credit suisse 2010 energy summit...credit suisse 2010 energy summit february 2, 2010 cnq 10 heavy...

THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT

VALUE CREATION RETURN ON CAPITAL LOW-COST PRODUCER RETURN ON ASSETS

Credit Suisse2010 Energy Summit

February 2, 2010

SNAPSHOT 2008 2009F 2010F

Cash flow (C$ millions) $6,969 $5,900 - $6,100 $6,500 - $6,900

Per share - basic (C$) $12.89 $10.70 - $11.45 $12.00 - $12.70

Capital expenditures (C$ millions) $7,451 $3,120 $3,922

Dividend (C$/share) $0.40

Common shares (thousands) 540,991

Production (annual average, before royalties)Oil (mbbl/d) 316 352 - 363 400 - 445

Natural gas (mmcf/d) 1,495 1,305 - 1,314 1,117 - 1,185BOE (mboe/d) 565 570 - 582 586 - 643

Conventional reserves (after royalties as at December 31, 2008 – constant pricing)

Proved oil (mmbbl) 1,346

Proved natural gas (bcf) 3,684

Proved BOE (mmboe) 1,960

Proved and probable BOE (mmboe) 2,996

Synthetic crude oil reserves (after royalties as at December 31, 2008 – constant pricing)Proved (mmbbl) 1,946Proved and probable (mmbbl) 2,944

Based upon the following actual and strip pricing, including the impact of hedging2009F 2010F

Oil WTI (US$/bbl) $62.42 $81.94Natural gas NYMEX (US$/mmbtu) $4.17 $5.87Heavy oil diff (US$/bbl) $10.04 $10.09C$/US$ $0.88 $0.94

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DELIVERING VALUE AND GROWTH

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1

Credit Suisse 2010 Energy Summit February 2, 2010

CNQ2

Production Mix (Q3/09)

North Sea6%

OffshoreWest Africa7%

NorthAmerica

87%

• Canadian based E&P company with international exposure

• ~US$40 billion enterprise value• ~575 mboe/d - Q3/09

– 62% crude oil weighted• ~586 - 643 mboe/d - 2010B • Returns focused • Major oil sands player

– Major in-situ producer with several projects in inventory

– Major mining project currently ramping production

The Premium Value, Defined Growth Independent

Who is Canadian Natural?Who is Canadian Natural?

CNQ3

0

500

1,000

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2,000

2,500

93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 100

100

200

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500

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700

• Consistent valuecreation through successful

–Exploitation –Exploration–Opportunistic

acquisitions

• 100% of reservessubject toindependent evaluation

Who is Canadian Natural?Who is Canadian Natural?

Consistent History of Value Creation

Production / Proved Reserves History (before royalties)

Production Reserves

Daily Production (m

boe/d)Prov

ed R

eser

ves

(mm

boe)

F

Note: Excluding bitumen mining reserves.

B

2


CNQ4

Why Invest in Why Invest in Canadian NaturalCanadian Natural’’s Futures 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


CNQ5

48%Oil

29%Gas

47.5%DropIn Oil

35%Oil

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

Q1

- 89

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10BHistorical Production GrowthHistorical Production Growth

(boe/d)

Canadian Natural Production - 1989 to Present

Significant Price Reduction

HorizonConstruction

3


CNQ6

A History of Value CreationA History of Value Creation

$0$2$4$6$8

$10$12$14$16

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008$0

$10$20$30$40$50$60$70$80

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

0

2

4

6

8

10

12

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 20080

3

6

9

12

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Conventional Pretax Net Asset Value Per Share*

Actual 25% CAGR

Cash Flow Per Share*

Daily Production Per 10,000 Shares (boe/d)

Reserves Per Share* (boe)

Gas Oil Mining SCO

Actual 25% CAGR

Gas Oil

*Refer to page 3 of the 2008 Canadian Natural Annual Report for a detailed description of notes.

28% CAGR28% CAGR

Consistent Growth

8% CAGR8% CAGR

20% CAGR20% CAGR

26% CAGR26% CAGR

CNQ7

Committed ManagementCommitted Management

$226 $198 $176 $189 $178$106

$46 $29

$752

0

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1,200

1,400

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1,800

CNQ XTO DVN EOG ECA APA APC PXD NXY TLM

• Substantial management and director wealth at stake

–Strong motivation for management to perform

–Delivers clear alignment with shareholder interests

Note: Based on share ownership data excluding options and priced at November 3, 2009.Source: Thomson Reuters.

Management / Directors Stock Ownership(US$ millions)

$1,612


4


CNQ8

Our StrategyOur 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

CNQ9

Natural Gas Natural Gas Operating Cost Peer ComparisonOperating Cost Peer Comparison

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

Q3/05 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

Note: Other Producers - NXY, HSE, TLM, ECA, ARC, PWT, PGF.UN.

($/mcf)

Canadian Natural

Peer Average

Source: Corporate reports.

Peer Group

Best in Class Versus Established Peers

5


CNQ10

Heavy Oil Heavy Oil Operating Cost Peer ComparisonOperating Cost Peer Comparison

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

Q3/05 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

($/bbl)

Note: Other Producers - NXY, HSE, TLM, ECA. CNQ heavy oil operations not including thermal operating costs.

Canadian Natural

Best in Class Versus Established Peers

Peer GroupPeer Average

Source: Corporate reports.

CNQ11

NW AB441 mmcf/d

15 mbbl/d

NE BC322 mmcf/d

5 mbbl/d

Northern Plains340 mmcf/d184 mbbl/d

SE SK3 mmcf/d8 mbbl/d

Southern Plains

158 mmcf/d11 mbbl/d

Oil Sands Mining 67 mbbl/d

North Sea Crude Oil Natural % of & NGLs Gas BOE Total

(mbbl) (mmcf) (6:1)2010B Production (per day) 31 - 36 17 - 21 34 - 402009F Production (per day) 37 - 39 9 - 10 39 - 412008 Production (per day) 45 10 47 8%2008 Proved Reserves (mmbbl/bcf) 256 67 267 12%

Note: Production numbers reflect Q3/09 actual production, before royalties. All figures are before royalties.

Offshore West Africa Crude Oil Natural % of & NGLs Gas BOE Total

(mbbl) (mmcf) (6:1)2010B Production (per day) 29 - 34 20 - 24 32 - 382009F Production (per day) 32 - 34 17 - 19 35 - 372008 Production (per day) 27 13 29 5%2008 Proved Reserves (mmbbl/bcf) 157 107 175 8%

North America Crude Oil Natural % of & NGLs Gas BOE/d Total (mbbl/d) (mmcf/d) (6:1)

2010B Production - conventional (per day) 250 - 270 1,080 - 1,140 430 - 4602009F Production - conventional (per day) 233 - 236 1,279 - 1,285 446 - 4502008 Production - conventional (per day) 243 1,472 488 87%2008 Proved reserves - conventional (mmbbl/bcf) 1,057 4,077 1,737 80%

2010B Production - oil sands mining (bbl/d SCO) 90 - 105 90 - 1052009F Production - oil sands mining (bbl/d SCO) 50 - 54 50 - 542008 Proved SCO reserves (mmbbl) 1,946

Overview of TodayOverview of Today’’s Operationss Operations

Canadian Targeted Asset Base with Selected International Exposure

6


CNQ12

1-2 years 3-5 years BeyondNatural Gas Optimize Potential for >8,000 potential

returns 3-5% CAGR drilling locations

NA Oil Pelican / Primary 5-7% CAGR >20 years ofPrimrose development

International Free cash High return Major area forflow projects growth (acq)

Horizon Commence Expansion to 6 - 8 billion bbl*Phase 1 232 - 250 mbbl/d

*Includes estimated mineable reserves and contingent resources.

A Growing, Returns - Focused E&P Creating Significant Value

Essential Elements to Our Defined PlanEssential Elements to Our Defined Plan

CNQ13

Canadian Natural Gas AssetsCanadian Natural Gas Assets

NW AB441 mmcf/d

NE BC322 mmcf/d

Northern Plains340 mmcf/d

SE SK3 mmcf/d

Southern Plains

158 mmcf/d

0

400

800

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2,000

2000 2001 2002 2003 2004 2005 2006 2007 2008

Disciplined Development of Strong Gas AssetsNote: Reflects Q3/09 actual production, before royalties.

• 2010 plan–Maintain development of

growth projects–Expand inventory–High grade

drilling program and optimize production

7


CNQ14

Natural Gas Natural Gas Core Area SummariesCore 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• 14% average annual growth

since 2004• NE British Columbia

– Unconventional - Muskwa and Montney

• Low cost entry• NW Alberta

– Resource projects - Deep Basin and Montney

• Repeatable, large scale

Northern / Southern

Plains

NE BC

Foothills

NW AB

BCAB

CNQ Land

SK

Balanced, Cost Effective Growth

CNQ15

2010 Budget 2010 Budget Natural GasNatural Gas• Drilling

–Focus on drainage and expiries–Development of Septimus (BC Montney)–Strategic setup wells

• Capital –$674 million (~$495 million in 2009)

• Production–~1,110 mmcf/d midpoint average–13% annual decline–6% entry to exit decline

8


CNQ16

Natural Gas Production Base EvolutionNatural Gas Production Base Evolution

• 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 93 well drilling program in 2010, results in only a 13% midpoint production decline

0

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600800

1,000

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1,6001,800

2,000

Jan-

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Jul-0

4

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Jul-1

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-10

Pre 2006 drilling 2006 Drilling 2007 Drilling 2008 Drilling 2009 Drilling 2010 Drilling

Forecast

Production(mmcf/d)

Note: Includes production volumes from all acquisitions.

CNQ17

2010 Budget2010 BudgetLight OilLight Oil• Drilling

–121 wells (~42 wells in 2009)–New play development – 18 wells–EOR / waterflood / CO2 development

• Capital –$316 million (~$126 million in 2009)

• Production (excludes NGLs)

–~31,400 bbl/d midpoint average–4% annual decline–5% entry to exit growth

9


CNQ18

Heavy Oil AssetsHeavy Oil Assets• Reliable conventional

production• Pelican Lake EOR

development– Access additional 247 - 370

million barrels of resource potential

• Thermal in-situ development– Significant resource potential in

current plans– ~285,000 bbl/d of additional

in-situ production over next15 years

• Canadian Natural has competitive advantage via its vast land base

Birch Mountain(W. Horizon)

Gregoire

CNQ Land

Primrose(52 mbbl/d)

300 miles

Conventional Heavy Oil

(86 mbbl/d)

Kirby

Note: Reflects Q3/09 actual production, before royalties.

ABSK

Pelican Lake(37 mbbl/d)

Technology Option

CNQ19

2010 Budget 2010 Budget Primary Heavy OilPrimary Heavy Oil• Drilling

–2010 ~616 wells–2009 ~494 wells–2008 396 wells

• Recompletions - 450 wells• Capital

–$615 million (~$436 million in 2009)• Production

–~88,300 bbl/d midpoint average–3% annual growth–7% entry to exit growth

• Excellent return on capital in current environment

10


CNQ20

0

10,000

20,000

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99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16

Heavy Oil Heavy Oil Pelican LakePelican Lake

Produced to Date**127 mmbbl

How big is the reservoir?

How much of that oil is producible?

What method will be used to produce that oil?

*Includes proved and probable (December 31, 2008) reserves and contingent resources. **Estimated at December 31, 2008.

Future Primary*56 mmbbl

FuturePolymer,

Waterflood*399 mmbbl

OOIP* - 4.1 billion barrels Developed Region

Massive Resource to Exploit

Estimated FutureProduction*455 mmbbl

Produced to Date**127 mmbbl

(bar

rels

per

day

) Convert waterfloods to polymer

Polymer flood

Primary

Waterflood

• World class oil pool

• Efficient, low cost operations

• Polymer flood successful both technically and economically

• Technology enhancement will continue to improve oil recovery

CNQ21

2010 Budget 2010 Budget Pelican Lake, AlbertaPelican Lake, Alberta• Pelican Lake

–Drilling• 25 horizontal wells for primary production• 120 horizontal wells for polymer flood expansion

– Initiate development of nearby Wabiskaw heavy oil pools• Capital

–$466 million (~$240 million in 2009)• Production

–~39,600 bbl/d midpoint average in 2010 –8% annual growth–15% entry to exit growth

11


CNQ22

Thermal Heavy Oil Thermal Heavy Oil PotentialPotential

285,000 bbl/d incremental production

Estimated Bitumen in Place33 billion barrels total

ClearwaterPrimrose

11 billion barrels

KirbyGrouseLeismer

Birch MountainGregoire

McMurray22 billion barrels

Proved and ProbableReserves*

1.1 billion barrels

Estimated Ultimate Recovery5.6 billion barrels total

Contingent Resources4.5 billion barrels

*December 31, 2008.

33 Billion Barrels of Bitumen in Place

CNQ23

2010 Budget 2010 Budget Thermal Heavy Crude OilThermal Heavy Crude Oil• Drilling

–Strats 197 wells–Production/steam 28 wells

• Capital–~$500 million (~$418 million in 2009)

• Production–~86,900 bbl/d midpoint average–35% annual growth

12


CNQ24

Thermal Heavy Oil Thermal Heavy Oil Growth PlanGrowth Plan

Oil Production TargetPhase Capacity Timing

(bbl/d) (year)

1 Primrose North/South 80,000 On Stream2 Primrose East 40,000 On Stream3 Kirby 45,000 20134 Grouse 60,000 20145 Birch Mountain East 60,000 20166 Gregoire 1 60,000 20187 CSS - Follow-up Process 30,000 20188 Leismer 30,000 2020

405,000

• 30,000 - 60,000 bbl/d addition every 2 - 3 years

Growth for Decades

CNQ25

Heavy Oil Heavy Oil Three Pronged Marketing PlanThree Pronged Marketing Plan

Southern Access expansionTerasen Phase 1 expansion (Edmonton to Vancouver)

Cum

ulat

ive

Incr

emen

tal V

olum

e

DilSynbitWCS (Western Canadian Select)Synbit

Blending

Pipelines

Short TermUp to 5 years

Medium Term5 to 10 years

Pegasus (Patoka to USGC)Spearhead (Chicago to Cushing)

Long Term>10 years

Conversioncapacity

CNQ isblending

~ 138 mbbl/d

Keystone (TCPL pipeline to Patoka, Cushing, Port Arthur)Alberta Clipper (ENB pipeline) CNQ has

committed120 mbbl/d

CNQ has committed

25 mbbl/d onPegasus

West Coast options (Gateway, TMX)

Texas Access USGC

Additional refinery conversion capacityRefining: cokers / hydrocrackersUpgrading: bitumen / heavy oil

CNQ has committed

100 mbbl/d to USGC refiner

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

13


CNQ26

International OperationsInternational 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–2008/9 activity

• Baobab sand issues dealt with, optimize West Espoir4 wells drilled over 2008/09, restored production of11,000 bbl/d net to Canadian Natural

• Mature Olowi exploitation projectFirst production achieved April 2009

Focus on Free Cash Flow While Setting Up For Future Expansion

CNQ27

Canadian NaturalCanadian Natural’’s Mineable Assets s Mineable Assets --Horizon Oil SandsHorizon Oil Sands• Mining resources

–16 billion barrels in place*, with 6 to 8 billion barrels recoverable**• 2.9 billion barrels of net proved

and probable SCO• Phased development (SCO)

110 mbbl/d capacity(Phase 1)Expansion to 232 to 250 mbbl/dcapacity targetedFuture expansions to ~500 mbbl/d

• Significant free cash flow generation for decades

*Discovered initially-in-place estimate.**Includes mineable reserves and contingent resources.

World Class Opportunity - 40 Year Reserve ~500* mbbl/d -No Production Declines

UTS

SYN

SHC

SYN

SYN

DVN

PCASU

PCA

IOL

ECA

SU

SU

IOL

HSE

XOM

SHC

SU

SynencoSHC

XOM

ECA

ECA

Deer Creek

SU

UTS

SYN

SHC

SYN

SYN

DVN

PCASU

PCA

IMO

ECA

SU

SU

IMO

HSE

XOM

SHC

SU

SynencoSHC

XOM

ECA

ECA

TOT

SU

FortMcMurray

~43

mile

s

CNQCNQ

CNQHorizon

Oil Sands

14


CNQ28

Horizon Oil Sands Horizon Oil Sands 2010 Plan2010 Plan• Establish reliability on production

• Identify debottlenecking opportunities

• Complete lessons learned from Phase 1

• Continue Tranche 2 capital

• Engineering for Phase 2/3 expansion

CNQ29

Horizon Oil SandsHorizon Oil SandsProduction PlanProduction Plan• First synthetic production - February 28, 2009• Staged production

–Ramp up to full capacity of 110,000 bbl/d SCO throughout 2009 and mid 2010

• New equipment - may have premature failures• Fine tune plant to design rates and operational reliability

• 2009 production plan–Annual equivalent daily production of

50,000 to 54,000 barrels of SCO

• 2010 production plan–Annual equivalent daily production of

90,000 to 105,000 barrels of SCO

Ramp up Throughout Mid 2010

15


CNQ30

Canadian NaturalCanadian Natural2010 Overall Plan2010 Overall Plan1) Pay down debt2) Ramp up Horizon Oil Sands production

– Lessons learned, progress expansion cost estimate3) Conserve our land base

– Expiries– Drainage

4) Significant primary heavy oil program5) Progress thermal development6) Prepare Kirby for sanction7) Progress Pelican Lake polymer flood8) Increased focus on EOR in light oil projects9) Focus on value growth not production growth

Focus on Value Growth

CNQ31

Canadian NaturalCanadian Natural2010 Production Guidance2010 Production Guidance

2009F 2010B ChangeDaily Production Volumes (before royalties)

Natural Gas (mmcf/d)North American Natural Gas 1,279 - 1,285 1,080 - 1,140 (13%)North Sea 9 - 10 17 - 21 100%Offshore West Africa 17 - 19 20 - 24 22%

Total 1,305 - 1,314 1,117 - 1,185 (12%)

Crude Oil and NGLs (mbbl/d)North America - Conventional 233 - 236 250 - 270 11%North America – Oil Sands 50 - 54 90 - 105 88%North Sea 37 - 39 31 - 36 (12%)Offshore West Africa 32 - 34 29 - 34 (5%)

Total 352 - 363 400 - 445 18%

Production (mboe/d) 570 - 582 586 - 643 7%

16


CNQ32

2009F 2010B ChangeProduction (mboe/d) 570 - 582 586 - 643 7%

Cashflow ($mm)* $5,900 - $6,100 $6,500 - $6,900 12%

Capital ($mm)North American Natural Gas $495 $674 36%North American Crude Oil and NGLs $1,220 $1,900 56%North Sea $170 $199 17%Offshore West Africa $550 $264 (52%)Property Acquisitions $ 85 $100 18%Horizon $600 $785 31%

Total $3,120 $3,922 26%

Free cash flow ($mm)** $2,800 - $3,000 $2,600 - $3,000

Canadian NaturalCanadian Natural2010 Capital Budget2010 Capital Budget

7% Production Growth While Spending Only 60% of Cash Flow

*2010 based on WTI US$81.94 and NYMEX US$5.87.**Cash flow less Capital.

CNQ33

-$3.0

-$2.0

-$1.0

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

Cash Flow Capital Free Cash Flow

(C$billions)

Conventional

Horizon North SeaOffshore

West Africa

All Divisions Generating Free Cash Flow

45%

53%46% 60%

Canadian Natural Canadian Natural Free Cash Flow 2010Free Cash Flow 2010

% of Cash Flow

WTI US$81.94/bbl, AECO C$5.77/GJ.

17


CNQ34

Canadian Natural AssetsCanadian 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 - take production to ~500,000 bbl/d–Technology upside

Significant Upside

CNQ35

Canadian Natural AdvantageCanadian 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

18


CNQ36

Certain statements 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. 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.

These statements are not guarantees of future performance and are subject to certain risks and the reader should not place undue reliance on these forward-looking statements as there can be no assurance that the plans, initiatives or expectations upon which they are based will occur.

The forward-looking statements are based on current expectations, estimates and projections about Canadian Natural Resources Limited (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 factors 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 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.

Forward Looking StatementsForward Looking Statements

CNQ37

Special Note Regarding Currency, Production and ReservesIn 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.Canadian Natural retains qualified independent reserve evaluators to evaluate 100% of the Company’s conventional proved, as well as proved and probable crude oil, natural gas liquids and natural gas reserves and prepare Evaluation Reports on these reserves. Canadian Natural has been granted an exemption from National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. This exemption allows the Company to substitute United States Security and Exchange Commission (“SEC”) requirements for certain disclosures required under NI 51-101. There are three principal differences between the two standards. The first is the requirement under NI 51-101 to disclose both proved, and proved and probable reserves, as well as the related net present value of future net revenues using forecast prices and costs. The second is in the definition of proved reserves; however, as discussed in the Canadian Oil and Gas Evaluation Handbook (“COGEH”), the standards that NI 51-101 employs, the difference in estimated proved reserves based on constant pricing and costs between the two standards is not material. The third is the requirement to disclose a gross reserve reconciliation (before the consideration of royalties). Canadian Natural discloses its reserve reconciliation net of royalties in adherence to SEC requirements.The Company has disclosed proved conventional reserves and the Standardized Measure of discounted future net cash flows using year-end constant prices and costs as mandated by the SEC. The Company has elected to provide the net present value of these same conventional proved reserves as well as its conventional proved and probable reserves and the net present value of these reserves under the same parameters as additional voluntary information. In addition to the constant price and cost scenario, Canadian Natural has also elected to provide both proved, and proved and probable conventional reserves and the net present value of these reserves using forecast prices and costs as voluntary additional information.Conventional reserves and net present values of these reserves presented for years prior to 2003 were evaluated in accordance with the standards of National Policy 2-B which has now been replaced by NI 51-101. The stated reserves were reasonably evaluated as economically productive using year-end costs and prices escalated at appropriate rates throughout the productive life of the properties.

Canadian Natural’s independent reserve evaluators utilize the proved conventional reserve definition as prescribed by SEC in Regulation S-X 210.4-10 and the conventional proved and probable reserves definitions as prescribed under NI 51-101 in COGEH. Mining reserves are evaluated as prescribed in SEC Industry Guide 7. Internal estimates of Contingent Resources also utilize the definitions as prescribed under NI 51-101 in COGEH.

In this presentation Canadian Natural may disclose contingent resources as additional information. These are internal estimates that utilize the definition within section 5 of the COGE Handbook as prescribed under NI 51-101. Contingent resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Additionally engineering and geotechnical appraisal through drilling, testing and/or production is required before the contingent resources can be classified as reserves. There is no certainty that any portion of the resources will be commercially viable to produce. Estimated Ultimate Recovery ("EUR"), as defined by the Society of Petroleum Engineers/ World Petroleum Council/ American Association of Petroleum Geologists/ Society of Petroleum Evaluation Engineers Petroleum Resources Management System ("SPE-PRMS"), is the potentially recoverable accumulation that includes reserves, resources and quantities already produced. In this presentation, the EUR Canadian Natural discloses includes only reserves and contingent resources. Canadian Natural also discloses discovered petroleum initially in-place which is the quantity of petroleum that is within a known accumulation prior to production. There is no certainty that any portion of these volumes will be commercially viable to produce.Special Note Regarding non-GAAP Financial MeasuresManagement'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 DisclosuresReporting Disclosures

19


CNQ38

AppendicesAppendices

CNQ39

Annualized Sensitivity to PricesAnnualized Sensitivity to Prices

• Annualized and based upon Q3/09 business conditions and sales volumes but excluding financial derivatives

*Includes financial derivatives.

Variable Impact on Cash FlowWTI +/- US$1.00/bbl ~$100 millionAECO +/- C$0.10/mcf ~$23 million$0.01 change in US$* ~$82 million10,000 bbl/d change in crude oil production ~$150 million10 mmcf/d change in natural gas production ~$8 million

Significant Upside from Conservative Budget Price Deck

20


CNQ40

International North SeaInternational North Sea

• Exploitation base similar to WCSB

• Operate ~99% and own ~80% of production

• Infill drilling / recompletions & waterflood optimization

• 1 drill string operating in 2010

• 1 well and 3 well interventions

NinianMurchison

Strathspey

Columba

Lyell

TiffanyToniThelma

Kyle

Banff

NorthernNorth Sea

CentralNorth Sea

CNQ Lands Oil Field

Playfair

Edinburgh

Hutton

ScotlandAberdeen

Value Creation Through Exploitation Approach

CNQ41

InternationalInternationalOffshore Côte dOffshore Côte d’’IvoireIvoire• East Espoir

– First oil achieved in 2002– 4 infills drilled in 2005/6– FPSO expansion in 2009

• 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

Acajou

Atlantic Ocean

West EspoirEast Espoir

KossipoBaobab

Foxtrot

Mantra

Panthere

CNQ Lands Oil FieldGas FieldProspects

Acajou

Jacqueville

Côte d’Ivoire

Area for Light Oil Growth

21


CNQ42

International Offshore GabonInternational Offshore Gabon

• Olowi Field development plan– 12 miles offshore in

100 ft of water – Already delineated by 15 wells– 90% interest and operated

• First oil in April 2009– Oil leg below large gas cap– 34˚ API crude oil

SCM-2

SCM-1

MAZM-1

BIM-2BIM-3BIM-4

OLM-4

CMY-1

OLGNM-1 (ST-1)

OLM-1 (ST-1)

NYAM-1

OLOWI EEA

OLM-5

OLM-3

FABM-1

AWM-1

ARM-1THEMIS

DLM-1CTM-1

OLDM-1OLM-6

BIM-1 (B-15)

OLM-2

CHRM-1

OLOWI

GabonBIGORNEAU

Atlantic Ocean

Libreville (~545km)

Platform A

Platform B

Platform C (CSP)

Platform D

CNQ Lands

Olowi Field - Springboard Into Gabon

CNQ43

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

CNQ ECA* HSE CVE** DVN TLM APA SU EOG NXY

Developed Undeveloped

Natural Gas Natural Gas Competitive AdvantageCompetitive Advantage• Large land base provides

exposure to many play types– Conventional – Unconventional– Deep exploration

• Vast, cost effective infrastructure

– ~21,000 miles of pipe• Extensive seismic database

– >890,000 kilometers of 2D– >61,000 sq. kilometers of 3D

• Large balanced inventory• Excellent people

Note: Based on 2008 Annual Reports and ECA proxy circular for Cenovus transaction.

WCB Land Holdings (Thousands of Net Acres)

Strong Gas Assets

*New EnCana.**Cenovus Energy Inc.

22


CNQ44

Natural Gas Natural Gas Defined Resource PotentialDefined Resource Potential• Drilling activity

–67% conventional andshallow gas

• Resource growth–60% Deep Basin,

Montney/Muskwa

Shallow Gas Conventional Plains

Jean Marie

Deep Basin

Foothills

C Plains HSC CBM

Montney/Muskwa

Shallow GasConventional

Plains

Jean Marie Deep Basin

FoothillsC Plains HSC CBM

Montney/Muskwa

10 Year PlanNet Risked Resource Additions by Play

2.0

0.7

3.0

5.0 10 Year PlanNet Risked Drilling Locations by Play

(total 6,578 identified locations)*

* Canadian Natural operated.

Balanced Short, Mid and Long Term Growth

CNQ45

Resource Plays Exploration Volumes Resource Plays Exploration Volumes 10 Year Plan10 Year Plan• Key projects

–Deep Basin - NW AB–Montney - NE BC–Muskwa - NE BC

• 10 year plan–1,233 wells forecast–395 mmcf/d

incremental volume

Natural Gas Incremental Volumes (mcf/d)

*British Columbia only.

020406080

100120140160

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Muskwa Montney Deep Basin

Natural Gas Wells (number)

050,000

100,000150,000200,000250,000300,000350,000400,000450,000

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Muskwa Montney Deep Basin*

*

Disciplined Long Term Growth

23


CNQ46

Impact of Royalty Review Panel Impact of Royalty Review Panel Proposals on Conventional Natural GasProposals on Conventional Natural Gas

Shifted the gas price at which projects are economic upward

$8.00/mcf is now equivalent to $11.00/mcf$7.00/mcf= $9.13/mcf

Old RoyaltyNew Royalty

$/mcf

7.26

11.00

14.0

16.80

19.60

EconomicZone

CNQ47

Expanding Pipeline OptionsExpanding Pipeline Options

ChicagoCasper

Patoka

VancouverSuperior

ExistingLong Term Potential Approved/Proceeding

Fort McMurray

Cushing

Kitimat Edmonton

ENB Alberta Clipper / Southern Lights450 mbbl/d / 150 mbbl/d in Q2/2010

USGC

Denver WoodRiver

Hardisty

ENB Spearhead 195 mbbl/d

ENB Gateway400 mbbl/d Crude Export Line

XOM Pegasus95 mbbl/d

ENB/XOM Texas AccessUSGC 400 mbbl/d

TCPL Keystone to Cushing 160 mbbl/d in 2010/11

TCPL Keystone XL Pipeline~500 mbbl/d in 2011/12

Steele City

TMX Staged Expansion 525 mbbl/d

Kinder Morgan 300 mbbl/d

TCPL Keystone to Patoka 435 mbbl/d in 2009/10

ENB Southern Access Mainline StagedExpansion 800 mbbl/d in 2008/09

24


CNQ48

Heavy OilHeavy OilKeystone PipelineKeystone Pipeline• Transportation

– Committed 120,000 bbl/d to the Keystone Pipeline Expansion 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 major

US Gulf Coast refiner for 20 years

Q4-2010Q4-2012

Pipeline Access to New Market is Critical

Q4-2009

CNQ49

0%

10%

20%

30%

40%

50%

60%

Jan-

05M

ar-0

5M

ay-0

5Ju

l-05

Sep

-05

Nov

-05

Jan-

06M

ar-0

6M

ay-0

6Ju

l-06

Sep

-06

Nov

-06

Jan-

07M

ar-0

7M

ay-0

7Ju

l-07

Sep

-07

Nov

-07

Jan-

08M

ar-0

8M

ay-0

8Ju

l-08

Sep

-08

Nov

-08

Jan-

09M

ar-0

9M

ay-0

9Ju

l-09

Sep

-09

WCS at Hardisty Maya at USGC

Maya

Logistical Constraints

WCS

Heavy Oil DifferentialsHeavy Oil Differentials

Differential Impacted by Logistical Constraints

Q4 to Q1 Q2 to Q3

(% of WTI)

25


CNQ50

Pelican Lake Polymer FloodPelican 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 facilitiesare required?

– Water handling capability at batteries– Polymer skids

• What is the incremental capital cost?– $6.00 to $8.00/bbl oil recovered

• What is the incremental operating cost?– $0.40 to $0.60/bbl oil recovered

PolymerInjector

Oil Production

CNQ51

Pelican LakePelican LakeEOR PlanEOR Plan

Polymer flood by end 2008

2009 Polymer Plan

5 Year Polymer Plan

30 miles

Polymer Success Leads to Expansion

26


CNQ52

Polymer Flood OptimizationPolymer Flood Optimization

• Reservoir–Testing polymer response in portions of the pool with higher

oil viscosities–Evaluating the use of alkaline surfactants to reduce residual oil–Optimizing the type and quantities of polymer being used–Optimizing injected volumes within the well patterns

• Infrastructure–Designing / constructing larger mixing skids and

distribution systems–Mixing polymer with brackish reservoir water rather than fresh

water for injection–Maximizing water recycling–Optimizing facilities for fluid increases due to polymer response

Continued Technology Development

CNQ53

Thermal Heavy Oil Growth PlanThermal Heavy Oil Growth PlanFuture ProductionFuture Production

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

220,000

240,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Primrose

Kirby Grouse

Primrose Development

Birch Mtn

Production(bbl/d)

27


CNQ54

Thermal Heavy OilThermal Heavy OilRecovery SchemesRecovery Schemes

Cyclic Steam Stimulation (CSS)– Inject steam from a single

horizontal or vertical well– Can use high pressure– Requires solution gas drive– Wet steam SOR

(~1.25 dry steam SOR)

Steam Assisted Gravity Drainage (SAGD)– Continuous injection of steam into

upper well and gravity drainage to lower producer well

– Higher recovery factor– Clean, continuous reservoir

Match Scheme to Reservoir

CNQ55

• Primary recovery 5-15% OOIP leaving billions of barrels unrecovered

• Enhancing recovery• Underway

• Infill drilling 5-10 wells per acre

• Selective waterflood applications• Selective use of

horizontal drilling– EOR recovery processes

being evaluated• Hydrocarbon solvent injections• CO2 injection• Polymer flooding

Primary Heavy OilPrimary Heavy OilEnhanced RecoveryEnhanced Recovery

Enormous Potential - Low Cost Barrels

Heavy Oil Heavy Oil

28


CNQ56

Technology OptionTechnology OptionThermal GeoThermal Geo--steering Well Placementsteering Well Placement

Bitumen burner tip

Primrose North Steam Plant

Capturing More of the Reservoir With Technology Advancement

CNQ57

Thermal Heavy OilThermal Heavy OilTechnology AdvancementTechnology Advancement

Stage 1, CSS recovery factor 20%

ºCelsiusHorizontal Wells

Stage 2, Infill recovery factor 30%

Infill Well

Stage 3, Gravity Drainage recovery factor 40%

Injector WellInjector Well Producing Well

Technology Maximizes Recovery and Value

29


CNQ58

Horizon Oil SandsHorizon Oil SandsProcess and TechnologyProcess and Technology

Only Proven Technologies Will be Utilized Reducing Technology Risks

CNQ59

UTS

SYN

SHC

SYN

SYN

DVN

PCASU

PCA

IOL

ECA

SU

SU

IOL

HSE

XOM

SHC

SU

SynencoSHC

XOM

ECA

ECA

Deer Creek

SU

UTS

SYN

SHC

SYN

SYN

DVN

PCASU

PCA

IMO

ECA

SU

SU

IMO

HSE

XOM

SHC

SU

SynencoSHC

XOM

ECA

ECA

TOT

SU

FortMcMurray

~43

mile

s

CNQCNQ

CNQHorizon

Oil SandsUTS

SYN

SHC

SYN

SYN

DVN

PCASU

PCA

IOL

ECA

SU

SU

IOL

HSE

XOM

SHC

SU

SynencoSHC

XOM

ECA

ECA

Deer Creek

SU

UTS

SYN

SHC

SYN

SYN

DVN

PCASU

PCA

IMO

ECA

SU

SU

IMO

HSE

XOM

SHC

SU

SynencoSHC

XOM

ECA

ECA

TOT

SU

FortMcMurray

~43

mile

s

CNQCNQ

CNQHorizon

Oil Sands

Horizon Oil Sands Site LayoutHorizon Oil Sands Site Layout

Lease 11

Lease 12

Lease 15

Lease 10

Lease 19

Lease20

Lease 18

Lease25

Ath

abas

caR

iver

TailingsPond

NorthwestPit

Northeast Pit

SouthwestPit Southeast

Pit

Plant Site

OverburdenDump

OverburdenDump

HorizonLake

OverburdenDump

Site Layout Maximizes Resource Recovery and Optimizes Economic Returns

30


CNQ60

Horizon Oil SandsHorizon Oil SandsOperating CostsOperating Costs• Phase 1 costs are targeted to be between $35.00/bbl to $45.00/bbl in 2009

– Impacted by fixed cost effect and lower production• Life of mine operating costs

$1.87 Admin - Property tax increase $1.32, Technical Services increase $.33 due to headcount & transfers in of I.T. costs and other overhead costs, Business Services $.22 Insurance .

$2.83 Mine increases mainly due to overburden escalation costs, tires & parts increase and higher overheads.$1.42 Bitumen Production increase due to increases in contract costs, overheads as well as material & supplies higher than

expected.$2.93 Nat Gas Price from $7.03/GJ to $8.98/GJ ($58 W TI prior vs $85.73 WTI current)

Power from $56.27/MW to $89/MW$0.52 Utilities & Services increase due to transfer in of headcount, overheads as well as increases in contract costs.$0.07 Green House Gas increase $0.72 Upgrading increase due to increases in contract costs and higher overheads.

$10.36

Major Changes - Operating from October 2007

Direct Natural Imported Forecast Oct-07 VarianceCost Gas Power per bbl SCO Estimate

Mining 8.04$ 0.01$ 0.06$ 8.11$ 4.95$ 3.16$ Bitumen production 3.03$ 0.34$ 0.55$ 3.92$ 2.18$ 1.74$

Upgrading 2.47$ 4.18$ 0.34$ 6.99$ 4.83$ 2.16$ Utilities & Services 1.69$ 2.23$ 0.18$ 4.10$ 2.74$ 1.36$

Administration 4.87$ 4.87$ 2.99$ 1.87$ Environmental 1.32$ 1.32$ 1.25$ 0.07$

Total $/bbl for Average Life 21.42$ 6.76$ 1.12$ 29.30$ 18.94$ 10.36$

Average Sustaining Capital 1.90$ 1.80$ 0.10$

Current ForecastNovember 2008 Estimate @ 232,000 bbl/d

CNQ61

Horizon Oil SandsHorizon Oil SandsPhase 2/3 Phase 2/3 -- AdvantagesAdvantages• Site Labour Agreement in place (Division 8 legislation)• Experience running support programs

–Bussing–Fly in / out –Bringing on new contractors (new to Alberta and Canada)

• Long leads purchased–Hydrotreating reactors and coke drums on site–Delivery of absorber stripper in Q1/09

• Team in place

31


CNQ62

Horizon Oil SandsHorizon Oil SandsPhase 2/3 Phase 2/3 -- Development StrategyDevelopment Strategy• Established four tranches

–Tranche 1: completed $212 million• Engineering design specification for 232,000 bbl/d• Front end engineering and design • Coker foundations and some supporting infrastructure built• Long lead equipment ordered

(coke drums, reactors, mobile equipment)

–Tranche 2: under development• No production loss during first shutdown

(Third OPP & Hydrotransport)• Environmental commitments (Gas Recovery Unit,

third Sulphur Plant)• Increase reliability “Flood the Upgrader” (mine equipment)• Debottlenecking potential production gains of 5% to 15%

CNQ63

Horizon Oil SandsHorizon Oil SandsPhase 2/3 Phase 2/3 -- Development StrategyDevelopment Strategy

–Tranche 3• Transition to new tailings technology (reduce energy and op costs)• Additional mining equipment & shops• Coker expansion, CO2 recovery• Production increase by 10,000 to 20,000 bbl/d SCO

–Tranche 4: • Ore Preparation Plants (trains 4 & 5)• Extraction retrofit trains 1 & 2• Second Froth Treatment Plant• Vacuum Recovery Unit / Diluent Recovery Unit• Hydotreating (2 units) • Hydrogen Plant • Sulphur Plant (train 4)• Cogeneration and Heat Integration• Tankage• Production expansion to 232,000 to 250,000 bbl/d SCO

32


CNQ64

Revolving Bank Credit FacilitiesRevolving Bank Credit Facilities

(C$ millions) MaturityRevolving bank line - Conventional $ 2,230 June 2012Revolving bank line - Horizon Oil Sands $ 1,500 June 2012Operating demand loan $ 200 DemandNorth Sea operating line (£15 million) $ 26 DemandTotal bank lines $ 3,956

Available - September 30, 2009 $ 1,261

CNQ65

0

200

400

600

800

1,000

1,200

1,400

2010 2013 2016 2019 2022 2025 2028 2031 2035 2039

C$ Public US$ Public

Maturity ScheduleMaturity SchedulePublic DebtPublic Debt

(C$ millions)

Manageable RefinancingNote: Represents principal repayments only and does not reflect fair value adjustments, original issue discounts or transaction costs.

33


CNQ66

$3$4$5$6$7$8$9

$10

0%

20%

40%

60%

80%

100%

Q4/09 Q1/10 Q2/10 Q3/10 Q4/10

Collars Physical Sales MarketNote: Refer to quarterly reports for detailed hedging positions. Strip pricing as at Sep 30, 2009.

72% - Market 82% - Market

28% $5.29

83% - Market84% - Market

Strip Floor Ceiling

82% - Market

2009 Natural Gas Hedging 2009 Natural Gas Hedging AECO (C$/GJ)AECO (C$/GJ)2009 Natural Gas Hedging 2009 Natural Gas Hedging AECO (C$/GJ)AECO (C$/GJ)

Upside Opportunity, Downside Protection

17% $6.00 - 8.00 18% $6.00 - 8.0016% $6.00 - 8.00 18% $6.00 - 8.00

CNQ67

$50$60$70$80$90

$100$110$120

0%

20%

40%

60%

80%

100%

Q4/09 Q1/10 Q2/10 Q3/10 Q4/10Collars Puts Market

2009 Crude Oil Hedging 2009 Crude Oil Hedging WTI (US$/bbl)WTI (US$/bbl)

Note: Refer to quarterly reports for detailed hedging positions. Strip pricing as at Sep 30, 2009.

Strip Floor Ceiling Puts

~23% - $100.00

~71% - Market ~49% - Market

~23% $60.00 - $90.13

~53% - Market 89% - Market

Upside Opportunity, Downside Protection

76% - Market

~12% $65.00 - $105.49 ~11% $60.00 - $75.08

~13% $60.00 - $75.08

~6% $70.00 - $111.56~13% $65.00 - $105.49

~25% $60.00 - $90.13

~12% $60.00 - $75.08~12% $65.00 - $105.49

~12% $60.00 - $75.08

Special Note Regarding Currency, Production and ReservesIn 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.Canadian Natural retains qualified independent reserve evaluators to evaluate 100% of the Company’s conventional proved, as well as proved and probable crude oil, natural gas liquids and natural gas reserves and prepare Evaluation Reports on these reserves. Canadian Natural has been granted an exemption from National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. This exemption allows the Company to substitute United States Security and Exchange Commission (“SEC”) requirements for certain disclosures required under NI 51-101. There are three principal differences between the two standards. The first is the requirement under NI 51-101 to disclose both proved, and proved and probable reserves, as well as the related net present value of future net revenues using forecast prices and costs. The second is in the definition of proved reserves; however, as discussed in the Canadian Oil and Gas Evaluation Handbook (“COGEH”), the standards that NI 51-101 employs, the difference in estimated proved reserves based on constant pricing and costs between the two standards is not material. The third is the requirement to disclose a gross reserve reconciliation (before the consideration of royalties). Canadian Natural discloses its reserve reconciliation net of royalties in adherence to SEC requirements.The Company has disclosed proved conventional reserves and the Standardized Measure of discounted future net cash flows using year-end constant prices and costs as mandated by the SEC. The Company has elected to provide the net present value of these same conventional proved reserves as well as its conventional proved and probable reserves and the net present value of these reserves under the same parameters as additional voluntary information. In addition to the constant price and cost scenario, Canadian Natural has also elected to provide both proved, and proved and probable conventional reserves and the net present value of these reserves using forecast prices and costs as voluntary additional information.Conventional reserves and net present values of these reserves presented for years prior to 2003 were evaluated in accordance with the standards of National Policy 2-B which has now been replaced by NI 51-101. The stated reserves were reasonably evaluated as economically productive using year-end costs and prices escalated at appropriate rates throughout the productive life of the properties.Canadian Natural’s independent reserve evaluators utilize the proved conventional reserve definition as prescribed by SEC in Regulation S-X 210.4-10 and the conventional proved and probable reserves definitions as prescribed under NI 51-101 in COGEH. Mining reserves are evaluated as prescribed in SEC Industry Guide 7. Internal estimates of Contingent Resources also utilize the definitions as prescribed under NI 51-101 in COGEH.

Special Note Regarding Forward-looking StatementsCertain statements 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. 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.

These statements are not guarantees of future performance and are subject to certain risks and the reader should not place undue reliance on these forward-looking statements as there can be no assurance that the plans, initiatives or expectations upon which they are based will occur.

The forward-looking statements are based on current expectations, estimates and projections about Canadian Natural Resources Limited (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 factors 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 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 MeasuresManagement’s discussion and analysis includes references to financial measures commonly used in the crude oil and natural gas industry, such as cash flow from operations, adjusted net earnings from operations, 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 activities). 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 its performance. 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 September 30, 2009, 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) Oct 2009 – Dec 2009 25,000 bbl/d US$70.00 – US$111.56 WTI

Jan 2010 – Jun 2010 100,000 bbl/d US$60.00 – US$90.13 WTI

Jan 2010 – Dec 2010 50,000 bbl/d US$60.00 – US$75.08 WTI

Crude oil puts Oct 2009 – Dec 2009 92,000 bbl/d US$100.00 WTI

(1) Subsequent to September 30, 2009, the Company entered into 50,000 bbl/d of US$65.00 – US$105.49 WTI collars for the period January to September 2010.

At September 30, 2009, the net cost of outstanding put options to be settled during the fourth quarter of 2009 was US$61 million.

Remaining term Volume Weighted average price Index

Natural gas Natural gas price collars Jan 2010 – Dec 2010 220,000 GJ/d C$6.00 – C$8.00 AECO

The Company’s outstanding commodity derivative financial instruments are expected to be settled monthly based on the applicable index pricing for the respective contract month. There were no commodity derivative financial instruments designated as hedges at September 30, 2009. In addition to the derivative financial instruments noted above, the Company entered into natural gas physical sales contracts for 400,000 GJ/d at an average fixed price of C$5.29 per GJ at AECO for the period October to December 2009.

2003 2004 2005 2006 2007 2008

Operational Information

Daily production, before royaltiesCrude oil and NGLs (mbbl/d) 242 283 313 332 331 316Natural gas (mmcf/d) 1,299 1,388 1,439 1,492 1,668 1,495Barrels of oil equivalent (mboe/d) 459 514 553 581 609 565

Daily production, after royaltiesCrude oil and NGLs (mbbl/d) 220 256 283 301 293 276Natural gas (mmcf/d) 1,030 1,105 1,147 1,209 1,402 1,246Barrels of oil equivalent (mboe/d) 391 440 474 502 526 484

Proved reserves, before royaltiesCrude oil and NGLs (mmbbl) 1,000 1,123 1,223 1,487 1,543 1,470Natural gas (bcf) 3,154 3,310 3,490 4,613 4,435 4,251Barrels of oil equivalent (mmboe) 1,526 1,674 1,804 2,256 2,282 2,178

Proved reserves, after royaltiesCrude oil and NGLs (mmbbl) 895 1,066 1,118 1,316 1,358 1,346Natural gas (bcf) 2,588 2,690 2,842 3,798 3,666 3,684Barrels of oil equivalent (mmboe) 1,320 1,514 1,592 1,949 1,969 1,960

Mining reserves, SCO (mmbbl) 1,761 1,946

Drilling activity, net wellsCrude oil and NGLs 458 328 627 603 592 682Natural gas 777 689 890 641 383 269Dry 118 96 117 119 93 39Strats and service 440 336 248 375 254 131

Undeveloped land (thousands of acres)North America 9,811 11,523 10,947 12,785 12,160 11,603North Sea 573 565 352 299 287 258Offshore West Africa 943 886 426 207 192 192

Realized product pricing, before hedging activities & after transportation costsCrude oil and NGLs (C$/bbl) 32.66 37.99 46.86 53.65 55.45 82.41Natural gas (C$/mcf) 6.21 6.50 8.57 6.72 6.85 8.39

Results of operations (C$ millions, except per share)Cash flow from operations 3,160 3,769 5,021 4,932 6,198 6,969per share 5.88 7.03 9.36 9.18 11.49 12.89

Net earnings 1,403 1,405 1,050 2,524 2,608 4,985per share 2.62 2.62 1.96 4.70 4.84 9.22

Capital expenditures (net, including combinations) 2,506 4,633 4,932 12,025 6,425 7,451

Balance Sheet Info (C$ millions)Property, plant and equipment 13,714 17,064 19,694 30,767 33,902 38,966Total assets 14,643 18,372 21,852 33,160 36,114 42,650Long-term debt 2,748 3,538 3,321 11,043 10,940 12,596Shareholders’ equity 6,006 7,324 8,237 10,690 13,321 18,374

RatiosDebt to cash flow, trailing 12 months 0.9x 1.0x 0.7x 2.2x 1.8x 1.9xDebt to book capitalization 33% 34% 29% 51% 45% 41%Return to common equity, trailing 12 months 26% 21% 14% 27% 22% 33%Daily production before royalties per 10,000 common shares 8.5 9.6 10.3 10.8 11.3 10.4Proved and probable reserves before royalties per common share 4.0 4.3 4.8 6.4 6.3 6.1

Share information

Common shares outstanding 534,926 536,361 536,348 537,903 539,729 540,991Weighted average common shares 536,940 536,223 536,650 537,339 539,336 540,647Dividend per share (C$) 0.15 0.20 0.24 0.30 0.34 0.40TSX trading info

Average daily trading volume (thousands) 2,344 2,724 2,542 2,028 1,709 2,708High (C$) 16.81 27.58 62.00 73.91 80.02 111.30Low (C$) 11.30 15.96 24.28 45.49 52.45 34.19Close (C$) 16.34 25.63 57.63 62.15 72.58 48.75

Note: All per share data adjusted for 2004 and 2005 stock splits.

KEY HISTORIC DATA

Fourth Quarter 2009 2009 Forecast

Daily Production Volumes, (before royalties)Natural gas (mmcf/d)

North America 1,185 - 1,210 1,279 - 1,285North Sea 10 - 12 9 - 10Offshore West Africa 18 - 21 17 - 19

1,213 - 1,243 1,305 - 1,314Crude oil and NGLs (mbbl/d)

North America – Conventional 225 - 235 233 - 236North America – Oil Sands Mining 70 - 85 50 - 54North Sea 34 - 37 37 - 39Offshore West Africa 30 - 33 32 - 34

359 - 390 352 - 363Capital Expenditures, (C$ millions)Conventional

North America natural gas $ 495North America crude oil and NGLs 1,220North Sea 170Offshore West Africa 550Property acquisitions, dispositions and midstream 85

Conventional 2,520Horizon Oil Sands Project

Phase 1 – Construction 90Phase 1 – Operating inventory, capital inventory and commissioning costs 200Phase 2/3 – Tranche 2 135Sustaining capital 100Capitalized interest and other costs 75

Horizon Oil Sands Project 600

Total Capital Expenditures $ 3,120

Average Annual Cost DataRoyalty Operating

Rate Cost

Natural Gas - North America (mcf) 7 - 8% $1.05 - 1.10 Crude oil and NGLs (bbl)

North America – Conventional 13 - 15% $14.85 - 15.05 North America – Oil Sands Mining* 2 - 3% $35.00 - 45.00North Sea - $27.50 - 28.50 Offshore West Africa 6 - 9% $12.50 - 13.50

*Royalties are payable on the bitumen production

Other InformationCash income and other taxes (C$ millions)

Sask. Resources Surcharge/Capital Tax $20 - 30 Current income taxes – North America $15 - 20 Current income taxes – International $350 - 390Petroleum Revenue Tax (PRT) $65 - 85

Effective tax rate on adjusted earnings 26% - 30% Depletion, depreciation and ARO accretion charge ($/BOE) $13.10 - 13.50Midstream cash flow (C$ millions) $40 - 50 Average corporate interest rate 4.25% - 4.40%

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. 2009 revised based on an average annual WTI of $62.42/bbl, NYMEX of US$4.17/mmbtu and an exchange rate of US$0.88 to C$1.00.

November 5, 2009

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

Allan P. Markin, Chairman

John G. Langille, Vice-Chairman

Steve W. Laut, President & 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,Supervisor, Investor Relations(403) 514-7845

CANADIAN NATURAL RESOURCES LIMITED2500, 855 - 2nd Street S.W.,

Calgary, Alberta, T2P 4J8

Telephone: (403) 514-7777Facsimile: (403) 514-7888

Email: [email protected]

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