TD Newcrest London Energy Conference January 17, 2011 DELIVERING - - PDF document

TD Newcrest London Energy Conference

January 17, 2011

THE PREMIUM VALUE ● DEFINED GROWTH ● INDEPENDENT

(1)Based upon the following average actual pricing to September 30, 2010 and average strip pricing as at

November 24, 2010, including the impact of hedging. 2009 2010F 2011B Oil WTI (US$/bbl) $61.93 $79.33 $84.32 Natural gas NYMEX (US$/mmbtu) $4.03 $4.38 $4.31 Heavy oil diff (US$/bbl) $9.64 $14.26 $18.55 C$/US$ $0.88 $0.97 $0.98

SNAPSHOT 2009 2010F 2011B Cash flow (C$ millions)

$6,090 $6,100 - $6,500 $7,000 - $7,400

Per share – basic (C$)

$5.62 $5.60 - $5.95 $6.40 - $6.75

Capital expenditures (C$ millions)

$2,997 $5,600 $5,575 - $5,975

Free cash flow (C$ millions)

$3,093 $500 - $900 $1,025 - $1,825

Dividend (C$/share)

$0.21 $0.30

Common shares (thousands)

1,084,654

Production (annual average, before royalties) Oil (mbbl/d)

355 423 - 430 449 - 486

Natural gas (mmcf/d)

1,315 1,242 - 1,250 1,177 - 1,246

BOE (mboe/d)

575 630 - 638 645 - 694

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)

DELIVERING VALUE AND GROWTH

(2)Including acquisitions. (3)Cash flow less capital expenditures. (4)Subject to the final impact of the January 2011 Horizon incident. (2) (3)

Note: All per share data in this presentation adjusted for 2004, 2005 and 2010 stock splits.

(4)

1 TD Newcrest London Energy Conference 2011 January 17, 2011

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Production Mix (Q3/10)

North Sea 4% Offshore West Africa 6% North America 90%

The Premium Value, Defined Growth Independent The Premium Value, Defined Growth Independent

Who is Canadian Natural? Who is Canadian Natural?

• Canadian based E&P company

with international exposure

• ~US$51 billion enterprise value
• 575 mboe/d – 2009

–62% crude oil weighted

• ~630-638 mboe/d – 2010F
• ~645-694 mboe/d – 2011B

–70% crude oil weighted

• Returns focused
• Major oil sands player

–Major in-situ producer with several projects in inventory –Major mining project currently ramping production

(1)Subject to the final impact of the January 2011 Horizon incident.

(1)

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Why Invest in Canadian Natural’s Future 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 Consistent History of Value Creation

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North America Natural Gas Core Area Summaries 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 Balanced, Cost Effective Growth

Northern / Southern Plains NE BC Foothills NW AB

CNQ Land SK AB BC

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Natural Gas Outlook 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

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Strategic Development Septimus Montney Play 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

CNQ SEPTIMUS ARC DAWSON ECA SWAN

Well Positioned Montney Asset Well Positioned Montney Asset

*Based on Q1/10 actual plus current 2010 strip at WTI US$86.98/bbl, AECO C$4.10/GJ.

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• Horizon mining operation

– 84,000 bbl/d – Best estimate contingent resource of 6 billion barrels of bitumen in place – ~500,000 bbl/d total capability

• Thermal in-situ development

– 85,000 bbl/d – Massive resource potential – Staged value growth – ~280,000 bbl/d of additional production

• Pelican Lake EOR development

– 38,000 bbl/d – 4.1 billion barrels OOIP – Largest polymer flood in North America – 3.5x increase in expected recovery

• Reliable primary production

– 93,000 bbl/d – Dominant land base ~ 1.6 million acres – Record ~650 wells in 2010

Heavy Oil Assets Heavy Oil Assets

Technology Option Technology Option

Birch Mountain (W. Horizon) Gregoire

CNQ Land

Primrose

(85 mbbl/d) 300 miles

Primary Heavy Oil

(93 mbbl/d)

Kirby

Note: Reflects Q3/10 actual working interest production. AB SK

Pelican Lake

(38 mbbl/d)

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20,000 40,000 60,000 80,000 100,000 120,000 140,000 1965 1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009

Heavy Oil Primary 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)

Gross Operated Heavy Oil Production

A Proven Success A Proven Success

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20,000 40,000 60,000 80,000 100,000 1995 2001 2007 2013 2019 Primary Waterflood Polymerflood

Pelican Lake Oil Pool Pelican Lake Oil Pool

• World class oil pool
• Polymer flood successful both

technically and economically

• Technology enhancement will

continue to improve

• il recovery

Massive Resource to Exploit Massive Resource to Exploit

Contingent Resources 198 mmbbl Probable Reserves 103 mmbbl Proved Reserves 246 mmbbl Produced to Date 140 mmbbl

How much of that oil is producible?

OOIP 4.1 billion barrels Developed Region (bbl/d)

Convert waterfloods to polymer

Polymer flood

Primary Waterflood

17%

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Polymer Injector Oil Production

Pelican Lake Polymer Flood 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 An Industry Leading Technology An Industry Leading Technology

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Thermal Heavy Oil Sands Thermal Heavy Oil Sands

• Land Holdings (net)

– McMurray - 373,000 acres

• Birch Mountain
• Gregoire
• Kirby
• Grouse
• Germain
• Leismer
• Ipiatik

– Clearwater - 201,000 acres

• Primrose
• Wolf Lake
• Hilda Lake
• Marie Lake

– Grand Rapids - 267,000 acres – Carbonates - 317,000 acres Great Assets, Huge Land Base Great Assets, Huge Land Base

Scale 1:1,730,000 Oil Sands Deposits

Calgary Edmonton Grande Prairie Fort McMurray

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Thermal Heavy Oil Sands Potential Thermal Heavy Oil Sands Potential

Estimated Bitumen in Place 34.5 billion barrels total

Clearwater 11 billion barrels Kirby Grouse Leismer Birch Mountain Gregoire McMurray

23.5 billion barrels

Contingent Resources 5.0 billion bbl Probable Reserves 0.6 billion bbl Proved Reserves 0.7 billion bbl Produced to Date 0.3 billion bbl

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Thermal Oil Sands Bitumen Recovery Schemes 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 Match Scheme to Reservoir

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Thermal Heavy Oil Sands Growth Plan 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 2016 Birch Mountain Phase 1 - SAGD McMurray 60,000 2018 Birch Mountain Phase 2 - SAGD McMurray 60,000 2021 Gregoire Ph 1 - SAGD McMurray 60,000 2023

Growth for Decades Growth for Decades

• 445,000 bbl/d of oil facility capacity in the defined growth plan
• 30,000-60,000 bbl/d addition every 2-3 years

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Contingent Steam-In (million barrels) PIIP* Reserves Resources Date Kirby Phase 1 365 2013 Proved 69 Probable 116 Kirby Phase 2 726 350 2016 Kirby Phase 1 - Debottleneck 434 170 2024

• Kirby will be developed through two phases plus debottleneck

potential

• Kirby Phase 1 sanctioned November 2010

–Peak production - 40,000 bbl/d

Thermal Heavy Oil Sands Kirby Thermal Heavy Oil Sands Kirby

*Petroleum initially in place (PIIP).

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Thermal Heavy Oil Sands Kirby Land Holdings Thermal Heavy Oil Sands Kirby Land Holdings

CNQ Oilsands Acquisition Kirby Phase 2 Kirby North Kirby Central Kirby Phase 1 Kirby South

Kirby North Plant (Remote Steam) Kirby South Plant (Steam & Oil Treating)

• Acquired lands

creates overall

• perating and capital

cost synergies

• Similar to Primrose

development

–Kirby Phase 2 regulatory application 2011 CNQ

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Heavy Oil Three Pronged Marketing Plan Heavy Oil Three Pronged Marketing Plan

Cumulative Incremental Volume

• DilSynbit
• WCS (Western Canadian Select)
• Synbit

Blending Pipelines

Short Term

Up to 5 years

Medium Term

5 to 10 years

Long Term

>10 years

Conversion capacity

Total blend is 280 mbbl/d CNQ 55%

• Keystone (Patoka June 2010 and to Cushing Q1/11)
• Alberta Clipper (complete)
• West Coast options

(Gateway, TMX)

• Texas Access USGC

Additional refinery conversion capacity

• Refining: cokers / hydrocrackers
• Upgrading: bitumen / heavy oil

CNQ commitments:

100 mbbl/d to USGC refiner

Access to Incremental Markets Over the Short, Medium and Long Term Access to Incremental Markets Over the Short, Medium and Long Term

• Keystone XL (USGC Q4/12)

CNQ has committed 120 mbbl/d

12.5 mbbl/d to NWU-1

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Horizon Oil Sands Horizon Oil Sands

• Mining resources

–16 billion barrels petroleum initially in place, PIIP (bitumen) with 6 billion barrels* of recoverable PIIP

• 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

UTS SYN SHC SYN SYN DVN PCA SU PCA IOL ECA SU SU IOL HSE XOM SHC SU Synenco SHC XOM ECA ECA Deer Creek SU Fort McMurray

~43 miles

CNQ CNQ

CNQ Horizon Oil Sands

World Class Opportunity World Class Opportunity

*Includes 3.5 billion barrels of bitumen upgraded to 3 billion barrels of proved and probable SCO reserves. Note: Volumes are gross lease.

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Reliability

• OPP 3, Hydrotransport, Sulfur Unit 3

(Tranche 2)

• 5,000 bbl/d SCO capacity increase in 2011/12

Directive 74

• Equipment and tailings process required to meet

new ERCB regulations Phase 2A

• Upgrading debottlenecking and coker expansion
• 10,000 bbl/d SCO capacity increase in 2013/14

Phase 2B

• OPP 4, Froth Treatment, Vacuum Distillations,

Gas/Oil Hydrotreater

• 45,000 bbl/d SCO capacity increase

Phase 3

• OPP 5, Extraction 3&4, Combined Hydrotreater,

Sulfur recovery

• 80,000 bbl/d SCO capacity increase

Horizon Oil Sands Future Expansion Horizon Oil Sands Future Expansion

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Horizon Oil Sands Expansion to 250,000 bbl/d 34º API SCO Horizon Oil Sands Expansion 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 CNQ 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 CNQ

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Horizon Oil Sands Tranche 2 Reliability Horizon Oil Sands Tranche 2 Reliability

• Purpose: Increase reliability and lower operating costs
• Ore Preparation Plant 3
• n stream Q4 2011
• Hydro transport
• n stream Q4 2011
• Tank expansion
• n stream Q1 2011
• Upgrading

–Sulfur Unit 3

• n stream Q4 2013

–Gas recovery

• n stream Q2 2014

–Butane treating

• n stream Q2 2014
• 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

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Canadian Natural 2011 Budget – Production Canadian Natural 2011 Budget – Production

Production 2010F 2011B % Change Crude oil (mbbl/d) Canada Light and NGLs 50-51 54-58 11% Pelican Lake 38-39 43-47 17% Heavy 93-94 101-105 10% Thermal 89-91 97-105 12% International 63-65 49-59 (16%) Horizon 90-93 105-112 19% Total 423-430 449-486 10% Natural gas (mmcf/d) 1,242-1,250 1,177-1,246 (3%) BOE/D 630-638 645-694 6%

(2) (2) (2) (1) (1)

(1)Rounded to the nearest 1,000 bbl/d. (2)Subject to the final impact of the January 2011 Horizon incident.

Note: Numbers may not add due to rounding.

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Capital ($ million) 2010F 2011B % Change Natural gas 700 600 (14%) Crude oil Pelican Lake 500 615 23% Heavy 630 820 30% Thermal 555 1,345 142% Light Canada 315 460 46% North Sea 180 370 106% Offshore West Africa 250 135 (46%) Total crude oil 2,430 3,745 54% Horizon Sustaining and reclamation 130 220 69% Capital Projects 360 800-1,200 122-233% Other 80 100 25% Total Horizon 570 1,120-1,520 96-167% Acquisition and Midstream 1,900 110

• Total

5,600 5,575-5,975 0-7%

Canadian Natural 2011 Budget – Capital Canadian Natural 2011 Budget – Capital

(1)Subject to the final impact of the January 2011 Horizon incident.

(1) (1) (1)

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Canadian Natural 2011 and Beyond Canadian Natural 2011 and Beyond

• Vast balanced assets
• Well defined yet flexible plan
• Leveraging technology
• Capital allocation flexibility
• Significant free cash flow
• 2011

–6% boe production growth – 10% oil growth –Allocate $2.4 billion to $2.8 billion (> 45% of budget) to future production growth (post 2011) –Pay down debt –Deliver $1.0 billion to $1.8 billion of free cash flow

(1)Subject to the final impact of the January 2011 Horizon incident.

(1)

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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

• utcome 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

• perates, 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

• perations 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

• bligations; 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

• bligation to update forward-looking statements should circumstances or Management’s estimates or opinions change.

Forward Looking Statements Forward Looking Statements

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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

• therwise 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 51-101 Standards for Disclosure for Oil and Gas Activities (“NI 51-101”) 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 51-101. This exemption allows the Company to substitute SEC requirements under Regulations S-K and S-X for certain disclosures required under NI 51-

• 101. 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 51-101, however, there are material differences to the type of volumes disclosed and the basis from which the volumes are determined. NI 51-101 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, 2009. 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 51-101. These estimates are evaluated internally. No independent third party evaluation or audit was completed. Contingent resources provided are best estimates as of December 31, 2009. 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.

Reporting Disclosures Reporting Disclosures

NOTES

NOTES

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 51-101 Standards for Disclosure for Oil and Gas Activities (“NI 51-101”) 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 51-101. This exemption allows the Company to substitute SEC requirements under Regulations S-K and S-X for certain disclosures required under NI 51-101. 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 51-101, however, there are material differences to the type of volumes disclosed and the basis from which the volumes are determined. NI 51-101 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, 2009. The reserves volumes provided are evaluated by IQRE under SEC guidelines using 12-month average prices and current costs. Resources Other Than Reserves The contingent resources other than reserves (“resources”) estimates provided in this presentation are evaluated in accordance to Canadian Oil and Gas Evaluation Handbook (“COGEH”) standards as directed under NI 51-101. These estimates are evaluated internally. No independent third party evaluation or audit was completed. Resources provided are best estimates as of December 31, 2009. The resources are evaluated using deterministic methods which represent the expected outcome with no optimism or conservatism. 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, 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

• f 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.

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

HEDGING

At November 4, 2010, the Company had the following net derivative financial instruments outstanding:

Remaining term Volume Weighted average price Index Crude oil (1) Crude oil price collars (2) Oct 2010 – Dec 2010 50,000 bbl/d US$60.00 – US$75.08 WTI Oct 2010 – Dec 2010 50,000 bbl/d US$65.00 – US$108.94 WTI Oct 2010 – Dec 2010 50,000 bbl/d US$70.00 – US$105.81 WTI Jan 2011 – Dec 2011 50,000 bbl/d US$70.00 – US$102.24 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$27 US$27 US$26 Remaining term Volume Weighted average price Index Natural gas Natural gas price collars Oct 2010 – Dec 2010 220,000 GJ/d C$6.00 – C$8.00 AECO

2004 2005 2006 2007 2008 2009

Operational Information

Daily production, before royalties Crude oil and NGLs (mbbl/d) 283 313 332 331 316 355 Natural gas (mmcf/d) 1,388 1,439 1,492 1,668 1,495 1,315 Barrels of oil equivalent (mboe/d) 514 553 581 609 565 575 Daily production, after royalties Crude oil and NGLs (mbbl/d) 256 283 301 293 276 318 Natural gas (mmcf/d) 1,105 1,147 1,209 1,402 1,246 1,214 Barrels of oil equivalent (mboe/d) 440 474 502 526 484 525 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 328 627 603 592 682 644 Natural gas 689 890 641 383 269 109 Dry 96 117 119 93 39 46 Strats and service 336 248 375 254 131 329 Undeveloped land (thousands of acres) North America 11,523 10,947 12,785 12,160 11,603 10,651 North Sea 565 352 299 287 258 150 Offshore West Africa 886 426 207 192 192 192 Realized product pricing, before hedging activities & after transportation costs Crude oil and NGLs (C$/bbl) 37.99 46.86 53.65 55.45 82.41 57.68 Natural gas (C$/mcf) 6.50 8.57 6.72 6.85 8.39 4.53 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 3.52 4.68 4.59 5.75 6.45 5.62

Net earnings 1,405 1,050 2,524 2,608 4,985 1,580

per share 1.31 0.98 2.35 2.42 4.61 1.46

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 4.8 5.2 5.4 5.6 5.2 5.3 Proved and probable reserves before royalties per common share* 2.2 2.4 3.2 3.2 3.1 5.8

*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$) 0.10 0.12 0.15 0.17 0.20 0.21 TSX trading info

Average daily trading volume (thousands) 5,448 5,084 4,056 3,418 5,416 4,144 High (C$) 13.79 31.00 36.96 40.01 55.65 39.50 Low (C$) 7.98 12.14 22.75 26.23 17.10 17.93 Close (C$) 12.82 28.82 31.08 36.29 24.38 38.00 Note: All per share data adjusted for 2004, 2005 and 2010 stock splits.

KEY HISTORIC DATA

Fourth Quarter 2010 2010 Guidance 2011 Budget

Daily Production Volumes, (before royalties) Natural gas (mmcf/d) North America 1,220 - 1,240 1,217 - 1,222 1,150 - 1,210 North Sea 8 - 10 10 - 11 7 - 10 Offshore West Africa 20 - 23 15 - 17 20 - 26 1,248 – 1,273 1,242 - 1,250 1,177 - 1,246 Crude oil and NGLs (mbbl/d) North America 283 - 293 270 - 272 295 - 315 North America – Oil Sands Mining 90 - 100 90 - 93 105 - 112 North Sea 30 - 32 33 - 34 27 - 32 Offshore West Africa 29 - 31 30 - 31 22 - 27 432 - 456 423 - 430 449 - 486 Capital Expenditures, (C$ millions) North America natural gas $ 700 $ 600 North America crude oil and NGLs 1,445 1,895 North America thermal crude oil Primrose and Future 465 830 Kirby Phase 1 90 515 North Sea crude oil 180 370 Offshore West Africa crude oil 250 135 Property acquisitions, dispositions and midstream 1,900 110 Total 5,030 4,455 Horizon Oil Sands Project Sustaining and reclamation capital 130 220 Project capital Reliability - Tranche 2 320 370 Directive 74 and Technology 10 130 Phase 2A 25 200 - 230 Phase 2B 5 10 - 295 Phase 3 90 - 150 Phase 4 0 - 25 Total Capital Projects 360 800 - 1,200 Capitalized interest and other 80 100 Total Horizon Project 570 1,120 - 1,520 Total Capital Expenditures $ 5,600 $ 5,575 - 5,975 Average Annual Cost Data Royalty Operating Royalty Operating Rate Cost Rate Cost Natural Gas - North America (mcf)

5 - 6% $1.05 - 1.10 4 - 6% $1.10 - 1.20

Crude oil and NGLs (bbl)

North America 17 - 19% $12.00 - 13.00 16 - 20% $12.00 - 13.00 North America – Oil Sands Mining* 4 - 5% $33.00 - 37.00 4 - 6% $30.00 - 36.00 North Sea

• $30.00 - 31.00
• $38.00 - 42.00

Offshore West Africa 6 - 8% $14.50 - 15.50 13 - 15% $18.00 - 21.00 *Royalties are payable on the bitumen production, royalty rate shown is imputed on SCO barrel.

Other Information Cash income and other taxes (C$ millions)

• Sask. Resources Surcharge/Capital Tax

$25 - 30 $40 - 50 Current income taxes – North America $450 - 500 $400 - 500 Current income taxes – International and Petroleum Revenue Tax (PRT) $290 - 330 $120 - 160 Effective tax rate on adjusted earnings 26% - 28% 26% - 30% Midstream cash flow (C$ millions) $50 - 55 $45 - 55 Average corporate interest rate 4.90% - 5.05% 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 budget based on an average annual WTI of $84.32/bbl, NYMEX of US$4.31/mmbtu and an exchange rate of US$0.98 to C$1.00.

December 2, 2010

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.

CORPORATE GUIDANCE

(1) (1)Subject to the final impact of the January 2011 Horizon incident.

(1) (1)

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 Allan P. Markin

Chairman

John G. Langille

Vice-Chairman

Steve W. Laut

President

Tim S. McKay

Chief Operating Officer

Douglas A. Proll

Chief Financial Officer & Senior Vice-President, Finance

Corey B. Bieber

Vice-President, Finance & Investor Relations (403) 517-6878

Mark Stainthorpe

Investor Relations (403) 514-7845

Leah Loyola

Analyst, Investor Relations (403) 514-7911

THE PREMIUM VALUE ● DEFINED GROWTH ● INDEPENDENT