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Canadian Natural Resources Limited Announces Third Quarter Results

Posted on: Thursday, 1 November 2007, 06:00 CDT

Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ):

Commenting on third quarter 2007 results, Canadian Natural's Chairman, Allan Markin stated, "As we exit the first nine months of the year, we continue with our defined plan to manage costs while maximizing value. With the Horizon Project at 84% complete, we remain on track for targeted first oil in the third quarter of 2008 and maintain our focus on execution. Our defined plan will be optimized to take into account the new royalty program that was announced by the Government of Alberta on October 25th and expected to take effect in 2009. The new royalty program will have a negative impact, which we are still attempting to fully define, on our development plans in 2008 and in the future. As a result, we will carefully adjust our activity to ensure we are maximizing returns for our shareholders."

John Langille, Vice-Chairman, stated, "With respect to our balance sheet, our debt to book capitalization decreased as expected. On the marketing side, while we have seen record breaking US dollar reference prices for crude oil, pricing for natural gas in Canada has been weaker than expected. Warmer weather has dictated the soft market for natural gas, along with increasing liquefied natural gas (LNG) imports to the United States. Given that crude oil and natural gas realized prices are tied to US reference prices, the strengthening of the Canadian dollar relative to the US dollar has also had a negative impact on industry cash flows, lessening the impact of higher WTI pricing. However, Canadian Natural's extensive 2007 hedging program has reduced the impact on our realized natural gas price."

Steve Laut, President and Chief Operating Officer of Canadian Natural commented, "In the first nine months of 2007 we continued to demonstrate the strength and quality of our asset base which facilitates the allocation of our capital to higher returning projects. North American natural gas production, as expected, declined in the quarter and will continue to decline for the remainder of the year, reflecting our reduced capital spending in 2007 due to the lower returns currently being generated in the natural gas part of the business. Conversely, North American conventional liquids returns remain strong and quarterly production increased, reflecting growth at Pelican Lake as well as thermal wells transitioning off the steaming cycle and into production."

 HIGHLIGHTS                                Three Months Ended       Nine Months Ended                            ------------------------------------------------- ($ millions, except as       Sep 30    Jun 30    Sep 30    Sep 30    Sep 30  noted)                        2007      2007      2006      2007      2006 ---------------------------------------------------------------------------- Net earnings               $    700 $     841 $   1,116 $   1,810 $   2,211  per common share, basic   and diluted              $   1.30 $    1.56 $    2.08 $    3.36 $    4.12 Adjusted net earnings  from operations (1)       $    644 $     595 $     470 $   1,860 $   1,252  per common share, basic   and diluted              $   1.19 $    1.10 $    0.87 $    3.44 $    2.33 Cash flow from  operations (2)            $  1,577 $   1,513 $   1,313 $   4,712 $   3,639  per common share, basic   and diluted              $   2.92 $    2.81 $    2.44 $    8.74 $    6.77 Capital expenditures, net  of dispositions           $  1,442 $   1,460 $   1,661 $   4,911 $   5,528 Daily production, before  royalties  Natural gas (mmcf/d)         1,647     1,722     1,437     1,695     1,449  Crude oil and NGLs   (bbl/d)                   333,062   327,494   321,665   329,208   328,053  Equivalent production   (boe/d)                   607,484   614,461   561,152   611,665   569,590 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Adjusted net earnings from operations is a non-GAAP measure that the     Company utilizes to evaluate its performance. The derivation of this     item is discussed in the Management's Discussion and Analysis ("MD&A"). (2) Cash flow from operations is a non-GAAP measure that the Company     considers key as it demonstrates the Company's ability to fund capital     reinvestment and debt repayment. The derivation of this measure is     discussed in the MD&A. 

- As expected, natural gas production volumes declined from the prior quarter in 2007 but continued to perform well. Natural gas production for Q3/07 averaged 1,647 mmcf/d, up 15% from 1,437 mmcf/d for Q3/06 and down 4% from 1,722 mmcf/d for Q2/07. Volumes in Q3/07 continued to reflect better than expected production from a number of wells, the addition of Anadarko Canada Corporation ("ACC") acquisition volumes, and continued high-grading of opportunities.

- Total crude oil and NGLs production for Q3/07 was 333,062 bbl/d. Q3/07 production was 4% higher than Q3/06 volumes of 321,665 bbl/d, and increased 2% from Q2/07 volumes of 327,494 bbl/d. Increased volumes in Q3/07 reflected the transition from steam cycles to production cycles for a number of thermal wells and continued development of Pelican Lake.

- Quarterly cash flow from operations was $1,577 million, an increase of 20% from Q3/06 and an increase of 4% from Q2/07. The increase from Q3/06 primarily reflected higher commodity realizations, lower year over year risk management losses, and the impact of higher sales volumes due to the acquisition of ACC. The increase from Q2/07 represented higher sales volumes in Q3/07. Cash flow in Q3/07 was negatively impacted by the strengthening of the Canadian dollar compared to the US dollar. The average exchange rate for Q3/07 was US$0.9565 per C$1.00 compared with US$0.9112 per C$1.00 for Q2/07 and US$0.8919 per C$1.00 for Q3/06.

- Q3/07 quarterly net earnings were $700 million, a 37% decrease from Q3/06 and a 17% decrease from Q2/07. Quarterly adjusted net earnings from operations for Q3/07 were $644 million, an increase of 8% from Q2/07 results and a 37% increase from Q3/06.

- Completed the Q3/07 North American drilling program targeting 153 net crude oil wells and 106 net natural gas wells with a 95% success ratio in the quarter, excluding stratigraphic test and service wells. The success rate is a reflection of Canadian Natural's strong, predictable, low-risk asset base. Crude oil drilling activity was down from 263 net wells in Q3/06 due to the timing of the drilling program. Natural gas drilling decreased 5% from Q3/06, reflecting Canadian Natural's reallocation of capital towards a higher return crude oil drilling program.

- Maintained a strong undeveloped conventional core land base in Canada of 11.9 million net acres - a key asset for continued value growth.

- Continued production improvements at the Pelican Lake Field from new drilling activity and the expansion of the enhanced crude oil recovery program. Pelican Lake crude oil production averaged approximately 35,000 bbl/d during the quarter, up 17% or approximately 5,000 bbl/d from Q3/06. Production is targeted to continue to increase in Q4/07.

- Secured a deep water drilling rig for the Baobab Field. The equipment is targeted to be mobilized in Q1/08, enabling work to begin on the restoration of shut-in production. It is forecasted that 3 of the 5 shut-in Baobab wells should come back on stream over the course of 2008 and 2009.

- Work progress on the Horizon Oil Sands Project ("Horizon Project") exited Q3/07 at 84% complete and remains on track for first oil targeted Q3/08.

- On October 25, 2007 the Province of Alberta issued the details of its proposed changes to the Alberta crude oil and natural gas royalty regime, effective January 1, 2009. The Company expects that its 2009 and future Alberta royalty payments will increase as a result of the proposed royalty regime changes and that its level of activity in Alberta will be reduced from what it otherwise would have been in the absence of such royalty changes. In the current pricing and cost environment, the biggest reduction in the Company's Alberta activity will be experienced in the conventional natural gas business. The number of natural gas wells to be drilled in Alberta by the Company in 2008 and years beyond will be approximately 30% to 50% less than the number of such wells that would have otherwise been drilled in the absence of such royalty changes.

- Declared a quarterly cash dividend on common shares of C$0.085 per common share, payable January 1, 2008, a 13% increase over the 2006 quarterly dividend.

OPERATIONS REVIEW AND CAPITAL ALLOCATION

In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where it can dominate the land base and infrastructure. Undeveloped land is critical to the Company's ongoing growth and development within these core regions. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By dominating infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Further, the Company maintains large project inventories and production diversification among each of the commodities it produces; namely natural gas, light/medium and heavy crude oil and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.

OPERATIONS REVIEW

 Activity by core region                                 --------------------------------------------                                    Net undeveloped land   Drilling activity                                                   as at   nine months ended                                            Sep 30, 2007        Sep 30, 2007                                 (thousands of net acres)     (net wells) (1) ---------------------------------------------------------------------------- Canadian conventional  Northeast British Columbia                       2,419                  53  Northwest Alberta                                1,501                  97  Northern Plains                                  6,523                 507  Southern Plains                                    901                  94  Southeast Saskatchewan                             117                  12  In-situ Oil Sands                                  482                 179 ----------------------------------------------------------------------------                                                  11,943                 942 Horizon Oil Sands Project                           115                  98 United Kingdom North Sea                            298                   7 Offshore West Africa                                206                   4 ----------------------------------------------------------------------------                                                  12,562               1,051 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Drilling activity includes stratigraphic test and service wells Drilling activity (number of wells)                                                Nine Months Ended                                        -------------------------------------                                            Sep 30, 2007        Sep 30 ,2006                                         Gross       Net     Gross       Net ---------------------------------------------------------------------------- Crude oil                                 458       423       471       426 Natural gas                               386       303       774       581 Dry                                        89        77       102        91 ---------------------------------------------------------------------------- Subtotal                                  933       803     1,347     1,098 Stratigraphic test / service wells        250       248       310       309 ---------------------------------------------------------------------------- Total                                   1,183     1,051     1,657     1,407 ---------------------------------------------------------------------------- Success rate (excluding stratigraphic  test / service wells)                               90%                 92% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North America Conventional North America natural gas                                 Three Months Ended       Nine Months Ended                            -------------------------------------------------                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30                                2007      2007      2006      2007      2006 ---------------------------------------------------------------------------- Natural gas production  (mmcf/d)                     1,622     1,696     1,416     1,670     1,425 ---------------------------------------------------------------------------- Net wells targeting  natural gas                    106         7       111       358       658 Net successful wells  drilled                         96         6        98       303       581 ----------------------------------------------------------------------------  Success rate                    91%       86%       88%       85%       88% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 

- Q3/07 North America natural gas production increased by 15% over Q3/06 and as expected, decreased by 4% from Q2/07. The increase from Q3/06 reflected the full impact of the acquisition of ACC natural gas volumes, whereas the decrease from Q2/07 reflected the Company's strategic decision to scale back the 2007 drilling program due to reallocation of capital to currently higher return crude oil projects.

- Canadian Natural targeted 106 net natural gas wells in Q3/07 including 32 wells in the Northern Plains region, 8 wells in the Northwest Alberta region, 63 well in the Southern Plains region and 3 wells in the Northeast British Columbia region, with an overall success rate of 91%. This compares to 111 net targeted natural gas wells in Q3/06, a 5% reduction.

- Planned drilling activity for Q4/07 includes 63 targeted natural gas wells.

 North America crude oil and NGLs                                 Three Months Ended       Nine Months Ended                            -------------------------------------------------                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30                                2007      2007      2006      2007      2006 ---------------------------------------------------------------------------- Crude oil and NGLs  production (bbl/d)         252,095   240,420   233,440   243,388   230,430 ---------------------------------------------------------------------------- Net wells targeting  crude oil                      153        78       263       438       431 Net successful wells  drilled                        150        75       253       416       417 ----------------------------------------------------------------------------  Success rate                    98%       96%       96%       95%       97% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 

- Q3/07 North America crude oil and NGLs production increased 8% from Q3/06 and increased 5% over Q2/07 levels. The majority of the incremental production volume was contributed by thermal crude oil and Pelican Lake crude oil. Primrose thermal production in Q3/07 was negatively impacted by unplanned outages at the processing plant due to lightning strikes and water treatment issues as well as higher than expected scaling rates on new pads. As a result, Primrose production was approximately 3,000 bbl/d less than Q3/07 expectations.

- During Q3/07, drilling activity included 94 net wells targeting heavy crude oil, 33 net wells targeting Pelican Lake crude oil, 21 net wells targeting thermal crude oil and 5 net wells targeting light crude oil.

- The Primrose East Expansion, a new facility located 15 kilometers from the existing Primrose South steam plant and 25 kilometers from the Wolf Lake central processing facility, is anticipated to add approximately 40,000 bbl/d of crude oil. The Primrose East Expansion received Board of Directors' sanction in 2006 and The Alberta Energy and Utilities Board regulatory approval in the first quarter of 2007. Drilling and construction are currently underway, and production is targeted to commence in 2009. Primrose East is the second phase of the 300,000 bbl/d conventional expansion plan identified to unlock the value from Canadian Natural's thermal crude oil resource base.

- In early 2007, Canadian Natural announced its proposed third phase of the conventional expansion plan with a development plan for the 45,000 bbl/d Kirby In-Situ Oil Sands Project located approximately 85 km northeast of Lac La Biche in the Regional Municipality of Wood Buffalo. The Company has filed its formal regulatory application documents for this project as part of the Company's normal course of business. Final corporate sanction will be impacted by the terms of the proposed changes to the Alberta royalty regime, environmental regulations, and the final determination of associated capital costs.

- Development of new pads and secondary recovery conversion projects at Pelican Lake continued as expected throughout Q3/07. Drilling consisted of 34 horizontal wells, with plans to drill 13 additional horizontal wells for the remainder of 2007. The response from the water and polymer flood project continues to be positive. Pelican Lake production averaged approximately 35,000 bbl/d for Q3/07 compared to approximately 30,000 bbl/d for Q3/06.

- Conventional heavy crude oil production volumes increased slightly in Q3/07 compared to Q2/07. Production levels for primary were below target due to earlier than expected declines in certain older fields.

- Planned drilling activity for Q4/07 includes 120 net crude oil wells, excluding stratigraphic test and service wells.

International

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

                                 Three Months Ended       Nine Months Ended                            -------------------------------------------------                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30                                2007      2007      2006      2007      2006 ---------------------------------------------------------------------------- Crude oil production  (bbl/d)  North Sea                   52,013    57,286    53,988    57,020    59,473  Offshore West Africa        28,954    29,788    34,237    28,800    38,150 ---------------------------------------------------------------------------- Natural gas production  (mmcf/d)  North Sea                       10        15        11        13        15  Offshore West Africa            15        11        10        12         9 ---------------------------------------------------------------------------- Net wells targeting  crude oil                      2.2       3.1       2.2       7.3       9.2 Net successful wells  drilled                        2.2       3.1       2.2       7.3       9.2 ----------------------------------------------------------------------------  Success rate                   100%      100%      100%      100%      100% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 

North Sea

- Planned platform maintenance shutdowns scheduled for Q3/07 at Ninian, B-Block and T-Block were successfully completed, reducing Q3/07 volumes compared to Q2/07, as expected. During Q3/07, 1.0 net crude oil well was drilled along with 0.9 net water injectors.

- The development of the Lyell Field continued with the second well onstream in Q3/07 through the existing infrastructure. Production from the initial Lyell producing wells has been below expectations. Although the wells encountered thick pay sections, the formation is tight and as a result production dropped from high initial rates to much lower than targeted stabilized rates. As a result continued development of the Lyell Field is under review.

- Commissioning of the Columba E raw water injection facilities was completed in Q2/07 along with 2 water injection wells facilitating water injection into the reservoir to commence. The subsea wells are currently injecting 2,500 bbl/d of water, lower than targeted, as they encountered significantly tighter formations than expected. As a result production increases from Columba will be delayed.

- In Q3/07, Canadian Natural entered into a Sale and Purchase Agreement for the disposal, subject to government and partner consents, of its entire working interest in the Balmoral, Stirling and Glamis Fields (B-Block). During Q3/07, transition arrangements and consents progressed, with closing expected during Q4/07 or early in 2008. In 2007, the B-Block has produced approximately 1,600 bbl/d net to Canadian Natural, representing less than 0.5% of Canadian Natural's total crude oil and NGLs production year to date.

Offshore West Africa

- During Q3/07, 1.2 net wells were drilled with 0.6 additional net wells drilling at the end of the quarter.

- West Espoir commenced production in mid 2006. During Q3/07, 1 additional production well and 1 additional injector were added. The West Espoir area has seen favorable production growth and development drilling is continuing into 2008 with producers and injectors being brought on-line as they are completed.

- During Q3/07, in order to increase its throughput handling capability Canadian Natural awarded a contract for the upgrade of the Espoir Floating Production Storage and Offtake ("FPSO") vessel. Design and procurement work commenced during the quarter, with installation of equipment on the FPSO targeted to start in late 2009.

- A deep water drilling rig has been secured for the Baobab Field. The rig is now targeted to be mobilized in Q1/08. The Company is targeting to bring 3 of 5 of the shut-in Baobab wells back into production over the course of 2008 and 2009.

- At the 90% owned and operated Olowi Field in offshore Gabon, all major construction contracts have been awarded. The project is on schedule with drilling targeted to commence in Q2/08 and first crude oil is targeted for late 2008 or early 2009. Production is targeted to plateau at approximately 20,000 bbl/d in Q4/09.

Horizon Project

- Canadian Natural achieved an overall work progress at the end of the quarter at 84% complete and construction 76% complete. All major vessels have either been erected or are currently on site. Work scheduled for the coming months will continue to focus on mechanical construction, which is scheduled to be completed through a combination of lump sum and reimbursable contracts.

- The Horizon Project remains on track for targeted first oil in Q3/08. Project progress achieved 9% progress despite the distraction of Alberta-wide labour negotiations that occurred throughout the summer.

- Pre-commissioning work has been initiated in the area of Utilities and Offsites and Bitumen Production, with hydro-testing targeted for completion.

- Previous decisions to defer several contracts and delay certain projects to capture cost reduction opportunities has caused overlap between some construction projects on the site and has resulted in an increase in peak project manpower requirements. Canadian Natural's supporting camp and transportation infrastructure has been successfully expanded to accommodate the higher peak in manpower to ensure workers are adequately accommodated.

- As a result, some work has been pushed into the more challenging winter months, resulting in a modest increase in the forecast completion cost for the Horizon Project. The Company's current Horizon Project completion cost forecast has been increased from the 5% to 12% range provided in the first quarter 2007 Horizon Project Update to an 8% to 14% range over the original $6.8 billion estimate.

- The quarterly update for Phase 1 of the Horizon Project is as follows:

 Project status summary                               June 30,     September 30,        December 31,                                  2007              2007                2007                                Actual  Actual  Original  Forecast  Original                                                    Plan                Plan Phase 1 - Work progress  (cumulative)                      75%     84%       88%       90%       94% Phase 1 - Construction  capital spending(a)  (cumulative)                      79%     89%       85%       99%       92% (a) Relative to overall Phase 1 project capital of $6.8 billion 

Accomplished to the End of the Third Quarter of 2007

Detailed Engineering

- Overall detailed engineering 98% complete and substantially completed in most areas.

Procurement

- Overall procurement progress is 98% complete.

- Have awarded over $5.5 billion in purchase orders and contracts to date.

- Delivered over 35,000 standard loads of all kinds to site.

- Operations and maintenance service and supply agreements are in negotiation.

Modularization

- Delivered an additional 80 oversized loads to site for a total of 1,504 loads, which represents approximately 91% of the total requirement.

Construction

- Overall construction progress is 76% complete.

- Mine overburden removal has moved 43.8 million bank cubic meters, which represents approximately 63% of the total to be moved and is slightly ahead of schedule.

- Energized Main Electrical Substations.

- Completed construction of Raw Water Pond.

- Started pre-commissioning activities in Bitumen Production Areas.

- Froth tank completed and hydro-tested.

- Commenced extraction plant hydro-testing.

- Permanent power energized in R1/R2 corridors pumphouses.

- Started commissioning of Recycle Water Pond.

Milestones for the Fourth Quarter of 2007

- Complete the closure of Dyke 10 (external tailings pond) in Mining.

- Complete erection of Crushing Plants and conveyors in Ore Preparation Area.

- Complete Primary Separation Cells in Extraction.

- Complete Main Control Room and Distributed Control Systems installation.

- Complete construction of Main Laboratory.

Plant and System Commissioning Schedule

Completed

- Permanent Potable Water Treatment

- Permanent Sewage Treatment

- Natural Gas Pipeline

- Raw and Recycled Water Pipelines

- River Water Intake and Pumphouse

Q4/07

- Raw Water Pond and Pumphouse

- Recycle Water Pond and Pumphouse

- Extraction

- Electrical Distribution System

Q1/08

- Cooling and Heating System

- Main Pipe Rack

Q2/08

- Cogeneration

- Ore Preparation Plant

- Froth Treatment

- Pipeline Corridors

- Hydrogen Plant

- Coker / Diluent Recovery Unit

- Gas Treating and Sulphur Recovery

- Synthetic crude oil pipeline

- Sulphur block pipelines

- West Tank Farm (inter-plant)

Q3/08

- Hydrotreating

- East Tank Farm (product)

Operations Readiness

- The Company expects to meet its hiring requirements by the end of the year for the Operations group. Training programs are in place and, in anticipation of turnover, Operations have commenced the review of systems in certain plants.

 MARKETING                                Three Months Ended       Nine Months Ended                            -------------------------------------------------                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30                                2007      2007      2006      2007      2006 ---------------------------------------------------------------------------- Crude oil and NGLs pricing  WTI(1) benchmark price   (US$/bbl)                $  75.33  $  65.02  $  70.55  $  66.26  $  68.29  Lloyd Blend Heavy oil   differential from WTI (%)      30%       30%       27%       29%       32%  Corporate average pricing   before risk management   (C$/bbl)                 $  58.10  $  53.74  $  62.55  $  54.57  $  55.91 Natural gas pricing  AECO benchmark price   (C$/GJ)                  $   5.32  $   6.99  $   5.72  $   6.46  $   6.82  Corporate average   pricing before risk   management (C$/mcf)      $   5.87  $   7.44  $   5.83  $   7.03  $   6.75 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at      Cushing, Oklahoma. 

- In Q3/07, the Lloyd Blend heavy crude oil differential as a percent of WTI was 30%, compared to 27% in Q3/06.

- Canadian Natural has committed to 25,000 bbl/d of pipeline capacity on the Pegasus Pipeline which transports Company crude oil volumes to the U.S. Gulf Coast as part of the Company's efforts towards working with various industry groups to find new markets for Western Canadian heavy crude oil and to ease the logistical constraints in getting crude oil to the area. The pipeline reversal has had the impact of improving the corporate realized price on Canadian Natural's heavy crude oil production. The heavy crude oil sold to the Gulf Coast receives Mayan equivalent pricing, a premium to the Lloyd Blend price. For Q3/07, the Mayan differential to WTI averaged US$12.30/bbl or 16%.

- During Q3/07, the Company contributed approximately 134,000 bbl/d of its heavy crude oil streams to the Western Canadian Select blend as market conditions resulted in this strategy offering the optimal pricing for bitumen.

- Natural gas inventories in North America continue to remain high in Q3/07 due to a significant increase in liquefied natural gas (LNG) imports to the United States along with stable production levels in that country. These factors contributed to depressed pricing for natural gas for North America relative to WTI.

FINANCIAL REVIEW

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

-- A diverse asset base geographically and by product - produced in excess of 607,000 boe/d in Q3/07, comprised of approximately 45% natural gas and 55% crude oil - with 95% of production located in G8 countries with stable and secure economies.

-- Financial stability and liquidity - cash flow from operations of $4.7 billion for the first nine months of 2007, available unused bank lines of $1.3 billion at September 30, 2007 and access to capital debt markets supported by strong credit ratings.

-- Reduced volatility of commodity prices - a proactive commodity hedging program to reduce the downside risk of volatility in commodity prices supporting cash flow for its capital expenditure program throughout the Horizon Project.

- In September 2007, the Company filed a short form prospectus that allows for the issue of up to US$3.0 billion of debt securities in the United States until October 2009. Simultaneously the Company filed a short form shelf prospectus that allows for the issue of up to $3.0 billion of medium-term notes in Canada until October 2009. If issued, these securities will bear interest as determined at the date of issuance.

- Declared a quarterly cash dividend on common shares of C$0.085 per common share, payable January 1, 2008, a 13% increase over the 2006 quarterly dividend.

OUTLOOK

The Company forecasts 2007 production levels before royalties to average between 1,664 and 1,676 mmcf/d of natural gas and between 326,000 and 334,000 bbl/d of crude oil and NGLs. Q4/07 production guidance before royalties is forecast to average between 1,577 and 1,616 mmcf/d of natural gas and between 321,000 and 344,000 bbl/d of crude oil and NGLs. Detailed guidance on revised production levels, capital allocation and operating costs can be found on the Company's website at http://www.cnrl.com/investor_info/corporate_guidance/.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Forward-Looking Statements

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

The forward-looking statements are based on current expectations and are subject to known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company's products; foreign currency exchange rates; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; availability and cost of seismic, drilling and other equipment; ability of the Company to complete its capital programs; ability of the Company to transport its products to market; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas; availability and cost of financing; success of exploration and development activities; timing and success of integrating the business and operations of acquired companies; production levels; uncertainty of reserve estimates; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations); asset retirement obligations; and other circumstances affecting revenues and expenses. Our domestic operations are subject to governmental risks that may impact our operations. Our domestic operations have been, and at times in the future may be affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.

Disclosure related to expected future commodity pricing, production volumes, royalties, capital expenditures and other 2007 guidance provided throughout this Management's Discussion and Analysis ("MD&A"), constitutes forward-looking statements as described above.

Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future.

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

Management's Discussion and Analysis

Management's Discussion and Analysis of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements for the nine months ended September 30, 2007 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2006.

All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). This MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings from operations and cash flow from operations. These financial measures are not defined by GAAP and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with GAAP, as an indication of the Company's performance. The measures adjusted net earnings from operations and cash flow from operations are reconciled to net earnings in the "Financial Highlights" section.

Certain figures related to the presentation of gross revenues and gross transportation and blending provided for the nine and three months ended September 30, 2006 have been reclassified to conform to the presentation adopted in the fourth quarter of 2006.

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

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

The following discussion refers primarily to the Company's financial results for the nine and three months ended September 30, 2007 in relation to the comparable periods in 2006 and the second quarter of 2007. The accompanying tables form an integral part of this MD&A. This MD&A is dated October 30, 2007. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2006, is available on SEDAR at www.sedar.com.

 FINANCIAL HIGHLIGHTS ($ millions, except per  common share amounts)                                 Three Months Ended       Nine Months Ended                            -------------------------------------------------                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30                                2007      2007    2006(1)     2007    2006(1) ---------------------------------------------------------------------------- Revenue, before royalties  $  3,073 $  3,152  $   3,108  $  9,343  $  8,817 Net earnings               $    700 $    841  $   1,116  $  1,810  $  2,211  Per common share -   basic and diluted        $   1.30 $   1.56  $    2.08  $   3.36  $   4.12 Adjusted net earnings  from operations (2)       $    644 $    595  $     470  $  1,860  $  1,252  Per common share -   basic and diluted        $   1.19 $   1.10  $    0.87  $   3.44  $   2.33 Cash flow from  operations (3)            $  1,577 $  1,513  $   1,313  $  4,712  $  3,639  Per common share -   basic and diluted        $   2.92 $   2.81  $    2.44  $   8.74  $   6.77 Capital expenditures,  net of dispositions       $  1,442 $  1,460  $   1,661  $  4,911  $  5,528 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Blending costs that were netted against gross revenues in prior periods     have been reclassified to transportation expense to conform to the     presentation adopted in the fourth quarter of 2006. (2) Adjusted net earnings from operations is a non-GAAP measure that     represents net earnings adjusted for certain items of a non-operational     nature. The Company evaluates its performance based on adjusted net     earnings from operations. This reconciliation lists the after-     tax effects of certain items of a non-operational nature that are     included in the Company's financial results. Adjusted net earnings from     operations may not be comparable to similar measures presented by other     companies. (3) Cash flow from operations is a non-GAAP measure that represents net     earnings adjusted for non-cash items. The Company evaluates its     performance based on cash flow from operations. The Company considers     cash flow from operations a key measure as it demonstrates the Company's     ability to generate the cash flow necessary to fund future growth     through capital investment and to repay debt. Cash flow from operations     may not be comparable to similar measures presented by other companies. Adjusted Net Earnings from Operations                                 Three Months Ended       Nine Months Ended                            -------------------------------------------------                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30 ($ millions)                   2007      2007      2006      2007      2006 ---------------------------------------------------------------------------- Net earnings as reported   $    700  $    841  $  1,116  $  1,810  $  2,211 Stock-based compensation  expense (recovery),  net of tax(a)                   54        74       (92)      145       (25) Unrealized risk management  loss (gain), net of tax(b)      57       (35)     (496)      384      (508) Unrealized foreign exchange  (gain) loss, net of tax(c)    (167)     (214)        9      (408)      (31) Effect of statutory tax rate  changes on future income  tax liabilities(d)               -       (71)      (67)      (71)     (395) ---------------------------------------------------------------------------- Adjusted net earnings from  operations                $    644  $    595  $    470  $  1,860  $  1,252 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (a) The Company's employee stock option plan provides for a cash payment     option. Accordingly, the intrinsic value of the outstanding vested     options is recorded as a liability on the Company's balance sheet and     periodic changes in the intrinsic value flow through net earnings or are     capitalized to the Horizon Oil Sands Project. (b) Derivative financial instruments are recorded at fair value on the     balance sheet, with changes in the fair value of non-designated hedges     flowing through net earnings. The amounts ultimately realized may be     materially different than reflected in the financial statements due to     changes in prices of the underlying items hedged, primarily crude oil     and natural gas. (c) Unrealized foreign exchange gains and losses result primarily from the     translation of US dollar denominated long-term debt to period-end     exchange rates, offset by the impact of cross currency swaps, and are     immediately recognized in net earnings. (d) All substantively enacted adjustments in applicable income tax rates     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. Income tax     rate changes in the second quarter of 2007 resulted in a reduction of     future income tax liabilities of approximately $71 million in North     America. Income tax rate changes in the first quarter of 2006 resulted     in an increase of future income tax liabilities of approximately $110     million in the UK North Sea. Income tax rate changes in the second     quarter of 2006 resulted in a reduction of future income tax     liabilities of approximately $438 million in North America. Income tax     rate changes in the third quarter of 2006 resulted in a reduction of     future income liabilities of approximately $67 million in Cote d'Ivoire,     Offshore West Africa. Cash Flow from Operations                                 Three Months Ended       Nine Months Ended                            -------------------------------------------------                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30 ($ millions)                   2007      2007      2006      2007      2006 ---------------------------------------------------------------------------- Net earnings               $    700  $    841  $  1,116  $  1,810  $  2,211 Non-cash items:  Depletion, depreciation   and amortization              715       720       589     2,144     1,667  Asset retirement   obligation accretion           18        17        17        53        50  Stock-based compensation   expense (recovery)             78       106      (135)      209       (37)  Unrealized risk management   loss (gain)                    76       (57)     (754)      555      (772)  Unrealized foreign   exchange (gain) loss         (195)     (250)       11      (477)      (37)  Deferred petroleum   revenue tax expense   (recovery)                     10        20        (4)       27        40  Future income tax expense      175       116       473       391       517 ---------------------------------------------------------------------------- Cash flow from operations  $  1,577  $  1,513  $  1,313  $  4,712  $  3,639 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 

SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS

For the nine months ended September 30, 2007, the Company reported net earnings of $1,810 million compared to net earnings of $2,211 million for the nine months ended September 30, 2006. Net earnings for the nine months ended September 30, 2007 included unrealized after-tax expenses of $50 million related to the effects of risk management activities, fluctuations in foreign exchange rates, stock-based compensation expense and the impact of statutory tax rate changes on future income tax liabilities, compared to net after-tax income of $959 million for the nine months ended September 30, 2006. Excluding these items, adjusted net earnings from operations for the nine months ended September 30, 2007 increased to $1,860 million from $1,252 million for the nine months ended September 30, 2006. The increase from the comparable period in 2006 was primarily due to increased sales volumes and decreased realized risk management losses. These factors were partially offset by increased production expense, increased depletion, depreciation and amortization expense, and the impact of the strengthening of the Canadian dollar relative to the US dollar.

Net earnings in the third quarter of 2007 were $700 million compared to net earnings of $1,116 million in the third quarter of 2006 and net earnings of $841 million in the prior quarter. Net earnings in the third quarter of 2007 included unrealized after-tax income of $56 million related to the effects of risk management activities, fluctuations in foreign exchange rates and stock-based compensation expense, compared to net after-tax income of $646 million for the third quarter of 2006 and net after-tax income of $246 million in the prior quarter. Excluding these items, adjusted net earnings from operations in the third quarter of 2007 increased to $644 million from $470 million in the third quarter of 2006, and from $595 million in the prior quarter. The increase in adjusted net earnings from the third quarter of 2006 was primarily due to the impact of increased sales volumes and decreased realized risk management losses. These factors were partially offset by the impact of the stronger Canadian dollar relative to the US dollar and increased depletion, depreciation and amortization expense. The increase from the prior quarter was primarily due to increased crude oil pricing, decreased production costs and increased realized risk management gains on natural gas, partially offset by decreased natural gas pricing and the impact of the stronger Canadian dollar relative to the US dollar.

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

The Company's commodity hedging program reduces the risk of volatility in commodity price markets and supports the Company's cash flow for its capital expenditure program throughout the Horizon Oil Sands Project ("Horizon Project") construction period. This program allows for the hedging of up to 75% of the near 12 months budgeted production, up to 50% of the following 13 to 24 months estimated production and up to 25% of production expected in months 25 to 48. For the purpose of this program, the purchase of crude oil put options is in addition to the above parameters. In accordance with the policy, approximately 60% of expected crude oil volumes and natural gas volumes are hedged for the remainder of 2007.

The Company's outstanding commodity related net financial derivatives as at September 30, 2007 are detailed on page 41 of this MD&A.

As disclosed in note 2 to the Company's unaudited interim consolidated financial statements, commencing January 1, 2007 all derivative financial instruments are recognized at fair value on the consolidated balance sheet at each balance sheet date. As effective as the Company's hedges are against reference commodity prices, a substantial portion of the derivative financial instruments entered into by the Company do not meet the requirements for hedge accounting under GAAP due to currency, product quality and location differentials (the "non-designated hedges"). The change in the fair value of the non-designated hedges is based on prevailing forward commodity prices in effect at the end of each reporting period and is reflected in risk management activities in consolidated net earnings. The cash settlement amount of the risk management derivative financial instruments may vary materially depending upon the underlying crude oil and natural gas prices at the time of final settlement of the derivative financial instruments, as compared to their mark-to-market value at September 30, 2007.

Due to the changes in crude oil and natural gas forward pricing and the reversal of prior-period unrealized gains and losses, the Company recorded a net unrealized loss of $555 million ($384 million after-tax) on its commodity risk management activities for the nine months ended September 30, 2007, including a $76 million ($57 million after-tax) unrealized loss for the three months ended September 30, 2007. Mark-to-market unrealized gains and losses do not impact the Company's current cash flow or its ability to finance ongoing capital programs. The Company continues to believe that its risk management program meets its objective of securing funding for its capital projects and does not intend to alter its current strategy of obtaining price certainty for its crude oil and natural gas sales. For further details, refer to Risk Management Activities on page 31 of this MD&A.

The Company also recorded a $209 million ($145 million after-tax) stock-based compensation expense as a result of the 22% increase in the Company's share price in the nine months ended September 30, 2007, and a $78 million ($54 million after-tax) stock-based compensation expense as a result of the 7% increase in the Company's share price for the three months ended September 30, 2007 (Company's share price as at: September 30, 2007 - C$75.56; June 30, 2007 - C$70.78; December 31, 2006 - C$62.15; September 30, 2006 - C$50.94). As required by GAAP, the Company records a liability for potential cash payments to settle its outstanding employee stock options each reporting period based on the difference between the exercise price of the stock options and the market price of the Company's common shares, pursuant to a graded vesting schedule. The liability is revalued each quarter to reflect the changes in the market price of the Company's common shares and the options exercised or surrendered in the period, with the net change recognized in net earnings, or capitalized as part of the Horizon Project during the construction period. The stock-based compensation liability at September 30, 2007 reflected the Company's potential cash liability should all the vested options be surrendered for a cash payout at the market price on September 30, 2007. In periods when substantial share price changes occur, the Company's net earnings are subject to significant volatility. The Company utilizes its stock-based compensation plan to attract and retain employees in a competitive environment. All employees participate in this plan.

Cash flow from operations for the nine months ended September 30, 2007 increased to $4,712 million from $3,639 million for the nine months ended September 30, 2006. The increase from the comparable period in 2006 was primarily due to increased sales volumes and decreased realized risk management losses, offset by increased production expense, higher cash taxes and the impact of the strengthening of the Canadian dollar relative to the US dollar.

Cash flow from operations for the third quarter of 2007 increased to $1,577 million from $1,313 million for the third quarter of 2006, and from $1,513 million in the prior quarter. The increase from the third quarter of 2006 was primarily due to the impact of increased sales volumes and decreased realized risk management losses, partially offset by the impact of the stronger Canadian dollar relative to the US dollar. The increase from the prior quarter was primarily due to increased crude oil pricing, lower production costs and increased realized risk management gains on natural gas, partially offset by decreased natural gas production and pricing, higher cash taxes and the impact of the stronger Canadian dollar relative to the US dollar.

Total production before royalties increased 7% to average 611,665 boe/d for the nine months ended September 30, 2007 from 569,590 boe/d for the nine months ended September 30, 2006. Production for the third quarter of 2007 increased 8% to 607,484 boe/d from 561,152 boe/d in the third quarter of 2006 and decreased 1% from 614,461 boe/d for the prior quarter.

 SUMMARY OF QUARTERLY RESULTS The following is a summary of the Company's quarterly results for the eight most recently completed quarters: ($ millions, except per common share   Sep 30    Jun 30    Mar 31    Dec 31 amounts)                                 2007      2007      2007      2006 ---------------------------------------------------------------------------- Revenue, before royalties            $  3,073  $  3,152  $  3,118  $  2,826 Net earnings                         $    700  $    841  $    269  $    313 Net earnings per common share  - Basic and diluted                 $   1.30  $   1.56  $   0.50  $   0.58 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ($ millions, except per common share   Sep 30    Jun 30    Mar 31    Dec 31  amounts)                                2006      2006      2006      2005 ---------------------------------------------------------------------------- Revenue, before royalties (1)        $  3,108  $  3,041  $  2,668  $  3,319 Net earnings                         $  1,116  $  1,038  $     57  $  1,104 Net earnings per common share  - Basic and diluted                 $   2.08  $   1.93  $   0.11  $   2.06 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Blending costs that were netted against gross revenues in prior periods     have been reclassified to transportation expense to conform to the     presentation adopted in the fourth quarter of 2006. 

Net earnings over the eight most recently completed quarters generally reflected fluctuations in realized crude oil and natural gas prices, increased sales volumes, the impact of mark-to-market accounting of financial instruments and adjustments to future income tax liabilities due to jurisdictional tax rate changes. More specifically, volatility in quarterly net earnings was primarily due to:

- Crude oil pricing

Crude oil prices reflected demand growth, continued geopolitical uncertainties and fluctuations in the Heavy Crude Oil Differential from WTI ("Heavy Differential") in North America.

- Natural gas pricing

Natural gas prices primarily reflected fluctuations in demand for natural gas and high inventory storage levels as a result of milder temperatures experienced during 2007 and 2006.

- Crude oil and NGLs sales volumes

Crude oil and NGLs sales volumes primarily reflected increased production from the Company's Primrose thermal projects, the positive results from the Pelican Lake water and polymer flood projects, and additional sales volumes from the Anadarko Canada Corporation ("ACC") acquisition completed in the fourth quarter of 2006.

- Natural gas sales volumes

Natural gas sales volumes reflected additional natural gas volumes as a result of the ACC acquisition and internally generated growth. The increase was partially offset by production declines due to the Company's strategic reduction in natural gas drilling activity.

- Foreign exchange rates

A general strengthening of the Canadian dollar relative to the US dollar has decreased the realized price the Company received for its crude oil and natural gas sales, as sales prices are based predominately on US dollar denominated benchmarks. Similarly, unrealized foreign exchange gains and losses were recorded with respect to US dollar denominated debt balances, UK pounds sterling denominated working capital balances, and the re-measurement of North Sea future income tax liabilities denominated in UK pounds sterling to US dollars.

- Commodity and cross currency hedges

Net earnings have fluctuated due to the recognition of realized and unrealized gains and losses from the mark-to-market of the Company's commodity and cross currency hedges.

- Changes in tax rates

Income tax expense and recovery fluctuations include jurisdictional tax rate changes substantively enacted in the various periods.

- Stock-based compensation

Net earnings have fluctuated due to the recognition of realized and unrealized expenses and recoveries from the mark-to-market of the Company's stock-based compensation liability. The liability reflected a general increase in the Company's share price over the eight most recently completed quarters.

- Production expense

Production expense has increased primarily due to industry-wide inflationary cost pressures.

- Depletion, depreciation and amortization

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

 OPERATING HIGHLIGHTS                                 Three Months Ended       Nine Months Ended                            -------------------------------------------------                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30                                2007      2007      2006      2007      2006 ---------------------------------------------------------------------------- Crude oil and NGLs  ($/bbl) (1) Sales price (2)            $  58.10  $  53.74  $  62.55  $  54.57  $  55.91 Royalties                      6.65      5.46      5.11      5.69      4.61 Production expense            13.13     15.01     13.47     13.97     12.29 ---------------------------------------------------------------------------- Netback                    $  38.32  $  33.27  $  43.97  $  34.91  $  39.01 ---------------------------------------------------------------------------- Natural gas ($/mcf) (1) Sales price (2)            $   5.87  $   7.44  $   5.83  $   7.03  $   6.75 Royalties                      0.89      1.10      1.11      1.16      1.31 Production expense             0.88      0.89      0.84      0.91      0.81 ---------------------------------------------------------------------------- Netback                    $   4.10  $   5.45  $   3.88  $   4.96  $   4.63 ---------------------------------------------------------------------------- Barrels of oil equivalent  ($/boe) (1) Sales price (2)            $  47.96  $  49.70  $  51.21  $  48.99  $  49.38 Royalties                      6.07      5.99      5.75      6.27      5.99 Production expense             9.62     10.44     10.01     10.05      9.13 ---------------------------------------------------------------------------- Netback                    $  32.27  $  33.27  $  35.45  $  32.67  $  34.26 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of transportation and blending costs and excluding risk management     activities. BUSINESS ENVIRONMENT                                 Three Months Ended       Nine Months Ended                            -------------------------------------------------                              Sep 30    Jun 30    Sep 30    Sep 30    Sep 30                                2007      2007      2006      2007      2006 ---------------------------------------------------------------------------- WTI benchmark price  (US$/bbl)                 $  75.33  $  65.02  $  70.55  $  66.26  $  68.29 Dated Brent benchmark  price (US$/bbl)           $  74.85  $  68.74  $  69.58  $  67.18  $  67.03 Differential to LLB blend  (US$/bbl)                 $  22.69  $  19.42  $  19.08  $  19.33  $  21.82 LLB blend differential  from WTI (%)                    30%       30%       27%       29%       32% Condensate benchmark price  (US$/bbl)                 $  75.93  $  65.66  $  70.26  $  66.82  $  68.49 NYMEX benchmark price  (US$/mmbtu)               $   6.13  $   7.56  $   6.52  $   6.88  $   7.47 AECO benchmark price  (C$/GJ)                   $   5.32  $   6.99  $   5.72  $   6.46  $   6.82 US / Cdn dollar average  exchange rate (US$)       $ 0.9565  $ 0.9112  $ 0.8919  $ 0.9045  $ 0.8830 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 

Commodity Prices

Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing

Source: MARKET WIRE

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