Directive 54 - CNRL 2012 PAW Annual Review Surface

Premium Value Defined Growth Independent

2012 Primrose, Wolf Lake, and Burnt Lake Annual Presentation to the ERCB

Surface Operations, Compliance and Issues Not Related to Resource Evaluation and Recovery

January 24, 2013

CNQSlide 2

Directive 54: Performance Presentations, Auditing, and Surveillance of In Situ Oil Sands Schemes

• January 23, 2013

3.1.1 Subsurface Issues Related to Resource Evaluation and Recovery

• January 24, 2013

3.1.2 Surface Operations, Compliance, and Issues Not Related toResource Evaluation and Recovery

Primrose, Wolf Lake, and Burnt LakeAnnual Presentation to the ERCB for 2011Primrose, Wolf Lake, and Burnt LakeAnnual Presentation to the ERCB for 2011

CNQSlide 3

• FacilitiesPlot Plans, Simplified Plant Schematic, Modifications and Updates

• Facility PerformanceOil & Water Treatment, Steam & Power GenerationGas Usage, Greenhouse Gas Emissions

• Measurement & ReportingWell Production Estimates, Proration factors, Test Durations, New Measurement Technology

• Water Production, Injection, and UsesUWIs, Water Uses and Water QualityFresh, Brackish, Steam and Produced Water Volumes & ForecastsBrackish Water SupplyUWIs & Disposal Well ComplianceWolf Lake Disposal & Water Storage VolumesWolf Lake Waste Disposal

• Sulphur ProductionSummary and Discussion of Emissions

Page5-9

10-1112-14

15-17

18-1920-2223-25

2627-32

33

34-38

Outline - Surface Operations, Compliance, and Issues Not Related to Resource Evaluation and RecoveryOutline - Surface Operations, Compliance, and Issues Not Related to Resource Evaluation and Recovery

CNQSlide 4

• Environmental SummaryCompliance Issues & AmendmentsMonitoring ProgramsReclamationRegional InitiativesArsenic MonitoringGroundwater Monitoring at E14 PadPrimrose East Risk Management PlanPad 75 Update

• Well & Formation Integrity• Abandonments• Approval Condition Compliance

Approvals (9140P, 9108, 8186A, 8672A, 8673, 3929A, 4128D, 9792A)

• Discussion of Non-Compliance ItemsSelf Disclosures

• Future Plans

Page39

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47-5051-52

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55-6364

65-72

73-74

75-76

Outline - Surface Operations, Compliance, and Issues Not Related to Resource Evaluation and RecoveryOutline - Surface Operations, Compliance, and Issues Not Related to Resource Evaluation and Recovery

CNQSlide 5

FacilitiesFacilities

• Detailed Site Survey Plans - refer to included drawings:Wolf Lake Plant Plot PlanPrimrose Plant Plot Plans (South, North, East)Typical Pad Plot Plan (Primrose East)

• Simplified Plant Schematic - refer to included drawings:Wolf Lake / Primrose Simplified Plant Facilities Schematic

• Summary of ModificationsWolf Lake Brackish Water Expansion – Phase 1– Completion of the project started in 2011. Project involved the addition of brackish water

tank, VRU, pumps, piping, heater exchangers, pick heaterWolf Lake Unit 8 DCS Upgrade– Replaced obsolete control system in Wolf Lake Plant Unit 8 (part of multi-year program)

Wolf Lake Slop Oil Treatment System– Added a centrifuge for slop oil treatment

Wolf Lake Unit 2 Separator Replacement– Replacement of an existing damaged inlet separator

CNQSlide 6

FacilitiesFacilities

• Summary of Modifications (cont’d)Wolf Lake Oil Debottlenecking – Numerous upgrades to improve oil treating. Including a new ORF in unit 10, sales pump

in Unit 8, various vessel control valve upsizingWolf Lake Salt Cavern Returns– Installed a salt cavern booster pump and made provisions for future filtration

CNQSlide 7

Specific Project UpdatesSpecific Project Updates

• Wolf Lake Slop Treatment ModificationsCentrifuge construction complete to treat slop oil (ie oil, water, solids, rag layers, emulsion) from all unitsCentrifuge to separate oil, water, slurrySlurry to be injected to existing salt cavernsSystem currently involved in commissioning

• Brackish Water Expansion – Phase 1Project to increase peak supply/treating/handling capacity to 35,000 m3/dInvolves 3 new brackish water wells on existing locations tied into the existing pipelinePlant upgrades include new 20,000 bbl tank, inlet skid and piping, pumps, VRU, steam heating and inlet to Unit 3 WLS, inlet and exchanger to Unit 8 skim tankProject completed and operational

CNQSlide 8

Primrose East Sulphur TreatmentPrimrose East Sulphur Treatment

• Temporary produced gas sweetening at Primrose EastSteam plant was shutdown on June 2, 2011 and restarted on February 7, 2012 for reservoir management

Produced gas was conserved by sending it to Primrose South as sweet fuel gas

A compressor, two phase separator, and liquid H2S scavenger system were installed

Flared for first 2 months of steam plant outage due to construction delays

System started on July 28, 2011 and was commissioned with sweet gas

Flared intermittently due to compressor issues/servicing, Primrose South outages, pigging of the gas pipeline and start up/shutdown of the steam plant

System shutdown on February 7, 2012 and decommissioned

CNQSlide 9

Primrose East Sulphur Treatment (con’t)Primrose East Sulphur Treatment (con’t)

• Prior to system start up (June 2, 2011 – July 27, 2011)Total sulphur flared: ~29 Tonnes

• System online (July 28, 2011 – February 6, 2012)Total sulphur removed: ~28 Tonnes

Total sulphur flared: ~13 Tonnes

CNQSlide 10

Facility PerformanceFacility Performance

• Bitumen and Water TreatmentOverall water quality and oil treating targets were generally met:– Experienced some treating and produced water de-oiling challenges due to low inlet

production temperatures (low produced water volumes and cooler Primrose East emulsion temperatures).

– Recycling of slop and skimmed oil is causing treating and rag layer issues. Problem is being mitigated by addition of slop oil treatment unit. Currently in commissioning phase. Slop oil treatment unit will be functional in Q1 2013.

Performance testing indicated additional available capacity in existing oil treating system. Wolf Lake debottlenecking project is nearing completion.Successfully completed Unit 8 oil side turnaround this year.

• Steam GenerationOverall steam generation targets were met:– Primrose South & North achieved 98.1% of budget injected steam volumes– Primrose East steam plant was shut down for a total of 39 days at the beginning of 2012

to allow depletion of the areaCorrosion and erosion issues in the steam piping systems caused production losses due to maintenance and repair outagesSix economizer tube failures at PSP contributed to unplanned downtimeHRSG tube sheet failure at PSP contributed to power disruptions

CNQSlide 11


• Power Generation/Consumption on a monthly basis

CNQSlide 12


• Gas Usage on a monthly basis

Month

Total Purchased Gas

Total Solution Gas Conserved

Total Gas Vented

Total Solution Gas

FlaredSolution Gas

Conserved

e3m3 e3m3 E3m3 e3m3 %

January 92,882 24,942 13 246 99.0%

February 105,719 23,816 13 553 97.7%

March 138,352 25,227 611 32 99.9%

April 123,915 24,627 44.51 1,437 94.2%

May 130,400 23,231 8 1,042 95.5%

June 133,213 24,647 12 175 99.3%

July 129,780 25,551 6 165 99.3%

August 116,428 23,823 5 1,207 94.9%

September 114,584 27,414 1.5 105 99.5%

October 126,818 31,476 0.4 47 99.8%

November 122,500 22,741 9 125 97.7%

December 124,869 25,498 4 392 98.5%

*Total purchased gas does not include gas from site gas wells *Solution gas flared volumes are corrected to remove purchased gas to flare*Total gas vented includes brackish water associated vent gasNotes: 1) Brackish usage increased in March 2012. New VRU commissioned April 24, 2012.

CNQSlide 13

• Flaring & Solution Gas Conservation ComplianceAll Primrose and Wolf Lake facilities are equipped for gas conservation except one pilot well, 15BM – granted exemption in 2004New pads (since 2004) are built with VRUs or are linked to a neighboring pad’s VRU

• Solution Gas Flare VolumesConserved ~ 97.9% of total Primrose and Wolf Lake solution gas in 2012

• Facility Venting ComplianceNo routine venting in the field No routine venting at Primrose North, South or East plantsVapour recovery on all major sources of solution gas at Wolf Lake Plant


CNQSlide 14

Facilities – Greenhouse Gas EmissionsFacilities – Greenhouse Gas Emissions

• PAW Greenhouse Gas Emissions

*2012 November and December emission is estimated using the average of the previous 3 months

Month 2012(tCO2e)

Jan 240,863

Feb 248,972

Mar 313,518

Apr 286,850

May 297,670

Jun 302,987

Jul 299,681

Aug 271,505

Sep 274,301

Oct 302,522

Nov* 282,776

Dec* 286,533

Year Total 3,408,177

CNQSlide 15

• Measurement, Accounting & Reporting Plan (MARP) for Wolf Lake / Primrose Thermal Bitumen Scheme Approved May 1st, 2007. Annual updates in March.

• Methods for estimating well production and injection volumes reported to the RegistryProduced emulsion from the scheme is commingled at the battery. Bitumen and water production from the battery is prorated to each well using monthly proration test data and proration factors.

– Total Battery Oil (Water) / Total Test Oil (Water) at Wells = Oil (Water) Proration Factor– Oil (Water) Proration Factor * Each Well Test Oil (Water) Volume = Oil (Water) Allocated to Each

Well Gas allocated to each well is determined by GOR (gas oil ratio) for the battery

– Total Solution Gas Produced / Total Battery Oil = Gas Oil Ratio– Gas Oil Ratio * Oil Allocated to Each Well = Gas Allocated to Each Well

Injected volumes of steam and water are not estimated, they are continuously measured at wellheadSome pads have capability to take steam from Primrose South or Primrose North Steam Plant. Estimating steam transfer volume from combined proration factor for both plants.

• Test DurationsThrough experience, CNRL field operations has identified the test durations, gross fluid rates and BS&W results required to obtain valid proration test data for each well. Most wells have 4 hour proration test durations; however some wells may be tested from 1 to 6 hours depending on their unique operating conditions and cycle maturity. Each well is tested each month and may be tested several times over the month.

Measurement and ReportingMeasurement and Reporting

CNQSlide 16

Measurement and Reporting – Proration FactorsMeasurement and Reporting – Proration Factors

CNQSlide 17

Measurement and ReportingMeasurement and Reporting

• New Measurement Technology– Installed multi-phase flow metering technology.

– Conducting field tests since mid-2012. Tests will be continued into 2013.

– Objective is to identify a multi-phase flow meter which provides adequate performance and accuracy to replace the traditional test separator system for multiple wells

– Installed a new nuclear level technology for interface control on one inlet separator vessel at Wolf Lake for improved interface level control. Proceeding with installation on other vessels.

– Installing low flow steam meters on new pads for improved measurement accuracy at low flows.

CNQSlide 18

• Primrose & Wolf Lake Project Water Well UWI ListingESRD fresh water well license renewed in 2012Primrose wells are utility use only

Fresh WSW Brackish WSW

Wolf Lake Primrose Grand Rapids McMurray

1F1/12-10-066-05W4M 1F1/10-05-67-04W4 102/10-08-66-5W4M 1F3/10-03-67-4W4M

1F2/12-10-066-05W4M 1F1/14-05-67-04W4 102/05-16-66-5W4M 1F1/11-06-67-3W4M

1F1/06-10-066-05W4M 1F2/15-05-67-04W4 104/05-16-66-5W4M 1F1/16-12-67-4W4M

1F2/06-10-066-05W4M 04-14-67-03W4 109/01-17-66-5W4M 1F1/11-05-67-3W4M

1F1/13-10-066-05W4M NW 08-068-04W4 107/02-17-66-5W4M 1F2/13-08-67-3W4M

1F2/13-10-066-05W4M NW 08-068-04W4 106/08-17-66-5W4M 1F1/14-08-67-3W4M

107/08-17-66-5W4M 1F1/12-09-67-3W4M

1F2/12-09-67-3W4M

1F1/10-08-67-3W4M

1F1/02-12-67-3W4M

1F1/07-06-67-3W4M

Water Production, Injection, and UsesWater Production, Injection, and Uses

CNQSlide 19


• Fresh water usesUtility water, utility steam, seal flush and gland water, slurry make-up, dilution water, filter backwash, quench water, miscellaneous –ends up as boiler feed water Water softener regenerations – some of this water is recycled as boiler feed water and some is used as cavern wash and then sent to disposalFresh water may also be used for boiler feed water make-up as required

• Brackish water usesDe-sand quench, filter backwash –ends up as boiler feed waterBoiler feed water make-up supply

• Water Quality AssessmentQuaternary Water Source Wells (6)

– Empress Unit 3 & Muriel Lake Formations– Average TDS = 609 mg/L, TDS ranges from 575 to 640 mg/L

Grand Rapids Fm. Water Source Wells (7)– Average TDS = 9,721 mg/L, TDS ranges from 8,900 to 10,300 mg/L

McMurray Fm. Water Source Wells (10)– Average TDS = 7,276 mg/L, TDS ranges from 6,470 to 8,570 mg/L

Produced Water Quality– Typical parameters: TDS = 7,102 mg/L, Cl = 3,700 mg/L, pH 7.3, hardness = 99 mg/L

CNQSlide 20


• Fresh, brackish, produced and steam injection volumes

CNQSlide 21

• Long term make-up yearly requirements approximately 35,000 m3/d• Reduction of fresh groundwater use – down to 3,000 m3/d in mid-2014

Excludes Surface Water and Cold Lake Fish Hatchery Effluent VolumesExcludes Surface Water and Cold Lake Fish Hatchery Effluent Volumes


CNQSlide 22

• PAW water volume summary for 2012Wolf Lake Fresh Water - Average 9,427 m3/dGrand Rapids Brackish Water - Average 920 m3/dMcMurray Brackish Water - Average 18,089 m3/dBurnt Lake Pilot Water – Cold Lake Fish Hatchery Effluent Diversion - Average 837 m3/dPlant Runoff Water – Average 352 m3/d


No runoff data before 2006No runoff data before 2006

CNQSlide 23

• Brackish to Fresh Groundwater Ratio Increase in brackish use compared to 2011 (19,065 vs. 13,512 m3/d) Average brackish to fresh groundwater ratio was 2.02 in 2012 (1.64 in 2011)

Excludes Cold Lake Fish Hatchery Effluent VolumesExcludes Cold Lake Fish Hatchery Effluent Volumes


CNQSlide 24

McMurray Fm Basal Aquifer Isopach Map - targeted due to prolific nature of aquifer

25 m Contour

IOR Pumping Centre

06-30 Obs Well

CNRL McMurray Wells

McMurray Brackish Water Supply – ExistingMcMurray Brackish Water Supply – Existing

• Producing wells3 Horizontals and 7 Verticals3 vertical wells brought online in Q1 2012

• 2012 production average – 18,089 m3/dmaximum – 30,222 m3/d

• Drawdown of 69 m in obs well 6-30 (6 km from pumping centre)

14-02 Obs Well

CNQSlide 25

McMurray Brackish Water Supply – Phase 2 ExpansionMcMurray Brackish Water Supply – Phase 2 Expansion

• Phase 2 ExpansionDevelop new pumping centre in NW67-3 and SW68-3

– away from planned CSS development

– following basal aquifer fairway north of existing pumping centre (PC1)

– add up to six water wellsRefurbishment of old pipeline Construction of new pipeline and roads in 2013/2014Constraints

– Geology– Thermal development– Target circle– Mineral and surface rights

System operational by end of Q2 2014

CNRL McMurray Wells

August 2010

C-314 Target Circle

PC2

PC1

CNRL McMurray Wells

C-314 Target Circle

PC2

PC1

CNRL McMurray Wells

C-314 Target Circle

PC2

PC1

CNQSlide 26

Wolf Lake Primrose South Primrose East

WDW#1 - 100090806605W400 103100506704W400 100031106703W400

WDW#2 - 100100806605W400 1F1110206703W400

WDW#4 – 100050806605W400

WDW#5 - 100150706605W400

WDW#9 - 100140506605W400

• Primrose & Wolf Lake Project Disposal Water Well UWI Listing Wells shown in bold are active, (Wolf Lake - WDW#1 and WDW#9 are zonally abandoned)

• Wolf Lake (WDW #2, 4, & 5)Disposal scheme was amended on June 16/10 to allow injection into WDW #4 (Approval 8672A). Maximum wellhead injection pressures decreased from 17,500 kPa to 13,770 kPa; with the ability to inject at 17,500 kPa for a maximum time period of 24 hrs.– Injection pressures have not exceeded 13,770 kPa in WDW #2, 4, or 5 in 2012.

• Primrose SouthInjected 0 m3 fluid in 2012

• Primrose East11-2 out of service since August 2007. Abandonment work still outstanding. Ongoing discussions with ERCB

Water & Waste Disposal Wells, Landfill Waste UWI List & Disposal ComplianceWater & Waste Disposal Wells, Landfill Waste UWI List & Disposal Compliance

CNQSlide 27

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Disposal VolumesWater & Waste Disposal Wells, Landfill Waste Wolf Lake Disposal Volumes

2012 Average Monthly Disposal Rates, Temperature and Pressure

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WDW #2: 2012 Average Monthly Disposal Rates, Temperature and Pressure

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CNQSlide 28

• Water is stored in the C3 Formation

Converted two wells to injectors in June 2003

• Injected 348,255 m3 total189,085 m3 to M2-S159,170 m3 to M2-E

• M2-E and M2-S are currently configured for short notice injection M2-S

M2-E

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Water StorageWater & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage

CNQSlide 29

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage VolumesWater & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage Volumes

Wolf Lake Water Storage Volumes

Year MonthGross (m3/d)

Oil (m3/d)

Water (m3/d)

Water Inj (m3/d)

Gross (m3/d)

Oil (m3/d)

Water (m3/d)

Water Inj (m3/d)

2003 21 2 20 243 40 1 39 2922004 0 0 21 28 0.2 28 492005 0.3 420062007 146 174200820092010 16 0.032011 5.39 0.142012 Jan 13.74 0

Feb 19.14 0Mar 0 0Apr 6.90 0.33May 0 0Jun 0 0Jul 0.32 0.32Aug 0 0Sep 0 0Oct 12.90 0Nov 9.33 0.33Dec 0 0

M2_E M2_S

CNQSlide 30

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage ComplianceWater & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage Compliance

• Formation Integrity and Pressure MonitoringOffset well reservoir pressures never exceeded the 2.5 MPa allowable during injection periodsM2-E injection packer successfully passed packer isolation test in 2012M2-S injection packer successfully passed packer isolation test in 2012No wellbore integrity issues encountered

• Wolf Lake Water Storage – ReservoirM2 & N2 Cumulative DI = 1.26

– Cumulative Gross Production = 12,535,817 m3

– Cumulative Oil Production = 1,539,321 m3

– Cumulative Steam Injected = 9,915,737 m3 CWE– Cumulative Water Injected = 348,235 m3

M2 & N2 Remaining Voidage = 2,271,845 m3

(CWE) Injected Steam TotalWater)(Bitumen Produced Fluid Total DI

CNQSlide 31

• From the outlined area (M2 wells and N2-F)

Total Injected Water = 348,235 m3

since Jan ’03Total Produced Water = 592,374 m3

since Jan ’03Difference = 244,139 m3

• Expected to have minimal water storage in 2013.

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage BalanceWater & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage Balance

CNQSlide 32

• Injectors appear to communicate readily with offset wells

• No problems anticipated when pumping out injected water

• Intend to maintain two wells as short notice injectors

• Expect to have minimal produced water storage in 2013

• M2-E and M2-S are classified as disposal wells on S-4 forms

Water & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage SummaryWater & Waste Disposal Wells, Landfill Waste Wolf Lake Water Storage Summary

CNQSlide 33

• Waste to CCS Lindbergh Cavern107,125 m3– liquid wastes including drilling wastes for PAW production (new pads) and OSE

• Waste to CCS Bonnyville Landfill4,918 m3 – contaminated soil59,944 tonnes - lime sludge waste

• Waste to RBW845 m3 solid waste – contaminated soils, plastics, filters inorganic chemicals, asbestos, scrap metal, glycol, caustics

• Waste to NewAlta 3,178 m3 – sludges822 m3 – coemulsion

Water & Waste Disposal Wells, Landfill Waste Waste Disposal SummaryWater & Waste Disposal Wells, Landfill Waste Waste Disposal Summary

CNQSlide 34

Sulphur ProductionSulphur Production

• EPEA approval limits for SO2: PSP + WLP = 6.7 t/dPNP = 2.0 t/dPEP = 2.0 t/d

• CEMS values are used for reporting at all steam plantsPNP from September 1, 2010 onwardPEP, PSP, and WLP from April 1, 2011 onward

• Quarterly averages for all steam plants < 1.0 t/d sulphur

• Contingency for compliance with ID 2001-3 is currently to restrict/delay production to maintain sulphur level below 1 t/d quarterly average

CNQSlide 35

Sulphur Recovery StudySulphur Recovery Study

• ObjectiveQ4 2012 decision to proceed or not proceed with Sulphur Recovery at any one or all Primrose Steam Plants

• RequirementsSelection of Optimal Technology– Liquid ScavengerEconomic Assessment of Delayed Oil vs. Sulphur Recovery – Based on April 2012 10 Year Plan and Sulphur Model

• ConclusionDo not proceed with Sulphur Recovery at any of the Primrose Plants at this time

CNQSlide 36


CNQSlide 37


• To maintain sulphur levels below 1 t/d, production from the following wells/pads were held back in Q1 2012:

Month of February:– Last 2 weeks of February:

• Primrose South Pad 28 S & N held back 4,590 m3 oil production• Primrose North Pads 62 & 66 held back 1,070 m3 oil production• Township 68 pads held back 5,660 m3 oil production

Month of March:– Week of March 1:

• Primrose South Phases 13, 14, 28 S & N held back production» Production held back: 5,100 m3 oil

• Township 68 south 3 pads held back production: 5,100 m3 oilProduction limitations lifted March 9, 2012

CNQSlide 38


• To maintain sulphur levels below 1 t/d, production from the following wells/pads were held back in Q1 2012 (Cont):

Production limitations reinstated for March 20 - 28, 2012Pads affected are as follows:

– Primrose North Plant (excluding Township 68 pads) – Held back 175 m3 of oil– Primrose South Plant – Held back 800 m3 of oil– Primrose North Plant Township 68 pads – Held back 975 m3 of oil

CNQSlide 39

• Compliance IssuesEPEA Approval: Air Related

– OTSG NOx exceedance later verified and followed up as non-exceedance (Primrose East June 2, 2012)

– Heat recovery steam generator Continuous Emissions Monitoring System availability uptime <90% (Primrose South Dec 19, 2012)

Water Related:– Runoff pond licensing discrepancies (April 19, 2012 Primrose North and East plant) – E-Pond high pH water discharge (July 22, 2012 Primrose East)– WSW daily limit exceedance (Sept 11, 2012 Wolf Lake Plant)– WSW daily limit exceedance (Dec 4, 2012, PRS)– WSW daily limit exceedance (x5) (Dec 13, 2012, PRS).

Notice of Investigation – Surface Runoff Ponds– Primrose North and East runoff ponds investigation – use of runoff water without Water

Act approval– Water Act Approval subsequently obtained for runoff ponds

Administrative Penalty – unauthorized installation (2008) and operation of the Wolf Lake 4 flare stack

Environmental SummaryCompliance & AmendmentsEnvironmental SummaryCompliance & Amendments

CNQSlide 40

• Environmental Monitoring Programs currently underway include:Wildlife Monitoring ProgramWildlife Mitigation PlanWildlife Habitat Enhancement ProgramWetlands and Hydrology Monitoring Program

Environmental SummaryMonitoring ProgramsEnvironmental SummaryMonitoring Programs

CNQSlide 41


• Objectives of Wildlife Monitoring ProgramTo determine if the PAW project has an influence on the abundance and distribution of wildlife species;

The effectiveness of crossing structures; and

Distribution and movement of caribou.

• Wildlife Monitoring Program activities for 2012:Breeding songbird surveys

– 58 transects surveyedWinter track surveys

– 36 transects surveyedWoodland caribou cameras

– 41 remote cameras deployed for 12 weeks along eastern and northern boundaries of Project Area to capture seasonal movement of caribou in the fall.

CNQSlide 42


• Wildlife Mitigation Plan activities in 2012Remote Camera Monitoring of Above-Ground Pipeline

– 30 remote cameras deployed along AGP to record wildlife behaviour and confirm wildlife movement under the AGP

– 30 remote cameras deployed along game trails or cutlines near remote camera areas on the AGP to record wildlife occurrence and behaviour as animals approach the pipeline

Wildlife Winter Tracking Along AGP– 38.6 km of AGP surveyed, noting movement patterns and wildlife behavioural

responses near the AGP

• Wildlife Habitat Enhancement ProgramNest Box Program

– 20 nest boxes maintained to confirm bird use during the breeding season. 30% showed evidence of use.

Revegetation Program– No activities in 2012; activities planned for 2013

CNQSlide 43

• Hydrology, Wetlands and Water Quality Monitoring Program 20122012 was the 6th year of the Hydrology Monitoring component which provides monitoring for lakes within the PAW development area.

Water quality program (started in 2009) continued surface water quality data collection from Burnt Lake and Sinclair Lake

– ESRD approved reduction of sampling events from 3 to 2– Sampling locations and depths did not change from 2011 to 2012


CNQSlide 44


• Preliminary ResultsHydrology Program

– Looseman Lake and North Reference Lake experienced average lake levels lower than the August 1, 2007 reference level. This may be attributed to changing outlet conditions or lower seasonal inputs.

Wetland Monitoring Program– 2012 re-measurement of wetland sites indicates only small differences in

species richness among monitoring and reference sites.

Water Quality Program– To-date, no large deviation was observed for surface water quality samples from

Burnt Lake and Sinclair Lake.– Phenol concentrations at Burnt Lake were at or above guideline concentrations

in a majority of samples.– Total phosphorus at or above guideline concentrations at Sinclair Lake.– Continued monitoring will determine if these results are indicative of a trend.

CNQSlide 45

• Reclamation activities in 2012:Reforested 13.6 ha of borrows in Primrose South. Infill planting on 10 ha of borrows in Primrose South and East.Total of 23.60 ha using 11,305 Trees and Shrubs.

• Proposed activities in 2013:Reforestation of 32.70 ha of Borrows in Primrose East.Planting of 0.52 ha Linear disturbances and 0.8 ha of non-linear disturbances as part of our Habitat Enhancement Program.

Environmental SummaryReclamation ProgramsEnvironmental SummaryReclamation Programs

CNQSlide 46

• LICA Airshed ZoneLICA is responsible for monitoring regional air qualityCurrently four continuous monitoring sites (Cold Lake, Maskwa, St. Lina and Portable), 26 passive stations, two VOC and PAH samplers, and two soil acidification monitoring plots distributed throughout the region.

• Beaver River Watershed Alliance (BRWA):The BRWA serves as the Watershed Planning and Advisory Council (as set out by Alberta Environment) for the Beaver River Watershed The BRWA State of the Watershed Report to be published spring 2013 provides a snapshot of watershed health and will act as the guiding document for development of the upcoming Water Management Plan for the Beaver River watershed.

Environmental SummaryRegional InitiativesEnvironmental SummaryRegional Initiatives

CNQSlide 47

• Arsenic Liberation in GroundwaterEvaluate liberation of arsenic associated with elevated groundwater temperatures from steamingZ8 Investigation ongoing since 2001Measure arsenic concentration and temperature in 30 wells – focus on 10 Empress Fm Wells ~ 150 m depthTemporal assessments associated with steaming

• Results - Empress Formation

Background 75 m down-

gradient

360 m down-

gradientTemp 5.2 deg C 30.4 deg C 9.4 deg C

As Conc

0.041 mg/L 0.131 mg/L 0.056 mg/L

Sept to Nov 2012Sept to Nov 2012

Environmental SummaryMonitoring - Dissolved Arsenic Z8 PadEnvironmental SummaryMonitoring - Dissolved Arsenic Z8 Pad

CNQSlide 48

• Groundwater In-Situ Temperatures - Empress Formation - Overall down-gradient thermal plume migration- Temperatures decrease with distance from the Pad- Temperatures are increasing over time


CNQSlide 49

Z8-03 E1

• Groundwater Dissolved Arsenic Concentrations – Empress Formation- Overall down-gradient dissolved arsenic plume migration- Concentrations increasing at down-gradient wells - Dissolved arsenic concentrations at Z8-23 (135m) and Z8-25 (160m) are greater than

Z8-21 (75m)


CNQSlide 50

• Summary of Z8 Pad Field Findings – Empress FormationIncreasing temperatures and concentrations at wells show that thermal and dissolved arsenic plumes are migrating down-gradient Dissolved arsenic concentration 135 m down-gradient of Pad is just greater than approximately 4 times backgroundDissolved arsenic plume expected to eventually detach from Pad as plume migrates down-gradient (no steaming since 2005)Arsenic plume leading-edge is likely greater than 360 m down-gradient

• Program for New Monitoring WellsSelected locations for two new Empress Formation monitoring wells (downgradient and cross-gradient) – expect to undertake in 2013

• Ongoing WorkContinued temperature and arsenic monitoringRegional Quaternary geology review Ongoing monitoring of arsenic in CNRL regional monitoring network


CNQSlide 51

Groundwater Monitoring at E14 PadGroundwater Monitoring at E14 Pad

16-32a16-32a

• A groundwater monitoring well was installed at E14 Pad (16-32-065-05W4M) as per the amendment to the Commercial Scheme Approval 9140I for SIB Pad

– Installed on the south side of the pad in July 2010 to monitor for changes in the basal quaternary aquifer associated with SIB operation

– Completed into the basal aquifer identified as the Muriel Lake (121 to 127 metres below ground surface)

– Instrumented to monitor water levels and temperatures

– Sampled semi-annually as part of regional groundwater monitoring program

NN SIBSIB

E14E14

CNQSlide 52

Groundwater Monitoring at E14 PadGroundwater Monitoring at E14 Pad

• Groundwater Monitoring Results for 16-32a - Anomalous water levels not noted- In-situ groundwater temperature at 7°C- Anomalous groundwater chemistry not noted (comparable to regional results Muriel

Lake Formation chemistry)

CNQSlide 53

Primrose East Pad 74 Risk Management PlanPrimrose East Pad 74 Risk Management Plan• The Primrose East groundwater management is continuing• Ongoing application of the Pad 74 Risk Management Plan

including:• Ongoing daily pressure and temperature monitoring in 24 wells on site• Ongoing monthly and quarterly groundwater sampling• Monthly reporting of Primrose East Area 1 (including Pad 74)

groundwater chemical analytical results (ERCB and ESRD)

• Monitoring and sampling results are reported annually to ESRD via PAW EPEA Approval since March 2012.

• Elevated dissolved solids and dissolved hydrocarbons have been noted in the past but currently neither exceed Tier 1 criteria.

CNQSlide 54

Pad 75 UpdatePad 75 Update• Elevated dissolved solids and dissolved hydrocarbons noted in

the Bonnyville Aquifer at Pad • Source believed to be release of BFW or produced water from

18A75 due to a casing breach• In 2012 remediation was initiated - pumped water from

Bonnyville Aquifer at three wells:• 05-12h July 11 through 24, 2012• 05-12g July 30 through October 22, 2012• 05-12f August 4 through October 22, 2012

• Recovered 235 m3 groundwater in total• Recovery system shut down for the winter on October 22, 2012• Pumping will resume in June 2013• Ongoing reporting to ESRD and ERCB

CNQSlide 55

• Out of Zone Casing Failures:There are 13 out of zone casing failures in PAW in 2012

Well Integrity- Summary of 2012 Casing FailuresWell Integrity- Summary of 2012 Casing Failures

Passive Seismic on Pad 66 damaged Jan 2012

CNQSlide 56

Well Integrity- Summary of 2012 Casing FailuresWell Integrity- Summary of 2012 Casing Failures• Out of Zone Casing Failures:

Current status of 2012 out of zone casing failures

`

No high pressure well failures in 2012

All 2012 out of zone casing failures were at the connection

Well Primary/Slimhole

Tubular OD (mm) Failure In: Confirmation

DateCycle of Failure:

Well Phase During Failure Current Status

8C28 P 244.5 CONN 13-Feb-12 3 Pump Patched18A78 P 244.5 CONN 20-Feb-12 3 Pump Slimhole11A74 P 244.5 CONN 28-Feb-12 4 Pump On Production - Fluid Level Below Break14A77 P 244.5 CONN 28-Feb-12 3 Pump Slimhole4C28 P 244.5 CONN 23-Mar-12 3 Pump/WKO Patched8B51 P 244.5 CONN 17-May-12 3 Pump Zonally suspended6A66 P 244.5 CONN 30-May-12 5 Pump/WKO Slimhole

14A66 P 244.5 CONN 16-Jul-12 5 Pump Slimhole12A66 P 244.5 CONN 8-Aug-12 5 Pump/WKO Slimhole7A77 P 244.5 CONN 6-Sep-12 4 Pump On Production - Fluid Level Below Break

15A62 P 244.5 CONN 20-Sep-12 5 Pump Slimhole14A63 P 244.5 CONN 30-Sep-12 3 Pump Zonally suspended4B29 P 244.5 CONN 20-Dec-12 4 Pump Zonally suspended

CNQSlide 57

• In Zone Casing Failures:There are 18 confirmed in zone casing failures in 2012

Well Integrity- Summary of 2012 Casing FailuresWell Integrity- Summary of 2012 Casing Failures

Majority of the in zone failures were at TWP 68

CNQSlide 58

Well Integrity- Summary of 2012 Casing FailuresWell Integrity- Summary of 2012 Casing Failures• In Zone Casing Failures:

Current status of 2012 in-zone casing failures

Well Primary/Slimhole

Tubular OD (mm) Failure In: Confirmation

DateCycle of Failure:

Well Phase During Failure Current Status

1A77 P 244.5 CONN 21-Mar-12 3 Pump/WKO Casing patch9C28 P 244.5 CONN 4-Apr-12 3 Pump Zonally suspended3A67 P 244.5 UNKNOWN 18-May-12 3 Pump/WKO Zonally suspended

11A62 P 244.5 UNKNOWN 19-May-12 5 Pump/WKO Zonally suspended1C27 P 244.5 CONN 8-Jun-12 4 Pump/WKO Casing patch

13A58 P 244.5 CONN 8-Jun-12 5 Pump/WKO Casing patch2C27 P 244.5 BODY 20-Jun-12 4 Pump Casing patch

13A62 P 244.5 CONN 10-Jul-12 5 Pump Initial mitigation was to slimhole2A67 P 244.5 Unknown 25-Jul-12 3 Steam Zonally suspended5A67 P 244.5 UNKNOWN 25-Jul-12 3 Pump Mech Plug9A63 P 244.5 CONN 22-Aug-12 3 Steam Casing patch

15A63 P 244.5 UNKNOWN 31-Aug-12 3 Trickle Steam Casing patch13A63 P 244.5 CONN 4-Oct-12 3 Steam On Production - Low Pressure16A63 P 244.5 UNKNOWN 10-Oct-12 3 Steam Casing patch10A63 P 244.5 CONN 2-Dec-12 3 Trickle Steam Casing patch10A59 P 244.5 CONN 13-Dec-12 3 Trickle Prod Casing patch12A63 P 244.5 CONN 14-Dec-12 3 Trickle Steam Casing patch6A63 P 244.5 CONN 17-Dec-12 3 Trickle Prod Casing patch

CNQSlide 59

Well and Formation IntegrityLogsWell and Formation IntegrityLogs

• Casing Pressure MonitoringNo casing failures were detected via DFP (differential flow pressure)

• Corrosion LogsA Vertilog was run in Primrose East well 11A78 in response to investigating a near surface casing failure at ~61m MD

• No significant corrosion was observed from TD to surface

- A Vertilog was run on water source well 110 – Corrosion was found at ~450m at the pump landing depth

• Internal corrosion of the 273mm production casing occuring within the formation

– Design of future water source wells under review by the team to address this issue

CNQSlide 60

• Cement Bond Logs (CBL)100% of all new wells in 2012 had cement bond logs run (160 total)

– 160 CSS down to the Clearwater Formation– Directive 51 applications were submitted for 9 pads

• 9 applications were approved by the ERCB84 other wells had cement bond logs run in 2012 (All casing failures had a cement bond log run for investigative and/or post repair purposes)

– 13 post steam CBL’s were run for investigative purposes on well with up-hole casing failures

– CBL’s run at Primrose East:• 17 CBL’s were run on observation wells • 43 CBL’s were run for investigative purposes on burnt lake primary wells

– CBL’s run at Primrose South:• 11 CBL’s were run on observation wells

Well and Formation IntegrityLogsWell and Formation IntegrityLogs

CNQSlide 61

Well and Formation IntegrityCasing and Cementing investigationsWell and Formation IntegrityCasing and Cementing investigations

• Review of casing failures at the BFS had indicated a correlation to collars placed within 4m of the BFS and failures of those collars.

Drilling program has been modified to ensure a casing collar is not placed within 4m of the BFS

• Review of casing failures at the CLWR top indicate that the connection closest to the shale/sand interface is most likely to fail

• Other drilling changes:Increased centralization through BFS and CLWR shale top

– BFS – to improve cement bond– CLWR – to decrease differential sticking to ensure rotation while cementing

CNQSlide 62

• Thermal fibre gives us the ability to monitor for fluid migration attributed to inferior cement jobs

• Thermal fibre is CNRL’s preferred method for fluid monitoring within the Colorado Shales

• Monitoring to date has shown no issues during steaming or production

• Data quality is acceptable, in that temperature profiles are repeatable

Formation IntegrityThermal FibreFormation IntegrityThermal Fibre

CNQSlide 63

Formation IntegrityB12 Pressure MonitoringFormation IntegrityB12 Pressure Monitoring

• B12 pressure monitoring has proven to be an effective addition to formation integrity surveillance during high pressure CSS

Under certain circumstances it can be difficult to distinguish heave from fluid invasion based on B12 pressure alone

– Pressure anomalies in the B12 must be examined in conjunction with all available data to determine pressure response sources:

• Passive seismic, thermal fiber, injectivity plots, production data

Continue to obtain data to quantify the poro-elastic heave pressures in the B12 (Lower Grand Rapids) during high pressure CSS steaming

Primrose East, Township 68, Phase 28 and Phases 22-24 all are currently equipped with B12 monitoring equipment

– All new pads are equipped with B12 pressure monitoring

CNRL shall notify the ERCB if a B12 pressure increase/decrease is greater than 200 kPa/day

CNQSlide 64

• There were 3 wells abandoned in 2012 in the Primrose/Wolf Lake area.

• CNRL plans to review all suspended wells to determine which wells require abandonment in order to ensure compliance to ERCB Directive 13 requirements

Well and Pad AbandonmentsWell and Pad Abandonments

CNQSlide 65

ApprovalsApproval 9140P – Oil Sands Primrose Wolf Lake ApprovalsApproval 9140P – Oil Sands Primrose Wolf Lake

CNQSlide 66

• Original Approval – August 2002• Amendment A - Approved October 2003

Approval to conduct Gas and Gas Solvent enhanced recovery pilot

• Amendment B - Approved January 2004Approval to develop PRN and decrease production volume to 14,000 m3/d

• Amendment C - Approved March 2007Approval for PRE and increase production volume to 19,000 m3/dApproval for Orange Valley Sand Phases 41-50 and Blue Valley Sand Phases 8, 9, 11, 12 (West)

• Amendment D - Approved March 2007Approval to expand the development area to include 67-5W4MApproval 6804 (Burnt Lake rescinded)

• Amendment E - Approved March 2008Pads 58, 62, 66 modification to development plan

• Amendment F - Approved August 2008Pads 59, 63, 7 modification to development plan

• Amendment G - Approved February 2010Approval for McMurray MC1 SAGD Pad

Approval 9140P – Oil Sands Primrose Wolf Lake Approval 9140P – Oil Sands Primrose Wolf Lake

• Amendment H - Approved July 2010Approval for Grand Rapids S1B SAGD Pad

• Amendment I - Approved September 2010Approval for PRS Phases 22-24

• Amendment J - Approved November 2010Approval for PRE Development Area 2

• Amendment K - Approved December 2010Approval for Trim Treating during PEP Steam Outage

• Amendment L - Approved August 2011Approval for modification of PRE Phases 90/91 drainage boxes

• Amendment M - Approved October 2011Approval for PRS Phases 25/26Approval for PRN Phases 60, 61, 64, 65 & 68

• Amendment N - Approved February 2012Approval for PRS D1 Steamflood Trial

• Amendment O - Approved May 2012Approval for Wolf Lake Sparky B8 Trial

• Amendment P - Approved November 2012Approval for Primrose South Phases 40-43

CNQSlide 67IN COMPLIANCE

• Annual Report(a) Summary of monthly injected and

produced volumes/well(b) Well/Formation Integrity(c) Reservoir Water Storage remaining(d) Water Balance, Bitumen Volumes

and Incremental Recovery(e) Overall performance and 2012 plans(f) Discussion of produced water

utilization & fresh water reductions

Approval 9108 – Wolf Lake Water StorageApproved July 2002 Approval 9108 – Wolf Lake Water StorageApproved July 2002

CNQSlide 68

• Approval Compliance RequirementsDirective 51 ComplianceMaximum Injection Pressures (kPa)

– F1/11-02-067-03W4/0 = 7800– 00/03-11-067-03W4/0 = 5500

• Injection packer isolation test failed on 11-2 in 2008

Well currently shut-inWork in progress

• No disposal in 2012 as water is now recovered and re-used

IN COMPLIANCE

Approval 8186A – Burnt Lake Water DisposalApproved February 1999 Approval 8186A – Burnt Lake Water DisposalApproved February 1999

CNQSlide 69

• Approval Compliance Requirements Directive 51 Compliance

• Operational injection pressure limit 13,770 kPa

• Maximum injection pressure 17,500 kPa for a 24 hour period

• Disposal wells are:WDW#1 - 00/09-08-066-05W4/0WDW#2 - 00/10-08-066-05W4/0WDW#4 - 00/05-08-066-05W4/0WDW#5 - 00/15-07-066-05W4/0WDW#9 - 00/14-05-066-05W4/0

IN COMPLIANCE

Approval 8672A – Wolf Lake Deep DisposalApproved June 2010 Approval 8672A – Wolf Lake Deep DisposalApproved June 2010

CNQSlide 70

• Approval Compliance RequirementsMonitoring Maximum Injection PressuresAnnual Report

– 2011 Report Submitted– 2012 Report will be prepared following annual cavern sounding

• Salt Cavern 1 – 118/12-8-66-5W4Cavern volume (as of April 2012 sounding) 191,531 m3

Wash water 10,862 m3

Oily waste (bitumen) 25 m3

Solid waste 0 m3

Next Cavern sounding expected in April 2013 • Salt Cavern 2 - 119/12-8-66-5W4 – Washing Only

Cavern volume (as of April 2012 sounding) 51,308 m3

Wash water 22,678 m3

Next Cavern sounding expected in April 2013

IN COMPLIANCE

Approval 8673 – Cavern DisposalApproved October 2000 Approval 8673 – Cavern DisposalApproved October 2000

CNQSlide 71

• Approval Compliance RequirementsOriginally approved 1983Transferred to Canadian Natural from Dome Petroleum – September 2011Directive 51 ComplianceMaximum Wellhead Injection Pressures (kPa)

– 03/10-05-067-04W4/0 = 6,000

IN COMPLIANCE

Approval 3929A – Primrose Class 1b DisposalAmended September 2011 Approval 3929A – Primrose Class 1b DisposalAmended September 2011

CNQSlide 72

• Approval No. 4128D – Class II DisposalTransferred to Canadian Natural from Dome Petroleum – September 2011Directive 51 Compliance02/10-05-067-04W4/0 = 16,000 kPA

• Approval No. 9792A– Class II Disposal00/14-02-065-08W4/0 has been abandoned and the approval was rescinded September 2011

IN COMPLIANCE

Additional ERCB Disposal ApprovalsAdditional ERCB Disposal Approvals

CNQSlide 73

Compliance DisclosuresCompliance Disclosures

• Reportable spills18 reportable spills were reported in 2012 including; 5 emulsion, 3 hydrochloric acid, 2 boiler feed, 1 hydrated lime, 1 oil, 1 sludge, 1 brackish water, 1 high pH, 1 produced water, 1 drilling mud and 1 diesel fuel.

• Digital Data Submissions (DDS)Notifications/Submissions were entered into the DDS as per Directives in 2012.

CNQSlide 74

Non-ComplianceNon-Compliance

• ERCB Scheme Approval 9140None

CNQSlide 75

Future PlansFuture Plans

• Wolf Lake Plant Control System & Electrical UpgradesSignificant work ongoing to upgrade equipment and infrastructure

• Wolf Lake Unit 2 ImprovementsIGF Replacement, desand system upgrades

• Wolf Lake Salt Cavern FiltrationSalt cavern return filtration and booster pumps

• Wolf Lake Oil Treating Capacity (9140 Approval 19,000 m3/d)Increasing plant capacity to ~ 23,000 m3/d

• Brackish Water System/Fresh Water ReductionReduce fresh water usage to 3,000 m3/d: Additional supply wells, pipelines, convert fresh water users to brackish water, glycol system expansion

Regulatory applications will be filed as required

CNQSlide 76

Future Plans Future Plans

• Wolf Lake Steam Generation Capacity IncreaseReviewing addition of steam generation for future SAGD steam demand and brackish heating

• Surface Facilities Associated with Field DevelopmentPrimrose South/East/North Pads (PRS 25-26, PRS 40-43, PRN 60-68)

• Primrose East Heat IntegrationRe-piping inlet heat exchangers to optimize heat transfer

• Primrose South Steam Generator Economizer UpgradesReplace damaged equipment and improve efficiency, 2 OTSG’s targeted for 2013Replace damaged HRSG evap modules

Regulatory applications will be filed as required

CNQSlide 77

Certain statements in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectivelyCertain statements relating to the Company in this document or documents incorporated herein by reference constitute forward-looking statements orinformation (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-lookingstatements 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 futureoutcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, production volumes, royalties, operating costs, capitalexpenditures, and other guidance provided in the 2010 outlook section and throughout this document and the documents incorporated herein by referenceconstitute forward looking statements. Disclosure of plans relating to existing and future developments including but not limited to Horizon, Primrose East,Pelican Lake, Olowi Field (Offshore Gabon), and the Kirby Thermal Oil Sands Project also constitute forward-looking statements. This forward-lookinginformation is based on annual budgets and multi-year forecasts and is reviewed and revised throughout the year if necessary in the context of targetedfinancial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of futureperformance and are subject to certain risks. The reader should not place undue reliance on these forward looking statements as there can be noassurances that the plans, initiatives or expectations upon which they are based will occur.In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certainestimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimatingquantities of proved crude oil and natural gas reserves and in projecting future rates of production and the timing of development expenditures. The totalamount or timing of actual future production may vary significantly from reserve and production estimates.The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Companyoperates, 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 aresubject to known and unknown risks, uncertainties and other factors that could cause the actual results, performance or achievements of the Company to bematerially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks anduncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of theCompany’s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions onwhich the Company’s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; politicaluncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of theCompany 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 andits subsidiaries’ ability to secure adequate transportation for its products; unexpected difficulties in mining, extracting or upgrading the Company’s bitumenproducts; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attractthe necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for andproduction and sale of crude oil and natural gas; availability and cost of financing; the Company’s and its subsidiaries’ success of exploration anddevelopment activities and their ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business andoperations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, bitumen, naturalgas and liquids not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply withthem (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirementobligations; the adequacy of the Company’s provision for taxes; and other circumstances affecting revenues and expenses. Certain of these factors arediscussed in more detail under the heading “Risk Factors”. The Company’s operations have been, and at times in the future may be affected by politicaldevelopments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amountspayable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of theserisks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from thoseprojected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as suchfactors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all informationthen available.Readers are cautioned that the foregoing list of important factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could alsohave material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-lookingstatements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as tofuture results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company orpersons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes noobligation to update forward-looking statements should circumstances or Management’s estimates or opinions change.

Forward Looking StatementsForward Looking Statements

CNQSlide 78

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 unlessotherwise 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 sixthousand 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 the6mcf:1bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head.

ReservesFor the year ended December 31, 2010 the Company retained Independent Qualified Reserves Evaluators (”Evaluators”), Sproule Associates Limited andSproule International Limited (together as “Sproule”) and GLJ Petroleum Consultants Ltd. (“GLJ”), to evaluate and review all of the Company’s proved andproved plus probable reserves with an effective date of December 31, 2010 and a preparation date of February 14, 2011. Sproule evaluated the NorthAmerica and International crude oil, NGL and natural gas reserves. GLJ evaluated the Horizon SCO reserves. The evaluation and review was conducted inaccordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and disclosed in accordance with NationalInstrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) requirements. In previous years, Canadian Natural had been grantedan exemption order from the securities regulators in Canada that allowed substitution of U.S. Securities Exchange Commission (“SEC”) requirements forcertain NI 51-101 reserves disclosures. This exemption expired on December 31, 2010. As a result, the 2010 reserves disclosure is presented inaccordance with Canadian reporting requirements using forecast prices and escalated costs. The recovery and reserves estimates of crude oil, NGL andnatural gas reserves provided in this presentation are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crudeoil, NGL and natural gas reserves may be greater than or less than the estimates provided.

Reserves estimates provided in this presentation are company gross, before royalties.

Resources Other Than ReservesThe contingent resources other than reserves (“resources”) estimates provided in this presentation are internally evaluated by qualified reserves evaluatorsin accordance with the COGE Handbook as directed by NI 51-101. No independent third party evaluation or audit was completed. Resources provided arebest estimates as of December 31, 2010. The resources are evaluated using deterministic methods which represent the expected outcome with nooptimism or conservatism.

Resources, as per the COGE Handbook definition, are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from knowaccumulations using established technology or technology under development, but are not currently considered commercially viable due to one or morecontingencies. There is no certainty that it will be commercially viable to produce any portion of these resources.

Due to the inherent differences in standards and requirements employed in the evaluation of reserves and contingent resources, the total volumes ofreserves or resources are not to be considered indicative of total volumes that may actually be recovered and are provided for illustrative purposes only.

Petroleum, bitumen or natural gas initially-in-place volumes provided are discovered resources which include: production, reserves, contingent resourcesand unrecoverable volumes.

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 flowper share and EBITDA (net earnings before interest, taxes, depreciation depletion and amortization, asset retirement obligation accretion, unrealized foreignexchange, stock-based compensation expense and unrealized risk management activity). These financial measures are not defined by generally acceptedaccounting principles (“GAAP”) and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not becomparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate the performance of theCompany and of its business segments. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, asdetermined 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

Premium Value Defined Growth Independent

Canadian Natural Resources Limited2500, 855 - 2 Street SW

Calgary Alberta T2P 4J8phone: 403.517.6700

fax: 403.517.7350email: [email protected]

www.cnrl.com

THE FUTURE CLEARLY DEFINED

Directive 54 - CNRL 2012 PAW Annual Review Surface

Documents

wolf lake plant unit

heater wolf lake unit

burnt lake annual presentation

related toresource evaluation

subsurface issues

produced water volumes

outl surface operations

water quality fresh