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THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT
VALUE CREATION RETURN ON CAPITAL LOW-COST PRODUCER RETURN ON ASSETS
The First Energy/The First Energy/SociSociééttéé GGéénnééraleraleCanadian Energy ConferenceCanadian Energy Conference
March 10-12, 2010
Based upon the following actual and strip pricing, including the impact of hedging2010F
Oil WTI (US$/bbl) $81.94Natural gas NYMEX (US$/mmbtu) $5.87Heavy oil diff (US$/bbl) $10.09C$/US$ $0.94
(1)
(1)
DELIVERING VALUE AND GROWTH
(1)
SNAPSHOT 2009 2010F
Cash flow (C$ millions) $6,090 $6,500 - $6,900
Per share - basic (C$) $11.24 $12.00 - $12.70
Capital expenditures (C$ millions) $2,997 $3,922
Dividend (C$/share) $0.42
Common shares (thousands) 542,327
Production (annual average, before royalties)Oil (mbbl/d) 355 400 - 445
Natural gas (mmcf/d) 1,315 1,117 - 1,185BOE (mboe/d) 575 586 - 643
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ1
Production Mix (2009)
North Sea7%
OffshoreWest Africa6%
NorthAmerica
87%
• Canadian based E&P company with international exposure
• ~US$45 billion enterprise value• ~575 mboe/d - 2009
– 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?
CNQ2
Production Reserves
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 100
100
200
300
400
500
600
700
B
• 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)
Daily Production (m
boe/d)Prov
ed R
eser
ves
(mm
boe)
Note: 2009 includes Horizon Oil Sands SCO reserves.
2
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ3
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
Consistent History of Value Creation
CNQ4
Historical Production GrowthHistorical Production Growth
(boe/d)
Canadian Natural Production - 1989 to Present
48%Oil
29%Gas
35%Oil
Significant Price Reduction
HorizonConstruction
47.5%DropIn Oil
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
Q1
- 89
Q1
- 90
Q1
- 91
Q1
- 92
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- 93
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Q1
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- 00
Q1
- 01
Q1
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- 07
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-08
Q1
- 09
Q1-
10B
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The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ5
A History of Value CreationA History of Value Creation
$0$2$4$6$8
$10$12$14$16
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009$0
$20$40$60$80
$100$120$140
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
0
24
6
810
12
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 20090
3
6
9
12
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Pretax Net Asset Value Per Share*
Actual 25% CAGR
Cash Flow Per Share*
Daily Production Per 10,000 Shares (boe/d)
Gross 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. Reserves include proved and probable. 2009 oil reserves include Horizon Oil Sands SCO.
21% CAGR21% CAGR
Consistent Growth
8% CAGR8% CAGR
17% CAGR17% CAGR
27% CAGR27% CAGR
CNQ6
Committed ManagementCommitted Management
$239 $223 $221$132 $111
$49 $32 $30
$374
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
CNQ DVN EOG APA APC PXD ECA NXY TLM CVE
• Substantial management and director wealth at stake
–Strong motivation for management to perform
–Delivers clear alignment with shareholder interests
Note: Peers based on share ownership data excluding options and priced at March 5, 2010.Source: Thomson Reuters.
Management / Directors Stock Ownership(US$ millions)
$1,652
Consistent History of Value Creation
4
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ7
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
CNQ8
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ9
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.
CNQ10
NW AB455 mmcf/d
15 mbbl/d
NE BC329 mmcf/d
5 mbbl/d
Northern Plains341 mmcf/d195 mbbl/d
SE SK3 mmcf/d8 mbbl/d
Southern Plains
158 mmcf/d11 mbbl/d
Oil Sands Mining 50 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 - 402009 Production (per day) 38 10 40 7%2009 Proved Reserves (mmbbl/bcf) 240 67 251 7%
Note: Production numbers reflect 2009 actual production, before royalties. Reserves are net of 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 - 382009 Production (per day) 33 18 36 6%2009 Proved Reserves (mmbbl/bcf) 123 85 137 4%
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 - 4602009 Production - conventional (per day) 235 1,287 450 78%2009 Proved reserves - conventional (mmbbl/bcf) 1,014 3,027 1,519 43%
2010B Production - oil sands mining (bbl/d SCO) 90 - 105 90 - 105
2009 Production - oil sands mining (bbl/d SCO) 50 50 9%2009 Proved SCO reserves (mmbbl) 1,650 46%
Overview of TodayOverview of Today’’s Operationss Operations
Canadian Targeted Asset Base with Selected International Exposure
6
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ11
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
CNQ12
Canadian Natural Gas AssetsCanadian Natural Gas Assets
NW AB455 mmcf/d
NE BC329 mmcf/d
Northern Plains341 mmcf/d
SE SK3 mmcf/d
Southern Plains
158 mmcf/d
0
400
800
1,200
1,600
2,000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Disciplined Development of Strong Gas AssetsNote: Reflects 2009 actual production, before royalties.
• 2010 plan–Maintain development of
growth projects–Expand inventory–High grade
drilling program and optimize production
7
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ13
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
CNQ14
2010 Budget 2010 Budget Natural GasNatural Gas• Drilling
–Focus on drainage and expiries–Development of Septimus (BC Montney)–Strategic setup wells
• Capital –$674 million
• Production–~1,110 mmcf/d midpoint average–14% annual decline–6% entry to exit decline
8
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ15
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
200400
600800
1,000
1,2001,400
1,6001,800
2,000
Jan-
04
Apr-
04
Jul-0
4
Oct
-04
Jan-
05
Apr-
05
Jul-0
5
Oct
-05
Jan-
06
Apr-
06
Jul-0
6
Oct
-06
Jan-
07
Apr-
07
Jul-0
7
Oct
-07
Jan-
08
Apr-
08
Jul-0
8
Oct
-08
Jan-
09
Apr-
09
Jul-0
9
Oct
-09
Jan-
10
Apr-
10
Jul-1
0
Oct
-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.
CNQ16
2010 Budget2010 BudgetLight OilLight Oil• Drilling
–121 wells (~42 wells in 2009)–New play development – 18 wells–EOR / waterflood / CO2 development
• Capital –$316 million
• Production (excludes NGLs)
–~31,400 bbl/d midpoint average–4% annual decline–5% entry to exit growth
9
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ17
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(64 mbbl/d)
300 miles
Conventional Heavy Oil
(86 mbbl/d)
Kirby
Note: Reflects 2009 actual production, before royalties.
ABSK
Pelican Lake(37 mbbl/d)
Technology Option
CNQ18
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• Production
–~88,300 bbl/d midpoint average–3% annual growth–7% entry to exit growth
• Excellent return on capital in current environment
10
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ19
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
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**140 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, 2009) reserves and contingent resources. **Estimated at December 31, 2009.
Future Primary*50 mmbbl
FuturePolymer,
Waterflood*510 mmbbl
OOIP* - 4.1 billion barrels Developed Region
Massive Resource to Exploit
Estimated FutureProduction*560 mmbbl
Produced to Date**140 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
CNQ20
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• Production
–~39,600 bbl/d midpoint average in 2010 –8% annual growth–15% entry to exit growth
11
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ21
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, 2009 net reserves.
33 Billion Barrels of Bitumen in Place
CNQ22
2010 Budget 2010 Budget Thermal Heavy Crude OilThermal Heavy Crude Oil• Drilling
–Strats 197 wells–Production/steam 28 wells
• Capital–~$500 million
• Production–~86,900 bbl/d midpoint average–37% annual growth
12
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ23
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
CNQ24
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
~ 140 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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ25
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
CNQ26
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**• 2.5 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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ27
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
CNQ28
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
50,250 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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ29
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
CNQ30
Canadian NaturalCanadian Natural2010 Production Guidance2010 Production Guidance
2009 2010B ChangeDaily Production Volumes (before royalties)
Natural Gas (mmcf/d)North American Natural Gas 1,287 1,080 - 1,140 (14%)North Sea 10 17 - 21 90%Offshore West Africa 18 20 - 24 22%
Total 1,315 1,117 - 1,185 (12%)
Crude Oil and NGLs (mbbl/d)North America - Conventional 235 250 - 270 11%North America - Oil Sands 50 90 - 105 95%North Sea 38 31 - 36 (12%)Offshore West Africa 33 29 - 34 (5%)
Total 356 400 - 445 19%
Production (mboe/d) 575 586 - 643 7%
16
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ31
2009 2010B ChangeProduction (mboe/d) 575 586 - 643 7%
Cashflow ($mm)* $6,090 $6,500 - $6,900 10%
Capital ($mm)North America - Conventional $1,714 $2,574 50%North Sea $168 $199 18%Offshore West Africa $544 $264 (51%)Property Acquisitions $18 $100 455%Horizon $553 $785 42%
Total $2,997 $3,922 31%
Free cash flow ($mm)** $3,093 $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.
CNQ32
-$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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ33
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
CNQ34
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ35
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
CNQ36
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ37
AppendicesAppendices
CNQ38
Annualized Sensitivity to PricesAnnualized Sensitivity to Prices
• Annualized and based upon Q4/09 business conditions and sales volumes but excluding financial derivatives
*Includes financial derivatives.
Variable Impact on Cash FlowWTI +/- US$1.00/bbl ~$109 millionAECO +/- C$0.10/mcf ~$33 million$0.01 change in US$* ~$96 million10,000 bbl/d change in crude oil production ~$161 million10 mmcf/d change in natural gas production ~$12 million
Significant Upside from Conservative Budget Price Deck
20
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ39
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
CNQ40
InternationalInternationalOffshore Côte dOffshore Côte d’’IvoireIvoire• East Espoir
– First oil achieved in 2002– 4 infills drilled in 2005/6– FPSO expansion
progressing in 2010• West Espoir development
– First oil achieved July 2006increased 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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ41
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
CNQ42
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ43
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
CNQ44
020406080
100120140160
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Muskwa Montney Deep Basin
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.
Natural Gas Wells (number)
*
*
Disciplined Long Term Growth
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
23
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ45
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
CNQ46
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 2012
Steele City
TMX Staged Expansion 525 mbbl/d
Kinder Morgan 300 mbbl/d
TCPL Keystone to Patoka 435 mbbl/d in 2009/10
24
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ47
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
CNQ48
0%
10%
20%
30%
40%
50%
60%
Jan-
05M
ar-0
5M
ay-0
5Ju
l-05
Sep-
05N
ov-0
5Ja
n-06
Mar
-06
May
-06
Jul-0
6Se
p-06
Nov
-06
Jan-
07M
ar-0
7M
ay-0
7Ju
l-07
Sep-
07N
ov-0
7Ja
n-08
Mar
-08
May
-08
Jul-0
8Se
p-08
Nov
-08
Jan-
09M
ar-0
9M
ay-0
9Ju
l-09
Sep-
09N
ov-0
9Ja
n-10
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ49
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
CNQ50
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ51
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
CNQ52
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ53
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
CNQ54
• 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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ55
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
CNQ56
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ57
Horizon Oil SandsHorizon Oil SandsProcess and TechnologyProcess and Technology
Only Proven Technologies Will be Utilized Reducing Technology Risks
CNQ58
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ59
$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 WTI 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
Horizon Oil SandsHorizon Oil SandsOperating CostsOperating Costs• Phase 1 costs were $39.89/bbl SCO in 2009 and are targeted to be between
$31.00/bbl to $37.00/bbl SCO in 2010– Impacted by fixed cost effect and lower production
• Life of mine operating costs
CNQ60
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ61
Horizon Oil SandsHorizon Oil SandsPhase 2/3 Phase 2/3 -- Development StrategyDevelopment Strategy• Established four tranches
–Tranche 1: completed $212 million• Engineering design specification for 232,000 bbl/d• Front end engineering and design • Coker foundations and some supporting infrastructure built• Long lead equipment ordered
(coke drums, reactors, mobile equipment)
–Tranche 2: under development• No production loss during first shutdown
(Third OPP & Hydrotransport)• Environmental commitments (Gas Recovery Unit,
third Sulphur Plant)• Increase reliability “Flood the Upgrader” (mine equipment)• Debottlenecking potential production gains of 5% to 15%
CNQ62
Horizon Oil SandsHorizon Oil SandsPhase 2/3 Phase 2/3 -- Development StrategyDevelopment Strategy
–Tranche 3• Transition to new tailings technology (reduce energy and op costs)• Additional mining equipment & shops• Coker expansion, CO2 recovery• Production increase by 10,000 to 20,000 bbl/d SCO
–Tranche 4: • Ore Preparation Plants (trains 4 & 5)• Extraction retrofit trains 1 & 2• Second Froth Treatment Plant• Vacuum Recovery Unit / Diluent Recovery Unit• Hydotreating (2 units) • Hydrogen Plant • Sulphur Plant (train 4)• Cogeneration and Heat Integration• Tankage• Production expansion to 232,000 to 250,000 bbl/d SCO
32
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ63
Revolving Bank Credit FacilitiesRevolving Bank Credit Facilities
(C$ 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) $ 25 DemandTotal bank lines $ 3,955
Available – December 31, 2009 $ 2,004
CNQ64
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
The First Energy/Société GénéraleCanadian Energy Conference
March 10-12, 2010
CNQ65
$3$4$5$6$7$8$9
$10
0%
20%
40%
60%
80%
100%
Q1/10 Q2/10 Q3/10 Q4/10Collars Physical Sales Market
Note: Refer to quarterly reports for detailed hedging positions. Strip pricing as at Mar 5, 2010.
83% - Market
~50% - Market~52% - Market
Strip Floor Ceiling
82% - Market
2009 Natural Gas Hedging 2009 Natural Gas Hedging AECO (C$/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 - 8.00~31% $4.50 - 6.30
18% $6.00 - 8.0017% $6.00 - 8.00
~18% $6.00 - 8.00~32% $4.50 - 6.30
CNQ66
0%
20%
40%
60%
80%
100%
Q1/10 Q2/10 Q3/10 Q4/10Collars Puts Market
$50$60$70$80$90
$100$110$120
2009 Crude Oil Hedging 2009 Crude Oil Hedging WTI (US$/bbl)WTI (US$/bbl)
Note: Refer to quarterly reports for detailed hedging positions. Strip pricing as at Mar 5, 2010.
Strip Floor Ceiling
~26% $60.00 - 90.13
~46% - Market ~52% - Market
~12% $60.00 - $75.08
~64% - Market78% - Market
Upside Opportunity, Downside Protection
~12% $65.00 - $105.49~13% $65.00 - $105.49~2% $60.00 - $105.15
~24% $60.00 - $90.13~13% $60.00 - $75.08
~12% $65.00 - $105.49 ~11% $65.00 - $108.94
~12% $60.00 - $75.08
~12% $65.00 - $108.94 ~11% $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 March 4, 2010, the Company had the following net derivative financial instruments outstanding to manage its commodity price exposures:
Remaining term Volume Weighted average price Index
Crude oil Crude oil price collars Jan 2010 – Mar 2010 6,000 bbl/d US$60.00 – US$105.15 WTI
Jan 2010 – Jun 2010 100,000 bbl/d US$60.00 – US$90.13 WTI
Jan 2010 – Sep 2010 50,000 bbl/d US$65.00 – US$105.49 WTI
Jan 2010 – Dec 2010 50,000 bbl/d US$60.00 – US$75.08 WTI
Jul 2010 – Dec 2010 50,000 bbl/d US$65.00 – US$108.94 WTI
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
Apr 2010 – Sep 2010 400,000 GJ/d C$4.50 – C$6.30 AECO
2004 2005 2006 2007 2008 2009
Operational Information
Daily production, before royaltiesCrude oil and NGLs (mbbl/d) 283 313 332 331 316 355Natural gas (mmcf/d) 1,388 1,439 1,492 1,668 1,495 1,315Barrels of oil equivalent (mboe/d) 514 553 581 609 565 575
Daily production, after royaltiesCrude oil and NGLs (mbbl/d) 256 283 301 293 276 318Natural gas (mmcf/d) 1,105 1,147 1,209 1,402 1,246 1,214Barrels of oil equivalent (mboe/d) 440 474 502 526 484 525
Proved reserves, after royaltiesCrude oil and NGLs (mmbbl) 1,066 1,118 1,316 1,358 1,346 1,377Natural gas (bcf) 2,690 2,842 3,798 3,666 3,684 3,179Barrels of oil equivalent (mmboe) 1,514 1,592 1,949 1,969 1,960 1,907Mining reserves, SCO (mmbbl) 1,761 1,946 1,650
Drilling activity, net wellsCrude oil and NGLs 328 627 603 592 682 644Natural gas 689 890 641 383 269 109Dry 96 117 119 93 39 46Strats and service 336 248 375 254 131 329
Undeveloped land (thousands of acres)North America 11,523 10,947 12,785 12,160 11,603 10,651North Sea 565 352 299 287 258 150Offshore West Africa 886 426 207 192 192 192
Realized product pricing, before hedging activities & after transportation costsCrude oil and NGLs (C$/bbl) 37.99 46.86 53.65 55.45 82.41 57.68Natural 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 6,090per share 7.03 9.36 9.18 11.49 12.89 11.24
Net earnings 1,405 1,050 2,524 2,608 4,985 1,580per share 2.62 1.96 4.70 4.84 9.22 2.92
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 39,115Total assets 18,372 21,852 33,160 36,114 42,650 41,024Long-term debt 3,538 3,321 11,043 10,940 12,596 9,658Shareholders’ equity 7,324 8,237 10,690 13,321 18,374 19,426
RatiosDebt to cash flow, trailing 12 months 1.0x 0.7x 2.2x 1.8x 1.9x 1.6xDebt 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 9.6 10.3 10.8 11.3 10.4 10.6Proved and probable reserves before royalties per common share* 4.3 4.8 6.4 6.3 6.1 11.5*2009 Horizon SCO included in Crude Oil and NGL’s reserves
Share information
Common shares outstanding 536,361 536,348 537,903 539,729 540,991 542,327Weighted average common shares 536,223 536,650 537,339 539,336 540,647 541,925Dividend per share (C$) 0.20 0.24 0.30 0.34 0.40 0.42TSX trading info
Average daily trading volume (thousands) 2,724 2,542 2,028 1,709 2,708 2,072High (C$) 27.58 62.00 73.91 80.02 111.30 79.00Low (C$) 15.96 24.28 45.49 52.45 34.19 35.85Close (C$) 25.63 57.63 62.15 72.58 48.75 76.00
Note: All per share data adjusted for 2004 and 2005 stock splits.
KEY HISTORIC DATA
First Quarter 2010 2010 GuidanceDaily Production Volumes, (before royalties)Natural gas (mmcf/d)
North America 1,165 - 1,185 1,080 - 1,140North Sea 14 - 16 17 - 21Offshore West Africa 18 - 20 20 - 24
1,197 - 1,221 1,117 - 1,185Crude oil and NGLs (mbbl/d)
North America – Conventional 240 - 250 250 - 270North America – Oil Sands Mining 70 - 90 90 - 105North Sea 34 - 37 31 - 36Offshore West Africa 28 - 32 29 - 34
372 - 409 400 - 445Capital Expenditures, (C$ millions)Conventional
North America natural gas $ 674North America crude oil and NGLs 1,900North Sea 199Offshore West Africa 264Property acquisitions, dispositions and midstream 100
Conventional 3,137Horizon Oil Sands Project
Phase 2/3 – Tranche 2 479Phase 2/3 – Engineering 95Sustaining capital 164Capitalized interest and other costs 47
Horizon Oil Sands Project 785
Total Capital Expenditures $ 3,922
Average Annual Cost DataRoyalty Operating
Rate Cost
Natural Gas - North America (mcf) 11 - 13% $1.15 - 1.25 Crude oil and NGLs (bbl)
North America – Conventional 17 - 19% $13.00 - 14.00North America – Oil Sands Mining* 4 -5% $31.00 - 37.00North Sea - $31.00 - 35.00 Offshore West Africa 7 - 9% $14.00 - 17.00
*Royalties are payable on the bitumen production, royalty rate shown is imputed on SCO barrel.
Other InformationCash income and other taxes (C$ millions)
Sask. Resources Surcharge/Capital Tax $30 - 40 Current income taxes – North America $450 - 550 Current income taxes – International $220 - 260Petroleum Revenue Tax (PRT) $45 - 75
Effective tax rate on adjusted earnings 26% - 30% Depletion, depreciation and ARO accretion charge ($/BOE) $13.80 - 14.30Midstream cash flow (C$ millions) $40 - 50 Average corporate interest rate 5.00% - 5.50%
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. 2010 budget based on an average annual WTI of $82.00/bbl, NYMEX of US$6.00/mmbtu and an exchange rate of US$0.94 to C$1.00.
March 4, 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
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,Supervisor, Investor Relations(403) 514-7845
Leah LoyolaAnalyst, Investor Relations (403) 514-7911
CANADIAN NATURAL RESOURCES LIMITED2500, 855 - 2nd Street S.W.,
Calgary, Alberta, T2P 4J8
Telephone: (403) 514-7777Facsimile: (403) 514-7888
Email: [email protected]
THE PREMIUM VALUE DEFINED GROWTH INDEPENDENT
WWW.CNRL.COM