THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT. Corporate Presentation

Transcription

1 THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT Corporate Presentation June 2010

2 DELIVERING VALUE AND GROWTH SNAPSHOT F Cash flow (C$ millions) $6,090 $6,800 - $7,200 (1) (1) Per share basic (C$) $5.62 $ $6.55 Capital expenditures (C$ millions) $2,997 $5,099 Dividend (C$/share) $0.21 Common shares (thousands) 1,084,654 Production (annual average, before royalties) Oil (mbbl/d) Natural gas (mmcf/d) 1,315 1,202-1,269 BOE (mboe/d) Reserves of crude oil and natural gas, net of royalties (as at December 31, 2009) Proved crude oil and NGLs (mmbbl) 3,027 Proved natural gas (bcf) 3,179 Proved BOE (mmboe) 3,557 Proved and probable BOE (mmboe) 5,440 (1) Based upon the following actual and strip pricing, including the impact of hedging F Oil WTI (US$/bbl) $61.93 $85.00 Natural gas NYMEX (US$/mmbtu) $4.03 $4.60 Heavy oil diff (US$/bbl) $9.64 $13.80 C$/US$ $0.88 $0.98 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$45 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 (Q1/10) North America 88% North Sea 6% 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) 800,000 Canadian Natural Production to Present 700, , , ,000 Significant Price Reduction 35% Oil Horizon Construction 47.5% Drop In Oil Forecast 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, $1,652 $374 $239 $223 $221 $132 $111 $49 $32 $30 DVN EOG APA APC PXD ECA NXY TLM CVE Note: Peers based on share ownership data excluding options and priced at March 5, Source: Thomson Reuters. 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 Note: Other Producers - NXY, HSE, TLM, ECA, ARC, PWT, PGF.UN. Source: Corporate reports. Canadian Natural 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 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 Overview of Today s Operations North America Crude Oil Natural & NGLs Gas BOE/d % of (mbbl/d) (mmcf/d) (6:1) Total 2010F Production - conventional (per day) ,175-1, Production - conventional (per day) 235 1, % 2009 Proved reserves - conventional (mmbbl/bcf) 1,014 3,027 1,519 43% 2010F Production - oil sands mining (bbl/d SCO) Production - oil sands mining (bbl/d SCO) % 2009 Proved SCO reserves (mmbbl) 1,650 46% NE BC 304 mmcf/d 5 mbbl/d NW AB 433 mmcf/d 15 mbbl/d Southern Plains 151 mmcf/d 11 mbbl/d Oil Sands Mining 87 mbbl/d Northern Plains 302 mmcf/d 213 mbbl/d SE SK 3 mmcf/d 8 mbbl/d North Sea Crude Oil Natural & NGLs Gas BOE % of (mbbl) (mmcf) (6:1) Total 2010F Production (per day) Production (per day) % 2009 Proved Reserves (mmbbl/bcf) % Offshore West Africa Crude Oil Natural % of & NGLs Gas BOE Total (mbbl) (mmcf) (6:1) 2010F Production (per day) Production (per day) % 2009 Proved Reserves (mmbbl/bcf) % Note: Production numbers reflect Q1/10 actual production, before royalties. Reserves are net of royalties. Canadian Targeted Asset Base with Selected International Exposure 11 5

8 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 12 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 304 mmcf/d NW AB 433 mmcf/d Southern Plains 151 mmcf/d Northern Plains 302 mmcf/d SE SK 3 mmcf/d Note: Reflects Q1/10 actual production, before royalties. Disciplined Development of Strong Gas Assets 13 6

9 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 14 North America 2010 Forecast Natural Gas Drilling Focus on drainage and expiries Development of Septimus (BC Montney) Strategic setup wells Capital $759 million Production ~1,205 mmcf/d midpoint average 6% annual decline 4% entry to exit growth 15 7

10 2010 Forecast North America Light Oil Drilling ~122 wells (38 wells in 2009) New play development 25 wells EOR / waterflood / CO 2 development Capital ~$375 million Production (excludes NGLs) ~34,000 bbl/d midpoint average 5% annual growth 20% entry to exit growth 16 Heavy Oil Assets Reliable conventional production Record ~600 wells Pelican Lake EOR development Proved reserves of 255 million barrels of oil equivalent Probable reserves of 108 million barrels of oil equivalent Contingent resources of 198 million barrels of oil equivalent Thermal in-situ development Significant resource potential in current plans ~285,000 bbl/d of additional in-situ production over next 15 years Canadian Natural has competitive advantage via its vast land base Technology Option Pelican Lake (37 mbbl/d) Conventional Heavy Oil (91 mbbl/d) Land Birch Mountain (W. Horizon) 300 miles Gregoire AB Kirby Primrose (76 mbbl/d) Note: Reflects Q1/10 actual working interest production. SK 17 8

11 2010 Forecast Primary Heavy Oil Drilling 2010 ~617 wells wells wells Recompletions wells Capital ~$625 million Production ~91,000 bbl/d midpoint average 6% annual growth 10% entry to exit growth Excellent return on capital in current environment 18 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 19 9

12 2010 Forecast Pelican Lake, Alberta 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 ~$510 million Production ~39,000 bbl/d midpoint average in % annual growth 15% entry to exit growth 20 Thermal Oil Sands Potential McMurray 22 billion barrels Kirby Grouse Leismer Birch Mountain Gregoire Jackfish 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 Estimated Bitumen in Place 33 billion barrels total 33 Billion Barrels of Bitumen in Place 21 10

13 2010 Forecast Thermal Heavy Crude Oil Drilling Strats 196 wells Production/steam 54 wells Capital ~$500 million Production ~87,000 bbl/d midpoint average 38% annual growth 22 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 - SAGD McM Low 45, 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 23 11

14 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 330 mbbl/d 52% commitments: 100 mbbl/d to USGC refiner West Coast options (Gateway, TMX) Texas Access USGC has committed 120 mbbl/d 12.5 mbbl/d to NWU-1 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 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 Currently ~3,500 bbl/d Successfully installed remaining 3 platforms First Oil delivered from Platform B April ,500 bbl/d Platform A production targeted for Q4/10 Focus on Free Cash Flow While Setting Up For Future Expansion 25 12

15 Canadian Natural s Mineable Assets - Horizon Oil Sands Mining resources 16 billion barrels of bitumen in place, with best estimate contingent resource of 6 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 World Class Opportunity 26 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 27 13

16 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 105,000 barrels SCO Q equivalent daily production was 86,995 barrels SCO Mid-April 2010 YTD equivalent daily production was >90,000 barrels SCO Continuing to ramp-up to design rates Ramp up to Reliable Production 28 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 29 14

17 Canadian Natural 2010 Production Guidance Daily Production Volumes (before royalties) F Change Natural Gas (mmcf/d) North American Natural Gas 1,287 1,175-1,235 (6%) North Sea % Offshore West Africa % Total 1,315 1,202-1,269 (6%) Crude Oil and NGLs (mbbl/d) North America - Conventional % North America - Oil Sands % North Sea (12%) Offshore West Africa (5%) Total % Production (mboe/d) % 30 Canadian Natural 2010 Capital Budget F Change Production (mboe/d) % Cashflow ($mm)* $6,090 $6,800 - $7,200 15% Capital ($mm) North America - Conventional $1,714 $2,761 61% North Sea $168 $233 39% Offshore West Africa $544 $260 (52%) Horizon $553 $785 42% Total Organic Capital $2,979 $4,039 36% Property Acquisitions $18 $1,060 Total $2,997 $5,099 70% Free cash flow ($mm)** $3,093 $1,700 - $2,100 *2010 based on WTI US$85.00 and NYMEX US$4.60. **Cash flow less Capital. 10% Production Growth While Spending Only 73% of Cash Flow 31 15

18 Canadian Natural Free Cash Flow 2010 (C$ billions) $6.0 Conventional $5.0 $4.0 $3.0 $2.0 % of Cash Flow 44% Horizon North Sea Offshore West Africa $1.0 $0.0 55% 47% 61% -$1.0 -$2.0 -$3.0 Cash Flow Capital Free Cash Flow Based on WTI US$85.00/bbl, AECO C$4.20/GJ. Excluding acquisitions and divestitures. All Divisions Generating Free Cash Flow 32 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 33 16

19 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 Low cost Execution focused The Premium Value, Defined Growth Independent 34 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 Q1/10 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 ~$112 million ~$31 million ~$161 million ~$13 million ~$102 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 progressing in 2010 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 Currently ~3,500 bbl/d Successfully installed remaining 3 platforms Drilling on Platform B First Oil delivered from Platform B April ,500 bbl/d Platform A production targeted in Q4/10 Target 2010 exit rate of ~14,000 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 Conventional 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% Logistical Constraints WCS 30% 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 Vancouver Fort McMurray Edmonton Hardisty ENB Alberta Clipper / Southern Lights 450 mbbl/d in Q4/2010 / 180 mbbl/d in July 2010 Superior TCPL Keystone to Patoka 435 mbbl/d in June 2010 Kinder Morgan 300 mbbl/d TCPL Keystone XL Pipeline 700 mbbl/d in Q4/2012 Casper Chicago TCPL Keystone to Cushing 155 mbbl/d in Q4/2010 Existing Near Completion Long Term Potential Proposed Steele City Denver Cushing USGC Wood River 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 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 52 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 53 26

29 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 54 Thermal Heavy Oil Growth Plan Future Production Production (bbl/d) 250, ,000 Birch Mtn 150,000 Kirby Grouse SAGD 100,000 50,000 Primrose CSS

30 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 56 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 57 28

31 Technology Option Thermal Geo-steering Well Placement Primrose North Steam Plant Bitumen burner tip Capturing More of the Reservoir With Technology Advancement 58 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 59 29

32 Horizon Oil Sands Process and Technology Only Proven Technologies Will be Utilized Reducing Technology Risks 60 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 61 30

33 Horizon Operating Costs Operating cost was $39.89/bbl SCO in 2009 Operating costs for 2010 Targeted range of $31.00/bbl to $37.00/bbl Q1/10 operating cost was high at $43.12/bbl primarily due to Unplanned maintenance activities including costs associated with the coker furnace repairs, increased property taxes and the impact of changes in product inventory carrying costs March 2010 operating costs were ~$32.50/bbl Given the fixed cost structure of the operation As production volumes increase over the remainder of 2010, production costs will decrease in line with guidance Planned vs. unplanned maintenance Horizon Will Be The Low Cost Producer 62 Hurdles Overcome to Date (bbl/d) 120, ,000 80,000 60,000 40,000 20,000 Leak in Hydrotreater Exchanger H2 Plant / PSA Valves 2009/2010 Production Data OPP-Ext reliability Dilbit Tanks high water content and high mine fines DCU pump reliability Coker furnace convection section replacement Sulphur plant burner restrictions Replacement of Sulphur Exchanger Planned outage 0 Start Up / Ramp Up Mar-09 Mar-09 Mar-09 Apr-09 Apr-09 May-09 May-09 Jun-09 Jun-09 Jul-09 Jul-09 Aug-09 Aug-09 Sep-09 Sep-09 Oct-09 Oct-09 Nov-09 Nov-09 Dec-09 Dec-09 Jan-10 Jan-10 Feb-10 Feb-10 Mar-10 Mar-10 Apr-10 Apr-10 May-10 Monthly Actual Steady Improvement 63 31

34 Phase 2/3, Tranche Execution Ore Preparation Plant #3 Overall progress 50% on target Processing plants - overall progress 52% on target MSE Wall and Plant Foundations engineering on target Tendering civil, foundations and MSE wall Hydrotransport Lines Overall progress 5% 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 Most critical purchase orders to be placed by mid-2010 Mine Maintenance Shop and Wash Bays Complete Preparing for Expansion 64 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 is well advanced and on schedule Completion by June Mechanical completion by the end of 2010 Preparing for Expansion 65 32

35 Revolving Bank Credit Facilities (C$ million) Maturity Revolving bank line - Conventional $ 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 March 31, 2010 $ 2,516 Solid Lines of Liquidity 66 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 67 33

36 2010 Natural Gas Hedging AECO (C$/GJ) $10 $9 $8 $7 $6 $5 $4 $3 Strip Floor Ceiling 100% 80% 60% 83% - Market ~52% - Market ~50% - Market 82% - Market 40% 20% 0% 17% $ ~17% $ ~31% $ Q1/10 Q2/10 Q3/10 Q4/10 Collars Market Note: Refer to quarterly reports for detailed hedging positions. Strip pricing as at Apr 30, ~18% $ ~32% $ % $ Upside Opportunity, Downside Protection Crude Oil Hedging WTI (US$/bbl) $120 $110 $100 $90 $80 $70 $60 $50 100% 80% 60% 40% 20% 0% ~46% - Market ~52% - Market ~64% - Market ~67% - Market ~26% $ $90.13 ~13% $ $75.08 ~13% $ $ ~2% $ $ Strip Floor Ceiling ~24% $ $90.13 ~12% $ $75.08 ~12% $ $ Q1/10 Q2/10 Q3/10 Q4/10 Collars Market Note: Refer to quarterly reports for detailed hedging positions. Strip pricing as at Apr 30, ~12% $ $75.08 ~12% $ $ ~12% $ $ ~11% $ $75.08 ~11% $ $ ~11% $ $ Upside Opportunity, Downside Protection 69 34

37 NOTES

38 NOTES

39 NOTES

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 May 6, 2010, the Company had the following net derivative financial instruments outstanding to manage its commodity price exposures: Remaining term Volume Weighted average price Index Crude oil Crude oil price collars (1) Apr 2010 Jun ,000 bbl/d US$60.00 US$90.13 WTI Apr 2010 Sep ,000 bbl/d US$65.00 US$ WTI Apr 2010 Dec ,000 bbl/d US$60.00 US$75.08 WTI Jul 2010 Dec ,000 bbl/d US$65.00 US$ WTI Oct 2010 Dec ,000 bbl/d US$70.00 US$ WTI Remaining term Volume Weighted average price Index Natural gas Natural gas price collars Apr 2010 Sep ,000 GJ/d C$4.50 C$6.30 AECO Apr 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.