THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT. Corporate Presentation

Transcription

1 THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT Corporate Presentation November 2010

2 DELIVERING VALUE AND GROWTH SNAPSHOT F Cash flow (C$ millions) $6,090 $6,300 - $6,700 (1) (1) Per share basic (C$) $5.62 $ $6.15 Capital expenditures (C$ millions) $2,997 $5,174 Dividend (C$/share) $0.21 Common shares (thousands) 1,084,654 Production (annual average, before royalties) Oil (mbbl/d) Natural gas (mmcf/d) 1,315 1,242-1,250 BOE (mboe/d) Reserves of crude oil and natural gas, net of royalties (as at December 31, 2009) Proved crude oil and NGLs (mmbbl) 3,027 Proved natural gas (bcf) 3,179 Proved BOE (mmboe) 3,557 Proved and probable BOE (mmboe) 5,440 (1) Based upon the following average actual pricing to September 30, 2010 and average strip pricing as at October 15, 2010, including the impact of hedging F Oil WTI (US$/bbl) $61.93 $78.83 Natural gas NYMEX (US$/mmbtu) $4.03 $4.45 Heavy oil diff (US$/bbl) $9.64 $14.60 C$/US$ $0.88 $0.97 Note: All per share data in this presentation adjusted for 2004, 2005 and 2010 stock splits.

3 Who is Canadian Natural? Canadian based E&P company with international exposure ~US$48 billion enterprise value 575 mboe/d % crude oil weighted ~ mboe/d 2010F Returns focused Major oil sands player Major in-situ producer with several projects in inventory Major mining project currently ramping production Production Mix (Q3/10) North America 90% North Sea 4% Offshore West Africa 6% The Premium Value, Defined Growth Independent 2 Who is Canadian Natural? Consistent value creation through successful Exploitation Exploration Opportunistic acquisitions 100% of reserves subject to independent evaluation Proved Reserves (mmboe) Production / Proved Reserves History (before royalties) 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, Daily Production (mboe/d) F 0 Note: 2009 includes Horizon SCO reserves. Production Reserves The Premium Value, Defined Growth Independent 3 1

4 Why Invest in Canadian Natural s Future Strong, low-risk asset base Includes world class oil sands in-situ and mining developments Largest producer of heavy crude oil in western Canada Largest net undeveloped land base in western Canada Second largest producer of natural gas in western Canada Balanced and large size reduces risk Track record of value creation Proven / committed management Winning exploitation-based strategy Defined plan for profitable growth Focused on value creation Consistent History of Value Creation 4 Historical Production Growth (boe/d) 700, ,000 Canadian Natural Production to Present Horizon Construction 47.5% Drop In Oil 500, ,000 Significant Price Reduction 35% Oil 300, , , % Gas 48% Oil Q1-89 Q1-90 Q1-91 Q1-92 Q1-93 Q1-94 Q1-95 Q1-96 Q1-97 Q1-98 Q1-99 Q1-00 Q1-01 Q1-02 Q1-03 Q1-04 Q1-05 Q1-06 Q1-07 Q1-08 Q1-09 Q

5 A History of Value Creation Daily Production Per 10,000 Shares (boe/d) 6 4 8% CAGR Gross Reserves Per Share* (boe) % CAGR Gas Oil Gas Oil Mining SCO Cash Flow Per Share* $8 $6 $4 $2 21% CAGR Pretax Net Asset Value Per Share* $60 $40 $20 27% CAGR $ $ *Refer to page 1 of the 2009 Canadian Natural Annual Report for a detailed description of notes. Per share values adjusted for 2004, 2005 and 2010 stock splits. Reserves include proved and probable oil reserves include Horizon SCO. Consistent Growth 6 Committed Management Substantial management and director wealth at stake Strong motivation for management to perform Delivers clear alignment with shareholder interests Management / Directors Stock Ownership (US$ millions) 2,000 1,800 1,600 1,400 1,200 1, $1, $184 $157 $137 $122 $97 $34 $27 $21 $12 DVN EOG APA APC PXD ECA NXY TLM CVE Note: Peers based on share ownership data excluding options and priced at November 5, Source: SEDI. Consistent History of Value Creation 7 3

6 Our Strategy Capital allocation to maximize value Defined growth / value enhancement plans by product / basin Balance Product mix Project time horizons Drill bit and acquisitions Strong balance sheet Opportunistic acquisitions Control costs through area knowledge and domination of core focus areas A Proven, Effective Strategy 8 Natural Gas Operating Cost Peer Comparison ($/mcf) $3.00 $2.50 $2.00 $1.50 Peer Average Peer Group $1.00 $0.50 $0.00 Q4/05 Q1/06 Q2/06 Q3/06 Q4/06 Q1/07 Q2/07 Q3/07 Q4/07 Q1/08 Q2/08 Q3/08 Q4/08 Q1/09 Q2/09 Q3/09 Q4/09 Q1/10 Q2/10 Canadian Natural Note: Other Producers - NXY, HSE, TLM, ECA, ARC, PWT, PGF.UN. Source: Corporate reports. Best in Class Versus Established Peers 9 4

7 Heavy Oil Operating Cost Peer Comparison ($/bbl) $25.00 $20.00 $15.00 Peer Average Peer Group $10.00 $5.00 $0.00 Q4/05 Q1/06 Q2/06 Q3/06 Q4/06 Q1/07 Q2/07 Q3/07 Q4/07 Q1/08 Q2/08 Q3/08 Q4/08 Q1/09 Q2/09 Q3/09 Q4/09 Q1/10 Q2/10 Canadian Natural Note: Other Producers - HSE, TLM, CVE. CVE and heavy oil operations not including thermal operating costs. Source: Corporate reports. Best in Class Versus Established Peers 10 Essential Elements to Our Defined Plan Natural Gas 1-2 years 3-5 years Beyond Optimize Potential for >8,000 potential returns 3-5% CAGR drilling locations NA Oil Pelican / Primary Potential for >20 years of Primrose 5-7% CAGR development International Free cash High return Major area for flow projects growth (acq) Horizon Stabilize production Expansion to 6 billion barrels Re-profile expansions mbbl/d bitumen in place A Growing, Returns - Focused E&P Creating Significant Value 11 5

8 North America Natural Gas Assets 2010 plan Maintain development of growth projects Expand inventory High grade drilling program and optimize production 2,000 1,600 1, NE BC 300 mmcf/d NW AB 489 mmcf/d Southern Plains 148 mmcf/d Northern Plains 294 mmcf/d SE SK 3 mmcf/d Note: Reflects Q3/10 actual production, before royalties. Disciplined Development of Strong Gas Assets 12 North America Natural Gas Core Area Summaries North and South Plains Conventional exploitation Shallow gas and HSC CBM resource projects Low risk, low cost, highly profitable Foothills High impact exploration NE British Columbia Unconventional - Muskwa and Montney Low cost entry NW Alberta Resource projects - Deep Basin and Montney Repeatable, large scale Balanced, Cost Effective Growth Foothills Land NE BC NW AB BC Northern / Southern Plains AB SK 13 6

9 North America 2010 Forecast Natural Gas Drilling Focus on drainage and expiries Development of Septimus (BC Montney) Strategic setup wells Capital ~$700 million Production ~1,220 mmcf/d midpoint average 5% annual decline 5% entry to exit growth Forecast North America Light Oil Drilling ~117 wells (38 wells in 2009) New play development 25 wells EOR / waterflood / CO 2 development Capital ~$315 million Production (excludes NGLs) ~34,000 bbl/d midpoint average 2% annual growth 18% entry to exit growth 15 7

10 Heavy Oil Assets Horizon mining operation 84,000 bbl/d Best estimate contingent resource of 6 billion barrels of bitumen in place ~500,000 bbl/d total capability Thermal in-situ development 85,000 bbl/d Massive resource potential Staged value growth ~285,000 bbl/d of additional production Pelican Lake EOR development 38,000 bbl/d 4.1 billion barrels OOIP Largest polymer flood in North America 3.5x increase in expected recovery Reliable primary production 93,000 bbl/d Dominant land base ~ 1.6 million acres Record ~650 wells Technology Option Pelican Lake (38 mbbl/d) Primary Heavy Oil (93 mbbl/d) Land Birch Mountain (W. Horizon) 300 miles Gregoire AB SK Kirby Primrose (85 mbbl/d) Note: Reflects Q3/10 actual working interest production Forecast Primary Heavy Oil Drilling 2010 ~650 wells wells wells Recompletions wells Capital ~$620 million Production ~92,300 bbl/d midpoint average 7% annual growth 8% entry to exit growth Excellent return on capital in current environment 17 8

11 Heavy Oil Pelican Lake World class oil pool Efficient, low cost operations Polymer flood successful both technically and economically Technology enhancement will continue to improve oil recovery OOIP 4.1 billion barrels Developed Region How much of that oil is producible? Contingent Resources 198 mmbbl Probable Reserves 103 mmbbl Proved Reserves 246 mmbbl Produced to Date 140 mmbbl (barrels per day) 100,000 80,000 60,000 40,000 20,000 Primary Convert waterfloods to polymer Waterflood Polymer flood Primary Waterflood Polymerflood Massive Resource to Exploit Forecast Pelican Lake Pelican Lake Drilling 28 horizontal wells for primary production 103 horizontal wells for polymer flood expansion Initiate development of nearby Wabiskaw heavy oil pools Capital ~$495 million Production ~38,000 bbl/d midpoint average in % annual growth 12% entry to exit growth 19 9

12 Thermal Oil Sands Potential McMurray 22 billion barrels Kirby Grouse Leismer Birch Mountain Gregoire Clearwater 11 billion barrels Contingent Resources 4.5 billion bbl Probable Reserves 0.6 billion bbl Proved Reserves 0.7 billion bbl Produced to Date 0.3 billion bbl Note: Excludes recent acquisitions. Estimated Bitumen in Place 33 billion barrels total 33 Billion Barrels of Bitumen in Place Forecast Thermal Heavy Oil Drilling Strats 182 wells Production/steam 40 wells Capital ~$540 million Production ~91,000 bbl/d midpoint average 43% annual growth 21 10

13 Thermal Heavy Oil Growth Plan Oil Facility Target Steam-In Phase Reservoir Complexity Capacity Target ** Timing (bbl/d) Primrose N/S - CSS Clwtr Low 80,000 On Stream Primrose E - CSS Clwtr Low 40,000 On Stream Kirby Ph 1 - SAGD McM Low 40, Grouse - SAGD McM Low 60, Birch Mountain Ph 1 - SAGD McM Mod 60, CSS - Follow-up Process* Clwtr Tech 30, Birch Mountain Ph 2 - SAGD McM Mod 60, Gregoire Ph 1 - SAGD McM High 60, ,000 bbl/d of oil facility capacity in the defined growth plan 30,000-60,000 bbl/d addition every 2-3 years (year) Low - Simple incised system Mod - Structural complications High - Structural plus saturations complications Tech - Requires Technology development *CSS -Follow up will be processed through existing facilities. **Production to be optimized around facility capacity. Growth for Decades 22 Kirby Development Plan Kirby development expanded through acquisitions in October 2010 adding best estimate contingent resource of 520 million barrels of bitumen. Kirby development will include three phases: Kirby Phase 1 Regulatory approval and Board of Directors Sanction Kirby Phase 2 Kirby Debottleneck Three Phases targeted to provide overall production capabilities of between 70,000 bbl/d and 100,000 bbl/d Kirby Phase 1 Construction to begin in Q First steam in late 2013 Overall Phase 1 capital costs targeted to be $1.25 billion Using Synergies to Create Value 23 11

14 Kirby Land Holdings Kirby Phase 2 Kirby North Kirby North Plant (Remote Steam) Kirby Phase 1 Kirby Central Kirby South Plant (Steam & Oil Treating) Oilsands Acquisition Kirby South 24 Heavy Oil Three Pronged Marketing Plan Conversion capacity Pipelines Blending Cumulative Incremental Volume DilSynbit WCS (Western Canadian Select) Synbit Additional refinery conversion capacity Refining: cokers / hydrocrackers Upgrading: bitumen / heavy oil Keystone XL (USGC Q4 2012) Alberta Clipper Q4/10 Keystone (Patoka June 2010 and to Cushing Q4/10) Total blend is 280 mbbl/d 55% commitments: 100 mbbl/d to USGC refiner 12.5 mbbl/d to NWU-1 West Coast options (Gateway, TMX) Texas Access USGC has committed 120 mbbl/d Short Term Up to 5 years Medium Term 5 to 10 years Long Term >10 years Access to Incremental Markets Over the Short, Medium and Long Term 25 12

15 International Operations North Sea Exploitation based value creation Delivering field life extension Generates significant free cash flow Opportunity for acquisition in future years Leveraging technical strengths in Africa Offshore West Africa High return, long lead projects Generates significant free cash flow 2009/10 activity - Gabon April 2009 first oil delivered from Platform C Successfully installed remaining 3 platforms First oil delivered from Platform B All 6 wells on Platform B completed and onstream in Q3/10 October 2010 first oil delivered from Platform A Focus on Free Cash Flow While Setting Up For Future Expansion 26 Canadian Natural s Mineable Assets - Horizon Oil Sands Mining resources 16 billion barrels of bitumen in place, with best estimate total reserves and contingent resource of 6 billion barrels of bitumen recoverable Phased development (SCO) 110 mbbl/d capacity (Phase 1) Target expansion to 232 to 250 mbbl/d Target future expansions to ~500 mbbl/d Significant free cash flow generation for decades ~43 miles Horizon Oil Sands DVN Deer Creek PCA SYN SHC Fort McMurray UTS SYN SHC SU SHC IOL XOM SYN SU HSE IOL PCA XOM ECA Synenco SU SU SU ECA ECA World Class Opportunity 27 13

16 Horizon Oil Sands 2010 Plan Establish reliability on production Identify debottlenecking opportunities Complete lessons learned from Phase 1 Continue Tranche 2 capital Engineering for Phase 2/3 expansion 28 Horizon Production Ramp-up Production ramp-up plan Ramp-up to design capacity of SCO planned Replacement / repair of equipment with premature failures and wear (Bad Actors) have delayed achieving full production sooner Focus is on fine tuning plant to design rates and sustained design rates Implementing lessons learned during 1 st year of operations 2010 production Guidance Annual equivalent daily production of 90,000 to 93,000 barrels SCO Q3/10 equivalent daily production was 84,000 barrels SCO Continuing to ramp-up to design rates Ramp up to Reliable Production 29 14

17 Canadian Natural 2010 Overall Plan 1) Pay down debt 2) Achieve reliable Horizon Oil Sands production Lessons learned, progress expansion cost estimate 3) Conserve our land base Expiries Drainage 4) Significant primary heavy oil program 5) Progress thermal development 6) Prepare Kirby for sanction 7) Progress Pelican Lake polymer flood 8) Increased focus on EOR in light oil projects 9) Leverage technology 10) Focus on value growth not production growth Focus on Value Growth 30 Canadian Natural 2010 Production Guidance Daily Production Volumes (before royalties) F Change Natural Gas (mmcf/d) North America Natural Gas 1,287 1,217-1,222 (5%) North Sea % Offshore West Africa (11%) Total 1,315 1,242-1,250 (5%) Crude Oil and NGLs (mbbl/d) North America % North America - Mining % North Sea (12%) Offshore West Africa (8%) Total % Production (mboe/d) % 31 15

18 Canadian Natural 2010 Capital Budget F Change Production (mboe/d) % Cashflow ($mm)* $6,090 $6,300 - $6,700 15% Capital ($mm) North America $1,714 $2,670 56% North Sea $168 $180 7% Offshore West Africa $544 $250 (54%) Horizon $553 $574 4% Total Organic Capital $2,979 $3,674 23% Property Acquisitions $18 $1,500 Total $2,997 $5,174 73% Free cash flow ($mm)** $3,093 $1,125 - $1,525 *2010 based on WTI US$78.83 and NYMEX US$4.45. **Cash flow less Capital. 10% Production Growth While Spending Only 80% of Cash Flow 32 Canadian Natural Free Cash Flow 2010F (C$ billions) $5.0 Conventional $4.0 $3.0 $2.0 $1.0 $0.0 % of Cash Flow 34% Horizon 58% North Sea Offshore West Africa 56% 57% -$1.0 -$2.0 -$3.0 Cash Flow Capital Free Cash Flow Based on WTI US$78.83/bbl, AECO C$3.93/GJ. Excluding acquisitions and divestitures. All Divisions Generating Free Cash Flow 33 16

19 Canadian Natural Assets Heavy crude oil 285,000 bbl/d incremental thermal oil Dominant primary heavy oil position Technology upside Natural gas Ultimate drilling potential of over >8,000 wells Strong exposure to shale gas Large land base in western Canada International Baobab infill Olowi development South Africa exploration Horizon Oil Sands Phase 1 onstream Future - target production to ~500,000 bbl/d Technology upside Significant Upside 34 Canadian Natural Advantage Management, business philosophy, practice Strong, balanced assets Vast opportunities Balanced, proven, effective strategy Control over capital allocation Nimble Capture opportunities Willingness to make tough decisions Significant free cash flow Canadian Natural culture Control of costs Execution focused The Premium Value, Defined Growth Independent 35 17

20 Forward Looking Statements Certain statements in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively Certain statements relating to the Company 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 guidance provided in the 2010 outlook section and throughout this document and the documents incorporated herein by reference constitute forward looking statements. Disclosure of plans relating to existing and future developments including but not limited to Horizon, Primrose East, Pelican Lake, Olowi Field (Offshore Gabon), and the Kirby Thermal Oil Sands Project also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts and is reviewed and revised throughout the year if necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. 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. The forward-looking statements are based on current expectations, estimates and projections about 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 risks and uncertainties 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. Certain of these factors are discussed in more detail under the heading Risk Factors. 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. 36 Reporting Disclosures Special Note Regarding Currency, Production and Reserves In this document, all references to dollars refer to Canadian dollars unless otherwise stated. Production data is presented on a before royalties basis unless otherwise stated. In addition, reference is made to oil and gas in common units called barrel of oil equivalent ( boe ). A boe is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6mcf:1bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head. Reserves National Instrument Standards for Disclosure for Oil and Gas Activities ( NI ) of the Canadian Securities Administrators imposes requirements and standards for Canadian public companies engaged in oil and gas activities. The Company has an exemption from certain provisions under NI This exemption allows the Company to substitute SEC requirements under Regulations S-K and S-X for certain disclosures required under NI On December 31, 2008, the SEC released its final rules for the modernization of oil and gas reporting ( Final Rule ). The material changes include the ability to include oil sands mining as an oil and gas activity, ability to use reliable technology to establish undeveloped reserves, the optional ability to report probable reserves, the requirement to track undeveloped locations, as well as the directive to use 12-month average prices and current costs. These resulting changes are more in line with the NI , however, there are material differences to the type of volumes disclosed and the basis from which the volumes are determined. NI requires gross reserves and future net revenue under forecast pricing and costs. The SEC requires disclosure of net reserves, after royalties, under 12-month average prices and current costs. The difference between the reported numbers under the two disclosure standards can be material. For the year ended December 31, 2009 the Company retained qualified independent reserves evaluators ( IQRE ), Sproule Associates Limited ( Sproule ), and GLJ Petroleum Consultants Ltd. ( GLJ ), to evaluate and review all of the Company s proved, as well as probable crude oil, synthetic crude oil, bitumen, coal bed methane, NGLs and natural gas reserves and prepare Evaluation Reports on these reserves. Sproule evaluated and reviewed all of the Company s crude oil, bitumen, natural gas, coal bed methane and NGLs reserves. GLJ evaluated all of the synthetic crude oil reserves related to the Company s oil sands mine. Reserves estimates provided in this presentation are working interest volumes, before royalties, and are as of December 31, The reserves volumes provided are evaluated by IQRE under SEC guidelines using 12-month average prices and current costs. Resources The Contingent resource estimates provided in this presentation are evaluated in accordance to Canadian Oil and Gas Evaluation Handbook ( COGEH ) standards as directed under NI These estimates are evaluated internally. No independent third party evaluation or audit was completed. Contingent resources provided are best estimates as of December 31, The contingent resources are evaluated using deterministic methods which represent the expected outcome with no optimism or conservatism. Contingent resources, as per COGEH definition, are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from know accumulations using established technology or technology under development, but are not currently considered commercially viable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of these resources. Due to the inherent differences in standards and requirements employed in the evaluation of reserves and contingent resources the total volumes of reserves or resources are not to be considered indicative of total volumes that may actually recovered and are provided for illustrative purposes only. Petroleum initially in place volumes provided are discovered resources which include: production, reserves, contingent resources and unrecoverable volumes. Special Note Regarding non-gaap Financial Measures Management's discussion and analysis includes references to financial measures commonly used in the oil and gas industry, such as cash flow, cash flow per share and EBITDA (net earnings before interest, taxes, depreciation depletion and amortization, asset retirement obligation accretion, unrealized foreign exchange, stock-based compensation expense and unrealized risk management activity). These financial measures are not defined by generally accepted accounting principles ( 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 the performance of the Company and of its business segments. The non-gaap measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with Canadian GAAP, as an indication of the Company's performance. Volumes shown are Company share before royalties unless otherwise stated

21 Appendices 38 Annualized Sensitivity to Prices Annualized and based upon Q3/10 business conditions and sales volumes but excluding financial derivatives Variable WTI +/- US$1.00/bbl AECO +/- C$0.10/mcf 10,000 bbl/d change in crude oil production 10 mmcf/d change in natural gas production $0.01 change in US$* Impact on Cash flow ~$129 million ~$35 million ~$166 million ~$9 million ~$100 million *Includes financial derivatives. Significant Upside from Conservative Budget Price Deck 39 19

22 International North Sea Exploitation base similar to WCSB Operate ~99% and own ~80% of production Infill drilling / recompletions & waterflood optimization 1 drill string operating in well and 3 well interventions Lands Oil Field Northern North Sea Scotland Aberdeen Murchison Hutton Lyell Central North Sea Ninian Columba Banff Strathspey Tiffany Toni Thelma Kyle Playfair Edinburgh Value Creation Through Exploitation Approach 40 International Offshore Côte d Ivoire East Espoir First oil achieved in infills drilled in 2005/6 FPSO expansion completed in Q2/10 West Espoir development First oil achieved July 2006 increased to ~13 mboe/d in 2007 Baobab development First oil achieved in 2005 Sand handling and infill drilling program in 2008/9 4 wells back on production Côte d Ivoire Panthere Foxtrot West Espoir Mantra East Espoir Baobab Jacqueville Acajou Acajou Kossipo Atlantic Ocean Lands Oil Field Gas Field Prospects Area for Light Oil Growth 41 20

23 International Offshore Gabon April 2009 first oil delivered from Platform C Successfully installed remaining 3 platforms First Oil delivered from Platform B All 6 wells on Platform B completed and on stream in Q3/10 October 2010 first oil delivered from Platform A Target 2010 exit rate of 7,000-11,000 bbl/d Libreville (~545km) BIGORNEAU Platform A Platform B OLOWI Platform C (CSP) Platform D Gabon THEMIS Atlantic Ocean Lands Olowi Field - Continue to Maximize Future Value 42 International South Africa - Big E Potential Existing production CNRI Block 11B/12B 1000m water depth Paddavissie Fairway 100km Large structures Challenging ocean conditions P50 STOIP of 3 Billion Barrels 43 21

24 North America Operations Competitive Advantage Largest land base 17.3 million net developed and undeveloped acres Large undeveloped land base 10.6 million net acres Extensive seismic database Leveraging a vast infrastructure Total Land Holdings (Thousands of Net Acres) 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 SU ECA HSE CVE DVN TLM APA EOG NXY Developed Undeveloped Note: Based on 2009 Annual Reports. Large Land Base and Dominant Infrastructure 44 Strategic Development Septimus Montney Play Large resource Discovered gas in place of 7.3 tcf 3.8 bcf of contingent resource per well Proved reserves of 57 bcf Probable reserves of 10 bcf Liquids rich gas with 27 bbl/mmcf Drilling / completion Drilling cost reduction of 37% from Q3/08 to Q1/10 Eligible for significant deep gas drilling credits 8-12 fracs per horizontal well Project economics* Full cycle target F&D - $2.07/mcfe Target operating costs - $0.60/mcfe Target recycle ratio - 1.8x *Based on Q1/10 actual plus current 2010 strip at WTI US$86.98/bbl, AECO C$4.10/GJ. SEPTIMUS ECA SWAN ARC DAWSON Well Positioned Montney Asset 45 22

25 Natural Gas Production Base Evolution Production (mmcf/d) 2,000 1,800 1,600 1,400 1,200 1, Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Oct-05 Jan-06 Apr-06 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Pre 2006 drilling 2006 Drilling 2007 Drilling 2008 Drilling 2009 Drilling 2010 Drilling Note: Includes production volumes from all acquisitions except Annual base decline rate is slowing Emphasis on resource plays such as Cardium, shallow, CBM have lower mature declines Reduced new drilling activity reduces first year decline impact Measured ~109 well drilling program in 2010, results in only a 13% midpoint production decline Forecast 46 Natural Gas 10 Year Plan Drilling activity 58% resource plays Natural gas growth 63% resource plays Drilling Activity Shale Gas 7% CBM 8% Conventional 41% Foothills 1% Tight Gas 43% CBM 2% Natural Gas Growth Shale Gas 23% Conventional 27% Foothills 10% Tight Gas 38% Cost Effective, Lower Risk 47 23

26 Heavy Oil Differentials (% of WTI) 60% 50% 40% 30% Logistical Constraints WCS Pipeline Issues in PADD II 20% 10% Maya 0% WCS at Hardisty Maya at USGC Q4 to Q1 Q2 to Q3 Differential Impacted by Logistical Constraints and Refining Margins 48 Expanding Pipeline Options ENB Gateway 400 mbbl/d Crude Export Line Kitimat TMX Staged Expansion 525 mbbl/d Kinder Morgan 300 mbbl/d Vancouver Fort McMurray Edmonton Hardisty ENB Alberta Clipper 450 mbbl/d Superior Southern Lights 180 mbbl/d TCPL Keystone to Patoka 435 mbbl/d TCPL Keystone XL Pipeline 700 mbbl/d in Q1/2013 TCPL Keystone to Cushing 155 mbbl/d in Q1/2011 Existing Near Completion Long Term Potential Proposed Casper Steele City Denver USGC Wood River Cushing Chicago Patoka ENB Spearhead 195 mbbl/d XOM Pegasus 95 mbbl/d Capacity to Access Markets 49 24

27 Heavy Oil Keystone XL Pipeline Transportation committed 120,000 bbl/d to the Keystone XL Pipeline to USGC for 20 years Mitigates logistical constraints Narrows heavy oil differential Significantly reduces market risk for incremental production Alternative routing in the event of pipeline apportionment Supply committed 100,000 bbl/d to a major US Gulf Coast refiner for 20 years Keystone XL received NEB approval March 2010 Expandable to 1.5 mmbbl/d Q Jun 2010 Q Q Pipeline Access to New Markets is Available 50 NW Upgrading Joint Venture Fits Canadian Natural s strategy to support additional heavy oil conversion capacity NWU and Canadian Natural to form 50/50 joint venture to construct and operate a new bitumen refinery near Redwater, AB if successful in being awarded a contract to process bitumen royalty in kind (BRIK) volumes from the Government of Alberta (GOA) Expected year end for final agreement with GOA Proposed bitumen refinery would convert 50 mbbl/d of raw bitumen into useable products and provide an integrated CO 2 capture and management solution Canadian Natural has committed 12.5 mbbl/d to phase 1 of the project Strong Strategic Fit 51 25

28 Heavy Oil Primary Robust economics Typical vertical / slant well costs $500,000 Typical well produces bbl/d Wells payout in less than 1 year Recycle ratio greater than 3x Target free cash flow $0.8-$0.9 billion in 2010F Today Largest primary producer in region Pumping technology transformed the heavy oil business Large resource remains unrecovered post primary What s next EOR Waterflooding - 2 pilots Polymerflooding (bbl/d) 140, , ,000 80,000 60,000 40,000 20, Gross Operated Heavy Oil Production A Proven Success 52 Pelican Lake Polymer Flood What is a polymer? It is a polyacrylamide powder mixed with water Why does it help recovery? It increases the viscosity of water and improves vertical and aerial sweep efficiencies by reducing fingering What additional facilities are required? Water handling capability at batteries Polymer skids What is the incremental capital cost? $6.00-$9.00/bbl oil recovered What is the incremental operating cost? $2.00-$3.00/bbl oil Oil Production Polymer Injector An Industry Leading Technology 53 26

29 Pelican Lake Polymer Flood Response Initial Pilot Well Oil Production (bbl/d) Jan-97 Jul-97 Primary 156 mbbl Jan-98 Jul-98 Jan-99 Jul-99 Strong Visible Response Polymer injection commenced Jan-00 Jul-00 Jan-01 Jul-01 Jan-02 Jul-02 Jan-03 Jul-03 Jan-04 Jul-04 Jan-05 Jul-05 Polymer flood 320 mbbl to date Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 Jul-09 Jan Pelican Lake Polymer Flood Expansion Polymer flood at end of % 2010 Polymer Plan 44% 5 Year Polymer Plan 88% Land Polymer Success Leads to Expansion 55 27

30 Polymer Flood Development Defined plan Continue reservoir fill-up with existing patterns Target first oil response Q4/10 Expand polymer flood to new patterns Targeted Construct bulk handling systems for polymer Test polymer in reservoir with heavier crude The future Evaluate surfactants with polymer Evaluate other pools for polymer flood application Evaluate other EOR techniques Great Opportunity for Optimization 56 Heavy Oil Oil Sands Land Holdings (net) McMurray - 373,000 acres Birch Mountain Gregoire Kirby Grouse Leismer Ipiatik Clearwater - 201,000 acres Primrose Wolf Lake Hilda Lake Marie Lake Grand Rapids - 267,000 acres Germain Carbonates - 317,000 acres Grande Prairie Oil Sands Deposits Edmonton Calgary Fort McMurray Birch Mountain Saleski Germain Gregoire AB Pelican Lake Leismer Cherpeta Kirby Oil Sands Cenovus Conoco Devon Shell Suncor Syncrude All Others Grouse Ipiatik Primrose ~140 miles SK Great Assets, Huge Land Base 57 28

31 Thermal Oil Sands Primrose CSS Continued Growth Primrose Production (bbl/d) 140,000 Actual Forecast 120, ,000 80,000 60,000 40,000 20, Wolf Lake Primrose South Primrose North Primrose East Growing Primrose to 120,000 bbl/d 58 Thermal Oil Sands Bitumen Recovery Schemes Cyclic Steam Stimulation (CSS) Inject / produce from single well High pressure Wet steam (~1.25 dry steam SOR) Only process for Clearwater Steam Assisted Gravity Drainage (SAGD) Dedicated injector / producer (2 wells) Low pressure continuous process Requires dry steam Only process for McMurray Match Scheme to Reservoir 59 29

32 Thermal Oil Sands Water Management Water Volume (bbl/d) 600, ,000 Historical Bitumen Production (bbl/d) 140,000 Forecast 120, , , ,000 Bitumen Production Produced Water 80,000 60, , , Fresh Water Recycle >98% Prod Water and Significant Efforts to Reduce Fresh Water Brackish Water ,000 20, Thermal Heavy Oil Growth Plan Future Production Production (bbl/d) 250, ,000 Birch Mtn Grouse SAGD 150,000 Kirby 100,000 50,000 Primrose CSS

33 Grand Forks ASP Flooding Alkaline Surfactant Polymer (ASP) flooding Surfactants reduce the oil left behind by the waterflood at Grand Forks Works like soap Polymer improves the sweep of the injected fluid, reaching reservoir bypassed by the waterflood Potential to expand - 60 pools currently waterflooded in area EOR for Shallow Reservoirs 62 Technology Option Thermal Geo-steering Well Placement Primrose North Steam Plant Bitumen burner tip Capturing More of the Reservoir With Technology Advancement 63 31

34 Thermal Heavy Oil Technology Advancement Stage 1, CSS recovery factor 20% Horizontal Wells ºCelsius Stage 2, Infill recovery factor 30% Infill Well Stage 3, Gravity Drainage recovery factor 40% Injector Well Producing Well Injector Well Technology Maximizes Recovery and Value 64 Horizon Oil Sands Process and Technology Only Proven Technologies Will be Utilized Reducing Technology Risks 65 32

35 Horizon Oil Sands Site Layout Lease 15 SHC RDS Synenco TOT SU Lease 12 Lease 11 ~43 miles Horizon UTS SU SHC Oil Sands RDS IMO IOL SYN XOM TOT Deer Creek SHC RDS HSE SU SU SYN IMO DVN IOL SU SYN DVN SU SU PCA SU ECA ECA SU PCA SU XOM ECA Lease 20 Lease 19 Lease 25 Overburden Dump Overburden Dump Lease 10 Athabasca River Fort McMurray ECA Horizon Lake Lease 18 NCI Tailings Pond Northwest Pit Southwest Pit Northeast Pit Plant Site Southeast Pit Overburden Dump Site Layout Maximizes Resource Recovery and Optimizes Economic Returns 66 Horizon Operating Costs Operating cost was $39.89/bbl SCO in 2009 Operating costs for 2010 Targeted range of $33.00/bbl to $37.00/bbl Q3/10 operating cost was $34.35 (including approximately $3.15 per barrel of natural gas input costs), primarily due to: A focus on proactive maintenance and operational optimization Given the fixed cost structure of the operation As production volumes increase and become sustainable, production costs will decrease Planned vs. unplanned maintenance Horizon Will Be The Low Cost Producer 67 33

36 Horizon Production (bbl/d) 120, /2010 Production Data 100,000 H2 Plant / PSA Valves OPP-Ext reliability DCU pump reliability 80,000 Leak in Hydrotreater Exchanger Sulphur plant burner restrictions 60,000 40,000 Dilbit Tanks high water content and high mine fines Replacement of Sulphur Exchanger Coker furnace convection section replacement Amine Unit pipe Planned outage 20,000 0 Start Up / Ramp Up Mar-09 Apr-09 May-09 Jun-09 Jul-09 Aug-09 Sep-09 Oct-09 Nov-09 Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Monthly Actual 68 Phase 2/3, Tranche Execution Ore Preparation Plant #3 Overall progress 66% complete MSE Wall and Plant Foundations engineering 34% complete Hydrotransport Lines Overall progress 28% on target Engineering services on schedule Upgrading (Gas Recovery, Sulphur and Butane) Engineering and Procurement (lump sum) on schedule Focused on implementing Phase 1 Lessons Learned Mine Maintenance Shop and Wash Bays Complete Preparing for Expansion 69 34

37 Phase 2/3, Tranche 3 and Execution Tranche 3 - no activity scheduled for 2010 Tranche 4 - untreated (Gasoil / Distillate) Swing Tank Overall progress 39% Tank erection complete Mechanical completion by the end of 2010 Preparing for Expansion 70 Revolving Bank Credit Facilities (C$ million) Maturity Revolving bank line $ 2,230 June 2012 Revolving bank line - Horizon $ 1,500 June 2012 Operating demand loan $ 200 Demand North Sea operating line ( 15 million) $ 24 Demand Total bank lines $ 3,954 Available Sep 30, 2010 $ 3,100 Solid Lines of Liquidity 71 35

38 Maturity Schedule Public Debt (C$ million) 1,400 1,200 1, C$ Public US$ Public (converted to C$ Equivalent) Note: Represents principal repayments only and does not reflect fair value adjustments, original issue discounts or transaction costs. Manageable Refinancing Natural Gas Hedging AECO (C$/GJ) $10 $9 $8 $7 $6 $5 $4 $3 100% 80% 60% Strip Floor Ceiling ~50% - Market 90% - Market 100% - Market 40% 20% 0% ~18% $ ~32% $ % $ Q3/10 Q4/10 Q1/11 Collars Market Note: Refer to quarterly reports for detailed hedging positions. Strip pricing as at Nov 02, Upside Opportunity, Downside Protection 73 36

39 2010 Crude Oil Hedging WTI (US$/bbl) $120 $110 $100 $90 $80 $70 $60 $50 Strip Floor Ceiling Puts 100% 80% 60% ~64% - Market ~67% - Market ~67% - Market 40% 20% 0% ~12% $ $75.08 ~12% $ $ ~12% $ $ ~11% $ $75.08 ~11% $ $ ~11% $ $ Q3/10 Q4/10 Q1/11 Collars Puts Market Note: Refer to quarterly reports for detailed hedging positions. Strip pricing as at Nov 02, ~22% $70.00 Puts ~11% $ $ Upside Opportunity, Downside Protection 74 37

40 Special Note Regarding Currency, Production and Reserves Special Note Regarding Currency, Production and Reserves In this document, all references to dollars refer to Canadian dollars unless otherwise stated. Production data is presented on a before royalties basis unless otherwise stated. In addition, reference is made to oil and gas in common units called barrel of oil equivalent ( boe ). A boe is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6mcf:1bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head. Reserves National Instrument Standards for Disclosure for Oil and Gas Activities ( NI ) of the Canadian Securities Administrators imposes requirements and standards for Canadian public companies engaged in oil and gas activities. The Company has an exemption from certain provisions under NI This exemption allows the Company to substitute SEC requirements under Regulations S-K and S-X for certain disclosures required under NI On December 31, 2008, the SEC released its final rules for the modernization of oil and gas reporting ( Final Rule ). The material changes include the ability to include oil sands mining as an oil and gas activity, ability to use reliable technology to establish undeveloped reserves, the optional ability to report probable reserves, the requirement to track undeveloped locations, as well as the directive to use 12-month average prices and current costs. These resulting changes are more in line with the NI , however, there are material differences to the type of volumes disclosed and the basis from which the volumes are determined. NI requires gross reserves and future net revenue under forecast pricing and costs. The SEC requires disclosure of net reserves, after royalties, under 12-month average prices and current costs. The difference between the reported numbers under the two disclosure standards can be material. For the year ended December 31, 2009 the Company retained qualified independent reserves evaluators ( IQRE ), Sproule Associates Limited ( Sproule ), and GLJ Petroleum Consultants Ltd. ( GLJ ), to evaluate and review all of the Company s proved, as well as probable crude oil, synthetic crude oil, bitumen, coal bed methane, NGLs and natural gas reserves and prepare Evaluation Reports on these reserves. Sproule evaluated and reviewed all of the Company s crude oil, bitumen, natural gas, coal bed methane and NGLs reserves. GLJ evaluated all of the synthetic crude oil reserves related to the Company s oil sands mine. Reserves estimates provided in this presentation are working interest volumes, before royalties, and are as of December 31, The reserves volumes provided are evaluated by IQRE under SEC guidelines using 12-month average prices and current costs. Resources The Contingent resource estimates provided in this presentation are evaluated in accordance to Canadian Oil and Gas Evaluation Handbook ( COGEH ) standards as directed under NI These estimates are evaluated internally. No independent third party evaluation or audit was completed. Contingent resources provided are best estimates as of December 31, The contingent resources are evaluated using deterministic methods which represent the expected outcome with no optimism or conservatism. Contingent resources, as per COGEH definition, are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from know accumulations using established technology or technology under development, but are not currently considered commercially viable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of these resources. Due to the inherent differences in standards and requirements employed in the evaluation of reserves and contingent resources the total volumes of reserves or resources are not to be considered indicative of total volumes that may actually recovered and are provided for illustrative purposes only. Petroleum initially in place volumes provided are discovered resources which include: production, reserves, contingent resources and unrecoverable volumes. Special Note Regarding Forward-looking Statements Certain statements in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively Certain statements relating to the Company 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 guidance provided in the 2010 outlook section and throughout this document and the documents incorporated herein by reference constitute forward looking statements. Disclosure of plans relating to existing and future developments including but not limited to Horizon, Primrose East, Pelican Lake, Olowi Field (Offshore Gabon), and the Kirby Thermal Oil Sands Project also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts and is reviewed and revised throughout the year if necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. 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. The forward-looking statements are based on current expectations, estimates and projections about 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 risks and uncertainties 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. Certain of these factors are discussed in more detail under the heading Risk Factors. 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 forwardlooking 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. Special Note Regarding non-gaap Financial Measures Special Note Regarding non-gaap Financial Measures Management's discussion and analysis includes references to financial measures commonly used in the oil and gas industry, such as cash flow, cash flow per share and EBITDA (net earnings before interest, taxes, depreciation depletion and amortization, asset retirement obligation accretion, unrealized foreign exchange, stock-based compensation expense and unrealized risk management activity). These financial measures are not defined by generally accepted accounting principles ( 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 the performance of the Company and of its business segments. The non-gaap measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with Canadian GAAP, as an indication of the Company's performance. Volumes shown are Company share before royalties unless otherwise stated. SPECIAL NOTES

41 HEDGING At November 4, 2010, the Company had the following net derivative financial instruments outstanding: Remaining term Volume Weighted average price Index Crude oil (1) Crude oil price collars (2) Oct 2010 Dec ,000 bbl/d US$60.00 US$75.08 WTI Oct 2010 Dec ,000 bbl/d US$65.00 US$ WTI Oct 2010 Dec ,000 bbl/d US$70.00 US$ WTI Jan 2011 Dec ,000 bbl/d US$70.00 US$ WTI Crude oil puts Jan 2011 Dec ,000 bbl/d US$70.00 WTI The net cost of outstanding put options and their respective periods of settlement is as follows: Q Q Q Q Cost ($ millions) US$26 US$27 US$27 US$26 Remaining term Volume Weighted average price Index Natural gas Natural gas price collars Oct 2010 Dec ,000 GJ/d C$6.00 C$8.00 AECO

42 KEY HISTORIC DATA Operational Information Daily production, before royalties Crude oil and NGLs (mbbl/d) Natural gas (mmcf/d) 1,388 1,439 1,492 1,668 1,495 1,315 Barrels of oil equivalent (mboe/d) Daily production, after royalties Crude oil and NGLs (mbbl/d) Natural gas (mmcf/d) 1,105 1,147 1,209 1,402 1,246 1,214 Barrels of oil equivalent (mboe/d) Proved reserves, after royalties Crude oil and NGLs (mmbbl) 1,066 1,118 1,316 1,358 1,346 1,377 Natural gas (bcf) 2,690 2,842 3,798 3,666 3,684 3,179 Barrels of oil equivalent (mmboe) 1,514 1,592 1,949 1,969 1,960 1,907 Mining reserves, SCO (mmbbl) 1,761 1,946 1,650 Drilling activity, net wells Crude oil and NGLs Natural gas Dry Strats and service Undeveloped land (thousands of acres) North America 11,523 10,947 12,785 12,160 11,603 10,651 North Sea Offshore West Africa Realized product pricing, before hedging activities & after transportation costs Crude oil and NGLs (C$/bbl) Natural gas (C$/mcf) Results of operations (C$ millions, except per share) Cash flow from operations 3,769 5,021 4,932 6,198 6,969 6,090 per share Net earnings 1,405 1,050 2,524 2,608 4,985 1,580 per share Capital expenditures (net, including combinations) 4,633 4,932 12,025 6,425 7,451 2,997 Balance Sheet Info (C$ millions) Property, plant and equipment 17,064 19,694 30,767 33,902 38,966 39,115 Total assets 18,372 21,852 33,160 36,114 42,650 41,024 Long-term debt 3,538 3,321 11,043 10,940 12,596 9,658 Shareholders equity 7,324 8,237 10,690 13,321 18,374 19,426 Ratios Debt to cash flow, trailing 12 months 1.0x 0.7x 2.2x 1.8x 1.9x 1.6x Debt to book capitalization 34% 29% 51% 45% 41% 33% Return to common equity, trailing 12 months 21% 14% 27% 22% 33% 8.4% Daily production before royalties per 10,000 common shares Proved and probable reserves before royalties per common share* *2009 Horizon SCO included in Crude Oil and NGL s reserves Share information Common shares outstanding 1,072,722 1,072,696 1,075,806 1,079,458 1,081,982 1,084,654 Weighted average common shares 1,072,446 1,073,300 1,074,678 1,078,672 1,081,294 1,083,850 Dividend per share (C$) TSX trading info Average daily trading volume (thousands) 5,448 5,084 4,056 3,418 5,416 4,144 High (C$) Low (C$) Close (C$) Note: All per share data adjusted for 2004, 2005 and 2010 stock splits.

43 CORPORATE GUIDANCE November 4, 2010 Fourth Quarter Guidance Daily Production Volumes, (before royalties) Natural gas (mmcf/d) North America 1,220-1,240 1,217-1,222 North Sea Offshore West Africa ,248-1,273 1,242-1,250 Crude oil and NGLs (mbbl/d) North America North America Oil Sands Mining North Sea Offshore West Africa Capital Expenditures, (C$ millions) North America natural gas $ 700 North America crude oil and NGLs 1,970 North Sea 180 Offshore West Africa 250 Property acquisitions, dispositions and midstream 1,500 4,600 Horizon Oil Sands Project Phase 2/3 Tranche Phase 2/3 Engineering 72 Sustaining capital 128 Capitalized interest, reclamation and other costs 82 Horizon Oil Sands Project 574 Total Capital Expenditures $ 5,174 Average Annual Cost Data Royalty Rate Operating Cost Natural Gas - North America (mcf) 5-6% $ Crude oil and NGLs (bbl) North America 17-19% $ North America Oil Sands Mining* 4-5% $ North Sea - $ Offshore West Africa 6-8% $ *Royalties are payable on the bitumen production, royalty rate shown is imputed on SCO barrel. Other Information Cash income and other taxes (C$ millions) Sask. Resources Surcharge/Capital Tax $25-30 Current income taxes North America $ Current income taxes International $ Petroleum Revenue Tax (PRT) $60-80 Effective tax rate on adjusted earnings 26% - 28% Depletion, depreciation and ARO accretion charge ($/BOE) $ Midstream cash flow (C$ millions) $50-55 Average corporate interest rate 4.90% % Note: Interest rates are subject to change depending upon short term rate changes. Cash income taxes are subject to variation with commodity prices and the level and classification of capital expenditures. Cash PRT is subject to variation due to commodity price and capital spending forecast based on an average annual WTI of $78.83/bbl, NYMEX of US$4.45/mmbtu and an exchange rate of US$0.97 to C$1.00. This document contains forward-looking statements under applicable securities laws, including, in particular, statements about Canadian Naturals plans, strategies and prospects. Although the Company believes that the expectations reflected in these forward-looking statements are reasonable, such statements are subject to known or unknown risks and uncertainties that may cause actual results to differ materially from those anticipated. Please refer to the Company s Interim Report or Annual Information Form for a full description of these risks and impacts.

44 Douglas A. Proll Chief Financial Officer & Senior Vice-President, Finance Corey B. Bieber Vice-President, Finance & Investor Relations (403) Allan P. Markin Chairman John G. Langille Vice-Chairman Steve W. Laut President Tim S. McKay Chief Operating Officer CANADIAN NATURAL RESOURCES LIMITED 2500, 855-2nd Street S.W., Calgary, Alberta, T2P 4J8 Telephone: (403) Facsimile: (403) Mark Stainthorpe Investor Relations (403) Leah Loyola Analyst, Investor Relations (403) THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT