THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT. Corporate Presentation

THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT Corporate Presentation April 2011

DELIVERING VALUE AND GROWTH SNAPSHOT 2010 2011F (3) Cash flow (1) (C$ millions) $6,321 $7,000 - $7,400 Per share basic (1) (C$) $5.81 $6.40 - $6.80 Capital expenditures (2) (C$ millions) $5,506 $6,155 - $6,555 Dividend (C$/share) $0.30 Common shares (thousands) 1,090,848 Production (annual average, before royalties) Oil (Mbbl/d) 425 385-427 Natural gas (MMcf/d) 1,243 1,177-1,246 BOE (MBOE/d) 632 581-635 Company Gross Reserves of crude oil and natural gas (as at December 31, 2010) Proved crude oil and NGLs (MMbbl) 3,795 Proved natural gas (Bcf) 4,262 Proved BOE (MMBOE) 4,505 Proved and probable BOE (MMBOE) 6,903 (1) Based upon the following average strip pricing as at February 18, 2011, including the impact of hedging. 2010 2011F Oil WTI (US$/bbl) $79.55 $101.38 Natural gas NYMEX (US$/MMbtu) $4.42 $4.15 Heavy oil diff (US$/bbl) $14.26 $22.64 C$/US$ $0.97 $1.02 (2) Including acquisitions. (3) Subject to the final impact of the January 2011 Horizon incident. Note: All per share data in this presentation adjusted for 2004, 2005 and 2010 stock splits.

Who is Canadian Natural? Canadian based E&P company with international exposure ~US$60 billion enterprise value 632 MBOE/d 2010 67% crude oil weighted ~581-635 MBOE/d 2011F (1) 67% crude oil weighted Returns focused Major oil sands player Major in-situ producer with several projects in inventory Major mining project currently ramping production Production Mix (Q4/10) North America 90% North Sea 5% Offshore West Africa 5% (1) Subject to the final impact of the January 2011 Horizon incident. 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 Production / Proved Reserves History (before royalties) Proved Reserves (MMBOE) 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11* Forecast 700 600 500 400 300 200 100 0 Daily Production (MBOE/d) *Subject to the final impact of the January 2011 Horizon incident. Note: 2009 and 2010 includes Horizon SCO reserves. Reserves prior to 2010 were calculated using constant prices and 2010 calculation based on escalating prices due to a change in disclosure requirements. Production Reserves The Premium Value, Defined Growth Independent 3 1

Why Invest in Canadian Natural s Future Strong, low-risk asset base Includes world class oil sands in-situ and mining developments One of the largest producers of heavy crude oil in western Canada Largest net unproved 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 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$ million) 2,400 2,200 2,000 1,800 1,600 1,400 1,200 1,000 800 $2,263 600 400 200 $245 $227 $172 $171 $76 $44 $36 $25 $11 0 EOG DVN PXD A PA APC CVE NXY ECA TLM Note: Peers based on share ownership data excluding options and priced at March 18, 2011. Source: SEDI and Thomson Financial. Consistent History of Value Creation 5 2

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 6 Natural Gas Operating Cost Peer Comparison ($/Mcf) $3.00 $2.50 Peer Average $2.00 $1.50 $1.00 $0.50 $0.00 Q1/06 Q2/06 Q3/06 Q4/06 Note: Other Producers - NXY, HSE, TLM, CVE, ECA, ARC, PWT, PGF.UN. Source: Corporate reports. Efficient and Effective Operations Peer Group Q1/07 Q2/07 Q3/07 Q4/07 Q1/08 Q2/08 Q3/08 Q4/08 Q1/09 Canadian Natural Q2/09 Q3/09 Q4/09 Q1/10 Q2/10 Q3/10 Q4/10 7 3

Heavy Oil Operating Cost Peer Comparison ($/bbl) $20.00 $15.00 Peer Average Peer Group $10.00 $5.00 $0.00 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 Q3/10 Q4/10 Canadian Natural Note: Other Producers NXY, HSE, BTE, BNP.UN, CVE and heavy oil operations not including thermal operating costs. Source: Corporate reports. Efficient and Effective Operations 8 Essential Elements to Our Defined Plan Natural Gas NA Oil International 1-2 years 3-5 years Beyond Optimize Potential for >8,000 potential returns 3-5% CAGR drilling locations Pelican / Primary Potential for >20 years of Primrose 5-7% CAGR development Free cash flow High return Potential area for projects growth (acq) Horizon Stabilize production Expansion and 16 billion barrels Re-profile expansions debottlenecking of bitumen initially in place A Growing, Returns - Focused E&P Creating Significant Value 9 4

North America Natural Gas Assets Leverage our dominant infrastructure and land base Maintain our position as most efficient producer Continue to strengthen our unconventional / tight gas asset base Continue to delineate new / emerging plays / technology Stay prepared for strengthening of natural gas prices Opportunistic acquisitions 2,000 1,600 1,200 800 400 0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 NE BC 313 MMcf/d NW AB 478 MMcf/d Southern Plains 145 MMcf/d Northern Plains 284 MMcf/d SE SK 3 MMcf/d Note: Reflects Q4/10 actual production, before royalties. Disciplined Development of Strong Gas Assets 10 North America Natural Gas Core Area Summaries North and South Plains Conventional exploitation Shallow gas and HSC CBM resource projects Low risk, efficient operations, highly profitable Foothills High impact exploration NE British Columbia Unconventional - Muskwa and Montney Economical entry costs 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 11 5

North America Natural Gas 2011 Plan 2010 2011F % Change Production (MMcf/d) 1,217 1,150-1,210 (3%) Drilling (net wells) 98 72 (27%) Capital ($ million) Turnaround / Maintenance $106 $120 13% Land / Seismic $56 $65 16% Drill, Complete, Tie-in $535 $415 (22%) Total $697 $600 (14%) 12 Canadian Light Oil 2011 Plan 2010 2011F % Change Production* (Mbbl/d) 50 54-58 12% Drilling (net wells) 117 138 18% Capital ($ million) Drilling, completions and tie-ins 142 290 104% Technology, EOR 147 170 16% Total 289 460 59% Target modest production growth of 2%-10% per year in 2012 and beyond *Includes NGLs. 13 6

Heavy Oil Assets Horizon mining operation 93,000 bbl/d Company gross proved plus probable SCO reserves 2.9 billion barrels (1) Best estimate contingent resources other than reserves 3.0 billion barrels of bitumen (1) ~500,000 bbl/d total capability Thermal in-situ development 104,000 bbl/d Massive resource potential Staged value growth ~325,000 bbl/d of additional production capacity Pelican Lake EOR development 38,000 bbl/d 4.1 billion barrels OOIP (2) Largest polymer flood in North America 3.5x increase in expected recovery Reliable primary production 93,000 bbl/d Dominant land base Record 654 wells in 2010 (1) Subject volumes are gross lease. (2) Original Oil in Place. 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 (104 Mbbl/d) Note: Reflects Q4/10 actual working interest production. 14 Primary Heavy Oil 2011 Plan 2010 2011F % Growth Production (Mbbl/d) 93 101-105 11% Drilling (net wells) 654 790 21% Recompletion (net wells) 468 465 - Capital ($ million) 645 820 27% Target production growth of roughly 10% per year for the next three years Strong Cash on Cash Returns 15 7

Pelican Lake Oil Pool World class oil pool Polymer flood successful both technically and economically Technology enhancement will continue to improve oil recovery (bbl/d) 100,000 80,000 60,000 40,000 20,000 *Original Oil in Place. **Best estimate contingent resources other than reserves. Primary Convert waterfloods to polymer Waterflood OOIP* 4.1 billion barrels Developed Region Polymer flood 0 1995 2001 2007 2013 2019 Primary Waterflood Polymerflood How much of that oil is producible? Resources** 198 MMbbl Probable Reserves 104 MMbbl Proved Reserves 234 MMbbl Produced to Date 153 MMbbl 17% Massive Resource to Exploit 16 Pelican Lake Plan 2010 2011F % Growth Production (Mbbl/d) 38 43-47 18% Drilling (horizontal net wells) Producers 62 11 (83%) Injectors 65 82 26% Capital ($ million) 473 615 30% Significant pre-investment for future polymer volumes Polymer response in 18 24 months from injection Production target ranges 2012 50,000-60,000 bbl/d 2013 75,000-80,000 bbl/d 2014 78,000-82,000 bbl/d 17 8

Thermal Heavy Oil Sands Potential McMurray 23.5 billion barrels Kirby Grouse Leismer Birch Mountain Gregoire Clearwater 11 billion barrels Resources* 4.7 billion bbl Probable Reserves 0.8 billion bbl Proved Reserves 0.9 billion bbl Produced to Date 0.3 billion bbl Estimated Bitumen Initially in Place 34.5 billion barrels total *Best estimate contingent resources other than reserves. 18 Thermal Heavy Oil Sands 2011 Plan 2010 2011F % Change Production (Mbbl/d) 90 97-105 12% Drilling (net wells) Producers 17 201 - Kirby SAGD pairs 0 16 - Strats / Observations wells 194 359 85% Service 13 16 23% Total 224 592 164% Capital ($ million) 544 1,345 147% Thermal targeted production ranges 2012 105,000-115,000 bbl/d 2013 125,000-130,000 bbl/d 2014 150,000-160,000 bbl/d 19 9

Thermal Heavy Oil Sands Land Holdings McMurray exposure Birch Mountain Gregoire Kirby Grouse Germain Leismer Ipiatik Clearwater exposure Primrose Wolf Lake Hilda Lake Marie Lake Grand Rapids exposure Carbonates exposure Grande Prairie Oil Sands Deposits Edmonton Calgary Fort McMurray Scale 1:1,730,000 Great Assets, Huge Land Base 20 Thermal Heavy Oil Sands Growth Plan Oil Facility Target Steam-In Phase Reservoir Capacity Target Timing (bbl/d) (year) Primrose South/North - CSS Clearwater 80,000 On Stream Primrose East - CSS Clearwater 40,000 On Stream Kirby Phase 1- SAGD McMurray 40,000 2013 Kirby Phase 2- SAGD McMurray 30,000-60,000 2016 Grouse - SAGD McMurray 60,000 2018 Birch Mountain Phase 1 - SAGD McMurray 60,000 2020 Birch Mountain Phase 2 - SAGD McMurray 60,000 2022 Gregoire Ph 1 - SAGD McMurray 60,000 2024 445,000 bbl/d of oil facility capacity in the defined growth plan 30,000-60,000 bbl/d addition every 2-3 years Growth for Decades 21 10

Thermal Heavy Oil Sands Kirby Kirby will be developed through two phases plus debottleneck potential Steam-In (million barrels) BIIP* Reserves Resources** Date Kirby Phase 1 365 2013 Proved 140 Probable 45 Kirby Phase 2 726 78 2016 Proved 109 Probable 163 Kirby Phase 1 - Debottleneck 434 170 2024 Kirby Phase 1 sanctioned November 2010 Peak production - 40,000 bbl/d *Bitumen Initially in Place. **Best estimate contingent resources other than reserves. 22 Thermal Heavy Oil Sands Kirby Land Holdings Acquired lands creates overall operating and capital cost synergies Similar to Primrose development Kirby Phase 2 regulatory application 2011 Kirby North Kirby Phase 2 Kirby North Plant (Remote Steam) Kirby Phase 1 Kirby Central Kirby South Plant (Steam & Oil Treating) Oilsands Acquisition Kirby South 23 11

Heavy Oil Three Pronged Marketing Plan Conversion capacity Pipelines Blending Cumulative Incremental Volume Alberta Clipper (complete) Keystone (Patoka complete and to Cushing Q1/11) DilSynbit WCS (Western Canadian Select) Synbit Additional refinery conversion capacity Refining: cokers / hydrocrackers Upgrading: bitumen / heavy oil Keystone XL (USGC Q1/13) Total blend is 312 Mbbl/d 58% for Q4/10 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 24 Redwater Upgrading and Refining Fits Canadian Natural s strategy to support additional heavy oil conversion capacity On Feb 16, 2011 NWU and Canadian Natural have formed a 50/50 partnership to construct and operate a new bitumen refinery near Redwater, AB Proposed bitumen refinery would convert 50 Mbbl/d of raw bitumen into useable products and provide an integrated CO 2 capture and management solution The technology selected and the process configuration make this plant the most advanced of its kind in the world Canadian Natural has committed 12.5 Mbbl/d to phase 1 of the project Potential synergies with s overall marketing strategy Strong Strategic Fit 25 12

International Overall Strategy Maintain our existing operations Convert undeveloped potential to production As platform slots become available North Sea Ninian Tiffany Murchison Offshore West Africa Espoir Baobab Progress near pool development in Côte d Ivoire Progress Big E exploration in South Africa Monitor acquisition opportunities Generate significant free cash flow Leverage Expertise 26 International 2011 Plan North Sea 2010 2011F % Change Crude oil production (Mbbl/d) 33 27-32 (11%) Capital ($ million) $149 $370 148% Offshore West Africa Crude oil production (Mbbl/d) 30 20-25 (25%) Capital ($ million) $246 $135 (45%) North Sea 10 workovers 2.3 net wells drilled Facility improvements Lyell subsea pump, manifold upgrades Turnaround on 4 platforms Lower volumes due to turnarounds and fixed cost nature result in higher operating costs in 2011 Offshore West Africa Olowi development complete Prepare for Espoir and Baobab infill programs Progress South Africa Big E exploration 27 13

Horizon Oil Sands Mining resources 14.3 billion barrels BIIP* Company gross proved plus probable SCO reserves 2.9 billion barrels Best estimate contingent resources other than reserves 3.0 billion barrels of bitumen 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 *Bitumen Initially in Place. Note: Volumes are gross lease. World Class Opportunity 28 Horizon Oil Sands Future Expansion Lessons learned complete Execution strategy framework complete Build to produce 34º API SCO - upgrade Cost estimate progressing 29 14

Horizon Oil Sands Future Expansion Reliability - OPP 3, Hydrotransport, Sulfur Unit 3 (Tranche 2) - 5,000 bbl/d SCO capacity increase in 2011/12 Directive 74 Phase 2A Phase 2B Phase 3 - Equipment and tailings process required to meet new ERCB regulations - Upgrading debottlenecking and coker expansion - 10,000 bbl/d SCO capacity increase in 2013/14 - OPP 4, Froth Treatment, Vacuum Distillations, Gas/Oil Hydrotreater - 45,000 bbl/d SCO capacity increase - OPP 5, Extraction 3&4, Combined Hydrotreater, Sulfur recovery - 80,000 bbl/d SCO capacity increase 30 Horizon Oil Sands Expansion up to 250,000 bbl/d 34º API SCO Execution strategy Debottlenecking and expansion to be combined Expansion will be broken into 46 individual projects Stop and start at discretion Each project (46) will be broken into Engineering & Procurement (E&P) and Construction (C) Construction will only be awarded when E&P is at required levels and market can absorb more construction Engineering will be extended past the 80/20 rule used in Phase 1 Lump sum E&P or C will be used when possible Highly unlikely to use lump sum EPC Construction labor force to be capped at 5,500 Phase 1 peak 10,000 Yearly capital exposure capped at $2.0 billion - $2.5 billion 31 15

Horizon Oil Sands Tranche 2 Reliability Purpose: Increase reliability and lower operating costs Ore Preparation Plant 3 on stream Q4/11 Hydro transport on stream Q4/11 Tank expansion on stream Q1/11 Upgrading Sulfur Unit 3 on stream Q4/13 Gas recovery on stream Q2/14 Butane treating on stream Q2/14 On schedule, trending below cost estimate $830 million target versus $925 million original estimate (10% reduction) Reliability projects will add 5,000 bbl/d SCO capacity 32 Horizon Oil Sands 2011 Plan 2010 2011F (2) % Change Production (Mbbl/d) 91 43-55 (46%) Operating costs ($/bbl) $36.36 Sustaining capital (1) ($ million) $130 $220 69% Project capital ($ million) Reliability - Tranche 2 $279 $370 Directive 74 and Technology $10 $130 Phase 2A $25 $200-230 Phase 2B $5 $10-295 Phase 3 $0 $90-150 Phase 4 $0 $0-25 Total $319 $800-1,200 (1) Includes reclamation capital. (2) Subject to the final impact of the January 2011 Horizon incident. 33 16

Canadian Natural 2011 Budget Production Production 2010 2011F % Change Crude oil (Mbbl/d) Canada Light and NGLs 50 54-58 12% Pelican Lake 38 43-47 18% Heavy 93 101-105 11% Thermal 90 97-105 12% International 63 47-57 (17%) Horizon (1) 91 43-55 (46%) Total (1) 425 385-427 (4%) Natural gas (MMcf/d) 1,243 1,177-1,246 (3%) BOE/D (1) 632 581-635 (4%) (1) Subject to the final impact of the January 2011 Horizon incident. Note: Numbers may not add due to rounding. 34 Canadian Natural 2011 Budget Capital Capital ($ million) 2010 2011F % Change Natural gas 697 600 (14%) Crude oil Pelican Lake 473 615 30% Heavy 645 820 27% Thermal 544 1,345 147% Light Canada 289 460 59% North Sea 149 370 148% Offshore West Africa 246 135 (45%) Total crude oil 2,346 3,745 60% Horizon (1) Sustaining and reclamation 128 220 72% Capital Projects 319 800-1,200 151-276% Other 88 100 14% Total Horizon (1) 535 1,120-1,520 109-184% Acquisition and Midstream 1,928 350 - Redwater Upgrader and Refining - 340 - Total (1) 5,506 6,155-6,555 12-19% (1) Subject to the final impact of the January 2011 Horizon incident. 35 17

Canadian Natural Free Cash Flow Uses 1) Opportunistic acquisitions 2) Pre invest in long term developments EOR Strat wells Strategic play development 3) Dividends Eleven consecutive years of dividend increases Must be sustainable 4) Pay down debt 5) Share buybacks Target to eliminate dilution Prudent Use of Free Cash Flow 36 Canadian Natural Advantage Management, business philosophy, practice Strong, balanced assets Vast opportunities Leveraging Technology 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 Efficient operations The Premium Value, Defined Growth Independent 37 18

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. 38 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 For the year ended December 31, 2010 the Company retained Independent Qualified Reserves Evaluators ( Evaluators ), Sproule Associates Limited and Sproule International Limited (together as Sproule ) and GLJ Petroleum Consultants Ltd. ( GLJ ), to evaluate and review all of the Company s proved and proved plus probable reserves with an effective date of December 31, 2010 and a preparation date of February 14, 2011. Sproule evaluated the North America and International crude oil, NGL and natural gas reserves. GLJ evaluated the Horizon SCO reserves. The evaluation and review was conducted in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ( COGE Handbook ) and disclosed in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ( NI 51-101 ) requirements. In previous years, Canadian Natural had been granted an exemption order from the securities regulators in Canada that allowed substitution of U.S. Securities Exchange Commission ( SEC ) requirements for certain NI 51-101 reserves disclosures. This exemption expired on December 31, 2010. As a result, the 2010 reserves disclosure is presented in accordance with Canadian reporting requirements using forecast prices and escalated costs. The recovery and reserves estimates of crude oil, NGL and natural gas reserves provided in this presentation are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided. Reserves estimates provided in this presentation are company gross, before royalties. Resources Other Than Reserves The contingent resources other than reserves ( resources ) estimates provided in this presentation are internally evaluated by qualified reserves evaluators in accordance with the COGE Handbook as directed by NI 51-101. No independent third party evaluation or audit was completed. Resources provided are best estimates as of December 31, 2010. The resources are evaluated using deterministic methods which represent the expected outcome with no optimism or conservatism. Resources, as per the COGE Handbook 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 be recovered and are provided for illustrative purposes only. Petroleum, bitumen or natural gas 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. 39 19

Appendices 40 Annualized Sensitivity to Prices Annualized and based upon Q4/10 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 ~$128 million ~$38 million ~$175 million ~$9 million ~$102 million *Includes financial derivatives. Significant Upside from Conservative Budget Price Deck 41 20

International North Sea Exploitation base similar to WCSB Operate ~99% and own ~80% of production Infill drilling / recompletions & waterflood optimization 2 drill strings operating in 2011 2.4 net wells drilled in North Sea 1.6 net crude oil wells 0.8 net injector wells Complete turnaround on four platforms 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 42 International Offshore Côte d Ivoire East Espoir First oil achieved in 2002 4 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 2011 Prepare for Espoir and Baobab infill programs Area for Light Oil Growth Côte d Ivoire Panthere Atlantic Ocean Foxtrot West Espoir Mantra East Espoir Baobab Jacqueville Lands Oil Field Gas Field Prospects Acajou Acajou Kossipo 43 21

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 2011 production of 5,000-6,000 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 44 International South Africa - Big E Potential Existing production CNRI Block 11B/12B 1000m water depth Paddavissie Fairway 100km Large structures Challenging ocean conditions *Original Oil in Place. Best Estimate Undiscovered OOIP* of 3 Billion Barrels 45 22

Canadian Light Oil Mature basin Large land holdings across basin Optimize existing water floods to maximize value New pool exploration New technology application Horizontal wells Multistage fracs Tertiary recovery CO 2 ASP (bbl/d) 120,000 100,000 80,000 60,000 40,000 20,000 0 1954 Gross Operated Light Oil Production 1 billion barrels recovered since 1974 peak 1959 1964 1969 1974 1979 1984 1989 1994 1999 2004 2009 Value Creation in Mature Basin 46 Technology Leverage / Implementation Capital ($ million) 2010 2011F Light Oil $142 $170 Primary Heavy Oil $20 $30 Thermal $20 $30 Pelican Lake $10 $10 Natural Gas $40 $65 Total $232 $305 47 23

Strategic Development Septimus Montney Play Large resource Discovered gas in place of 7.3 Tcf Proved reserves of 182 Bcf Probable reserves of 47 Bcf Liquids rich gas with 30 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 SEPTIMUS ~45 miles ECA SWAN ARC DAWSON *Based on Q1/10 actual plus current 2010 strip at WTI US$86.98/bbl, AECO C$4.10/GJ. Well Positioned Montney Asset 48 Natural Gas Outlook Shale gas production is real Shale gas reserves look real Shale gas full cycle returns at $4.00 AECO not certain Sweet spots yes Liquids rich yes to maybe Overall too early to tell LNG supply threat still exists Anticipate North America natural gas market to be over supplied for 2-7 years Being the most efficient producer is paramount 49 24

Natural Gas Future Growth Potential (MMcf/d) 1,600 1,400 5% Growth Potential $6 plus 1,200 1,000 No Growth $4-$5 Upside Potential Option 800 600 12% Proactive Decline Sub $4 400 200 Disciplined Allocation of Capital 0 2010F 2011 2012 2013 2014 Natural Gas Production Forecast $6.00 plus Natural Gas Sub $4.00 Natural Gas $4.00-$5.00 Natural Gas Focus on Creating Value 50 Heavy Oil Differentials (% of WTI) 60% 50% 40% Logistical Constraints WCS Pipeline Issues in PADD II 30% 20% 10% Maya 0% 0 2005 2006 2007 2008 2009 2010 2011 WCS at Hardisty Maya at USGC Q4 to Q1 Q2 to Q3 Source: Bloomberg, PLATTS. Differential Impacted by Logistical Constraints and Refining Margins 51 25

Expanding Pipeline Options ENB Gateway 400 Mbbl/d Crude Export Line Kitimat TMX Staged Expansion 525 Mbbl/d Vancouver Fort McMurray Edmonton Hardisty ENB Alberta Clipper 450 Mbbl/d started Oct 2010 Southern Lights 180 Mbbl/d started Jul 2010 Superior TCPL Keystone to Patoka 435 Mbbl/d Kinder Morgan 300 Mbbl/d TCPL Keystone XL Pipeline 700 Mbbl/d in Q1/13 TCPL Keystone to Cushing 155 Mbbl/d in Q1/11 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 52 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; awaiting US Presidential Permit Expandable to 1.5 MMbbl/d Q1/13 Jun 2010 Q1/11 Pipeline Access to New Markets is Available 53 26

Heavy Oil Primary Robust economics Typical vertical / slant well costs $500,000 Typical well produces 40-50 bbl/d Wells payout in less than 1 year Recycle ratio greater than 3x 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) 140,000 120,000 100,000 80,000 60,000 40,000 20,000 0 Gross Operated Heavy Oil Production 1965 1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009 A Proven Success 54 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 55 27

Pelican Lake Polymer Flood Response Initial Pilot Well Oil Production (bbl/d) 400 350 300 250 200 150 100 50 0 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-10 56 Pelican Lake Polymer Flood Expansion Polymer flood at end of 2009 30% 2010 Polymer Plan 44% 5 Year Polymer Plan 88% Land Polymer Success Leads to Expansion 57 28

Pelican Lake 2011 Plan Technology Success Story Long reach horizontal wells Leading edge polymer flood Staged conversion to polymer flood - % of field polymer flooded 2009 25% 2010 44% 2011 54% 2012 61% 2013 71% Facility expansions for polymer and other developments 2010 44,500 bbl/d to 52,500 bbl/d 2011 52,500 bbl/d to 68,500 bbl/d 2012 68,500 bbl/d to 106,500 bbl/d to accommodate other properties Polymer flood optimization Still on steep part of learning curve Performance Operating costs 58 Thermal Oil Sands Primrose CSS Continued Growth Primrose Production (bbl/d) 140,000 Actual Forecast 120,000 100,000 80,000 60,000 40,000 20,000 0 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Wolf Lake Primrose South Primrose North Primrose East Growing Primrose to 120,000 bbl/d 59 29

Thermal Heavy Oil Sands Primrose Plan Significant pad adds to fully develop Optimize steaming techniques Potential future facility debottleneck / expansion Wolf Lake; McMurray / Grand Rapids development Follow up process In-fill drilling, steam flood, solvents Leverage technology Industry learning curve still steep 60 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 61 30

Thermal Oil Sands Water Management Water Volume (bbl/d) 600,000 500,000 Historical Bitumen Production (bbl/d) 140,000 Forecast 120,000 400,000 100,000 300,000 Bitumen Production Produced Water 80,000 60,000 200,000 100,000 0 1995 1996 Fresh Water 1997 1998 1999 2000 2001 2002 2003 2004 2005 Recycle >98% Prod Water and Significant Efforts to Reduce Fresh Water 2006 2007 2008 2009 2010 2011 2012 2013 2014 Brackish Water 2015 2016 40,000 20,000 0 62 Thermal Heavy Oil Sands Projects Update Primrose field development Kirby hub Kirby Phase 1, Kirby Phase 2, debottleneck Kirby Phase 2 regulatory application 2011/12 Grouse Stratigraphic well delineation Regulatory application 2011/12 Birch Mountain East Stratigraphic well delineation Regulatory application 2011/12 Gregoire Work existing data Germain Initiate strat program 63 31

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 64 Technology Option Thermal Geo-steering Well Placement Primrose North Steam Plant Bitumen burner tip Capturing More of the Reservoir With Technology Advancement 65 32

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 66 Horizon Oil Sands Process and Technology Only Proven Technologies Will be Utilized Reducing Technology Risks 67 33

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 68 Horizon Operating Costs Operating cost was $39.89/bbl SCO in 2009 Operating costs for 2010/11 (1) 2010 operating cost was $36.36/bbl (including approximately $3.78 per barrel of natural gas input costs) 2011 previously targeted range of $30.00/bbl to $36.00/bbl (1) Q4/10 operating cost was $33.13 (including approximately $3.04 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 (1) Subject to the final impact of the January 2011 Horizon incident. Horizon Will Be The Low Cost Producer 69 34

Horizon Oil Sands Next Steps 1. Complete more detailed cost estimate Q1/11 2. Kick off E&P work in Q1/11 for Directive 74 2 of 2 projects Phase 2A 4 of 5 projects Phase 3 3 of 14 projects 3. If market conditions are favorable and economics meet threshold criteria Q1 Kick off construction on Directive 74 1 of 2 projects Phase 2A 1 of 5 projects Phase 3 2 of 14 projects Q3 Kick off detailed engineering and procurement Phase 2A Last 1 of 5 projects Phase 2B 19 of 25 projects Phase 3 2 of 14 projects Q3 Kick off construction on Phase 2B 1 of 25 projects 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) $ 23 Demand Total bank lines $ 3,953 Available Dec 31, 2010 $ 2,444 Solid Lines of Liquidity 71 35

Maturity Schedule Public Debt (C$ million) 1,400 1,200 1,000 800 600 400 200 0 2011 2014 2017 2020 2023 2026 2029 2032 2037 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 72 2011 Natural Gas Hedging AECO (C$/GJ) $5 $4 $3 $2 $1 100% 80% 60% 40% 20% 0% Strip 100% - Market 100% - Market 100% - Market 100% - Market Q1/11 Q2/11 Q3/11 Q4/11 Collars Market Note: Refer to quarterly reports for detailed hedging positions. Strip pricing as at Mar 03, 2011. 73 36

2011 Crude Oil Hedging WTI (US$/bbl) $120 $110 $100 $90 $80 $70 $60 $50 100% 80% 60% 40% 20% 0% ~59% - Market ~62% - Market ~27% $70.00 Puts ~14% $70.00 - $102.23 Strip Floor Ceiling Puts ~25% $70.00 Puts ~13% $70.00 - $102.23 ~64% - Market ~24% $70.00 Puts ~12% $70.00 - $102.23 ~67% - Market ~22% $70.00 Puts ~11% $70.00 - $102.23 Q1/11 Q2/11 Q3/11 Q4/11 Collars Puts Market Note: Refer to quarterly reports for detailed hedging positions. Strip pricing as at Mar 03, 2011. Upside Opportunity, Downside Protection 74 Resource Disclosure (1) 1. Bitumen (Thermal Oil) Discovered Bitumen Initially-in-place Proved Company Gross Reserves Probable Company Gross Reserves Best Estimate Contingent Resources other than Reserves Bitumen Produced to Date Unrecoverable portion of Discovered Bitumen Initially-in-place (2) 34.5 billion barrels 0.9 billion barrels of Bitumen 0.8 billion barrels of Bitumen 4.7 billion barrels of Bitumen 0.3 billion barrels 27.8 billion barrels 2. Pelican Lake Heavy Crude Oil Pool Discovered Heavy Crude Oil Initially-in-place Proved Company Gross Reserves Probable Company Gross Reserves Best Estimate Contingent Resources other than Reserves Heavy Crude Oil Produced to Date Unrecoverable portion of Discovered Heavy Crude Oil Initially-in-place (2) 4,100 million barrels 234 million barrels of heavy crude oil 104 million barrels of heavy crude oil 198 million barrels of heavy crude oil 153 million barrels 3,411 million barrels 3. Horizon Oil Sands Synthetic Crude Oil Discovered Bitumen Initially-in-place Proved Company Gross Reserves - 1.9 billion barrels of SCO Bitumen volume associated with Proved SCO reserves Probable Company Gross Reserves - 1.0 billion barrels of SCO Bitumen volume associated with Probable SCO reserves Best Estimate Contingent Resources other than Reserves Bitumen Produced to Date Unrecoverable portion of Discovered Bitumen Initially-in-place (2) 14.3 billion barrels 2.3 billion barrels of Bitumen 1.1 billion barrels of Bitumen 3.0 billion barrels of Bitumen 0.1 billion barrels of Bitumen 7.8 billion barrels (1) All volumes are company gross. (2) A portion may be recoverable with the development of new technology. 75 37

SPECIAL NOTES 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 For the year ended December 31, 2010 the Company retained Independent Qualified Reserves Evaluators ( Evaluators ), Sproule Associates Limited and Sproule International Limited (together as Sproule ) and GLJ Petroleum Consultants Ltd. ( GLJ ), to evaluate and review all of the Company s proved and proved plus probable reserves with an effective date of December 31, 2010 and a preparation date of February 14, 2011. Sproule evaluated the North America and International crude oil, NGL and natural gas reserves. GLJ evaluated the Horizon SCO reserves. The evaluation and review was conducted in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ( COGE Handbook ) and disclosed in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ( NI 51-101 ) requirements. In previous years, Canadian Natural had been granted an exemption order from the securities regulators in Canada that allowed substitution of U.S. Securities Exchange Commission ( SEC ) requirements for certain NI 51-101 reserves disclosures. This exemption expired on December 31, 2010. As a result, the 2010 reserves disclosure is presented in accordance with Canadian reporting requirements using forecast prices and escalated costs. The recovery and reserves estimates of crude oil, NGL and natural gas reserves provided in this presentation are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided. Reserves estimates provided in this presentation are company gross, before royalties. Resources Other Than Reserves The contingent resources other than reserves ( resources ) estimates provided in this presentation are internally evaluated by qualified reserves evaluators in accordance with the COGE Handbook as directed by NI 51-101. No independent third party evaluation or audit was completed. Resources provided are best estimates as of December 31, 2010. The resources are evaluated using deterministic methods which represent the expected outcome with no optimism or conservatism. Resources, as per the COGE Handbook 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 be recovered and are provided for illustrative purposes only. Petroleum, bitumen or natural gas 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 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.

HEDGING At March 3, 2011, the Company had the following net derivative financial instruments outstanding: Crude oil Remaining term Volume Weighted average price Index Crude oil price collars Jan 2011 Dec 2011 50,000 bbl/d US$70.00 US$102.23 WTI Crude oil puts Jan 2011 Dec 2011 100,000 bbl/d US$70.00 WTI The net cost of outstanding put options and their respective periods of settlement is as follows: Q1 2011 Q2 2011 Q3 2011 Q4 2011 Cost ($ millions) US$26 US$26 US$27 US$27

KEY HISTORIC DATA Operational Information 2005 2006 2007 2008 2009 2010 Daily production, before royalties Crude oil and NGLs (mbbl/d) 313 332 331 316 355 425 Natural gas (mmcf/d) 1,439 1,492 1,668 1,495 1,315 1,243 Barrels of oil equivalent (mboe/d) 553 581 609 565 575 632 Daily production, after royalties Crude oil and NGLs (mbbl/d) 283 301 293 276 318 369 Natural gas (mmcf/d) 1,147 1,209 1,402 1,246 1,214 1,193 Barrels of oil equivalent (mboe/d) 474 502 526 484 525 568 Proved reserves, after royalties (1) Crude oil and NGLs (mmbbl) 1,118 1,316 1,358 1,346 1,377 1,519 Natural gas (bcf) 2,842 3,798 3,666 3,684 3,179 3,792 Barrels of oil equivalent (mmboe) 1,592 1,949 1,969 1,960 1,907 2,151 Mining reserves, SCO (mmbbl) 1,761 1,946 1,650 1,597 Drilling activity, net wells Crude oil and NGLs 627 603 592 682 644 934 Natural gas 890 641 383 269 109 92 Dry 117 119 93 39 46 33 Strats and service 248 375 254 131 329 491 Realized product pricing, before hedging activities & after transportation costs Crude oil and NGLs (C$/bbl) 46.86 53.65 55.45 82.41 57.68 65.81 Natural gas (C$/mcf) 8.57 6.72 6.85 8.39 4.53 4.08 Results of operations (C$ millions, except per share) Cash flow from operations 5,021 4,932 6,198 6,969 6,090 6,321 per share 4.68 4.59 5.75 6.45 5.62 5.81 Net earnings 1,050 2,524 2,608 4,985 1,580 1,697 per share 0.98 2.35 2.42 4.61 1.46 1.56 Capital expenditures (net, including combinations) 4,932 12,025 6,425 7,451 2,997 5,506 Balance Sheet Info (C$ millions) Property, plant and equipment 19,694 30,767 33,902 38,966 39,115 40,472 Total assets 21,852 33,160 36,114 42,650 41,024 42,669 Long-term debt 3,321 11,043 10,940 12,596 9,658 8,499 Shareholders equity 8,237 10,690 13,321 18,374 19,426 20,985 Ratios Debt to cash flow, trailing 12 months 0.7x 2.2x 1.8x 1.9x 1.6x 1.3x Debt to book capitalization 29% 51% 45% 41% 33% 29% Return to common equity, trailing 12 months 14% 27% 22% 33% 8.4% 8% Daily production before royalties per 10,000 common shares 5.2 5.4 5.6 5.2 5.3 5.8 Proved and probable reserves before royalties per common share* 2.4 3.2 3.2 3.1 5.8 6.3 *2009 and 2010 Horizon SCO included in Crude Oil and NGLs reserves Share information Common shares outstanding 1,072,696 1,075,806 1,079,458 1,081,982 1,084,654 1,090,848 Weighted average common shares 1,073,300 1,074,678 1,078,672 1,081,294 1,083,850 1,088,096 Dividend per share (C$) 0.12 0.15 0.17 0.20 0.21 0.30 TSX trading info Average daily trading volume (thousands) 5,084 4,056 3,418 5,416 4,144 3,544 High (C$) 31.00 36.96 40.01 55.65 39.50 44.70 Low (C$) 12.14 12.14 26.23 17.10 17.93 32.91 Close (C$) 28.82 31.08 36.29 24.38 38.00 44.35 (1) Reserves prior to 2010 were calculated using constant prices and 2010 calculations were based on escalating prices due to a change in disclosure requirements. Note: All per share data adjusted for 2004, 2005 and 2010 stock splits.

CORPORATE GUIDANCE March 3, 2011 First Quarter 2011 2011 Guidance Daily Production Volumes, (before royalties) Natural gas (MMcf/d) North America 1,220-1,240 1,150-1,210 North Sea 7-9 7-10 Offshore West Africa 22-24 20-26 1,249-1,273 1,177-1,246 Crude oil and NGLs (Mbbl/d) North America 285-295 295-315 North America Oil Sands Mining 7 43-55 North Sea 32-35 27-32 Offshore West Africa 24-28 20-25 348-365 385-427 Capital Expenditures, (C$ millions) North America natural gas $ 600 North America crude oil and NGLs 1,895 North America thermal crude oil Primrose and Future 830 Kirby Phase 1 515 Redwater Upgrading and Refining 340 North Sea crude oil 370 Offshore West Africa crude oil 135 Property acquisitions, dispositions and midstream 350 5,035 Horizon Oil Sands Project Sustaining and reclamation capital 220 Project capital Reliability - Tranche 2 370 Directive 74 and Technology 130 Phase 2A 200-230 Phase 2B 10-295 Phase 3 90-150 Phase 4 0-25 Total Capital Projects 800-1,200 Capitalized interest and other 100 Total Horizon Project* 1,120-1,520 *Cost or insurance recoveries related to the Primary Upgrader fire are not included. Total Capital Expenditures $ 6,155-6,555 Average Annual Cost Data Royalty Rate Operating Cost Natural Gas - North America (Mcf) 4-6% $1.10-1.20 Crude oil and NGLs (bbl) North America (excluding Oil Sands Mining)* 16-20% $12.00-13.00 North Sea - $38.00-42.00 Offshore West Africa 13-15% $18.00-21.00 *Guidance regarding Horizon Oil Sands operating costs will be provided closer to onstream production. Previously issued guidance for 2011 was $30.00 to $36.00 per barrel SCO. Other Information Cash income and other taxes (C$ millions) Sask. Resources Surcharge/Capital Tax $20-30 Current income taxes North America $350-450 Current income taxes International and Petroleum Revenue Tax (PRT) $280-320 Effective tax rate on adjusted earnings 26% - 30% Midstream cash flow (C$ millions) $45-55 Average corporate interest rate 5.25% - 5.75% 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. 2011 guidance based on an average annual WTI of $94.38/bbl, NYMEX of US$4.16/MMBtu and an exchange rate of US$1.01 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.

Douglas A. Proll Chief Financial Officer & Senior Vice-President, Finance Corey B. Bieber Vice-President, Finance & Investor Relations (403) 517-6878 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) 514-7777 Facsimile: (403) 514-7888 Email: ir@cnrl.com WWW.CNRL.COM Mark Stainthorpe Investor Relations (403) 514-7845 Leah Loyola Analyst, Investor Relations (403) 514-7911 THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT