            1,204        $       24       $     25,219
===================================================================================================================================

<CAPTION>

COSTS INCURRED IN CRUDE OIL AND NATURAL GAS ACTIVITIES

                                                                        2008
---------------------------------------------------------------------------------------------------------------------------------
                                            North             North                 Offshore
(millions of Canadian dollars)            America               Sea              West Africa             Other             Total
---------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>               <C>                <C>                      <C>              <C>
Property acquisitions
   Proved                            $        299      $         (7)      $               44       $         -      $        336
   Unproved                                    84                 1                        1                 -                86
Exploration                                   144                 3                        -                 1               148
Development                                 1,810               195                      772                 -             2,777
---------------------------------------------------------------------------------------------------------------------------------
Costs incurred                       $      2,337      $        192       $              817       $         1      $      3,347
=================================================================================================================================

<CAPTION>
                                                                        2007
---------------------------------------------------------------------------------------------------------------------------------
                                            North             North                 Offshore
(millions of Canadian dollars)            America               Sea              West Africa             Other             Total
---------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>               <C>                <C>                      <C>              <C>
Property acquisitions
   Proved                            $         55      $        (38)      $                -       $         -      $         17
   Unproved                                    13                 1                        -                 -                14
Exploration                                   239                19                        -                 1               259
Development                                 2,173               380                      148                 -             2,701
---------------------------------------------------------------------------------------------------------------------------------
Costs incurred                       $      2,480      $        362       $              148       $         1      $      2,991
=================================================================================================================================


<CAPTION>
                                                                           2006
---------------------------------------------------------------------------------------------------------------------------------
                                            North             North                 Offshore
(millions of Canadian dollars)            America               Sea              West Africa             Other             Total
---------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>               <C>                <C>                      <C>              <C>
Property acquisitions
   Proved                            $      5,627      $          -       $                1       $         -      $      5,628
   Unproved                                   910                 -                        -                 -               910
Exploration                                   238                 4                        1                11               254
Development                                 2,807               628                      133                 -             3,568
---------------------------------------------------------------------------------------------------------------------------------
Costs incurred                       $      9,582      $        632       $              135       $        11      $     10,360
=================================================================================================================================
</TABLE>

RESULTS OF OPERATIONS FROM CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES

The Company's  results of  operations  from crude oil and natural gas producing
activities for the years ended December 31, 2008, 2007, and 2006 are summarized
in the following tables:

<TABLE>
<CAPTION>
                                                                                  2008
--------------------------------------------------------------------------------------------------------------------------------
                                                                 North              North             Offshore
(millions of Canadian dollars)                                 America                Sea          West Africa            Total
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>                 <C>               <C>                   <C>
Crude oil and natural gas revenue, net of                $       8,126       $      1,731      $           801       $   10,658
  royalties and blending costs
Production                                                      (1,881)              (457)                (102)          (2,440)
Transportation                                                    (327)               (10)                  (1)            (338)
Depletion, depreciation and amortization (1)                    (9,661)            (1,564)                (132)         (11,357)
Asset retirement obligation accretion                              (42)               (27)                  (2)             (71)
Petroleum revenue tax                                                -               (143)                   -             (143)
Income tax                                                       1,128                235                 (141)           1,222
--------------------------------------------------------------------------------------------------------------------------------
Results of operations                                    $      (2,657)      $       (235)     $           423       $   (2,469)
================================================================================================================================
</TABLE>

(1)  Includes the impact of a ceiling test impairt  December 31, 2008 of $8,665
     million, pre-tax.

<TABLE>
<CAPTION>
                                                                                            2007
-----------------------------------------------------------------------------------------------------------------------------
                                                                  North            North            Offshore
(millions of Canadian dollars)                                  America              Sea         West Africa           Total
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                        <C>                <C>             <C>                  <C>
Crude oil and natural gas revenue, net of                  $      7,441       $    1,522      $          709       $   9,672
  royalties and blending costs
Production                                                       (1,642)            (432)                (94)         (2,168)
Transportation                                                     (335)             (16)                 (1)           (352)
Depletion, depreciation and amortization                         (2,359)            (340)               (165)         (2,864)
Asset retirement obligation accretion                               (38)             (30)                 (2)            (70)
Petroleum revenue tax                                                 -             (141)                  -            (141)
Income tax                                                         (997)            (282)               (121)         (1,400)
-----------------------------------------------------------------------------------------------------------------------------
Results of operations                                      $      2,070       $      281      $          326       $   2,677
=============================================================================================================================

<CAPTION>
                                                                                         2006
-----------------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars)                                    North            North            Offshore           Total
                                                                America              Sea         West Africa
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                        <C>                <C>             <C>                  <C>
Crude oil and natural gas revenue, net of                  $      5,707       $    1,310      $          911       $   7,928
  royalties and blending costs
Production                                                       (1,436)            (390)               (106)         (1,932)
Transportation                                                     (326)             (15)                 (1)           (342)
Depletion, depreciation and amortization                         (1,894)            (297)               (189)         (2,380)
Asset retirement obligation accretion                               (35)             (31)                 (2)            (68)
Petroleum revenue tax                                                 -             (234)                  -            (234)
Income tax                                                         (706)            (172)               (172)         (1,050)
-----------------------------------------------------------------------------------------------------------------------------
Results of operations                                      $      1,310       $      171      $          441       $   1,922
=============================================================================================================================
</TABLE>

STANDARDIZED  MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED CRUDE OIL
AND NATURAL GAS RESERVES AND CHANGES THEREIN

The following  standardized  measure of  discounted  future net cash flows from
proved  crude oil and natural gas  reserves has been  computed  using  year-end
sales  prices and costs and  year-end  statutory  income tax rates.  A discount
factor of 10% has been  applied  in  determining  the  standardized  measure of
discounted  future  net cash  flows.  The  Company  does not  believe  that the
standardized measure of discounted future net cash flows will be representative
of actual  future net cash flows and should not be  considered to represent the
fair value of the crude oil and natural gas  properties.  Actual net cash flows
will differ from the presented  estimated  future net cash flows due to several
factors including:

o    Future production will include production not only from proved properties,
     but may also include production from probable and possible reserves;
o    Future production of crude oil and natural gas from proved properties will
     differ from reserves estimated;
o    Future production rates will vary from those estimated;
o    Future rather than year-end sales prices and costs will apply;
o    Economic factors such as interest rates, income tax rates,  regulatory and
     fiscal environments and operating conditions will change;
o    Future  estimated  income  taxes do not take into  account  the effects of
     future exploration expenditures; and
o    Future development and asset retirement obligations will differ from those
     estimated.

Future net revenues,  development,  production and restoration  costs have been
based upon the estimates  referred to above. The following tables summarize the
Company's  future net cash flows  relating to proved  crude oil and natural gas
reserves based on the standardized measure as prescribed in FAS 69:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------------
                                                                                          2008
-------------------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars)                                    North              North           Offshore            Total
                                                                America                Sea        West Africa
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                        <C>               <C>               <C>                 <C>
Future cash inflows                                        $     51,913      $      13,681     $        6,789      $    72,383
Future production costs                                         (23,747)            (6,845)            (3,000)         (33,592)
Future development and asset retirement
  obligations                                                    (9,238)            (4,674)              (364)         (14,276)
Future income taxes                                              (3,097)            (2,011)            (1,061)          (6,169)
-------------------------------------------------------------------------------------------------------------------------------
Future net cash flows                                            15,831                151              2,364           18,346
10% annual discount for timing of future
   cash flows                                                    (6,872)               (76)            (1,011)          (7,959)
-------------------------------------------------------------------------------------------------------------------------------
Standardized measure of future net cash flows              $      8,959      $          75     $        1,353      $    10,387
===============================================================================================================================
</TABLE>

<PAGE>

<TABLE>
<CAPTION>
                                                                                             2007
----------------------------------------------------------------------------------------------------------------------------------
                                                                  North               North            Offshore
(millions of Canadian dollars)                                  America                 Sea         West Africa             Total
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                        <C>                <C>                <C>                  <C>
Future cash inflows                                        $     71,069       $      30,269      $        9,921       $   111,259
Future production costs                                         (23,729)             (9,316)             (2,419)          (35,464)
Future development and asset retirement
  obligations                                                    (7,938)             (4,021)               (621)          (12,580)
Future income taxes                                              (9,508)            (11,376)             (1,978)          (22,862)
----------------------------------------------------------------------------------------------------------------------------------
Future net cash flows                                            29,894               5,556               4,903            40,353
10% annual discount for timing of future
   cash flows                                                   (13,952)             (2,176)             (2,505)          (18,633)
----------------------------------------------------------------------------------------------------------------------------------
Standardized measure of future net cash flows              $     15,942       $       3,380      $        2,398       $    21,720
==================================================================================================================================

<CAPTION>
                                                                                              2006
----------------------------------------------------------------------------------------------------------------------------------
                                                                  North               North            Offshore
(millions of Canadian dollars)                                  America                 Sea         West Africa             Total
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                        <C>                <C>                <C>                  <C>
Future cash inflows                                        $     63,368       $      20,815      $        7,779       $    91,962
Future production costs                                         (21,634)             (8,077)             (2,517)          (32,228)
Future development and asset retirement
  obligations                                                    (7,029)             (4,348)               (824)          (12,201)
Future income taxes                                              (9,118)             (5,623)             (1,372)          (16,113)
----------------------------------------------------------------------------------------------------------------------------------
Future net cash flows                                            25,587               2,767               3,066            31,420
10% annual discount for timing of future
   cash flows                                                   (11,214)               (956)             (1,258)          (13,428)
----------------------------------------------------------------------------------------------------------------------------------
Standardized measure of future net cash flows              $     14,373      $        1,811      $        1,808       $    17,992
==================================================================================================================================
</TABLE>

The principal sources of change in the standardized measure of discounted future
net cash flows are summarized in the following table:

<TABLE>
<CAPTION>
(millions of Canadian dollars)                                            2008                 2007                  2006
---------------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>                    <C>                 <C>
Sales of crude oil and natural gas produced, net of              $       (9,679)        $     (7,150)       $       (5,635)
  production costs
Net changes in sales prices and production costs                        (14,680)               7,412                (2,420)
Extensions, discoveries and improved recovery                               820                1,429                 4,769
Changes in estimated future development costs                              (715)                (169)               (1,885)
Purchases of proved reserves in place                                       113                   39                 2,406
Sales of proved reserves in place                                            (1)                (103)                   (2)
Revisions of previous reserve estimates                                     112                2,380                    81
Accretion of discount                                                     3,468                2,760                 3,112
Changes in production timing and other                                      767                  508                (2,156)
Net change in income taxes                                                8,462               (3,378)                1,270
---------------------------------------------------------------------------------------------------------------------------
Net change                                                              (11,333)               3,728                  (460)
Balance - beginning of year                                              21,720               17,992                18,452
---------------------------------------------------------------------------------------------------------------------------
Balance - end of year                                            $       10,387         $     21,720        $       17,992
===========================================================================================================================
</TABLE>


<PAGE>

                                                                      EXHIBIT 2


 CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13A-14(A) OR 15D-14
                     OF THE SECURITIES EXCHANGE ACT OF 1934


CERTIFICATION


I, Steve W. Laut, certify that:


1.   I have  reviewed  this  annual  report  on Form 40-F of  Canadian  Natural
     Resources Limited;

2.   Based on my knowledge,  this report does not contain any untrue  statement
     of a material fact or omit to state a material fact  necessary to make the
     statements made, in light of the circumstances under which such statements
     were made,  not  misleading  with  respect  to the period  covered by this
     report;

3.   Based on my  knowledge,  the  financial  statements,  and other  financial
     information  included  in this  report,  fairly  present  in all  material
     respects the financial condition,  results of operations and cash flows of
     the issuer as of, and for, the periods presented in this report;

4.   The  issuer's  other  certifying  officer(s)  and  I are  responsible  for
     establishing  and  maintaining  disclosure  controls  and  procedures  (as
     defined in  Exchange  Act Rules  13a-15(e)  and  15d-15(e))  and  internal
     control over financial reporting (as defined in Exchange Act Rules 13(a) -
     15(f) and 15d -15(f)) for the issuer and have:

     a)   Designed  such  disclosure  controls and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed  under  our
          supervision,  to ensure  that  material  information  relating to the
          issuer, including its consolidated subsidiaries,  is made known to us
          by others within those  entities,  particularly  during the period in
          which this report is being prepared;

     b)   Designed such internal  control over financial  reporting,  or caused
          such internal  control over financial  reporting to be designed under
          our  supervision,  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;

     c)   Evaluated the effectiveness of the issuer's  disclosure  controls and
          procedures  and  presented in this report our  conclusions  about the
          effectiveness  of the disclosure  controls and procedures,  as of the
          end of the period  covered by this report  based on such  evaluation;
          and

     d)   Disclosed in this report any change in the issuer's  internal control
          over financial  reporting that occurred  during the period covered by
          the annual  report that has  materially  affected,  or is  reasonably
          likely to  materially  affect,  the  issuer's  internal  control over
          financial reporting; and

5.   The issuer's other  certifying  officer(s) and I have disclosed,  based on
     our most recent  evaluation of internal control over financial  reporting,
     to the  issuer's  auditors and the audit  committee  of issuer's  board of
     directors (or persons performing the equivalent functions):

     a)   All significant deficiencies and material weaknesses in the design or
          operation of internal  control  over  financial  reporting  which are
          reasonably likely to adversely affect the issuer's ability to record,
          process, summarize and report financial information; and


     b)   Any fraud, whether or not material, that involves management or other
          employees  who  have a  significant  role  in the  issuer's  internal
          control over financial reporting.

Dated this 25th day of March, 2009.

SIGNED " STEVE W. LAUT"
-----------------------
Steve W. Laut
President and Chief Operating Officer (Principal Executive Officer),
Canadian Natural Resources Limited

<PAGE>

                                                                      EXHIBIT 3


 CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13A-14(A) OR 15D-14
                     OF THE SECURITIES EXCHANGE ACT OF 1934


CERTIFICATION

I, Douglas A. Proll, certify that:

1.   I have  reviewed  this  annual  report  on Form 40-F of  Canadian  Natural
     Resources Limited;

2.   Based on my knowledge,  this report does not contain any untrue  statement
     of a material fact or omit to state a material fact  necessary to make the
     statements made, in light of the circumstances under which such statements
     were made,  not  misleading  with  respect  to the period  covered by this
     report;

3.   Based on my  knowledge,  the  financial  statements,  and other  financial
     information  included  in this  report,  fairly  present  in all  material
     respects the financial condition,  results of operations and cash flows of
     the issuer as of, and for, the periods presented in this report;

4.   The  issuer's  other  certifying  officer(s)  and  I are  responsible  for
     establishing  and  maintaining  disclosure  controls  and  procedures  (as
     defined in  Exchange  Act Rules  13a-15(e)  and  15d-15(e))  and  internal
     control over financial reporting (as defined in Exchange Act Rules 13(a) -
     15(f) and 15d -15(f)) for the issuer and have:

     a)   Designed  such  disclosure  controls and  procedures,  or caused such
          disclosure   controls  and   procedures  to  be  designed  under  our
          supervision,  to ensure  that  material  information  relating to the
          issuer, including its consolidated subsidiaries,  is made known to us
          by others within those  entities,  particularly  during the period in
          which this report is being prepared;

     b)   Designed such internal  control over financial  reporting,  or caused
          such internal  control over financial  reporting to be designed under
          our  supervision,  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;

     c)   Evaluated the effectiveness of the issuer's  disclosure  controls and
          procedures  and  presented  in this report our  conclusion  about the
          effectiveness  of the disclosure  controls and procedures,  as of the
          end of the period  covered by this report  based on such  evaluation;
          and

     d)   Disclosed in this report any change in the issuer's  internal control
          over financial  reporting that occurred  during the period covered by
          the annual  report that has  materially  affected,  or is  reasonably
          likely to  materially  affect,  the  issuer's  internal  control over
          financial reporting; and

5.     The issuer's other certifying officer(s) and I have disclosed, based on
       our most recent evaluation of internal control over financial reporting,
       to the issuer's auditors and the audit committee of issuer's board of
       directors (or persons performing the equivalent functions):

       a)     All significant deficiencies and material weaknesses in the design
              or operation of internal control over financial reporting which
              are reasonably likely to adversely affect the issuer's ability to
              record, process, summarize and report financial information; and


       b)     Any fraud, whether or not material, that involves management or
              other employees who have a significant role in the issuer's
              internal control over financial reporting.

Dated this 25th day of March, 2009.


SIGNED "DOUGLAS A. PROLL"
-----------------------------
Douglas A. Proll
Chief Financial Officer and Senior Vice-President, Finance
(Principal Financial Officer),
Canadian Natural Resources Limited


<PAGE>

                                                                      EXHIBIT 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)

In  connection  with the report of  Canadian  Natural  Resources  Limited  (the
"Company")  on the Form 40-F for the fiscal  year ending  December  31, 2008 as
filed with the  Securities  and  Exchange  Commission  on the date  hereof (the
"Report"),  I, Steve W. Laut,  certify  pursuant to 18 U.S.C.  1350, as adopted
pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002, that to the best of
my knowledge:

1.    The Report fully complies with the requirements of section 13(a) or 15(d)
      of the Securities Exchange Act of 1934; and

2.    The information  contained in the Report fairly presents, in all material
      respects,  the  financial  condition  and  results of  operations  of the
      Company.



DATED this 25th day of March, 2009.


SIGNED "STEVE W. LAUT"
----------------------
Steve W. Laut
President and Chief Operating Officer (Principal Executive Officer),
Canadian Natural Resources Limited


<PAGE>

                                                                      EXHIBIT 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)

In  connection  with the report of  Canadian  Natural  Resources  Limited  (the
"Company")  on the Form 40-F for the fiscal  year ending  December  31, 2008 as
filed with the  Securities  and  Exchange  Commission  on the date  hereof (the
"Report"),  I, Douglas A. Proll, certify pursuant to 18 U.S.C. 1350, as adopted
pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002, that to the best of
my knowledge:

1.    The Report fully complies with the requirements of section 13(a) or 15(d)
      of the Securities Exchange Act of 1934; and

2.    The information  contained in the Report fairly presents, in all material
      respects,  the  financial  condition  and  results of  operations  of the
      Company.


DATED this 25th day of March, 2009.


SIGNED "DOUGLAS A. PROLL"
-------------------------
Douglas A. Proll
Chief Operating Officer and Senior Vice-President, Finance
(Principal Financial Officer),
Canadian Natural Resources Limited

<PAGE>

                                                                      EXHIBIT 6


    CONSENT OF PRICEWATERHOUSECOOPERS LLP, INDEPENDENT CHARTERED ACCOUNTANTS


We hereby consent to (i) the inclusion in Canadian Natural Resources  Limited's
Annual Report on Form 40-F for the year ended  December 31, 2008;  and (ii) the
incorporation by reference in the registration  statement on Form F-9 (File No.
333-146056),  of our  audit  report  dated  March 4,  2009 on the  consolidated
balance sheets of Canadian  Natural  Resources  Limited as at December 31, 2008
and 2007, and the consolidated  statements of earnings,  shareholder's  equity,
comprehensive  income  and cash  flows for each of the years in the  three-year
period ended December 31, 2008 and the  effectiveness  of internal control over
financial  reporting of Canadian Natural  Resources  Limited as of December 31,
2008.


Calgary, Alberta
March 25, 2009

<PAGE>

                                                                      EXHIBIT 7


                     CONSENT OF SPROULE ASSOCIATES LIMITED,
                  INDEPENDENT PETROLEUM ENGINEERING CONSULTANTS


We consent  to the use of our  report  with  respect  to the  reserves  data of
Canadian Natural Resources Limited  incorporated by reference in its (i) Annual
Report (Form 40-F) for the year ended  December 31, 2008 and (ii)  Registration
Statement on Form F-9 (Registration  No.  333-146056) filed with the Securities
and Exchange Commission.


SIGNED "SPROULE ASSOCIATES LIMITED"


Calgary, Alberta
March 25, 2009


<PAGE>

                                                                      EXHIBIT 8


                   CONSENT OF GLJ PETROLEUM CONSULTANTS LTD.,
                 INDEPENDENT PETROLEUM ENGINEERING CONSULTANTS


We consent  to the use of our  report  with  respect  to the  reserves  data of
Canadian Natural Resources Limited  incorporated by reference in its (i) Annual
Report (From 40-F) for the year ended  December 31, 2008 and (ii)  Registration
Statement on Form F-9 (Registration  No.  333-146056) filed with the Securities
and Exchange Commission.



SIGNED "GLJ PETROLEUM CONSULTANTS LTD."

Calgary, Alberta
March 25, 2009