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2015 Budget summary

2015 Budget summary. November 6, 2014. Forward Looking Statements. Reporting Disclosures. Agenda. Q3/14 Highlights Canadian Natural’s Advantage 2015 Budget Summary Asset Overview. Q3/14 Highlights. Quarterly production 797,000 BOE/d – 13% YOY growth

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2015 Budget summary

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  1. 2015 Budget summary November 6, 2014

  2. Forward Looking Statements

  3. Reporting Disclosures

  4. Agenda Q3/14 Highlights Canadian Natural’s Advantage 2015 Budget Summary Asset Overview

  5. Q3/14 Highlights • Quarterly production • 797,000 BOE/d – 13% YOY growth • 518,000 bbl/d crude oil & NGLs – 2% YOY growth • 2014F targeted annual growth of 12% • 1,674 MMcf/d natural gas – 44% YOY growth • Record Pelican Lake heavy crude oil production ~ 51,900 bbl/d • Primrose East Area 1 steam flood application approved • Horizon reliable operations continue • Phase 2A Coker expansion completed in September 2014 on time, on budget • Horizon run rate 122,000 - 127,000 bbl/d • Progress royalty stream monetization • Very strong cash flow and earnings • $2,440 million cash flow from operations • Adjusted net earnings of $984 million

  6. Canadian Natural’s Advantage

  7. Canadian Natural’s Advantage GROWING AND INCREASING THE SUSTAINABLY OF FREE CASH FLOW • Large, diversified, well balanced asset base • Delivers significant cash flow, only a portion required to provide near term growth • Delivers increasing and more sustainable free cash flow to allocate to: • Resource development – transitioning to longer life assets • Returns to shareholders • Opportunistic acquisitions • Balance sheet strength • Driven by: • Effective capital allocation • Effective and efficient operations • Strong management teams

  8. 1P (Proven) Reserves After Royalties (MMBOE) CNQ Note: Sourced from 2013 corporate reports. Peers include: APA, APC, EOG, CVE, CHK, DVN, ECA, HSE, IMO, OXY, NBL, SU, TLM. CNQ does not include reserves associated with acquisitions closed to date in 2014. SIGNIFICANT VALUE TO UNLOCK

  9. 2P (Proven and Probable) Reserves Before Royalties (MMBOE) CNQ Based on forecast pricing assumptions. Note: Sourced from 2013 corporate reports. Peers include: CVE, ECA, HSE, IMO, SU, TLM. CNQ does not include reserves associated with acquisitions closed to date in 2014. SIGNIFICANT VALUE TO UNLOCK

  10. Large Resource Base to Develop (MMBOE) Gross Proved Reserves(1)Gross Probable Reserves(1)Resources(2) Reserves(1) Resources(2) Reserves & Resources(1)(2) (1) Company gross proved and probable reserves at December 31, 2013. (2) Company gross best estimate contingent resources other than reserves at December 31, 2013. Note: Contingent resource includes Thermal, Pelican Lake, Horizon, Heavy Oil, NA Light Oil, Montney and Deep Basin. Please see reporting disclosures for additional information. Vast Resource Base Holds Significant Future Value

  11. Transitioning to a Longer Life Asset Base (% of CNQ liquids production)* *2015B - 2018F based on company internal forecast as at November 2014. Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. LONG LIFE ASSETS = MORE SUSTAINABLE free CASH FLOW

  12. Field Operating Free Cash Flow Breakdown North America E&P includes Midstream free cash flow. Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. Field operating free cash flow represents operating cash flow (cash flow from operations before corporate costs, interest, foreign exchange, risk management and taxes) less capital. 2015B pricing assumptions: WTI of US$81.00/bbl, AECO of C$3.45/GJ, WCS differential of 18% and foreign exchange of US$1.00 to C$1.13.

  13. Horizon Field Operating Free Cash Flow ($ Billion) $90.00 $81.00 $70.00 Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. Field operating free cash flow represents operating cash flow (operational cash flow before corporate costs , interest, foreign exchange, risk management and taxes) less capital. 2015B pricing assumptions: WTI of US$81.00/bbl, AECO of C$3.45/GJ, WCS differential of 18% and foreign exchange of US$1.00 to C$1.13. See Advisory for pricing assumptions – Note 2 & 3. STRONG FREE CASH FLOW GENERGATION IS CLOSE

  14. Targeted Total Corporate Free Cash Flow ($ Billion) 35% CAGR (2014F-2018F) $90.00 $81.00 $70.00 Free Cash Flow including 2014 opportunistic acquisitions Note: Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. Free cash flow represents cash flow (cash flow net of corporate costs, interest, foreign exchange and taxes) less capital before dividends and share purchases. Capital targeted between $8.0 and $8.75 billion for 2016F-2017F and less thereafter. See Advisory for pricing assumptions – Note: 2 & 3. GROWING FREE CASH FLOW

  15. Free Cash Flow Allocation PRUDENT USE OF CASH FLOW • Resource development • Executing our defined plan • Dividends • 14 consecutive years of dividend increases • 34% CAGR (2009 - 2014) • Must be sustainable • Share purchases • 10.2 million common shares purchased in 2013 at an average price of $31.46/share • 9.675 million common shares purchased to date in 2014 at an average price of $45.01/share • Opportunistic acquisitions • Pay down debt

  16. Balanced Free Cash Flow Allocation Return to Shareholders ($ million) ~44% CAGR Horizon build years Note: CAGR represents 2009-2014 potential. 10.2 million common shares purchased in 2013 at a weighted average price of $31.46/share. As at November 6, 2014, 9.675 million common shares have been purchased in 2014 at a weighted average price of $45.01/share. RETURNS TO SHAREHOLDERS A PRIORITY

  17. 2015 Budget Summary

  18. 2015 Budget Highlights *2015B pricing assumptions: WTI of US$81.00/bbl, AECO of C$3.45/GJ, WCS differential of 18% and foreign exchange of US$1.00 to C$1.13. • Strong cash flow generation – $9.4 billion* • Assets generate field operating free cash flow • Maintaining capital discipline • Delivering strong production growth – 89,000 BOE/d or 11% • Retaining significant capital flexibility ($2 billion) • Preserving dividend increase/share purchase capacity • Long life/low decline asset transition in final stages • Horizon Phase 2B • 45,000 bbl/d incremental capacity 172,000 bbl/d in late 2016 • Horizon Phase 3 • 80,000 bbl/d incremental capacity 252,000 bbl/d in late 2017 • Strong balance sheet • Prepared for low commodity price cycle

  19. Canadian Natural2015 Capital Budget

  20. 2015 Capital Flexibility Capital that can be curtailed in 2015. Includes Technology and Phase 4.

  21. Canadian Natural2015 Production Budget Rounded to the nearest 1,000 bbl/d. Note: Numbers may not add due to rounding. Strategic, Defined Growth Plan

  22. 2015 Targeted Free Cash Flow Uses *Dependent on CNQ share price and commodity prices. Note: Does not include any potential proceedsfrom Royalty Land monetization. See Advisory for pricing assumptions – Note 1 & 2.

  23. Slide 23 2015 Budget Summary *At midpoint of 2015B production guidance. See Advisory for pricing assumptions – Note 2. • Strong cash flow • $9.4 billion* • $8.50 per share* • Strong production growth – 11% YOY BOE/d • Significant capital flexibility – $2 billion of budgeted capital • Strong balance sheet • Prepared for low commodity price cycle

  24. Asset Overview

  25. North America Natural Gas & NGLsCore Area Summary • Largest natural gas producer in Canada • Q3/14 natural gas production of 1,644 MMcf/d • Q3/14 average NGLs yield over 20 bbl/MMcf • Large resource base • 8.3 Tcfe reserves(1) • Significant unconventional assets • Montney and Deep Basin • Totalland position • 22.1 million net acres(2) • High working interest, low decline assets • Owned infrastructure • $1 increase in AECO = ~$420 million additional annual cash flow(3) AB SK East 371 MMcf/d MB West 1,273 MMcf/d BC CNQ Total Land Base Note: Reflects Q3/14 actual production, before royalties. Does not included NGLs production. (1) Company Gross proved plus probable reserves at December 31, 2013 including Company Gross proved reserves related to the Devon acquisition. (2) Land position as at December 31, 2013 including lands associated with 2014 opportunistic acquisitions. (3) Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. INCREASED SOLID ASSET BASE

  26. North America Natural Gas & NGLs2015 Plan • Capital discipline • Preserve land base for increasing natural gas prices • 2015 operating cost guidance $1.30 - $1.40/mcf • Targeting selective liquids rich gas plays • Septimus, Deep Basin • Capital increase to expand facility and infrastructure to capture 3rd party revenue and lower overall operating costs • 2015 field operating free cash flow targeted at $245 million* *Excludes NGLs. See Advisory for pricing assumptions – Note 2. MOST EFFICIENT AND EFFECTIVE PRODUCER

  27. North America Light Crude Oil 2015 Plan Note: Rounded to the nearest 1,000 bbl/d. • 2015 budget activity • Target multiple formations across basin • Leverage infrastructure and “Drill-to-Fill” • Drives capital efficiencies • Maximizes value • Opportunities to optimize facilities and operating costs • Leverage technology, horizontal multifracs • 87% of total drilling – horizontal • Reduce costs • 2015 field operating free cash flow targeted at $860 million* *Includes NGLs. See Advisory for pricing assumptions – Note 2. SIGNIFICANT LAND BASE & OPPORTUNITY

  28. International Light Crude Oil 2015 Plan Note: Rounded to the nearest 1,000 bbl/d. See Advisory for pricing assumptions – Note 2. FIELD OPERATING FREE CASH FLOW GENERATION • North Sea • 4 Brownfield Allowances (BFAs) approved to date • Ninian development plan commenced in Q4/13 • 6 well program • Offshore Africa • Espoir 10 well infill drilling program • Targeted to commence late Q4/14 • Baobab 6 well drilling program • Targeted to commence Q1/15 • 2006 - 2013 field operating free cash flow – $6.1 billion • 2015 capital spending drives targeted 2016 field operating free cash flow of $285 million

  29. International Exploration • Côte d’Ivorie • CI-514 – CNQ 36% WI • First exploratory well encountered 40 meter column of 34 degree API crude • Second exploratory well targeted up-dip for first half of 2015 • CI-12 – CNQ 60% WI • 3D seismic acquired and under evaluation for exploratory targets • Prospectivity enhanced by results 35 kilometers west at CI-514 • South Africa • Blocks 11B/12B, Outeniqua Basin - CNQ 50% WI • Block contains 5 separate structures up to 1 billion barrels each • Exploratory drilling commenced in Q3/14, but encountered rig equipmentmechanical failure • Operator reviewing causes and expecting rig to return in 2016

  30. Primary Heavy Crude Oil Core Area Summary • Largest primary heavy oil producer in Canada • Record Q3/14 production of ~142,500 bbl/d • Delivering strong execution • Extensive land base and infrastructure • Over 8,000 drilling locations • 5 major processing facilities • ECHO sales pipeline • 2P reserves • 334 million barrels* • High return on capital • Low operating costs • Strong netbacks ECHO Pipeline CNQ Producing Properties CNQ Lands ~212km *Company Gross proved plus probable reserves as at December 31, 2013. VAST LAND BASE AND INFRASTRUCTURE CAPTURES VALUE

  31. Primary Heavy Crude Oil 2015 Plan Note: Rounded to the nearest 1,000 bbl/d. • Low operating costs high netbacks strong field operating free cash flow • Reducing capital to maintain capital efficiencies • Technology advancements unlock value • 2015 field operating free cash flow targeted at $900 million = See Advisory for pricing assumptions – Note 2. STRONG CASH-ON-CASH RETURNS

  32. Pelican Lake Crude Oil • Wabiskaw heavy crude oil pool • Industry leading EOR project • Amongst the largest polymer floods in the world • Technology development continues to improve crude oil recovery • Leading example of technology driving value growth • Industry leading operating costs • Record Q3/14 production of ~51,900 bbl/d • 2014 targeted production growth of 17% • 2015 targeted production growth of 7% How much of that crude oilis recoverable? OIIP(1) 4.1 billion barrels Developed Region Proved Reserves(2) 258 MMbbl Probable Reserves(2) 104 MMbbl 19% RF Resources(3) 204 MMbbl Produced to Date 197 MMbbl (1) Discovered heavy crude oil Initially in Place. (2) Company Gross proved plus probable reserves as at December 31, 2013.(3) Best estimate contingent resources other than reserves as at December 31, 2013. MASSIVE RESOURCES TO EXPLOIT

  33. Pelican Lake 2015 Plan Note: Rounded to the nearest 1,000 bbl/d. • Increasing field operating free cash flow as capital requirements are reduced and polymer driven performance is realized • Industry leading operating costs • 2015 field operating free cash flow targeted at $580 million See Advisory for pricing assumptions – Note 2. TECHNOLOGY ADVANCEMENT PROVIDES SIGNIFICANT UPSIDE

  34. Thermal In Situ Oil Sands Tremendous Potential • Long life low decline asset base • Vast asset base developed with a defined growth plan • Effective and efficient thermal operator • Kirby South ramping up • Primrose development plans underway • Significant field operating free cash flow near, mid and long term 97 billion barrels total BIIP(1) Grand Rapids15 billion barrels Clearwater14 billion barrels Proved Reserves(2) 1.2 billion bbl Probable Reserves(2) 1.0billion bbl Wabiskaw 9 billion barrels Resources(3) 8.7 billion bbl McMurray 49 billion barrels Produced to Date(4) 0.4 billion bbl Carbonates10 billion barrels (1) Discovered bitumen Initially in Place. (2) Company Gross proved plusprobable reserves as at December 31, 2013. (3) Best estimate contingent resources other than reserves as at December 31, 2013. (4) Produced to December 31, 2013. MASSIVE RESOURCE TO DEVELOP

  35. Thermal In Situ Oil Sands Growth Plan • 522,000 bbl/d of oil facility capacity in the defined growth plan • 40,000 - 60,000 bbl/d addition every 2-3 years • 100% working interest and operatorship CAPTURING VALUE BY DOING IT RIGHT

  36. Thermal 2015 Plan • Primrose • Ramp up Primrose East Area1 steamflood • 2015 targeted exit rate of 15,000 - 17,000 bbl/d • Low Pressure Cycle Steam Primrose East Area 2 • 4 pads targeted for Q1/15, subject to regulatory approval • Primrose South Development • Orange sand development ramp up • Kirby • Continue Kirby South production ramp up • Ramp up paused to repair steam generators • 40,000 bbl/d Q1/15 • Kirby North expansion underway • Target 70% complete by year end 2015 • Steam in Q4/16

  37. Thermal In Situ Oil Sands 2015 Plan Note: Rounded to the nearest 1,000 bbl/d. • 2015 field operating free cash flow targeted at $715 million See Advisory for pricing assumptions – Note 2. CONTINUED PRODUCTION GROWTH WITH LONG TERM FOCUS

  38. Horizon Oil Sands - OperationsCore Area Summary • World Class asset • 14.4 billion barrels BIIP(1) • 2P SCO reserves – 3.3 billion barrels(2) • Best estimate contingent resources other than reserves – 4.1 billion barrels of bitumen(3) • Phased development (SCO) • Current targeted production capacity of 127,000 bbl/d • Targeted completion of Phase 2/3 to 250,000 bbl/d • Potential future expansion to ~500,000 bbl/d of SCO or Bitumen equivalent • 40+ years of production with no declines • 100% working interest • Significant field operating free cash flow for decades Synenco SHC SU CNQHorizonOil Sands UTS SHC IOL SYN XOM Deer CNQ SHC SU Creek HSE CNQ SYN SU IOL DVN SYN ~43 miles SU PCA ECA SU PCA ECA XOM FortMcMurray ECA (1) Discovered Bitumen Initially in Place. (2) Company Gross proved plusprobable reserves as at December 31, 2013. (3) Best estimate contingent resources other than reserves as at December 31, 2013. WORLD CLASS OPPORTUNITY

  39. Horizon Oil Sands - Operations2015 Plan *2014F and 2015B operating costs reflect production downtime for planned tie-ins and turnarounds.. Note: Rounded to the nearest 1,000 bbl/d. FOCUS ON OPERATIONAL EXCELLENCE • Enhanced reliability • Continued focus on safe, steady and reliable operations • Plant utilization of 95% post turnaround 2013 • Greater focus on operating cost efficiencies • 2015 Guidance: $35.00 - $38.00/bbl, $32.00 - $35.00/bbl excluding turnaround • Targeted production capacity increased to 127,000 bbl/d • 35 day major turnaround targeted for Q3/15

  40. Horizon Oil Sands - OperationsIndustry Leading Utilization (% Utilization) Oil Sands Upgrader Utilization 99 2013 Best annual performance of last 5 years 94 87 87 87 84 84 84 76 YTD 2014 Q2/14 Q1/14 Source: For 2013 and best annual performance of last 5 years: - FirstEnergy Capital Corp. – Synopsis: Integrated, Oilsands, and Large Cap Oil & Gas Producers, April 2014”. Note For Q1/14 to Q3/14, CNQ internal. Peers include: Suncor, Syncrude. BEST IN CLASS OPERATIONAL PERFORMANCE

  41. Horizon Oil Sands - Expansion2015 Plan – Phase 2/3 Project Expansion Note: Rounded to the nearest $1,000. FOCUS ON PROJECT EXECUTION • CNQ execution strategy is working • Overall costs tracking at budget • 2014 tracking to bottom end of capital budgeted range of $2,520 - $2,920 million • Phase 2/3 expansion targeted to be 70% complete by year end 2015

  42. Horizon Oil Sands - ExpansionProduction Capacity Plan • Phase 2A completed 9 months ahead of schedule (bbl/d) 80,000 bbl/d added Actual/Forecast/Budget Capacity Target 45,000 bbl/d added 12,000 bbl/d added Phase 2A Phase 2B Phase 3 Note: Capacity additions – 3-6 months required to ramp up to full rates. Project progressdependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. 2014F - 2019F based on Company internal forecast as at November 2014. FUTURE EXPANSION CREATES VALUE

  43. Horizon Oil Sands - OperationsTargeted Operating Costs Targeted Operating Cost per Year Targeted Operating Cost per Barrel ($million) ($/bbl) • Labour is a major portion of fixed costs • Production increases 2.3x while labour increases 1.4x • Introduction of thickeners, saves energy, reduces cost • Increased yield Note: Cost estimated with mine diesel and gas/energy as the major variable costs. No sustaining capital or major unplanned outage costs are included. 2015B cost per barrel excludes planned production downtime in 2015 for turnaround. Based on company internal forecast as at November 2014. Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. IMPROVING ECONOMICS THROUGH EXPANSION

  44. Asset Summary Large, balanced, high quality diverse asset base Asset delivers free cash flow Vast long life, low decline resource base Sustainable, organic, profitable growth Unlocks significant value Delivers increasing and sustainable free cash flow

  45. Targeted Total Corporate Free Cash Flow ($ Billion) 35% CAGR (2014F-2018F) $90.00 $81.00 $70.00 Free Cash Flow including 2014 opportunistic acquisitions Note: Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. Free cash flow represents cash flow (cash flow net of corporate costs, interest, foreign exchange and taxes) less capital before dividends and share purchases. Capital targeted between $8.0 and $8.75 billion for 2016F-2017F and less thereafter. See Advisory for pricing assumptions – Note: 2 & 3. GROWING FREE CASH FLOW

  46. Free Cash Flow Allocation PRUDENT USE OF CASH FLOW • Resource development • Executing our defined plan • Dividends • 14 consecutive years of dividend increases • 34% CAGR (2009 - 2014) • Must be sustainable • Share purchases • 9.675 million common shares purchased year to date in 2014 at an average price of $45.01/share • Opportunistic acquisitions • Pay down debt

  47. 2015 Budget Highlights *2015B pricing assumptions: WTI of US$81.00/bbl, AECO of C$3.45/GJ, WCS differential of 18% and foreign exchange of US$1.00 to C$1.13. • Strong cash flow generation – $9.4 billion* • Assets generate field operating free cash flow • Maintaining capital discipline • Delivering strong production growth – 89,000 BOE/d or 11% • Retaining significant capital flexibility ($2 billion) • Preserving dividend increase/share purchase capacity • Long life/low decline asset transition in final stages • Horizon Phase 2B • 45,000 bbl/d incremental capacity 172,000 bbl/d in late 2016 • Horizon Phase 3 • 80,000 bbl/d incremental capacity 252,000 bbl/d in late 2017 • Strong balance sheet • Prepared for low commodity price cycle

  48. Canadian Natural’s Advantage GROWING AND INCREASING THE SUSTAINABLY OF FREE CASH FLOW • Large, diversified, well balanced asset base • Delivers significant cash flow, only a portion required to provide near term growth • Delivers increasing and more sustainable free cash flow to allocate to: • Resource development – transitioning to longer life assets • Returns to shareholders • Opportunistic acquisitions • Balance sheet strength • Driven by: • Effective capital allocation • Effective and efficient operations • Strong management teams

  49. Advisory Pricing Assumptions • 2014F based upon pricing assumptions at October 2014; WTI of US$95.34/bbl, AECO of C$4.19/GJ, WCS differential of 20% and foreign exchange of US$1.00 to C$1.10. • 2015B based upon pricing assumptions at October 2014; WTI of US$81.00/bbl, AECO of C$3.45/GJ, WCS differential of 18% and foreign exchange of US$1.00 to C$1.13. For $70 and $90 cases for 2015B, see table below. • 2016F to 2020F based on constant price assumptions of: Definitions • Field operating free cash flow represents operating cash flow (operational cash flow before corporate costs, interest, foreign exchange, risk management and taxes) less capital. • Free cash flow represents cash flow (cash flow net of corporate costs, interest, foreign exchange and taxes) less capital before dividends and share purchases. • CAGR – Compound Annual Growth Rate • BOE/d – Barrel of oil equivalent per day

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