TABLE OF CONTENTS PART 1 PROJECT UPDATE... 1 PROPOSED PLANT SITE EXPANSION...1

Canadian Natural Resources Limited - i - Table of Contents TABLE OF CONTENTS SECTION PAGE PART 1 PROJECT UPDATE... 1 PROPOSED PLANT SITE EXPANSION...1 PART 2 SUPPLEMENTAL INFORMATION REQUEST RESPONSES... 7 WATER...7 APPROVALS / CONSERVATION AND RECLAMATION...49 ERRATA...63

Canadian Natural Resources Limited - 1 - Proposed Plant Site Expansion PART 1 PROJECT UPDATE PROPOSED PLANT SITE EXPANSION On September 18, 2007 Canadian Natural Resources Limited (Canadian Natural) filed the Kirby In-Situ Oil Sands Project Application for Approval (Application for Approval) (Canadian Natural 2007) with Alberta Environment (AENV) and the Energy Resources Conservation Board (ERCB). Canadian Natural is proposing an expansion to the Kirby Central Plant (KCP) footprint described in the Application for Approval (Figure 1). The following update provides an overview of the proposed expansion. Since the filing of the Application for Approval, Canadian Natural has conducted Project design work which indicates additional area will be required on the KCP site for soil stockpiling, equipment laydown, access and execution of plant maintenance shutdowns (turnarounds). The required increase in KCP area will be 11 ha. Because 4 ha of the expansion area were previously included in the Project footprint described in the Application for Approval (Canadian Natural 2007), the change will increase the Project footprint by 7 ha to 334 ha total (Figure 1). Comparisons of the terrestrial vegetation and wetlands types, and soils types within the original and revised Project footprints are provided in Tables 1 and 2, respectively. The vegetation ecosites/wetland types and soil types most affected by the KCP expansion include the Labrador tea-mesic jack pine-black spruce (c1) ecosite (4 ha increase; less than 1% of the 3,568 ha terrestrial Local Study Area [LSA]) and the wooded bog (BTNN) vegetation type (1 ha increase; less than 1% of the LSA) (Table 1). For soils, the most affected are the Kinosis and McLelland soil map units (each with a 2 ha increase; less than 1% of the LSA) (Table 2). There is minimal disturbance to the Mildred and Muskeg soil map units (each with approximately 1 ha increase; less than 1% of the LSA). Since the KCP expansion utilizes 3 ha (less than 1% of the LSA) of existing disturbance, this will minimize the impact to existing vegetation and soils. All of the proposed KCP expansion is within areas rated as having nil to low caribou habitat suitability (Volume 5, Appendix II of the Application for Approval, Wildlife Habitat Modelling [Canadian Natural 2007]). The increase in the overall Project footprint from 327 to 334 ha, as a result of the KCP expansion, represents less than 1% of the 3,568 ha terrestrial LSA. This small change does not alter the original conclusions of the Environmental Impact Assessment (EIA). A reassessment of impacts is therefore not warranted. The mitigation described for the Project in the Application for Approval also applies to the KCP expansion activities and footprint. The KCP expansion, and the resulting salvage of soils during construction, will affect the topsoil and subsoil balances presented in Tables 7 and 8 of the Conservation and Reclamation Plan (Volume 1B, Attachment 1 of the Application for Approval [Canadian

Canadian Natural Resources Limited - 2 - Proposed Plant Site Expansion Natural 2007]). The revised topsoil and subsoil balances are presented in the responses to SIRs 9 and 13, respectively, of Part 2 of this document. Positive topsoil and subsoil balances will still be achieved for the KCP site and for the overall Project. The expansion area will be covered in more detail as part of the KCP Pre-Development Assessment to be submitted to AENV and Alberta Sustainable Resource Development (ASRD). Figure 1 shows that the general surface drainage pattern of the expansion area will be away from the Central Processing Facility (CPF) portion of the KCP site. Runoff from the expansion area will be managed as described below, and independently from the CPF runoff (discussed in the response to SIR 16, Part 2 of this document).

498000 498500 499000 LEGEND GENERAL SURFACE DRAINAGE DIRECTION ORIGINAL PLANT SITE PLANT SITE EXPANSION ADDITIONAL ACCESS, LAYDOWN AND PLANT TURNAROUNDS SOIL STORAGE 29 Rg. 7 W4M 6133000 6133000 28 REFERENCE 21 Alberta digital data obtained from The Orthoshop ULC (Colour Orthophotos, October 2006), Footprint obtained from CNRL. Projection: UTM Zone 12 Datum: NAD 83 6132500 6132500 I:\CLIENTS\CNRL\06-1346-015\mapping\mxd\General\ProposedKirbyPlantSiteExpansion.mxd 20 150 0 150 SCALE 1:4,000 PROJECT TITLE METRES KIRBY IN-SITU OIL SANDS PROJECT REVISED PLANT SITE FOOTPRINT TO REFLECT PLANT SITE EXPANSION PROJECT NO. 06-1346-015 498000 498500 499000 Calgary, Alberta DESIGN GIS CHECK REVIEW BL SL DC DB 20 May 2009 15 Sep. 2009 15 Sep. 2009 15 Sep. 2009 SCALE AS SHOWN REV. 0 FIGURE: 1

Canadian Natural Resources Limited - 4 - Proposed Plant Site Expansion Table 1 Vegetation Communities Vegetation Ecosite Phases and Wetland Types Disturbance Comparison Vegetation Ecosite Phases and Wetland Types Terrestrial Ecosite Phases Original Project Footprint Area [ha] Revised Project Footprint with Plant Site Expansion Area [ha] Change in Project Footprint Area [ha] [% LSA] (a) a1 Lichen jack pine 1 1 0 0 b1 blueberry jack pine-aspen 12 12 0 0 b2 blueberry aspen (white birch) 5 5 0 0 b3 blueberry aspen-white spruce 1 1 0 0 c1 Labrador tea-mesic jack pine-black spruce 57 61 4 <1 d1 low-bush cranberry aspen 29 29 0 0 d2 low-bush cranberry aspen-white spruce 4 4 0 0 d3 low-bush cranberry white spruce 1 1 0 0 g1 Labrador tea-subhygric black spruce-jack pine 62 62 0 0 h1 Labrador tea/horsetail white spruce-black spruce 2 2 0 0 Wetlands BTNN wooded bog 39 40 1 <1 FTNN wooded fen 41 41 <1 <1 FTNI wooded fen with internal lawns 2 2 0 0 FONS shrubby fen <1 <1 0 0 FONG graminoid fen <1 <1 0 0 STNN wooded swamp 1 1 0 0 SONS shrubby swamp <1 <1 0 0 Disturbances CC Clearcut <1 <1 <1 <1 Dis Disturbed 69 72 3 <1 Total 327 334 7 <1 <=less than. Note: Some numbers are rounded for presentation purposes. Therefore, it may appear that the totals do not equal the sum of the individual values. (a) The terrestrial local study area is 3,568 ha.

Canadian Natural Resources Limited - 5 - Proposed Plant Site Expansion Table 2 Dominant Soil Map Units Soil Map Unit Disturbance Comparison Mineral Soils Soil Map Units Original Project Footprint Area [ha] Revised Project Footprint with Plant Site Expansion Area [ha] Change in Project Footprint Area [ha] [% LSA] (a) BMT3 Bitumount 4 4 0 0 KNS1, KNS2 (b), KNS6 (b) Kinosis 82 84 2 <1 MIL1, MIL2 (b), MIL5 Mildred 14 15 1 <1 STP2, STP3 Steepbank 4 4 0 0 SUT5 Sutherland 10 10 0 0 WNF1, WNF5 Winefred 15 15 0 0 Organic Soils MLD1, MLD2, MLD1-2 (b) McLelland 114 116 2 <1 MUS1 (b),mus2, MUS1-2 (b) Muskeg 43 44 1 <1 Non-Soils Dis Disturbed 40 42 3 <1 Total 327 334 7 <1 <=less than. Note: Some numbers are rounded for presentation purposes. Therefore, it may appear that the totals do not equal the sum of the individual values. (a) The terrestrial local study area is 3,568 ha. (b) Soil map units found in the plant site expansion area. Laydown, Access And Turnaround Area The additional area for equipment laydown, plant turnaround and access will be designed to be stable and non-eroding and to prevent the movement of sediment offsite with runoff. Specific measures to be incorporated will include the following: The area will be graded to minimize steep slopes. The area will be constructed with packed clay materials and covered with gravel to stabilize the surfaces and minimize sediment generation by runoff. Runoff from the area will be directed to an adjacent road ditch system, which will be upgraded during construction. All ditches will be designed to be stable and to adequately convey runoff while minimizing the runoff energy, including the use of properly sized and located culverts, armouring/gabions, etc. Canadian Natural will establish a grass cover within the ditches to further manage erosion and sediment generation (seed mix of native grass species to be determined through discussion with ASRD). Other measures (e.g., silt fencing) will be incorporated where needed. These facilities and measures will be regularly inspected and adjustments and repairs will be made as necessary.

Canadian Natural Resources Limited - 6 - Proposed Plant Site Expansion Runoff collected in the road ditches will ultimately be conveyed to adjacent, well-vegetated natural areas, located at least 200 m from open waterbodies. Stockpile Area The soil stockpiles will be designed to be stable and non-eroding, to ensure the security of stockpiled soil materials, and to prevent the movement of sediment offsite with runoff. Specific measures to be incorporated will include the following: All stockpile locations will have stable foundations, stockpile side slopes will not exceed a maximum 3:1 gradient (horizontal:vertical) and stockpile heights will not exceed 5 m. Soil stockpiles will be seeded to establish a vegetation cover (seed mix of native grass species to be determined through discussion with ASRD). Other erosion control measures (e.g., silt fencing, erosion-control matting, tackifying agents) will be incorporated as needed to stabilize the stockpiles. Silt fencing or other equivalent measure will be installed at the perimeter of each stockpile to retain soils within the stockpile areas and prevent the movement of sediment offsite in runoff. The soil stockpiles will be regularly monitored and adjustments will be made as necessary, including but not limited to the re-seeding of areas with inadequate vegetation establishment and the incorporation of additional erosion control measures. The stockpiles will be designed and constructed to prevent the concentration of runoff flows. Apart from flowing through the perimeters of silt fencing or other equivalent measure, runoff from the stockpile areas will be allowed to drain freely into adjacent, wellvegetated natural areas. Based on the planned locations for the stockpiles (Figure 1) the runoff will drain into areas located at least 200 m from open waterbodies. References Canadian Natural (Canadian Natural Resources Limited). 2007. Kirby In-Situ Oil Sands Project Application for Approval. Volumes 1-6. Submitted to Alberta Energy and Utilities Board and Alberta Environment. September 2007. Calgary, AB.

Canadian Natural Resources Limited - 7 - Supplemental Information Request 3 PART 2 SUPPLEMENTAL INFORMATION REQUEST RESPONSES WATER 1. Part 1, Project Update, Page 1. CNRL states, The EnCana Corporation (EnCana) Foster Creek reservoir was used as an analog for the Project reservoir because of the similar geology. Provide a discussion on the analysis conducted to support this statement including a detailed comparison of the reservoir characteristics for each project that could have an influence on reservoir retention. Response: Canadian Natural Resources Limited (Canadian Natural) reviewed the operating Steam Assisted Gravity Drainage (SAGD) projects in the McMurray reservoir at the time of application and selected EnCana FCCL Ltd. s (EnCana s) Foster Creek reservoir as an analog to the Kirby Project reservoir based on similar geology. The review was limited to publicly available data which included data available in Accumap such as well logs, core data and production data. In addition, Canadian Natural has reviewed information in publicly available submissions from EnCana to the Energy Resources Conservation Board (ERCB) such as the annual in-situ progress reports. Canadian Natural has also examined some of the available cores at the ERCB s core facility for comparison to cores from the Kirby Project area. While the main purpose of the review was to identify a reservoir analog to be used for oil production and steam injection forecasting, the geological characteristics of the Foster Creek reservoir also made it a reasonable analog for estimating reservoir water retention for the Kirby Project. Operational practices are likely to have a significant impact on reservoir water retention; however Canadian Natural does not have access to EnCana s operational data and therefore cannot determine how different operating practices will impact reservoir retention. Table 1-1 compares the average geological properties of the two reservoirs. As shown in the table, the porosity, oil saturation, permeability, reservoir depth and reservoir pressure of the McMurray Formation in EnCana s Foster Creek area are similar to those of the McMurray in the Kirby Project area. Although the Foster Creek reservoir has a greater average SAGD pay thickness than the Kirby Project reservoir, it is still similar enough to the Kirby Project reservoir to be a reasonable analog. The main reservoir characteristics that could influence reservoir water retention are the presence and extent of gas caps, lean zones and bottom water zones. Gas caps, lean zones and bottom water can behave as thief zones for steam, resulting in increased reservoir water retention. Both the Foster Creek and Kirby reservoirs have minimal top gas in the McMurray formation. EnCana s 2009 application for the Phase F/G/H expansion of the Foster Creek Thermal Project (EnCana 2009) states that SAGD gas (any gas zone in direct

Canadian Natural Resources Limited - 8 - Supplemental Information Request 3 communication with the SAGD interval) is rare within the Foster Creek area. As discussed in Canadian Natural s September 2007 Application for Approval (Volume 1, Section B2.4.6 [Canadian Natural 2007]), gas in the McMurray Formation is minor in the Kirby Project regional geographic study area and only one well in the Project area has McMurray gas on logs, with a thickness of less than 1m. The same section of the Application for Approval (Canadian Natural 2007) includes mapping of the gas zones in the Kirby area. Neither the Foster Creek nor Kirby reservoirs have any significant lean zones (zones of reduced bitumen saturation) within the SAGD pay intervals. Another important factor is the amount of water in contact with the base of the SAGD interval. EnCana defines its transition zone as a zone at the base of the SAGD interval with a bitumen saturation of 50 to 60% (i.e., 40 to 50% water saturation). According to their expansion application from 2009 (EnCana 2009), this zone is rarely greater than 5 m thick. At Canadian Natural s Kirby Project, the bottom water thickness (defined by a resistivity log cut-off which is approximately equivalent to 95% water saturation or higher (5% bitumen saturation or less)) ranges from 0 to 20 m in the Project area. A transition zone of 1 to 2 m in thickness is sometimes present between the bitumen zone and the bottom water in the Kirby area. Bottom water maps are available in the Application for Approval (Volume 1, Section B2.4.7 [Canadian Natural 2007]). Bottom water may behave as a thief zone depending on many factors such as operating conditions, proximity of wells to the bottom water, and connectivity/flow properties of the bottom water. Although there is more bottom water in some areas of the Kirby Project, the Foster Creek reservoir is still a good analog, particularly for the initial Kirby wellpads where the amount of bottom water is less than in the Western wellpads. The overall similarities of the two reservoirs support the use of Foster Creek data for reservoir water retention estimation for the Kirby Project.

Canadian Natural Resources Limited - 9 - Supplemental Information Request 3 Table 1-1 Comparison of Reservoir Characteristics for EnCana s Foster Creek and Canadian Natural s Kirby Projects Property EnCana Foster Creek Canadian Natural Kirby Bitumen Weight Percent (%) (calculated from porosity and oil saturation, assumes oil and water densities of 1,000 kg/m 3 and a matrix density of 13.0 12.7 2,650 kg/m 3 ) Porosity (%) 34 (a) 33 Oil Saturation (%) 80 (50% in transition zone) (a) 80 Average SAGD Pay Thickness (as defined by Canadian Natural pay cut-offs) (m) 25 to 30 20 Average Permeability (D) 6 (a) 6.5 (air permeability in core) (a) Bottom water pressure is Original Reservoir Pressure (kpa) 2,700 2,600 to 2,700 Reservoir Depth Top Gas in the McMurray Formation (gas above SAGD zone in direct communication with the SAGD pay interval) (a) (b) Bottom water / transition zone thickness (m) Source: EnCana 2007. Source: EnCana 2009. 462 to 520 m TVD (180 to 225 m subsea) (a) Rare (b) Transition zone rarely exceeds 5 m thick (bitumen saturation in this region is 50 to 60%) (b) 500 to 560 m TVD (170 to 210 m subsea) Minor - only 1 well with McMurray gas in the detailed geological study area Bottom water thickness of 0 to 20 m depending on location References Canadian Natural (Canadian Natural Resources Limited). 2007. Kirby In-Situ Oil Sands Project Application for Approval. Volumes 1-6. Submitted to Energy and Utilities Board and Alberta Environment. September 2007. Calgary, AB. EnCana (EnCana FCCL Ltd.). 2007. EnCana Foster Creek In Situ Oil Sands Scheme 2007 Update. May 2007. EnCana. 2009. Air Quality Assessment of the EnCana Foster Creek Thermal Project PHASE FGH Expansion. Submitted to Energy Resources Conservation Board and Alberta Environment. May 2009. 2. Part 1, Project Update, Page 2. CNRL states, To demonstrate potential ranges in make-up water requirements for the Project, as a function of reservoir retention, water balance forecasts for the following three different reservoir retention scenarios have been generated. Provide a detailed discussion on analysis conducted by CNRL to refine the reservoir retention predictions for the project including:

Canadian Natural Resources Limited - 10 - Supplemental Information Request 3 a) The use of analog data from existing projects such as Foster Creek. b) Reservoir simulation modeling conducted to assess reservoir retention at the project and to understand the relative impact on reservoir retention of varying model input parameters such as relative permeability, water saturation distribution, bottom water, operating pressure, etc. Provide the input data file(s) for the model runs. c) The methodology for applying the reservoir simulation results to predictions of reservoir retention over the life of project. Response: a) The EnCana Foster Creek reservoir was chosen as the analog for the Kirby Project reservoir because of the geological similarities (see response to SIR 1) and because of the long Foster Creek production histories available. Canadian Natural undertook an assessment of the Foster Creek reservoir retention data. Using Accumap software, an updated well list was generated for the Foster Creek area by including horizontal and directional wells and excluding source and disposal wells, gas wells and wells in the Grand Rapids and Clearwater formations. This list included more current Foster Creek data than the data referenced above from the response to Round 2 SIR 3. The updated data have been provided to the ERCB. Using the updated well list, the monthly water production (m 3 ) and monthly water injection (m 3 ) was extracted from Accumap. Because the Kirby Project will not include infill and VAPEX wells, a second well list was prepared by removing the infill wells and a pair of VAPEX wells from the original list. The data was retrieved from Accumap for this second well list also. A monthly reservoir water retention percentage was calculated by subtracting the produced water volume from the injected water (i.e., steam) volume and dividing by the injected water volume. Reservoir retention values are plotted in Figure 2-1 for the two well lists, along with points showing the annual reservoir water retention for the data set without the infill and VAPEX wells. The annual values were calculated by adding the monthly water volumes for all months in a given year and then computing the percentage retention. Beginning in 2005, the data set with the infill wells included shows lower reservoir retention values since the infill wells are not accompanied by corresponding SAGD injection wells (thus the field produces more water with the same injected volumes as the data set containing all of the SAGD wells). This effect is magnified towards 2008 as more and more infills are added to the Foster Creek Thermal Project. As stated previously, Canadian Natural does not currently plan to utilize infill wells or the VAPEX process within the Kirby Project and has therefore used the data excluding the VAPEX and infill wells.

Canadian Natural Resources Limited - 11 - Supplemental Information Request 3 Figure 2-1 Foster Creek Reservoir Water Retention Entire Field Foster Creek - Reservoir Water Retention - Full Field Data Set 80.0% Monthly reservoir water retention (%) [(monthly inj wtr-monthly prod wtr)/(monthly inj wtr)] 60.0% 40.0% 20.0% 0.0% Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10-20.0% -40.0% -60.0% -80.0% Month & Year all wells excluding infill & VAPEX wells annual water retention - excludes infills & VAPEX wells As can be seen in Figure 2-1, the annual reservoir retention (with the infills and VAPEX wells excluded) in the Foster Creek field was approximately 20% for 1999 and 2000 and 35% for 2001. In subsequent years, the annual retention values ranged from - 8% to +7%. These annual numbers are based on calendar year totals. If a rolling 12- month average is used for the years following 2001, the range for retention is -9% to +9%. The monthly data for this same portion of the data set revealed substantial variation in reservoir retentions with time, ranging from -26% to +14%. Although monthly values in excess of 40% reservoir retention were observed at the Foster Creek Thermal Project for some months in the earlier years of the Project, Canadian Natural selected a more conservative reservoir retention range of 0 to 20% to be used for calculating water requirements for the Kirby Project (as stated in the Round 2 SIR 3 response). Canadian Natural believes reservoir retention is affected by well placement, different reservoir characteristics (e.g., facies, facies distribution within the reservoir, mineralogy, presence of lean zones, depleted zones, bottom water, etc.), well operations, plant operations and metering issues. A learning curve also accompanies new operations, and a certain amount of operational flexibility is required to ensure optimal production and recovery efficiency. Canadian Natural believes that the 20%

Canadian Natural Resources Limited - 12 - Supplemental Information Request 3 reservoir water retention should be used in calculating the maximum required water volumes to ensure that the Kirby Project is operationally viable and not steam limited. b) Canadian Natural s reservoir simulations were not conducted with the intent of assessing reservoir retention. There are many parameters outside the scope of the simulation that can and will impact reservoir retention, including: Operational upsets at the well pad and at the central plant can cause swings in rates and pressures, which will create significant phase change effects associated with water within the reservoir and within the steam chamber. The irreducible water saturations increase with temperature. This is a potential form of hold-up related to elevated temperatures. The as-drilled placement of the well pairs within the reservoir can result in proximity to barriers and/or oil/water contacts. The presence or absence of a water leg and the ability to accurately maintain pressure control in such cases. The existence of a mobile water saturation within the oil column itself, which presents a form of leak-off. The lack of a detailed reservoir characterization including multiple relative permeability curves which should depend on such things as grain size distribution, mineralogy and wettability, all of which could vary throughout the developed reservoir. In addition to the above, it is very difficult to set realistic boundary conditions in the simulation. If lean zones or bottom water zones exist, the boundary conditions could have a significant influence on reservoir retention calculations. Despite these limitations, one of the simulations generated in support of the Kirby Project Application for Approval (Canadian Natural 2007a) was reconsidered using the software CMG STARS to understand how the reservoir retention varied. All of the original simulations were made using bounded reservoir segments with simplified reservoir characterizations, and were meant to assess the relationship between steam injection rate and oil production rate as these are the principle cost and revenue factors. With these simplifications, the estimates for the retention cannot be expected to be reliable. In the re-evaluated simulation, a simple one SAGD pair model was constructed as an extension of the original 20 m pay thickness reservoir simulation model submitted to the ERCB with the Application for Approval (Canadian Natural 2007b). All of the data used in the new simulation have also been provided to the ERCB. Pressure controlled sink and source horizontal wells were added at the boundaries of the model in the six lowermost layers. The sink / source wells were added to allow for the flow of water into or out of the model, and to allow movement of mobile water in the bitumen

Canadian Natural Resources Limited - 13 - Supplemental Information Request 3 zone and in the increasingly water-saturated zones at the base of the model. The boundary wells were set up to inject water into the reservoir when the reservoir pressure dropped below its original value and to produce liquid (i.e., behave as a thief zone) when the pressure exceeded the original reservoir pressure. The residual water saturation in the reservoir model was lowered to 15% (from its original value of 20%) to allow for some initial water mobility and resulting leak-off. The SAGD well pair in these models was operated at constant pressure. A base case was run with the SAGD well pair operating at the original reservoir pressure at the elevation of the producer, without flow at the boundaries (i.e., a closed model). This case was then run again with the wells at the boundaries operating as sink / source wells. Several sensitivities were then conducted in which the residual water saturation was changed back to the original 20% saturation and the SAGD operating pressure was raised by 300 kpa above the original reservoir pressure to observe the effect of pressure on the reservoir water retention. Figure 2-2 shows the monthly water retention (calculated from monthly rates) for the various scenarios. The figure illustrates that reservoir retention could range from -20% in the case of the closed model with no boundary flow to an initial 100% within the first year of operation when operated at 300 kpa above the original reservoir pressure. Near the end of the first year of the simulation, reservoir retentions approaching 20% are observed in the cases operating at reservoir pressure. In later years retentions were in the range of 4 to 14%. The spike to 100% in the curves for the 300 kpa elevated pressure cases occurs when the steam chambers reach the sides of the model, which results in massive leak-off as the chambers have a higher pressure than the reservoir model at that point in time. This causes the steam chamber to depressure and reservoir retention rapidly increases as the SAGD injection rate increases to try to keep up with boundary losses.

Canadian Natural Resources Limited - 14 - Supplemental Information Request 3 Figure 2-2 Reservoir Water Retention Values Obtained From a Simulation with Sink / Source Wells at the Boundaries Simulation - Reservoir Water Retention Reservoir P indicates SAGD operation at reservoir pressure, 300 kpa above indicates operation at 300 kpa higher, SWR = connate water saturation used in the simulations 100.0% Monthly Reservoir Water Retention (%) [ (SAGD Injected water- SAGD produced water) / SAGD Injected water ] 80.0% 60.0% 40.0% 20.0% 0.0% 0 500 1000 1500 2000 2500-20.0% -40.0% Time (days) SWR=0.15, reservoir P, boundary flow SWR=0.20, reservoir P, boundary flow SWR=0.15, reservoir P, NO BOUNDARY FLOW SWR=0.15, 300kPa above, boundary flow SWR=0.20, 300 kpa above, boundary flow Having observed these effects, it is important to note that the simulation results are dependent on the pressure and flow rates assigned to the boundary wells, the operating pressures of the SAGD well pairs, and on the initial connate water saturation within the reservoir. It is difficult to determine representative rates and assign controlling parameters to the boundary wells without operational history including some field production and injection data to match using simulation. The work presented here only provides evidence that a range of reservoir water retention values is possible, and these values are very dependent on parameters which are difficult to provide realistic estimates for. Canadian Natural believes that the most reliable estimate for water retention can be obtained by reviewing analog data, in this case, Foster Creek data. This information reinforces the importance of using existing field data, like that available from EnCana s Foster Creek Thermal Project development, as the best source for estimating reservoir retention. c) Based on the discussion above, Canadian Natural did not use reservoir simulation results in the prediction of reservoir retention over the life of the Project. Instead, field data from EnCana s Foster Creek Project were used as analog for estimating reservoir water retention at the Kirby Project.

Canadian Natural Resources Limited - 15 - Supplemental Information Request 3 References Canadian Natural (Canadian Natural Resources Limited). 2007a. Kirby In-Situ Oil Sands Project Application for Approval. Volumes 1-6. Submitted to Alberta Energy and Utilities Board and Alberta Environment. September 2007. Calgary, AB. Canadian Natural. 2007b. Kirby In-Situ Oil Sands Project Application for Approval. Reservoir Model Simulation Files for the EUB. Submitted to Alberta Energy and Utilities Board. September 2007. Calgary, AB 3. Part 1, Project Update, Page 4, Table 1. In Table 1, the projected fresh water use for years 2020, 2021, and 2022 are in excess of CNRL s applied for diversion licence rates. Please clarify this apparent discrepancy. Response: Canadian Natural does not expect 20% reservoir retention to extend beyond the first 5 years of operation. Therefore, Canadian Natural has generated a revised water forecast for the Project (Table 3-1). The revised forecast is based on 20% reservoir retention for the first 5 years of operation when it is anticipated that reservoir retention will be the highest, and 10% for the remainder of the Project when reservoir retention is expected to be lower. This update results in a peak annual average fresh water use of 4,440 m 3 /cd in 2014 and 2015, consistent with the applied for diversion licence rates.

Canadian Natural Resources Limited - 16 - Supplemental Information Request 3 Table 3-1 Water Balance for Steam Generation and Utilities (Expected Case: 20 to 10% Reservoir Retention Over the Project Life) Time (Years) Bitumen Annual Average [m³/cd] Steam Annual Average [m³/cd] Produced Water (a) Make-Up Water(b)(h) Plant Use - Utility (c) Annual Average Disposal Water (d) Annual Average [m³/cd] Peak (e) [m³/cd] Normal [m³/cd] Annual Average (f) [m³/cd] McMurray [m³/cd] Grand Rapids [m³/cd] Empress (g) [m³/cd] 2011 525 10,500 7,140 7,585 3,805 5,065 1,500 3,000 565 950 310 205 5,375 3,875 654 623 223 1,500 2012 4,900 16,000 12,800 4,905 4,905 4,905 1,500 2,855 550 950 310 205 5,215 3,715 807 517 176 1,500 2013 7,000 18,000 14,400 5,305 5,305 5,305 1,500 3,000 805 950 310 205 5,615 4,115 834 489 178 1,500 2014 6,720 19,080 15,155 5,850 5,520 5,630 1,500 3,000 1,130 950 310 205 5,940 4,440 846 477 177 1,500 2015 6,450 19,080 15,155 5,850 5,520 5,630 1,500 3,000 1,130 950 310 205 5,940 4,440 846 477 177 1,500 2016 6,190 19,080 17,030 3,515 3,095 3,235 980 1,705 550 950 310 205 3,545 2,565 679 228 73 980 2017 5,940 19,080 17,123 3,240 3,095 3,143 980 1,613 550 950 310 206 3,453 2,473 682 228 69 980 2018 5,705 19,080 17,170 3,095 3,095 3,095 980 1,565 550 950 310 205 3,405 2,425 684 228 67 980 2019 5,115 19,080 17,075 3,380 3,095 3,190 980 1,660 550 950 310 205 3,500 2,520 681 228 71 980 2020 4,585 19,080 16,155 6,145 3,095 4,112 980 2,582 550 950 310 207 4,422 3,442 646 226 107 980 2021 4,110 19,080 16,615 4,755 3,095 3,648 980 2,118 550 950 310 203 3,958 2,978 664 227 89 980 2022 3,685 19,080 16,985 3,655 3,095 3,282 980 1,752 550 950 310 207 3,592 2,612 677 228 75 980 2023 3,305 18,000 16,015 3,520 2,970 3,153 980 1,623 550 950 310 188 3,463 2,483 671 237 72 980 2024 2,935 16,700 14,705 3,765 2,800 3,122 950 1,622 550 950 310 177 3,432 2,482 642 234 74 950 2025 2,600 15,300 13,675 2,870 2,595 2,687 900 1,237 550 950 310 162 2,997 2,097 616 225 58 900 2026 2,305 14,200 12,410 3,555 2,450 2,818 875 1,393 550 950 310 153 3,128 2,253 585 224 66 875 2027 2,045 12,600 11,340 2,250 2,250 2,250 850 850 550 950 310 140 2,560 1,710 577 229 45 850 2028 1,815 11,400 10,260 2,040 2,040 2,040 775 715 550 950 310 125 2,350 1,575 531 206 38 775 2029 1,600 10,300 9,270 1,845 1,845 1,845 700 595 550 950 310 115 2,155 1,455 486 182 32 700 2030 1,425 9,400 8,460 1,745 1,745 1,745 700 495 550 950 310 105 2,055 1,355 480 191 29 700 2031 1,265 8,900 8,010 1,690 1,690 1,690 700 440 550 950 310 100 2,000 1,300 476 197 27 700 Average 3,820 15,858 13,664 3,836 3,195 3,409 1,038 1,753 618 950 310 178 3,719 2,681 656 291 91 1,038 (a) Produced water and make-up water volumes are based on annual average flow rates. (b) The make-up water volumes represent the water required to make steam. (c) The Kirby Central Plant Use (Utility) water volumes represent water volumes that do not return to process to make steam including evaporator losses. (d) Disposal volumes may vary due to operating upsets, system reliability, and produced water fluctuations. Peak disposal volume for short period of time would be 8,000 m³/cd. (e) Peak rates include additional make-up water volumes for planned well pair additions required to sustain production. (f) Annual average make-up water is based upon 4 months peak use and 8 months normal use rate per year. (g) A minimum 550 m³/cd of Empress water is required for seal flush, chemical dilution, and utility stations (for example floor washes), etc. 550 m³/cd of Empress water has a primary use as 'utility' water but is included as make-up water because it will eventually be used as boiler feed water. (h) Reservoir retention and makeup water volumes are based upon a normal SAGD operation reservoir retention of 20% for the first 5 years and 10% thereafter. This is a revised forecast in advance of operating experience - the actual reservoir retention profile may differ. Empress (Peak) [m³/cd] Annual Average [m³/cd] Evaporator Losses [m³/cd] Total Water [m³/cd] Total Fresh Water [m³/cd] Produced Water [m³/cd] Brackish Water [m³/cd] Fresh Water [m³/cd] Total Disposal [m³/cd]

Canadian Natural Resources Limited - 17 - Supplemental Information Request 3 4. Part 1, Project Update, Page 6: Table 3 and Page 7. CNRL states, The McMurray Formation basal aquifer underlies and is in contact with the bitumen reservoir, and the amount of water which can be sourced from this aquifer must be balanced with equal amounts of disposal into the same formation, in order to balance the reservoir pressure and optimize recovery of the resource However, in Table 3, the disposal rates are not balanced with the production rates from the McMurray. Please explain why or provide an updated Table 3 where the disposal and production rates balance. Response: Canadian Natural does not expect 0% reservoir retention to be realized during operations and therefore it is unlikely that there will be an imbalance between disposal into the McMurray Formation and withdrawal of source water from the McMurray Formation. Table 3 was provided, in addition to Tables 1 and 2, for illustrative purposes to demonstrate a range of potential reservoir retention scenarios. Table 3-1 (see response to SIR 3) provides a revised water forecast for the Project. This revised forecast illustrates equal disposal and withdrawal rates to/from the McMurray Formation. Canadian Natural will monitor the underlying McMurray Formation aquifer pressures during operations, and will take corrective action in the unlikely event that noticeable impacts are occurring due to an imbalance of volumes in the McMurray Formation. 5. Revised Water Act Application, Page 79, Table 16. Table 16 provides the pipeline and well pad information summary for each water supply scenario. a) In Table 16, the total pipeline length for Scenario 3 is 24.8 km. However, in Table 14c, the pipeline length used for the economic analysis is 29 km. Clarify this apparent discrepancy and provide any necessary updates. Response: a) The pipeline length used for the economic analysis for Scenario 3 in the Revised Water Act Application was incorrect. The correct total pipeline length is 24.8 km. Table 14c has been revised and is provided below as Table 5-1. Table 6-3 in the response to SIR 6c provides the updated net present values for this scenario.

Canadian Natural Resources Limited - 18 - Supplemental Information Request 3 Table 5-1 (Table 14c - Revised) Scenario 3 Economic Evaluation of Water Source Alternatives for Kirby Project Clearwater Case Component Unit Cost [$] Units No. Units Component Cost [$] McMurray Formation Drill Wells 758,225 each 2 1,516,450 7-33-73-8W4M Complete Wells 617,461 each 2 1,234,922 VFD Drive + Transformer 80,470 each 2 160,940 separate p/l Facilities 550,000 each 1 550,000 6" Titeliner Underground Pipelines 360 metre 12,430 4,474,800 Road 363 metre 3,370 1,223,310 Contingency at 10% 916,042 each 1 916,042 subtotal 7-33 10,076,464 Clearwater Drill Wells 647,300 each 7 4,531,100 4 Wellpads in 19-75-7 W4M Complete Wells (incl. pump) 397,449 each 7 2,782,143 7 wells in 19-75-7 W4M VFD Drive + Transformer 80,470 each 7 563,290 24.8 km of 10" titeliner p/l Underground Pipelines 480 metre 24,800 11,904,000 3 km of road Surface Piping 550,000 well 7 3,850,000 Road 363 metre 3,000 1,089,000 OBS Well - Drill and Complete 456,195 each 1 456,195 Contingency at 10% 2,517,573 each 1 2,517,573 subtotal Clearwater 27,693,301 Empress at Kirby 13-21 Drill Wells 0 each 1 0 Complete Wells 0 each 1 0 Utility water supply only VFD Drive + Transformer 80,470 each 1 80,470 Facilities 50,000 each 1 50,000 Underground Pipelines 350 metre 660 231,000 Road 363 metre 123 44,649 OBS Well - Drill and Complete 357,000 each 1 357,000 Annual Mon and Reporting 40,000 each 1 40,000 Contingency at 10% 80,312 each 1 80,312 subtotal 13-21 883,431 Total Capital $38,653,196 Operation and Maintenance Annual Operating Costs - $1,035,221 6. Part 2, SIR Response 8a, Page 41. CNRL states, Canadian Natural believes an aquifer thickness of at least 25 m is required before the Clearwater aquifer has water source development potential. a) Provide the basis for this statement including all supporting analysis and data. b) Discuss the water source developmental potential in thinner portions of the Clearwater aquifer if horizontal wells were used. Please note that EnCana is

Canadian Natural Resources Limited - 19 - Supplemental Information Request 3 currently using horizontal water source wells at locations (F1/13-34-075-06W4/0, F1/13-35-075-06W4/0) where the Clearwater aquifer is 15 m thick. c) Provide an updated versions of Scenario 3 (both economics and environmental) based on a direct route to the Clearwater aquifer for both a 15 m and a 25 m aquifer thickness. Response: a) The estimated Clearwater Formation thickness required for source water development potential is based on the judgement and experience of Canadian Natural gained through working with aquifers in the region, particularly the McMurray Formation aquifer and Grand Rapids Formation aquifer. Canadian Natural has not conducted aquifer testing or a rigorous hydrogeological assessment of the Clearwater Formation. However, considering the close proximity of the Clearwater Formation sand southern (no-flow) boundary to the south (see Figure 8-2 in response to Round 2 SIR 8 [Canadian Natural 2009]) and the characteristics of the aquifer (discussed in Section 8.3 of the Water Act Application (Revised) (Part 1 - Project Update, Round 2 Supplemental Information Responses [Canadian Natural 2009]) it is believed that a location containing 25 m of Clearwater Formation sand thickness is required before the Clearwater Formation can be considered a reliable source of groundwater. A source well selection would not be based solely on sand thickness however. Important considerations in addition to acceptable aquifer thickness and distance from boundaries are mineral land rights and the presence of existing wells/geological data. An assessment of potential wells at a location containing 25 m of Clearwater Formation sand thickness was conducted as Scenario 3 in the Water Act Application (Revised). The well locations in this scenario were chosen for the following reasons: A reasonable Clearwater Formation sand thickness is present and the locations are believed to be an adequate distance north from the no-flow boundaries. Canadian Natural holds petroleum and natural gas mineral rights to the Clearwater Formation at the locations (Note: Canadian Natural does not hold oil sands rights to the Clearwater Formation. While the unit is not oil sands bearing in this region it is uncertain whether Canadian Natural could obtain approval to produce water from this interval from the rights holder). Wells have been drilled in the area providing certainty regarding the presence of the required sand thicknesses in the area. It is generally Canadian Natural s practice to drill water source wells adjacent to existing wells due to the close proximity of existing geological data and a significant certainty of success. b) Canadian Natural has experience in drilling both horizontal and vertical saline water source wells, and utilizes four vertical and three horizontal McMurray Formation saline source wells at the Primrose and Wolf Lake operation.

Canadian Natural Resources Limited - 20 - Supplemental Information Request 3 Both horizontal and vertical types of wells have positive and negative features. Horizontal wells provide an opportunity for increased available drawdown due to the ability to place the pump near the base of the formation. They are also able to provide greater surface area adjacent to the formation. However, this greater surface area does not necessarily translate to significantly greater well inflow. Due to the nature of horizontal wells, effective well development may not be possible and the horizontal wells may have significantly lower well efficiency than a vertical well. Vertical wells are more economical to drill and complete and are easily developed resulting in generally high well efficiencies. Due to the uncertainty involved with horizontal well completion and deliverability, Canadian Natural s preference is to use vertical wells in the development of groundwater sources for the Kirby Project. An assessment of water source potential of a 15-m-thick Clearwater Formation Aquifer for theoretical horizontal well locations in Sections 34 and 36-74-08W4M (Figure 6-1) was conducted using Modflow as the groundwater flow model and Visual Modflow as a pre-processor/post-processor. The following parameters were used in the model: rate: 3,500 m 3 /d; duration: 20 years (duration of the Kirby Project); hydraulic conductivity: 3 x 10-5 m/s (EnCana 2005); storativity: 1.0 x 10-4 ; aquifer thickness: 15 m; depth to top of aquifer: 370 m; initial groundwater level: 180 m; and distance to no-flow boundary: 3 km. The assessment suggested that source water production in this area may be possible assuming the wells are adequately spaced apart. The model calculated that the drawdown in the aquifer using the parameters listed above at 20 years would be about 100 m at the pumping centre. Based on the modelling results, it is assumed the aquifer could sustain 3,500 m 3 /day for 20 years if the aquifer properties utilized in the modelling assessment are similar to the aquifer properties at the well location. For example, the storativity and hydraulic conductivity of the unit at this location could be much lower than the values used in the modelling simulations.

490000 500000 Tp.76 Rg.9 W4M Tp.76 Rg.8 W4M Tp.76 Rg.7 W4M Sunday Creek Tp.76 Rg.6 W4M 16-24-75-8 W4M 13-19-75-7 W4M 6150000 Tp.75 Rg.9 W4M Glover Lake Edwards Lake Tp.75 Rg.8 W4M 10-19-75-7 W4M 04-19-75-7 W4M Tp.75 Rg.7 W4M Tp.75 Rg.6 W4M 6150000 34-74-8 W4M 36-74-8 W4M Wiau Lake Tp.74 Rg.9 W4M Tp.74 Rg.8 W4M HWY 881 Scenario 3 Scenario 7 Tp.74 Rg.7 W4M Tp.74 Rg.6 W4M 6140000 6140000 Scenario 6 14-30-73-7 W4M Scenario 1 Central Plant I:\CLIENTS\CNRL\08-1346-0021\mapping\mxd\General\SIR3\Water_supply_core_scenarios_SIR3.mxd 6130000 LEGEND Tp.73 Rg.9 W4M HORIZONTAL WELL DOWN HOLE COLD LAKE AIR WEAPONS RANGE BOUNDARY HORIZONTAL WELL KIRBY PROJECT FOOTPRINT OPEN WATER PIPELINE ROUTE AND WELLPAD LOCATIONS SCENARIO 1: APPLICATION CASE SCENARIO 3: CLEARWATER FORMATION CASE Tp.73 Rg.8 W4M SCENARIO 6: 15 m CLEARWATER DIRECT ROUTE SCENARIO 7: 25 m CLEARWATER DIRECT ROUTE 490000 10-20-73-7 W4M Scenario 1 Ipiatik Lake WELLPAD REFERENCE Imagery obtained from GeoBase (2006). Alberta digital data obtained from AltaLIS Ltd. (September 2006), used under licence. Projection: UTM Zone 12 Datum: NAD 83 Tp.73 Rg.7 W4M COLD LAKE AIR WEAPONS RANGE PROJECT TITLE 500000 Calgary, Alberta Tp.73 Rg.6 W4M 4 0 4 SCALE 1:150,000 KILOMETRES WATER SUPPLY PIPELINE ROUTES AND WELLPAD LOCATION SCENARIOS REGIONAL MAP PROJECT NO. 08-1346-0021 SCALE AS SHOWN DESIGN DC 30 Jul. 2009 GIS SL 15 Sep. 2009 CHECK DC 15 Sep. 2009 REVIEW DB 15 Sep. 2009 6130000 KIRBY IN-SITU OIL SANDS PROJECT REV. 0 FIGURE: 6-1

Canadian Natural Resources Limited - 22 - Supplemental Information Request 3 Before selecting a source water location where the Clearwater Formation aquifer is 15 m thick Canadian Natural would need to conduct the following work in order to provide reasonable certainty of supply: An aquifer test to provide a reasonable estimate of aquifer parameters and aquifer boundaries. A more rigorous groundwater numerical flow model to estimate the drawdown effects and long-term delivery potential of water source wells for given locations and pumping rates using site-specific aquifer parameters obtained via the aquifer test. Obtain permission from the Petroleum and Natural Gas (P&NG) rights holders, if other than Canadian Natural. Canadian Natural holds 53.75% of P&NG lease rights at the locations in Sections 34 and 36-74-08W4M that were the subject of the preliminary modelling assessment. c) The updated versions of Scenario 3 are illustrated in Figure 6-1 as Scenarios 6 and 7, and represent direct pipeline routes to locations where the Clearwater Formation aquifer is 15 m and 25 m thick, respectively. Please note that the original Scenario 3 presented in the Water Act Application (Revised) (Part 1 - Project Update, Round 2 Supplemental Information Responses [Canadian Natural 2009]), did not follow a direct pipeline route because discussions with Alberta Sustainable Resource Development (ASRD) have historically indicated that any new development should follow existing disturbance where possible. The following discussion provides screening-level economic and environmental information for Scenarios 6 and 7, consistent with the Tier 2 requirements of the Water Conservation and Allocation Guideline for Oilfield Injection 2006 (Alberta Government 2006). For context, the discussion also provides comparisons between Scenarios 6 and 7, and Scenarios 1 (Application Case) and 3 (indirect route to 25 m Clearwater Formation aquifer thickness) presented in the Water Act Application (Revised) (Part 1 - Project Update, Round 2 Supplemental Information Responses [Canadian Natural 2009]). Canadian Natural has assessed the most direct route possible for Scenarios 6 and 7 with consideration of the following basic restrictions regarding pipeline routing: the pipeline and associated 20-m-wide right of way (ROW) will need to avoid the Kirby Project camp site and will therefore parallel the road from the Kirby Central Plant (KCP) site north for approximately 1 km, at which point a fairly direct route will be possible (Figure 6-1); and a 100 m buffer will be needed between the ROW and waterbodies, consistent with the requirements of ASRD.

Canadian Natural Resources Limited - 23 - Supplemental Information Request 3 Scenario 6 Scenario 6 involves two 200 m x 200 m wellpads (each wellpad is 4 ha), one in each of 34 and 36-74-8 W4M, with a total of seven horizontal water wells (Figure 6-1). The groundwater wells modelled in support of the response to SIR 6b are the basis for this scenario and the horizontal portion of each well within the Clearwater Formation aquifer is 800 m. The first wellpad in 36-74-8 W4M is located approximately 13 km north of the KCP and the wellpads are both accessed from secondary Highway 881. The ROW between secondary Highway 881 and the wellpads is 38 m wide to reflect the parallel pipeline, road and power line. The pipeline ROW from the KCP to the first wellpad is 20 m wide as discussed above. This scenario involves the annual average use of 3,580 m 3 /cd saline make-up water from the Clearwater Formation, 1,500 m 3 /cd saline make-up water from the McMurray Formation and 860 m 3 /cd non-saline water from the Empress Formation for utility needs (of that it would be possible to recycle 500 m 3 /cd for use as make-up water). It is assumed that sufficient deliverability exists at the well locations proposed for this scenario, although the deliverability of the Clearwater Formation is not well-defined in this area, as discussed in the response to SIR 6b. Scenario 7 Apart from the direct pipeline route from the KCP, Scenario 7 is the same as the Scenario 3 presented in the Water Act Application (Revised) (Part 1 - Project Update, Round 2 Supplemental Information Responses [Canadian Natural 2009]). Scenario 7 involves four wellpads, one in each of 16-24-75-8 W4M, 04-19, 10-19 and 13-19-75-7 W4M, with a total of seven vertical water wells (Figure 6-1). The first wellpad at 10-19-75-7 W4M is located about 19 km north of the KCP. The pipeline ROW from the KCP to the first wellpad is 20 m wide as discussed above. All wellpads are accessed from secondary Highway 881. The ROW between secondary Highway 881 and the wellpads is 38 m wide to reflect the parallel pipeline, road and power line. Scenario 7 involves the annual average use of 3,580 m 3 /cd saline make-up water from the Clearwater Formation, 1,500 m 3 /cd saline make-up water from the McMurray Formation and 860 m 3 /cd non-saline water from the Empress Formation for utility needs (of that it would be possible to recycle 500 m 3 /cd for use as make-up water). It is assumed that sufficient deliverability exists at the well locations proposed for this scenario, although the deliverability of the Clearwater Formation is not well-defined in this area, as discussed in Section 9 of the Water Act Application (Revised) (Part 1 - Project Update, Round 2 Supplemental Information Responses [Canadian Natural 2009]).