Canadian Natural Resources Limited Announces Record Nine Month Results, Part 1 of 2.

Energy Editors/Business Editors

CALGARY, Alberta--(BUSINESS WIRE)--Nov. 5, 2003

In commenting on third quarter 2003 results, Canadian Natural's Chairman, Allan Markin, stated "This was another quarter of executing our program and delivering results. Our quarterly production was on guidance and when combined with strong commodity prices and lower operating costs, resulted in record cash flow and solid third quarter earnings. Operationally, our Western Canadian and North Sea assets are delivering as expected, and we have made significant progress on our larger, future-growth projects."

"During the quarter we completed the Joint Panel for regulatory approvals on the Horizon Oil Sands Project. Completion of this public hearing positions us to have the required regulatory approvals in place for the project late this year or early next year. We also started our detailed engineering work for the project, which will be complete in 2004, a key consideration for final construction approval by our Board of Directors."

"In Offshore West Africa, we have completed the first phase of the East Espoir project and development of the Baobab Field is underway with development drilling commencing in November."

"We have also finalized our 2004 Budget which results in average organic production growth estimated in excess of 5% and exit volume growth in excess of 10%, despite significant spending on long-lead projects at Baobab and Horizon."

HIGHLIGHTS OF THE THIRD QUARTER

-- Record nine month net earnings of $1.2 billion ($8.61 per

common share) compared with $0.4 billion ($2.87 per common

share) in 2002.

-- Record nine month cash flow of $2.4 billion ($18.06 per common

share) compared with $1.5 billion ($11.73 per common share) in

2002.

-- Record third quarter cash flow of $758 million ($5.62 per

common share) compared with $643 million ($4.83 per common

share) in the third quarter of 2002 and $762 million ($5.68

per common share) in the previous quarter.

-- Third quarter net earnings of $203 million ($1.51 per common

share) compared with $117 million ($0.88 per common share) for

the third quarter of 2002 and $525 million ($3.91 per common

share) in the previous quarter. Adjusted net earnings from

operations amounted to $215 million ($1.60 per common share)

compared with $164 million ($1.23 per common share) for the

third quarter of 2002 and $256 million ($1.91 per common

share) in the previous quarter.

-- Record third quarter crude oil and NGLs sales of over 247

thousand barrels per day, at the mid point of guidance.

-- Continued strong natural gas sales of 1,289 million cubic feet

per day, at the mid point of guidance and equal to 46% of

production.

-- Net capital expenditures of $621 million reflected the active

heavy crude oil drilling program, facilities work resulting

from the winter natural gas drilling program and continued

development of international properties. During the quarter,

Canadian Natural drilled 385 wells, including 196 shallow

natural gas wells.

-- Reduced long-term debt by $153 million during the quarter

through repayments of $148 million and foreign exchange gains

of $5 million resulting from the strengthening of the Canadian

dollar. This reduced debt to book capitalization to 33%

compared with 46% at year end 2002 and 48% immediately

following the acquisition of Rio Alto Exploration Ltd. on July

1, 2002.

-- Under its Normal Course Issuer Bid, the Company purchased

1,075,000 of its common shares during the third quarter for a

total cost of $58 million (average cost - $54.01/share). As of

November 4, 2003, the Company had purchased approximately 2.4

million of its common shares (average cost - $51.29/share) for

a total cost of $125 million.

-- As expected, crude oil and NGLs production expenses were

reduced in each area for total savings of $0.66 per barrel or

6% from the previous quarter.

-- Horizon Oil Sands Project Joint Panel for regulatory approvals

was held during September with regulatory approvals expected

late this year or early next year. Third and final phase of

pre-construction engineering, Engineering Design Specification

("EDS"), commenced with completion expected in mid-2004.

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 for each of the periods reported. Adjusted net earnings from operations is a non-GAAP term that the Company utilizes to evaluate its performance and that of its business segments.

($ millions, except per common share amounts)

                              Three Months Ended   Nine Months Ended
                            Sep 30   Jun 30  Sep 30   Sep 30  Sep 30
                              2003     2003    2002     2003    2002
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Net earnings attributable
 to common shareholders as
 reported                   $  203   $  525  $  117 $  1,156  $  361

Unrealized foreign
 exchange (gain) loss(1)        (9)     (87)     41     (192)    (35)

Unrealized foreign exchange
 (gain) loss on preferred
 securities(1)                   -       (7)      6      (14)      -

Effect of statutory
 tax rate changes on
 future income tax
 liabilities(2)                  -     (247)      -     (247)     13

Stock-based compensation
 expense (3)                    21       72       -       93       -

Reduction in carrying
 value of foreign
 assets(4)                       -        -       -        -      30
--------------------------------------------------------------------
Adjusted net earnings
 from operations
 attributable to
 common shareholders        $  215   $  256  $  164   $  796  $  369
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Per share - basic           $ 1.60   $ 1.91  $ 1.23   $ 5.93  $ 2.93

          - diluted         $ 1.58   $ 1.88  $ 1.20   $ 5.79  $ 2.83
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(1) Unrealized foreign exchange gains and losses result primarily from the translation of long-term debt and preferred securities to period end exchange rates and are immediately recognized in net earnings attributable to common shareholders. In 2002, the Company utilized previously unrecognized income tax benefits on capital losses to offset income taxes related to these gains.

(2) All substantively enacted adjustments in applicable income tax rates are applied to underlying assets and liabilities on the Company's balance sheet in determining future income tax assets and liabilities. The impact of these tax rate changes is recorded in net earnings during the period the legislation is substantively enacted. During the second quarter of 2003, the Canadian Government introduced several income tax changes, including rate reductions, for the resource industry. Also during the second quarter, a Canadian province reduced corporate income tax rates. During the nine months ended September 30, 2002, the United Kingdom increased income taxes applicable to the crude oil and natural gas industry and a Canadian province reduced corporate income tax rates.

(3) During the second quarter of 2003, the Company modified its employee stock option plan to provide for a cash payment option. A charge of $72 million after taxes ($105 million before taxes) was recognized to represent the mark-to-market liability of the plan for all earned options as at June 30, 2003. An additional expense of $21 million after taxes ($32 million before taxes) was recognized in the third quarter of 2003.

(4) Following an unsuccessful exploratory well drilled in 2002 on Block 19 in Angola and the decision to withdraw from an exploration block in Nigeria, all capitalized costs related to these projects were charged to net earnings attributable to common shareholders.

OPERATIONS REVIEW

Production

Production of both natural gas and crude oil and NGLs were within guidance parameters previously announced. Crude oil and NGLs production for the nine month period ended September 30, 2003 increased approximately 35 mbbls/d or 17% from the previous year. Similarly natural gas production has increased by 120 mmcf/d or 10% from the previous year.

During the third quarter, crude oil and NGLs production increased as a result of the Company's heavy crude oil drilling program in western Canada and the perforation of upper producing zones at the Espoir Field located offshore Cote d'Ivoire. North Sea production increases reflected previous quarter downtime resulting from maintenance work at the Ninian South Platform and the consolidation of interests at the Banff Field.

As expected, natural gas production levels decreased from the second quarter to 1,289 mmcf/d. This reflects the normal production declines on the portion of Canadian Natural's asset base that is suitable for winter-only access. In addition, approximately 11 mmcf/d of Canadian Natural's natural gas production was shut-in during the month of September due to the bitumen conservation measures undertaken by the Energy Utilities Board ("EUB") in Alberta. The Alberta Department of Energy ("ADOE") has recently announced an interim assistance plan under which Alberta crown royalty deferrals are granted at a rate of $0.60/mcf of shut-in production. A long-term assistance plan is still under discussion with the ADOE.

The Company's production composition is as follows:

                         Q3 2003          Q2 2003         Q3 2002
                     mboe/d      %     mboe/d      %    mboe/d     %
--------------------------------------------------------------------
Natural gas           214.9     46      220.9     48     237.9    50
Light crude oil
 and NGLs             118.9     26      112.0     24     102.8    21
Pelican Lake
 crude oil             23.5      5       25.9      6      32.0     7
Primary heavy
 crude oil             68.3     15       63.8     14      66.9    14
Thermal heavy
 crude oil             36.3      8       38.9      8      40.3     8
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Total                 461.9    100      461.5    100     479.9   100
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The Company expects production levels in the fourth quarter of 2003 to average 1,255 to 1,280 mmcf/d of natural gas and 240 to 250 mbbls/d of crude oil and NGLs. This results in expected annual 2003 production levels of approximately 1,295 to 1,300 mmcf/d of natural gas (2002 - 1,230 mmcf/d) and approximately 241 to 245 mbbls/d of crude oil and NGLs (2002 - 215 mbbls/d).

DRILLING ACTIVITY (number of wells)

                             Nine Months Ended September 30
                               2003               2002
                          Gross       Net    Gross         Net
----------------------------------------------------------------
Oil                         390       366      290         253
Natural gas                 616       577      165         150
Dry and abandoned            44        41       27          23
---------------------------------------------------------------
Subtotal                   1050       984      482         426
Stratigraphic test/
 service wells              378       374      416         408
----------------------------------------------------------------
Total                      1428      1358      898         834
----------------------------------------------------------------
Success rate (excluding
 strat test/service wells)            96%                  95%
----------------------------------------------------------------
----------------------------------------------------------------

During the third quarter, Canadian Natural drilled 93 net crude oil wells concentrated in the Company's heavy crude oil areas of North Alberta/West Saskatchewan and 278 net natural gas wells. The natural gas wells included 196 shallow wells in South Alberta, which have productive rates from 50 mcf/d to 200 mcf/d, as well as 25 net wells in Northwest Alberta which have productive rates from 400 mcf/d to 5,000 mcf/d. The total success rate for Canadian Natural's drilling program was 97% during the third quarter, excluding injection/stratigraphic test wells.

During the first nine months of the year, the Company has drilled a total of 1,358 wells, up 63% from 2002 levels. In particular, natural gas drilling has increased to almost four times the level of activity experienced last year, while crude oil drilling has increased 45%.

Canadian Natural expects to drill approximately 460 net crude oil and 895 net natural gas wells during 2003, up 74% and 452% from 2002 levels and 99% and 88% from 2001 levels, respectively.

During the first nine months of the year, the Company drilled 374 net stratigraphic test/service wells on the oil sands leases in the Horizon Oil Sands Project and in North Alberta/West Saskatchewan.

Pricing

Product pricing remained strong during the third quarter for both crude oil and natural gas. West Texas Intermediate ("WTI") benchmark pricing was up versus both the previous quarter and last year, while natural gas pricing was slightly below second quarter but significantly higher than the corresponding quarter of last year. Heavy oil price differentials remained tight, largely as a result of lower supply from Venezuela. Canadian Natural expects these heavy oil differentials to widen during the fourth quarter due to normal seasonality. Detailed reviews of benchmark pricing and Canadian Natural's realized prices are available in Management's Discussion and Analysis.

Canadian Natural's realized prices are sensitive to currency exchange rates. The recent increase in value of the Canadian dollar in relation to the United States dollar had a negative impact on commodity price realizations. Sensitivity to exchange rate changes and commodity prices are detailed in Management's Discussion and Analysis.

The Company utilizes hedges on a portion of its production in an effort to assure operating cash flows are sufficient to cover capital expenditures. Policies now allow for up to 50% of any one commodity to be hedged using cost-less collars for a period not exceeding 12 months, and for up to 25% of production to be hedged beyond 12 months and up to 24 months. The corporate hedging policies are reviewed on a regular basis and this revision reflects the transition of Canadian Natural's project portfolio to longer-term developments. This policy may be reviewed at a future date in anticipation of the significant scope of the Horizon Oil Sands Project. As at November 4, the Company had entered into fourth quarter 2003 commodity hedges covering approximately 1% and 50% of anticipated natural gas production and crude oil production, respectively.

Fourth quarter indicative prices as at November 4, 2003 include a reference WTI price of US$28.78/bbl, and NYMEX natural gas price of US$4.71/mmbtu and a Lloyd Blend heavy oil differential of US$11.48/bbl.

ACTIVITY BY CORE REGION

                         Net Undeveloped Land      Drilling Activity
                                        as at      nine months ended
                           September 30, 2003     September 30, 2003
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                      (thousands of net acres)           (net wells)
--------------------------------------------------------------------
Northeast British Columbia              1,536                     96
Northwest Alberta                       1,762                     78
North Alberta                           5,680                    553
South Alberta                             671                    281
Southeast Saskatchewan                    147                     20
Horizon Oil Sands Project                 117                    312
North Sea                                 563                     15
Offshore West Africa                      943                      3
Total                                  11,419                  1,358
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2004 Budget

Canadian Natural continues its strategy of maintaining a large portfolio of varied projects, which enables the Company over an extended period of time to provide consistent growth in production and high shareholder returns. Annual budgets are developed, scrutinized throughout the year and changed if necessary in the context of project returns, product pricing expectations, and balance in project risks and time horizons. Canadian Natural maintains a high ownership level and operatorship level in all of its properties and can therefore control the nature, timing and extent of expenditures in each of its project areas.

Canadian Natural is presently budgeting cash flow from operations in 2004 of $2.4 billion to $2.7 billion. This cash flow is derived from production of 1,320 to 1,395 mmcf/d of natural gas and 247,000 to 272,000 bbls/d of crude oil and NGLs, and applying pricing parameters averaging WTI price of US $26.00/bbl, a Lloyd Blend heavy oil differential of US $8.50/bbl, NYMEX natural gas price of US $5.00/mmbtu and a US $/Cdn $ exchange rate of $0.75.

Based upon the following capital expenditure budget, Canadian Natural expects to incur Canadian current income tax expense in 2004 of $150 to $250 million.

Canadian Natural expects to drill approximately 921 net natural gas wells and 459 net crude oil wells and 321 stratigraphic test/service wells in 2004, the programs for which are further discussed in the applicable area summary.

The budgeted capital expenditures in 2004 are currently expected to be as follows:

                                               2003             2004
 ($ millions)                              Forecast           Budget
--------------------------------------------------------------------
North American natural gas                 $    950  $           928
North American liquids                     $    630              615
North Sea liquids                          $    270              340
Offshore West Africa liquids               $    210              350
Property acquisitions and midstream        $    325               59
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                                           $  2,385            2,292
Horizon Oil Sands Project(1)               $    165        200 - 600
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Total                                      $  2,550  $ 2,492 - 2,892
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(1) Expenditure level is dependent upon timing of regulatory and Board of Director approvals.

Capital spending in North America will be reduced by $200 million from 2003 spending levels reflecting Canadian Natural's view that property acquisition opportunities will be reduced. Natural gas spending is down reflecting Canadian Natural's significant capital efficiencies achieved during 2003.

The implementation of this capital program will result in Canadian Natural's 2004 North American natural gas exit rates increasing in excess of 8% with average yearly rates increasing by approximately 6%. Overall crude oil and NGLs exit rates will increase in excess of 15% with average rates increasing by approximately 7%.

North American Natural Gas

Canadian Natural's drilling program during the third quarter was highlighted by the summer shallow natural gas program (196 wells) in South Alberta. Shallow natural gas programs in South Alberta, while integral to the Company's ongoing success are not sufficient to offset normal production declines from winter-only access fields in other Core Regions and the declines experienced at Ladyfern; hence the Company experienced lower third quarter volumes when compared with second quarter natural gas production levels.

Canadian Natural continually focuses on reducing costs by achieving capital efficiency in its operations. In Northwest Alberta Canadian Natural has achieved significant cost reductions in drilling and completions. On the majority of properties in the Cardium based southern portion, drilling costs (a significant component of finding and development costs) were reduced by at least 40% and completion costs by 50% from those experienced in 2002. These cost reductions were achieved applying the most appropriate technical applications to maximize well reserves and rate. Canadian Natural is ramping up development of this area and expects to drill a further 10-15 wells in 2003 and 174 wells during 2004.

The 2004 natural gas program will be highlighted by expanded drilling programs in the Northwest Alberta and Northeast British Columbia core regions as shown below.

(number of wells)                      2003 Forecast     2004 Budget
--------------------------------------------------------------------
Northeast British Columbia                       108             176
Northwest Alberta                                112             165
North Alberta                                    223             174
South Alberta                                    479             406
TOTAL                                            922             921
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Northeast British Columbia drilling reflects an increased Helmet drilling program, as well as a shallow natural gas drilling program in the Fort St. John block which benefits from the revised royalty regime for shallow natural gas wells in British Columbia.

North America Crude Oil and NGLs

Canadian Natural continues the disciplined development of its vast heavy crude oil resources. As has been previously articulated, these reserves will be developed as heavy crude oil markets permit. Given the normal production profile of new heavy crude oil wells, third quarter production increases reflect the drilling program completed by the Company over the first nine months of the year. Canadian Natural's drilling program during the third quarter was concentrated on 63 heavy crude oil wells in North Alberta, for a total of 257 wells during the first nine months of the year.

As an integral part of the long-term heavy crude oil strategy mentioned above, the Company's Primrose drilling program continues on budget with 21 new thermal wells already having been drilled during 2003. A further 22 wells will be drilled during the fourth quarter of 2003, with steaming to commence late in 2003. First production from these new wells will commence in mid-2004.

In 2004, Canadian Natural expects to grow its North American volumes by approximately 3 to 7%, largely through continued drilling of conventional heavy crude oil wells and through production increases from the previously mentioned Primrose drilling program. The 2004 drilling program consists of 180 conventional heavy wells, 94 thermal heavy wells, 62 light crude oil wells and 96 Pelican Lake wells. At Pelican Lake, the Enhanced Oil Recovery waterflood test program was a success and as such, Canadian Natural will begin the phased roll out of the waterflood with approximately 20% of the field being under waterflood by the end of 2004. The waterflood will stabilize production, but will require a further 63 Pelican Lake productive wells to be converted from producer to water injectors and 87 new wells to be drilled as producers.

North America Horizon Oil Sands Project

Significant progress was achieved on the six billion barrel Horizon Oil Sands Project during the third quarter. The Design Basis Memorandum ("DBM") was completed and the EDS commenced, representing the detailed design of the project.

The 100% owned and operated Horizon Oil Sands Project is expected to be built in three phases and produce approximately 232,000 barrels per day of light, sweet synthetic crude oil. Management expects to have regulatory approval from provincial and federal authorities by late 2003 or early 2004. The third phase of engineering, EDS, will be complete in 2004. In addition, the financing plan will be optimized and finalized by the third quarter of 2004.

The financing of the first phase of development will be guided by the competing principles of retaining as much direct ownership interest as possible while maintaining current strong debt ratings and not issuing additional equity in common shares. Canadian Natural is also investigating the use of long-term commodity hedges in order to reduce cash flow risks during the construction phase. The Company could also look to offload capital commitments through the acceptance of complementary business partners, or potentially, project joint venture partners. Recent commodity price increases have significantly strengthened the balance sheet of the Company, placing it in a better position to achieve all three of its guiding principles.

From a regulatory standpoint, the EUB and the federal responsible authority successfully concluded their Joint Panel hearing in Fort McMurray during September. With the hearing completed, Canadian Natural remains confident that key regulatory decisions for the Horizon Oil Sands Project will be provided by late 2003/early 2004.

The 2004 capital budget for the Horizon Oil Sands Project will be phased in over 2004 dependent on regulatory approval and cost estimates. In 2004, the EDS will be completed with a capital budget of $150 million. If regulatory approval is received on a timely basis and Board of Directors approval is received based on acceptable certainty of forecasted capital costs, $50 million of pre-construction activities will be undertaken. Once the EDS is complete, a reasonable cost estimate is finalized, and Board of Director approval is obtained, up to an additional $400 million of construction activities could be undertaken in 2004.

The Company currently employs 110 full time employees and 345 full time contractors on this project and expects this to continue to increase as the EDS continues. The members of this team are very experienced in all facets of oil sands construction and operations.

United Kingdom

Canadian Natural remains excited about continuing to create value from the crude oil fields at Ninian and Murchison. During the third quarter, the Company drilled two crude oil wells and one water injector well targeting unswept crude oil reserves within the Ninian and Murchison fields. Additionally, during the third quarter, the Company further consolidated ownership interests to 87.6% in the Banff Field located in the Central North Sea. The Company also assumed operatorship of the Banff Field and the adjoining Block 29/2a. Canadian Natural now operates 99% of its North Sea production and maintains an average ownership interest of about 80% in its properties. Finally, in late July 2003, Canadian Natural was the successful bidder on 6 new exploration licenses at the UK Government's 21st Seaward Licensing Round. These Blocks provide for additional exploration lands adjacent to the Ninian hub in the Northern North Sea.

During the third quarter, one unsuccessful exploration well was drilled into the French portion of the southwest approaches of the North Sea. During the fourth quarter, Canadian Natural plans to drill a further 4 net crude oil and 3 net injector wells from the Ninian and Murchison platforms, including an exploratory drill into the Jude structure, a Ninian satellite.

In 2004, Canadian Natural anticipates drilling approximately 12 crude oil wells, implementing a secondary recovery natural gas injection scheme at Banff, optimizing Ninian and Murchison waterfloods, and continuing its successful 2003 recompletion program. Average crude oil production is expected to increase by approximately 9%, however natural gas volumes will be lower as natural gas sales at Banff are diverted to reinjection. The 2004 capital budget for the North Sea is $340 million.

Offshore West Africa

During the third quarter Canadian Natural completed a fourth water injection well and an additional production well at the East Espoir Field located offshore Cote d'Ivoire. Production exited the quarter at approximately 13,500 bbls/d, a level expected to be maintained during the fourth quarter, and 2004.

At the 57.61% owned and operated Baobab Field, also located offshore Cote d'Ivoire, field development of the estimated recoverable reserves of 200 million barrels of crude oil has commenced. Hydrocarbons will be delivered from subsea well clusters to a Floating Production, Storage and Offtake ("FPSO") vessel with a storage capacity of 2 million barrels. Crude oil production, which is expected to commence mid 2005 at gross well rates of approximately 45,000 bbls/d and subsequently peak at 60,000 bbls/d, will be sold directly from the FPSO, with the associated natural gas being transported to shore via the Espoir Field infrastructure. Development drilling will commence in early November.

In Offshore Angola, drilling of the Zenza project commenced on October 2nd. It is anticipated that results from this well will be available before year end. The Zenza prospect is located in 1,200 metres of water with a total drilling depth of 3,900 metres. Block 16, where the Company operates with a 50% working interest, represents a high risk/high impact exploration development for the Company in one of the most prolific crude oil regions of the world.

In 2004, the capital budget for Offshore West Africa is set at $350 million. Canadian Natural anticipates $220 million to be spent on the ongoing development of the Baobab Field in Cote d'Ivoire. The remainder will be spent on the pre-development work for the West Espoir development and various exploration activities.

FINANCIAL REVIEW

Canadian Natural is focused on maintaining a strong financial position in order to withstand volatile crude oil and natural gas commodity prices and the operational risks inherent in the crude oil and natural gas business environment.

During the first nine months of 2003, strong operational results and product pricing enabled the Company to repay approximately $726 million of long-term debt. The strength of the Canadian dollar during the half also reduced carrying values of US dollar based borrowings by an additional $419 million, resulting in a total decrease of long-term debt of $1,145 billion. Corporate debt to cash flow was reduced to 0.9 times versus 1.9 times at December 31, 2002, while debt to book capitalization improved to 33% from 46% at year-end 2002.

Continuing higher than budgeted prices received for the Company's products are expected to result in increased cash flow to the Company in 2003 over the capital budget established in late 2002. The Company has allocated a minimum of 50% of its cash flow surplus toward debt repayment. The remaining excess will be directed to the Company's authorized share buy-back program and additional expenditures on conventional crude oil and natural gas opportunities. The largest portion of the additional capital expenditures will take place in the fourth quarter of 2003 and accordingly will not add materially to Canadian Natural's 2003 average production volumes. Should additional economic opportunities for share buy-backs or capital activities not materialize, such allocations of excess cash flow would revert to debt repayment. To date, 2.4 million common shares have been purchased for cancellation in 2003 under the Normal Course Issuer Bid.

Implementation of this allocation policy will result in additional capital expenditures of $125 million during the last quarter of 2003 and a final 2003 capital budget of $2,525 million.

In June 2003, the Company announced a small shareholders selling program, which allows registered and beneficial shareholders who own in aggregate 99 or fewer common shares to sell their shares without incurring any brokerage commission. This program was extended on September 2, 2003 and ends on November 28, 2003. Interest parties should contact Georgeson Shareholders Communications Canada, Inc. for further details at 1-866-869-7468.

CORPORATE REVIEW

Canadian Natural is pleased to announce that Mr. Allan Markin, Chairman of the Company, has returned to his day to day company activities following a short-term leave of absence.

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 ("Canadian Natural" or the "Company"), should be read in conjunction with the unaudited interim consolidated financial statements for the three months and nine months ended September 30, 2003 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2002.

All dollar amounts, except per common share data, are referenced in millions of Canadian dollars, except where noted otherwise. The calculation of barrels of oil equivalent ("boe") is based on a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil to estimate relative energy content. Production volumes are the Company's interest before royalties, and realized prices include the effect of hedging gains and losses, except where noted otherwise.

FINANCIAL HIGHLIGHTS ($ millions, except per common share amounts)

                               Three Months Ended  Nine Months Ended
                            Sep 30   Jun 30  Sep 30   Sep 30  Sep 30
                              2003     2003    2002     2003    2002
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Revenue                    $ 1,371  $ 1,413 $ 1,173  $ 4,412 $ 2,753

Cash flow from operations
 attributable to common
 shareholders(1)           $   758  $   762 $   643  $ 2,426 $ 1,477

   Per common share
            - basic        $  5.62  $  5.68 $  4.83  $ 18.06 $ 11.73
            - diluted      $  5.56  $  5.57 $  4.71  $ 17.62 $ 11.28

Net earnings attributable
to common shareholders(2)  $   203  $   525 $   117  $ 1,156 $   361

   Per common share
            - basic        $  1.51  $  3.91 $  0.88  $  8.61 $  2.87
            - diluted      $  1.49  $  3.78 $  0.86  $  8.30 $  2.78

Business combination       $     -  $     - $ 2,373  $     - $ 2,373

Capital expenditures,
 net of dispositions       $   621  $   410 $   620  $ 1,844 $ 1,384
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(1)Cash flow from operations attributable to common shareholders is a non-GAAP term that represents net earnings attributable to common shareholders adjusted for non-cash items. The Company evaluates its performance and that of its business segments based on net earnings and cash flow from operations. The Company considers cash flow a key measure as it demonstrates the Company's ability and the ability of its business segments to generate the cash flow necessary to fund future growth through capital investment and to repay debt.

                              Three Months Ended   Nine Months Ended
                            Sep 30   Jun 30  Sep 30   Sep 30  Sep 30
                              2003     2003    2002     2003    2002
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Net earnings attributable
 to common shareholders      $ 203    $ 525   $ 117  $ 1,156   $ 361

Non-cash items:

  Future tax on dividend
   on preferred securities      (1)      (1)     (1)      (3)     (3)

  Revaluation of preferred
   securities (net of tax)       -       (7)      6      (14)      -

  Stock-based compensation      32      105       -      137       -

  Depletion, depreciation
   and amortization            401      384     403    1,160     928

  Unrealized foreign
   exchange (gain) loss        (11)    (109)     41     (239)    (35)

  Deferred petroleum
   revenue tax                   1        4       1        8       4

  Future income tax
   (recovery)                  133     (139)     76      221     222
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Cash flow from operations
 attributable to common
 shareholders                $ 758    $ 762   $ 643  $ 2,426 $ 1,477
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(2)After dividend and revaluation of preferred securities.

Cash flow in the third quarter of 2003 reached record levels. Net earnings increased 74% to $203 million and increased 220% to $1,156 million for the three and nine months ended September 30, 2003 from the comparable periods in the prior year. Cash flow increased 18% to $758 million and 64% to $2,426 million for the three and nine months ended September 30, 2003 from the comparable periods in 2002. The increase in net earnings and cash flow for the nine months ended September 30, 2003 was a result of higher prices for crude oil, NGLs and natural gas and higher production volumes. The increase in production volumes was primarily associated with an active capital expenditure program, the consolidation of working interests in the North Sea, and the acquisition of Rio Alto Exploration Ltd. ("Rio Alto") on July 1, 2002. Net earnings and cash flow increased in the third quarter of 2003 from the prior year due to higher natural gas prices. Net earnings for the third quarter of 2003 decreased compared to the prior quarter due to the reduction in the Canadian federal and Alberta provincial corporate income tax rates and the larger foreign exchange gain on the Company's US dollar denominated debt in the second quarter of 2003. Cash flow in the third quarter of 2003 decreased from the prior quarter due to lower natural gas prices.

ANALYSIS OF QUARTERLY CHANGES IN REVENUE
($ millions)
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                       Crude oil    Natural
                        and NGLs        gas    Midstream       Total
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September 30, 2002       $   749    $   411       $   13   $   1,173
Price variance               (57)       235            -         178
Volume variance               (5)       (18)           -         (23)
Other variance                 -          -            2           2
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December 31, 2002            687        628           15       1,330
Price variance                83        267            -         350
Volume variance              (15)       (40)           -         (55)
Other variance                 -          -            3           3
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March 31, 2003               755        855           18       1,628
Price variance              (110)      (136)           -        (246)
Volume variance               16         19            -          35
Other variance                 -          -           (4)         (4)
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June 30, 2003                661        738           14       1,413
Price variance                15        (70)           -         (55)
Volume variance               30        (16)           -          14
Other variance                 -          -           (1)         (1)
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September 30, 2003       $   706    $   652       $   13   $   1,371
--------------------------------------------------------------------
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OPERATING HIGHLIGHTS
                            Three Months Ended     Nine Months Ended
                        Sep 30    Jun 30    Sep 30   Sep 30   Sep 30
                          2003      2003      2002     2003     2002
--------------------------------------------------------------------
Crude oil and NGLs
 ($/bbl, except daily
 production)
Daily production
 (bbls/d)              247,016   240,607   242,051  241,762  206,822
Sales price           $  30.97  $  30.27  $  33.57 $  32.13 $  29.23
Royalties                 2.56      2.78      3.56     2.96     3.01
Production expense       10.14     10.80      8.67    10.57     8.19
--------------------------------------------------------------------
Netback               $  18.27  $  16.69  $  21.34 $  18.60 $  18.03
--------------------------------------------------------------------
Natural gas ($/mcf,
 except daily
 production)
Daily production
 (mmcf/d)                1,289     1,325     1,427    1,308    1,188
Sales price           $   5.50  $   6.12  $   3.13 $   6.29 $   3.28
Royalties                 1.11      1.35      0.67     1.41     0.67
Production expense        0.63      0.59      0.55     0.60     0.57
--------------------------------------------------------------------
Netback               $   3.76  $   4.18  $   1.91 $   4.28 $   2.04
--------------------------------------------------------------------
Barrels of oil
 equivalent ($/boe,
 except daily
 production)
Daily production
 (boe/d)               461,882   461,455   479,949  459,785  404,745
Sales price           $  31.94  $  33.32  $  26.26 $  34.79 $  24.57
Royalties                 4.46      5.32      3.80     5.57     3.49
Production expense        7.17      7.34      6.01     7.26     5.85
--------------------------------------------------------------------
Netback               $  20.31  $  20.66  $  16.45 $  21.96 $  15.23
--------------------------------------------------------------------
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BUSINESS ENVIRONMENT
                            Three Months Ended     Nine Months Ended
                        Sep 30    Jun 30    Sep 30   Sep 30   Sep 30
                          2003      2003      2002     2003     2002
--------------------------------------------------------------------
WTI benchmark price
 (US $/bbl)           $  30.20  $  28.90  $  28.25 $  30.96 $  25.42
Differential to LLB
 blend (US $/bbl)     $   8.72  $   7.18  $   5.97 $   7.93 $   5.91
Condensate benchmark
 price (US $/bbl)     $  29.97  $  29.88  $  28.14 $  31.37 $  25.14
NYMEX benchmark price
 (US $/mmbtu)         $   5.10  $   5.48  $   3.26 $   5.74 $   3.01
AECO benchmark price
 (Cdn $/mmbtu)        $   6.28  $   6.99  $   3.25 $   7.07 $   3.68
US/Canadian dollar
 exchange rate (US $) $   0.72  $   0.72  $   0.64 $   0.70 $   0.64
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--------------------------------------------------------------------

World crude oil prices have remained strong throughout 2003 due to concerns over supply relating to the war in Iraq, the strike in Venezuela and the unrest in Nigeria. West Texas Intermediate ("WTI") averaged US $30.20 per bbl in the third quarter of 2003, up 5% compared to US $28.90 per bbl in the prior quarter, and up 7% from US $28.25 per bbl compared to the third quarter of 2002. WTI prices averaged US $30.96 per bbl for the nine months ended September 30, 2003, up 22% compared to the prior year.

Natural gas prices fell in the third quarter of 2003 to their lowest levels of the year but continue to remain higher than the prior year. NYMEX natural gas spot price averaged US $5.10 per mmbtu in the third quarter of 2003, down 7% compared to US $5.48 per mmbtu in the prior quarter, but up 56% compared to the third quarter of 2002. AECO natural gas price averaged $6.28 per mmbtu in the third quarter of 2003, down 10% compared to $6.99 per mmbtu in the prior quarter, but up 93% compared to the third quarter of 2002. The decrease in natural gas prices in the third quarter of 2003 was due to reduced industrial demand and the increase in natural gas storage levels.

PRODUCT PRICES
                            Three Months Ended     Nine Months Ended
                        Sep 30    Jun 30    Sep 30   Sep 30   Sep 30
                          2003      2003      2002     2003     2002
---------------------------------------------------------------------
Crude oil and NGLs
 ($/bbl)
North America         $  27.48  $  27.64  $  31.07 $  28.42 $  26.85
North Sea             $  39.84  $  37.83  $  41.68 $  42.59 $  38.77
Offshore West Africa  $  37.37  $  34.34  $  42.78 $  36.50 $  38.95
Company average       $  30.97  $  30.27  $  33.57 $  32.13 $  29.23

Natural gas ($/mcf)
North America         $   5.62  $   6.25  $   3.15 $   6.41 $   3.29
North Sea             $   2.57  $   2.21  $   1.98 $   2.91 $   2.56
Offshore West Africa  $   4.59  $   5.09  $   4.97 $   4.60 $   4.97
Company average       $   5.50  $   6.12  $   3.13 $   6.29 $   3.28

Percentage of revenue
 (excluding midstream
 revenue)
Crude oil and NGLs        52.0%     47.3%     64.6%    48.6%    60.9%
Natural gas               48.0%     52.7%     35.4%    51.4%    39.1%
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---------------------------------------------------------------------

Realized crude oil prices decreased for the three months ended September 30, 2003 from the comparable period in 2002 for all segments. Realized crude oil prices increased for the nine months ended September 30, 2003 from the comparable period in 2002 due to the higher world crude oil price resulting from concerns surrounding supply. North America realized crude oil prices decreased in the third quarter of 2003 from the prior quarter as a result of the higher heavy oil differential and the stronger Canadian dollar. Heavy oil differentials averaged US $8.72 per bbl in the third quarter of 2003, up 46% from US $5.97 per bbl in the third quarter of 2002 and up 21% from US $7.18 per bbl in the second quarter of 2003. The Offshore West Africa realized crude oil price decreased due to the timing of and prices received on specific product lifting dates. The North Sea and Offshore West Africa realized crude oil prices increased in the third quarter compared to the prior quarter due to the narrowing of the Brent differential. As a result of the use of derivative financial instruments, the realized price from the sale of crude oil was reduced by $0.48 per bbl in the quarter ended September 30, 2003 ($0.39 per bbl and $1.62 per bbl reduction, respectively, in the quarters ended June 30, 2003 and September 30, 2002).

The Company's average natural gas price increased 76% to $5.50 per mcf for the three months ended September 30, 2003 and increased 92% to $6.29 per mcf for the nine months ended September 30, 2003 from the comparable periods in 2002 due to supply and demand concerns in North America. The Company's average natural gas price decreased 10% in the third quarter from the prior quarter due to the decrease in demand and the easing of concerns surrounding storage levels heading into the winter heating season. Derivative financial instruments entered into by the Company on its natural gas portfolio affects realized prices. The price realized from the sale of its natural gas was decreased by $0.07 per mcf in the third quarter of 2003 ($0.13 per mcf reduction and $0.05 per mcf increase, respectively, in the quarters ended June 30, 2003 and September 30, 2002).

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

                                       Q3 2003    Q2 2003    Q3 2002
--------------------------------------------------------------------
Canadian Natural's Wellhead Price(1)
 Light crude oil and NGLs (Cdn $/bbl)  $ 34.37    $ 35.54    $ 34.36
 Pelican Lake crude oil (Cdn $/bbl)    $ 27.20    $ 25.66    $ 30.58
 Primary heavy crude oil (Cdn $/bbl)   $ 24.93    $ 24.76    $ 30.11
 Thermal heavy crude oil (Cdn $/bbl)   $ 23.58    $ 24.22    $ 29.23
 Natural gas (Cdn $/mcf)               $  5.62    $  6.25    $  3.15
--------------------------------------------------------------------
--------------------------------------------------------------------
(1) Including financial instruments.


DAILY PRODUCTION
                            Three Months Ended     Nine Months Ended
                        Sep 30    Jun 30    Sep 30   Sep 30   Sep 30
                          2003      2003      2002     2003     2002
---------------------------------------------------------------------
Crude oil and NGLs
 (bbls/d)
North America          174,838   175,232   185,990  174,378  165,608
North Sea               60,193    55,781    47,114   57,658   34,629
Offshore West Africa    11,985     9,594     8,947    9,726    6,585
---------------------------------------------------------------------
Total                  247,016   240,607   242,051  241,762  206,822
---------------------------------------------------------------------

Natural gas (mmcf/d)
North America            1,229     1,278     1,395    1,258    1,162
North Sea                   49        40        29       43       25
Offshore West Africa        11         7         3        7        1
--------------------------------------------------------------------
Total                    1,289     1,325     1,427    1,308    1,188
---------------------------------------------------------------------

Product mix
Light crude oil and
 NGLs                     25.7%     24.3%     21.4%    24.9%    20.2%
Pelican Lake crude
 oil                       5.1%      5.6%      6.7%     5.4%     7.4%
Primary heavy crude
 oil                      14.8%     13.8%     13.9%    14.0%    13.7%
Thermal heavy crude
 oil                       7.9%      8.4%      8.4%     8.3%     9.8%
Natural gas               46.5%     47.9%     49.6%    47.4%    48.9%
---------------------------------------------------------------------
---------------------------------------------------------------------

Crude oil and NGLs production for the three and nine months ended September 30, 2003 increased 2% or 4,965 bbls/d and 17% or 34,940 bbls/d respectively from the comparable periods in 2002. Crude oil and NGLs production for the third quarter of 2003 was in line with the Company's guidance previously provided.

Crude oil and NGLs production in North America for the three months ended September 30, 2003 decreased 6% or 11,152 bbls/d from the comparable period in 2002 but remained relatively consistent with the prior quarter. The decrease in North American crude oil production was due to reduced crude oil drilling activity in the fourth quarter of 2002 and the first quarter of 2003, reflecting the increased focus on natural gas drilling. Crude oil and NGLs production in North America for the nine months ended September 30, 2003 increased 5% or 8,770 bbls/d from the comparable period in 2002 due to additional heavy crude oil drilling activity in the second quarter of 2003, property acquisitions in the Company's core operating regions in 2002, and the acquisition of Rio Alto.

Crude oil production from the North Sea for the three and nine months ended September 30, 2003 increased 28% or 13,079 bbls/d and 67% or 23,029 bbls/d from the comparable periods in 2002. The increase was a result of drilling activities and the consolidation of the Company's working interests in the North Sea during the last two years. Crude oil production in the third quarter increased 8% or 4,412 bbls/d from the previous quarter due to the completion of an extensive turnaround on the Ninian South Platform in the second quarter. Production also increased as a result of in-fill drilling in the Ninian, Murchison and Columba Fields; the re-entry into a number of producing wells to access behind pipe reserves; and the continued consolidation of the Company's working interests in the North Sea.

Offshore West Africa crude oil production for the three and nine months ended September 30, 2003 increased 34% or 3,038 bbls/d and 48% or 3,141 bbls/d from the comparable periods in 2002. In addition, crude oil production in the third quarter increased 25% or 2,391 bbls/d from the prior quarter. The increases in production are due to the perforation of the upper zone of the East Espoir structure in the second quarter of 2003 and the completion of the fourth water injection well and an additional production well in the third quarter of 2003.

Natural gas production for the third quarter of 2003 was in line with the Company's guidance previously provided. Natural gas production in the third quarter continued to represent the Company's largest product offering but decreased 10% or 138 mmcf/d from the comparable period in 2002. The decrease was due to third quarter drilling activity, which focused on shallow natural gas in the South Alberta region, not offsetting the normal production declines from winter access fields in the Company's other core regions. Natural gas production for the nine months ended September 30, 2003 increased 10% or 120 mmcf/d from the comparable period in 2002. The increase in natural gas production was due to the acquisition of Rio Alto on July 1, 2002 and ongoing drilling activities. Natural gas production decreased 3% or 36 mmcf/d from the prior quarter due to normal production declines. Production from the Ladyfern field in Northeast British Columbia declined 15 mmcf/d to average 47 mmcf/d during the third quarter of 2003, down from 62 mmcf/d in the second quarter of 2003 and 178 mmcf/d in the third quarter of 2002 as well pressures continue to decline. In addition, on September 1, 2003 approximately 11 mmcf/d of the Company's natural gas production in the Athabasca Wabiskaw-McMurray oilsands area was shut in pursuant to the decision of the Alberta Energy and Utilities Board.

Natural gas production in the North Sea increased from the comparable periods in the prior year and the prior quarter due to the increased working interests acquired in the Banff Field as a result of the Company's consolidation of its working interest in the North Sea.

Natural gas production in Offshore West Africa increased over the comparable period in the prior year due to the natural gas pipeline commencing operation in the third quarter of 2002. Natural gas production increased in the third quarter of 2003 due to the perforation of the upper zone of the East Espoir structure in the second quarter of 2003. In addition, production increased as a result of the drilling of an additional producing well in the third quarter of 2003.

The Company expects fourth quarter production levels to average 1,255 to 1,280 mmcf/d of natural gas and 240,000 to 250,000 bbls/d of crude oil and NGLs. This results in expected annual production levels of approximately 1,295 to 1,300 mmcf/d of natural gas and 241,000 to 245,000 bbls/d of crude oil and NGLs in 2003.

ROYALTIES
                            Three Months Ended     Nine Months Ended
                        Sep 30    Jun 30    Sep 30   Sep 30   Sep 30
                          2003      2003      2002     2003     2002
---------------------------------------------------------------------
Crude oil and NGLs
 ($/bbl)
North America         $   3.52  $   3.83  $   3.92 $   4.04 $   3.28
North Sea             $   0.09  $  (0.19) $   2.56 $      - $   2.06
Offshore West Africa  $   1.13  $   0.99  $   1.34 $   1.10 $   1.36
Company average       $   2.56  $   2.78  $   3.56 $   2.96 $   3.01

Natural gas ($/mcf)
North America         $   1.16  $   1.40  $   0.69 $   1.46 $   0.68
Offshore West Africa  $   0.14  $   0.15  $   0.15 $   0.14 $   0.15
Company average       $   1.11  $   1.35  $   0.67 $   1.41 $   0.67

Company average
 ($/boe)              $   4.46  $   5.32  $   3.80 $   5.57 $   3.49

Percentage of revenue
 (excluding financial
 instruments)
Crude oil and NGLs         8.2%      9.1%     10.1%     8.8%     9.8%
Natural gas               19.8%     21.6%     21.8%    21.6%    20.4%
---------------------------------------------------------------------
---------------------------------------------------------------------

North America crude oil and NGLs royalties for the three months ended September 30, 2003 decreased on a per barrel basis from the comparable period in 2002 and the prior quarter due to lower crude oil prices as a result of the higher heavy oil differential. North America crude oil and NGLs royalties for the nine months ended September 30, 2003 increased on a per barrel basis from the comparable period in the prior year due to higher crude oil prices and certain heavy oil projects reaching payout in 2002 and becoming subject to higher government royalties.

North Sea crude oil royalties decreased from the comparable periods in the prior year as a result of the elimination of government royalties in the North Sea effective January 1, 2003. In the second quarter of 2003, the Company received a refund of royalties previously provided for related to the Ninian Field.

Natural gas royalty fluctuations as a percentage of revenue from both the prior quarter and the comparable periods in the prior year are a result of the strong correlation of royalties to natural gas prices.

PRODUCTION EXPENSE
                            Three Months Ended     Nine Months Ended
                        Sep 30    Jun 30    Sep 30   Sep 30   Sep 30
                          2003      2003      2002     2003     2002
--------------------------------------------------------------------
Crude oil and NGLs
 ($/bbl)
North America         $   9.27  $   9.80  $   6.10 $   9.39 $   6.50
North Sea             $  13.25  $  14.17  $  18.30 $  14.29 $  15.25
Offshore West Africa  $   7.11  $   9.32  $  11.23 $   9.61 $  13.60
Company average       $  10.14  $  10.80  $   8.67 $  10.57 $   8.19

Natural gas ($/mcf)
North America         $   0.58  $   0.56  $   0.52 $   0.57 $   0.54
North Sea             $   1.60  $   1.45  $   1.78 $   1.39 $   1.65
Offshore West Africa  $   1.24  $   1.45  $   1.77 $   1.51 $   1.77
Company average       $   0.63  $   0.59  $   0.55 $   0.60 $   0.57

Company average
 ($/boe)              $   7.17  $   7.34  $   6.01 $   7.26 $   5.85
--------------------------------------------------------------------
--------------------------------------------------------------------

The cost of natural gas used to generate steam to heat the Company's thermal crude oil formations in the Primrose area of Alberta decreased, while the steam/crude oil ratios remained relatively constant, resulting in a decrease in the North America crude oil and NGLs production expense compared to the previous quarter. Third quarter 2003 production expense decreased from the prior quarter as a result of increased production volumes coming on stream as a result of the work associated with the heavy crude oil drilling and recompletion programs. The decrease in North America crude oil and NGLs production expense was partially offset by higher unit costs associated with Pelican Lake, which have increased from historical levels due to the conversion of producing wells to injection wells while implementing the waterflood pilots.

North Sea crude oil production expense for the three months ended September 30, 2003 decreased on a per barrel basis from both the prior quarter and the comparable period in 2002 due to increased volumes on a relatively fixed cost lease and the timing of maintenance work. North Sea crude oil production expense for the nine months ended September 30, 2003 decreased from the prior year due to the overall impact of increased volumes on relatively fixed costs.

Offshore West Africa crude oil production expenses are largely fixed in nature and therefore decreased on a per barrel basis from the comparable periods due to increased production from the Espoir Field.

North America natural gas production expense in the third quarter of 2003 increased marginally from both the prior quarter and the comparable period in the prior year as a result of a general increase in service costs associated with increased industry activity. North Sea natural gas production expense decreased from comparable periods in the prior year due to costs associated with the natural gas pipeline blockage that occurred in 2002. Offshore West Africa natural gas production expense decreased for the three and nine months ended September 30, 2003 as production volumes increased while costs remained relatively fixed.

MIDSTREAM ($ millions)
                            Three Months Ended     Nine Months Ended
                        Sep 30    Jun 30    Sep 30   Sep 30   Sep 30
                          2003      2003      2002     2003     2002
--------------------------------------------------------------------
Revenue               $     13  $     14  $     13 $     45 $     37
Operating costs              3         3         3       11       10
--------------------------------------------------------------------
Operating cash flow         10        11        10       34       27
Depreciation                 2         2         2        6        6
--------------------------------------------------------------------
Segment earnings
 before taxes         $      8  $      9  $      8 $     28 $     21
--------------------------------------------------------------------
--------------------------------------------------------------------

The Company's midstream assets consist of three crude oil pipeline systems and an 84-megawatt cogeneration plant at Primrose where the Company has a 50% working interest. Approximately 86% of the Company's heavy oil production was transported to international 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 transport its own production volumes at reduced costs compared to other transportation alternatives as well as earn third party revenue. This transportation control enhances the Company's ability to control the full range of costs associated with the development and marketing of its heavy oil.

Revenue from the midstream assets increased for the nine months ended September 30, 2003 from the comparable period in 2002 due to higher electricity prices received in the first quarter of 2003 and increased revenue generated by the ECHO pipeline. Revenue from the Company's midstream assets is expected to increase with the completion of the expansion of the ECHO pipeline capacity to 72 mbbls/d from 58 mbbls/d in October 2003.

DEPLETION, DEPRECIATION AND AMORTIZATION

                            Three Months Ended     Nine Months Ended
                        Sep 30    Jun 30    Sep 30   Sep 30   Sep 30
                          2003      2003      2002     2003     2002
--------------------------------------------------------------------
Expense ($ millions)  $    399  $    382  $    401 $  1,154 $    922
     $/boe            $   9.41  $   9.09  $   9.08 $   9.20 $   8.35
--------------------------------------------------------------------
--------------------------------------------------------------------
(1) DD&A excludes depreciation on midstream assets.

DD&A for the nine months ended September 30, 2003 increased in total and per boe from the comparable period in 2002. The increase was due to higher finding and development costs associated with natural gas exploration in North America, the allocation of the acquisition costs associated with Rio Alto and future abandonment costs associated with the acquisition of additional interests in the North Sea. DD&A increased from the prior quarter in total and per boe due to higher finding and development costs, including higher future costs to develop, and the write-off of costs associated with the unsuccessful well in offshore France.

ADMINISTRATION EXPENSE

                            Three Months Ended     Nine Months Ended
                        Sep 30    Jun 30    Sep 30   Sep 30   Sep 30
                          2003      2003      2002     2003     2002
--------------------------------------------------------------------
Net expense ($ millions) $  22     $  23     $  18    $  63    $  44
    $/boe                $0.51     $0.56     $0.40    $0.50    $0.39
--------------------------------------------------------------------
--------------------------------------------------------------------

Administration expense for the three and nine months ended September 30, 2003 increased in total and on a per boe basis from the comparable periods in 2002 due to higher staffing levels associated with the growth in production and the expanding asset base.

STOCK-BASED COMPENSATION
                            Three Months Ended     Nine Months Ended
                        Sep 30    Jun 30    Sep 30   Sep 30   Sep 30
                          2003      2003      2002     2003     2002
--------------------------------------------------------------------
Expense ($ millions)  $     32  $    105   $     - $    137  $     -
    $/boe             $   0.77  $   2.49   $     - $   1.10  $     -
--------------------------------------------------------------------
--------------------------------------------------------------------

In June 2003, the Board of Directors approved an amendment to the Company's Stock Option Plan (the "Option Plan") that provides current employees, officers and directors (the "option holders") with the right to elect to receive common shares or a direct cash payment in exchange for options exercised. The amendment to the Option Plan balances the need for a long-term compensation program to retain employees and the concerns of shareholders regarding the dilution caused by stock options. Transparency of the cost of the Option Plan is increased since changes in the intrinsic value of outstanding stock options are expensed. 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.

(MORE TO FOLLOW)