<DOCUMENT>
<TYPE>EX-99
<SEQUENCE>2
<FILENAME>ex99-1form6k_q106int.txt
<DESCRIPTION>EXHIBIT 99.1
<TEXT>

                                                                    EXHIBIT 99.1
                                                                    ------------

--------------------------------------------------------------------------------
[GRAPHIC AND PHOTOGRAPHS OMITTED]                     [LOGO - CANADIAN NATURAL]

                                                        FIRST QUARTER REPORT
                                                       ----------------------
                                                         THREE MONTHS ENDED
                                                           MARCH 31, 2006
--------------------------------------------------------------------------------


                 CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES
                      STRONG QUARTERLY OPERATING RESULTS


In  commenting on first quarter 2006  results,  Canadian  Natural's  Chairman,
Allan Markin stated,  "The execution of our defined plan for profitable growth
continues on track. In the first quarter we executed a record drilling program
in a challenging  environment due to  unseasonably  warm weather and limits in
the  availability of rigs and services,  all the while achieving a 90% overall
success  rate.  On our major  projects we saw first  production  from Primrose
North which reached  15,000 bbl/d during the quarter,  we received  government
approval of the Olowi Field  development  plan offshore Gabon,  and we started
seeing positive  production  results from the waterflood and polymer floods at
Pelican Lake. At the Horizon  Project,  our team continues to execute and as a
result,  we remain  slightly  ahead of project  targets with all critical path
items  remaining on track. We are extremely proud of the work of our people in
meeting the challenges that we face on a daily basis, both on the conventional
side of the business and on the Horizon Project."


John Langille,  Vice-Chairman,  commented  "Much wider than normal heavy crude
oil  differentials  combined  with a decrease  in natural  gas  pricing  and a
stronger  Canadian  dollar reduced  average  selling  prices  received for our
products in the first quarter.  Heavy oil differentials have improved markedly
in  recent  weeks,  due in part to our  heavy oil  marketing  strategy  and in
particular our  participation in certain  pipeline  reversals which access new
markets.  Today,  based on current  strip  pricing we would expect to generate
cash flow in the range of $5.4  billion to $5.6  billion,  as  forecast in our
2006 budget. This strong cash flow, combined with the continued  management of
our  capital  costs in this very heated  environment  means that we will still
expect to exit 2006 with an exceptionally  strong balance sheet,  with debt to
cash flow targeted  under 1x and debt to book  capitalization  targeted in the
low 30% range."

Canadian  Natural's  President  and Chief  Operating  Officer,  Steve Laut, in
commenting on the Company's  quarter end and winter  drilling  program stated,
"The 2006 winter  drilling  program was  challenging in terms of managing both
the impacts of unusual  weather  patterns  and  general  cost  pressures.  The
abnormally warm weather resulted in the majority of our drilling program being
executed in March, which is more typically expected in January. The results of
the drilling  program were  excellent;  however the timing of the drilling and
tie-ins  has  left  at  the  end of the  quarter  70  mmcf/d  of  natural  gas
unconnected to sales lines when compared to plan. Due to cost  pressures,  the
Company  has made the  strategic  decision to  maintain  its  planned  capital
expenditure  level which will result in a slight reduction in overall drilling
activity.  This reduction will be focused primarily on natural gas activity as
a result of the significant  change in relative  pricing between crude oil and
natural  gas.  On the other  hand,  at the  Horizon  Project,  the warm winter
weather  has  allowed us to achieve  progress  ahead of plan.  To date we have
awarded  in  excess  of  C$4  billion  in  contracts   compared  to  a  target
construction  cost of  C$6.8  billion,  providing  a  greater  degree  of cost
certainty in this highly inflationary environment."


<PAGE>

HIGHLIGHTS
<TABLE>
<CAPTION>
                                                                      Three Months Ended
                                                     ---------------
                                                             MAR 31            Dec 31             Mar 31
($ millions, except as noted)                                  2006              2005               2005
---------------------------------------------------------------------------------------------------------
<S>                                                  <C>                <C>               <C>
Net earnings (loss)                                  $           57     $       1,104     $         (424)
     per common share, basic(1)                      $         0.11     $        2.06     $        (0.79)
Adjusted net earnings from operations(2)             $          268     $         601     $          380
     per common share, basic(1)                      $         0.50     $        1.12     $         0.71
Cash flow from operations(3)                         $        1,039     $       1,490     $        1,009
     per common share, basic(1)                      $         1.93     $        2.78     $         1.88
Capital expenditures, net of dispositions            $        2,309     $       1,679     $        1,372
Debt to book capitalization(4)                                  34%               29%                37%
Daily production, before royalties
     Natural gas (mmcf/d)                                     1,436             1,423              1,455
     Crude oil and NGLs (bbl/d)                             323,662           340,268            287,803
     Equivalent production (boe/d)                          563,027           577,505            530,316
=========================================================================================================
(1) RESTATED TO REFLECT TWO-FOR-ONE COMMON SHARE SPLIT IN MAY 2005.
(2) ADJUSTED NET EARNINGS FROM  OPERATIONS IS A NON-GAAP TERM THAT THE COMPANY  UTILIZES TO EVALUATE ITS
    PERFORMANCE.  THE  DERIVATION  OF THIS ITEM IS DISCUSSED  IN  MANAGEMENT'S  DISCUSSION  AND ANALYSIS
    ("MD&A").
(3) CASH FLOW FROM OPERATIONS IS A NON-GAAP TERM THAT THE COMPANY  CONSIDERS KEY AS IT DEMONSTRATES  ITS
    ABILITY TO FUND CAPITAL REINVESTMENT AND DEBT REPAYMENT. THE DERIVATION OF THIS ITEM IS DISCUSSED IN
    THE MD&A.
(4) INCLUDES CURRENT PORTION OF LONG-TERM DEBT.
</TABLE>

o   Quarterly cash flow of $1.039 billion, neutral compared to Q1/05 and a 30%
    decrease  from Q4/05 due to lower price  realizations  and,  as  expected,
    lower  sales  volumes  from   Primrose  and  high  netback   International
    operations.

o   Quarterly  net earnings of $57 million  compared to a loss of $424 million
    in Q1/05. First quarter net earnings included:

    --   A charge of $110 million for the effect of the UK statutory  tax rate
         changes on future income tax liabilities.

    --   A charge of $88 million after tax for revaluation of the stock option
         liability to reflect stock price appreciation during the quarter.

o   Strong quarterly adjusted net earnings from operations of $268 million.

o   Strong  balance  sheet with debt to book  capitalization  exiting what has
    historically been our highest capital quarter and lowest cash flow quarter
    at  34%  and  debt  to  EBITDA  at  0.8x   compared  with  37%  and  0.9x,
    respectively, at the end of Q1/05.

o   Quarterly production volumes 6% higher than Q1/05.

o   North America  natural gas production in Q1/06 increased 1% over Q4/05 but
    decreased  1% from Q1/05  reflecting  the impact of the delays in the 2006
    winter drilling  program where more wells were drilled later in the season
    than originally planned.

o   Completed  a record  first  quarter  drilling  program  of 593 net  wells,
    excluding  stratigraphic test and service wells, with a 90% success ratio,
    reflecting Canadian Natural's strong, predictable, low-risk asset base.

o   Maintained our strong undeveloped conventional land base in Canada of 11.0
    million net acres - a key asset in today's highly competitive industry.

  2                                       CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

o   Continued  production  improvements at Pelican Lake Field arising from new
    drilling  activity and  expansion  of enhanced  oil  recovery  strategies.
    Pelican Lake crude oil  production  averaged 29 mbbl/d during the quarter,
    up 62% or 11 mbbl/d  from  Q1/05 and up 1 mbbl/d  from  Q4/05.  During the
    quarter,  the Company installed the first two polymer skids as part of the
    commercial polymer flood.

o   Completed  drilling  at East  Espoir  and  are  currently  mobilizing  the
    drilling rig to the West Espoir  tower,  which  targets  production  of 13
    mboe/d later this year.

o   The Development Plan for the Olowi Field was approved by the Government of
    Gabon for this offshore crude oil development  targeting first  production
    in the last quarter of 2008.

o   The Horizon Oil Sands  Project  remained on budget and ahead of  schedule,
    with site preparation and  construction  work benefiting from a warmer and
    drier than normal first quarter.

o   The first  quarter  dividend was increased 25% from $0.06 per common share
    to $0.075  per common  share  commencing  with the April 1, 2006  dividend
    payment.

OPERATIONS REVIEW AND CAPITAL ALLOCATION

In order to facilitate  efficient  operations,  Canadian  Natural  focuses its
activities  into  core  regions  where  it can  dominate  the  land  base  and
infrastructure.  Undeveloped  land  is  critical  to our  ongoing  growth  and
development  within these core regions.  Land  inventories  are  maintained to
enable 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. Further, the Company maintains 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. A large diversified project portfolio enables the effective allocation of
capital to higher return opportunities.

Cost  pressures  and  significant  changes in relative  commodity  prices have
allowed  Canadian  Natural  the  opportunity  to  utilize  its large  drilling
inventory to maximize  value in the short and  long-term.  Natural gas pricing
has  softened  significantly  in early  2006,  whereas  crude oil prices  have
remained strong and heavy crude oil differentials  have narrowed from over 45%
of  WTI  in  the  first  quarter  of  2005  to  the  current  differential  of
approximately  29% of WTI range in Q2/06 resulting in record heavy oil pricing
at the wellhead.

As a result of increased  drilling and completion costs,  Canadian Natural has
made the strategic decision to maintain its planned capital  expenditure level
which will result in a slight  reduction in overall  drilling  activity.  This
reduction will be focused primarily on natural gas activity as a result of the
significant change in relative pricing between crude oil and natural gas.

As a result of this strategic decision,  Canadian Natural will drill 150 fewer
natural gas wells than  originally  planned in 2006,  a 13%  reduction,  while
maintaining  crude oil  drilling  at  planned  2006  levels.  This will  allow
Canadian  Natural  to  maximize  near term  returns  in a high crude oil price
environment,  and  reduce  overall  activity  in a  highly  inflationary  cost
environment.

  CANADIAN NATURAL RESOURCES LIMITED                                       3
==============================================================================
<PAGE>

ACTIVITY BY CORE REGION
<TABLE>
<CAPTION>
                                                               -----------------------------------------------------------
                                                                    NET UNDEVELOPED LAND                 DRILLING ACTIVITY
                                                                                   AS AT                THREE MONTHS ENDED
                                                                            MAR 31, 2006                      MAR 31, 2006
                                                                (THOUSANDS OF NET ACRES)                       (NET WELLS)
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>                                 <C>
Canadian conventional
     Northeast British Columbia                                                    2,040                              192
     Northwest Alberta                                                             1,516                               84
     Northern Plains                                                               6,221                              264
     Southern Plains                                                                 687                               45
     Southeast Saskatchewan                                                           89                                3
--------------------------------------------------------------------------------------------------------------------------
                                                                                  10,553                              588
In Situ Oil Sands                                                                    406                              194
Horizon Oil Sands Project                                                            116                              103
United Kingdom North Sea                                                             352                                2
Offshore West Africa                                                                 207                                3
--------------------------------------------------------------------------------------------------------------------------
                                                                                  11,634                              890
==========================================================================================================================
</TABLE>

DRILLING ACTIVITY (number of wells)
<TABLE>
<CAPTION>
                                                                             Three Months Ended Mar 31
                                                               --------------------------
                                                                      2006                             2005
                                                                   GROSS            NET           Gross             Net
------------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>              <C>             <C>             <C>
Crude oil                                                            106             92             130             109
Natural gas                                                          537            440             380             338
Dry                                                                   65             61              64              56
------------------------------------------------------------------------------------------------------------------------
Subtotal                                                             708            593             574             503
Stratigraphic test / service wells                                   297            297             188             188
------------------------------------------------------------------------------------------------------------------------
Total                                                              1,005            890             762             691
------------------------------------------------------------------------------------------------------------------------
Success rate (excluding stratigraphic test / service wells)                         90%                             89%
========================================================================================================================

NORTH AMERICA NATURAL GAS
                                                                              Quarterly Results
                                                               ------------
                                                                     Q1/06                 Q4/05                  Q1/05
------------------------------------------------------------------------------------------------------------------------
Natural gas production (mmcf/d)                                      1,411                 1,402                  1,430
------------------------------------------------------------------------------------------------------------------------

Net wells targeting natural gas                                        499                   295                    386
Net successful wells drilled                                           440                   279                    338
------------------------------------------------------------------------------------------------------------------------
     Success rate                                                      88%                   95%                    88%
========================================================================================================================
</TABLE>

  4                                       CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

o    Q1/06 natural gas production  represented a 1% increase over the previous
     quarter  despite  warmer  than  normal  weather  influencing  the  winter
     drilling program. As such the Company drilled more wells in March than in
     January. Despite these challenges Canadian Natural completed the majority
     of its winter  drilling  program with a high success rate.  However,  the
     shift in the timing of drilling  from early in the season to later in the
     season significantly delayed tie-ins of many of these new wells.

o    As a result of the back loaded drilling program,  approximately 70 mmcf/d
     of natural gas production remained behind pipe at the end of the quarter.
     Some  locations  will be  tied-in  during  the  second,  third and fourth
     quarters,  however it is estimated that 20-30 mmcf/d will remain stranded
     until freeze up in late Q4/06 or early Q1/07.

o    High success  rates  reflect  Canadian  Natural's  low-risk  exploitation
     approach  and  high  quality  land  base.  The  Q1/06  drilling   program
     represented  an active  program  across the Company's  core  regions.  In
     Northeast  British  Columbia  191 net wells  targeting  natural  gas were
     drilled, while in Northwest Alberta 80 net wells were drilled,  including
     37 Cardium  targets.  In Northern and Southern Plains, a total of 26 coal
     bed methane,  23 shallow natural gas and 179  conventional net wells were
     drilled.

o    The results of our Q1 natural gas  program met  expectations  in terms of
     reserve and rate  expectations,  and were within our  economic  criteria.
     However,  with service costs continuing to escalate and relatively strong
     crude oil prices compared to natural gas prices, the Company has made the
     strategic decision to drill 150 fewer (13% less than originally  planned)
     natural gas wells in 2006.

o    This reduction in planned drilling activity and the delays in getting our
     Q1/06  drilling  program tied in have  resulted in a small  adjustment of
     less  than 2% to the mid  point  of our  annual  corporate  guidance  for
     natural gas production volumes reflecting the strength and quality of our
     natural gas drilling program.

o    Planned  drilling  activity  for the second  quarter of 2006  includes 66
     wells targeting natural gas.


NORTH AMERICA CRUDE OIL AND NGLS
<TABLE>
<CAPTION>
                                                                                  Quarterly Results
                                                                  -------------
                                                                         Q1/06               Q4/05                Q1/05
------------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>                 <C>                  <C>
Crude oil and NGLs production (bbl/d)                                  222,955             230,263              209,125
------------------------------------------------------------------------------------------------------------------------

Net wells targeting crude oil                                               90                 191                  114
Net successful wells drilled                                                88                 185                  106
------------------------------------------------------------------------------------------------------------------------
     Success rate                                                          98%                 97%                  93%
========================================================================================================================
</TABLE>

o    During the quarter,  drilling  activity included 33 wells targeting heavy
     crude oil and 15 wells  targeting  light crude oil.  The  majority of the
     wells, 79 of 90 net wells,  targeting crude oil during Q1/06 were drilled
     in the Northern  Plains core region.

o    The  Primrose  Field  development  continued  with the drilling of 20 net
     wells in Q1/06.  Production  from the pads at  Primrose is subject to the
     cycling  of steam  injection  and  crude  oil  production.  Due to normal
     cycling activities as well as the addition of new well pads from Primrose
     North, average thermal crude oil production levels in Q1/06 were 8 mbbl/d
     or 14% lower than Q4/05 but slightly better than originally  anticipated.
     Production  volumes are expected to increase in Q2/06 and will ramp up to
     approximately  75 mbbl/d in Q3/06  resulting in peak  production from the
     area as the crude oil processing plant approaches its design capacity.

o    The Primrose East  expansion  program  continues  through the  regulatory
     phase  and,  if  approved,  will  see  the  expansion  of the  crude  oil
     processing  facility  from 80  mbbl/d  to 120  mbbl/d  ,as well  as,  the
     construction of a steam  generation plant and new pad drilling which will
     add production gains targeted at 30 mbbl/d in 2009.

  CANADIAN NATURAL RESOURCES LIMITED                                       5
==============================================================================
<PAGE>

o    At Pelican Lake the  development  of new acreage and  secondary  recovery
     conversion  projects  continued  as  planned.  Drilling  consisted  of 22
     horizontal  producing wells, 13 stratigraphic wells and four water source
     wells.  During  the  remainder  of 2006,  the  Company  plans to drill an
     additional 117 wells at Pelican Lake. Production increased from 28 mbbl/d
     in Q4/05 to 29 mbbl/d in Q1/06. The North Brintnell waterflood conversion
     project  was  expanded  by 744  acres.  Pressure  response  data from the
     polymer  flood  pilot  remains  on track with  expectations.  Also at the
     project, Canadian Natural commenced installation of the first two polymer
     skids as part of the commercial polymer flood project.

o    Planned  drilling  activity for the second quarter  includes 87 net crude
     oil wells.

CANADIAN NATURAL UPGRADER PROJECT

Originally  announced in the fall of 2005,  the Company  remains on track with
its plans to design, construct and operate a heavy oil upgrader to process its
conventional  heavy and thermal heavy crude oil production.  The Scoping Study
for the Canadian Natural Upgrader was initiated during the quarter.  The terms
of reference for this study will evaluate end product alternatives,  location,
technology, gasification and integration with existing assets. Recommendations
are expected in late 2006 / early 2007 and  represent the first stage of front
end loading for the project. This is the same disciplined approach utilized in
the Horizon  Project.  Following this Study,  the Design Basis  Memorandum and
Engineering  Design  Specification will be completed prior to construction and
sanctioning of the project by the Board of Directors.

This  upgrader  is  expected  to enable  the  Company  to  unlock  significant
shareholder  value  through the  development  and  upgrading of over 3 billion
barrels of thermal  in-situ oil sands  resources  over the next 15 years.  The
project  is  expected  to be  undertaken  in two phases  with the first  phase
targeting  upgrading  capacity  of 125  mbbl/d of SCO with a current  forecast
start-up date in 2012.


INTERNATIONAL

The  Company  operates  in the  North  Sea  and  Offshore  West  Africa  where
production of lighter  quality  crude oil is targeted,  but natural gas may be
produced in association with crude oil production.

<TABLE>
<CAPTION>
                                                                                    Quarterly Results
                                                                   --------------
                                                                           Q1/06              Q4/05               Q1/05
------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>                <C>                  <C>
Total crude oil production (bbl/d)
     North Sea                                                            60,802             66,798              71,139
     Offshore West Africa                                                 39,905             43,207               7,539
------------------------------------------------------------------------------------------------------------------------
Total natural gas production (mmcf/d)
     North Sea                                                                17                 15                  23
     Offshore West Africa                                                      8                  6                   2
------------------------------------------------------------------------------------------------------------------------
Net wells targeting crude oil                                                4.2                5.9                 2.9
Net successful wells drilled                                                 4.2                5.0                 2.3
------------------------------------------------------------------------------------------------------------------------
     Success rate                                                           100%                85%                 79%
========================================================================================================================
</TABLE>

NORTH SEA

o    Canadian Natural  continues to execute its  exploitation  strategy in the
     North Sea.  The first  stage of this  exploitation  program is based upon
     optimizing   existing   facilities  and  waterfloods.   Canadian  Natural
     continues  to apply this first stage of  exploitation  on its holdings in
     the North Sea. The second stage of  exploitation  incorporates  more near
     pool development and exploration in order to maximize  utilization of the
     common  facilities and ultimately  extend all fields'  economic lives. In
     2006 and beyond, increasing emphasis on this type of work is evidenced by
     the ongoing development at the Columba Terraces and the Lyell Field.

  6                                       CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

o    During  Q1/06,  2.8 net wells,  including 0.9 net water  injectors,  were
     drilled  with an  additional  3.9 net wells  drilling  over  quarter end.
     Production  levels were in line with expectations and reflected growth at
     Columba D Terrace and Ninian Field and expected temporary curtailments at
     the  Lyell  Field  and  the  Columba  E  Terrace  as  well  as  temporary
     restrictions at B-Block and Playfair Fields.

o    The prolific  new well  drilled  into the Columba D Terrace  during Q4/05
     declined  in line  with  expectation.  In  February,  additional  pay was
     perforated in this well which yielded a 6 mbbl/d initial  uplift,  net to
     Canadian  Natural,  and  a  water  injector  to  support  this  developed
     production  was  completed  during the quarter.  At quarter end, an early
     positive waterflood re-pressuring response was observed.

o    On the  Ninian  Field,  the  platform  rig  completed  a  Ninian  Central
     producer,  which was brought onstream towards the end of the quarter at a
     rate of 8.7 mbbl/d, net to Canadian Natural.

o    Construction  of the  subsea  water  injection  pump at Columba E Terrace
     progressed during the quarter. This will be tied into 2 additional subsea
     water   injection   wells  that  will  be  drilled  late  in  2006.  This
     repressurization  of the pool,  combined with artificial lift will result
     in increased productive capacity from the existing long reach wells.

o    Plans for the further  development of the Lyell Field  progressed,  which
     entails  drilling 4 net wells and  working  over 2 existing  net wells in
     2006/7.  At its plateau,  new  production of  approximately  20 mboe/d is
     forecast from this field.

OFFSHORE WEST AFRICA

o    During Q1/06, 2.3 net wells were drilled with an additional 0.6 net wells
     drilling over quarter end.  Production  levels were ahead of expectation,
     primarily due to early  delivery of planned wells at both Baobab and East
     Espoir.  Some  curtailment of production was  experienced  due to planned
     outages to tie these wells in.

o    At Baobab, peak crude oil production reached 52 mbbl/d (33 mmbbl/d net to
     Canadian  Natural)  during  the  quarter  and  averaged  25 mbbl/d net to
     Canadian  Natural.  The eighth  production  well  continues to experience
     production restrictions due to limitations resulting from monitoring sand
     screen effectiveness.  During the first quarter two additional production
     wells were  drilled  resulting  in an initial  uplift of 10 mbbl/d net to
     Canadian Natural. Production is expected to remain constant at Q1 average
     levels  until the sand screen  effectiveness  issues are  resolved on the
     eighth producer and as cleanup continues on the new wells.

o    Net  production  at East Espoir was in line with Q4/05,  and  averaged 15
     mboe/d during Q1/06  following the build-up of production from the infill
     drilling program.  The infill drilling program consisted of 4 wells, with
     the 2 remaining wells now completed and the field currently  producing at
     a record level of 20 mbbl/d, net to Canadian Natural.

o    At Espoir, drilling is now complete on the East Espoir Field with the rig
     being  moved from East Espoir  tower to the West Espoir  tower in Q2. The
     West Espoir project  continues on time and on budget with first crude oil
     production  expected in the second half of 2006,  ramping up to 13 mboe/d
     when fully developed. During the quarter, the West Espoir drilling tower,
     which  will  facilitate  development  drilling  of  this  reservoir,  was
     installed and the drilling conductors were driven to depth.

o    Following the review of 3-D seismic previously  acquired on Block CI-400,
     located offshore Cote d'Ivoire, the Company has relinquished its rights.

o    In Gabon, a development plan comprising a Floating Production Storage and
     Offtake Vessel and four drilling towers was approved for execution by the
     Government in the first quarter of 2006.  The  development is expected to
     commence  in late 2006 with first  production  targeted  for late 2008 to
     reach a plateau rate of 20 mbbl/d. The permit comprises a 90% interest in
     the  production  sharing  agreement  for the block  containing  the Olowi
     Field,  located  about 20  kilometres  from the Gabonese  coast and in 30
     metres water depth. Olowi has been delineated by the drilling of 15 wells
     on the block and  potentially  contains as much as 500 million barrels of
     34(0) API light crude oil originally in place. The crude oil reservoir is
     overlain by a large gas cap with  potentially  one trillion cubic feet of
     gas originally in place.

  CANADIAN NATURAL RESOURCES LIMITED                                       7
==============================================================================
<PAGE>

HORIZON OIL SANDS PROJECT ("HORIZON PROJECT")

o    Phase 1 of the Horizon  Project  continues  on plan and on budget.  First
     production of 110 mbbl/d of light, sweet Synthetic Crude Oil from Phase 1
     construction  is  targeted  to  commence  in the  second  half  of  2008.
     Production is targeted to increase to 155 mbbl/d following  completion of
     Phase 2 in 2010.  Production  levels of 232 mbbl/d are targeted for 2012,
     following  completion of Phase 3  construction.  The Company is currently
     evaluating the  opportunity to combine Phase 2 and 3 for a targeted joint
     operational date of 2011.

o    As a result of the mild winter  weather  conditions  experienced in early
     2006,  the  progress on major  milestones,  a key  component in achieving
     critical path success, are slightly ahead of schedule.

o    The high degree of up front  project  engineering  and  pre-planning  has
     reduced the risks on "cost-plus" aspects of the project and will mitigate
     the risk of scope  changes on the fixed bid portions  (targeted at 68% of
     Phase 1 costs). The pre-engineering and lessons learned from predecessors
     have also  enabled  the  Company to prepare a  detailed  development  and
     logistical  plan  to  reduce  the  scheduling  risk.  Geological  risk is
     considered  low on the  Company's  mining  leases as over 16  delineation
     wells have been drilled per section with over 40 wells per section having
     been  drilled  on the  south  pit,  which  will be the first to be mined.
     Finally,  technology  risk is low as the Company is using existing proven
     technologies for mining, extraction and upgrading processes.

o    Construction  capital  costs  for  Phase  1 of the  Horizon  Project  are
     budgeted at $6.8 billion,  including a contingency  fund of $700 million,
     with $1.9 billion spent to date, $2.0 billion  targeted to be incurred in
     the  remainder of 2006 and $2.9  billion  targeted to be incurred in 2007
     and 2008.

o    During the first quarter of 2006,  major  milestones were achieved sooner
     than  expected  and safety  performance  remained  ahead of  target.  The
     placement  of  the  four  coke  drums,  each  weighing  400  tonnes,  was
     completed. The first piperack modules were also placed on foundations and
     we  continue to place  additional  modules on an ongoing  basis.  The new
     40m(3) hydraulic shovel is being  commissioned and sufficient  overburden
     is expected to be removed to enable the start of  construction of the Ore
     Preparation Plant during the second quarter.

o    The quarterly update for the project is as follows:


PROJECT STATUS SUMMARY

<TABLE>
<CAPTION>
                                                                     ----------------------
                                                                        MAR 31, 2006           Jun 30, 2006
                                                                       ACTUAL          Plan            Plan
    --------------------------------------------------------------------------------------------------------
    <S>                                                                   <C>           <C>             <C>
    Phase 1 - Work progress (cumulative)                                  26%           22%             31%
    Phase 1 - Construction capital spending (cumulative)                  27%           29%             39%
    ========================================================================================================
</TABLE>

ACCOMPLISHED DURING THE FIRST QUARTER

DETAILED ENGINEERING

     --   Completed 60% of detailed engineering model reviews in all areas.

     --   Completed  hazard and  operability  reviews for all plants,  a major
          hurdle to ensure scope changes are not required.

PROCUREMENT

     --   Awarded in excess of C$200 million of contracts and purchase  orders
          in the quarter bringing  awards-to-date to over C$4 billion,  with a
          further C$600 million in various stages of the tender process.

     --   Awarded key Mechanical contracts for Bitumen Production.

     --   Completed  "Contractor Open House" sessions across Canada to attract
          new contractors and skilled trades people to the oil sands industry.
          Over 300 contractors participated in these sessions.

     --   Completed transport of naphtha reactor to site from the rail staging
          area south of Fort McMurray.

     --   Site  assembly  of gas oil and  distillate  reactors  on  track  for
          completion in the fourth quarter.

     --   Issued purchase orders for long lead equipment (cokers and reactors)
          for Phase 2 and 3 upgrading.

  8                                       CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

MODULARIZATION

     --   Delivered 164 oversized  loads to site, out of  approximately  1,500
          total loads to be delivered during the construction period.

CONSTRUCTION

     --   Site safety performance remains ahead of benchmarked targets.

     --   Delivered  four  coke  drums  to  site as  planned  and  erected  on
          schedule.

     --   Started setting of piperack modules on foundations.

     --   Commissioned  operation of permanent water and waste water treatment
          plants.

     --   Main administration  building,  security building, plant maintenance
          shop and fire hall were completed and occupied.

     --   Mine  overburden  removal  has moved 10.8  million  bcm (bank  cubic
          meters) compared to a plan of 10.4 million bcm with commissioning of
          a new 40m(3) hydraulic shovel planned for the second quarter.

     --   Completed 98% of site preparation and undergrounds.

SECOND QUARTER 2006 MILESTONES

     --   Overall detailed engineering to surpass 80% completion.

     --   Occupancy of the second of three camps.

     --   New 40m(3) shovel  expected to be in operation  for mine  overburden
          removal.

     --   Occupation  of  Mine  Overburden   Administration   and  Maintenance
          Facility to take place.

     --   Ore Preparation Plant site turnover by Mining to Bitumen Production.

MARKETING

<TABLE>
<CAPTION>
                                                                                              Quarterly Results
                                                                     -----------------
                                                                                Q1/06             Q4/05              Q1/05
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>                <C>               <C>
Crude oil and NGLs pricing
     WTI(1) benchmark price (US$/bbl)                                  $        63.53     $       60.04     $        49.90
     Lloyd Blend Heavy oil differential from WTI (%)                              45%               40%                39%
     Corporate average pricing before risk management (C$/bbl)         $        43.79     $       46.38     $        39.81
---------------------------------------------------------------------------------------------------------------------------
Natural gas pricing
     AECO benchmark price (C$/GJ)                                      $         8.82     $       11.07     $         6.35
     Corporate average pricing before risk management (C$/mcf)         $         8.30     $       11.67     $         6.68
===========================================================================================================================
</TABLE>
(1) REFERS TO WEST TEXAS INTERMEDIATE CRUDE OIL BARREL PRICED AT CUSHING,
    OKLAHOMA.

o    Despite  having  averaged  45% of  WTI  during  Q1/06,  heavy  crude  oil
     differentials   have  narrowed   significantly   in  the  second  quarter
     coincident with the reversal of the Corsicana and Spearhead Pipelines,  a
     third  party  outage,  as well as the  start  of the high  demand  paving
     season.  The Company has committed to 25 mbbl/d of new pipeline  capacity
     on the reversal of the Corsicana  Pipeline  which carries heavy crude oil
     from the terminus of the current pipeline sales lines at Patoka, Illinois
     to the east Texas  refining  complex near  Nederland.  This  pipeline was
     commissioned in late March with Canadian Natural's first sales deliveries
     reaching Nederland on April 6, 2006.

o    During the first  quarter,  the  Company  contributed  approximately  156
     mbbl/d of its heavy  crude oil  streams to the  Western  Canadian  Select
     ("WCS") blend as market conditions resulted in this strategy offering the
     optimal pricing for bitumen.

  CANADIAN NATURAL RESOURCES LIMITED                                       9
==============================================================================
<PAGE>

o    The price for  natural  gas was 20% lower than in the  previous  quarter,
     reflecting the warmest month of January on record for North America.  The
     demand in the first quarter was  unusually  weak,  which  resulted in the
     highest gas  inventory  position at the end of March since 1991.  Weather
     and relative  value to crude oil pricing will greatly  impact the pricing
     level over the next several months.

FINANCIAL REVIEW

o    Canadian  Natural has structured its financial  position so as to be able
     to profitably grow its conventional  crude oil and natural gas operations
     over the next  several  years  and to build  the  financial  capacity  to
     complete the Horizon Project and other major projects. A brief summary of
     its strengths are:

     --  A diverse  asset  base  geographically  and by  product  -  currently
         producing  in excess of 590 mboe/d,  comprised of  approximately  43%
         natural gas and 57% crude oil - with 93% of production  located in G7
         countries with stable and secure economies.

     --  Financial  stability  and  liquidity  - $3.5  billion of bank  credit
         facilities,  of which, Canadian Natural had in aggregate $2.7 billion
         of unused bank lines available at March 31, 2006.

     --  Strong  balance sheet - with a debt to book  capitalization  ratio of
         34%,  debt to  cash  flow  of  0.9x,  debt  to  EBITDA  of  0.8x  and
         shareholders' equity of $8.3 billion.

o    In January 2005,  the Board of Directors  authorized the expansion of the
     Company's  commodity  hedging program to reduce the risk of volatility in
     commodity  price markets and to support the  Company's  cash flow for its
     capital expenditure  program throughout the Horizon Project  construction
     period.  This expanded program allows for the hedging of up to 75% of the
     near 12 months budgeted  production,  up to 50% of the following 13 to 24
     months  estimated  production  and up to 25% of  production  expected  in
     months 25 to 48 through the use of derivative financial instruments.  For
     the purpose of this program,  the purchase of crude oil put options is in
     addition  to the  above  parameters.  As a result,  approximately  75% of
     budgeted  2006 crude oil volumes and  approximately  55% of budgeted 2006
     natural gas volumes  have been hedged  through the use of collars for the
     remainder of 2006. Details of current hedge positions may be found on the
     Company's website at:
     http://www.cnrl.com/investor_info/corporate_guidance/hedging.html.

o    As effective as economic hedges are against reference commodity prices, a
     substantial  portion of the  financial  instruments  entered  into by the
     Company do not meet the  requirements for hedge accounting under GAAP due
     to   currency,   product   quality  and   location   differentials   (the
     "non-designated hedges"). The Company is required to mark-to-market these
     non-designated  hedges based on prevailing  forward  commodity  prices in
     effect at the end of each reporting period.  Accordingly,  the unrealized
     risk management liability reflects,  at March 31, 2006, the implied price
     differentials for the non-designated hedges in 2006 and future years. Due
     to the changes in crude oil and natural gas forward pricing,  the Company
     recorded a net $8 million ($5 million after tax)  unrealized  loss on its
     risk  management  activities  for the three  months ended March 31, 2006.
     Mark-to-market  unrealized  gains and losses do not impact the  Company's
     current cash flow or its ability to finance ongoing capital programs. The
     Company  continues to believe that its risk management  program meets its
     objective  of  securing  funding for its  capital  projects  and does not
     intend to alter its current strategy of obtaining price certainty for its
     crude oil and natural gas production.

o    Effective  January 1, 2006,  the UK government  substantively  enacted an
     increase to the  supplementary  charge on profits from UK North Sea crude
     oil and natural gas production from 10% to 20%,  increasing the Company's
     effective  income  tax rate in the North Sea to  approximately  50%.  The
     supplementary  charge  excludes any deduction for  financing  costs.  The
     Company's  opening  future  income tax  liability  was  increased by $110
     million as at January 1, 2006, with respect to this tax rate change.

o    The Normal Course Issuer Bid has been extended to January 2007,  allowing
     for the repurchase of up to 26.9 million shares through the facilities of
     the Toronto Stock Exchange and the New York Stock  Exchange.  To date, no
     common shares have been repurchased under this program.

o    In January 2006, Canadian Natural issued C$400 million of 7-year notes at
     a rate of 4.50%

o    In  February  2006,  the Board of  Directors  approved an increase in the
     quarterly  dividend  to $0.075  per  common  share  from $0.06 per common
     share.  The 25% increase  recognizes the stability of Canadian  Natural's
     cash flow and  provides  a further  return to  shareholders.  This is the
     sixth  consecutive  year in which the Company has paid a dividend and the
     fifth  consecutive  year  of  increase  in the  distribution  paid to its
     shareholders.  The increased dividend became effective with the quarterly
     payment paid on April 1, 2006.

  10                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

Q2/06 OUTLOOK

The Company has revised its annual production guidance and currently expects
2006 production levels before royalties to average 1,448 to 1,516 mmcf/d of
natural gas and 338 to 370 mbbl/d of crude oil and NGLs. Q2/06 production
guidance before royalties is 1,461 to 1,520 mmcf/d of natural gas and 326 to
348 mbbl/d of crude oil and NGLs.

Detailed guidance on revised production levels, capital allocation and
operating costs can be found on the Company's website at
http://www.cnrl.com/investor_info/corporate_guidance/. Commodity hedge
information is regularly updated and may similarly be found at
http://www.cnrl.com/investor_info/corporate_guidance/hedging.html.





  CANADIAN NATURAL RESOURCES LIMITED                                       11
==============================================================================
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS


Management's  Discussion and Analysis ("MD&A") of the financial  condition and
results of operations of Canadian Natural  Resources  Limited (the "Company"),
should  be  read  in  conjunction  with  the  unaudited  interim  consolidated
financial  statements  for the three  months ended March 31, 2006 and the MD&A
and the audited consolidated  financial statements for the year ended December
31, 2005.

All dollar  amounts are  referenced  in millions of Canadian  dollars,  except
where  noted  otherwise.  The  financial  statements  have  been  prepared  in
accordance with Canadian generally accepted  accounting  principles  ("GAAP").
MD&A includes  references to financial measures commonly used in the crude oil
and natural gas industry, such as adjusted net earnings from operations,  cash
flow from  operations,  and  EBITDA  (net  earnings  before  interest,  taxes,
depreciation,   depletion  and  amortization,   asset  retirement   obligation
accretion,  unrealized foreign exchange,  stock-based compensation expense and
unrealized  risk  management  activities).  These  financial  measures are not
defined by 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  GAAP,  as an  indication  of  the  Company's
performance.  The measures adjusted net earnings from operation, and cash flow
from  operations are reconciled to net earnings in the "Financial  Highlights"
section.

Certain prior period amounts have been  reclassified to enable comparison with
the current period's presentation.

The calculation of barrels of oil equivalent  ("boe") is based on a conversion
ratio of six thousand  cubic feet ("mcf") of natural gas to one barrel ("bbl")
of crude oil to estimate  relative  energy  content.  This  conversion  may be
misleading,  particularly when used in isolation,  since the 6 mcf:1 bbl ratio
is based on an energy equivalency at the burner tip and does not represent the
value equivalency at the well head.

Production volumes are presented throughout this MD&A on a "before royalty" or
"gross"  basis,  and  realized  prices  exclude the effect of risk  management
activities,  except  where noted  otherwise.  Production  net of  royalties is
presented for information purposes only.

The following  discussion refers primarily to the Company's  financial results
for the three months ended March 31, 2006 in relation to the first  quarter of
2005 and the prior quarter.  The accompanying  tables form an integral part of
this MD&A. This MD&A is dated May 3, 2006.


  12                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
<TABLE>
<CAPTION>
                                                                              Three Months Ended
                                                       ---------------------
                                                                  MAR 31                 Dec 31               Mar 31
                                                                    2006                   2005               2005(1)
---------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                   <C>                    <C>
Revenue, before royalties                              $           2,372     $            3,032     $          1,993
Net earnings (loss)                                    $              57     $            1,104     $           (424)
   Per common share        - basic                     $            0.11     $             2.06     $          (0.79)
                           - diluted                   $            0.11     $             2.06     $          (0.79)
Adjusted net earnings from operations(2)               $             268     $              601     $            380
   Per common share        - basic                     $            0.50     $             1.12     $           0.71
                           - diluted                   $            0.50     $             1.12     $           0.71
Cash flow from operations(3)                           $           1,039     $            1,490     $          1,009
   Per common share        - basic                     $            1.93     $             2.78     $           1.88
                           - diluted                   $            1.93     $             2.78     $           1.88
Capital expenditures, net of dispositions              $           2,309     $            1,679     $          1,372
=====================================================================================================================
</TABLE>
(1)  RESTATED TO REFLECT A TWO-FOR-ONE COMMON SHARE SPLIT IN MAY 2005.
(2)  ADJUSTED NET EARNINGS FROM  OPERATIONS IS A NON-GAAP TERM THAT REPRESENTS
     NET EARNINGS ADJUSTED FOR CERTAIN ITEMS OF A NON- OPERATIONAL NATURE. THE
     COMPANY  EVALUATES  ITS  PERFORMANCE  BASED ON ADJUSTED NET EARNINGS FROM
     OPERATIONS.  THE FOLLOWING  RECONCILIATION LISTS THE AFTER-TAX EFFECTS OF
     CERTAIN  ITEMS  OF A  NON-OPERATIONAL  NATURE  THAT ARE  INCLUDED  IN THE
     COMPANY'S  FINANCIAL  RESULTS.  ADJUSTED NET EARNINGS FROM OPERATIONS MAY
     NOT BE COMPARABLE TO SIMILAR MEASURES PRESENTED BY OTHER COMPANIES.

<TABLE>
<CAPTION>
                                                                                         THREE MONTHS ENDED
                                                       --------------------
                                                                 MAR 31                  DEC 31               MAR 31
($ MILLIONS)                                                       2006                    2005                 2005
---------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                   <C>                    <C>
NET EARNINGS (LOSS) AS REPORTED                        $             57      $            1,104     $           (424)
STOCK-BASED COMPENSATION, NET OF TAX(A)                              88                      75                  125
UNREALIZED RISK MANAGEMENT LOSS (GAIN), NET OF TAX(B)                 5                    (583)                 679
UNREALIZED FOREIGN EXCHANGE LOSS, NET OF TAX(C)                       8                       5                    -
EFFECT OF STATUTORY TAX RATE CHANGES ON FUTURE INCOME
TAX LIABILITIES(D)                                                  110                       -                    -
---------------------------------------------------------------------------------------------------------------------
ADJUSTED NET EARNINGS FROM OPERATIONS                  $            268      $              601     $            380
=====================================================================================================================
</TABLE>
(A)  THE  COMPANY'S  EMPLOYEE  STOCK  OPTION PLAN  PROVIDES FOR A CASH PAYMENT
     OPTION.  ACCORDINGLY,  THE  INTRINSIC  VALUE  OF THE  OUTSTANDING  VESTED
     OPTIONS IS RECORDED AS A LIABILITY  ON THE  COMPANY'S  BALANCE  SHEET AND
     PERIODIC CHANGES IN THE INTRINSIC  VALUE, NET OF TAXES,  FLOW THROUGH NET
     EARNINGS, OR ARE CAPITALIZED TO THE HORIZON OIL SANDS PROJECT.

(B)  FINANCIAL INSTRUMENTS NOT DESIGNATED AS HEDGES ARE RECORDED AT FAIR VALUE
     ON THE BALANCE SHEET,  WITH CHANGES IN FAIR VALUE, NET OF TAXES,  FLOWING
     THROUGH NET EARNINGS.  THE AMOUNTS ULTIMATELY  REALIZED MAY BE MATERIALLY
     DIFFERENT  THAN  REFLECTED IN THE FINANCIAL  STATEMENTS DUE TO CHANGES IN
     PRICES OF THE UNDERLYING  ITEMS HEDGED,  PRIMARILY  CRUDE OIL AND NATURAL
     GAS.

(C)  UNREALIZED  FOREIGN  EXCHANGE GAINS AND LOSSES RESULT  PRIMARILY FROM THE
     TRANSLATION  OF  US  DOLLAR  DENOMINATED  LONG-TERM  DEBT  TO  PERIOD-END
     EXCHANGE RATES AND ARE IMMEDIATELY RECOGNIZED IN NET EARNINGS.

(D)  ALL SUBSTANTIVELY  ENACTED ADJUSTMENTS IN APPLICABLE INCOME TAX RATES ARE
     APPLIED TO UNDERLYING  ASSETS AND  LIABILITIES  ON THE COMPANY'S  BALANCE
     SHEET IN DETERMINING  ITS FUTURE INCOME TAX ASSETS AND  LIABILITIES.  THE
     IMPACT OF THE TAX RATE CHANGES ARE RECORDED IN NET EARNINGS IN THE PERIOD
     THE LEGISLATION IS SUBSTANTIVELY ENACTED.  EFFECTIVE JANUARY 1, 2006, THE
     UK  GOVERNMENT  SUBSTANTIVELY  ENACTED AN INCREASE  TO THE  SUPPLEMENTARY
     CHARGE ON PROFITS FROM UK NORTH SEA CRUDE OIL AND NATURAL GAS  PRODUCTION
     FROM 10% TO 20%,  INCREASING THE COMPANY'S  EFFECTIVE  INCOME TAX RATE IN
     THE NORTH SEA TO APPROXIMATELY 50%. THE SUPPLEMENTARY CHARGE EXCLUDES ANY
     DEDUCTION FOR FINANCING  COSTS. THE COMPANY'S FUTURE INCOME TAX LIABILITY
     WAS INCREASED BY $110 MILLION WITH RESPECT TO THIS TAX RATE CHANGE.

  CANADIAN NATURAL RESOURCES LIMITED                                       13
==============================================================================
<PAGE>

(3)  CASH FLOW FROM OPERATIONS IS A NON-GAAP TERM THAT REPRESENTS NET EARNINGS
     ADJUSTED FOR NON-CASH ITEMS. THE COMPANY  EVALUATES ITS PERFORMANCE BASED
     ON CASH  FLOW  FROM  OPERATIONS.  THE  COMPANY  CONSIDERS  CASH FLOW FROM
     OPERATIONS  A KEY MEASURE AS IT  DEMONSTRATES  THE  COMPANY'S  ABILITY TO
     GENERATE THE CASH FLOW  NECESSARY TO FUND FUTURE GROWTH  THROUGH  CAPITAL
     INVESTMENT  AND TO REPAY  DEBT.  CASH  FLOW  FROM  OPERATIONS  MAY NOT BE
     COMPARABLE TO SIMILAR MEASURES PRESENTED BY OTHER COMPANIES.

<TABLE>
<CAPTION>
                                                                        THREE MONTHS ENDED
                                                       --------------
                                                           MAR 31           DEC 31            MAR 31
($ MILLIONS)                                                 2006             2005              2005
-----------------------------------------------------------------------------------------------------
<S>                                                         <C>       <C>               <C>
NET EARNINGS (LOSS)                                   $        57     $      1,104      $       (424)
NON-CASH ITEMS:
   DEPLETION, DEPRECIATION AND AMORTIZATION                   521              550               474
   ASSET RETIREMENT OBLIGATION ACCRETION                       17               16                18
   STOCK-BASED COMPENSATION                                   132              125               184
   UNREALIZED RISK MANAGEMENT ACTIVITIES                        8             (825)              998
   UNREALIZED FOREIGN EXCHANGE LOSS                            10                5                 -
   DEFERRED PETROLEUM REVENUE TAX                              26                1                 -
   FUTURE INCOME TAX EXPENSE (RECOVERY)                       268              514              (241)
-----------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS                             $     1,039     $      1,490      $      1,009
=====================================================================================================
</TABLE>


SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS

For the three months ended March 31, 2006,  the Company  reported net earnings
of $57  million  compared to a net loss of $424  million for the three  months
ended March 31, 2005 and net  earnings of $1,104  million for the three months
ended  December  31,  2005.  Net earnings for the three months ended March 31,
2006 included  unrealized  after-tax  expenses of $211 million  related to the
effects of a UK statutory  tax rate change on future  income tax  liabilities,
stock-based  compensation expense, foreign exchange losses and risk management
activities.  This compared to $804 million of net  after-tax  expenses for the
three months ended March 31, 2005 and $503 million of net after-tax income for
the three months ended December 31, 2005. Excluding these items,  adjusted net
earnings from  operations  for the three months ended March 31, 2006 decreased
by 29% to $268  million from $380 million for the three months ended March 31,
2005, primarily due to higher realized losses from risk management  activities
that  offset  higher  realized  crude  oil  and  natural  gas  pricing  net of
differentials  and a stronger  Canadian  dollar.  Adjusted net  earnings  from
operations  decreased  by 55% from $601  million  for the three  months  ended
December 31, 2005,  primarily  due to lower  realized  crude oil prices net of
differentials and lower realized natural gas prices.

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

The Board of Directors  authorized  the expansion of the  Company's  commodity
hedging  program to reduce the risk of volatility  in commodity  price markets
and to support the  Company's  cash flow for its capital  expenditure  program
throughout  the Horizon Oil Sands  Project  ("Horizon  Project")  construction
period.  This expanded program allows for the hedging of up to 75% of the near
12 months  budgeted  production,  up to 50% of the  following  13 to 24 months
estimated  production and up to 25% of production  expected in months 25 to 48
through the use of derivative financial  instruments.  For the purpose of this
program,  the  purchase  of crude oil put  options is in addition to the above
parameters.  As a result,  approximately 75% of budgeted crude oil volumes and
approximately 55% of budgeted natural gas volumes have been hedged through the
use of collars for the remainder of 2006.

  14                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

As effective as the Company's hedges are against reference commodity prices, a
substantial  portion of the derivative  financial  instruments entered into by
the Company do not meet the  requirements  for hedge accounting under GAAP due
to currency,  product quality and location  differentials (the "non-designated
hedges").  The  Company is  required to  mark-to-market  these  non-designated
hedges based on prevailing  forward  commodity  prices in effect at the end of
each reporting period.  Accordingly,  the unrealized risk management liability
reflects,  at  March  31,  2006,  the  implied  price  differentials  for  the
non-designated  hedges for future periods.  The cash settlement  amount of the
risk management financial derivative instruments may vary materially depending
upon the  underlying  crude oil and  natural  gas  prices at the time of final
settlement  of the  financial  derivative  instruments,  as  compared to their
mark-to-market value at March 31, 2006.

Due to the changes in crude oil and natural gas forward  pricing,  the Company
recorded a net $8 million ($5 million  after-tax)  unrealized loss on its risk
management   activities   for  the  three   months   ended  March  31,   2006.
Mark-to-market unrealized gains and losses do not impact the Company's current
cash flow or its  ability to finance  ongoing  capital  programs.  The Company
continues to believe that its risk  management  program meets its objective of
securing  funding  for its capital  projects  and does not intend to alter its
current  strategy of obtaining  price  certainty for its crude oil and natural
gas production.

The Company also recorded a $132 million ($88 million  after-tax)  stock-based
compensation  expense for the three months ended March 31, 2006 in  connection
with the 13%  appreciation  in the  Company's  share  price  during  the first
quarter  of 2006  (Company's  share  price as at:  March 31,  2006 -  C$64.90;
December 31, 2005 - C$57.63;  March 31, 2005 - C$34.18).  As required by GAAP,
the Company  records a liability  for  potential  cash  payments to settle its
outstanding  employee  stock  options,  based on the  difference  between  the
exercise  price of the stock  options  and the market  price of the  Company's
common  shares,  pursuant  to a graded  vesting  schedule.  The  liability  is
revalued  each  quarter to  reflect  the  changes  in the market  price of the
Company's  common  shares and the  options  exercised  or  surrendered  in the
period, with the net change recognized in earnings,  or capitalized during the
construction  period  in the  case of the  Horizon  Project.  The  stock-based
compensation  liability reflects the Company's potential cash liability should
all the vested options be surrendered for a cash payout at the market price on
March 31, 2006. In periods when  substantial  stock price changes  occur,  the
Company's  net earnings  are subject to  significant  volatility.  The Company
utilizes its stock-based  compensation plan to attract and retain employees in
a competitive environment. All employees participate in this plan.

Cash flow from  operations for the three months ended March 31, 2006 increased
slightly to $1,039  million  from $1,009  million for the three  months  ended
March 31, 2005,  and  decreased  30% from $1,490  million for the three months
ended  December 31, 2005. The decrease in cash flow from  operations  from the
prior quarter  reflects  primarily the impact of the widening  heavy crude oil
differentials,  lower natural gas prices and a  strengthening  Canadian dollar
relative to the US dollar,  partially  offset by a decrease  in realized  risk
management losses. As a result of seasonal demands, reversals of the Corsicana
and Spearhead  pipelines and third party outages,  the heavy oil  differential
has  narrowed.  This is expected to result in  improvements  in the  Company's
realized crude oil pricing.

Total production before royalties  averaged 563,027 boe/d for the three months
ended March 31,  2006,  up 6% from  530,316  boe/d for the three  months ended
March 31, 2005, but decreased 3% from 577,505 boe/d for the three months ended
December 31, 2005.

  CANADIAN NATURAL RESOURCES LIMITED                                       15
==============================================================================
<PAGE>

OPERATING HIGHLIGHTS
<TABLE>
<CAPTION>
                                                                            Three Months Ended
                                                       -------------------
                                                                MAR 31               Dec 31               Mar 31
                                                                  2006                 2005                 2005
-----------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                 <C>                  <C>
CRUDE OIL AND NGLS ($/bbl)(1)
Sales price(2)                                         $         43.79     $          46.38     $          39.81
Royalties                                                         3.48                 3.89                 3.39
Production expense                                               11.33                10.33                11.30
-----------------------------------------------------------------------------------------------------------------
Netback                                                $         28.98     $          32.16     $          25.12
-----------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf)(1)
Sales price(2)                                         $          8.30     $          11.67     $           6.68
Royalties                                                         1.70                 2.30                 1.30
Production expense                                                0.80                 0.76                 0.69
-----------------------------------------------------------------------------------------------------------------
Netback                                                $          5.80     $           8.61     $           4.69
-----------------------------------------------------------------------------------------------------------------
BARRELS OF OIL EQUIVALENT ($/boe)(1)
Sales price(2)                                         $         46.30     $          56.08     $          39.94
Royalties                                                         6.44                 8.01                 5.42
Production expense                                                8.46                 7.93                 8.04
-----------------------------------------------------------------------------------------------------------------
Netback                                                $         31.40     $          40.14     $          26.48
=================================================================================================================
</TABLE>
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) INCLUDING TRANSPORTATION COSTS AND EXCLUDING RISK MANAGEMENT ACTIVITIES.

  16                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

BUSINESS ENVIRONMENT
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                       -------------------
                                                                MAR 31               Dec 31               Mar 31
                                                                  2006                 2005                 2005
-----------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                 <C>
WTI benchmark price (US$/bbl)                          $         63.53      $         60.04     $          49.90
Dated Brent benchmark price (US$/bbl)                  $         61.80      $         56.93     $          47.71
Dated Brent differential from WTI (%)                               3%                   5%                   4%
Differential to LLB blend (US$/bbl)                    $         28.70      $         24.09     $          19.26
LLB blend differential from WTI (%)                                45%                  40%                  39%
Condensate benchmark price (US$/bbl)                   $         63.63      $         60.41     $          51.45
NYMEX benchmark price (US$/mmbtu)                      $          9.10      $         12.83     $           6.31
AECO benchmark price (C$/GJ)                           $          8.82      $         11.07     $           6.35
US / Canadian dollar average
         exchange rate (US$)                                    0.8660               0.8523               0.8152
=================================================================================================================
</TABLE>

World crude oil prices  remained  strong in the first  quarter of 2006 despite
increasing crude oil inventories, due to:

o    continued demand growth, particularly in China and the United States;

o    ongoing geopolitical  uncertainties in Iran, Nigeria, Iraq and Venezuela;
     and

o    production losses in the Gulf of Mexico from hurricanes Katrina and Rita.

West Texas Intermediate ("WTI") averaged US$63.53 per bbl for the three months
ended March 31, 2006,  an increase of 27% compared to US$49.90 per bbl for the
three months ended March 31, 2005, and an increase of 6% from US$60.04 per bbl
for the three months ended December 31, 2005.

While  crude oil  benchmark  prices  continued  to  increase  during the first
quarter  of  2006,  the  full  benefit  of  higher  WTI  pricing  does not get
completely  reflected  in the  Company's  crude  oil price  realizations.  The
positive impact of higher WTI prices on the Company's crude oil production was
hampered by the widening heavy crude oil differentials, which increased 49% to
average  US$28.70  per bbl for the three  months  ended  March  31,  2006 from
US$19.26 per bbl for the three months ended March 31, 2005 and  increased  19%
from  US$24.09  per bbl for the three months  ended  December  31,  2005.  The
widening in the heavy crude oil  differential  from the first  quarter of 2005
was  primarily due to increased  demand for lighter  barrels of crude oil. The
stronger  demand for higher  yield light  barrels of crude oil  increased  the
benchmark  light  crude oil prices such as WTI,  resulting  in wider heavy oil
differentials.  Heavy  crude oil  differentials  continued  to widen  from the
fourth  quarter  of 2005 to the first  quarter  of 2006 due to both  increased
demand for lighter barrels of crude oil and normal winter seasonal  decline in
demand for heavy crude oil. The Company's  crude oil price  realizations  were
also impacted by the effect of a strengthening Canadian dollar relative to the
US dollar.  A strengthening in the Canadian dollar reduces the Canadian dollar
sales price the Company  receives  for its crude oil  production  as crude oil
prices are based on US dollar denominated benchmarks.

The Company anticipates a narrowing of the heavy crude oil differential in the
second quarter of 2006 due to seasonal demands, the reversals of the Corsicana
and  Spearhead  pipelines  and a third party outage that is expected to reduce
supply.

NYMEX natural gas prices averaged US$9.10 per mmbtu for the three months ended
March 31, 2006, up 44% from US$6.31 per mmbtu for the three months ended March
31,  2005,  and down 29% from  US$12.83  per mmbtu for the three  months ended
December 31, 2005.  AECO natural gas pricing moved  directionally  with NYMEX.
The increase  from the first  quarter of 2005 to the first quarter of 2006 was
primarily a response to increasing  benchmark  crude oil prices.  The decrease
from the fourth quarter of 2005 reflects mild weather  experienced  during the
first quarter of 2006, which resulted in reduced demand and higher natural gas
inventory levels.

  CANADIAN NATURAL RESOURCES LIMITED                                       17
==============================================================================
<PAGE>

PRODUCT PRICES(1)
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                       --------------------
                                                                 MAR 31               Dec 31               Mar 31
                                                                   2006                 2005                 2005
------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                  <C>
CRUDE OIL AND NGLS ($/bbl)(2)
North America                                          $          34.16     $          37.96     $          32.28
North Sea                                              $          68.05     $          66.88     $          59.56
Offshore West Africa                                   $          65.23     $          60.19     $          62.34
Company average                                        $          43.79     $          46.38     $          39.81

NATURAL GAS ($/mcf)(2)
North America                                          $           8.39     $          11.79     $           6.73
North Sea                                              $           2.38     $           3.40     $           3.52
Offshore West Africa                                   $           5.59     $           5.13     $           7.67
Company average                                        $           8.30     $          11.67     $           6.68

COMPANY AVERAGE ($/boe)(2)                             $          46.30     $          56.08     $          39.94

PERCENTAGE OF REVENUE
     (excluding midstream revenue)
Crude oil and NGLs                                                  53%                  48%                  54%
Natural gas                                                         47%                  52%                  46%
==================================================================================================================
</TABLE>
(1) INCLUDING TRANSPORTATION COSTS AND EXCLUDING RISK MANAGEMENT ACTIVITIES.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

Company  realized crude oil prices increased 10% to average $43.79 per bbl for
the three months  ended March 31,  2006,  up from $39.81 per bbl for the three
months ended March 31, 2005 and decreased 6% from $46.38 per bbl for the three
months ended  December 31, 2005.  The increase  from the first quarter of 2005
was primarily due to higher  benchmark world crude oil prices and an increased
proportion  of crude oil and NGLs sales  coming  from  Offshore  West  Africa,
offset by wider heavy crude oil  differentials in North America and a stronger
Canadian  dollar.  The decrease  from the prior  quarter was  primarily due to
higher  diluent  pricing,  wider  Canadian light crude oil and heavy crude oil
differentials and the strengthening Canadian dollar.

The Company's  realized  natural gas price  increased 24% to average $8.30 per
mcf for the three months  ended March 31, 2006,  up from $6.68 per mcf for the
three  months  ended March 31,  2005,  primarily  in  response  to  increasing
benchmark crude oil prices. The Company's realized natural gas price decreased
29% from  $11.67 per mcf in the prior  quarter  primarily  as a result of mild
weather  experienced  during the first  quarter  of 2006,  which  resulted  in
reduced demand and higher natural gas inventory levels.

NORTH AMERICA

North America realized crude oil prices increased 6% to average $34.16 per bbl
for the three  months  ended  March 31,  2006,  up from $32.28 per bbl for the
three months ended March 31, 2005,  but  decreased 10% from $37.96 per bbl for
the three months ended  December 31, 2005. The increase from the first quarter
of 2005 was primarily due to higher benchmark world crude oil prices offset by
wider  heavy  crude oil  differentials  and a stronger  Canadian  dollar.  The
decrease from the prior quarter was primarily due to higher  diluent  pricing,
and wider Canadian light crude oil and heavy crude oil differentials.

  18                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

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
the first  quarter,  the Company  contributed  approximately  156,000 bbl/d of
heavy crude oil blends to the Western  Canadian Select ("WCS")  stream,  a new
blend of up to 10 different crude oil streams.  WCS resembles a Bow River type
crude with  distillation  cuts  approximating  a natural  heavy crude oil with
premium  quality  asphalt  characteristics  and has an API of  19-22  degrees.
Volumes of the new blend are expected to grow,  with the potential to become a
new benchmark  for North America  markets in addition to WTI. The Company also
continues  to work with  refiners  to  advance  expansion  of heavy  crude oil
conversion  capacity,  and is working with  pipeline  companies to develop new
capacity  to the  Canadian  west coast where crude oil cargos can be sold on a
world-wide basis. The Company has committed to 25,000 bbl/d of capacity on the
Corsicana Pipeline,  which carries crude oil to the Gulf of Mexico with a view
to expanding  markets for its heavy crude oil. The Corsicana  Pipeline is made
up of a series of segments  extending  from  Patoka,  Illinois  to  Nederland,
Texas,  near the Gulf Coast.  The  Company's  first  sales from the  Corsicana
pipeline occurred on April 6, 2006.

North America  realized  natural gas prices increased 25% to average $8.39 per
mcf for the three months  ended March 31, 2006,  up from $6.73 per mcf for the
three months ended March 31, 2005. The increase from the first quarter of 2005
to the first quarter of 2006 was primarily in response to increasing benchmark
crude oil prices.  Realized  natural gas prices for the first  quarter of 2006
decreased 29% from $11.79 per mcf for the three months ended December 31, 2005
as a result of mild  weather  experienced  during  the first  quarter of 2006,
which resulted in reduced demand and higher natural gas inventory levels.

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

<TABLE>
<CAPTION>
                                                                       Three Months Ended
                                                       ---------------
                                                            MAR 31           Dec 31            Mar 31
                                                              2006             2005              2005
------------------------------------------------------------------------------------------------------
<S>                                                    <C>              <C>              <C>
Wellhead Price(1)(2)
     Light/medium crude oil and NGLs (C$/bbl)          $     58.21      $     61.33      $      50.46
     Pelican Lake crude oil (C$/bbl)                   $     31.60      $     34.86      $      31.74
     Primary heavy crude oil (C$/bbl)                  $     25.91      $     31.00      $      25.46
     Thermal heavy crude oil (C$/bbl)                  $     23.60      $     28.84      $      24.69
         Natural gas (C$/mcf)                          $      8.39      $     11.79      $       6.73
======================================================================================================
</TABLE>
(1) INCLUDING TRANSPORTATION COSTS AND EXCLUDING RISK MANAGEMENT ACTIVITIES.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

NORTH SEA

North Sea realized  crude oil prices  increased 14% to average  $68.05 per bbl
for the three  months  ended  March 31, 2006 from $59.56 per bbl for the three
months  ended March 31,  2005,  and  increased  2% from $66.88 per bbl for the
three months ended  December 31, 2005.  The increase in the realized crude oil
price  compared  to the first  quarter of 2005 was due mainly to higher  world
benchmark crude oil prices and a narrowing of the average Brent  differential,
offset by the strengthening Canadian dollar.

OFFSHORE WEST AFRICA

Offshore West Africa  realized  crude oil prices  increased 5% from $62.34 per
bbl for the three months ended March 31, 2005,  to average  $65.23 per bbl for
the three months ended March 31,  2006,  and  increased 8% from $60.19 per bbl
for the three  months ended  December  31, 2005.  The increase in the realized
crude oil price was due mainly to higher  world  benchmark  crude oil  prices,
offset by the strengthening Canadian dollar.

  CANADIAN NATURAL RESOURCES LIMITED                                       19
==============================================================================
<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,  referred  to as
"liftings" in this MD&A. The related cumulative crude oil inventory volumes by
segment, which have not been recognized in revenue, were as follows:

<TABLE>
<CAPTION>
                                                                           ------------------
                                                                                     MAR 31           Dec 31
(bbl)                                                                                  2006               2005
--------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>                  <C>
North America, related to pipeline fill                                         1,097,526            484,157
North Sea, related to timing of liftings                                        1,528,040            747,141
Offshore West Africa, related to timing of liftings                               584,931            412,841
--------------------------------------------------------------------------------------------------------------
                                                                                3,210,497          1,644,139
==============================================================================================================
</TABLE>

DAILY PRODUCTION, BEFORE ROYALTIES
<TABLE>
<CAPTION>
                                                                          Three Months Ended
                                                       -----------------
                                                              MAR 31              Dec 31               Mar 31
                                                                2006                2005                 2005
--------------------------------------------------------------------------------------------------------------
<S>                                                          <C>                 <C>                  <C>
CRUDE OIL AND NGLS (bbl/d)
North America                                                222,955             230,263              209,125
North Sea                                                     60,802              66,798               71,139
Offshore West Africa                                          39,905              43,207                7,539
--------------------------------------------------------------------------------------------------------------
                                                             323,662             340,268              287,803
--------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America                                                  1,411               1,402                1,430
North Sea                                                         17                  15                   23
Offshore West Africa                                               8                   6                    2
--------------------------------------------------------------------------------------------------------------
                                                               1,436               1,423                1,455
--------------------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d)                       563,027             577,505              530,316
--------------------------------------------------------------------------------------------------------------
PRODUCT MIX
Light / medium crude oil and NGLs                                27%                 28%                  25%
Pelican Lake crude oil                                            5%                  5%                   3%
Primary heavy crude oil                                          17%                 17%                  17%
Thermal heavy crude oil                                           8%                  9%                   9%
Natural gas                                                      43%                 41%                  46%
==============================================================================================================
</TABLE>

  20                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

DAILY PRODUCTION, NET OF ROYALTIES
<TABLE>
<CAPTION>
                                                                          Three Months Ended
                                                       -----------------
                                                              MAR 31              Dec 31               Mar 31
                                                                2006                2005                 2005
--------------------------------------------------------------------------------------------------------------
<S>                                                          <C>                 <C>                  <C>
CRUDE OIL AND NGLS (bbl/d)
North America                                                192,747             198,047              179,472
North Sea                                                     60,694              66,664               71,074
Offshore West Africa                                          38,958              42,081                7,310
--------------------------------------------------------------------------------------------------------------
                                                             292,399             306,792              257,856
--------------------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America                                                  1,120               1,124                1,148
North Sea                                                         17                  15                   23
Offshore West Africa                                               8                   6                    2
--------------------------------------------------------------------------------------------------------------
                                                               1,145               1,145                1,173
--------------------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d)                       483,143             497,679              453,385
==============================================================================================================
</TABLE>

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

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 crude oil and  natural gas  production  averaged  563,027  boe/d for the
three months  ended March 31, 2006, a 6% increase  from the three months ended
March 31, 2005.  The increase in production was due to organic growth from the
Company's   extensive  North  America  capital  expenditure  program  and  the
commencement  of  production  from the  Baobab  Field  located  offshore  Cote
d'Ivoire  in  the  third  quarter  of  2005,  partially  offset  by  decreased
production in the North Sea.

Total crude oil and NGLs  production for the three months ended March 31, 2006
increased  12% to 323,662  bbl/d from 287,803 bbl/d for the three months ended
March 31, 2005. Crude oil and NGLs production in the first quarter of 2006 was
in line with the Company's  previously  issued  guidance of 306,000 to 334,000
bbl/d.

Natural gas production  continues to represent the Company's  largest  product
offering.  Natural gas  production  for the three  months ended March 31, 2006
decreased  slightly to average  1,436 mmcf/d  compared to 1,455 mmcf/d for the
three months ended March 31, 2005.  The Company's  first  quarter  natural gas
production  was within the Company's  previously  issued  guidance of 1,426 to
1,475 mmcf/d.

As a result of the Company's decision to reduce overall North America drilling
activity for the remainder of 2006,  and to shift capital from its natural gas
program to its crude oil program,  the Company has revised its 2006 production
guidance.  The Company  currently  expects annual production levels in 2006 to
average  1,448 to 1,516 mmcf/d of natural gas and 338,000 to 370,000  bbl/d of
crude oil and NGLs. Second quarter 2006 production  guidance is 1,461 to 1,520
mmcf/d of natural gas and 326,000 to 348,000 bbl/d of crude oil and NGLs.

  CANADIAN NATURAL RESOURCES LIMITED                                       21
==============================================================================
<PAGE>

NORTH AMERICA

North America crude oil and NGLs  production  for the three months ended March
31, 2006 increased 7% to average  222,955 bbl/d, up from 209,125 bbl/d for the
three  months  ended  March  31,  2005.  The  increase  in crude  oil and NGLs
production  was mainly due to increased  Primrose  production and the positive
results from the Pelican Lake waterflood project.  First quarter crude oil and
NGLs  production  decreased 3% from  230,263  bbl/d for the three months ended
December 31, 2005 due to the timing of the Primrose production cycle.

North America natural gas production for the three months ended March 31, 2006
decreased  slightly to average  1,411  mmcf/d from 1,430  mmcf/d for the three
months  ended March 31,  2005.  The winter  drilling  program  was  negatively
impacted by warmer than normal weather,  which precluded timely access to many
locations in Northern Alberta and Northeast British  Columbia.  This situation
improved  markedly in late February  allowing much of the planned locations to
be  drilled.  As a result,  however,  approximately  70 mmcf/d of natural  gas
production was delayed.  The Company  anticipates  that some locations will be
tied-in  during the second and third  quarters  of 2006;  however  the Company
anticipates  that 20 - 30 mmcf/d will not be tied-in  until  freeze up late in
the fourth quarter of 2006 or early in the first quarter of 2007.


NORTH SEA

North Sea crude oil  production  for the three  months  ended  March 31,  2006
averaged  60,802  bbl/d,  15% lower than the 71,139  bbl/d in the three months
ended March 31, 2005 and 9% lower than the 66,798 bbl/d in the prior  quarter.
Production  levels  were in line  with  expectations,  reflecting  anticipated
temporary  curtailments at the Lyell Field and the Columba E Terraces, as well
as temporary restrictions at B-Block and Playfair.

Natural gas  production  in the North Sea for the three months ended March 31,
2006 averaged 17 mmcf/d compared to 23 mmcf/d for the three months ended March
31, 2005, and changed marginally from the prior quarter.


OFFSHORE WEST AFRICA

Offshore West Africa crude oil production for the three months ended March 31,
2006  increased  429% to 39,905  bbl/d from 7,539  bbl/d for the three  months
ended  March  31,  2005.  The   production   increase  was  primarily  due  to
commencement  of production from the 57.61% owned and operated Baobab Field in
August 2005.  First quarter 2006 production  decreased by 8% from 43,207 bbl/d
in the prior quarter.  This decrease was due in large part to limitations from
monitoring sand screen effectiveness on one producing well.

  22                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

ROYALTIES
<TABLE>
<CAPTION>
                                                                             Three Months Ended
                                                       --------------------
                                                                 MAR 31               Dec 31               Mar 31
                                                                   2006                 2005                 2005
------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                  <C>
CRUDE OIL AND NGLS ($/bbl)(1)
North America                                          $           4.63     $           5.39     $           4.58
North Sea                                              $           0.12     $           0.14     $           0.05
Offshore West Africa                                   $           1.55     $           1.57     $           1.90
Company average                                        $           3.48     $           3.89     $           3.39

NATURAL GAS ($/mcf)(1)
North America                                          $           1.73     $           2.34     $           1.33
North Sea                                              $              -     $              -     $              -
Offshore West Africa                                   $           0.13     $           0.14     $           0.23
Company average                                        $           1.70     $           2.30     $           1.30

COMPANY AVERAGE ($/boe)(1)                             $           6.44     $           8.01     $           5.42

PERCENTAGE OF REVENUE(2)
Crude oil and NGLs                                                   8%                   8%                   9%
Natural gas                                                         21%                  20%                  20%
Boe                                                                 14%                  14%                  14%
==================================================================================================================
</TABLE>
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2) INCLUDING TRANSPORTATION COSTS AND EXCLUDING RISK MANAGEMENT ACTIVITIES.


NORTH AMERICA

North America crude oil and NGLs  royalties per bbl for the three months ended
March 31, 2006  increased from the three months ended March 31, 2005 primarily
due  to  higher  benchmark  crude  oil  prices,  offset  by  wider  heavy  oil
differentials and a stronger Canadian dollar. First quarter 2006 crude oil and
NGLs royalties per bbl decreased from the three months ended December 31, 2005
due to wider heavy oil  differentials  and a  strengthening  Canadian  dollar,
offset by higher benchmark crude oil prices. Based on current pricing,  payout
on the Primrose  thermal projects is anticipated to be reached in the third or
fourth  quarter of 2006, at which point Crown royalty rates will increase from
1% of gross  revenue  to 25% of revenue  net of  operating  costs and  capital
expenditures.

Natural gas royalties for the three months ended March 31, 2006 increased from
the three  months  ended  March 31, 2005 due to higher  benchmark  natural gas
prices.

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.

  CANADIAN NATURAL RESOURCES LIMITED                                       23
==============================================================================
<PAGE>

OFFSHORE WEST AFRICA

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

PRODUCTION EXPENSE
<TABLE>
<CAPTION>
                                                                             Three Months Ended
                                                       --------------------
                                                                 MAR 31               Dec 31               Mar 31
                                                                   2006                 2005                 2005
------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                  <C>
CRUDE OIL AND NGLS ($/bbl)(1)
North America                                          $          10.91     $          10.92     $          10.07
North Sea                                              $          16.85     $          12.11     $          14.91
Offshore West Africa                                   $           6.08     $           5.62     $          11.43
Company average                                        $          11.33     $          10.33     $          11.30

NATURAL GAS ($/mcf)(1)
North America                                          $           0.79     $           0.74     $           0.66
North Sea                                              $           1.26     $           1.96     $           2.52
Offshore West Africa                                   $           1.00     $           0.80     $           1.25
Company average                                        $           0.80     $           0.76     $           0.69

COMPANY AVERAGE ($/boe)(1)                             $           8.46     $           7.93     $           8.04
==================================================================================================================
</TABLE>
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

NORTH AMERICA

North  America  crude oil and NGLs  production  expense  per bbl for the three
months  ended March 31, 2006  increased 8% to $10.91 from $10.07 for the three
months ended March 31, 2005.  The increase  from the first quarter of 2005 was
primarily due to higher industry wide service costs. Based on expectations for
the  remainder of the year,  the Company has reduced its annual North  America
crude oil and NGLs production expense guidance to $11.00 - $11.80 per bbl.

North  America  natural gas  production  expense per mcf for the three  months
ended March 31, 2006 increased over the three months ended March 31, 2005, and
the prior quarter.  This increase from the comparable periods is primarily due
to the continued  service and cost pressures  seen industry wide.  Natural gas
production  expense is expected to be lower over the remainder of the year due
primarily  to the  impact of reduced  seasonal  costs  through  the spring and
summer in natural gas areas. Based on the higher costs in the first quarter of
2006, and  expectations  for the remainder of the year the Company has revised
its annual North America  natural gas production  expense  guidance to $0.75 -
$0.79 per mcf.

  24                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

NORTH SEA

North Sea crude oil  production  expense varied on a per barrel basis from the
comparable  periods  due to the timing of  maintenance  work,  the  changes in
production  volumes on a relatively fixed cost base and the timing of liftings
from various fields.

OFFSHORE WEST AFRICA

Offshore West Africa crude oil production expenses are largely fixed in nature
and  fluctuated  on a per barrel  basis  from the  comparable  periods  due to
changes in  production.  Production  expenses for the three months ended March
31, 2006  compared  to the three  months  ended March 31, 2005 were  primarily
impacted by the  commencement  of  production  from the Baobab Field in August
2005.

MIDSTREAM
<TABLE>
<CAPTION>
                                                                       Three Months Ended
                                                       ----------------
                                                             MAR 31             Dec 31              Mar 31
($ millions)                                                   2006               2005                2005
-----------------------------------------------------------------------------------------------------------
<S>                                                    <C>                 <C>                <C>
Revenue                                                $         18        $        21        $         21
Production expense                                                5                  8                   6
-----------------------------------------------------------------------------------------------------------
Midstream cash flow                                              13                 13                  15
Depreciation                                                      2                  2                   2
-----------------------------------------------------------------------------------------------------------
Segment earnings before taxes                          $         11        $        11        $         13
===========================================================================================================
</TABLE>

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


DEPLETION, DEPRECIATION AND AMORTIZATION(1)
<TABLE>
<CAPTION>
                                                                            Three Months Ended
                                                       -----------------
                                                              MAR 31             Dec 31             Mar 31
                                                                2006               2005               2005
-----------------------------------------------------------------------------------------------------------
<S>                                                    <C>                <C>                <C>
Expense ($ millions)                                   $         519      $         548      $         472
     $/boe(2)                                          $       10.56      $       10.44      $        9.89
===========================================================================================================
</TABLE>
(1) DD&A EXCLUDES DEPRECIATION ON MIDSTREAM ASSETS.
(2) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

Depletion,  Depreciation and Amortization  ("DD&A") for the three months ended
March 31,  2006  increased  in total and on a boe basis from the three  months
ended March 31, 2005. The increase in DD&A on a boe basis was primarily due to
higher finding and development  costs  associated with natural gas exploration
in North  America and higher  estimated  future costs to develop the Company's
proved undeveloped reserves in the North Sea. DD&A decreased in total from the
prior quarter as a result of lower sales volumes due to the timing of liftings
and production volumes used as pipeline line fill.

  CANADIAN NATURAL RESOURCES LIMITED                                       25
==============================================================================
<PAGE>

ASSET RETIREMENT OBLIGATION ACCRETION
<TABLE>
<CAPTION>
                                                                            Three Months Ended
                                                       -------------------
                                                                MAR 31               Dec 31               Mar 31
                                                                  2006                 2005                 2005
-----------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                  <C>
Expense ($ millions)                                   $            17      $            16      $            18
     $/boe(1)                                          $          0.34      $          0.30      $          0.38
=================================================================================================================
</TABLE>
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

Asset retirement  obligation accretion expense is the increase in the carrying
amount of the asset retirement obligation due to the passage of time.

ADMINISTRATION EXPENSE
<TABLE>
<CAPTION>
                                                                            Three Months Ended
                                                       -------------------
                                                                MAR 31               Dec 31               Mar 31
                                                                  2006                 2005                 2005
-----------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                 <C>
Net expense ($ millions)                               $            42      $            36     $             35
     $/boe(1)                                          $          0.85      $          0.68     $           0.74
=================================================================================================================
</TABLE>
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

Administration  expense for the three months ended March 31, 2006 increased in
total and on a boe basis from the three  months  ended  March 31, 2005 and the
three months ended  December 31, 2005.  The increase from the first quarter of
2005 was primarily due to increased  insurance  premiums  related to hurricane
activity in 2005 and  increased  staffing  costs.  The increase from the prior
quarter was impacted by increased  costs related to the Company's  Share Bonus
Plan.

The Share Bonus Plan  incorporates  employee  share  ownership  in the Company
while  reducing  the  granting of stock  options  and the  dilution of current
Shareholders.  Under the plan  cash  bonuses  awarded,  based on  Company  and
employee  performance,  are  subsequently  used by a trustee to acquire common
shares  of  the  Company.  The  common  shares  vest  to the  employee  over a
three-year  period  provided the employee does not leave the employment of the
Company.  If the employee  leaves the employment of the Company,  the unvested
common shares are forfeited  under the terms of the plan. For the three months
ended  March 31,  2006,  the  Company  recognized  $6 million of  compensation
expense under the Share Bonus Plan (December 31, 2005 - $3 million;  March 31,
2005 - $7 million).

STOCK-BASED COMPENSATION
<TABLE>
<CAPTION>
                                                                             Three Months Ended
                                                       -------------------
                                                                MAR 31               Dec 31               Mar 31
($ millions)                                                      2006                 2005                 2005
-----------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                  <C>
Stock option plan                                      $           132      $           125      $           184
=================================================================================================================
</TABLE>

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

  26                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

The  Company  recorded a $132  million  ($88  million  after tax)  stock-based
compensation  expense for the three months ended March 31, 2006 in  connection
with the 13% appreciation in the Company's share price since December 31, 2005
(Company's  share price as at:  March 31, 2006 - C$64.90;  December 31, 2005 -
C$57.63;  March 31,  2005 -  C$34.18).  As  required  by GAAP,  the  Company's
outstanding  stock  options  are valued  based on the  difference  between the
exercise  price of the stock  options  and the market  price of the  Company's
common  shares,  pursuant  to a graded  vesting  schedule.  The  liability  is
revalued  quarterly to reflect  changes in the market  price of the  Company's
common shares and the options exercised or surrendered in the period, with the
net change recognized in net earnings,  or capitalized during the construction
period in the case of the Horizon  Project.  For the three  months ended March
31, 2006 the Company  capitalized  $30 million in stock-based  compensation on
the Horizon  Project  (December  31, 2005 - $37 million;  March 31, 2005 - $22
million).  The  stock-based  compensation  liability  reflects  the  Company's
potential  cash liability  should all the vested options be surrendered  for a
cash payout at the market price on March 31, 2006. In periods when substantial
stock price  changes  occur,  the Company is subject to  significant  earnings
volatility.

For the three months  ended March 31, 2006,  the Company paid $123 million for
stock  options  surrendered  for  cash  settlement  (December  31,  2005 - $52
million; March 31, 2005 - $77 million).

INTEREST EXPENSE
<TABLE>
<CAPTION>
                                                                             Three Months Ended
                                                       --------------------
                                                                 MAR 31               Dec 31               Mar 31
                                                                   2006                 2005                 2005
------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                  <C>
Interest expense, gross ($ millions)                   $             58     $             55     $             54
Less: capitalized interest, Horizon Project            $             33     $             27     $             11
------------------------------------------------------------------------------------------------------------------
Interest expense, net                                  $             25     $             28     $             43
     $/boe(1)                                          $           0.51     $           0.53     $           0.91
Average effective interest rate                                    5.7%                 5.7%                 5.5%
==================================================================================================================
</TABLE>
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.

Gross  interest  expense  increased  from  the  comparable  quarters  in  2005
primarily due to higher debt levels and carrying charges. Net interest expense
decreased on a total and boe basis due to the  capitalization  of construction
period interest related to the Horizon Project.


RISK MANAGEMENT ACTIVITIES

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

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

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

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

  CANADIAN NATURAL RESOURCES LIMITED                                       27
==============================================================================
<PAGE>

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


RISK MANAGEMENT
<TABLE>
<CAPTION>
                                                                             Three Months Ended
                                                       --------------------
                                                                 MAR 31               Dec 31               Mar 31
($ millions)                                                       2006                 2005                 2005
------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                  <C>
REALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments               $            332     $            235     $            105
Natural gas financial instruments                                    56                  242                  (10)
Interest rate swaps                                                   -                   (1)                  (8)
------------------------------------------------------------------------------------------------------------------
                                                       $            388     $            476     $             87
------------------------------------------------------------------------------------------------------------------
UNREALIZED LOSS (GAIN)
Crude oil and NGLs financial instruments               $            114     $           (514)    $            907
Natural gas financial instruments                                  (104)                (307)                  86
Interest rate swaps                                                  (2)                  (4)                   5
------------------------------------------------------------------------------------------------------------------
                                                       $              8     $           (825)    $            998
------------------------------------------------------------------------------------------------------------------
TOTAL                                                  $            396     $           (349)    $          1,085
==================================================================================================================
</TABLE>

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

<TABLE>
<CAPTION>
                                                                             Three Months Ended
                                                       --------------------
                                                                 MAR 31               Dec 31               Mar 31
                                                                   2006                 2005                 2005
------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                     <C>
Crude oil and NGLs ($/bbl)(1)                          $          12.04     $           7.67        $        4.07
Natural gas ($/mcf)(1)                                 $           0.43     $           1.85        $       (0.08)
==================================================================================================================
</TABLE>
(1) AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.


  28                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

The  effect  of the  realized  gain  on  non-designated  interest  rate  swaps
decreased the Company's interest expense as follows:

<TABLE>
<CAPTION>
                                                                            Three Months Ended
                                                       -------------------
                                                                MAR 31               Dec 31               Mar 31
($ millions)                                                      2006                 2005                 2005
-----------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                 <C>                  <C>
Interest expense as reported                           $            25     $             28     $             43
Realized risk management gain                                        -                   (1)                  (8)
-----------------------------------------------------------------------------------------------------------------
                                                       $            25     $             27     $             35
Average effective interest rate                                   5.7%                 5.6%                 4.5%
=================================================================================================================
</TABLE>

As effective as commodity  hedges are against  reference  commodity  prices, a
substantial  portion of the derivative  financial  instruments entered into by
the Company do not meet the  requirements  for hedge accounting under GAAP due
to currency,  product quality and location  differentials (the "non-designated
hedges").  The  Company is  required to  mark-to-market  these  non-designated
hedges based on prevailing  forward  commodity  prices in effect at the end of
each reporting period.  Accordingly,  the unrealized risk management liability
reflects,  at  March  31,  2006,  the  implied  price  differentials  for  the
non-designated hedges for future years. The cash settlement amount of the risk
management financial derivative instruments may vary materially depending upon
the  underlying  crude  oil and  natural  gas  prices  at the  time  of  final
settlement  of the  financial  derivative  instruments,  as  compared to their
mark-to-market  value at March 31,  2006.  Due to changes in the crude oil and
natural gas forward  pricing at March 31, 2006, the Company  recorded a net $8
million  ($5  million  after  tax)  unrealized  loss  on its  risk  management
activities  for the three  months  ended March 31, 2006  (December  31, 2005 -
unrealized  gain of $825  million;  March 31, 2005 -  unrealized  loss of $998
million).

In addition to the risk management  liability  recognized on the balance sheet
at March 31, 2006, the net unrecognized liability related to the fair value of
derivative  financial  instruments  designated  as hedges was $521  million at
March 31, 2006 (December 31, 2005 - $990 million).

Details related to outstanding  derivative financial  instruments at March 31,
2006 are disclosed in note 7 to the Company's  unaudited interim  consolidated
financial statements

FOREIGN EXCHANGE
<TABLE>
<CAPTION>
                                                                            Three Months Ended
                                                       -------------------
                                                                MAR 31               Dec 31               Mar 31
($ millions)                                                      2006                 2005                 2005
-----------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                 <C>                  <C>
Realized foreign exchange gain                         $            (5)    $            (16)    $            (12)
Unrealized foreign exchange loss                                     10                   5                    -
-----------------------------------------------------------------------------------------------------------------
                                                       $             5     $            (11)    $            (12)
=================================================================================================================
</TABLE>

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

The  majority  of the  realized  foreign  exchange  gain was the result of the
effects  of foreign  exchange  rate  fluctuations  on  working  capital  items
denominated in US dollars or UK pounds sterling.  Unrealized  foreign exchange
loss is related to the  fluctuation of the Canadian  dollar in relation to the
US dollar with respect to the US dollar debt, and working capital  denominated
in US dollars  or UK pounds  sterling.  The  Canadian  dollar  ended the first
quarter at US$0.8568  compared to US$0.8267  at March 31, 2005  (December  31,
2005 - US$0.8577).

  CANADIAN NATURAL RESOURCES LIMITED                                       29
==============================================================================
<PAGE>

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


TAXES
<TABLE>
<CAPTION>
                                                                             Three Months Ended
                                                       --------------------
                                                                 MAR 31               Dec 31               Mar 31
($ millions, except income tax rates)                              2006                 2005                 2005
------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                  <C>
TAXES OTHER THAN INCOME TAX
Current                                                $             35     $             50     $             42
Deferred                                                             26                    1                    -
------------------------------------------------------------------------------------------------------------------
                                                       $             61     $             51     $             42
------------------------------------------------------------------------------------------------------------------

CURRENT INCOME TAX
North America - Current income tax                     $             15     $              2     $             30
North America - Large corporations tax                                3                    5                    2
North Sea                                                             1                   31                   39
Offshore West Africa                                                 13                   19                    3
Other                                                                 -                    1                    -
------------------------------------------------------------------------------------------------------------------
                                                       $             32     $             58     $             74
------------------------------------------------------------------------------------------------------------------
FUTURE INCOME TAX EXPENSE                              $            268     $            514     $           (241)
EFFECTIVE INCOME TAX RATE                                      83.9%(1)                34.1%                28.3%
==================================================================================================================
</TABLE>
(1)  INCLUDES THE EFFECT OF A ONE TIME CHARGE OF $110 MILLION RELATED TO THE
     INCREASED SUPPLEMENTARY CHARGE ON OIL AND GAS PROFITS IN THE UK NORTH
     SEA, EFFECTIVE JANUARY 1, 2006.

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

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

The North Sea current  income tax expense for the three months ended March 31,
2006  decreased  from the three  months  ended  March  31,  2005 and the prior
quarter  primarily due to the effect of decreased  crude oil  production,  the
timing of liftings from various fields and the level of capital  expenditures,
offset by increased realized crude oil prices.  Effective January 1, 2006, the
UK government substantively enacted an increase to the supplementary charge on
profits  from UK North Sea crude oil and  natural gas  production  from 10% to
20%,  increasing the Company's  effective  income tax rate in the North Sea to
approximately  50%.  The  supplementary  charge  excludes  any  deduction  for
financing  costs.  The Company's  future income tax liability was increased by
$110 million as at January 1, 2006, with respect to this tax rate change.

Subsequent  to March 31,  2006,  the  provinces  of Alberta  and  Saskatchewan
substantively enacted reductions in their corporate income tax rates that will
result in a reduction of future tax liabilities of approximately $160 million.
This  reduction  will  be  reflected  in the  Company's  reported  results  of
operations in the second quarter of 2006.

  30                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

CAPITAL EXPENDITURES (1)
<TABLE>
<CAPTION>
                                                                            Three Months Ended
                                                       -------------------
                                                                MAR 31               Dec 31               Mar 31
($ millions)                                                      2006                 2005                 2005
-----------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                  <C>                 <C>
EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT
Net property acquisitions                              $            12      $            19     $              2
Land acquisition and retention                                      99                   97                   36
Seismic evaluations                                                 52                   40                   41
Well drilling, completion and equipping                            936                  629                  634
Pipeline and production facilities                                 500                  314                  432
-----------------------------------------------------------------------------------------------------------------
TOTAL NET RESERVE REPLACEMENT EXPENDITURES                       1,599                1,099                1,145
-----------------------------------------------------------------------------------------------------------------
Horizon Project:
   Phase 1 construction costs(2)                                   616                  469                  131
   Phases 2 and 3 costs                                              1                    -                    -
   Capitalized interest, stock-based compensation and
   other(2)                                                         69                   88                   84
-----------------------------------------------------------------------------------------------------------------
Total Horizon Project                                              686                  557                  215
-----------------------------------------------------------------------------------------------------------------
Midstream                                                            3                    1                    4
Abandonments(3)                                                     15                   16                    4
Head office                                                          6                    6                    4
-----------------------------------------------------------------------------------------------------------------
TOTAL NET CAPITAL EXPENDITURES                         $         2,309      $         1,679     $          1,372
-----------------------------------------------------------------------------------------------------------------
BY SEGMENT
North America                                          $         1,404      $           862     $            940
North Sea                                                          138                  118                   57
Offshore West Africa                                                50                  119                  144
Other                                                                7                    -                    4
Horizon Project                                                    686                  557                  215
Midstream                                                            3                    1                    4
Abandonments(3)                                                     15                   16                    4
Head office                                                          6                    6                    4
-----------------------------------------------------------------------------------------------------------------
Total                                                  $         2,309      $         1,679     $          1,372
=================================================================================================================
</TABLE>
(1) THE NET CAPITAL EXPENDITURES DO NOT INCLUDE NON-CASH PROPERTY, PLANT AND
    EQUIPMENT ADDITIONS OR DISPOSALS.

(2) PRIOR PERIOD AMOUNTS HAVE BEEN RECLASSIFIED WITH RESPECT TO STOCK-BASED
    COMPENSATION COSTS.

(3) ABANDONMENTS REPRESENT EXPENDITURES TO SETTLE ASSET RETIREMENT OBLIGATIONS
    AND HAVE BEEN REFLECTED AS CAPITAL EXPENDITURES IN THIS TABLE.

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

  CANADIAN NATURAL RESOURCES LIMITED                                       31
==============================================================================
<PAGE>

Net capital  expenditures in the three months ended March 31, 2006 were $2,309
million  compared to $1,372  million in the three  months ended March 31, 2005
and $1,679  million in the three months ended  December 31, 2005. The increase
was primarily related to increased capital expenditures on the Horizon Project
and increased activity on the North America conventional  drilling program. In
the first quarter,  the Company drilled a total of 890 net wells consisting of
440 natural gas wells, 92 crude oil wells, 297 stratigraphic  test and service
wells,  and 61 wells that were dry.  The 297  stratigraphic  test and  service
wells include 103  stratigraphic  test wells  related to the Horizon  Project.
This  compared  to 691 net wells  drilled in the first  quarter  of 2005.  The
Company achieved an overall success rate of 90%, excluding  stratigraphic test
and service wells.


NORTH AMERICA

North  America   accounted  for   approximately   91%  of  the  total  capital
expenditures   for  the  three  months  ended  March  31,  2006   compared  to
approximately 85% in the comparable period in 2005.

During the first quarter 2006,  the Company  targeted to drill 499 net natural
gas wells, including 191 wells in Northeast British Columbia, 186 wells in the
Northern  Plains region,  80 wells in Northwest  Alberta,  and 42 wells in the
Southern  Plains  region.  The  Company  also  targeted 90 net crude oil wells
during the first quarter 2006.  The majority of these wells were  concentrated
in the  Company's  crude oil Northern  Plains  region where 33 heavy crude oil
wells,  22 Pelican  Lake crude oil wells,  20 thermal  crude oil wells,  and 4
light  crude oil wells were  drilled.  Another  11 light  crude oil wells were
drilled during the quarter outside of the Northern  Plains region.  The winter
drilling  program was negatively  impacted by much warmer than normal weather,
which  precluded  timely  access to many  locations  in  Northern  Alberta and
Northeast British Columbia. This situation improved markedly in late February,
allowing many of the planned locations to be drilled.

Due to cost pressures and  significant  changes in relative  commodity  prices
between  crude oil and natural gas, the Company has taken the  opportunity  to
utilize its large  drilling  inventory to maximize value in both the short and
long-term.  Natural gas pricing has  softened  significantly  in 2006  whereas
crude oil  pricing  remains  strong  with  narrowing  heavy oil  differentials
starting in the second  quarter of 2006. As a result,  the Company  decided to
maintain its planned capital  expenditure  level which will result in a slight
reduction in drilling  activity.  The Company will drill 150 fewer natural gas
wells, a 13% reduction from the original plan for 2006.

As part of the  development of the Company's  heavy crude oil  resources,  the
Company is continuing with its Primrose thermal  projects,  which includes the
Primrose North expansion project and drilling additional wells in the Primrose
South project to augment existing production. To date, the Company has drilled
174  stratigraphic  test wells,  and has drilled 20 thermal oil wells that are
currently  producing.  First steaming for the Primrose North expansion project
commenced in November  2005 and current  production  is  approximately  15,000
bbl/d.  Overall Primrose  thermal  production for the three months ended March
31, 2006 was approximately 47,000 bbl/d.

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

Development  of new  acreage and  secondary  recovery  conversion  projects at
Pelican Lake continued as expected through the first quarter of 2006. Drilling
consisted of 22 horizontal producing wells, 13 stratigraphic wells and 4 water
source wells,  with plans to drill 117  additional  horizontal  wells over the
remainder of the year. The North Brintnell  waterflood  conversion project was
expanded by 744 acres.  The  pressure  response  from the Polymer  Flood pilot
continued to be positive.  The Company commenced installation of the first two
polymer skids as part of the commercial  Polymer Flood  project.  Pelican Lake
production was approximately 29,000 bbl/d for the first quarter.

In the second  quarter of 2006,  the Company's  overall  drilling  activity in
North America is expected to be comprised of 66 natural gas wells and 87 crude
oil wells excluding stratigraphic and service wells.

  32                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

HORIZON OIL SANDS PROJECT

The Horizon Project  continued on schedule and on budget with construction 26%
complete  at  quarter  end.  The  project  status as at March 31,  2006 was as
follows:

   o  Completed 60% model reviews in all areas;

   o  Awarded total contracts and purchase orders in excess of $4 billion;

   o  Four coke drums were delivered to the site as planned and installed on
      schedule;

   o  Completed  transport  of the  naptha  reactor  to the site from the rail
      staging area south of Fort McMurray;

   o  Started setting of piperack modules on foundations; and

   o  Site preparation and underground infrastructure 98% complete.

Major activities for the second quarter of 2006 will include:

   o  Overall detailed engineering anticipated to surpass 80%;

   o  Occupancy of the second of three camps; and

   o  Ore preparation plant site turnover by mining to bitumen production.


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


NORTH SEA

In the first quarter, the Company continued with its planned program of infill
drilling,  recompletions,  workovers and waterflood optimizations.  During the
first  quarter,  2.8 net wells were drilled,  with an additional 3.7 net wells
drilling at quarter-end.

Construction  of the  sub-sea  water  injection  pump at the Columba E Terrace
progressed  during  the first  quarter.  This  will be tied into 2  additional
sub-sea water injection wells that will be drilled late in 2006.

Further  development of the Lyell Field  progressed on schedule.  This project
comprises the drilling of 4 net wells and workovers at 2 existing wells during
2006  and  2007.  At its  peak,  the  Company's  share  of net  production  is
forecasted to be approximately 20,000 boe/d.


OFFSHORE WEST AFRICA

Offshore West Africa capital expenditures  included the drilling and tie in of
2 additional  wells at Baobab.  Both wells were tied into the Baobab  floating
production,  storage and offtake vessel  ("FPSO")  during the first quarter of
2006.

At East Espoir,  the 2 remaining planned wells were successfully  delivered in
the  first  quarter  of 2006.  The  drilling  of these  wells  was a result of
additional testing and evaluation that revealed a larger quantity of crude oil
in place,  based upon reservoir studies and production  history to date. These
new producer  wells will  effectively  exploit this  additional  potential and
could  increase the  recoverable  resources  and  production.  The West Espoir
drilling tower, which will facilitate  development  drilling of the reservoir,
is on site and was installed in late 2005. This project is progressing on time
and on budget with first crude oil expected in 2006,  increasing the Company's
share of net production to approximately 13,000 boe/d once fully developed.

The  Company  purchased  a 90%  interest  in the Olowi PSC  offshore  Gabon in
October  2005  and  received   approval  of  its  development  plan  for  this
acquisition  during the first  quarter of 2006.  Development  plans include an
FPSO,  handling  input from two or three  shallow-water  producing  platforms.
Following engineering design and request for tenders,  development is expected
to  begin  in late  2006,  with  first  oil  expected  late in 2008 and a peak
production rate of approximately 20,000 bbl/d.

  CANADIAN NATURAL RESOURCES LIMITED                                       33
==============================================================================
<PAGE>

LIQUIDITY AND CAPITAL RESOURCES
<TABLE>
<CAPTION>
                                                       ---------------
($ millions, except ratios)                                 MAR 31            Dec 31          Mar 31
                                                              2006              2005            2005
-----------------------------------------------------------------------------------------------------
<S>                                                    <C>              <C>              <C>
Working capital deficit(1)                             $     2,065      $      1,774     $     1,288
Long-term debt                                         $     4,342      $      3,321     $     3,831

Shareholders' equity
Share capital                                          $     2,500      $      2,442     $     2,416
Retained earnings                                            5,821             5,804           4,468
Foreign currency translation adjustment                        (11)               (9)             (6)
-----------------------------------------------------------------------------------------------------
Total                                                  $     8,310      $      8,237     $     6,878

Debt to cash flow(2)                                          0.9X              0.7x            1.0x
Debt to EBITDA(3)                                             0.8X              0.6x            0.9x
Debt to book capitalization(4)                               34.3%             28.7%           36.9%
Debt to market capitalization                                11.1%              9.7%           18.0%
After tax return on average common
     shareholders' equity(5)                                 20.3%             14.3%           10.7%
After tax return on average capital
     employed(6)                                             14.2%             10.4%            8.1%
=====================================================================================================
</TABLE>
(1)  CALCULATED AS CURRENT ASSETS LESS CURRENT LIABILITIES.

(2)  CALCULATED  AS  CURRENT  AND  LONG-TERM  DEBT;  DIVIDED BY CASH FLOW FROM
     OPERATIONS FOR THE TWELVE MONTH TRAILING PERIOD.

(3)  CALCULATED  AS CURRENT AND  LONG-TERM  DEBT;  DIVIDED BY EARNINGS  BEFORE
     INTEREST,  TAXES,   DEPRECIATION,   DEPLETION  AND  AMORTIZATION,   ASSET
     RETIREMENT OBLIGATION ACCRETION, UNREALIZED FOREIGN EXCHANGE, STOCK-BASED
     COMPENSATION  EXPENSE AND UNREALIZED RISK  MANAGEMENT  ACTIVITIES FOR THE
     TWELVE MONTH TRAILING PERIOD.

(4)  CALCULATED  AS CURRENT AND LONG-TERM  DEBT;  DIVIDED BY THE BOOK VALUE OF
     COMMON SHAREHOLDERS' EQUITY PLUS CURRENT AND LONG-TERM DEBT.

(5)  CALCULATED  AS NET  EARNINGS FOR THE TWELVE  MONTH  TRAILING  PERIOD AS A
     PERCENTAGE OF AVERAGE COMMON SHAREHOLDERS' EQUITY FOR THE PERIOD.

(6)  CALCULATED AS NET EARNINGS PLUS AFTER-TAX INTEREST EXPENSE FOR THE TWELVE
     MONTH TRAILING  PERIOD;  AS A PERCENTAGE OF AVERAGE CAPITAL  EMPLOYED FOR
     THE PERIOD.  AVERAGE CAPITAL EMPLOYED IS THE AVERAGE SHAREHOLDERS' EQUITY
     AND CURRENT AND LONG-TERM DEBT FOR THE PERIOD.

The Company's  capital  resources at March 31, 2006 consist  primarily of cash
flow  from  operations,   access  to  capital  markets  and  available  credit
facilities. Cash flow from operations is dependent on factors discussed in the
Risks and  Uncertainties  section of the  Company's  December  31, 2005 annual
MD&A. The Company's  ability to renew existing credit facilities and raise new
debt is dependent  upon these factors,  maintaining  an investment  grade debt
rating and the condition of capital and credit  markets.  Management  believes
internally  generated  cash  flows  supported  by  the  implementation  of the
Company's hedge policy,  the flexibility of its capital  expenditure  programs
supported by its five and ten year  financial  plans,  the Company's  existing
credit  facilities  and the  Company's  ability  to raise  new  debt,  will be
sufficient to sustain its operations and support its growth strategy.

At March 31,  2006 the  Company  had  undrawn  bank  lines of credit of $2,687
million.  These credit lines are supported by credit facilities,  which if not
extended, mature in 2008, 2009 and 2010.

  34                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

At March 31, 2006, the working capital deficit was $2,065 million and included
the  current  portion  of  other  long-term  liabilities  of  $1,397  million,
comprised of stock-based  compensation of $629 million and the  mark-to-market
valuation of non-designated risk management financial  derivative  instruments
of $768 million.  The repayment of the stock-based  compensation  liability is
dependant upon both the surrender of vested stock options for cash  settlement
by  employees  and the  value  of the  Company's  share  price  at the time of
surrender.  The  cash  settlement  amount  of the  risk  management  financial
derivative instruments may vary materially depending upon the underlying crude
oil and natural gas prices at the time of final  settlement  of the  financial
derivative instruments, as compared to their mark-to-market value at March 31,
2006.

The Company is committed to maintaining a strong  financial  position.  In the
first quarter of 2006,  strong  operational  results and high commodity prices
resulted in a debt to book capitalization level of 34.3%. The Company believes
it has the necessary  financial capacity to complete the Horizon Project while
at the same  time not  compromising  delivery  of  conventional  crude oil and
natural  gas growth  opportunities.  The  financing  of Phase 1 of the Horizon
Project development is guided by the competing principles of retaining as much
direct  ownership  interest as possible  while  maintaining  a strong  balance
sheet.  Existing proved development  projects,  which have largely been funded
prior to March 31, 2006, such as Baobab,  Primrose and West Espoir may provide
identified growth in production volumes in 2006 through 2008, and may generate
incremental free cash flows during this period.

The Company's commodity hedging program was put in place to reduce the risk of
volatility in commodity  price markets and to underpin the Company's cash flow
for its capital  expenditures program through the Horizon Project construction
period.  This expanded program allows for the economic hedging of up to 75% of
the near 12 months  budgeted  production,  up to 50% of the following 13 to 24
months estimated  production and up to 25% of production expected in months 25
to 48 through the use of derivative financial instruments.  For the purpose of
this  program,  the  purchase  of crude oil put  options is in addition to the
above parameters. As a result, approximately 75% of budgeted crude oil volumes
and approximately 55% of budgeted natural gas volumes have been hedged through
the use of collars for the remainder of 2006.

LONG-TERM DEBT

Long-term  debt as at March 31,  2006 was $4,342  million.  The debt to EBITDA
ratio was 0.8x (December 31, 2005 - 0.6x;  March 31, 2005 - 0.9x) and the debt
to book  capitalization was 34.3% (December 31, 2005 - 28.7%; March 31, 2005 -
36.9%) as at March 31, 2006.  These ratios are  currently  below the Company's
guidelines for balance sheet  management of debt to EBITDA of 1.5x to 2.0x and
debt to book capitalization of 35% to 45%.

OPERATING FACILITIES

As at March 31, 2006 the Company had in place unsecured syndicated bank credit
facilities of $3,455 million, comprised of:

    --   a $100 million operating demand credit facility;

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

    --   a 5-year  revolving credit and term loan facility of $1,500 million;
         and

    --   an unsecured  (pound  sterling)15  million  demand  overdraft  credit
         facility for the Company's North Sea operations.

The first  $1,000  million  tranche of the $1,825  million  facility  is fully
revolving for a period of three years  maturing June 2008.  The second tranche
of $825 million is fully  revolving  for a period of five years  maturing June
2010. Both tranches are extendible annually for one year periods at the mutual
agreement of the Company and the lenders. If the facility is not extended, the
full amount of the outstanding  principal would be repayable on the respective
maturity  dates.  The $1,500  million  credit and term loan  facility is fully
revolving for a period of five years maturing  December 2009. The facility has
three,  one year extension  provisions at the mutual  agreement of the Company
and the  lenders.  If the  facility  is not  extended,  the full amount of the
outstanding principal would be repayable on the maturity date.

In  addition  to the  outstanding  debt,  letters  of credit  and  performance
guarantees aggregating $65 million were also outstanding at March 31, 2006.

  CANADIAN NATURAL RESOURCES LIMITED                                       35
==============================================================================
<PAGE>

MEDIUM-TERM NOTES

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

US DOLLAR DEBT SECURITIES

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

SHARE CAPITAL

As at March 31, 2006, there were 537,272,000 common shares outstanding.  As at
May 3, 2006, the Company had 537,390,000 common shares outstanding.

In January 2006 the Company  announced the renewal of its Normal Course Issuer
Bid through the  facilities  of the Toronto  Stock  Exchange  and the New York
Stock  Exchange  to  purchase  up to  26,852,545  common  shares  or 5% of the
outstanding  common  shares of the  Company  on the date of the  announcement,
during the 12-month period  beginning  January 24, 2006 and ending January 23,
2007.  As at May 3, 2006,  the Company had not  purchased any shares under its
Normal Course Issuer Bid.

In February 2006, the Company's Board of Directors approved an increase in the
annual  dividend  paid by the Company  from $0.236 in 2005 to $0.30 per common
share for 2006.


CONTRACTUAL OBLIGATIONS

In the normal  course of  business,  the  Company  has  entered  into  various
contractual  arrangements  and  commitments  that  will  have an impact on the
Company's future  operations.  These  contractual  obligations and commitments
primarily relate to debt repayments, operating leases relating to office space
and  offshore  production  and  storage  vessels,  and  firm  commitments  for
gathering,  processing  and  transmission  services,  as well as  expenditures
relating to asset retirement obligations. The Company has not entered into any
contracts that would require  consolidation  under CICA  Accounting  Handbook,
AcG-15,  Consolidation  of Variable  Interest  Entities.  The following  table
summarizes the Company's commitments as at March 31, 2006:

<TABLE>
<CAPTION>
($ millions)                                   2006          2007         2008        2009     2010     Thereafter
-------------------------------------------------------------------------------------------------------------------
<S>                                       <C>           <C>           <C>            <C>        <C>     <C>
Product transportation and
pipeline(1)                               $     156     $     169     $    174       $ 121      112     $    1,121

Offshore equipment operating lease        $      39     $      51     $     52       $  51       51     $      180

Offshore drilling                         $     104     $     132     $     40       $   -        -     $        -

Asset retirement obligations(2)           $      67     $       4     $      4       $   4        7     $    3,274

Long-term debt(3)                         $       -     $     161     $     36       $  36        -     $    3,368

Other(4)                                  $      47     $      65     $     26       $  33       27     $       11
===================================================================================================================
</TABLE>
(1)  IN 2005,  THE  COMPANY  ENTERED  INTO A 25 YEAR  PIPELINE  TRANSPORTATION
     AGREEMENT COMMENCING IN 2008, RELATED TO FUTURE CRUDE OIL PRODUCTION. THE
     AGREEMENT IS RENEWABLE FOR  SUCCESSIVE  10-YEAR  PERIODS AT THE COMPANY'S
     OPTION.  DURING THE INITIAL TERM,  ANNUAL TOLL PAYMENTS BEFORE  OPERATING
     COSTS WILL BE APPROXIMATELY $35 MILLION.

(2)  REPRESENTS  MANAGEMENT'S  ESTIMATE OF THE FUTURE UNDISCOUNTED PAYMENTS TO
     SETTLE  ASSET  RETIREMENT  OBLIGATIONS  RELATED TO  RESOURCE  PROPERTIES,
     FACILITIES,  AND PRODUCTION  PLATFORMS,  BASED ON CURRENT LEGISLATION AND
     INDUSTRY OPERATING PRACTICES.

(3)  NO DEBT  REPAYMENTS  ARE REFLECTED FOR THE BANK CREDIT  FACILITIES DUE TO
     THE EXTENDABLE NATURE OF THE FACILITIES.

(4)  CONSISTS  OF FUTURE  EXPENDITURES  RELATED  PRIMARILY  TO  OFFICE  LEASE,
     ELECTRICITY AND CRUDE OIL PROCESSING.

  36                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

The Board of Directors has approved the construction  costs for Phase 1 of the
Horizon  Project,  which  are  budgeted  to  be  $6.8  billion,   including  a
contingency fund of $700 million,  with cumulative spending of $1.9 billion to
March 31, 2006, $2.0 billion  targeted to be incurred in the remainder of 2006
and $2.9 billion targeted to be incurred in 2007 and 2008.

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


CRITICAL ACCOUNTING ESTIMATES

The  preparation  of  financial   statements  requires  the  Company  to  make
judgements, assumptions and estimates in the application of generally accepted
accounting  principles that have a significant impact on the financial results
of  the  Company.   Actual  results  could  differ  from  those  estimates.  A
comprehensive  discussion of the Company's significant  accounting policies is
contained in the MD&A and the audited  consolidated  financial  statements for
the year ended December 31, 2005.


SENSITIVITY ANALYSIS (1)

The following table is indicative of the annualized sensitivities of cash flow
from  operations and net earnings from changes in certain key  variables.  The
analysis is based on business  conditions  and  production  volumes during the
first quarter of 2006.  Each separate item in the  sensitivity  analysis shows
the effect of an increase in that variable only; all other  variables are held
constant.

<TABLE>
<CAPTION>
                                                                        CASH FLOW
                                                      CASH FLOW              FROM                                NET
                                                           FROM        OPERATIONS              NET          EARNINGS
                                                     OPERATIONS       (PER COMMON         EARNINGS       (PER COMMON
                                                   ($ MILLIONS)     SHARE, BASIC)     ($ MILLIONS)     SHARE, BASIC)
---------------------------------------------------------------------------------------------------------------------
<S>                                                <C>             <C>                <C>              <C>
PRICE CHANGES
Crude oil - WTI US$1.00/bbl(2)
   Excluding financial derivatives                 $       102     $         0.19     $         71     $        0.13
   Including financial derivatives                 $        68     $         0.13     $         46     $        0.09
Natural gas - AECO C$0.10/mcf(2)
   Excluding financial derivatives                 $        38     $         0.07     $         25     $        0.05
   Including financial derivatives                 $        26     $         0.05     $         17     $        0.03
VOLUME CHANGES
Crude oil - 10,000 bbl/d                           $        89     $         0.17     $         42     $        0.08
Natural gas  - 10 mmcf/d                           $        21     $         0.04     $         10     $        0.02
FOREIGN CURRENCY RATE CHANGE
$0.01 change in C$ in relation to US$(2)           $        61     $         0.11     $         19     $        0.03
INTEREST RATE CHANGE - 1%                          $        10     $         0.02     $         10     $        0.02
=====================================================================================================================
</TABLE>
(1)  THE SENSITIVITIES ARE CALCULATED BASED ON 2006 FIRST QUARTER RESULTS
     EXCLUDING MARK-TO-MARKET GAINS (LOSSES) ON RISK MANAGEMENT ACTIVITIES.

(2)  FOR DETAILS OF OUTSTANDING FINANCIAL INSTRUMENTS IN PLACE, REFER TO NOTE
     7 OF THE COMPANY'S UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS.

  CANADIAN NATURAL RESOURCES LIMITED                                       37
==============================================================================
<PAGE>

OTHER OPERATING HIGHLIGHTS

NETBACK ANALYSIS
<TABLE>
<CAPTION>
                                                                           Three Months Ended
                                                       -------------------
                                                                MAR 31              Dec 31              Mar 31
($/boe)(1)                                                        2006                2005                2005
---------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                 <C>                 <C>
Sales price(2)                                         $         46.30     $         56.08     $         39.94
Royalties                                                         6.44                8.01                5.42
Production expense(3)                                             8.46                7.93                8.04
---------------------------------------------------------------------------------------------------------------
NETBACK                                                          31.40               40.14               26.48
Midstream contribution(3)                                        (0.25)              (0.25)              (0.31)
Administration                                                    0.85                0.68                0.74
Interest, net                                                     0.51                0.53                0.91
Realized risk management loss                                     7.90                9.07                1.83
Realized foreign exchange gain                                   (0.12)              (0.29)              (0.25)
Taxes other than income tax - current                             0.71                0.93                0.87
Current income tax - North America                                0.29                0.04                0.63
Current income tax - Large corporations tax                       0.07                0.11                0.05
Current income tax - North Sea                                    0.01                0.59                0.81
Current income tax - Offshore West Africa                         0.27                0.35                0.06
Current income tax - other                                           -                0.02                   -
---------------------------------------------------------------------------------------------------------------
CASH FLOW                                              $         21.16     $         28.36     $         21.14
===============================================================================================================
</TABLE>
(1)  AMOUNTS EXPRESSED ON A PER UNIT BASIS ARE BASED ON SALES VOLUMES.
(2)  INCLUDING TRANSPORTATION COSTS AND EXCLUDING RISK MANAGEMENT ACTIVITIES.
(3)  EXCLUDING INTERSEGMENT ELIMINATION.


  38                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

FINANCIAL STATEMENTS

CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
                                                                          ---------------
                                                                               MAR 31            Dec 31
(millions of Canadian dollars, unaudited)                                        2006              2005
--------------------------------------------------------------------------------------------------------
<S>                                                                       <C>              <C>
ASSETS
CURRENT ASSETS
   Cash and cash equivalents                                              $        12      $         18
   Accounts receivable and other                                                1,345             1,546
   Future income tax                                                              495               487
--------------------------------------------------------------------------------------------------------
                                                                                1,852             2,051
PROPERTY, PLANT AND EQUIPMENT                                                  21,465            19,694
OTHER LONG-TERM ASSETS                                                            122               107
--------------------------------------------------------------------------------------------------------
                                                                          $    23,439      $     21,852
========================================================================================================

LIABILITIES
CURRENT LIABILITIES
   Accounts payable                                                       $       621      $        573
   Accrued liabilities                                                          1,899             1,781
   Current portion of other long-term liabilities (note 3)                      1,397             1,471
--------------------------------------------------------------------------------------------------------
                                                                                3,917             3,825
LONG-TERM DEBT (note 2)                                                         4,342             3,321
OTHER LONG-TERM LIABILITIES (note 3)                                            1,526             1,434
FUTURE INCOME TAX                                                               5,344             5,035
--------------------------------------------------------------------------------------------------------
                                                                               15,129            13,615
--------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
SHARE CAPITAL (note 5)                                                          2,500             2,442
RETAINED EARNINGS                                                               5,821             5,804
FOREIGN CURRENCY TRANSLATION ADJUSTMENT                                           (11)               (9)
--------------------------------------------------------------------------------------------------------
                                                                                8,310             8,237
--------------------------------------------------------------------------------------------------------
                                                                          $    23,439      $     21,852
========================================================================================================
</TABLE>
COMMITMENTS (NOTE 8)


  CANADIAN NATURAL RESOURCES LIMITED                                       39
==============================================================================
<PAGE>

CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
<TABLE>
<CAPTION>
                                                                                Three Months Ended
                                                                          -----------------
                                                                                 MAR 31            Mar 31
(millions of Canadian dollars, except per common share amounts, unaudited)         2006              2005
----------------------------------------------------------------------------------------------------------
<S>                                                                       <C>                <C>
REVENUE                                                                   $       2,372      $      1,993
Less: royalties                                                                    (316)             (259)
----------------------------------------------------------------------------------------------------------
REVENUE, NET OF ROYALTIES                                                         2,056             1,734
----------------------------------------------------------------------------------------------------------
EXPENSES
Production                                                                          419               389
Transportation                                                                       81                67
Depletion, depreciation and amortization                                            521               474
Asset retirement obligation accretion (note 3)                                       17                18
Administration                                                                       42                35
Stock-based compensation (note 3)                                                   132               184
Interest, net                                                                        25                43
Risk management activities (note 7)                                                 396             1,085
Foreign exchange loss (gain)                                                          5               (12)
----------------------------------------------------------------------------------------------------------
                                                                                  1,638             2,283
----------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) BEFORE TAXES                                                        418              (549)
Taxes other than income tax                                                          61                42
Current income tax expense (note 4)                                                  32                74
Future income tax expense (recovery) (note 4)                                       268              (241)
----------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)                                                       $          57      $       (424)
----------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS) PER COMMON SHARE (note 6)
   Basic and diluted                                                      $        0.11      $      (0.79)
==========================================================================================================

CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                                                                   Three Months Ended
                                                                          -----------------
                                                                                 MAR 31            Mar 31
(millions of Canadian dollars, unaudited)                                          2006              2005
----------------------------------------------------------------------------------------------------------
BALANCE - BEGINNING OF PERIOD                                             $       5,804      $      4,922
Net earnings (loss)                                                                  57              (424)
Dividends on common shares (note 5)                                                 (40)              (30)
----------------------------------------------------------------------------------------------------------
BALANCE - END OF PERIOD                                                   $       5,821      $      4,468
==========================================================================================================
</TABLE>


  40                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
                                                                                Three Months Ended
                                                                          -----------------
                                                                                 MAR 31            Mar 31
(millions of Canadian dollars, unaudited)                                          2006              2005
----------------------------------------------------------------------------------------------------------
<S>                                                                       <C>                <C>
OPERATING ACTIVITIES
Net earnings (loss)                                                       $          57      $       (424)
Non-cash items
   Depletion, depreciation and amortization                                         521               474
   Asset retirement obligation accretion                                             17                18
   Stock-based compensation                                                         132               184
   Unrealized risk management activities                                              8               998
   Unrealized foreign exchange loss                                                  10                 -
   Deferred petroleum revenue tax                                                    26                 -
   Future income tax expense (recovery)                                             268              (241)
Deferred charges                                                                    (15)               (5)
Abandonment expenditures                                                            (15)               (4)
Net change in non-cash working capital                                             (311)             (222)
----------------------------------------------------------------------------------------------------------
                                                                                    698               778
----------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Issue of bankers' acceptances                                                       619               273
Issue of medium-term notes                                                          400                 -
Issue of common shares on exercise of stock options                                  10                 2
Dividends on common shares                                                          (32)              (27)
Net change in non-cash working capital                                                2                16
----------------------------------------------------------------------------------------------------------
                                                                                    999               264
----------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant and equipment                                    (2,294)           (1,368)
Net change in non-cash working capital                                              591               339
----------------------------------------------------------------------------------------------------------
                                                                                 (1,703)           (1,029)
----------------------------------------------------------------------------------------------------------
(DECREASE) INCREASE IN CASH                                                          (6)               13
CASH - BEGINNING OF PERIOD                                                           18                28
----------------------------------------------------------------------------------------------------------
CASH - END OF PERIOD                                                      $          12      $         41
==========================================================================================================
INTEREST PAID                                                             $          52      $         44
TAXES PAID
   Taxes other than income tax                                            $          81      $        110
   Current income tax                                                     $         173      $        111
==========================================================================================================
</TABLE>


  CANADIAN NATURAL RESOURCES LIMITED                                       41
==============================================================================
<PAGE>

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

1.   ACCOUNTING POLICIES

The interim  consolidated  financial  statements of Canadian Natural Resources
Limited (the "Company")  include the Company and all of its  subsidiaries  and
partnerships, and have been prepared following the same accounting policies as
the audited  consolidated  financial  statements of the Company as at December
31, 2005. The interim  consolidated  financial  statements contain disclosures
that are supplemental to the Company's annual audited  consolidated  financial
statements.  Certain  disclosures that are normally required to be included in
the notes to the annual audited  consolidated  financial  statements have been
condensed.  These financial  statements should be read in conjunction with the
Company's audited consolidated  financial statements and notes thereto for the
year ended December 31, 2005.


COMPARATIVE FIGURES

Certain figures provided for the prior year have been  reclassified to conform
to the presentation adopted in 2006.


2.   LONG-TERM DEBT
<TABLE>
<CAPTION>
                                                                          ----------------
                                                                                MAR 31             Dec 31
                                                                                  2006               2005
----------------------------------------------------------------------------------------------------------
<S>                                                                       <C>               <C>
Bank credit facilities
     Bankers' acceptances                                                 $        741      $         122
Medium-term notes                                                                  925                525
Senior unsecured notes (2006 and 2005 - US$93 million)                             108                108
US dollar debt securities (2006 and 2005 - US$2,200 million)                     2,568              2,566
----------------------------------------------------------------------------------------------------------
                                                                          $      4,342      $       3,321
==========================================================================================================
</TABLE>


BANK CREDIT FACILITIES

As at March 31,  2006,  the Company  had in place  unsecured  syndicated  bank
credit facilities of $3,455 million, comprised of:

    o    a $100 million operating demand credit facility;

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

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

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

The first  $1,000  million  tranche of the $1,825  million  facility  is fully
revolving for a period of three years  maturing June 2008.  The second tranche
of $825 million is fully  revolving  for a period of five years  maturing June
2010. Both tranches are extendible annually for one year periods at the mutual
agreement of the Company and the lenders. If the facility is not extended, the
full amount of the outstanding  principal would be repayable on the respective
maturity  dates.  The $1,500  million  credit and term loan  facility is fully
revolving for a period of five years maturing  December 2009. The facility has
three,  one-year  extension  provisions at the mutual agreement of the Company
and the  lenders.  If the  facility  is not  extended,  the full amount of the
outstanding principal would be repayable on the maturity date.

The weighted average interest rate of the bank credit  facilities  outstanding
at March 31, 2006, was 4.4% (December 31, 2005 - 4.0%).

In  addition  to the  outstanding  debt,  letters  of credit  and  performance
guarantees aggregating $65 million were outstanding at March 31, 2006.

  42                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

MEDIUM-TERM NOTES

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


US DOLLAR DEBT SECURITIES

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


3.   OTHER LONG-TERM LIABILITIES
<TABLE>
<CAPTION>
                                                       ---------------------
                                                                  MAR 31                Dec 31
                                                                    2006                  2005
-----------------------------------------------------------------------------------------------
<S>                                                    <C>                    <C>
Asset retirement obligations                           $           1,118      $          1,112
Stock-based compensation                                             882                   891
Risk management (note 7)                                             893                   885
Other                                                                 30                    17
-----------------------------------------------------------------------------------------------
                                                                   2,923                 2,905
Less: current portion                                              1,397                 1,471
-----------------------------------------------------------------------------------------------
                                                       $           1,526      $          1,434
===============================================================================================
</TABLE>

ASSET RETIREMENT OBLIGATIONS

At March 31, 2006, the Company's total estimated  undiscounted  cost to settle
its asset retirement  obligations was  approximately  $3,360 million (December
31, 2005 - $3,325 million). These costs will be incurred over the lives of the
operating  assets and have been  discounted  using an average  credit-adjusted
risk free rate of 6.8%. A  reconciliation  of the discounted  asset retirement
obligations is as follows:

<TABLE>
<CAPTION>
                                                       ---------------------
                                                            THREE MONTHS                  Year
                                                                   ENDED                 Ended
                                                            MAR 31, 2006          Dec 31, 2005
-----------------------------------------------------------------------------------------------
<S>                                                    <C>                    <C>
Balance - beginning of period                          $           1,112      $          1,119
     Liabilities incurred                                              5                    47
     Liabilities settled                                             (15)                  (46)
     Asset retirement obligation accretion                            17                    69
     Revision of estimates                                             -                   (56)
     Foreign exchange                                                 (1)                  (21)
-----------------------------------------------------------------------------------------------
Balance - end of period                                $           1,118      $          1,112
===============================================================================================
</TABLE>

The Company's pipelines have indeterminant lives 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
years in which the lives of the assets are determinable.

  CANADIAN NATURAL RESOURCES LIMITED                                       43
==============================================================================
<PAGE>

STOCK-BASED COMPENSATION

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

<TABLE>
<CAPTION>
                                                       --------------------
                                                           THREE MONTHS                  Year
                                                                  ENDED                 Ended
                                                           MAR 31, 2006          Dec 31, 2005
----------------------------------------------------------------------------------------------
<S>                                                    <C>                   <C>
Balance - beginning of period                          $            891      $            323
     Stock-based compensation provision                             132                   723
     Current period payment for options surrendered                (123)                 (227)
     Transferred to common shares                                   (48)                  (29)
     Capitalized to Horizon Project                                  30                   101
----------------------------------------------------------------------------------------------
Balance - end of period                                             882                   891
Less: current portion of stock-based compensation                   629                   629
----------------------------------------------------------------------------------------------
                                                       $            253      $            262
==============================================================================================
</TABLE>

4.   INCOME TAXES

The provision for income taxes is as follows:
<TABLE>
<CAPTION>
                                                            Three Months Ended
                                                       ----------------
                                                             MAR 31                    Mar 31
                                                               2006                      2005
----------------------------------------------------------------------------------------------
<S>                                                    <C>                 <C>
Current income tax - North America                     $         15        $               30
Large corporations tax - North America                            3                         2
Current income tax - North Sea                                    1                        39
Current income tax - Offshore West Africa                        13                         3
----------------------------------------------------------------------------------------------
Current income tax expense                                       32                        74
Future income tax expense (recovery)                            268                      (241)
----------------------------------------------------------------------------------------------
Income tax expense (recovery)                          $        300        $             (167)
==============================================================================================
</TABLE>

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

Effective January 1, 2006, the UK government substantively enacted an increase
to the supplementary charge on profits from UK North Sea crude oil and natural
gas production from 10% to 20%,  increasing the Company's effective income tax
rate in the North Sea to approximately 50%. The supplementary  charge excludes
any deduction for financing  costs.  The Company's future income tax liability
was increased by $110 million as at January 1, 2006,  with respect to this tax
rate change.

Subsequent  to March 31,  2006,  the  provinces  of Alberta  and  Saskatchewan
substantively enacted reductions in their corporate income tax rates that will
result in a reduction of future tax liabilities of approximately $160 million.
This  reduction  will  be  reflected  in the  Company's  reported  results  of
operations in the second quarter of 2006.

  44                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

5.   SHARE CAPITAL

<TABLE>
<CAPTION>
                                                                          --------------------------------------------
                                                                               Three Months Ended Mar 31, 2006

ISSUED                                                                      NUMBER OF SHARES
COMMON SHARES                                                                    (thousands)                   AMOUNT
----------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>         <C>
Balance - beginning of period                                                        536,348     $              2,442
     Issued upon exercise of stock options                                               924                       10
     Previously recognized liability on stock options exercised for
         common shares                                                                     -                       48
----------------------------------------------------------------------------------------------------------------------
Balance - end of period                                                              537,272     $              2,500
======================================================================================================================
</TABLE>

NORMAL COURSE ISSUER BID

In January 2006, the Company announced the renewal of its Normal Course Issuer
Bid through the  facilities  of the Toronto  Stock  Exchange  and the New York
Stock  Exchange  to  purchase  up to  26,852,545  common  shares  or 5% of the
outstanding  common  shares of the  Company  on the date of the  announcement,
during the 12-month period  beginning  January 24, 2006 and ending January 23,
2007. As at March 31, 2006, the Company had not purchased any shares under the
Normal Course Issuer Bid.


DIVIDEND POLICY

In February 2006, the Board of Directors set the regular quarterly dividend at
$0.075 per common  share (2005 - $0.059 per common  share).  The Company  pays
regular quarterly dividends in January, April, July, and October of each year.


STOCK OPTIONS
<TABLE>
<CAPTION>
                                                       -------------------------------------------
                                                              Three Months Ended Mar 31, 2006
                                                           STOCK OPTIONS         WEIGHTED AVERAGE
                                                             (thousands)           EXERCISE PRICE
--------------------------------------------------------------------------------------------------
<S>                                                               <C>        <C>
Outstanding - beginning of period                                 30,510     $              17.79
     Granted                                                       4,407     $              60.33
     Exercised for common shares                                    (924)    $               9.19
     Surrendered for cash settlement                              (2,661)    $              12.07
     Forfeited                                                      (375)    $              30.09
--------------------------------------------------------------------------------------------------
Outstanding - end of period                                       30,957     $              24.44
--------------------------------------------------------------------------------------------------
Exercisable - end of period                                       10,075     $              13.27
==================================================================================================
</TABLE>


  CANADIAN NATURAL RESOURCES LIMITED                                       45
==============================================================================
<PAGE>

6.   NET EARNINGS (LOSS) PER COMMON SHARE
<TABLE>
<CAPTION>
                                                                                      Three Months Ended
                                                                                --------------
                                                                                     MAR 31       Mar 31
                                                                                       2006     2005 (1)
---------------------------------------------------------------------------------------------------------
<S>                                                                             <C>          <C>
Weighted average common shares outstanding (thousands) - basic and diluted      $   537,227   $  536,330
---------------------------------------------------------------------------------------------------------
Net earnings (loss) - basic and diluted                                                  57         (424)
---------------------------------------------------------------------------------------------------------
Net earnings (loss) per common share - basic and diluted                        $      0.11   $    (0.79)
=========================================================================================================
</TABLE>
(1)  RESTATED TO REFLECT TWO-FOR-ONE COMMON SHARE SPLIT IN MAY 2005.

7.   FINANCIAL INSTRUMENTS

RISK MANAGEMENT

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
trading or other speculative purposes.

The  estimated  fair  values  of  non-designated  financial  derivatives  were
comprised as follows:

<TABLE>
<CAPTION>
                                               ---------------------------------
                                                THREE MONTHS ENDED MAR 31, 2006              Year Ended Dec 31, 2005
--------------------------------------------------------------------------------------------------------------------
                                                           RISK                                Risk
                                                     MANAGEMENT         DEFERRED         management         Deferred
Asset/(liability)                                MARK-TO-MARKET          REVENUE     mark-to-market          revenue
--------------------------------------------------------------------------------------------------------------------
<S>                                             <C>                <C>              <C>                 <C>
Balance - beginning of period                   $         (877)    $         (8)    $            66     $       (26)
Net cost of outstanding put options                        334                -                 190               -
Net change in fair value of outstanding
   derivative financial instruments                        (11)               -                (943)              -
Amortization of deferred revenue                             -                3                   -              18
--------------------------------------------------------------------------------------------------------------------
                                                          (554)              (5)               (687)             (8)
Add: Put premium financing obligations                    (334)               -                (190)              -
--------------------------------------------------------------------------------------------------------------------
Balance - end of period                                   (888)              (5)               (877)             (8)
Less: current portion                                      763                5                 834               8
--------------------------------------------------------------------------------------------------------------------
                                                $         (125)    $          -     $           (43)    $         -
====================================================================================================================
</TABLE>

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


  46                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

Net losses from risk management activities for the periods ended March 31 were
as follows:

<TABLE>
<CAPTION>
                                                                                    Three Months Ended
                                                                      -----------------------
                                                                                   MAR 31                      Mar 31
                                                                                     2006                        2005
----------------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>                     <C>
Net realized risk management loss                                     $               388     $                    87
Net unrealized risk management
   mark-to-market loss                                                                  8                         998
----------------------------------------------------------------------------------------------------------------------
                                                                      $               396     $                 1,085
======================================================================================================================
</TABLE>

As at March 31, 2006, the net unrecognized  liability related to the estimated
fair values of derivative financial instruments  designated as hedges was $521
million (December 31, 2005 - $990 million).


The Company had the following  financial  derivatives  outstanding as at March
31, 2006:

<TABLE>
<CAPTION>
                                         Remaining term            Volume               Average price             Index
------------------------------------------------------------------------------------------------------------------------
<S>                            <C>             <C>          <C>                 <C>                     <C>
CRUDE OIL
Crude oil price collars        Apr 2006        Dec 2006     160,000 bbl/d       US$38.17  -  US$48.16               WTI
                               Apr 2006        Dec 2006      90,000 bbl/d       US$45.00  -  US$77.93               WTI
                               Apr 2006        Dec 2006      22,000 bbl/d        C$46.53  -  C$58.67                WTI
Crude oil puts                 Apr 2006        Jul 2006      38,000 bbl/d              US$40.00                     WTI
                               Aug 2006        Dec 2006      51,000 bbl/d              US$50.00                     WTI
                               Jan 2007        Dec 2007     100,000 bbl/d              US$28.00                     WTI
                               Jan 2007        Dec 2007     100,000 bbl/d              US$45.00                     WTI
                               Jan 2007        Dec 2007     100,000 bbl/d              US$50.00                     WTI
Brent differential swaps       Apr 2006        Dec 2006      25,000 bbl/d               US$1.29         WTI/Dated Brent
                               Jan 2007        Dec 2007      50,000 bbl/d               US$1.34         WTI/Dated Brent
========================================================================================================================


                                         Remaining term            Volume                Average price            Index
------------------------------------------------------------------------------------------------------------------------
NATURAL GAS
AECO collars                  Apr 2006         Jun 2006      973,000 GJ/d         C$5.71  -   C$8.15               AECO
                              Apr 2006         Jun 2006      100,000 GJ/d         C$7.00  -  C$14.16               AECO
                              Jul 2006         Sep 2006      705,000 GJ/d         C$5.61  -   C$7.61               AECO
                              Jul 2006         Sep 2006      100,000 GJ/d         C$7.00  -  C$14.16               AECO
                              Oct 2006         Dec 2006      237,500 GJ/d         C$5.61  -   C$7.61               AECO
                              Oct 2006         Dec 2006      100,000 GJ/d         C$7.00  -  C$14.16               AECO
                              Nov 2006         Dec 2006      700,000 GJ/d         C$7.50  -  C$18.80               AECO
                              Jan 2007         Mar 2007      700,000 GJ/d         C$7.50  -  C$18.80               AECO
========================================================================================================================
</TABLE>


  CANADIAN NATURAL RESOURCES LIMITED                                       47
==============================================================================
<PAGE>

<TABLE>
<CAPTION>
                                                                     Amount
                                         Remaining term         ($ millions)     Fixed rate         Floating rate
------------------------------------------------------------------------------------------------------------------
<S>                              <C>                                 <C>              <C>        <C>
INTEREST RATE
Swaps - fixed to floating        Apr 2006   -  Oct 2012              US$350           5.45%      LIBOR(1) + 0.81%
                                 Apr 2006   -  Dec 2014              US$350           4.90%      LIBOR(1) + 0.38%

Swaps - floating to fixed        Apr 2006   -  Mar 2007                 C$4           7.36%               CDOR(2)
==================================================================================================================
</TABLE>
(1)   LONDON INTERBANK OFFERED RATE.
(2)  CANADIAN DEPOSIT OVERNIGHT RATE.

8.   COMMITMENTS

The Company has committed to certain payments as follows:

<TABLE>
<CAPTION>
                                      Remaining
                                        2006           2007          2008          2009         2010    Thereafter
-------------------------------------------------------------------------------------------------------------------
<S>                                <C>            <C>            <C>           <C>          <C>          <C>
Product transportation and
   pipeline(1)                     $     156      $     169      $    174      $    121     $    112     $   1,121
Offshore equipment operating
   lease                           $      39      $      51      $     52      $     51     $     51     $     180
Offshore drilling                  $     104      $     132      $     40      $      -     $      -     $       -
Asset retirement
   obligations(2)                  $      67      $       4      $      4      $      4     $      7     $   3,274
Other(3)                           $      47      $      65      $     26      $     33     $     27     $      11
===================================================================================================================
</TABLE>
(1)  THE COMPANY HAS ENTERED INTO A 25 YEAR PIPELINE TRANSPORTATION  AGREEMENT
     COMMENCING IN 2008, RELATED TO FUTURE CRUDE OIL PRODUCTION. THE AGREEMENT
     IS RENEWABLE FOR  SUCCESSIVE  10-YEAR  PERIODS AT THE  COMPANY'S  OPTION.
     DURING THE INITIAL TERM, THE ANNUAL TOLL PAYMENTS BEFORE  OPERATING COSTS
     WILL BE APPROXIMATELY $35 MILLION.

(2)  REPRESENTS  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.

(3)  CONSISTS  OF FUTURE  EXPENDITURES  RELATED  PRIMARILY  TO  OFFICE  LEASE,
     ELECTRICITY AND CRUDE OIL PROCESSING.

The Board of Directors has approved the construction  costs for Phase 1 of the
Horizon Oil Sands Project ("Horizon  Project"),  which are budgeted to be $6.8
billion,  including  a  contingency  fund of  $700  million,  with  cumulative
spending  of $1.9  billion to March 31,  2006,  $2.0  billion  targeted  to be
incurred in the remainder of 2006 and $2.9 billion  targeted to be incurred in
2007 and 2008.

  48                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

9.   SEGMENTED INFORMATION
<TABLE>
<CAPTION>
                                   NORTH AMERICA             NORTH SEA          OFFSHORE WEST AFRICA           MIDSTREAM
(millions of Canadian           Three Months Ended       Three Months Ended      Three Months Ended       Three Months Ended
dollars,  unaudited)                  Mar 31                   Mar 31                  Mar 31                   Mar 31
                                -----------           -----------            ----------            ----------
                                   2006       2005       2006        2005       2006       2005       2006          2005
----------------------------------------------------------------------------------------------------------------------------
<S>                               <C>        <C>          <C>         <C>        <C>         <C>        <C>           <C>
SEGMENTED REVENUE                 1,820      1,544        320         394        227         44         18            21
Less: royalties                    (310)      (257)       (1)          (1)       (5)         (1)         -             -
----------------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE, NET OF         1,510      1,287        319         393        222         43         18            21
   ROYALTIES
----------------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production                          312        275         81         101         22          8          5             6
Transportation                       88         70          3           6          -          -          -             -
Depletion, depreciation and
   amortization                     415        384         60          82         44          6          2             2
Asset retirement obligation
   accretion                          8          9          8           9          1          -          -             -
Realized risk management
   activities                       317         59         71          28          -          -          -             -
----------------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES          1,140        797        223         226         67         14          7             8
----------------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS (LOSS)
   BEFORE  THE FOLLOWING            370        490         96         167        155         29         11            13
----------------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration
Stock-based compensation
Interest, net
Unrealized risk management
   activities
Foreign exchange loss (gain)
----------------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED EXPENSES
----------------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) BEFORE TAXES
Taxes other than income tax
Current income tax expense
Future income tax expense
   (recovery)
----------------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)
============================================================================================================================
</TABLE>


  CANADIAN NATURAL RESOURCES LIMITED                                       49
==============================================================================
<PAGE>

<TABLE>
<CAPTION>
                                 INTER-SEGMENT ELIMINATION AND OTHER                               TOTAL
(millions of Canadian                    Three Months Ended                                 Three Months Ended
   dollars, unaudited)                         Mar 31                                            Mar 31
                                -------------------                     ------------------------
                                            2006                2005                     2006                2005
------------------------------------------------------------------------------------------------------------------
<S>                                          <C>                 <C>                    <C>                 <C>
SEGMENTED REVENUE                            (13)                (10)                   2,372               1,993
Less: royalties                                -                   -                     (316)               (259)
------------------------------------------------------------------------------------------------------------------
SEGMENTED REVENUE, NET OF                    (13)                (10)                   2,056               1,734
   ROYALTIES
------------------------------------------------------------------------------------------------------------------
SEGMENTED EXPENSES
Production                                    (1)                 (1)                     419                 389
Transportation                               (10)                 (9)                      81                  67
Depletion, depreciation and
   amortization                                -                   -                      521                 474
Asset retirement obligation
   accretion                                   -                   -                       17                  18
Realized risk management
   activities                                  -                   -                      388                  87
------------------------------------------------------------------------------------------------------------------
TOTAL SEGMENTED EXPENSES                     (11)                (10)                   1,426               1,035
------------------------------------------------------------------------------------------------------------------
SEGMENTED EARNINGS (LOSS)
   BEFORE THE FOLLOWING                       (2)                  -                      630                 699
------------------------------------------------------------------------------------------------------------------
NON-SEGMENTED EXPENSES
Administration                                                                             42                  35
Stock-based compensation                                                                  132                 184
Interest, net                                                                              25                  43
Unrealized risk management
   activities                                                                               8                 998
Foreign exchange loss (gain)                                                                5                 (12)
------------------------------------------------------------------------------------------------------------------
TOTAL NON-SEGMENTED EXPENSES                                                              212               1,248
------------------------------------------------------------------------------------------------------------------
EARNINGS (LOSS) BEFORE TAXES                                                              418                (549)
Taxes other than income tax                                                                61                  42
Current income tax expense                                                                 32                  74
Future income tax expense
   (recovery)                                                                             268                (241)
------------------------------------------------------------------------------------------------------------------
NET EARNINGS (LOSS)                                                                        57                (424)
==================================================================================================================
</TABLE>


  50                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

NET ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
                                                                      Three Months Ended

                                                 MAR 31, 2006                                      Mar 31, 2005
                              --------------------------------------------------
                                                   NON-CASH/                                       Non-Cash/
                                      CASH        FAIR VALUE      CAPITALIZED             Cash    Fair Value     Capitalized
                              EXPENDITURES        CHANGES(1)            COSTS     Expenditures    Changes(1)           Costs
-----------------------------------------------------------------------------------------------------------------------------
<S>                            <C>               <C>             <C>              <C>             <C>               <C>
North America                  $     1,404       $        5      $      1,409     $        940    $        9        $    949
North Sea                              138                -               138               57             -              57
Offshore West Africa                    50                -                50              144             -             144
Other                                    7                -                 7                4             -               4
Horizon Project(2)                     686                -               686              215             -             215
Midstream                                3                -                 3                4             -               4
Head office                              6                -                 6                4             -               4
-----------------------------------------------------------------------------------------------------------------------------
                               $     2,294       $         5     $      2,299     $      1,368    $        9        $  1,377
=============================================================================================================================
</TABLE>
(1)  ASSET  RETIREMENT  OBLIGATIONS,  FUTURE INCOME TAX ADJUSTMENTS ON NON-TAX
     BASE ASSETS, AND OTHER FAIR VALUE ADJUSTMENTS.
(2)  CASH  EXPENDITURES  ALSO INCLUDE  CAPITALIZED  INTEREST  AND  STOCK-BASED
     COMPENSATION.

CAPITALIZED INTEREST

Beginning in 2005,  following the Board of Directors'  approval of the Horizon
Project, the Company commenced  capitalization of construction period interest
based  on  costs  incurred  and  the  Company's  cost of  borrowing.  Interest
capitalization  ceases once  construction is substantially  complete.  For the
three  months  ended  March 31,  2006,  pre-tax  interest  of $33  million was
capitalized to the Horizon Project (March 31, 2005 - $11 million).

<TABLE>
<CAPTION>
                                        Property, plant and equipment                         Total assets
                                 -------------------                     --------------------
                                          MAR 31              Dec 31               MAR 31                Dec 31
                                            2006                2005                 2006                  2005
----------------------------------------------------------------------------------------------------------------
<S>                              <C>                  <C>                 <C>                 <C>
SEGMENTED ASSETS
North America                    $        15,301      $       14,310      $        16,721     $          15,939
North Sea                                  1,761               1,681                2,004                 1,950
Offshore West Africa                       1,256               1,253                1,396                 1,371
Other                                         20                  13                   31                    30
Horizon Project                            2,855               2,169                2,928                 2,239
Midstream                                    204                 203                  291                   258
Head office                                   68                  65                   68                    65
----------------------------------------------------------------------------------------------------------------
                                 $        21,465      $       19,694      $        23,439     $          21,852
================================================================================================================
</TABLE>


  CANADIAN NATURAL RESOURCES LIMITED                                       51
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<PAGE>

SUPPLEMENTARY INFORMATION


INTEREST COVERAGE RATIOS

The following  financial  ratios are provided in connection with the Company's
continuous offering of medium-term notes pursuant to the short form prospectus
dated  August  2005.   These  ratios  are  based  on  the  Company's   interim
consolidated  financial  statements  that  are  prepared  in  accordance  with
accounting principles generally accepted in Canada.

Interest coverage ratios for the twelve month period ended March 31, 2006:
-------------------------------------------------------------------------------
Interest coverage (times)
     Net earnings(1)                                                     12.3x
     Cash flow from operations(2)                                        24.1x
===============================================================================
(1)  NET EARNINGS PLUS INCOME TAXES AND INTEREST  EXPENSE;  DIVIDED BY THE SUM
     OF INTEREST EXPENSE AND CAPITALIZED INTEREST.

(2)  CASH FLOW FROM OPERATIONS PLUS CURRENT INCOME TAXES AND INTEREST EXPENSE;
     DIVIDED BY THE SUM OF INTEREST EXPENSE AND CAPITALIZED INTEREST.





  52                                      CANADIAN NATURAL RESOURCES LIMITED
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<PAGE>

FORWARD-LOOKING STATEMENTS

Certain  statements  in this  document  or  documents  incorporated  herein by
reference  for  Canadian  Natural   Resources   Limited  (the  "Company")  may
constitute  "forward-looking  statements"  within  the  meaning  of the United
States Private Litigation Reform Act of 1995. These forward-looking statements
can generally be  identified as such because of the context of the  statements
including  words such as the  Company  "believes",  "anticipates",  "expects",
"plans", "estimates", or words of a similar nature.

The  forward-looking  statements  are based on  current  expectations  and are
subject to known and unknown risks,  uncertainties  and other factors that may
cause the actual  results,  performance  or  achievements  of the Company,  or
industry  results,  to  be  materially  different  from  any  future  results,
performance  or  achievements  expressed  or implied  by such  forward-looking
statements.  Such factors include, among others: general economic and business
conditions which will, among other things, impact demand for and market prices
of  the  Company's  products;   foreign  currency  exchange  rates;   economic
conditions  in the  countries  and  regions  in  which  the  Company  conducts
business;  political uncertainty,  including actions of or against terrorists,
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,  availability
and cost of seismic,  drilling and other equipment;  ability of the Company to
complete  its  capital  programs;  ability  of the  Company to  transport  its
products  to market;  potential  delays or  changes  in plans with  respect to
exploration or development  projects or capital  expenditures;  ability of the
Company  to attract  the  necessary  labour  required  to build its  projects;
operating hazards and other  difficulties  inherent in the exploration for and
production  and sale of crude oil and natural  gas;  availability  and cost of
financing;  success of  exploration  and  development  activities;  timing and
success of  integrating  the business and  operations  of acquired  companies;
production levels;  uncertainty of reserve estimates;  actions by governmental
authorities;  government  regulations and the expenditures  required to comply
with them (especially  safety and environmental  laws and regulations);  asset
retirement  obligations;   and  other  circumstances  affecting  revenues  and
expenses.  The  impact  of any  one  factor  on a  particular  forward-looking
statement   is  not   determinable   with   certainty   as  such  factors  are
interdependent  upon other factors,  and the Company's  course of action would
depend upon its  assessment of the future  considering  all  information  then
available.  Statements relating to "reserves" are deemed to be forward-looking
statements as they involve the implied  assessment based on certain  estimates
and assumptions that the reserves described can be profitably  produced in the
future.  Readers are cautioned that the foregoing list of important factors is
not exhaustive.  Although the Company believes that the expectations  conveyed
by  the  forward-looking   statements  are  reasonable  based  on  information
available  to it on the date such  forward-looking  statements  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                                       53
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<PAGE>

<TABLE>
<CAPTION>
CORPORATE INFORMATION

OFFICERS

   <S>                                                 <C>
   Allan P. Markin*                                                                  Randall S. Davis*
   CHAIRMAN OF THE BOARD                               VICE-PRESIDENT, FINANCIAL ACCOUNTING & CONTROLS

   N. Murray Edwards*                                                                   Larry C. Galea
   VICE-CHAIRMAN OF THE BOARD                                      VICE-PRESIDENT, OPERATIONS PLANNING

   John G. Langille*                                                                   Jerry W. Harvey
   VICE-CHAIRMAN OF THE BOARD                                    VICE-PRESIDENT, COMMERCIAL OPERATIONS

   Steve W. Laut*                                                                      Peter J. Janson
   PRESIDENT & CHIEF OPERATING OFFICER                         VICE-PRESIDENT, ENGINEERING INTEGRATION

   Douglas A. Proll*                                                                  Terry J. Jocksch
   CHIEF FINANCIAL OFFICER &                                       VICE-PRESIDENT, EXPLOITATION - EAST
   SENIOR VICE-PRESIDENT, FINANCE
                                                                                   Christopher M. Kean
   Real M. Cusson*                                                VICE-PRESIDENT, UTILITIES & OFFSITES
   SENIOR VICE-PRESIDENT, MARKETING
                                                                                       Philip A. Keele
   Real J.H. Doucet*                                                            VICE-PRESIDENT, MINING
   SENIOR VICE-PRESIDENT, OIL SANDS
                                                                                     Cameron S. Kramer
   Allen M. Knight*                                                   VICE-PRESIDENT, FIELD OPERATIONS
   SENIOR VICE-PRESIDENT, INTERNATIONAL & CORPORATE
   DEVELOPMENT                                                                              Leon Miura
                                                                             VICE-PRESIDENT, UPGRADING
   Tim S. McKay*
   SENIOR VICE-PRESIDENT, OPERATIONS                                                      S. John Parr
                                                                     VICE-PRESIDENT, PRODUCTION - EAST
   Lyle G. Stevens*
   SENIOR VICE-PRESIDENT, EXPLOITATION                                                  David A. Payne
                                                                   VICE-PRESIDENT, EXPLOITATION - WEST
   Jeff W. Wilson*
   SENIOR VICE-PRESIDENT, EXPLORATION                                                 Bill R. Peterson
                                                                     VICE-PRESIDENT, PRODUCTION - WEST
   Mary-Jo E. Case*
   VICE-PRESIDENT, LAND                                                              John C. Puckering
                                                                      VICE-PRESIDENT, SITE DEVELOPMENT
   Corey B. Bieber
   VICE-PRESIDENT, INVESTOR RELATIONS                                             Sheldon L. Schroeder
                                                                       VICE-PRESIDENT, PROJECT CONTROL
   Wayne M. Chorney
   VICE-PRESIDENT, DEVELOPMENT OPERATIONS                                                 Ken W. Stagg
                                                                     VICE-PRESIDENT, EXPLORATION, WEST
   William R. Clapperton
   VICE-PRESIDENT, REGULATORY, STAKEHOLDER &                                           Lynn M. Zeidler
   ENVIRONMENTAL AFFAIRS                                            VICE-PRESIDENT, BITUMEN PRODUCTION

   Gordon M. Coveney                                                                 Kimberly I. McKay
   VICE-PRESIDENT, EXPLORATION - EAST                                                       TREASURER

                                                                                      Bruce E. McGrath
                                                                                   CORPORATE SECRETARY
   *Management Committee
</TABLE>

  54                                      CANADIAN NATURAL RESOURCES LIMITED
==============================================================================
<PAGE>

<TABLE>
<CAPTION>

   <S>                                                 <C>
   STOCK LISTING                                                          BOARD OF DIRECTORS
   Toronto Stock Exchange                                                  Catherine M. Best
   Trading Symbol - CNQ and CNQ.U*                                         N. Murray Edwards
                                                       Honourable Gary A. Filmon, P.C., O.M.
   *denotes trading in US funds                                  Ambassador Gordon D. Giffin
                                                                            John G. Langille
   New York Stock Exchange                                               Keith A.J. MacPhail
   Trading Symbol - CNQ                                                      Allan P. Markin
                                                                          Norman F. McIntyre
                                                         James S. Palmer, C.M., A.O.E., Q.C.
   REGISTRAR AND TRANSFER AGENT                                         Eldon R. Smith, M.D.
   Computershare Trust Company of Canada                                       David A. Tuer
   CALGARY, ALBERTA
   TORONTO, ONTARIO
   Computershare Investor Services LLC                              INTERNATIONAL OPERATIONS
   NEW YORK, NEW YORK                                       CNR International (U.K.) Limited
                                                                          Aberdeen, Scotland

                                                                          INVESTOR RELATIONS
                                                                  Telephone:  (403) 514-7777
                                                                  Facsimile:  (403) 517-7370
                                                                          Email: ir@cnrl.com
                                                                      Website:  www.cnrl.com
</TABLE>


  CANADIAN NATURAL RESOURCES LIMITED                                       55
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  CANADIAN NATURAL RESOURCES LIMITED                                       57
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  CANADIAN NATURAL RESOURCES LIMITED                                       59
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      C A N A D I A N   N A T U R A L   R E S O U R C E S   L I M I T E D

              2500, 855 - 2 Street S.W., Calgary, Alberta T2P 4J8
              Telephone: (403) 517-6700 Facsimile: (403) 517-7350

                              Email: ir@cnrl.com
                             Website: www.cnrl.com


                               Printed in Canada




</TEXT>
</DOCUMENT>
