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Canadian Natural Resources Limited Announces 2008 Second Quarter Results

August 7, 2008

CALGARY, ALBERTA–(Marketwire – Aug. 7, 2008) – Canadian Natural Resources Limited (TSX:CNQ) (NYSE:CNQ) –

Commenting on second quarter results, Allan Markin, Chairman of Canadian Natural stated, “This is an exciting time for Canadian Natural. Phase 1 of our Horizon Project is approaching completion. This is a complex project which involves moving raw oil sands materials through a complex process to yield raw bitumen crude oil and then upgrading it to 34 degrees API, light sweet synthetic crude oil. The hard work of everyone involved on the Horizon Project has produced a world class asset that will provide steady cash flow for years to come. Strong results from our conventional operations reflect the strength and depth of our existing asset base. It is a credit to our team and assets that we managed our growth profile for conventional crude oil and natural gas growth opportunities to build the Horizon Project.”

John Langille, Vice-Chairman of Canadian Natural stated, “The second quarter of 2008 saw continuing strength in both crude oil and natural gas pricing. Narrow heavy crude oil differentials combined with higher realized pricing for the quarter resulted in Q2/08 cash flow of nearly $1.86 billion. As cash flow from the Horizon Project is added to existing conventional cash flow, we will focus on further strengthening our balance sheet as well as opportunities available in our diverse asset base. Capital discipline and allocation remain priorities to ensure returns are optimized, even in a high commodity price environment.”

Steve Laut, President and Chief Operating Officer of Canadian Natural commented, “Q2/08 was a very strong quarter for us. In Q2/ 08 both crude oil and natural gas production in Canada exceeded the top end of our guidance, reflecting the strength of our conventional asset base. Canadian Natural has achieved a significant milestone as we proceed with the final construction, commissioning and staged start-up of the Horizon Project and begin to realize the benefits of the largest single capital project in Canadian Natural’s history. Our current schedule will see us producing first bitumen crude oil in early September, first partially upgraded crude oil by the end of September, and first 34 degrees API, light sweet synthetic crude oil in Q4/08.

We have experienced a slippage in our targeted start-up in the production of synthetic crude oil as we have experienced delays in the completion of the primary and secondary upgrading processes. This has also resulted in increased project costs as manpower requirements have been extended longer than our planning schedule anticipated. Our current cost estimate has increased by 8% above our previous estimate bringing the total cost to 36% above our original 2004 estimate of $6.8 billion. The start-up of the Horizon Project is a major step for Canadian Natural. We continue to evolve and diversify our asset base and look forward to the continuous stream of cash flow for years to come. The result is an even stronger and more sustainable company.

As part of our three phase heavy crude oil marketing strategy, Canadian Natural has made a significant step in the second phase to secure additional markets. Canadian Natural has committed 120,000 bbl/d for 20 years to the Keystone Pipeline US Gulf Coast expansion from Hardisty, Alberta to Port Arthur, Texas, which is subject to regulatory approval. Canadian Natural has also secured an option to acquire an equity interest in the Keystone Project.

Also fulfilling our defined heavy crude oil marketing plan is a 20 year 100,000 bbl/d supply arrangement with a major US refiner to supply refineries in the Gulf Coast at market prices.

The completion of both of these agreements allows Canadian Natural to proceed with increased confidence the development of Canadian Natural’s vast heavy oil assets and to deliver in a methodical staged manner an incremental 325,000 bbl/d of heavy crude oil. These agreements facilitate the unlocking of the value in our vast heavy oil resource base and will create tremendous value for Canadian Natural shareholders.

We remain focused on the costs we are able to control and manage those that are outside our influence. We continue to direct our investment – of time, energy and capital – towards those projects and activities that provide the greatest return.”

HIGHLIGHTS ____________________________________Three Months Ended____ Six Months Ended ____________________________ ————————————— ——– ______________________________Jun 30__ Mar 31__ Jun 30______Jun 30__ Jun 30 ($ millions, except as noted)__ 2008____ 2008____ 2007________2008____ 2007 ——————————————————————– ——– Net earnings (loss)__________$__(347)__$__727__ $__841______$__380__$ 1,110 per common share, basic and diluted__________ $ (0.65)__$ 1.35__ $ 1.56______$ 0.70__$__2.06 Adjusted net earnings from operations (1)______________$__ 960__ $__872__ $__595______$1,832__$ 1,216 __per common share, __basic and diluted__________$__1.78__ $ 1.61__ $ 1.10______$ 3.39__$__2.25 Cash flow from operations (2)______________$ 1,859__ $1,725__ $1,513______$3,584__$ 3,135 __per common share, __basic and diluted__________$__3.44__ $ 3.19__ $ 2.81______$ 6.63__$__5.82 Capital expenditures, net of dispositions________ $ 2,127__ $1,753__ $1,460______$3,880__$ 3,469 Daily production, before royalties __Natural gas (mmcf/d)________ 1,526____1,538____1,722______ 1,532____1,719 __Crude oil and NGLs (bbl/d) 319,077__327,217__327,494____ 323,147__327,249 __Equivalent production __ (boe/d)__________________ 573,437__583,488__614,461____ 578,461__613,790 ——————————————————————– ——– ——————————————————————– ——– (1) Adjusted net earnings from operations is a non-GAAP measure that the ____Company utilizes to evaluate its performance. The derivation of this ____measure 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 repay debt. The derivation of this measure is ____discussed in the MD&A.

– Natural gas production volumes for the second quarter represented 44% of the Company’s total production. Natural gas production for Q2/08 averaged 1,526 mmcf/d, down slightly from 1,538 mmcf/d for Q1/08 and down 11% from 1,722 mmcf/d for Q2/07. Q2/08 saw a very successful drilling program with North America volumes exceeding corporate guidance. The decrease in volumes for Q2/08 from Q2/07 reflected continued reallocation of capital towards higher return projects in crude oil.

– Total crude oil and NGLs production for Q2/08 was 319,077 bbl/ d. Q2/08 crude oil production volumes decreased 2% from Q1/08 of 327,217 bbl/d, and decreased 3% from Q2/07 of 327,494 bbl/d. Volumes in Q2/08 reflect the transition between steam and production cycles for Primrose thermal wells, continued conversion of production wells to polymer injection wells at Pelican Lake, along with turnarounds in the North Sea.

– Quarterly cash flow from operations was nearly $1.86 billion, an 8% increase from Q1/08 and an increase of 23% from Q2/07. The increase from Q2/07 primarily reflected higher crude oil and natural gas realizations, partially offset by realized risk management losses.

– Quarterly net loss for Q2/08 was $347 million primarily as a result of risk management losses. Quarterly adjusted net earnings from operations for Q2/08 were $960 million primarily due to higher product prices.

– Maintained a strong undeveloped conventional core land base in Canada of 11.4 million net acres – a key asset for continued value growth.

– Improvements at the Pelican Lake Field continue with the conversion of water flood wells to polymer flood wells, with a daily average of approximately 37,000 bbl/d.

– The Primrose East Expansion, which is targeted to add 40,000 bbl/d of capacity, has made significant progress. First steam is scheduled for September, coming in ahead of schedule, with first production targeted for Q4/08 versus a previous target of Q1/09.

– Drilling has started at Baobab in Offshore Cote d’Ivoire. The equipment was mobilized in early Q2/08, enabling work to begin on the restoration of shut-in production. It is targeted that a minimum 3 of the 5 Baobab wells will come on stream over the course of 2008 and 2009.

– The Olowi Project in Offshore Gabon continues on schedule with first crude oil production targeted for late 2008.

– Construction and commissioning of the Horizon Oil Sands Project (“Horizon Project”) continued in Q2/08 with first bitumen crude oil production targeted for early September, partially upgraded crude oil production targeted for the end of September, and first 34 degrees API, light sweet synthetic crude oil production (“SCO”) in Q4/08.

– Committed to ship 120,000 bbl/d of heavy crude oil for 20 years on the proposed Keystone pipeline US Gulf Coast expansion from Hardisty, Alberta to Port Arthur, Texas.

– Committed to a 100,000 bbl/d heavy crude oil supply agreement with a major US refiner to supply refineries in the Gulf Coast at market prices for 20 years.

– Declared a quarterly cash dividend on common shares of C$0.10 per common share, payable October 1, 2008.

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 crude oil, 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______ six months ended ________________________________________Jun 30, 2008__________ Jun 30, 2008 ____________________________ (thousands of net acres)________(net wells) (1) ——————————————————————– ——– Canadian conventional Northeast British Columbia____________________2,318__________________ 21.8 Northwest Alberta____________________________ 1,428__________________ 53.9 Northern Plains______________________________ 6,635__________________252.1 Southern Plains________________________________ 863__________________ 68.8 Southeast Saskatchewan__________________________123__________________ 19.4 In-situ Oil Sands______________________________ 483__________________ 53.0 ——————————————————————– ——–

_______________________________________11,850__________________469.0 Horizon Oil Sands Project________________________115______________________- United Kingdom North Sea________________________ 268____________________4.1 Offshore West Africa____________________________ 206____________________1.5 ——————————————————————– ——–

_______________________________________12,439__________________474.6 ——————————————————————– ——– ——————————————————————– ——– (1) Drilling activity includes stratigraphic test and service wells Drilling activity (number of wells) ______________________________________________Six Months Ended Jun 30 __________________________________ ——————————— ——– __________________________________________ 2008__________________ 2007 ____________________________________Gross________Net______ Gross________Net ——————————————————————– ——– Crude oil____________________________ 284________266________ 290________271 Natural gas__________________________ 202________166________ 254________207 Dry____________________________________20________ 17__________74________ 64 ——————————————————————– ——– Subtotal______________________________506________449________ 618________542 Stratigraphic test / service wells____ 26________ 26________ 241________241 ——————————————————————– ——– Total________________________________ 532________475________ 859________783 ——————————————————————– ——– Success rate (excluding __stratigraphic test / service wells)____________ 96%____________________88% ——————————————————————– ——– ——————————————————————– ——– North America Conventional North America natural gas ____________________________________Three Months Ended____ Six Months Ended ____________________________ ————————————— ——– ______________________________Jun 30__ Mar 31__ Jun 30______Jun 30__ Jun 30 ________________________________2008____ 2008____ 2007________2008____ 2007 ——————————————————————– ——– Natural gas production (mmcf/d)______________________1,501____1,513____1,696______ 1,507____1,694 ——————————————————————– ——– Net wells targeting natural gas____8______167________7________ 175______252 Net successful wells drilled______ 5______161________6________ 166______207 ——————————————————————– ——– Success rate____________________ 63%______96%______86%________ 95%______82% ——————————————————————– ——– ——————————————————————– ——–

– Q2/08 North America natural gas production decreased marginally from Q1/08 and decreased 11% from Q2/07. The year over year decrease reflected natural declines in base production and the Company’s strategic decision to reduce spending on natural gas drilling. However, it was a very successful quarter with volumes exceeding quarterly guidance targets.

– Canadian Natural targeted 8 net natural gas wells in Q2/08. In Northeast British Columbia, 2 net wells were drilled, while in Northwest Alberta, 1 net well was drilled. In the Northern Plains, 4 net wells were drilled, with 1 net well drilled in the Southern Plains.

– Planned drilling activity for Q3/08 includes 81 natural gas wells compared to drilling activity for Q3/07 of 106 natural gas wells.

– Inflationary pressure continues to affect capital and service costs for natural gas drilling. Cost control and maximizing shareholder value remain priorities within this business environment.

North America crude oil and NGLs ____________________________________Three Months Ended____ Six Months Ended ____________________________ ————————————— ——– ______________________________Jun 30__ Mar 31__ Jun 30______Jun 30__ Jun 30 ________________________________2008____ 2008____ 2007________2008____ 2007 ——————————————————————– ——– Crude oil and NGLs production (bbl/d)__________245,616__248,960__240,420____ 247,288__238,962 ——————————————————————– ——– Net wells targeting crude oil____ 94______176______ 78________ 270______285 Net successful wells drilled______92______171______ 75________ 263______266 ——————————————————————– ——– Success rate____________________ 98%______97%______96%________ 97%______93% ——————————————————————– ——– ——————————————————————– ——–

– Q2/08 North America crude oil and NGLs production decreased marginally from Q1/08 and increased 2% from Q2/07 levels. The majority of the incremental production volume from Q2/07 was contributed by thermal crude oil. The decrease from Q1/08 is a reflection of transitioning off the production cycle peaks at Primrose pads.

– 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 targeted to add approximately 40,000 bbl/d of crude oil. Drilling is complete and facility construction is ahead of schedule, with production targeted to commence in late 2008 versus the previous production target of Q1/09. Primrose East is the second phase of the 325,000 bbl/d thermal growth 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 thermal growth 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.

– Development of new pads and secondary recovery conversion projects at Pelican Lake continued as expected throughout Q2/08. In Q2/08, the Company drilled 32 horizontal wells with plans to drill an additional 57 horizontal wells and 1 vertical service well throughout the remainder of 2008. Pelican Lake production averaged approximately 37,000 bbl/d for Q2/08 compared to approximately 34,000 bbl/d for Q2/07 and approximately 37,000 bbl/d for Q1/08. The response from the polymer flood project continues to be positive and the Company is moving forward on converting regions currently under waterflood to polymer flood and expanding the polymer flood to new areas.

– Conventional heavy crude oil production volumes remained constant in Q2/08 compared to Q1/08, with volumes as expected.

– During Q2/08, drilling activity targeted 94 net wells including 40 wells targeting heavy crude oil, 32 wells targeting Pelican Lake crude oil, 14 wells targeting thermal crude oil and 8 wells targeting light crude oil.

– Planned drilling activity for Q3/08 includes 256 net crude oil wells, excluding stratigraphic test and service wells.

– Inflationary pressure continues to affect capital and service costs for crude oil drilling. Cost control and maximizing shareholder value remain priorities within this business environment.

International ____________________________________Three Months Ended____ Six Months Ended ____________________________ ————————————— ——– ______________________________Jun 30__ Mar 31__ Jun 30______Jun 30__ Jun 30 ________________________________2008____ 2008____ 2007________2008____ 2007 ——————————————————————– ——– Crude oil production (bbl/d) North Sea____________________45,830__ 49,568__ 57,286______47,699__ 59,565 Offshore West Africa________ 27,631__ 28,689__ 29,788______28,160__ 28,722 ——————————————————————– ——– Natural gas production (mmcf/d) North Sea________________________10______ 11______ 15__________11______ 15 Offshore West Africa____________ 15______ 14______ 11__________14______ 10 ——————————————————————– ——– Net wells targeting crude oil____1.6______2.2______3.1________ 3.8______5.1 Net successful wells drilled____ 0.8______2.2______3.1________ 3.0______5.1 ——————————————————————– ——– Success rate____________________ 50%____ 100%____ 100%________ 79%____ 100%

North Sea

– During Q2/08, 2.4 net wells were drilled including 0.8 net injection wells. At the end of the quarter 0.9 net crude oil wells were in progress. Crude oil production was down 8% in Q2/08 to 45,830 bbl/d from 49,568 bbl/d in Q1/08 as a result of a planned shutdown for maintenance at Ninian.

– Focus on waterflood optimization at Ninian continued with one new water injection well being completed in Q2/08, increasing water injection capacity. Compared to the first six months of last year the Company has increased water injection by 25%.

– At Murchison, the second of two production wells planned for 2008 was completed in the quarter.

– During the quarter, an unsuccessful exploration well was drilled on the Anning prospect which lies in proximity of the Murchison Field.

Offshore West Africa

– Offshore West Africa’s crude oil production was down 4% in Q2/ 08 to 27,631 bbl/d from 28,689 bbl/d in Q1/08 with stable production at Espoir and Baobab during the quarter.

– Progress on the Facility Upgrade Project at Espoir to increase capacity of the Floating, Production, Storage and Offtake Vessel (“FPSO”) continues to progress ahead of schedule and is still expected to be completed in Q3/09, an acceleration of 3 to 6 months from the original estimate.

– The deep water drilling rig for Baobab was mobilized early in Q2/08, enabling work to begin on the restoration of shut-in production. It is targeted that a minimum 3 of the 5 shut-in Baobab wells be on stream over the course of 2008 and 2009.

– At the Olowi project in Offshore Gabon, a drilling rig was mobilized and drilling commenced in early May of this year with first crude oil production targeted for late 2008.

– Capital spending in Offshore West Africa is expected to increase $250 million in 2008 primarily due to early delivery of the second wellhead tower and minor scope changes for pipeline heating at Olowi.

Horizon Project

– Canadian Natural has achieved a significant milestone, entering the final construction, commissioning and staged start-up of the Horizon Project. There are seven stages to the start-up and the associated targeted start-up dates are as follows:

— Stage 1 – Mining. The mining operation has been ready for operation since May, and continues to move overburden. The mining team awaits the call for first oil sands delivery.

— Stage 2 – Steam Supply. Utility plants have been supplying low, medium and high pressure steam in stages, with the last steam (high pressure) delivered in the third week of July for testing and commissioning purposes.

— Stage 3 – Bitumen Crude Oil Production. Bitumen crude oil production operations are in the final stages of commissioning with first bitumen crude oil production targeted for early September.

— Stage 4 – Electricity Generation. The Co-generation Plant is targeted to deliver full load electricity in the second half of September.

— Stage 5 – Sulphur Plant/Sour Gas Treating. The Sulphur Plant is targeted to be ready to receive sour gas feed mid-August and circulate amine, awaiting the first delivery of sour gas.

— Stage 6 – Partially Upgraded Crude Oil Production. The Delayed Coker/Diluent Recovery Unit Plants are in the commissioning stage concurrent with the completion of final task lists (i.e. punch- lists), and are targeted to deliver partially upgraded crude oil to intermediate tanks by the end of September.

— Stage 7 – 34 degrees API, Light Sweet SCO Production. The Naphtha Hydrotreating Plant (Unit 41) is completing loop checks and insulation concurrent with commissioning. First product output is currently targeted for October. The Gas Oil Hydrotreating Plant (Unit 43) is completing punch-lists, loop checks, electrical heat tracing and insulation concurrent with commissioning with first product output currently targeted for Q4/08. First, 34 degrees API, light sweet SCO in the sales pipeline is currently targeted for Q4/ 08. Capacity is targeted to be 70,000 bbl/d, meeting scheduled product ramp-up. The Distillate Hydrotreating Plant (Unit 42) is finishing mechanical completion, and completing electrical heat tracing, insulation and loop checks, and currently targeted first product output is for the latter part of Q4/08. Facility capacity will be targeted to be 110,000 bbl/d of 34 degrees API, light sweet SCO upon Plant 42 completion, ramping up production to facility capacity and maintaining the previous production ramp-up schedule.

– During the second quarter, Canadian Natural completed a majority of the pre-commissioning activity, commissioned another shovel and 12 more trucks in the mine, brought on Utilities (air, water, steam, power and natural gas), and commenced operating several of the bitumen crude oil production plants on water as a “wet run” before the introduction of oil sands.

– Pre start-up safety reviews are taking longer to complete than originally anticipated, however, the Company is remaining disciplined and will not put the facilities and personnel at risk.

– Significant progress was made but the Company has found that testing and closing of all safety and operations punch-lists are taking longer than expected. 42% of the over 800 plant systems were turned over to operations at the end of the quarter. Progress by major plant facility shows:

— Mining – Completed, ready to mine oil sands and continues to move overburden

— Ore Preparation Plant – Completed, targeted to receive first oil sands in August

— Hydrotransport – Completed, ready to accept slurry

— Piperack – Completed, live and operational

— Extraction – Completed, ready for operation

— Froth Treatment – Targeted to be complete by August

— Delayed Coker/Diluent Recovery Unit – Commissioning well underway

— Hydrogen Plant – Completed, turned over to operations

— Hydrotreaters – Plant 41 and 43 completing loop checks, Plant 42 encountering some scheduling issues

— Co-generation – Completed, producing steam

— Sulphur Plant – Completed, turned over to operations

— Tankage – Completed, ready for first oil

— Main Control Room – Completed, live and fully operational

— Utilities & Services – Completed, live and fully operational

— SCO Pipeline(third party owned and operated) – Completed, ready to accept product, with terminaling facilities in Edmonton arranged

– Many challenges continue to be faced, with the critical path item being the completion and turnover of all three Hydrotreaters in a small window. The Distillate and Gas Oil Hydrotreater units have encountered delays and schedule slippage resulting in commissioning beyond the third quarter. The operations team has developed an overall start-up scenario for initial operation at approximately 60% of the design rate until the Distillate Hydrotreater is commissioned to mitigate any impact to overall production ramp-up.

– After the thorough monthly review in the second half of July 2008, it was determined that there was schedule slippage in Upgrading/Hydrotreating Plants and it is taking longer to complete testing, reinstatement and pre-commissioning activities of these plants.

– A detailed review of the current cost estimate indicates that the Horizon Project targeted final cost will increase by approximately 8% or approximately $525 million above the previous construction cost estimates bringing the total cost estimate of the Horizon Project to approximately 36% above our original 2004 $6.8 billion estimate, or approximately $9.27 billion (up from the previous total cost estimate of $8.74 billion). This increase will result in a targeted on-stream cost of $84,000 bbl/d of capacity, including the benefits of the significant pre-build capital invested for Phase 2/3.

– With primary focus on completing Phase 1 and producing SCO, Canadian Natural has a team working on future expansions. Several long lead items for Phase 2/3 expansions are on site, including the coke drums and hydrotreating reactors. The reactors have been assembled on site and hydrotested. The Company has awarded nearly all the Engineering (detailed design) and Procurement contracts for the Tranche 2 scope and have held kick-off meetings with the majority of the contractors.

– Canadian Natural is managing its commitment to safety and celebrated over 20 million manhours without a lost time incident – more than 1 year. Along with systems and start-up training for a significant number of staff, the Company has completed its ‘Going Live’ safety orientation for all Horizon Project employees and contractors. The Pre Start-Up Safety Reviews have been initiated in all plants and the learnings from earlier system turnovers are being applied.

– For further details, refer to the Horizon Oil Sands Project update from August 6, 2008.

MARKETING ____________________________________Three Months Ended____ Six Months Ended ____________________________ ————————————— ——– ______________________________Jun 30__ Mar 31__ Jun 30______Jun 30__ Jun 30 ________________________________2008____ 2008____ 2007________2008____ 2007 ——————————————————————– ——– Crude oil and NGLs pricing WTI(1) benchmark price __(US$/bbl)________________ $ 124.00 $__97.96 $__65.02____$ 110.98 $__61.64 Western Canadian Select __blend differential(2) __from WTI (%)____________________17%______22%______29%________ 19%______28% Corporate average pricing __before risk management __(C$/bbl)__________________$ 103.73 $__78.99 $__53.74____$__91.11 $__52.72 Natural gas pricing AECO benchmark price __(C$/GJ)__________________ $__ 8.86 $__ 6.76 $__ 6.99____$__ 7.81 $__ 7.03 Corporate average pricing __before risk management __(C$/mcf)__________________$__ 9.89 $__ 7.77 $__ 7.44____$__ 8.83 $__ 7.59 ——————————————————————– ——– ——————————————————————– ——– (1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at ____Cushing, Oklahoma. (2) Beginning in Q1 2008, the Company has quantified the Heavy Differential ____using the Western Canadian Select (“WCS”) blend as the heavy crude oil ____marker. Prior period amounts have been reclassified.

– In Q2/08, the WCS heavy crude oil differential as a percent of WTI was 17%, compared to 22% in Q1/08. Heavy crude oil differentials improved in Q2/08 due to a strong worldwide demand for diesel and low crack spreads, with overall high demand for crude oil products. Combined with declining heavy crude oil production in Mexico, and increased Venezuelan supply shipments to the Asian markets, demand has been strong for Canadian heavy crude oil.

– The Company continues its efforts with other industry players to find new markets and to ease the logistical constraints in getting Western Canadian heavy crude oil to new markets, such as the US Gulf Coast. Plans were recently announced to expand the Keystone crude oil pipeline system providing additional capacity to the US Gulf Coast by 2012. Canadian Natural sees this as an important step in its marketing strategy by allowing Canadian heavy crude oil into the US Gulf Coast market and as such has committed 120,000 bbl/d to the Keystone Pipeline US Gulf Coast Expansion, which is subject to regulatory approval, for a 20 year period. The agreement also includes an option for Canadian Natural to acquire an equity interest of the Keystone Pipeline.

– Canadian Natural has also entered into a 20 year supply agreement with a major US refiner for 100,000 bbl/d of heavy crude oil to US Gulf Coast refineries. These agreements represent a step forward in the defined marketing plan of Canadian Natural to improve the margins on the Company’s heavy crude oil production and to reduce the volatility historically experienced in the heavy crude oil market. With the Keystone agreement, Canadian Natural will retain full ownership of the resource while gaining access to a key market for Canadian heavy crude oil. The refining capacity in the US Gulf Coast area is approximately 7.5 million bbl/d. The long term supply agreement with a US refiner, which is contingent on the completion of the Keystone Pipeline US Gulf Coast Expansion, ensures a customer at the end of the Keystone Pipeline for a large portion of Canadian Natural’s heavy crude oil that is shipped at prevailing US Gulf Coast heavy oil market prices at the points of delivery.

– The Company sees this as a strategic component to its heavy crude oil development which targets an increase to heavy crude oil production capacity from just over 200,000 bbl/d today, to over 500,000 bbl/d over the course of the next 15 years. Canadian heavy crude oil is very competitive against other international grades available in the US Gulf Coast. For Q2/08, the differential for the heavy crude oil marker, Mayan grade, was US$21.00/bbl or 17%.

– During Q2/08, the Company contributed approximately 158,000 bbl/ d of its heavy crude oil streams to the WCS blend as market conditions resulted in this strategy offering the optimal pricing for bitumen crude oil.

– Natural gas pricing for Q2/08 was strong as demand for natural gas increased more than expected during the quarter. The quarter also saw fewer imports of liquefied natural gas to North America as a result of stronger pricing in Europe and Asia, again resulting in decreased supply to North America.

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 the Company’s strengths are:

— A diverse asset base geographically and by product – produced in excess of 573,000 boe/d in Q2/08, comprised of approximately 44% natural gas and 56% crude oil – with 95% of production located in G8 countries with stable and secure economies.

— Financial stability and liquidity – cash flow from operations of $1.86 billion for Q2/08, available unused bank lines of $2.7 billion at June 30, 2008 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.

— A strengthening balance sheet with debt to book capitalization of 45% and debt to EBITDA of 1.6 times, both within targeted ranges.

– Commencing January 1, 2009, the Company’s commodity hedging program has been revised by its Board of Directors to allow for the hedging of up to 50% of the near 12 months budgeted production and up to 25% of the following 13 to 24 months estimated production. The purchase of put options will continue to be in addition to the above parameters. The current program allows for hedging of 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 the expected production in months 25 to 48. The Company continues to believe that its risk management program meets its objective of securing funding for its capital projects.

– In 2007 and 2008, the Province of Alberta issued certain details of its proposed changes to the Alberta crude oil and natural gas royalty regime, effective January 1, 2009. The Company is currently awaiting finalization and government approval of the royalty regulations, however it expects that its 2009 and future Alberta royalty payments will increase as a result of the proposed royalty changes and that its level of activity in Alberta in aggregate will be reduced from what it otherwise would have been in the absence of such royalty changes.

– Declared a quarterly cash dividend on common shares of C$0.10 per common share, payable October 1, 2008.

OUTLOOK

The Company forecasts 2008 production levels before royalties to average between 1,482 and 1,511 mmcf/d of natural gas and between 308,000 and 350,000 bbl/d of crude oil and NGLs. Q3/08 production guidance before royalties is forecast to average between 1,466 and 1,490 mmcf/d of natural gas and between 299,000 and 316,000 bbl/d of crude oil and NGLs. Detailed guidance on 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 constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, production volumes, royalties, operating costs, capital expenditures and other 2008 guidance provided throughout this Management’s Discussion and Analysis (“MD&A”), constitutes forward-looking statements. In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates.

These statements are not guarantees of future performance and are subject to certain risks and the reader should not place undue reliance on these forward-looking statements as there can be no assurance that the plans, initiatives or expectations upon which they are based will occur.

The forward-looking statements are based on current expectations, estimates and projections about Canadian Natural Resources Limited (the “Company”) and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks, uncertainties and other factors that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.

Such factors include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company’s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company’s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company’s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete its capital programs; the Company’s and its subsidiaries’ ability to secure adequate transportation for its products; unexpected difficulties in mining, extracting or upgrading the Company’s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas; availability and cost of financing; the Company’s and its subsidiaries’ success of exploration and development activities and their ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, bitumen, natural gas and liquids not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company’s provision for taxes; and other circumstances affecting revenues and expenses.

The Company’s operations have been, and at times in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward- looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all information then available.

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

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 six and three months ended June 30, 2008 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2007.

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 of this MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the “Liquidity and Capital Resources” section of this MD&A.

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 and transportation and blending costs, 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 six and three months ended June 30, 2008 in relation to the comparable periods in 2007 and the first quarter of 2008. The accompanying tables form an integral part of this MD&A. This MD&A is dated August 6, 2008. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2007, is available on SEDAR at www.sedar.com.

FINANCIAL HIGHLIGHTS ($ millions, except per common share amounts) ____________________________________Three Months Ended____ Six Months Ended ____________________________ ————————————— ——– ______________________________Jun 30__ Mar 31__ Jun 30______Jun 30__ Jun 30 ________________________________2008____ 2008____ 2007________2008____ 2007 ——————————————————————– ——– Revenue, before royalties____$ 5,112__$ 3,967__$ 3,152____ $ 9,079__$ 6,270 Net earnings (loss)__________$__(347) $__ 727__$__ 841____ $__ 380__$ 1,110 Per common share __- basic and diluted________$ (0.65) $__1.35__$__1.56____ $__0.70__$__2.06 Adjusted net earnings from operations (1)________ $__ 960__$__ 872__$__ 595____ $ 1,832__$ 1,216 Per common share __- basic and diluted________$__1.78__$__1.61__$__1.10____ $__3.39__$__2.25 Cash flow from operations (2)______________$ 1,859__$ 1,725__$ 1,513____ $ 3,584__$ 3,135 Per common share __- basic and diluted________$__3.44__$__3.19__$__2.81____ $__6.63__$__5.82 Capital expenditures, net of dispositions________ $ 2,127__$ 1,753__$ 1,460____ $ 3,880__$ 3,469 ——————————————————————– ——– ——————————————————————– ——– (1) Adjusted net earnings from operations is a non-GAAP measure that ____represents net earnings adjusted for certain items of a non- operational ____nature. The Company evaluates its performance based on adjusted net ____earnings from operations. The reconciliation “Adjusted Net Earnings from ____Operations” presented below lists the after-tax effects of certain items ____of a non-operational nature that are included in the Company’s financial ____results. Adjusted net earnings from operations may not be comparable to ____similar measures presented by other companies. (2) Cash flow from operations is a non-GAAP measure that represents net ____earnings adjusted for non-cash items before working capital adjustments. ____The Company evaluates its performance based on cash flow from ____operations. The Company considers cash flow from operations a key ____measure as it demonstrates the Company’s ability to generate the cash ____flow necessary to fund future growth through capital investment and to ____repay debt. The reconciliation “Cash Flow from Operations” presented ____below lists certain non-cash items that are included in the Company’s ____financial results. Cash flow from operations may not be comparable to ____similar measures presented by other companies. Adjusted Net Earnings from Operations ____________________________________Three Months Ended____ Six Months Ended ____________________________ ————————————— ——– ______________________________Jun 30__ Mar 31__ Jun 30______Jun 30__ Jun 30 ($ millions)____________________2008____ 2008____ 2007________2008____ 2007 ——————————————————————– ——– Net earnings (loss) as reported________________ $__(347)__$__727__ $__841____ $__ 380__$ 1,110 Stock-based compensation expense, net of tax (a)________ 328________-______ 74________ 328______ 91 Unrealized risk management loss (gain), net of tax (b)____ 997______ 76______(35)______1,073______327 Unrealized foreign exchange (gain) loss, net of tax (c)____ (18)____ 110____ (214)________ 92____ (241) Effect of statutory tax rate and other legislative changes on future income tax liabilities (d)__________________ -______(41)____ (71)________(41)____ (71) ——————————————————————– ——– Adjusted net earnings from operations__________________$__ 960__ $__872__ $__595____ $ 1,832__$ 1,216 ——————————————————————– ——– ——————————————————————– ——– (a) The Company’s employee stock option plan provides for a cash payment ____option. Accordingly, the intrinsic value of outstanding vested options ____is recorded as a liability on the Company’s balance sheet and periodic ____changes in the intrinsic value are recognized in net earnings or are ____capitalized as part of the Horizon Oil Sands Project during the ____construction period. (b) Derivative financial instruments are recorded at fair value on the ____balance sheet, with changes in fair value of non-designated hedges ____recognized in net earnings. The amounts ultimately realized may be ____materially different than reflected in the financial statements due to ____changes in prices of the underlying items hedged, primarily crude oil ____and natural gas. (c) Unrealized foreign exchange gains and losses result primarily from the ____translation of US dollar denominated long-term debt to period- end ____exchange rates, offset by the impact of cross currency swaps, and are ____recognized in net earnings. (d) All substantively enacted adjustments in applicable income tax rates ____and other legislative changes are applied to underlying assets and ____liabilities on the Company’s consolidated balance sheet in determining ____future income tax assets and liabilities. The impact of these tax rate ____and other legislative changes is recorded in net earnings during the ____period the legislation is substantively enacted. Income tax rate changes ____in the first quarter of 2008 resulted in a reduction of future income ____tax liabilities of approximately $19 million in North America and $22 ____million in Cote d’Ivoire, Offshore West Africa. Income tax rate changes ____in the second quarter of 2007 resulted in a reduction of future income ____tax liabilities of approximately $71 million in North America. Cash Flow from Operations ____________________________________Three Months Ended____ Six Months Ended ____________________________ ————————————— ——– ______________________________Jun 30__ Mar 31__ Jun 30______Jun 30__ Jun 30 ($ millions)____________________2008____ 2008____ 2007________2008____ 2007 ——————————————————————– ——– Net earnings (loss)__________$__(347) $__ 727__$__ 841____ $__ 380__$ 1,110 Non-cash items: Depletion, depreciation __and amortization______________ 670______688______720______ 1,358____1,429 Asset retirement obligation __accretion______________________ 17______ 17______ 17__________34______ 35 Stock-based compensation __expense________________________459________-______106________ 459______131 Unrealized risk management __loss (gain)__________________1,415______108______(57)______1,523______479 Unrealized foreign exchange __(gain) loss____________________(20)____ 126____ (250)________106____ (282) Deferred petroleum revenue __tax (recovery) expense________ (34)____ (21)______20________ (55)______17 Future income tax (recovery) __expense______________________ (301)______80______116________(221)____ 216 ——————————————————————– ——– Cash flow from operations____$ 1,859__$ 1,725__$ 1,513____ $ 3,584__$ 3,135 ——————————————————————– ——– ——————————————————————– ——–

SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS

Net earnings for the six months ended June 30, 2008 were $380 million compared to $1,110 million for the six months ended June 30, 2007. Net earnings for the six months ended June 30, 2008 included net unrealized after-tax expenses of $1,452 million related to the effects of risk management activities, fluctuations in foreign exchange rates, fluctuations in stock-based compensation expense and the impact of statutory tax rate changes on future income tax liabilities, compared to net unrealized after-tax expenses of $106 million for the six months ended June 30, 2007. Excluding these items, adjusted net earnings from operations for the six months ended June 30, 2008 increased to a record $1,832 million compared to $1,216 million for the six months ended June 30, 2007. The increase in adjusted net earnings from the comparable period in 2007 was primarily due to the impact of higher realized pricing, lower depletion, depreciation and amortization expense, lower interest expense, and lower administration expense. These factors were partially offset by higher realized risk management losses, higher royalty and production expense, lower sales volumes and the impact of the stronger Canadian dollar relative to the US dollar.

The net loss for the second quarter of 2008 was $347 million compared to net earnings of $841 million for the second quarter of 2007 and net earnings of $727 million for the prior quarter. The net loss for the second quarter of 2008 included net unrealized after- tax expenses of $1,307 million related to the effects of risk management activities, fluctuations in foreign exchange rates, and fluctuations in stock-based compensation expense, compared to net unrealized after-tax income of $246 million for the second quarter of 2007 and net unrealized after-tax expenses of $145 million for the prior quarter, which also included the impact of statutory tax rate changes on future income tax liabilities. Excluding these items, adjusted net earnings from operations for the second quarter of 2008 increased to a record $960 million compared to $595 million for the second quarter of 2007 and $872 million for the prior quarter. The increase in adjusted net earnings from the second quarter of 2007 and the prior quarter was primarily due to the impact of higher realized pricing, lower depletion, depreciation and amortization expense, lower interest expense, and lower administration expense. These factors were partially offset by higher realized risk management losses, higher royalty and production expense, and lower sales volumes. The increase in adjusted net earnings from the second quarter of 2007 was also partially offset by the impact of the stronger Canadian dollar relative to the US dollar.

The impacts of risk management activities, stock-based compensation expense and fluctuations in foreign exchange rates are expected to continue to contribute to significant quarterly volatility in consolidated net earnings.

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 expenditures throughout the Horizon Oil Sands Project (“Horizon Project”) construction period. This program currently 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 put options is in addition to the above parameters. In accordance with the policy, approximately 57% of budgeted crude oil volumes are hedged for the remainder of 2008, approximately 18% of budgeted natural gas volumes are hedged for the third quarter of 2008 and approximately 6% of estimated crude oil volumes are hedged for 2009. In addition, 50,000 bbl/d of crude oil volumes are protected by put options for the remainder of 2008 at a strike price of US$55.00 per bbl, 50,000 bbl/d of crude oil volumes are protected by put options for 2009 at a strike price of US$80.00 per bbl, and 42,000 bbl/d of crude oil volumes are protected by put options for 2009 at a strike price of US$100.00 per bbl. Subsequent to June 30, 2008, the Company unwound 50,000 bbl/d of US$80.00 WTI put options and entered into 50,000 bbl/d of US$100.00 WTI put options for the period January to December 2009.

Commencing January 1, 2009, following the planned completion of Phase 1 of the Horizon Project, the Company’s commodity hedging program has been revised by its Board of Directors to allow for the hedging of up to 50% of the near 12 months budgeted production and up to 25% of the following 13 to 24 months estimated production. The purchase of put options will continue to be in addition to the above parameters.

The Company’s outstanding commodity related financial derivatives as at June 30, 2008 are detailed in the “Liquidity and Capital Resources” section of this MD&A.

The commodity derivative financial instruments currently outstanding have not been designated as hedges for accounting purposes (the “non-designated hedges”). The fair value of these non- designated hedges is based on prevailing forward commodity prices in effect at the end of each reporting period and is reflected in risk management activities in consolidated net earnings. The cash settlement amount of the 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 June 30, 2008.

Due to changes in crude oil and natural gas forward pricing and the reversal of prior period unrealized gains and losses, the Company recorded a net unrealized loss of $1,523 million ($1,073 million after-tax) on its commodity risk management activities for the six months ended June 30, 2008, including a $1,415 million ($997 million after-tax) unrealized loss for the three months ended June 30, 2008. 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. For further details, refer to the “Risk Management Activities” section of this MD&A.

Subsequent to June 30, 2008, prevailing forward commodity prices declined. Based on forward pricing as at July 31, 2008 and including the effects of July 2008 settlements, unrealized risk management losses as at June 30, 2008 would have decreased by approximately $680 million ($480 million after-tax).

The Company recorded a $459 million ($328 million after-tax) stock-based compensation expense for the six and three months ended June 30, 2008 as a result of the increase in the Company’s share price (Company’s share price as at: June 30, 2008 – C$100.84; March 31, 2008 – C$70.27; December 31, 2007 – C$72.58; June 30, 2007 – C$70.78). 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 quarterly 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 June 30, 2008 reflected the Company’s potential cash liability should vested options be surrendered for a cash payout at the market price on June 30, 2008. 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 six months ended June 30, 2008 increased to a record $3,584 million compared to $3,135 million for the six months ended June 30, 2007. The increase from the comparable period in 2007 was primarily due to the impact of higher realized pricing, partially offset by higher realized risk management losses, higher royalty and production expense, higher current income tax expense, lower sales volumes and the impact of the stronger Canadian dollar relative to the US dollar.

Cash flow from operations for the second quarter of 2008 increased to a record $1,859 million compared to $1,513 million for the second quarter of 2007 and $1,725 million for the prior quarter. The increase from the second quarter of 2007 was primarily due to the impact of higher realized pricing, partially offset by higher realized risk management losses, higher royalty and production expense, higher current income tax expense, lower sales volumes and the impact of the stronger Canadian dollar relative to the US dollar. The increase from the prior quarter was primarily due to the impact of higher realized pricing, partially offset by higher realized risk management losses, and higher royalty and production expense.

Total production before royalties for the six months ended June 30, 2008 decreased 6% to average 578,461 boe/d from 613,790 boe/d for the six months ended June 30, 2007. Production for the second quarter of 2008 decreased 7% to 573,437 boe/d from 614,461 boe/d for the second quarter of 2007 and 2% from 583,488 boe/d for the prior quarter. Total production for the second quarter of 2008 was at the high end of the Company’s previously issued guidance.

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__ Jun 30____Mar 31____Dec 31____Sep 30

s)________________________________2008______2008______2007______2007 ——————————————————————– ——– Revenue, before royalties____________$__5,112__$__3,967__$__3,200__$__3,073 Net earnings (loss)__________________$__ (347) $____727__$____798__$____700 Net earnings (loss) per common share – Basic and diluted________________ $__(0.65) $__ 1.35__$__ 1.48__$__ 1.30 ——————————————————————– ——– ——————————————————————– ——– ($ millions, except per common share__ Jun 30____Mar 31____Dec 31____Sep 30

s)________________________________2007______2007______2006______2006 ——————————————————————– ——– Revenue, before royalties____________$__3,152__$__3,118__$__2,826__$__3,108 Net earnings________________________ $____841__$____269__$____313__$__1,116 Net earnings per common share – Basic and diluted________________ $__ 1.56__$__ 0.50__$__ 0.58__$__ 2.08 ——————————————————————– ——– ——————————————————————– ——–

Net earnings (loss) over the eight most recently completed quarters generally reflected fluctuations in realized crude oil and natural gas prices, fluctuations in sales volumes, the impact of mark-to-market accounting of financial instruments and stock-based compensation,




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