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

Energy Editors/Business Editors

CALGARY, Alberta--(BUSINESS WIRE)--May 7, 2003

In commenting on first quarter 2003 results, Canadian Natural's Chairman, Allan Markin, stated "For the third consecutive quarter, we have achieved record cash flow levels and this was a remarkable quarter for Canadian Natural (NYSE, TSX SYMBOL: CNQ) in several other respects. From an operational perspective, we accomplished the most aggressive drilling program in our history with 749 total wells drilled and a 94% success rate. In Western Canada, we are on track with our plan to extract value from the natural gas prone Northwest Alberta core region. In the North Sea, we have delivered new reserves and are proving that significant upside can still be extracted from these mature reservoirs."

"From an economic perspective, we have generated record quarterly earnings and cash flows. Our quarter-end balance sheet continued to strengthen with debt to book capitalization of 40%, just nine months after the acquisition of Rio Alto, when the same ratio was approximately 48%. This ratio at the end of the first quarter was achieved even with the repurchase of 665,600 common shares under our share-buyback plan."

"We have also enhanced the overall governance of the organization with major changes to the composition of the Committees of the Board of Directors. Each of the Governance, Compensation and Audit Committees are now solely comprised of unrelated directors. This, coupled with the formalization of various management roles, has resulted in a continued strengthening of our effective system of governance."

"All of this results in the generation of significant shareholder value. During the quarter we clearly benefited from strong commodity prices, but we also wisely reinvested in a very efficient manner. We expect our disciplined development strategy to continue to provide robust returns, particularly when this proven and effective approach is coupled with our well balanced and strong asset base, which will provide years of significant, low-risk growth."

HIGHLIGHTS OF THE FIRST QUARTER

-- Record net earnings of $428 million ($3.19 per common share)

compared with $99 million ($0.81 per common share) for the

first quarter of 2002 and $209 million ($1.56 per common

share) in the previous quarter.

-- Record cash flow of $906 million ($6.76 per common share)

compared with $359 million ($2.95 per common share) in the

first quarter of 2002 and $777 million ($5.81 per common

share) in the previous quarter.

-- Natural gas sales of 1,310 million cubic feet per day,

representing 48% of equivalent production during the quarter.

-- Crude oil and NGLs sales of 238 thousand barrels per day.

-- Reduced long-term debt by $580 million during the quarter

through repayments of $377 million and foreign exchange gains

of $203 million from the strengthening of the Canadian dollar.

This reduced debt to book capitalization to 40%, compared with

46% at year end 2002 and 48% immediately following the

acquisition of Rio Alto Exploration Ltd. on July 1, 2002.

-- Capital expenditures of $813 million, reflecting the high

activity levels associated with winter drilling areas. During

the quarter, Canadian Natural drilled a record 749 wells,

including 244 natural gas wells.

-- Extended its Normal Course Issuer Bid for a further 12-month

period through the facilities of the Toronto Stock Exchange

and the New York Stock Exchange for the purchase of up to 5%

of the Company's common shares outstanding (approximately 6.7

million common shares) at the market price, if and when

acquired. During the three months ended March 31, 2003, the

Company repurchased 665,600 common shares for gross cost of

$32 million. As of April 30, 2003, the Company had repurchased

approximately 1.1 million common shares under this plan.

-- Increased the quarterly dividend by 20% to $0.15 per common

share commencing with the April 1, 2003 payment.

OPERATIONS REVIEW

Production

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 oil, Pelican Lake oil, primary heavy oil and thermal heavy oil.

Natural gas production levels stabilized during the first quarter with January volumes of 1,300 mmcf/d and quarterly average production of 1,310 mmcf/d. The stabilization of production volumes confirms the strength of Canadian Natural's asset base and its ability to bring on new reserves at low cost. Natural gas production in April was 1,360 mmcf/d. Canadian Natural's production from the Ladyfern field declined from 82 mmcf/d in January 2003 to 69 mmcf/d during April 2003.

Production of oil and liquids during the first quarter of 2003 was 3 mbbls/d lower than the previous quarter but 49 mbbls/d higher than the corresponding period of last year. Volume increases in North America, when compared with first quarter 2002, reflected additional heavy oil drilling activity and acquired production. North Sea volumes increased primarily as a result of the acquisition of additional interests to consolidate the Company's position in the northern sector of the North Sea. Offshore West Africa volumes increased as production was brought on stream at the Espoir field.

The Company's production composition is as follows:

                                  Q1 2003      Q4 2002      Q1 2002
                               mboe/d    %  mboe/d    %  mboe/d    %
--------------------------------------------------------------------
Natural gas                     218.4   48   227.5   49   175.6   48
Light oil and NGLs              112.6   25   104.7   22    72.2   20
Pelican Lake oil                 25.1    5    28.6    6    26.6    7
Primary heavy oil                60.4   13    68.5   15    48.0   13
Thermal heavy oil                39.5    9    38.8    8    41.6   12
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Total                           456.0  100   468.1  100   364.0  100
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The Company expects production levels in 2003 to average 1,280 to 1,330 mmcf/d of natural gas and 240 to 260 mbbls/d of oil and liquids, unchanged from previous expectations. Second quarter 2003 production guidance for natural gas is 1,330 to 1,350 mmcf/d of natural gas and 230 to 251 mbbls/d of oil and liquids. During the second quarter, maintenance activities are expected to occur on North American natural gas fields and North Sea platforms. Further detailed guidance on production levels and operating costs may be found on the Company's website (http://www.cnrl.com/investor/guidance.htm).

DRILLING ACTIVITY (number of wells)

                                      Three Months Ended March 31
                                        2003                2002
                                  Gross       Net     Gross      Net
--------------------------------------------------------------------
Oil                                 124       116        55       47
Natural gas                         261       244       103       95
Dry                                  24        23        14       13
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Subtotal                            409       383       172      155
Stratigraphic test/
 service wells                      367       366       409      403
--------------------------------------------------------------------
Total                               776       749       581      558
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Success rate (excluding
 strat tests/service wells)          94%                92%
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During the quarter, Canadian Natural drilled a record 749 wells, including 366 stratigraphic test and service wells. Representing the second most active natural gas program in the Company's history, a total of 244 natural gas wells were drilled, a 157% increase over the first quarter results of 2002 when drilling was intentionally deferred in an effort to build inventory to offset anticipated Ladyfern declines.

The Company also drilled 116 net oil wells during the first quarter 2003, representing the third highest activity level in its history. These wells were concentrated in the Company's oil region of North Alberta with 68 primary heavy oil and 26 Pelican Lake wells being drilled. Five high-pressure horizontal thermal wells were also drilled and completed at Primrose as part of the 2003/2004 development strategy of the area.

Finally, 312 stratigraphic test wells were drilled on the oil sands leases in Horizon Oil Sands Project and 51 wells in Primrose and Pelican Lake.

Total success rate for Canadian Natural's drilling program was 94%, excluding stratigraphic test and service wells. This reflects the disciplined approach that the Company takes in its exploitation and development programs and the strength of our asset base. Success rates were enhanced despite increasing the drilling program by about 2.5 times 2002 levels.

Pricing

As a result of political unrest in the Middle East and Venezuela, world oil prices significantly improved in comparison to the previous quarter. During this same time, no appreciable increases in heavy oil differentials occurred, largely the result of lower supplies available to PADD II refiners. As a result, the netbacks received for Canadian Natural's oil and liquids production improved in the first quarter of the year. Similarly, cold weather and decreasing natural gas supplies resulted in significant natural gas price increases. As a result of the usage of financial instruments, the realized price from the sale of crude oil was reduced by $4.11 per bbl in the quarter ended March 31, 2003 ($1.73 per bbl and $0.50 per bbl reduction, respectively, in the quarters ended December 31, 2002 and March 31, 2002). Financial instruments entered into by the Company on its natural gas portfolio resulted in a reduction to realized prices. The price realized from the sale of its natural gas was decreased by $0.50 per mcf in the first quarter of 2003 ($0.07 per mcf reduction and $0.08 per mcf increase, respectively, in the quarters ended December 31, 2002 and March 31, 2002). A comparison of the price received for the Company's North American production is as follows:

                             May 5, 2003
                                 Pricing
                             Indications  Q1 2003   Q4 2002   Q1 2002
---------------------------------------------------------------------
WTI benchmark price (US $/bbl)  $ 26.49   $ 33.80   $ 28.17   $ 21.67
Differential to LLB blend
 (US $/bbl)                     $  6.92   $  8.10   $  8.13   $  5.73
Condensate benchmark price
 (US $/bbl)                     $ 27.10   $ 33.30   $ 28.56   $ 20.83
NYMEX benchmark price
 (US $/mmbtu)                   $  5.69   $  6.64   $  3.99   $  2.40
AECO benchmark price
 (Cdn $/mmbtu)                  $  6.70   $  7.95   $  5.25   $  3.35
Canadian Natural's Wellhead
 Price(1)
 Light oil and NGLs (Cdn $/bbl) $ 33.09   $ 38.52   $ 36.08   $ 27.83
 Pelican Lake oil (Cdn $/bbl)   $ 23.73   $ 27.52   $ 25.30   $ 21.89
 Primary heavy oil (Cdn $/bbl)  $ 23.38   $ 27.41   $ 24.78   $ 20.54
 Thermal heavy oil (Cdn $/bbl)  $ 22.00   $ 25.44   $ 24.11   $ 19.40
Natural gas (Cdn $/mcf)         $  6.54   $  7.36   $  5.04   $  3.05
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(1) Including financial instruments


ACTIVITY BY CORE REGION
                            ----------------------------------------
                                                   Drilling Activity
                                   Net Undeveloped      Three months
                                        Land as at             ended
                                    March 31, 2003    March 31, 2003
--------------------------------------------------------------------
                           (thousands of net acres)       (net wells)
--------------------------------------------------------------------
Northeast British Columbia                   1,467                82
Northwest Alberta                            1,783                42
North Alberta                                5,854               277
South Alberta                                  719                23
Southeast Saskatchewan                         159                 8
Horizon Oil Sands Project                      117               312
United Kingdom North Sea                       410                 4
Offshore West Africa                           943                 1
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                                            11,452               749
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North American Natural Gas

Included in the natural gas drilling count are 33 successful wells in the new Northwest Alberta core region, where Canadian Natural has taken a disciplined approach to development with a view of reducing capital costs and total finding costs. During the first quarter of 2003, many geological and development theories were tested on the southern area where the prolific Cardium formation is prevalent. This work sets up an expanded exploration and development program in 2004 and will allow for a lower-cost exploration and development program when compared with predecessor operations. In particular, the Company has gained better insights into the following key issues:

-- The appropriateness of drilling vertical wells in place of

traditional, higher cost horizontal wells. The Company has

found that areas of medium to high fracture density are better

suited to vertical wells where multiple reservoirs can be

drilled and hydraulically fractured. These vertical well costs

are often about 40% of the cost of a horizontal well,

significantly reducing finding costs.

-- In areas with low fracture density, horizontal wells with

optimal location in stress transfer zones or within folds

related to thrusting have better overall effectiveness, again

increasing ultimate deliverability and economics of the

reserves.

-- For those areas with low matrix porosity, drilling results

have shown that wells may still be economic if effective

fracturing of the structure is present or if it can be

achieved with an optimized stimulation program.

Early indications from the first quarter drilling program have exceeded expectations and are very encouraging. The Company will continue to monitor the production performance of the new wells before undertaking a more aggressive development program.

In the Cardium-oriented southern portion of the Northwest Alberta core region, a total of 11 wells targeting natural gas were drilled with a success rate of 100%, providing 29 bcfe of proved reserves. In the Cretaceous-oriented northern portion of this core region, a total of 30 wells targeting natural gas were drilled with a success rate of 74%, providing 58 bcfe of proved reserves. Canadian Natural believes that ultimately, the northern portion could add up to 1.0 trillion cubic feet equivalent of new reserves while the southern portion could add up to 0.75 trillion cubic feet equivalent of new reserves.

In the Northeast British Columbia core region, a total of 81 wells targeting natural gas were drilled, with 36 representing horizontal drilling on the Helmet area development. In this region, a success rate of 96% was achieved. Included in these results were three unsuccessful Slave Point natural gas exploration wells and two unsuccessful exploration wells drilled in the Colville Lake region of the Northwest Territories. Work in this area will now be scaled back pending expansion of natural gas pipeline facilities into the area.

Canadian Natural was also active in its traditional natural gas core regions of North Alberta and South Alberta, drilling 119 and 22 wells targeting natural gas respectively.

North American Crude Oil and NGLs

Canadian Natural continues the disciplined development of its vast heavy oil resources. As has been previously articulated, these reserves will be developed as heavy oil markets permit. The Company is working with refiners to expand heavy oil conversion capacity of refineries in the Midwest United States; and is working with pipeline companies to develop new capacity to the Canadian west coast where crude cargoes could be sold on a world-wide basis. Over the long term, as these opportunities come to fruition, Canadian Natural will accelerate development of up to three billion barrels of currently unbooked bitumen resources. As part of this development plan, the Company is currently transitioning its Primrose thermal oil development from low-pressure to high-pressure steaming. New wells are currently being drilled and steaming will commence over the next few months with first increases in production expected in spring 2004.

In the first quarter, the Company drilled 68 heavy oil wells, 26 Pelican Lake oil wells and five high-pressure cyclic steam wells at Primrose. The majority of these wells were drilled late in the first quarter as the drilling program was focussed on natural gas early in the quarter. The majority of the North American oil drilling program will commence late in the second quarter of 2003 as the Company's oil areas are more suited for summer drilling.

The Pelican Lake enhanced oil recovery project also continues. This project seeks to significantly increase recovery efficiency on this vast blanket sand in North Alberta. The utilization of emulsion technology offers the best upside potential in ultimate recoverability, however, the drilling of an observation well during the first quarter indicates that while effective, the timeliness of the response is slow. During the remainder of 2003, Canadian Natural will investigate the use of conventional waterflood technologies alone and in conjunction with the emulsion in an effort to maximize value creation through the balancing of recovery factors with timely response.

Horizon Oil Sands Project

Following increased clarity on the Canadian Government's implementation plan for the Kyoto Protocol, engineering work on the Horizon Oil Sands Project ("Horizon Project") continued towards completion of the Design Basis Memorandum ("DBM") phase of engineering. Completion of the DBM is expected this summer with Engineering Design Specification to commence immediately thereafter. Work on a new 30 kilometre access road, including three bridges, has also commenced. It is currently anticipated that the Regulatory Hearing on the Horizon Project application will occur in the summer, with full approvals still targeted for late 2003.

With respect to the Kyoto Protocol, the Company is still working with the Canadian Government to gain certainty on the form of implementation beyond 2012. Such certainty in the principles of implementation would be a requirement prior to final Board of Directors' approval for major construction expenditures in 2004 and beyond. Management remains optimistic that required certainty will be obtained prior to this date.

Canadian Natural has been refining detailed cost reviews throughout the DBM phase of engineering. Canadian Natural recognizes cost pressures exist, however, it has utilized conservative cost estimating practices and completed extensive benchmarking to actual field costs throughout the DBM engineering phase. The Company expects to have final cost estimates at the end of the DBM phase that are not materially different from the original estimate of $4.9 billion for phase one production and $8.5 billion for the full three-phase development.

North Sea

Canadian Natural, as a new operator in the northern North Sea, remains excited about the prospects of extracting additional value from the oil fields surrounding the Ninian and Murchison platforms. During the first quarter, the Company drilled two oil wells targeting reserves stranded against faults within the Ninian field. These wells provided average rates of 3,600 bbls/d of oil with significantly higher flush rates. While it is not anticipated that all results will be this positive, it is an indicator of the potential of the field redevelopment program initiated by Canadian Natural. Similarly, at the Murchison platform a successful producing well has increased production by 1,100 bbls/d. A satellite pool was also drilled off the Murchison platform but encountered no hydrocarbons.

As the new operator of these northern North Sea platforms, Canadian Natural planned for extensive platform turnarounds during the second quarter of 2003. During February 2003, a small oil leak was discovered on the Ninian South Platform, resulting in the shift of this platform's planned turnaround from June to February. This platform also handles all production from the satellite pools at the Columba fields as well as Lyell and Strathspey. During the turnaround, additional equipment inspections discovered degraded pipework between two oil processing modules resulting in the proactive shut-down for a further 39 days commencing March 18, 2003. As a result of unscheduled turnarounds, Canadian Natural's production from the North Sea was reduced by approximately 7,500 bbls/d in the first quarter and 5,800 bbls/d in the second quarter. On an annual basis, Canadian Natural will achieve its production guidance targets despite the second, unanticipated shut-down for pipework improvements due to the recent drilling success and the originally planned summer platform turnaround at Ninian South being completed in February.

Offshore West Africa

The development of the Espoir Field offshore Cote d'Ivoire continued with the drilling of one injector well in the East Espoir structure, consistent with previously disclosed plans. Canadian Natural plans to perforate the upper zone of the East Espoir structure during the second quarter, adding up to 5,000 bbls/d of net new production. In addition, a producing well was completed late in the quarter, adding about 2,400 bbls/d of production.

Subsequent to the quarter-end, the successful drilling of the satellite pool, Acajou, was completed. The Acajou 1X well has been production tested at gross rates of 3,500 bbls/d. The productive, oil-bearing sands encountered in 1X are thin; however, additional sands, which hold significant potential on the northern portion of the structure, were encountered. After the analysis of the 1X test is completed, Canadian Natural will evaluate drilling the northern portion of Acajou and determine if the development of the satellite field is economically feasible.

The Baobab field development also continues in Cote d'Ivoire. During the quarter, quotes for subsea equipment were awarded and bids were received for a Floating Production, Storage and Offtake ("FPSO") vessel. During the second quarter, an FPSO contract is expected to be awarded and tenders for drilling rigs will be accepted. Based upon two successful exploration well tests, Canadian Natural estimates that 200 million barrels of recoverable oil exist within the structure. The Company is planning for an initial start-up date in 2005 at approximately 45,000 bbls/d for the field. Canadian Natural owns approximately 58% of this field.

Extensive 3-D seismic was also shot over parts of offshore Blocks CI-40 and CI-400, reflecting Canadian Natural's belief that the Espoir/Baobab trend continues across these Blocks. Prospects identified through the interpretation of this seismic may lead to additional exploration drilling in future years.

During the quarter, Canadian Natural also continued to reprocess seismic on Block 16 located offshore Angola to optimize the locations on two separate significant structures; Zenza and Omba. Based on the results of the seismic reprocessing and the results of nearby drilling completed in Block 32 by another operator, the Company will drill one of the two structures in the fourth quarter. Block 16 represents a high risk/high impact exploration development for the Company in one of the most prolific oil regions of the world.

FINANCIAL REVIEW

Canadian Natural recognizes the need for a strong financial position in order to withstand volatile oil and natural gas commodity prices and the operational risks inherent in the oil and natural gas business environment.

During the first quarter of 2003, strong operational results and product pricing enabled the Company to repay approximately $377 million of long-term debt. The strength of the Canadian dollar during the quarter also reduced carrying values of US dollar based borrowings by an additional $203 million, resulting in a total decrease of long-term debt of $580 million. Corporate debt to cash flow was reduced to 1.2 times versus 1.8 times recorded in 2002, while debt to book capitalization improved to 40% from 46% recorded last quarter.

As at March 31, 2003, Canadian Natural had:

-- Approximately $1.2 billion of available unused bank credit

lines.

-- Fixed/floating interest rate mix of 45%/55%.

-- An overall average borrowing cost of approximately 4.9% for

the first quarter of 2003.

-- 82% of borrowings denominated in US dollars.

-- Non-bank based borrowings amounting to 84% of total long-term

debt, with an average maturity of 15.3 years.

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 will monitor its expected cash flow surplus and at present intends to allocate a minimum of 50% of such amounts toward debt repayment. The remaining excess will be directed to the Company's authorized share buy-back program and additional expenditures on conventional oil and natural gas opportunities. Such expenditures will only be incurred as excess cash flows are realized and will be subject to the same economic tests as regular budgeted expenditures. It is expected that the largest portion of the additional capital expenditures will take place late in the third and fourth quarters of 2003 and accordingly will not add materially to Canadian Natural's 2003 average production volumes. Should additional economic opportunities for share buy-back or capital activities not materialize, such allocations of excess cash flow would revert to debt repayment.

In response to the expected demand for oil and natural gas, the related pricing and to protect capital expenditure programs, the Company uses financial instruments to manage exposure to market volatility. The details of these positions are set out in note 8 to the unaudited interim consolidated financial statements.

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 ended March 31, 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
                              March 31    December 31       March 31
                                  2003           2002           2002
--------------------------------------------------------------------
Revenue                        $ 1,628        $ 1,330        $   717
Cash flow from
operations attributable
to common shareholders(1)      $   906        $   777        $   359
  Per common share
   - basic                     $  6.76        $  5.81        $  2.95
   - diluted                   $  6.53        $  5.62        $  2.85
Net earnings
 attributable to common
 shareholders(2)               $   428        $   209        $    99
  Per common share
   - basic                     $  3.19        $  1.56        $  0.81
   - diluted                   $  3.03        $  1.51        $  0.79
Capital expenditures,
 net of dispositions           $   813        $   292        $   459
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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 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
                              March 31    December 31       March 31
($ millions)                      2003           2002           2002
--------------------------------------------------------------------
Net earnings
 attributable to common
 shareholders                      $ 428         $ 209          $  99
Non-cash items:
 Future tax on dividend on preferred
 securities                         (1)            (1)            (1)
 Revaluation of
 preferred securities
 (net of tax)                       (7)            (1)             -
 Depletion, depreciation
  and amortization                 375            386            234
 Unrealized foreign
  exchange gain                   (119)             -            (12)
 Deferred petroleum
  revenue tax                        3              6              1
 Future income tax                 227            178             38
--------------------------------------------------------------------
 Cash flow from
  operations attributable
  to common shareholders         $ 906          $ 777          $ 359
--------------------------------------------------------------------
--------------------------------------------------------------------
(2) After dividend and revaluation of preferred securities.

Canadian Natural achieved record levels of net earnings and cash flow for the three months ended March 31, 2003. Net earnings increased to $428 million, up 332% from the prior year and up 105% from the prior quarter. Cash flow increased to $906 million, up 152% from the prior year and up 17% from the prior quarter. The increase in net earnings and cash flow in the first quarter of 2003, compared to the first quarter of 2002, 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 the acquisition of Rio Alto Exploration Ltd. ("Rio Alto"), the consolidation of working interests in the North Sea and the commencement of production from the Espoir field, located offshore Cote d'Ivoire. Cash flow increased from the prior quarter due to higher product prices. Net earnings increased over the comparable periods due to the increase in product prices and to the strengthening Canadian dollar, resulting in an unrealized foreign exchange gain on the Company's US dollar denominated debt.

ANALYSIS OF QUARTERLY CHANGES IN REVENUE
                 Crude oil and      Natural
                          NGLs          gas   Midstream       Total
-------------------------------------------------------------------
Quarterly Revenue
 ($ millions)
March 31, 2002         $   416      $   291     $    10     $   717
Price variance              66           60           -         126
Volume variance              7           10           -          17
Other variance               -            -           3           3
-------------------------------------------------------------------
June 30, 2002              489          361          13         863
Price variance             117          (72)          -          45
Volume variance            143          122           -         265
Other variance               -            -           -           -
-------------------------------------------------------------------
September 30, 2002         749          411          13       1,173
Price variance             (57)         235           -         178
Volume variance             (5)         (18)          -         (23)
Other variance               -            -           2           2
-------------------------------------------------------------------
December 31, 2002          687          628          15       1,330
Price variance              83          267           -         350
Volume variance            (15)         (40)          -         (55)
Other variance               -            -           3           3
-------------------------------------------------------------------
March 31, 2003         $   755      $   855     $    18     $ 1,628
-------------------------------------------------------------------
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OPERATING HIGHLIGHTS
                                       Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
--------------------------------------------------------------------
Crude oil and NGLs
 ($/bbl, except daily
 production)
Daily production
 (bbls/d)                      237,560        240,596        188,439
Sales price                    $ 35.26        $ 31.10        $ 24.50
Royalties                         3.56           3.53           2.28
Production expense               10.79           9.10           7.81
--------------------------------------------------------------------
Netback                        $ 20.91        $ 18.47        $ 14.41
--------------------------------------------------------------------
Natural gas ($/mcf, except
 daily production)
Daily production (mmcf/d)        1,310          1,365          1,053
Sales price                    $  7.25        $  5.00         $ 3.06
Royalties                         1.78           1.09           0.55
Production expense                0.57           0.57           0.58
--------------------------------------------------------------------
Netback                        $  4.90        $  3.34         $ 1.93
--------------------------------------------------------------------
Barrels of oil equivalent
 ($/boe, except daily
 production)
Daily production (boe/d)       455,952        468,132        363,990
Sales price                    $ 39.24        $ 30.54        $ 21.58
Royalties                         6.96           4.98           2.78
Production expense                7.27           6.34           5.73
--------------------------------------------------------------------
Netback                        $ 25.01        $ 19.22        $ 13.07
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BUSINESS ENVIRONMENT
                                        Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
--------------------------------------------------------------------
WTI benchmark price (US
 $/bbl)                        $ 33.80        $ 28.17        $ 21.67
Differential to LLB
 blend (US $/bbl)              $  8.10        $  8.13        $  5.73
Condensate benchmark
 price (US $/bbl)              $ 33.30        $ 28.56        $ 20.83
NYMEX benchmark price
 (US $/mmbtu)                  $  6.64        $  3.99        $  2.40
AECO benchmark price
 (Cdn $/mmbtu)                 $  7.95        $  5.25        $  3.35
US/Canadian dollar
 exchange rate (US $)          $  0.66        $  0.64        $  0.63
--------------------------------------------------------------------
--------------------------------------------------------------------

In the first quarter of 2003, world oil prices improved significantly due to the uncertainty around the political unrest in Iraq and world supply issues. West Texas Intermediate ("WTI") averaged US $33.80 per bbl in the first quarter of 2003, up 20% compared to US $28.17 per bbl in the prior quarter, and up 56% from US $21.67 compared to the first quarter of 2002.

PRODUCT PRICES
                                       Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
--------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
North America                  $ 30.20        $ 27.57        $ 22.18
North Sea                      $ 50.27        $ 41.83        $ 33.75
Offshore West Africa           $ 37.86        $ 43.15        $ 37.61
Company average                $ 35.26        $ 31.10        $ 24.50
Natural gas ($/mcf)
North America                  $  7.36        $  5.04        $  3.05
North Sea                      $  4.03        $  3.20        $  3.77
Offshore West Africa           $  3.80        $  4.63        $     -
Company average                $  7.25        $  5.00        $  3.06
Percentage of revenue
 (excluding midstream
 revenue)
Crude oil and NGLs               46.9%          52.3%          58.9%
Natural gas                      53.1%          47.7%          41.1%
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North American and North Sea realized crude oil prices increased from the prior quarter and the comparable period in 2002 due to the increase in the world oil price. In the first quarter of 2003, the heavy oil differential averaged US $8.10 per bbl, just below US $8.13 per bbl in the fourth quarter of 2002 and up 41% from US $5.73 per bbl in the first quarter of 2002. The Offshore West Africa realized crude oil price decreased due to the timing and price received on specific product lifting dates. As a result of the use of financial instruments, the realized price from the sale of crude oil was reduced by $4.11 per bbl in the quarter ended March 31, 2003 ($1.73 per bbl and $0.50 per bbl reduction, respectively, in the quarters ended December 31, 2002 and March 31, 2002).

The natural gas price increased 137% from the comparable period in 2002 and 45% from the prior quarter due to higher seasonal demand as a result of colder temperatures and reduced supply, which resulted in lower than normal storage levels in the North American market. During the first quarter of 2003, storage levels were at historical low levels. AECO and NYMEX prices averaged $7.95 and US $6.64 per mmbtu, respectively, during the quarter ended March 31, 2003 compared to $5.25 and US $3.99 per mmbtu during the previous quarter and $3.35 and US $2.40 per mmbtu in the first quarter of 2002. Financial instruments entered into by the Company on its natural gas portfolio resulted in a reduction to realized prices. The price realized from the sale of its natural gas was decreased by $0.50 per mcf in the first quarter of 2003 ($0.07 per mcf reduction and $0.08 per mcf increase, respectively, in the quarters ended December 31, 2002 and March 31, 2002).

DAILY PRODUCTION
                                        Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
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Crude oil and NGLs(bbls/d)
North America                  173,045        181,744        152,268
North Sea                       56,963         51,478         30,910
Offshore West Africa             7,552          7,374          5,261
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Total                          237,560        240,596        188,439
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Natural gas (mmcf/d)
North America                    1,265          1,331          1,026
North Sea                           41             32             27
Offshore West Africa                 4              2              -
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Total                            1,310          1,365          1,053
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Product mix
Light crude oil and NGLs         24.7%          22.4%          19.9%
Pelican Lake crude oil            5.5%           6.1%           7.3%
Primary heavy crude oil          13.2%          14.6%          13.2%
Thermal heavy crude oil           8.7%           8.3%          11.4%
Natural gas                      47.9%          48.6%          48.2%
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Crude oil and NGLs production increased 26% or 49,121 bbls/d from the comparable period in 2002. Crude oil and NGLs production for the first quarter of 2003 was in line with the Company's guidance of 235,000 to 240,000 bbls/d previously provided.

Crude oil and NGLs production in North America increased 14% or 20,777 bbls/d from the comparable period in 2002 due to the acquisition of Rio Alto, additional heavy oil drilling activity and property acquisitions in the Company's core operating regions in North America in 2002. As anticipated, in the Company's guidance, North America crude oil production declined 5% or 8,699 bbls/d over the prior quarter 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 production from the North Sea increased 84% or 26,053 bbls/d from the comparable period in 2002 and 11% or 5,485 bbls/d from the previous quarter due to the consolidation of the Company's working interests in the North Sea during the past year. Crude oil production from the North Sea was impacted by two unscheduled turnarounds on the Ninian South Platform, which resulted in the Company not reaching its expected North Sea production levels for the first quarter of 2003 of 58,000 to 60,000 bbls/d. The Company had planned for extensive platform turnarounds during the second quarter of 2003. Due to the maintenance required at the Ninian South Platform, the turnaround was accelerated and commenced in the first quarter of 2003. As previously announced on March 26, 2003, crude oil production from the Ninian South Platform was shut in until late April in order to proactively replace critical pipework to significantly increase the reliability and integrity of the Ninian South Platform. On an annual basis the Company expects to achieve its production guidance targets in the North Sea due to recent drilling success and the planned summer platform turnaround work being completed on the Ninian South Platform.

Offshore West Africa crude oil production increased 44% or 2,291 bbls/d from the comparable period in 2002 and 2% or 178 bbls/d from the prior quarter as an additional producing well was completed. Production from this field is anticipated to increase as the Company plans to perforate the upper zone of the East Espoir structure during the second quarter, resulting in an anticipated 5,000 bbls/d of additional production to the Company.

Natural gas production continues to represent the Company's largest product offering and increased 24% or 257 mmcf/d from the comparable period in 2002 as a result of the acquisition of Rio Alto on July 1, 2002 and ongoing drilling activities. Natural gas production decreased 4% or 55 mmcf/d from the prior quarter primarily due to declines at the Ladyfern field in northeast British Columbia. Ladyfern production declined from an average of 127 mmcf/d in the fourth quarter of 2002 to 76 mmcf/d during the first quarter of 2003 as well pressures continue to decline. Overall, natural gas production in the first quarter was in line with the Company's guidance of 1,300 to 1,320 mmcf/d.

Natural gas production in the North Sea increased due to the increased working interests acquired in the Banff field as a result of a property swap in 2002.

Natural gas production in Offshore West Africa increased over the comparable period in 2002 due to the natural gas pipeline commencing operation in the third quarter of 2002.

The Company expects production levels to average 1,280 to 1,330 mmcf/d of natural gas and 240,000 to 260,0000 bbls/d of crude oil and NGLs in 2003, unchanged from previous expectations. Second quarter 2003 production guidance is 1,330 to 1,350 mmcf/d of natural gas and 230,000 to 251,000 bbls/d of crude oil and NGLs. During the second quarter, maintenance activities are expected to occur on North American natural gas fields and North Sea platforms excluding the Ninian South Platform.

ROYALTIES
                                        Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
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Crude oil and NGLs ($/bbl)
North America                   $ 4.80         $ 3.82         $ 2.46
North Sea                       $ 0.11         $ 2.79         $ 1.54
Offshore West Africa            $ 1.20         $ 1.35         $ 1.65
Company average                 $ 3.56         $ 3.53         $ 2.28
Natural gas ($/mcf)
North America                   $ 1.84         $ 1.11         $ 0.57
Offshore West Africa            $ 0.11         $ 0.15         $    -
Company average                 $ 1.78         $ 1.09         $ 0.55
Company average ($/boe)         $ 6.96         $ 4.98         $ 2.78
Percentage of revenue
 (excluding financial
 instruments)
Crude oil and NGLs                9.0%          10.7%           9.1%
Natural gas                      22.9%          21.4%          18.5%
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North America crude oil and NGLs royalties increased as a result of certain heavy oil projects reaching payout in 2002 and becoming subject to higher government royalties. North Sea crude oil royalties as a percentage of revenue decreased in the first quarter 2003 as a result of the elimination of government royalties in the North Sea effective January 1, 2003.

Natural gas royalties as a percentage of revenue increased over both the prior quarter and the comparable prior year period as a result of the strong correlation of royalties to natural gas prices.

PRODUCTION EXPENSE
                                      Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
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Crude oil and NGLs ($/bbl)
North America                  $  9.09        $  7.34        $  6.97
North Sea                      $ 15.50        $ 14.68        $ 10.09
Offshore West Africa           $ 14.03        $ 13.68        $ 18.62
Company average                $ 10.79        $  9.10        $  7.81
Natural gas ($/mcf)
North America                  $  0.55        $  0.55        $  0.56
North Sea                      $  1.09        $  1.25        $  1.33
Offshore West Africa           $  2.37        $  1.85        $     -
Company average                $  0.57        $  0.57        $  0.58
Company average ($/boe)        $  7.27        $  6.34        $  5.73
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The increase in North American crude oil and NGLs production expense over the comparable three-month periods is primarily attributable to the increase in natural gas fuel costs. Natural gas is used to produce the steam to heat the Company's thermal oil formations in the Primrose area of Alberta. North Sea crude oil production expense increased on a per barrel basis due to the impact of reduced production as a result of the shut down of the Ninian South Platform. Offshore West Africa crude oil production costs for the three months ended March 31, 2003 decreased from the comparable period in 2002 due to increased production from the Espoir field.

Natural gas production expense for the three months ended March 31, 2003 was consistent with the prior quarters.

MIDSTREAM ($ millions)
                                        Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
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Revenue                           $ 18           $ 15           $ 10
Operating costs                      5              5              3
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Operating cash flow                 13             10              7
Depreciation                         2              2              2
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Segment earnings before taxes     $ 11           $  8           $  5
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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 82% of the Company's heavy oil production was transported to the 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 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 in the first quarter of 2003 from the comparable periods due to higher electricity prices received in the first quarter of 2003. Revenue from the Company's midstream assets is expected to increase later in 2003, with the expansion of the ECHO pipeline to 72 mbbls/d from 58 mbbls/d.

DEPLETION, DEPRECIATION AND AMORTIZATION(1)

                                        Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
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Expense ($ millions)            $  373         $  384         $  232
 $/boe                          $ 9.09         $ 8.92         $ 7.08
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(1) DD&A does not include midstream operations.

Depletion, depreciation and amortization ("DD&A") in the first quarter of 2003 increased in total and per boe from the first quarter of 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 decreased from the prior quarter on a total basis due to lower production, but increased on a boe basis due to a higher portion of the Company's production coming from the North Sea segment.

ADMINISTRATION EXPENSE

                                       Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
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Net expense ($ millions)        $   18         $   17         $   14
 $/boe                          $ 0.44         $ 0.41         $ 0.41
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Administration expense for the three months ended March 31, 2003 remained relatively stable with the prior quarter in total but increased on a boe basis due to decreased production levels. Administration expense increased from the first quarter of 2002 due to the increased costs associated with the growth in production and the expanding asset base.

INTEREST EXPENSE
                                         Three Months Ended
                              March 31    December 31      March 31
                                  2003           2002           2002
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Interest expense, net
 ($ millions)                   $   48         $   53         $   28
  $/boe                         $ 1.16         $ 1.22         $ 0.88
Average effective
 interest rate                    4.9%           5.0%           4.1%
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Interest expense for the three months ended March 31, 2003 increased from the comparable period in 2002 due to higher debt levels associated with the acquisition of Rio Alto on July 1, 2002. The increase in interest expense was also affected by the increase in the Company's effective interest rate resulting from increases in the Canadian prime lending rate and a greater proportion of higher fixed rate debt. Interest expense decreased from the previous quarter due to lower debt levels as the Company used excess cash flow generated in the first quarter to repay $377 million of long-term debt. In addition, the strengthening Canadian dollar reduced the Canadian equivalent interest expense on the Company's US dollar denominated debt.

FOREIGN EXCHANGE ($ millions)
                                        Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
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Realized foreign
 exchange loss                  $    1         $    2         $    2
Unrealized foreign
 exchange gain                    (119)             -            (12)
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                                $ (118)        $    2         $  (10)
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The strengthening of the Canadian dollar to US $0.68 at the end of the first quarter compared to US $0.63 at December 31, 2002 resulted in an unrealized foreign exchange gain on the Company's US dollar denominated debt.

In order to mitigate a portion of the volatility associated with the Canadian dollar, 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. For the three months ended March 31, 2003, foreign exchange gains of $62 million (December 31, 2002 - $4 million gain; March 31, 2002 - nil) were included in the foreign currency translation adjustment.

TAXES ($ millions, except income tax rates)
                                         Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
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Taxes other than income tax
Current                          $  25          $  15          $  14
Deferred                             3              6              1
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Total                            $  28          $  21          $  15
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Current income tax
North Sea                        $  15          $ (36)         $  11
Offshore West Africa                 2              1              1
North America - Current
 income tax                         16              -              -
North America - Large
 corporations tax                    6              7              4
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Total                            $  39          $ (28)         $  16
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Future income tax                $ 227          $ 178          $  38
Effective income tax rate        38.6%          41.7%          35.0%
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Taxes other than income tax consists of current and deferred petroleum revenue tax ("PRT"), other international taxes and provincial capital taxes. PRT is charged on certain fields in the North Sea at the rate of 50% of net operating income, after certain deductions including abandonment expenditures. Taxes other than income taxes increased from the comparable periods as a result of higher oil prices and increased production levels.

North Sea current income tax in the first quarter of 2003 increased from the previous year due to the introduction of the supplementary charge of 10% on profits from UK North Sea oil and natural gas production. The North Sea supplementary charge took effect April 17, 2002, is in addition to the corporate tax rate of 30% and excludes any deduction for financing costs. Current income tax in the first quarter 2003 increased due to the settlement in the fourth quarter 2002 of certain outstanding matters from prior years and the impact of the increase in the first year allowance rate for plant and machinery expenditures to 100% from the previous rate of 25%.

Taxable income from the conventional oil and natural gas business in Canada is generated by partnerships and the related income taxes will be payable in the following year. Current income taxes have been provided on the basis of the corporate structure and available income tax deductions. No current income tax provision was required for North America in 2002.

In its 2003 budget speech, the Canadian Federal Government announced the elimination of the federal Large Corporations Tax ("LCT") over a five-year period. The LCT is currently levied at a rate of 0.225% of the Company's taxable capital employed in Canada. The Federal Government also announced plans to reduce the general corporate income tax rate on income from resource activities over a five-year period from the current rate of 28% to 21%, bringing the resource industry in line with the general corporate income tax rate. As part of the corporate income tax rate reduction, the budget also plans for the elimination of the existing 25% resource allowance and the introduction of a deduction for actual provincial and other crown royalties paid. No adjustments for these proposed changes will be made until the plan becomes substantively enacted.

Future income tax expense for the three months ended March 31, 2003 increased over the comparable three month periods due to higher taxable income generated by high product prices.

CAPITAL EXPENDITURES ($ millions)
                                          Three Months Ended
                              March 31    December 31       March 31
                                  2003           2002           2002
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Expenditures on
 property, plant and
 equipment
Net property
 acquisitions                    $ 178          $  39          $  35
Land acquisition and
 retention                          21             18             28
Seismic evaluations                 19             19             25
Well drilling,
 completion and
 equipping                         396            139            207
Pipeline and production
 facilities                        149             45            124
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Total net reserve
 replacement
 expenditures                    $ 763          $ 260          $ 419
Horizon Oil Sands Project           41             19             22
Midstream                            3              6             10
Abandonments                         3              4              7
Head office                          3              3              1
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Total net capital
 expenditures                    $ 813          $ 292          $ 459
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By segment
North America                    $ 643          $ 124          $ 390
North Sea                           90            120            (32)
Offshore West Africa                30             16             61
Horizon Oil Sands Project           41             19             22
Midstream                            3              6             10
Abandonments                         3              4              7
Head office                          3              3              1
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Total                            $ 813          $ 292          $ 459
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During the first quarter of 2003, the Company drilled a record 749 wells, including 366 stratigraphic test and service wells. The Company had a very active natural gas drilling program, drilling a total of 244 successful natural gas wells. North America capital expenditures included the drilling of 42 wells in the new Northwest Alberta core region, where the Company is taking a disciplined approach to the development with a view of reducing capital costs and total finding costs. In the Cardium-oriented southern portion of the Northwest core region, a total of 11 wells targeting natural gas were drilled with a success rate of 100%. In the Cretaceous-oriented northern portion of this core region, a total of 30 wells targeting natural gas were drilled with a success rate of 74%. In the Northeast British Columbia core region, a total of 81 wells targeting natural gas were drilled, including the drilling of three unsuccessful Slave Point natural gas exploration wells. The Company was also active in its traditional natural gas core regions of North Alberta and South Alberta where 119 and 22 wells targeting natural gas were drilled respectively. The Company also drilled 116 successful oil wells during the first quarter. These wells were concentrated in the Company's oil region of North Alberta, where 68 primary heavy oil and 26 Pelican Lake wells were drilled. Five high-pressure horizontal thermal wells were also drilled and completed at Primrose as part of the 2003/2004 development strategy for this area. The Company drilled 312 stratigraphic test wells on the oil sands leases of the Horizon Oil Sands Project and an additional 51 stratigraphic test wells in North Alberta. Capital expenditures also included work on the Horizon Oil Sands Project, where work continues on the Design Basis Memorandum ("DBM") that is anticipated to be completed early in the summer. The Engineering Design Specification will commence immediately after the completion of the DBM. Work has commenced on the access road, including the construction of three bridges.

North Sea capital expenditures included successfully drilling two oil wells from the Ninian platforms and one well from the Murchison platform. In addition, a satellite pool was drilled off the Murchison platform but encountered no hydrocarbons.

Offshore West Africa capital expenditures included the continued development of the Espoir field located offshore Cote d'Ivoire with the drilling of one injector well in the East Espoir structure. The Company plans to perforate the upper zone of the East Espoir structure during the second quarter of 2003. Development of the Baobab field continued during the first quarter with quotes for subsea equipment being awarded and bid requests received for a Floating Production, Storage and Offtake vessel. The first quarter also saw extensive 3-D seismic shot over parts of offshore Blocks CI-40 and CI-400 and the Company continues to reprocess seismic on Block 16, located offshore Angola. The Company's current plans regarding Block 16 envision the drilling of either the Zenza or the Omba prospect during the fourth quarter of 2003.

LIQUIDITY AND CAPITAL RESOURCES
                                        Three Months Ended
($ millions, except ratios)   March 31    December 31       March 31
                                  2003           2002           2002
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Working capital deficit        $   318        $    14        $    84
Long-term debt                   3,494          4,074          2,658
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Total                          $ 3,812        $ 4,088        $ 2,742
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Shareholders' equity
Preferred securities             $ 118          $ 126        $   128
Share capital                    2,327          2,304          1,739
Retained earnings                2,801          2,414          1,992
Foreign currency
 translation adjustment             16             24             69
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Total                          $ 5,262        $ 4,868        $ 3,928
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Debt to cash flow(1)              1.2x           1.8x           1.6x
Debt to book
 capitalization                  39.9%          45.6%          40.4%
Debt to market
 capitalization                  33.8%          38.9%          29.2%
After tax return on
 average common
 shareholders' equity(1)         20.3%          13.8%          14.6%
After tax return on
 average capital
 employed(1)                     12.6%           8.9%           9.7%
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(1) Based on trailing 12-month activity.

The Company recognizes the need for a strong financial position in order to withstand volatile oil and natural gas commodity prices and the operational risks inherent in the oil and natural gas business environment. During the first quarter long-term debt was reduced by $580 million. Higher than budgeted prices received for the Company's products are expected to result in cash flow to the Company in 2003 over the budget established in late 2002. The Company is continuing to monitor its expected cash flow surplus and at present intends to allocate a minimum of 50% of such amounts toward debt repayment. The remaining excess will be directed to the Company's authorized share buy-back program and additional expenditures on conventional oil and natural gas opportunities. These expenditures will only be incurred as excess cash flow are realized and will be subject to the same economic tests as regular budgeted expenditures. It is expected that the largest portion of the additional capital expenditures will take place late in the third and fourth quarters of 2003 and accordingly will not add materially to the Company's 2003 average production volumes. Should additional economic opportunities for share buy-back or capital activities not materialize to the extent allocated, such allocations of surplus cash flow would revert to debt repayment.

(MORE TO FOLLOW)