Canadian Natural Resources Limited Announces 2010 Fourth Quarter and Year End Results

CALGARY, ALBERTA--(Marketwire - March 3, 2011) - Canadian Natural Resources Limited (TSX:CNQ) (NYSE:CNQ) "Canadian Natural reached a milestone in 2010 as we achieved an overall record yearly production level of over 632,000 barrels per day of oil equivalent. In addition, we increased our total proved plus probable company gross reserves by 9% to 6.9 billion barrels of oil equivalent, replacing 341% of our 2010 production and providing us a strong base of reserves with significant upside potential for years to come. Finally, to demonstrate confidence in our growth and sustainability, the Board of Directors has increased the quarterly dividend to $0.09 per common share, a 20% increase from 2010, marking this as the eleventh year of consecutive increases for the Company." Canadian Natural's Chairman, Allan Markin stated. John Langille, Vice-Chairman of Canadian Natural summarized, "Over the last two years our core business has generated approximately $6.0 billion of free cash flow allowing us to make discretionary acquisitions of $1.9 billion while at the same time reducing debt by $4.5 billion, resulting in a debt to book capitalization of 29%. The Company's ability to generate strong cash flow enables us to manage the reduced cash flow we will experience from Horizon in 2011 without affecting our ongoing operations or capital expenditure plans. Our focus on financial discipline ensures we maintain a strong balance sheet going forward." With regards to Canadian Natural's 2010 operating year, Steve Laut, President commented, "2010 was a strong year as we capitalized on the balance in our asset base through the effective allocation of capital to projects that provide the highest returns. We are in a solid position as the project portfolio continues to build strength and optionality preparing us to provide growth through a variety of commodity price scenarios." /T/ HIGHLIGHTS Three Months Ended Year End Results ($ millions, except as Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 noted) 2010 2010 2009(1) 2010 2009(1) ---------------------------------------------------------------------------- Net earnings (loss) $ (416) $ 580 $ 455 $ 1,697 $ 1,580 Per common share, basic and diluted $ (0.38) $ 0.53 $ 0.42 $ 1.56 $ 1.46 Adjusted net earnings from operations (2) $ 618 $ 606 $ 667 $ 2,570 $ 2,689 Per common share, basic and diluted $ 0.57 $ 0.55 $ 0.61 $ 2.36 $ 2.48 Cash flow from operations (3) $ 1,641 $ 1,545 $ 1,703 $ 6,321 $ 6,090 Per common share, basic and diluted $ 1.51 $ 1.42 $ 1.57 $ 5.81 $ 5.62 Capital expenditures, net of dispositions $ 1,947 $ 914 $ 694 $ 5,506 $ 2,997 Daily production, before royalties Natural gas (MMcf/d) 1,252 1,258 1,250 1,243 1,315 Crude oil and NGLs (bbl/d) 438,835 411,585 366,451 424,985 355,463 Equivalent production (BOE/d) 647,441 621,284 574,857 632,191 574,730 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Per common share amounts have been restated to reflect a two-for-one common share split in May 2010. (2) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation of this measure is discussed in Management's Discussion and Analysis ("MD&A"). (3) Cash flow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company's ability to fund capital reinvestment and debt repayment. The derivation of this measure is discussed in the MD&A. /T/ Annual - During 2010, total crude oil and NGLs production increased by 20% from 2009 to average 424,985 bbl/d reflecting increased crude oil drilling demonstrating the Company's flexibility in allocating capital to higher return crude oil projects as well as increased production volumes from the Company's thermal and Horizon Oil Sands ("Horizon") operations. - Total natural gas production for the year averaged 1,243 MMcf/d, a decrease of 5% from 2009. Production volumes were targeted to decrease from 2009 due to the Company's strategic decision to reduce capital re-investment in natural gas resulting in a 16% reduction in North America natural gas net drilling activity. - Net earnings in 2010 increased to $1.7 billion compared to $1.6 billion in 2009. Net earnings for 2010 included net unrealized after-tax expenses related to the effects of risk management activities, fluctuations in foreign exchange rates, stock-based compensation, a $0.67 billion (after tax) ceiling test impairment charge at Gabon, Offshore West Africa and the impact of statutory tax rate changes on future income tax liabilities. Adjusted net earnings in 2010 were $2.6 billion compared to $2.7 billion in 2009. - Cash flow from operations was approximately $6.3 billion, an increase of 4% from $6.1 billion in 2009. The increase in cash flow primarily resulted from the increase in higher crude oil and NGL sales volumes and netbacks partially offset by lower realized risk management gains, lower natural gas sales volumes and netbacks, the impact of the stronger Canadian dollar and higher cash taxes. - Independent Qualified Reserves Evaluators evaluated and reviewed all of the Company's crude oil and natural gas reserves and the following are highlights based on Company gross reserves using forecast prices and costs as at December 31, 2010: -- Company Gross proved crude oil and NGL reserves increased 8% to 3.80 billion barrels. Company Gross proved natural gas reserves increased 9% to 4.26 Tcf. Total proved BOE increased 8% to 4.51 billion barrels. -- Company Gross proved plus probable crude oil and NGL reserves increased 9% to 5.94 billion barrels. Company Gross proved plus probable natural gas reserves increased 10% to 5.77 Tcf. Total proved plus probable BOE increased 9% to 6.90 billion barrels. -- Company Gross proved reserve additions, including acquisitions, were 433 million barrels of crude oil and NGL and 814 billion cubic feet of natural gas, equating to 569 million barrels of oil equivalent. The total proved reserve replacement ratio on a BOE basis is 246%. Proved undeveloped reserves accounted for 30% of the Corporate total proved reserves. -- Company Gross proved plus probable reserve additions, including acquisitions, were 624 million barrels of crude oil and NGL and 979 billion cubic feet of natural gas equating to 787 million barrels of oil equivalent. The total proved plus probable reserve replacement ratio on a BOE basis is 341%. - Total net exploration and production reserve replacement expenditures totaled $4.8 billion in 2010, including acquisitions of approximately $1.9 billion. Horizon sustaining capital totaled $0.13 billion while project capital accumulated $0.41 billion (including capitalized interest, stock-based compensation and other). Total consolidated net capital expenditures for 2010 were $5.5 billion, an increase of $2.5 billion from 2009. Fourth Quarter - Total crude oil and NGLs production for Q4/10 was 438,835 bbl/d. Q4/10 crude oil production volumes increased 7% from Q3/10 of 411,585 bbl/d, and increased 20% from Q4/09 of 366,451 bbl/d. The increase in volumes in Q4/10 from Q3/10 and Q4/09 was primarily due to the Company's thermal and Horizon production volumes. - Natural gas production volumes for the fourth quarter represented 32% of the Company's total production. Natural gas production for Q4/10 averaged 1,252 MMcf/d, comparable to 1,258 MMcf/d for Q3/10 and to 1,250 MMcf/d for Q4/09. - The Company incurred a net loss in Q4/10 of $0.4 billion which included net unrealized after-tax expenses of $1.0 billion related to the effects of risk management activities, fluctuations in foreign exchange rates, stock-based compensation and a ceiling test impairment charge at Gabon, Offshore West Africa. Excluding these items, adjusted net earnings from operations for Q4/10 was $0.6 billion, compared to adjusted net earnings of $0.6 billion in Q3/10 and $0.7 billion in Q4/09. - Quarterly cash flow from operations was approximately $1.64 billion, a 6% increase from Q3/10 and a 4% decrease from Q4/09. The increase from Q3/10 primarily reflected higher crude oil and NGL sales volumes and netbacks, partially offset by realized risk management losses. The decrease from Q4/09 reflects the impact of realized risk management losses, lower natural gas pricing and higher cash taxes, partially offset by higher crude oil and NGL sales volumes. Operational and Financial - Canadian Natural drilled a record 654 net primary heavy crude oil wells in 2010. The Company targets to drill 791 net primary heavy crude oil wells in 2011 which will drive a target 11% production growth in 2011. - Record quarterly thermal heavy crude oil production of approximately 104,000 bbl/d was achieved in Q4/10. Thermal production levels increased approximately 22% from Q3/10 and 81% from Q4/09. The Company targets 12% production growth in 2011 and continues to execute on its thermal heavy crude oil growth plan. - The Company drilled 127 horizontal wells in 2010 at Pelican Lake with plans to drill an additional 93 horizontal wells in 2011. The Company continues to convert wells to polymer flood injectors and targets 18% production growth in 2011. - During 2010, a 15 well drilling program was completed at Septimus, a Montney shale play in Northeast British Columbia and all wells have been tied in. Production volumes up to 60 MMcf/d have been achieved through the plant which had a design processing capacity of the 50 MMcf/d. Additionally, the liquids ratio associated with the Septimus play are slightly higher than expected at 30 bbl/MMcf or 1,800 bbl/d. - International operations in the North Sea and Offshore West Africa provided cash flow from operations in 2010 of approximately $960 million against capital expenditures of $395 million, resulting in significant free cash flow to the Company. International operations provide exposure to Brent oil pricing and the Company targets additional significant free cash flow from the International operations in 2011. - A continued focus on effective and efficient operations in 2010 resulted in lower production costs across the Company. In 2010, production costs on a Company average $/BOE basis decreased 6% compared to 2009. - Company total capital expenditures are targeted between $6.2 billion and $6.6 billion in 2011. The capital expenditures reflect an allocation of approximately $2.6 billion to long-term growth initiatives that will add long-term production volumes in 2012 and beyond. As the Company generates strong cash flow, the production volumes impacted at Horizon due to the Coker fire have not impacted the Company's capital expenditure plans for 2011. - During 2010, the Company acquired approximately $1.9 billion of crude oil and natural gas properties in its core regions in Western Canada. These assets provide opportunities to lower operating costs, increase reserves and/or production and capture synergies with existing processing facilities and pipelines. - The acquisition of leases adjacent to Canadian Natural's Kirby In Situ Oil Sands Project ("Kirby") provided the Company with gross proved plus probable reserves of 272 million barrels and the Company expects to gain significant operating synergies through these leases which will create the potential to drive exploitation opportunities. - Construction of Kirby Phase 1 commenced soon after sanction in Q4/10. Kirby's first steam-in is targeted for 2013 and production is targeted to peak at 40,000 bbl/d. The overall cost of Kirby Phase 1 is targeted to be $1.25 billion. - Horizon Synthetic Crude Oil ("SCO") production averaged 90,867 bbl/d in 2010, an increase of 81% from 2009. During 2010, average month over month production volumes demonstrated more consistency as preventative maintenance activities continued to be fine tuned. 2011 production volumes have been impacted as a result of a Coker fire that occurred on January 6, 2011. The Company targets to reach half plant production rates (55,000 bbl/d SCO) in Q2/11 and full plant production rates (110,000 bbl/d SCO) in Q3/11. Corporate guidance has been revised to reflect newly targeted volumes for 2011. - The Company announced the re-profiling of Horizon's expansion in Q4/10. The expansion will be executed in a staged project execution plan. Project capital will be allocated to several different modules. Total expenditures on Horizon in 2011 will range between $800 million and $1,200 million dependent upon favorable market conditions and whether the business case meets the Company's investment criteria. - In the first quarter of 2011, Canadian Natural announced that it has partnered with North West Upgrading Inc. to move forward with detailed engineering regarding the construction and operation of the bitumen refinery under the Alberta Royalty Framework's Bitumen Royalty In Kind ("BRIK") program. This project supports the Company's marketing strategy to ensure conversion capacity for the Company's products. - Long term debt reductions of approximately $1.2 billion in 2010 further enhances the Company's already strong balance sheet, even after completing approximately $1.9 billion of acquisitions over the course of the year. - During 2010, the Company repurchased two million common shares under the Company's Normal Course Issuer Bid. - Canadian Natural's Board of Directors has resolved to increase its cash dividend on common shares for the eleventh year in a row. The 2011 quarterly dividend on common shares increased by 20% to C$0.09 from C$0.075 per common share, payable April 1, 2011. The dividend increase in 2011 follows a 43% increase in 2010. OPERATIONS REVIEW AND CAPITAL ALLOCATION In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where it can dominate the land base and infrastructure. Unproved property is critical to the Company's ongoing growth and development within these core regions. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By dominating infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Further, the Company maintains large project inventories and production diversification among each of the commodities it produces; namely natural gas, light/medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, thermal heavy crude oil, synthetic crude oil and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities. /T/ OPERATIONS REVIEW Activity by core region -------------------------------------------- Net unproved properties as at Drilling activity Dec 31, 2010 year ended (thousands of net Dec 31, 2010 acres)(1) (net wells)(2) ---------------------------------------------------------------------------- North America Northeast British Columbia 2,389 34.9 Northwest Alberta 1,810 63.5 Northern Plains 6,497 879.4 Southern Plains 1,012 35.7 Southeast Saskatchewan 106 39.1 Thermal In Situ Oil Sands(3) 717 224.0 ---------------------------------------------------------------------------- 12,531 1,276.6 Oil Sands Mining and Upgrading (3) 63 264.0 North Sea 128 1.8 Offshore West Africa 4,193 7.1 ---------------------------------------------------------------------------- 16,915 1,549.5 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Unproved property refers to a property or part of a property to which no reserves have been specifically attributed. (2) Drilling activity includes stratigraphic test and service wells. (3) Portions of the Oil Sands Mining and Upgrading lands relating to Birch Mountain have been reclassified to Thermal In Situ Oil Sands in Q4/10. Drilling activity (number of wells) Year Ended Dec 31 ---------------- 2010 2009 Gross Net Gross Net ---------------------------------------------------------------------------- Crude oil 997 934 686 644 Natural gas 112 92 141 109 Dry 38 33 49 46 ---------------------------------------------------------------------------- Subtotal 1,147 1,059 876 799 Stratigraphic test / service wells 492 491 329 329 ---------------------------------------------------------------------------- Total 1,639 1,550 1,205 1,128 ---------------------------------------------------------------------------- Success rate (excluding stratigraphic test / service wells) 97% 94% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North America Exploration and Production North America natural gas Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Natural gas production (MMcf/d) 1,223 1,234 1,218 1,217 1,287 ---------------------------------------------------------------------------- Net wells targeting natural gas 19 19 28 98 117 Net successful wells drilled 18 19 28 92 109 ---------------------------------------------------------------------------- Success rate 95% 100% 100% 94% 93% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ - Q4/10 North America natural gas production volumes were up slightly from Q4/09 as a result of strong performance at Septimus and acquired natural gas volumes. Annual production for North America natural gas in 2010 was 1,217 MMcf/d, a decrease of 5% from 2009, as expected The reduction in 2010 volumes compared to 2009 was the result of a 16% reduction in the natural gas drilling program proactively implemented by the Company and partially offset by acquired natural gas volumes in 2010. - Annual natural gas production costs in 2010 were $0.01 per Mcf lower than 2009 despite a production volume decrease of 5% from 2009 and the acquisition of higher production cost properties within core areas. This demonstrates the Company's focus on effective and efficient operations and the Company's ability to leverage its dominant owned infrastructure to create synergies to lower production costs. - Canadian Natural targeted 19 net natural gas wells in Q4/10. In Northeast British Columbia, 1 net well was drilled, while in Northwest Alberta, 12 net wells were drilled. In the Northern Plains, 5 net wells were drilled, with 1 net well drilled in the Southern Plains. - Planned drilling activity for 2011 includes 72 net natural gas wells compared to drilling activity for 2010 of 98 net natural gas wells. The reduction in drilling demonstrates the Company's ability to allocate capital to higher return projects. /T/ North America crude oil and NGLs Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Crude oil and NGLs production (bbl/d) 286,698 267,177 229,206 270,562 234,523 ---------------------------------------------------------------------------- Net wells targeting crude oil 323 289 212 953 676 Net successful wells drilled 316 280 195 926 638 ---------------------------------------------------------------------------- Success rate 98% 97% 92% 97% 94% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ - Annual production for North America crude oil and NGLs in 2010 was 270,562 bbl/d, an increase of 15% from 2009 production. Q4/10 North America crude oil and NGLs production increased 7% and 25% from Q3/10 and Q4/09 levels respectively. The increase from the previous quarter reflects higher heavy crude oil volumes from each of our three growth areas, Primrose, Primary heavy crude oil and Pelican Lake. - Annual crude oil and NGLs per unit production costs in 2010 decreased 17% from 2009 as a result of higher production volumes and the lower cost of natural gas used for fuel. - Construction of Kirby Phase 1 commenced soon after sanction in Q4/10. Kirby's first steam-in is targeted for 2013 and production targeted to peak at 40,000 bbl/d. The overall cost of Kirby Phase 1 is targeted to be $1.25 billion. The Company expects to gain significant operating synergies within the Kirby development, which will create the potential to drive exploitation opportunities similar to those seen at Primrose over the last decade. - Development of new pads and tertiary recovery conversion projects at Pelican Lake continued as targeted in Q4/10. The Company drilled 127 horizontal wells in 2010 at Pelican Lake with plans to drill an additional 93 horizontal wells in 2011. Production averaged approximately 38,000 bbl/d for Q4/10, compared to approximately 38,000 bbl/d and 37,000 bbl/d for Q3/10 and Q4/09 respectively. Polymer flood production response is typically seen 18 to 24 months from injection of polymer flood and production increases from the Company's 2010 program are expected in late 2011/early 2012. By the end of 2010, 44% of the field has been converted to polymer flood. Canadian Natural targets to have close to 90% of the field under flood by 2015. - A record drilling program in primary heavy crude oil was completed in 2010. 654 net primary heavy crude oil wells were drilled and the Company is targeting to drill 791 net primary heavy crude wells in 2011. - During Q4/10, drilling activity targeted 323 net crude oil wells including 257 wells targeting heavy crude oil, 18 wells targeting Pelican Lake crude oil, 5 wells targeting thermal crude oil and 43 wells targeting light crude oil. - Planned drilling activity for 2011 includes 1,186 net crude oil wells, excluding stratigraphic test and service wells compared with 953 in 2010. The Company targets 13% production growth in North America crude oil and NGLs in 2011. /T/ International Exploration and Production Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Crude oil production (bbl/d) North Sea 31,701 27,045 34,408 33,292 37,761 Offshore West Africa 27,706 33,554 32,643 30,264 32,929 ---------------------------------------------------------------------------- Natural gas production (MMcf/d) North Sea 9 8 12 10 10 Offshore West Africa 20 16 20 16 18 ---------------------------------------------------------------------------- Net wells targeting crude oil 2.4 0.9 - 8.0 6.4 Net successful wells drilled 2.4 0.9 - 8.0 6.1 ---------------------------------------------------------------------------- Success rate 100% 100% - 100% 95% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ North Sea - North Sea production was 31,701 bbl/d during the quarter, and in line with Corporate guidance. Q4/10 production increased 17% from the previous quarter as Q3/10 was impacted by planned maintenance shut downs on all of the Company's North Sea production facilities. On an annual basis North Sea production was 33,292 bbl/d, a 12% decrease from 2009 reflecting natural declines and timing of scheduled maintenance shut downs. Offshore West Africa - In Q4/10, crude oil production at Offshore West Africa was 27,706 bbl/d, a decrease of 15% from Q4/09 as a result of natural declines and a decrease of 17% from Q3/10 reflecting compressor downtime at the Olowi Field ("Olowi"). Compressor repairs have been conducted in the fourth quarter of 2010 resulting in improved performance. - Performance at Olowi continues to be below expectations, as was previously communicated by the Company, and as a result, the Company recognized an after tax ceiling test impairment on the Olowi property of $672 million at December 31, 2010. The Company has drilled 5 wells on Platform C, 6 wells on Platform B and 2 wells on Platform A and has elected to curtail further drilling at this time as the reserve expectations are not currently economic. /T/ North America Oil Sands Mining and Upgrading - Horizon Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Synthetic crude oil production (bbl/d) 92,730 83,809 70,194 90,867 50,250 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ - Horizon SCO production averaged 90,867 bbl/d in 2010, an increase of 81% from 2009. During 2010, average month over month production volumes demonstrated more consistency as preventative maintenance activities continued to be fine tuned. 2011 production volumes will be negatively impacted as a result of a Coker fire that occurred on January 6, 2011. Corporate guidance has been revised to reflect newly targeted volumes for 2011. - Cash production costs for the year averaged $36.36 per barrel of SCO (including approximately $3.78 per barrel of natural gas input costs), which is within the Company's previously issued guidance. The decrease in costs from 2009 costs of $39.89 per barrel of SCO was primarily due to the Company's focus on planned maintenance, reliability improvement and stabilized production at higher volumes. In Q4/10, cash production costs averaged $36.13 per barrel of SCO (including approximately $3.04 per barrel of natural gas input costs) compared to $41.21 per barrel of SCO in Q4/09. - The Company announced the re-profiling of Horizon's expansion in Q4/10. The expansion will be executed in a staged project execution plan. Project capital will be allocated to several different modules. Total expenditures on Horizon in 2011 will range between $800 million and $1,200 million dependent upon favorability of market conditions and whether the business case meets the Company's investment criteria. - The Company is continuing restoration of production from, and its investigation into, the fire at its coker unit at Horizon, which occurred on January 6, 2011. A preliminary assessment of the extent of damage and timelines to repair and rebuild are as follows: -- The Coke Drums are serviceable. -- Instrumentation to many areas of the plant remain intact. -- Damage to the derrick structure over Coke Drums 1A and 1B will require the derrick to be replaced as anticipated. Damage to the derrick structure over Coke Drums 2A and 2B appears to be minimal at this point. -- Limited damage to the rails that guide the cutting tools over Coke Drum 2B will require repair before Coke Drums 2A and 2B can be restarted. -- Damage to the structural beams supporting both derrick structures over the Coke Drums will require limited repair or replacement. -- The control station used for cutting of Coke Drums 1A and 1B will need to be replaced. -- Pipe work above the Coke Drums will require inspection and testing (x-ray and or pressure testing) to determine if certain sections of pipework needs to be replaced. -- Collateral freeze damage due to the unplanned shutdown and extreme cold weather has occurred after the fire and it has been determined to be more extensive than the preliminary assessment indicated. Some pumps and more importantly, the air coolers and furnace tubes associated with the Coke Drum operation will require extensive repair or replacement. -- Material and equipment orders were initiated in January to replace components above Coke Drums 1A and 1B, as any excess material not needed for repair will be utilized in the future expansion which includes the installation of Coke Drums 3A and 3B. -- Preliminary target time lines at this early stage indicate that the first set of Coke Drums 2A and 2B are targeted to resume production in Q2/11. Once the first set of Coke Drums is onstream production rates are targeted to be 55,000 bbl/d of SCO. -- The second set of Coke Drums 1A and 1B are currently targeted to be on production in Q3/11. -- The Company has determined that the derrick and equipment above Coke Drum 2A and 2B are not on the critical path. Coker furnace tube replacement due to freezing after the fire is now on the critical path for Coke Drums 2A and 2B startup. - Fire repair/rebuild costs, including associated damage, are currently estimated at approximately $300 million to $400 million at this time, reflecting a more detailed onsite review of damages. The Company will continue to provide updates as the repair progresses. - The Company maintains an insurance program adequate to cover the cost of the repair/rebuild, as well as, business interruption insurance subject to a waiting period, to alleviate ongoing operating costs thereby somewhat mitigating financial impacts of the incident. /T/ MARKETING Three Months Ended Year Months Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Crude oil and NGLs pricing WTI(1) benchmark price (US$/bbl) $ 85.18 $ 76.21 $ 76.17 $ 79.55 $ 61.93 Western Canadian Select blend differential from WTI(%) 21% 20% 16% 18% 16% SCO price (US$/bbl) $ 83.14 $ 75.30 $ 75.07 $ 78.56 $ 61.51 Average realized pricing before risk management(2) (C$/bbl) $ 67.74 $ 63.21 $ 68.00 $ 65.81 $ 57.68 Natural gas pricing AECO benchmark price (C$/GJ) $ 3.39 $ 3.53 $ 4.01 $ 3.91 $ 3.91 Average realized pricing before risk management (C$/Mcf) $ 3.56 $ 3.75 $ 4.75 $ 4.08 $ 4.53 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at Cushing, Oklahoma. (2) Excludes SCO. /T/ - In Q4/10, the Western Canadian Select ("WCS") heavy crude oil differential as a percent of WTI was 21%. Widening of heavy crude oil differentials in Q4/10 from the comparable period in 2009 largely resulted from pipeline disruptions in the United States that occurred during Q3/10. - During Q4/10, the Company contributed approximately 180,000 bbl/d of its heavy crude oil streams to the WCS blend. Canadian Natural is the largest contributor accounting for 58% of the WCS blend. REDWATER UPGRADING AND REFINING - In Q1/11, Canadian Natural announced that it has partnered with North West Upgrading Inc. to move forward with detailed engineering regarding the construction and operation of the bitumen refinery. In addition, the partnership has entered into an agreement to process bitumen supplied by the Government of Alberta under the BRIK initiative. The project engineering is well advanced and work towards sanction level completion is ongoing. FINANCIAL REVIEW - As a result of the Company's continued focus on discipline and efficient and effective operations, the financial position of the Company is robust. Canadian Natural continually examines its liquidity position and targets a low risk approach to finance. The Company's commodity hedging program, its existing credit facilities and capital expenditure programs all support a flexible financial position: -- A large and diverse asset base spread over various commodity types - produced in excess of 630,000 BOE/d in 2010, with 95% of production located in G8 countries. -- Financial stability and liquidity - cash flow from operations of $6.3 billion in 2010 with available unused bank lines of $2.4 billion at December 31, 2010. The Company believes that its capital resources are sufficient to compensate for any short-term cashflow reductions arising from Horizon, and accordingly, the Company's targeted capital program currently remains unchanged for 2011. -- Flexibility in asset base and positive free cash flow produced from International and North America assets, and allows for a disciplined capital allocation program. - A strong balance sheet with debt to book capitalization of 29% and debt to EBITDA of 1.1 times. - Long term debt reductions of approximately $1.2 billion in 2010 further enhances the Company's already strong balance sheet, even after completing approximately $1.9 billion of acquisitions over the course of the year. - During 2010, the Company repurchased two million common shares under the Company's Normal Course Issuer Bid. - Canadian Natural's Board of Directors has resolved to increase its cash dividend on common shares for the eleventh year in a row. The 2011 quarterly dividend on common shares increased by 20% to C$0.09 from C$0.075 per common share, payable April 1, 2011. The dividend increase in 2011 follows a 43% increase in 2010. OUTLOOK The Company forecasts 2011 production levels before royalties to average between 1,177 and 1,246 MMcf/d of natural gas and between 385,000 and 427,000 bbl/d of crude oil and NGLs. Q1/11 production guidance before royalties is forecast to average between 1,249 and 1,273 MMcf/d of natural gas and between 348,000 and 365,000 bbl/d of crude oil and NGLs. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company's website at www.cnrl.com. YEAR-END RESERVES Determination of Reserves For the year ended December 31, 2010 the Company retained Independent Qualified Reserves Evaluators ("Evaluators"), Sproule Associates Limited ("Sproule") and GLJ Petroleum Consultants Ltd. ("GLJ"), to evaluate and review all of the Company's proved and proved plus probable reserves. Sproule evaluated the Company's North America and International crude oil, NGL and natural gas reserves. GLJ evaluated the Company's Horizon synthetic crude oil reserves. The Evaluators conducted the evaluation and review in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). In previous years, Canadian Natural had been granted an exemption order from the securities regulators in Canada that allowed substitution of U.S. Securities Exchange Commission requirements for certain NI 51-101 reserves disclosures. This exemption expired on December 31, 2010. As a result the 2010 reserves disclosure is presented in accordance with Canadian reporting requirements using forecast prices and escalated costs. The Reserves Committee of the Company's Board of Directors has met with and carried out independent due diligence procedures with the Evaluators as to the Company's reserves. Corporate Total - Company Gross proved crude oil and NGL reserves increased 8% to 3.80 billion barrels. Company Gross proved natural gas reserves increased 9% to 4.26 Tcf. Total proved BOE increased 8% to 4.51 billion barrels. - Company Gross proved plus probable crude oil and NGL reserves increased 9% to 5.94 billion barrels. Company Gross proved plus probable natural gas reserves increased 10% to 5.77 Tcf. Total proved plus probable BOE increased 9% to 6.90 billion barrels. - Company Gross proved reserve additions, including acquisitions, were 433 million barrels of crude oil and NGL and 814 billion cubic feet of natural gas. The total proved reserve replacement ratio on a BOE basis is 246%. Proved undeveloped reserves accounted for 30% of the Corporate total proved reserves. - On a BOE basis, crude oil and NGLs account for 84% of Company gross proved reserves and 86% of Company gross proved plus probable reserves. North America Exploration and Production - North America company gross proved crude oil and NGL reserves increased 20% to 1.49 billion barrels. Company Gross proved natural gas reserves increased 10% to 4.09 Tcf. Total proved BOE increased 16% to 2.17 billion barrels. - North America company gross proved plus probable crude oil and NGL reserves increased 22% to 2.50 billion barrels. Company Gross proved plus probable natural gas reserves increased 10% to 5.52 Tcf. Total proved plus probable BOE increased 19% to 3.42 billion barrels. - North America company gross proved reserve additions, including acquisitions, were 345 million barrels of crude oil and NGL and 805 billion cubic feet of natural gas. The total proved reserve replacement ratio on a BOE basis is 277%. Proved undeveloped reserves accounted for 48% of the North America total proved reserves. North America Oil Sands Mining and Upgrading - Company gross proved synthetic crude oil reserves increased 3% to 1.93 billion barrels. - Company gross proved plus probable synthetic crude oil reserves increased 2% to 2.89 billion barrels International Exploration and Production - North Sea company gross proved reserves decreased 4% to 265 million barrels of oil equivalent due to production and limited reserve adding activity in 2010. North Sea company gross proved plus probable reserves are 394 million barrels of oil equivalent. - Offshore West Africa company gross proved reserves decreased 11% to 135 million barrels of oil equivalent due to production and technical revisions. Offshore West Africa company gross proved plus probable reserves are 200 million barrels of oil equivalent. /T/ Summary of Company Gross Oil and Gas Reserves As of December 31, 2010 Forecast Prices and Costs Light and Primary Pelican Lake Bitumen Medium Oil Heavy Oil Heavy Oil (Thermal Oil) (MMbbl) (MMbbl) (MMbbl) (MMbbl) North America Proved Developed Producing 93 74 153 219 Developed Non-Producing 4 20 1 13 Undeveloped 13 66 85 687 ---------------------------------------------------------------------------- Total Proved 110 160 239 919 Probable 40 57 109 783 ---------------------------------------------------------------------------- Total Proved plus Probable 150 217 348 1,702 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North Sea Proved Developed Producing 78 Developed Non-Producing 16 Undeveloped 158 ---------------------------------------------------------------------------- Total Proved 252 Probable 124 ---------------------------------------------------------------------------- Total Proved plus Probable 376 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Offshore West Africa Proved Developed Producing 96 Developed Non-Producing - Undeveloped 24 ---------------------------------------------------------------------------- Total Proved 120 Probable 57 ---------------------------------------------------------------------------- Total Proved plus Probable 177 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Company Proved Developed Producing 267 74 153 219 Developed Non-Producing 20 20 1 13 Undeveloped 195 66 85 687 ---------------------------------------------------------------------------- Total Proved 482 160 239 919 Probable 221 57 109 783 ---------------------------------------------------------------------------- Total Proved plus Probable 703 217 348 1,702 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Synthetic Natural Barrels of Oil Crude Oil Natural Gas Gas Liquids Equivalent (MMbbl) (Bcf) (MMbbl) (MMBOE) ---------------------------------------------------------------------------- North America Proved Developed Producing 1,804 2,864 44 2,864 Developed Non-Producing - 180 2 70 Undeveloped 128 1,048 17 1,171 ---------------------------------------------------------------------------- Total Proved 1,932 4,092 63 4,105 Probable 956 1,430 20 2,203 ---------------------------------------------------------------------------- Total Proved plus Probable 2,888 5,522 83 6,308 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North Sea Proved Developed Producing 12 80 Developed Non-Producing 37 22 Undeveloped 29 163 ---------------------------------------------------------------------------- Total Proved 78 265 Probable 29 129 ---------------------------------------------------------------------------- Total Proved plus Probable 107 394 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Offshore West Africa Proved Developed Producing 87 110 Developed Non-Producing - - Undeveloped 5 25 ---------------------------------------------------------------------------- Total Proved 92 135 Probable 46 65 ---------------------------------------------------------------------------- Total Proved plus Probable 138 200 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Company Proved Developed Producing 1,804 2,963 44 3,055 Developed Non-Producing - 217 2 92 Undeveloped 128 1,082 17 1,358 ---------------------------------------------------------------------------- Total Proved 1,932 4,262 63 4,505 Probable 956 1,505 20 2,397 ---------------------------------------------------------------------------- Total Proved plus Probable 2,888 5,767 83 6,902 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Reconciliation of Company Gross Reserves by Product As of December 31, 2010 Forecast Prices and Costs PROVED Light and Primary Pelican Lake Bitumen North America Medium Oil Heavy Oil Heavy Oil (Thermal Oil) (MMbbl) (MMbbl) (MMbbl) (MMbbl) ---------------------------------------------------------------------------- December 31, 2009 100 116 251 732 ---------------------------------------------------------------------------- Discoveries - 1 - - Extensions 1 20 2 47 Infill Drilling 3 25 - - Improved Recovery - - 1 - Acquisitions 12 2 - 109 Dispositions - - - - Economic Factors - - - - Technical Revisions 6 30 (1) 64 Production (12) (34) (14) (33) ---------------------------------------------------------------------------- December 31, 2010 110 160 239 919 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North Sea ---------------------------------------------------------------------------- December 31, 2009 265 ---------------------------------------------------------------------------- Discoveries - Extensions - Infill Drilling - Improved Recovery - Acquisitions - Dispositions - Economic Factors - Technical Revisions (1) Production (12) ---------------------------------------------------------------------------- December 31, 2010 252 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Offshore West Africa ---------------------------------------------------------------------------- December 31, 2009 136 ---------------------------------------------------------------------------- Discoveries - Extensions - Infill Drilling - Improved Recovery - Acquisitions - Dispositions - Economic Factors - Technical Revisions (5) Production (11) ---------------------------------------------------------------------------- December 31, 2010 120 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Company ---------------------------------------------------------------------------- December 31, 2009 501 116 251 732 ---------------------------------------------------------------------------- Discoveries - 1 - - Extensions 1 20 2 47 Infill Drilling 3 25 - - Improved Recovery - - 1 - Acquisitions 12 2 - 109 Dispositions - - - - Economic Factors - - - - Technical Revisions - 30 (1) 64 Production (35) (34) (14) (33) ---------------------------------------------------------------------------- December 31, 2010 482 160 239 919 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- PROVED Synthetic Natural Gas Barrels of Oil North America Crude Oil Natural Gas Liquids Equivalent (MMbbl) (Bcf) (MMbbl) (MMBOE) ---------------------------------------------------------------------------- December 31, 2009 1,871 3,731 46 3,738 ---------------------------------------------------------------------------- Discoveries - 69 2 15 Extensions - 217 5 111 Infill Drilling - 21 1 33 Improved Recovery - 2 3 4 Acquisitions - 446 7 204 Disposition - - - - Economic Factors 1 (94) (1) (16) Technical Revisions 93 144 6 222 Production (33) (444) (6) (206) ---------------------------------------------------------------------------- December 31, 2010 1,932 4,092 63 4,105 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North Sea ---------------------------------------------------------------------------- December 31, 2009 72 277 ---------------------------------------------------------------------------- Discoveries - - Extensions - - Infill Drilling - - Improved Recovery - - Acquisitions - - Dispositions - - Economic Factors - - Technical Revisions 10 1 Production (4) (13) ---------------------------------------------------------------------------- December 31, 2010 78 265 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Offshore West Africa ---------------------------------------------------------------------------- December 31, 2009 99 152 ---------------------------------------------------------------------------- Discoveries - - Extensions - - Infill Drilling - - Improved Recovery - - Acquisitions - - Dispositions - - Economic Factors - - Technical Revisions (1) (5) Production (6) (12) ---------------------------------------------------------------------------- December 31, 2010 92 135 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Company ---------------------------------------------------------------------------- December 31, 2009 1,871 3,902 46 4,167 ---------------------------------------------------------------------------- Discoveries - 69 2 15 Extensions - 217 5 111 Infill Drilling - 21 1 33 Improved Recovery - 2 3 4 Acquisitions - 446 7 204 Dispositions - - - - Economic Factors 1 (94) (1) (16) Technical Revisions 93 153 6 218 Production (33) (454) (6) (231) ---------------------------------------------------------------------------- December 31, 2010 1,932 4,262 63 4,505 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Reconciliation of Company Gross Reserves by Product As of December 31, 2010 Forecast Prices and Costs PROBABLE Light and Primary Pelican Lake Bitumen North America Medium Oil Heavy Oil Heavy Oil (Thermal Oil) (MMbbl) (MMbbl) (MMbbl) (MMbbl) ---------------------------------------------------------------------------- December 31, 2009 41 39 106 595 ---------------------------------------------------------------------------- Discoveries - - - - Extensions - 8 2 61 Infill Drilling 3 10 1 - Improved Recovery - - - - Acquisitions 4 1 - 163 Dispositions - - - - Economic Factors - - - - Technical Revisions (8) (1) - (36) Production - - - - ---------------------------------------------------------------------------- December 31, 2010 40 57 109 783 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North Sea ---------------------------------------------------------------------------- December 31, 2009 127 ---------------------------------------------------------------------------- Discoveries - Extensions - Infill Drilling - Improved Recovery - Acquisitions - Dispositions - Economic Factors - Technical Revisions (3) Production - ---------------------------------------------------------------------------- December 31, 2010 124 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Offshore West Africa ---------------------------------------------------------------------------- December 31, 2009 63 ---------------------------------------------------------------------------- Discoveries - Extensions - Infill Drilling - Improved Recovery - Acquisitions - Dispositions - Economic Factors - Technical Revisions (6) Production - ---------------------------------------------------------------------------- December 31, 2010 57 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Company ---------------------------------------------------------------------------- December 31, 2009 231 39 106 595 ---------------------------------------------------------------------------- Discoveries - - - - Extensions - 8 2 61 Infill Drilling 3 10 1 - Improved Recovery - - - - Acquisitions 4 1 - 163 Dispositions - - - - Economic Factors - - - - Technical Revisions (17) (1) - (36) Production - - - - ---------------------------------------------------------------------------- December 31, 2010 221 57 109 783 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- PROBABLE Synthetic Natural Gas Barrels of Oil North America Crude Oil Natural Gas Liquids Equivalent (MMbbl) (Bcf) (MMbbl) (MMBOE) ---------------------------------------------------------------------------- December 31, 2009 969 1,271 15 1,977 ---------------------------------------------------------------------------- Discoveries - 19 1 4 Extensions - 98 2 89 Infill Drilling - 14 - 16 Improved Recovery - - - - Acquisitions - 110 1 187 Dispositions - (1) - - Economic Factors (3) (26) - (7) Technical Revisions (10) (55) 1 (63) Production - - - - ---------------------------------------------------------------------------- December 31, 2010 956 1,430 20 2,203 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North Sea ---------------------------------------------------------------------------- December 31, 2009 24 131 ---------------------------------------------------------------------------- Discoveries - - Extensions - - Infill Drilling - - Improved Recovery - - Acquisitions - - Dispositions - - Economic Factors - - Technical Revisions 5 (2) Production - - ---------------------------------------------------------------------------- December 31, 2010 29 129 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Offshore West Africa ---------------------------------------------------------------------------- December 31, 2009 45 71 ---------------------------------------------------------------------------- Discoveries - - Extensions - - Infill Drilling - - Improved Recovery - - Acquisitions - - Dispositions - - Economic Factors - - Technical Revisions 1 (6) Production - - ---------------------------------------------------------------------------- December 31, 2010 46 65 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Company ---------------------------------------------------------------------------- December 31, 2009 969 1,340 15 2,179 ---------------------------------------------------------------------------- Discoveries - 19 1 4 Extensions - 98 2 89 Infill Drilling - 14 - 16 Improved Recovery - - - - Acquisitions - 110 1 187 Dispositions - (1) - - Economic Factors (3) (26) - (7) Technical Revisions (10) (49) 1 (71) Production - - - - ---------------------------------------------------------------------------- December 31, 2010 956 1,505 20 2,397 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Reconciliation of Company Gross Reserves by Product As of December 31, 2010 Forecast Prices and Costs PROVED PLUS PROBABLE Light and Primary Pelican Lake Bitumen North America Medium Oil Heavy Oil Heavy Oil (Thermal Oil) (MMbbl) (MMbbl) (MMbbl) (MMbbl) ---------------------------------------------------------------------------- December 31, 2009 141 155 357 1,327 ---------------------------------------------------------------------------- Discoveries - 1 - - Extensions 1 28 4 108 Infill Drilling 6 35 1 - Improved Recovery - - 1 - Acquisitions 16 3 - 272 Dispositions - - - - Economic Factors - - - - Technical Revisions (2) 29 (1) 28 Production (12) (34) (14) (33) ---------------------------------------------------------------------------- December 31, 2010 150 217 348 1,702 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North Sea ---------------------------------------------------------------------------- December 31, 2009 392 ---------------------------------------------------------------------------- Discoveries - Extensions - Infill Drilling - Improved Recovery - Acquisitions - Dispositions - Economic Factors - Technical Revisions (4) Production (12) ---------------------------------------------------------------------------- December 31, 2010 376 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Offshore West Africa ---------------------------------------------------------------------------- December 31, 2009 199 ---------------------------------------------------------------------------- Discoveries - Extensions - Infill Drilling - Improved Recovery - Acquisitions - Dispositions - Economic Factors - Technical Revisions (11) Production (11) ---------------------------------------------------------------------------- December 31, 2010 177 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Company ---------------------------------------------------------------------------- December 31, 2009 732 155 357 1,327 ---------------------------------------------------------------------------- Discoveries - 1 - - Extensions 1 28 4 108 Infill Drilling 6 35 1 - Improved Recovery - - 1 - Acquisitions 16 3 - 272 Dispositions - - - - Economic Factors - - - - Technical Revisions (17) 29 (1) 28 Production (35) (34) (14) (33) ---------------------------------------------------------------------------- December 31, 2010 703 217 348 1,702 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- PROVED PLUS PROBABLE Synthetic Natural Gas Barrels of Oil North America Crude Oil Natural Gas Liquids Equivalent (MMbbl) (Bcf) (MMbbl) (MMBOE) ---------------------------------------------------------------------------- December 31, 2009 2,840 5,002 61 5,715 ---------------------------------------------------------------------------- Discoveries - 88 3 19 Extensions - 315 7 200 Infill Drilling - 35 1 49 Improved Recovery - 2 3 4 Acquisitions - 556 8 391 Dispositions - (1) - - Economic Factors (2) (120) (1) (23) Technical Revisions 83 88 7 159 Production (33) (444) (6) (206) ---------------------------------------------------------------------------- December 31, 2010 2,888 5,522 83 6,308 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North Sea ---------------------------------------------------------------------------- December 31, 2009 96 408 ---------------------------------------------------------------------------- Discoveries - - Extensions - - Infill Drilling - - Improved Recovery - - Acquisitions - - Dispositions - - Economic Factors - - Technical Revisions 15 (1) Production (4) (13) ---------------------------------------------------------------------------- December 31, 2010 107 394 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Offshore West Africa ---------------------------------------------------------------------------- December 31, 2009 144 223 ---------------------------------------------------------------------------- Discoveries - - Extensions - - Infill Drilling - - Improved Recovery - - Acquisitions - - Dispositions - - Economic Factors - - Technical Revisions - (11) Production (6) (12) ---------------------------------------------------------------------------- December 31, 2010 138 200 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Company ---------------------------------------------------------------------------- December 31, 2009 2,840 5,242 61 6,346 ---------------------------------------------------------------------------- Discoveries - 88 3 19 Extensions - 315 7 200 Infill Drilling - 35 1 49 Improved Recovery - 2 3 4 Acquisitions - 556 8 391 Dispositions - (1) - - Economic Factors (2) (120) (1) (23) Technical Revisions 83 104 7 147 Production (33) (454) (6) (231) ---------------------------------------------------------------------------- December 31, 2010 2,888 5,767 83 6,902 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Summary of Company Net Oil and Gas Reserves As of December 31, 2010 Forecast Prices and Costs Light and Primary Pelican Lake Bitumen Medium Oil Heavy Oil Heavy Oil (Thermal Oil) (MMbbl) (MMbbl) (MMbbl) (MMbbl) North America Proved Developed Producing 79 62 120 164 Developed Non-Producing 3 16 - 12 Undeveloped 11 57 62 535 ---------------------------------------------------------------------------- Total Proved 93 135 182 711 Probable 33 47 72 600 ---------------------------------------------------------------------------- Total Proved plus Probable 126 182 254 1,311 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North Sea Proved Developed Producing 78 Developed Non-Producing 16 Undeveloped 158 ---------------------------------------------------------------------------- Total Proved 252 Probable 124 ---------------------------------------------------------------------------- Total Proved plus Probable 376 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Offshore West Africa Proved Developed Producing 82 Developed Non-Producing - Undeveloped 19 ---------------------------------------------------------------------------- Total Proved 101 Probable 48 ---------------------------------------------------------------------------- Total Proved plus Probable 149 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Company Proved Developed Producing 239 62 120 164 Developed Non-Producing 19 16 - 12 Undeveloped 188 57 62 535 ---------------------------------------------------------------------------- Total Proved 446 135 182 711 Probable 205 47 72 600 ---------------------------------------------------------------------------- Total Proved plus Probable 651 182 254 1,311 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Synthetic Natural Gas Barrels of Oil Crude Oil Natural Gas Liquids Equivalent (MMbbl) (Bcf) (MMbbl) (MMBOE) North America Proved Developed Producing 1,483 2,561 30 2,365 Developed Non-Producing - 150 2 58 Undeveloped 114 927 13 946 ---------------------------------------------------------------------------- Total Proved 1,597 3,638 45 3,369 Probable 764 1,232 14 1,735 ---------------------------------------------------------------------------- Total Proved plus Probable 2,361 4,870 59 5,104 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- North Sea Proved Developed Producing 12 80 Developed Non-Producing 37 22 Undeveloped 29 163 ---------------------------------------------------------------------------- Total Proved 78 265 Probable 29 129 ---------------------------------------------------------------------------- Total Proved plus Probable 107 394 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Offshore West Africa Proved Developed Producing 72 94 Developed Non-Producing - - Undeveloped 4 20 ---------------------------------------------------------------------------- Total Proved 76 114 Probable 37 54 ---------------------------------------------------------------------------- Total Proved plus Probable 113 168 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Company Proved Developed Producing 1,483 2,645 30 2,539 Developed Non-Producing - 187 2 80 Undeveloped 114 960 13 1,129 ---------------------------------------------------------------------------- Total Proved 1,597 3,792 45 3,748 Probable 764 1,298 14 1,918 ---------------------------------------------------------------------------- Total Proved plus Probable 2,361 5,090 59 5,666 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests. (2) Company Net reserves are working interest share after deduction of royalties and including any royalty interests. (3) Forecast pricing assumptions utilized by the independent qualified reserves evaluators in the reserve estimates were provided by Sproule Associates Limited: Average annual increase 2011 2012 2013 2014 2015 thereafter ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Crude oil and NGLs WTI at Cushing (US$/bbl) $88.40 $89.14 $88.77 $88.88 $90.22 1.5% Western Canada Select (C$/bbl) $80.04 $80.71 $78.48 $76.70 $77.86 1.5% Edmonton Par (C$/bbl) $93.08 $93.85 $93.43 $93.54 $94.95 1.5% Edmonton Pentanes+ (C$/bbl) $95.32 $96.11 $95.68 $95.79 $97.24 1.5% North Sea Brent (US$/bbl) $87.15 $87.87 $87.48 $87.58 $88.89 1.5% ---------------------------------------------------------------------------- Natural gas Henry Hub Louisiana (US$/MMBtu) $ 4.44 $ 5.01 $ 5.32 $ 6.80 $ 6.90 1.5% AECO (C$/MMBtu) $ 4.04 $ 4.66 $ 4.99 $ 6.58 $ 6.69 1.5% BC Westcoast Station 2 (C$/MMBtu) $ 3.98 $ 4.60 $ 4.93 $ 6.52 $ 6.63 1.5% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- A foreign exchange rate of US$0.932/C$ 1.000 was used in the 2010 evaluation. (4) Reserve additions are comprised of all categories of Company Gross reserve changes, exclusive of production. (5) Reserve replacement ratio is the Company Gross reserve additions divided by the Company Gross production in the same period. (6) Barrels of oil equivalent (BOE)is a conversion ratio of six thousand cubic feet (Mcf) of natural gas to one barrel (bbl) of crude oil. /T/ MANAGEMENT'S DISCUSSION AND ANALYSIS Forward-Looking Statements Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes and costs, royalties, operating costs, capital expenditures, income tax expenses and other guidance provided throughout this Management's Discussion and Analysis ("MD&A"), constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands resumption of production and future expansion, Primrose, Pelican Lake, Olowi Field (Offshore Gabon), the Kirby Thermal Oil Sands Project, the Keystone Pipeline US Gulf Coast expansion, and the construction and operation of the North West upgrader also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company's products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company's current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company's and its subsidiaries' ability to secure adequate transportation for its products; unexpected difficulties in mining, extracting or upgrading the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas; availability and cost of financing; the Company's and its subsidiaries' success of exploration and development activities and their ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, bitumen, natural gas and natural gas liquids ("NGLs") not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company's provision for taxes; and other circumstances affecting revenues and expenses. The Company's operations have been, and in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available. Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements should circumstances or Management's estimates or opinions change. Management's Discussion and Analysis Management's Discussion and Analysis of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements for the year ended December 31, 2010 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2009. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. Common share data has been restated to reflect the two-for-one share split in May 2010. The Company's consolidated financial statements and this MD&A have been prepared in accordance with generally accepted accounting principles in Canada ("GAAP") in effect as at and for the periods ended December 31, 2010. Effective January 1, 2011, the Company will adopt International Financial Reporting Standards ("IFRS") as promulgated by the International Accounting Standards Board. Unless otherwise stated, references to Canadian GAAP do not incorporate the impact of any changes to accounting standards that will be required due to changes required by IFRS. This MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings from operations, cash flow from operations, and cash production costs. These financial measures are not defined by GAAP and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with GAAP, as an indication of the Company's performance. The non-GAAP measures adjusted net earnings from operations and cash flow from operations are reconciled to net earnings, as determined in accordance with GAAP, in the "Financial Highlights" section of this MD&A. The derivation of cash production costs is included in the "Operating Highlights - Oil Sands Mining and Upgrading" section of this MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the "Liquidity and Capital Resources" section of this MD&A. The calculation of barrels of oil equivalent ("BOE") is based on a conversion ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil to estimate relative energy content. This conversion may be misleading, particularly when used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency method primarily applicable at the burner tip and does not represent the value equivalency at the wellhead. Production volumes and per barrel statistics are presented throughout this MD&A on a "before royalty" or "gross" basis, and realized prices are net of transportation and blending costs and exclude the effect of risk management activities. Production on an "after royalty" or "net" basis is also presented for information purposes only. The following discussion refers primarily to the Company's financial results for the year and three months ended December 31, 2010 in relation to the comparable periods in 2009 and the third quarter of 2010. The accompanying tables form an integral part of this MD&A. This MD&A is dated March 1, 2011. Additional information relating to the Company, including its amended Annual Information Form for the year ended December 31, 2009, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. /T/ FINANCIAL HIGHLIGHTS ($ millions, except per common share amounts) Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009(1) 2010 2009(1) ---------------------------------------------------------------------------- Revenue, before royalties $ 3,787 $ 3,341 $ 3,319 $ 14,322 $ 11,078 Net earnings (loss) $ (416) $ 580 $ 455 $ 1,697 $ 1,580 Per common share - basic and diluted $ (0.38) $ 0.53 $ 0.42 $ 1.56 $ 1.46 Adjusted net earnings from operations (2) $ 618 $ 606 $ 667 $ 2,570 $ 2,689 Per common share - basic and diluted $ 0.57 $ 0.55 $ 0.61 $ 2.36 $ 2.48 Cash flow from operations (3) $ 1,641 $ 1,545 $ 1,703 $ 6,321 $ 6,090 Per common share - basic and diluted $ 1.51 $ 1.42 $ 1.57 $ 5.81 $ 5.62 Capital expenditures, net of dispositions $ 1,947 $ 914 $ 694 $ 5,506 $ 2,997 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Per common share amounts have been restated to reflect a two-for-one common share split in May 2010. (2) Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation "Adjusted Net Earnings from Operations" presented below lists the after-tax effects of certain items of a non-operational nature that are included in the Company's financial results. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies. (3) Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation "Cash Flow from Operations" presented below lists certain non-cash items that are included in the Company's financial results. Cash flow from operations may not be comparable to similar measures presented by other companies. Adjusted Net Earnings from Operations Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($ millions) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Net earnings (loss) as reported $ (416) $ 580 $ 455 $ 1,697 $ 1,580 Stock-based compensation expense, net of tax (a)(e) 336 18 65 294 261 Unrealized risk management loss (gain), net of tax (b) 131 71 224 (16) 1,437 Unrealized foreign exchange gain, net of tax (c) (105) (63) (77) (160) (570) Gabon, Offshore West Africa ceiling test impairment (d) 672 - - 672 - Effect of statutory tax rate and other legislative changes on future income tax liabilities (e) - - - 83 (19) ---------------------------------------------------------------------------- Adjusted net earnings from operations $ 618 $ 606 $ 667 $ 2,570 $ 2,689 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (a) The Company's employee stock option plan provides for a cash payment option. Accordingly, the intrinsic value of the outstanding vested options is recorded as a liability on the Company's balance sheet and periodic changes in the intrinsic value are recognized in net earnings or are capitalized to Oil Sands Mining and Upgrading construction costs. (b) Derivative financial instruments are recorded at fair value on the balance sheet, with changes in fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil and natural gas. (c) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, offset by the impact of cross currency swaps, and are recognized in net earnings. (d) Performance from the Olowi Field continues to be below expectations. As a result, the Company recognized a pre-tax ceiling test impairment charge of $726 million ($672 million after-tax) at December 31, 2010. (e) All substantively enacted or enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company's consolidated balance sheet in determining future income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in net earnings during the period the legislation is substantively enacted or enacted. During the first quarter of 2010, the Canadian Federal budget proposed changes to the taxation of stock options surrendered by employees for cash payments. As a result of the changes, the Company anticipates that Canadian based employees will no longer surrender their options for cash payments, resulting in a loss of future income tax deductions for the Company. The impact of this change was an $83 million charge to future income tax expense during the first quarter. Income tax rate changes in the first quarter of 2009 resulted in a reduction of future income tax liabilities of approximately $19 million in North America. Cash Flow from Operations Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($ millions) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Net earnings (loss) $ (416) $ 580 $ 455 $ 1,697 $ 1,580 Non-cash items: Depletion, depreciation and amortization 1,578 851 836 4,036 2,819 Asset retirement obligation accretion 27 28 23 107 90 Stock-based compensation expense 336 18 87 294 355 Unrealized risk management loss (gain) 173 92 308 (25) 1,991 Unrealized foreign exchange gain (120) (75) (88) (180) (661) Deferred petroleum revenue tax expense 5 11 7 28 15 Future income tax expense (recovery) 58 40 75 364 (99) ---------------------------------------------------------------------------- Cash flow from operations $ 1,641 $ 1,545 $ 1,703 $ 6,321 $ 6,090 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS Net earnings for the year ended December 31, 2010 were $1,697 million compared to $1,580 million for the year ended December 31, 2009. Net earnings for the year ended December 31, 2010 included net unrealized after-tax expenses of $873 million related to the effects of stock-based compensation, risk management activities, fluctuations in foreign exchange rates, the impact of a ceiling test impairment charge at Gabon, Offshore West Africa and the impact of statutory tax rate and other legislative changes on future income tax liabilities, compared to $1,109 million for the year ended December 31, 2009. Excluding these items, adjusted net earnings from operations for the year ended December 31, 2010 were $2,570 million, compared to $2,689 million for the year ended December 31, 2009. The decrease in adjusted net earnings from the year ended December 31, 2009 was primarily due to: - lower realized risk management gains; - higher depletion, depreciation and amortization expense; - lower natural gas sales volumes and netbacks; and - the impact of the stronger Canadian dollar, partially offset by - the impact of higher crude oil and NGL sales volumes and netbacks. The net loss for the fourth quarter of 2010 was $416 million compared to net earnings of $455 million for the fourth quarter of 2009 and $580 million for the prior quarter. The net loss for the fourth quarter of 2010 included net unrealized after-tax expenses of $1,034 million related to the effects of stock-based compensation, risk management activities, fluctuations in foreign exchange rates, and the impact of a ceiling test impairment charge at Gabon, Offshore West Africa compared to $212 million for the fourth quarter of 2009 and $26 million for the prior quarter. Excluding these items, adjusted net earnings from operations for the fourth quarter of 2010 were $618 million compared to $667 million for the fourth quarter of 2009 and $606 million for the prior quarter. The decrease in adjusted net earnings for the fourth quarter of 2010, compared to the fourth quarter of 2009 was primarily due to the impact of realized risk management losses, lower natural gas pricing and the impact of the stronger Canadian dollar, partially offset by higher crude oil and NGL sales volumes. The increase in adjusted net earnings for the fourth quarter of 2010, compared to the prior quarter, was primarily due to the impact of higher crude oil and NGL sales volumes and netbacks, partially offset by realized risk management losses. The impacts of stock-based compensation, unrealized risk management activities and changes in foreign exchange rates are expected to continue to contribute to quarterly volatility in consolidated net earnings and are discussed in detail in the relevant sections of this MD&A. Cash flow from operations for the year ended December 31, 2010 was $6,321 million compared to $6,090 million for the year ended December 31, 2009. Cash flow from operations for the fourth quarter of 2010 was $1,641 million compared to $1,703 million for the fourth quarter of 2009 and $1,545 million for the prior quarter. The increase in cash flow from operations for the year ended December 31, 2010 from the comparable period in 2009 was primarily due to: - the impact of higher crude oil and NGL sales volumes and netbacks, partially offset by - lower realized risk management gains; - lower natural gas sales volumes and netbacks; - higher cash taxes; and - the impact of the stronger Canadian dollar. The decrease in cash flow from operations in the current quarter compared to the fourth quarter of 2009 was primarily due to: - realized risk management losses; - the impact of lower natural gas pricing; and - higher cash taxes, partially offset by - the impact of higher crude oil and NGL sales volumes. The increase in cash flow from operations from the prior quarter was primarily due to the impact of higher crude oil and NGL sales volumes and netbacks, partially offset by realized risk management losses. Total production before royalties for the year ended December 31, 2010 increased 10% to 632,191 BOE/d from 574,730 BOE/d for the year ended December 31, 2009. Total production before royalties for the fourth quarter of 2010 increased 13% to 647,441 BOE/d from 574,857 BOE/d for the fourth quarter of 2009 and increased 4% from 621,284 BOE/d for the prior quarter. Production for the fourth quarter of 2010 was within the Company's previously issued guidance. SUMMARY OF QUARTERLY RESULTS The following is a summary of the Company's quarterly results for the eight most recently completed quarters: /T/ ($ millions, except per common Dec 31 Sep 30 Jun 30 Mar 31 share amounts) 2010 2010 2010 2010(1) ---------------------------------------------------------------------------- Revenue, before royalties $ 3,787 $ 3,341 $ 3,614 $ 3,580 Net earnings (loss) $ (416) $ 580 $ 667 $ 866 Net earnings (loss) per common share - Basic and diluted $ (0.38) $ 0.53 $ 0.61 $ 0.80 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ($ millions, except per common share Dec 31 Sep 30 Jun 30 Mar 31 amounts) 2009(1) 2009(1) 2009(1) 2009(1) ---------------------------------------------------------------------------- Revenue, before royalties $ 3,319 $ 2,823 $ 2,750 $ 2,186 Net earnings $ 455 $ 658 $ 162 $ 305 Net earnings per common share - Basic and diluted $ 0.42 $ 0.61 $ 0.15 $ 0.28 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Per common share amounts have been restated to reflect a two-for-one common share split in May 2010. /T/ Volatility in the quarterly net earnings (loss) over the eight most recently completed quarters was primarily due to: - Crude oil pricing - The impact of fluctuating demand, inventory storage levels and geopolitical uncertainties on worldwide benchmark pricing, and the impact of the Heavy Crude Oil Differential from WTI ("Heavy Differential") in North America. - Natural gas pricing - The impact of seasonal fluctuations in both the demand for natural gas and inventory storage levels, and the impact of increased shale gas production in the US, as well as fluctuations in imports of liquefied natural gas into the US. - Crude oil and NGLs sales volumes - Fluctuations in production due to the cyclic nature of the Company's Primrose thermal projects, the results from the Pelican Lake water and polymer flood projects, and the commencement and ramp up of operations at Horizon. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore West Africa. - Natural gas sales volumes - Fluctuations in production due to the Company's strategic decision to reduce natural gas drilling activity in North America and the allocation of capital to higher return crude oil projects, as well as natural decline rates and the impact of acquisitions. - Production expense - Fluctuations primarily due to the impact of the demand for services, fluctuations in product mix, the impact of seasonal costs that are dependent on weather, production and cost optimizations in North America and the commencement of operations at Horizon and the Olowi Field in Offshore Gabon. - Depletion, depreciation and amortization - Fluctuations due to changes in sales volumes, proved reserves, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, the impact of the commencement of operations at Horizon and the Olowi Field in Offshore Gabon and the impact of ceiling test impairments at the Olowi Field. - Stock-based compensation - Fluctuations due to the mark-to-market movements of the Company's stock-based compensation liability. Stock-based compensation expense (recovery) reflected fluctuations in the Company's share price. - Risk management - Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company's risk management activities. - Foreign exchange rates - Changes in the Canadian dollar relative to the US dollar impacted the realized price the Company received for its crude oil and natural gas sales, as sales prices are based predominately on US dollar denominated benchmarks. Fluctuations in unrealized foreign exchange gains and losses are recorded with respect to US dollar denominated debt and the re-measurement of North Sea future income tax liabilities denominated in UK pounds sterling to US dollars, partially offset by the impact of cross currency swap hedges. - Income tax expense - Fluctuations in income tax expense (recovery) include statutory tax rate and other legislative changes substantively enacted or enacted in the various periods. /T/ BUSINESS ENVIRONMENT Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- WTI benchmark price (US$/bbl) (1) $ 85.18 $ 76.21 $ 76.17 $ 79.55 $ 61.93 Dated Brent benchmark price (US$/bbl) $ 86.49 $ 76.85 $ 74.54 $ 79.50 $ 61.61 WCS blend differential from WTI (US$/bbl) $ 18.15 $ 15.60 $ 12.08 $ 14.26 $ 9.64 WCS blend differential from WTI (%) 21% 20% 16% 18% 16% SCO price (US$/bbl) (2) $ 83.14 $ 75.30 $ 75.07 $ 78.56 $ 61.51 Condensate benchmark price (US$/bbl) $ 85.18 $ 74.52 $ 74.46 $ 81.81 $ 60.60 NYMEX benchmark price (US$/MMBtu) $ 3.81 $ 4.42 $ 4.27 $ 4.42 $ 4.03 AECO benchmark price (C$/GJ) $ 3.39 $ 3.53 $ 4.01 $ 3.91 $ 3.91 US / Canadian dollar average exchange rate $ 0.9874 $ 0.9624 $ 0.9468 $ 0.9709 $ 0.8760 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) West Texas Intermediate ("WTI") (2) Synthetic Crude Oil ("SCO") /T/ Commodity Prices Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$79.55 per bbl for the year ended December 31, 2010, an increase of 28% from US$61.93 per bbl for the year ended December 31, 2009. WTI averaged US$85.18 per bbl for the fourth quarter of 2010, an increase of 12% from US$76.17 per bbl for the fourth quarter of 2009, and from US$76.21 per bbl in the prior quarter. WTI pricing was reflective of the slow overall economic recovery in the United States and Europe, with offsetting strong Asian demand mitigating the decline. The relative weakness of the US dollar also contributed to higher WTI pricing. Crude oil sales contracts for the Company's North Sea and Offshore West Africa segments are typically based on Dated Brent ("Brent") pricing, which is more reflective of international markets and overall supply and demand. Brent averaged US$79.50 per bbl for the year ended December 31, 2010, an increase of 29% compared to US$61.61 per bbl for the year ended December 31, 2009. Brent averaged US$86.49 per bbl for the fourth quarter of 2010, an increase of 16% compared to US$74.54 per bbl for the fourth quarter of 2009, and an increase of 13% from US$76.85 per bbl for the prior quarter. Brent pricing was reflective of continued strong demand from Asian markets. The higher Brent pricing relative to WTI was due to logistical constraints and high inventory levels of crude at Cushing during portions of 2010. The Western Canadian Select ("WCS") Heavy Differential averaged 18% for the year ended December 31, 2010 compared to 16% for the year ended December 31, 2009. The WCS Heavy Differential widened in the fourth quarter of 2010, averaging 21% compared to 16% for the fourth quarter of 2009 and 20% for the prior quarter, partially due to pipeline disruptions in the last half of 2010 that forced the temporary shutdown and apportionment of major oil pipelines to Midwest refineries in the United States. The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During the fourth quarter of 2010, condensate prices were comparable to WTI, compared to a discount in the prior quarter, reflecting normal seasonality. The Company anticipates continued volatility in crude oil pricing benchmarks due to the unpredictable nature of supply and demand factors, geopolitical events, and the timing and extent of the continuing economic recovery. The Heavy Differential is expected to continue to reflect seasonal demand fluctuations and refinery margins. NYMEX natural gas prices averaged US$4.42 per MMBtu for the year ended December 31, 2010, an increase of 10% from US$4.03 per MMBtu for the year ended December 31, 2009. NYMEX natural gas prices averaged US$3.81 per MMBtu for the fourth quarter of 2010, a decrease of 11% from US$4.27 per MMBtu for the fourth quarter of 2009, and a decrease of 14% from US$4.42 per MMBtu for the prior quarter. AECO natural gas prices averaged $3.91 per GJ for the years ended December 31, 2010 and 2009. AECO natural gas prices for the fourth quarter of 2010 decreased 15% to average $3.39 per GJ from $4.01 per GJ in the fourth quarter of 2009, and decreased 4% from $3.53 per GJ for the prior quarter. Cool weather in the United States in the fourth quarter of 2010 positively impacted natural gas prices, drawing down the high inventory levels and partially offsetting strong incremental production from shale gas plays. Natural gas prices continue to be depressed due to strong US natural gas production limiting the upside to natural gas price recovery. /T/ DAILY PRODUCTION, before royalties Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Crude oil and NGLs (bbl/d) North America - Exploration and Production 286,698 267,177 229,206 270,562 234,523 North America - Oil Sands Mining and Upgrading 92,730 83,809 70,194 90,867 50,250 North Sea 31,701 27,045 34,408 33,292 37,761 Offshore West Africa 27,706 33,554 32,643 30,264 32,929 ---------------------------------------------------------------------------- 438,835 411,585 366,451 424,985 355,463 ---------------------------------------------------------------------------- Natural gas (MMcf/d) North America 1,223 1,234 1,218 1,217 1,287 North Sea 9 8 12 10 10 Offshore West Africa 20 16 20 16 18 ---------------------------------------------------------------------------- 1,252 1,258 1,250 1,243 1,315 ---------------------------------------------------------------------------- Total barrels of oil equivalent (BOE/d) 647,441 621,284 574,857 632,191 574,730 ---------------------------------------------------------------------------- Product mix Light/medium crude oil and NGLs 17% 18% 20% 18% 21% Heavy Pelican Lake crude oil 6% 6% 7% 6% 6% Heavy primary crude oil 15% 15% 15% 15% 15% Bitumen (thermal heavy crude oil) 16% 14% 10% 14% 11% Synthetic crude oil 14% 13% 12% 14% 9% Natural gas 32% 34% 36% 33% 38% ---------------------------------------------------------------------------- Percentage of gross revenue (1) (excluding midstream revenue) Crude oil and NGLs 88% 86% 82% 85% 78% Natural gas 12% 14% 18% 15% 22% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Net of transportation and blending costs and excluding risk management activities. DAILY PRODUCTION, net of royalties Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Crude oil and NGLs (bbl/d) North America - Exploration and Production 223,034 220,836 195,070 219,736 201,873 North America - Oil Sands Mining and Upgrading 89,530 81,077 67,806 87,763 48,833 North Sea 31,644 27,002 34,341 33,227 37,683 Offshore West Africa 25,291 30,724 30,296 28,288 29,922 ---------------------------------------------------------------------------- 369,499 359,639 327,513 369,014 318,311 ---------------------------------------------------------------------------- Natural gas (MMcf/d) North America 1,206 1,213 1,135 1,168 1,214 North Sea 9 8 12 10 10 Offshore West Africa 18 15 19 15 17 ---------------------------------------------------------------------------- 1,233 1,236 1,166 1,193 1,241 ---------------------------------------------------------------------------- Total barrels of oil equivalent (BOE/d) 574,959 565,595 521,894 567,743 525,103 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ The Company's business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely natural gas, light/medium crude oil and NGLs, heavy Pelican Lake crude oil, heavy primary crude oil, bitumen (thermal heavy crude oil), and SCO. Total crude oil and NGLs production for the year ended December 31, 2010 increased 20% to 424,985 bbl/d from 355,463 bbl/d for the year ended December 31, 2009. The increase was primarily due to the higher volumes from the Company's thermal and Horizon operations. Total crude oil and NGLs production for the fourth quarter of 2010 increased 20% to 438,835 bbl/d from 366,451 bbl/d for the fourth quarter of 2009, and increased 7% from 411,585 bbl/d for the prior quarter. The increase from the comparable period in 2009 was primarily related to the cyclic nature of the Company's thermal operations and increased Horizon production. The increase from the prior quarter was related to an unplanned outage at Horizon and planned turnaround activities in the North Sea that reduced production in the third quarter of 2010, and the impact of the cyclic nature of the Company's thermal production. Crude oil and NGLs production in the fourth quarter of 2010 was within the Company's previously issued guidance of 432,000 to 456,000 bbl/d. Natural gas production for the year ended December 31, 2010 decreased 5% to 1,243 MMcf/d compared to 1,315 MMcf/d for the year ended December 31, 2009. Natural gas production for the fourth quarter of 2010 of 1,252 MMcf/d was comparable to the fourth quarter of 2009 and the prior quarter. The decrease in natural gas production from the year ended December 31, 2009 reflects the expected production declines due to the allocation of capital to higher return crude oil projects, which resulted in a strategic reduction of natural gas drilling activity, partially offset by new production volumes from the Septimus facility in North East British Columbia and from natural gas producing properties acquired during the year. Natural gas production in the fourth quarter of 2010 was within the Company's previously issued guidance of 1,248 to 1,273 MMcf/d. For 2011, revised annual production guidance is targeted to average between 385,000 and 427,000 bbl/d of crude oil and NGLs and between 1,177 and 1,246 MMcf/d of natural gas. First quarter 2011 production guidance is targeted to average between 348,000 and 365,000 bbl/d of crude oil and NGLs and between 1,249 and 1,273 MMcf/d of natural gas. North America - Exploration and Production North America crude oil and NGLs production for the year ended December 31, 2010 increased 15% to average 270,562 bbl/d from 234,523 bbl/d for the year ended December 31, 2009. For the fourth quarter of 2010, crude oil and NGLs production increased 25% to average 286,698 bbl/d, compared to 229,206 bbl/d for the fourth quarter of 2009, and increased 7% from 267,177 bbl/d for the prior quarter. Increases in crude oil and NGLs production from comparable periods were primarily due to the cyclic nature of the Company's thermal production and the results of the impact of a record heavy oil drilling program. Production of crude oil and NGLs was within the Company's previously issued guidance of 283,000 bbl/d to 293,000 bbl/d for the fourth quarter of 2010. Natural gas production for the year ended December 31, 2010 decreased 5% to 1,217 MMcf/d from 1,287 MMcf/d for the year ended December 31, 2009. For the fourth quarter of 2010, natural gas production of 1,223 MMcf/d was comparable to the fourth quarter of 2009 and the prior quarter. The decrease in natural gas production for the year ended December 31, 2010 from the comparable period in 2009 reflected the expected production declines due to the allocation of capital to higher return crude oil projects, which resulted in a strategic reduction of natural gas drilling activity, partially offset by new production volumes from the Septimus facility in North East British Columbia and from natural gas producing properties acquired during the year. Production of natural gas was within the Company's previously issued guidance of 1,220 MMcf/d to 1,240 MMcf/d for the fourth quarter of 2010. North America - Oil Sands Mining and Upgrading Horizon Phase 1 commenced production of synthetic crude oil during 2009. Production averaged 90,867 bbl/d for the year ended December 31, 2010, an increase of 81% from 50,250 bbl/d for the year ended December 31, 2009. For the fourth quarter of 2010, production increased 32% to 92,730 bbl/d, compared to 70,194 bbl/d in the fourth quarter of 2009, and increased 11% from 83,809 bbl/d in the prior quarter. Increases in production of synthetic crude oil from comparable periods in 2009 reflected the Company's focus on reliability improvements and ramping up of production. The increase in the current quarter, compared to the prior quarter, reflected the impact of a plant-wide shutdown for unplanned maintenance in the prior quarter. Fourth quarter production for 2010 was within the Company's previously issued guidance of 90,000 bbl/d to 100,000 bbl/d. North Sea North Sea crude oil production for the year ended December 31, 2010 decreased 12% to 33,292 bbl/d from 37,761 bbl/d for the year ended December 31, 2009. Fourth quarter 2010 North Sea crude oil production decreased 8% to 31,701 bbl/d from 34,408 bbl/d for the fourth quarter of 2009 and increased 17% from 27,045 bbl/d in the prior quarter. Decreases in production volumes from the comparable periods in 2009 were due to the natural field declines and timing of scheduled maintenance shut downs. The increase in production volumes in the current quarter was a result of planned maintenance shut downs on all of the Company's North Sea production facilities in the prior quarter. Production in the fourth quarter of 2010 was within the Company's previously issued guidance of 30,000 bbl/d to 32,000 bbl/d. Offshore West Africa Offshore West Africa crude oil production decreased 8% to 30,264 bbl/d for the year ended December 31, 2010 from 32,929 bbl/d for the year ended December 31, 2009. Fourth quarter crude oil production decreased 15% to 27,706 bbl/d from 32,643 bbl/d for the fourth quarter of 2009, and decreased 17% from 33,554 bbl/d in the prior quarter. Decreases in production volumes from the comparable periods in 2009 were due to natural field declines. The decrease in production volumes from the prior quarter was due to compressor downtime at the Olowi Field. Repairs have been conducted in the fourth quarter of 2010 resulting in better compressor uptimes during the first quarter of 2011. Production in the fourth quarter of 2010 was below the Company's previously issued guidance of 29,000 bbl/d to 31,000 bbl/d. Crude Oil Inventory Volumes The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place. Revenue has not been recognized on crude oil volumes that were stored in various tanks, pipelines, or floating production, storage and offloading vessels, as follows: /T/ Dec 31 Sep 30 Dec 31 (bbl) 2010 2010 2009 ---------------------------------------------------------------------------- North America - Exploration and Production 761,351 761,351 1,131,372 North America - Oil Sands Mining and Upgrading (SCO) 1,172,200 1,045,281 1,224,481 North Sea 264,995 793,582 713,112 Offshore West Africa 404,197 918,535 51,103 ---------------------------------------------------------------------------- 2,602,743 3,518,749 3,120,068 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Crude oil and NGLs ($/bbl) (1) Sales price (2) $ 67.74 $ 63.21 $ 68.00 $ 65.81 $ 57.68 Royalties 12.14 9.05 7.96 10.09 6.73 Production expense 13.59 15.37 15.45 14.16 15.92 ---------------------------------------------------------------------------- Netback $ 42.01 $ 38.79 $ 44.59 $ 41.56 $ 35.03 ---------------------------------------------------------------------------- Natural gas ($/Mcf) (1) Sales price (2) $ 3.56 $ 3.75 $ 4.75 $ 4.08 $ 4.53 Royalties (3) 0.07 0.11 0.35 0.20 0.32 Production expense 1.05 1.05 1.03 1.09 1.08 ---------------------------------------------------------------------------- Netback $ 2.44 $ 2.59 $ 3.37 $ 2.79 $ 3.13 ---------------------------------------------------------------------------- Barrels of oil equivalent ($/BOE) (1) Sales price (2) $ 50.41 $ 47.44 $ 51.95 $ 49.90 $ 44.87 Royalties 7.83 5.83 5.60 6.72 4.72 Production expense 10.91 11.89 11.72 11.25 11.98 ---------------------------------------------------------------------------- Netback $ 31.67 $ 29.72 $ 34.63 $ 31.93 $ 28.17 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of transportation and blending costs and excluding risk management activities. (3) Natural gas royalties for 2009 reflect the impact of natural gas physical sales contracts. PRODUCT PRICES - EXPLORATION AND PRODUCTION Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Crude oil and NGLs ($/bbl) (1) (2) North America $ 63.62 $ 59.13 $ 65.12 $ 62.28 $ 54.70 North Sea $ 88.05 $ 81.47 $ 78.89 $ 82.49 $ 68.84 Offshore West Africa $ 80.39 $ 77.32 $ 72.88 $ 78.93 $ 65.27 Company average $ 67.74 $ 63.21 $ 68.00 $ 65.81 $ 57.68 Natural gas ($/Mcf) (1)(2) North America $ 3.50 $ 3.70 $ 4.75 $ 4.05 $ 4.51 North Sea $ 2.99 $ 4.52 $ 4.94 $ 3.83 $ 4.66 Offshore West Africa $ 7.59 $ 7.36 $ 5.04 $ 6.63 $ 6.11 Company average $ 3.56 $ 3.75 $ 4.75 $ 4.08 $ 4.53 Company average ($/BOE) (1)(2) $ 50.41 $ 47.44 $ 51.95 $ 49.90 $ 44.87 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of transportation and blending costs and excluding risk management activities. /T/ North America North America realized crude oil prices increased 14% to average $62.28 per bbl for the year ended December 31, 2010 from $54.70 per bbl for the year ended December 31, 2009. Realized crude oil prices averaged $63.62 per bbl for the fourth quarter of 2010, a decrease of 2% compared to $65.12 per bbl for the fourth quarter of 2009 and an increase of 8% compared to $59.13 per bbl for the prior quarter. The increase in prices from the year ended December 31, 2009 and the prior quarter was primarily a result of increased WTI benchmark pricing, partially offset by the impact of the widening Heavy Differential and the stronger Canadian dollar relative to the US dollar. The decrease in realized crude oil prices in the fourth quarter of 2010 from the comparable period in 2009 was due to the impact of a widening Heavy Differential and the stronger Canadian dollar. The Company continues to focus on its crude oil marketing strategy, and in the fourth quarter of 2010 contributed approximately 180,000 bbl/d of heavy crude oil blends to the WCS stream. Subsequent to December 31, 2010, the Company announced that it had entered into a partnership agreement with North West Upgrading Inc. to move forward with detailed engineering regarding the construction and operation of a bitumen refinery near Redwater, Alberta. In addition, the partnership has entered into an agreement to process bitumen supplied by the Government of Alberta under the Alberta Royalty Framework's Bitumen Royalty In Kind initiative. Project development is dependent upon completion of this detailed engineering and final project sanction by the respective parties. North America realized natural gas prices decreased 10% to average $4.05 per Mcf for the year ended December 31, 2010 from $4.51 per Mcf for the year ended December 31, 2009. Realized natural gas prices averaged $3.50 per Mcf for the fourth quarter of 2010, a decrease of 26% compared to $4.75 per Mcf for the fourth quarter of 2009 and a decrease of 5% from $3.70 per Mcf for the prior quarter. The decrease in natural gas prices from comparable periods in 2009 was primarily related to the impact of weak benchmark prices due to lower demand and high storage levels, the widening NYMEX and AECO differential, the impact of natural gas physical sales contracts in 2009 and the impact of a stronger Canadian dollar relative to the US dollar. The decrease in natural gas prices from the prior quarter was primarily related to lower benchmark prices due to high storage levels. /T/ Comparisons of the prices received in North America Exploration and Production by product type were as follows: Dec 31 Sep 30 Dec 31 (Quarterly Average) 2010 2010 2009 ---------------------------------------------------------------------------- Wellhead Price (1) (2) Light/medium crude oil and NGLs ($/bbl) $69.77 $62.40 $67.30 Heavy Pelican Lake crude oil ($/bbl) $61.73 $58.44 $63.75 Heavy primary crude oil ($/bbl) $62.62 $58.97 $65.46 Bitumen (thermal heavy crude oil) ($/bbl) $62.10 $57.60 $63.62 Natural gas ($/Mcf) $ 3.50 $ 3.70 $ 4.75 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of transportation and blending costs and excluding risk management activities. /T/ North Sea North Sea realized crude oil prices increased 20% to average $82.49 per bbl for the year ended December 31, 2010 from $68.84 per bbl for the year ended December 31, 2009. Realized crude oil prices increased 12% to average $88.05 per bbl for the fourth quarter of 2010 from $78.89 per bbl for the fourth quarter of 2009, and increased 8% from $81.47 per bbl for the prior quarter. The increase in realized crude oil prices in the North Sea from the comparable periods in 2009 was primarily the result of increased Brent benchmark pricing, partially offset by the impact of the stronger Canadian dollar. Offshore West Africa Offshore West Africa realized crude oil prices increased 21% to average $78.93 per bbl for the year ended December 31, 2010 from $65.27 per bbl for the year ended December 31, 2009. Realized crude oil prices increased 10% to average $80.39 per bbl for the fourth quarter of 2010 from $72.88 per bbl for the fourth quarter of 2009, and increased 4% from $77.32 per bbl in the prior quarter. The increase in realized crude oil prices in Offshore West Africa from the comparable periods in 2009 was primarily the result of increased Brent benchmark pricing, partially offset by the impact of the stronger Canadian dollar. /T/ ROYALTIES - EXPLORATION AND PRODUCTION Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Crude oil and NGLs ($/bbl) (1) North America $ 14.30 $ 10.40 $ 9.88 $ 11.85 $ 7.93 North Sea $ 0.16 $ 0.13 $ 0.15 $ 0.16 $ 0.14 Offshore West Africa $ 7.01 $ 6.52 $ 5.24 $ 5.54 $ 5.79 Company average $ 12.14 $ 9.05 $ 7.96 $ 10.09 $ 6.73 Natural gas ($/Mcf) (1) North America (2) $ 0.06 $ 0.10 $ 0.35 $ 0.20 $ 0.32 Offshore West Africa $ 0.69 $ 0.85 $ 0.27 $ 0.53 $ 0.53 Company average $ 0.07 $ 0.11 $ 0.35 $ 0.20 $ 0.32 Company average ($/BOE) (1) $ 7.83 $ 5.83 $ 5.60 $ 6.72 $ 4.72 Percentage of revenue (3) Crude oil and NGLs 18% 14% 12% 15% 12% Natural gas (2) 2% 3% 7% 5% 7% BOE 16% 12% 11% 13% 11% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Natural gas royalties for 2009 reflect the impact of natural gas physical sales contracts. (3) Net of transportation and blending costs and excluding risk management activities. /T/ North America North America royalties for the year ended December 31, 2010 compared to the year ended December 31, 2009 reflected stronger benchmark crude oil commodity prices and the impact of the changes under the Alberta Royalty Framework. Crude oil and NGLs royalties averaged approximately 19% of revenues in 2010, compared to 14% in 2009. The increase in royalties was due to higher crude oil pricing and crude oil royalty adjustments. Crude oil and NGLs royalties averaged approximately 22% of revenues for the fourth quarter of 2010, compared to 15% for the fourth quarter in 2009 and 18% for the prior quarter. The increase in royalties from the comparable periods was due to crude oil royalty adjustments. Crude oil and NGLs royalties per bbl are anticipated to average 16% to 20% of gross revenue for 2011. Natural gas royalties averaged approximately 5% of revenues in 2010, compared to 7% in 2009. Natural gas royalties averaged approximately 2% of revenues for the fourth quarter, compared to 7% for the fourth quarter of 2009 and 3% for the prior quarter. The decrease in natural gas royalty rates for the fourth quarter of 2010 compared to the fourth quarter of 2009 was primarily due to lower benchmark pricing. Natural gas royalties are anticipated to average 4% to 6% of gross revenue for 2011. Offshore West Africa Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital costs, and the timing of liftings from each field. Royalty rates as a percentage of revenue averaged approximately 7% in 2010 compared to 9% in 2009. Royalty rates as a percentage of revenue averaged approximately 9% for the fourth quarter of 2010 compared to 7% for the fourth quarter of 2009 and 9% for the prior quarter. Offshore West Africa royalty rates are anticipated to increase in 2011 to average 13% to 15% of gross revenue for 2011, as a result of the expected payout of the Baobab Field. /T/ PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Crude oil and NGLs ($/bbl) (1) North America $ 11.41 $ 12.41 $ 13.44 $ 12.14 $ 14.63 North Sea $ 30.05 $ 44.45 $ 27.03 $ 29.73 $ 26.98 Offshore West Africa $ 13.86 $ 13.66 $ 15.26 $ 14.64 $ 12.83 Company average $ 13.59 $ 15.37 $ 15.45 $ 14.16 $ 15.92 Natural gas ($/Mcf) (1) North America $ 1.02 $ 1.04 $ 1.01 $ 1.06 $ 1.07 North Sea $ 2.70 $ 2.42 $ 3.23 $ 2.91 $ 2.16 Offshore West Africa $ 2.00 $ 1.69 $ 0.70 $ 1.76 $ 1.23 Company average $ 1.05 $ 1.05 $ 1.03 $ 1.09 $ 1.08 Company average ($/BOE) (1) $ 10.91 $ 11.89 $ 11.72 $ 11.25 $ 11.98 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. /T/ North America North America crude oil and NGLs production expense for the year ended December 31, 2010 decreased 17% to $12.14 per bbl from $14.63 per bbl for the year ended December 31, 2009. Production expense for the fourth quarter of 2010 decreased 15% to $11.41 per bbl from $13.44 per bbl for the fourth quarter of 2009 and decreased 8% from $12.41 per bbl for the prior quarter. The decrease in production expense per barrel from the comparable periods in 2009 was a result of higher production volumes and the lower cost of natural gas used for fuel. The decrease in production expense per barrel from the prior quarter was due to the timing of thermal steam cycles. North America crude oil and NGLs production expense is anticipated to average $12.00 to $13.00 per bbl for 2011. North America natural gas production expense for the year ended December 31, 2010 was comparable to production expense for the year ended December 31, 2009, as lower service costs offset the effects of lower production volumes. Production expense for the fourth quarter of 2010 was comparable to the fourth quarter of 2009 and decreased 2% from $1.04 per Mcf for the prior quarter. North America natural gas production expense is anticipated to average $1.10 to $1.20 per Mcf for 2011. North Sea North Sea crude oil production expense for the year ended December 31, 2010 increased 10% to $29.73 per bbl from $26.98 per bbl for the year ended December 31, 2009. Production expense for the fourth quarter of 2010 increased 11% to $30.05 per bbl from $27.03 per bbl for the fourth quarter of 2009 and decreased 32% from $44.45 per bbl for the prior quarter. Production expense increased on a per barrel basis from the comparable periods in 2009 due to lower volumes on relatively fixed costs. Production expense decreased on a per barrel basis from the prior quarter due to the timing of planned facility maintenance shutdowns in the prior quarter. Production expense is anticipated to average $38.00 to $42.00 per bbl for 2011. Offshore West Africa Offshore West Africa crude oil production expense increased 14% to $14.64 per bbl from $12.83 per bbl for the year ended December 31, 2009. Production expense for the fourth quarter of 2010 decreased 9% to $13.86 per bbl from $15.26 per bbl for the fourth quarter of 2009 and was comparable to the prior quarter. Production expense for the year ended December 31, 2010 increased on a per barrel basis from the comparable period in 2009 due to the timing of liftings for each field, including the impact of costs associated with the Olowi Field which has higher production expenses than the Espoir and Baobab Fields. Production expense for the fourth quarter of 2010 decreased from the comparable period in 2009 due to lower sales from the Olowi Field. Production expense is anticipated to average $18.00 to $21.00 per bbl for 2011. /T/ DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND PRODUCTION Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Expense ($ millions) $ 1,480 $ 763 $ 754 $ 3,662 $ 2,656 $/BOE (1) $ 28.41 $ 15.22 $ 15.68 $ 18.49 $ 13.82 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. /T/ The increase in depletion, depreciation and amortization expense from the comparable periods in 2009 and the prior quarter was due to higher production in North America, an increase in the estimated future costs to develop the Company's proved undeveloped reserves in the North Sea and the impact of a ceiling test impairment related to Gabon, Offshore West Africa at December 31, 2010. /T/ ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND PRODUCTION Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Expense ($ millions) $ 22 $ 22 $ 17 $ 85 $ 69 $/BOE (1) $ 0.41 $ 0.43 $ 0.36 $ 0.43 $ 0.36 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. /T/ Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Accretion expense for the year ended December 31, 2010 increased from the comparable period due to higher asset retirement obligations recognized in the North Sea in 2009. /T/ OPERATING HIGHLIGHTS - OIL SANDS MINING AND UPGRADING FINANCIAL METRICS Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($/bbl) (1) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- SCO sales price (2) $ 81.51 $ 75.31 $ 76.33 $ 77.89 $ 70.83 Bitumen value for royalty purposes (3) $ 56.42 $ 54.13 $ 58.90 $ 56.14 $ 56.57 Bitumen royalties (4) $ 2.77 $ 2.57 $ 3.06 $ 2.72 $ 2.15 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of transportation. (3) Calculated as the simple average of the monthly bitumen valuation methodology price. (4) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes. /T/ Realized SCO sales prices increased 10% to average $77.89 per bbl for the year ended December 31, 2010 from $70.83 per bbl for the year ended December 31, 2009. Realized SCO sales prices averaged $81.51 per bbl for the fourth quarter of 2010, an increase of 7% compared to $76.33 per bbl for the fourth quarter of 2009 and an increase of 8% compared to $75.31 per bbl for the prior quarter. The increase in SCO prices from the comparative periods was primarily due to the increase in the WTI benchmark price, offset by the impact of the strengthening Canadian dollar. There is an active market for SCO throughout North America. PRODUCTION COSTS The following tables provide reconciliations of Oil Sands Mining and Upgrading production costs to the Segmented Information disclosed in note 13 to the Company's unaudited interim consolidated financial statements. /T/ Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($ millions) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Cash costs, excluding natural gas costs $ 278 $ 243 $ 228 $ 1,082 $ 599 Natural gas costs 26 25 31 126 84 ---------------------------------------------------------------------------- Total cash production costs $ 304 $ 268 $ 259 $ 1,208 $ 683 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($/bbl) (1) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Cash costs, excluding natural gas costs $ 33.09 $ 31.20 $ 36.23 $ 32.58 $ 34.97 Natural gas costs 3.04 3.15 4.98 3.78 4.92 ---------------------------------------------------------------------------- Total cash production costs $ 36.13 $ 34.35 $ 41.21 $ 36.36 $ 39.89 ---------------------------------------------------------------------------- Sales (bbl/d) 91,350 84,836 68,140 91,010 46,896 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. /T/ First sales from Horizon occurred in the second quarter of 2009. Total cash production costs averaged $36.36 per bbl for the year ended December 31, 2010 compared to $39.89 per bbl for the year ended December 31, 2009. Total cash production costs averaged $36.13 per bbl in the fourth quarter of 2010 compared to $41.21 per bbl for the fourth quarter of 2009, and $34.35 per bbl in the prior quarter. The decrease in cash production costs from the comparative periods in 2009 was primarily due to the Company's focus on planned maintenance, reliability improvements and the stabilization of production volumes at levels approaching plant capacity. The increase in cash production costs from the prior quarter was primarily due to higher seasonal costs related to winter operating conditions, including higher diesel fuel costs, and the commencement of the annual winter stratigraphic well drilling program, partially offset by the effects of increased production volumes. /T/ Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($ millions) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Depletion, depreciation and amortization $ 96 $ 86 $ 83 $ 366 $ 187 Asset retirement obligation accretion 5 6 6 22 21 ---------------------------------------------------------------------------- Total $ 101 $ 92 $ 89 $ 388 $ 208 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($/bbl) (1) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Depletion, depreciation and amortization $ 11.49 $ 10.96 $ 13.28 $ 11.02 $ 10.95 Asset retirement obligation accretion 0.66 0.71 1.00 0.67 1.22 ---------------------------------------------------------------------------- Total $ 12.15 $ 11.67 $ 14.28 $ 11.69 $ 12.17 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. /T/ Depletion, depreciation and amortization increased from the comparable periods in 2009 and the prior quarter primarily due to higher sales volumes and the impact of certain assets depreciated on a straight-line basis. On January 6, 2011, the Company suspended synthetic crude oil production at its Oil Sands Mining and Upgrading operations due to a fire in the primary upgrading coking plant. Production will recommence once plant operating capacity is restored and all necessary regulatory and operating approvals are received. /T/ MIDSTREAM Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($ millions) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Revenue $ 20 $ 19 $ 18 $ 79 $ 72 Production expense 6 4 5 22 19 ---------------------------------------------------------------------------- Midstream cash flow 14 15 13 57 53 Depreciation 2 2 3 8 9 ---------------------------------------------------------------------------- Segment earnings before taxes $ 12 $ 13 $ 10 $ 49 $ 44 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Midstream operating results were consistent with the comparable periods. ADMINISTRATION EXPENSE Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Expense ($ millions) $ 53 $ 43 $ 49 $ 210 $ 181 $/BOE (1) $ 0.88 $ 0.73 $ 0.92 $ 0.91 $ 0.87 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. /T/ Administration expense for the year and three months ended December 31, 2010 increased from the comparative periods in 2009 and the prior quarter due to higher staffing and general corporate costs. /T/ STOCK-BASED COMPENSATION EXPENSE Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($ millions) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Expense $ 336 $ 18 $ 87 $ 294 $ 355 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ The Company recorded a $294 million after-tax stock-based compensation expense for the year ended December 31, 2010 primarily as a result of normal course graded vesting of options granted in prior periods, the impact of vested options exercised or surrendered during the period, and a 17% increase in the Company's share price (Company's share price as at: December 31, 2010 - $44.35; September 30, 2010 - $35.59; December 31, 2009 - $38.00). For the year ended December 31, 2010, the Company capitalized $24 million in stock-based compensation to Oil Sands Mining and Upgrading (December 31, 2009 - $2 million). The stock-based compensation liability reflected the Company's potential cash liability should all the vested options be surrendered for a cash payout at the market price on December 31, 2010. The Company's stock option plan provides current employees with the right to receive common shares or a direct cash payment in exchange for options surrendered. As a result of enacted changes to Canadian income tax legislation related to the cash surrender of options, the Company anticipates that Canadian based employees will now choose to exercise their options to receive newly issued common shares rather than surrender their options for cash payment. For the year ended December 31, 2010, the Company paid $45 million for stock options surrendered for cash settlement (December 31, 2009 - $94 million). /T/ INTEREST EXPENSE Three Months Ended Year Ended ($ millions, except per Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 BOE amounts) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Expense, gross $ 129 $ 116 $ 119 $ 477 $ 516 Less: capitalized interest, Oil Sands Mining and Upgrading 9 7 8 28 106 ---------------------------------------------------------------------------- Expense, net $ 120 $ 109 $ 111 $ 449 $ 410 $/BOE (1) $ 1.98 $ 1.89 $ 2.06 $ 1.94 $ 1.96 Average effective interest rate 5.7% 4.9% 4.5% 5.0% 4.3% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts expressed on a per unit basis are based on sales volumes. /T/ Gross interest expense for the year ended December 31, 2010 decreased from 2009 as lower overall debt levels and the impact of a stronger Canadian dollar on US dollar denominated debt partially offset the impact of higher variable interest rates. Gross interest expense for the fourth quarter of 2010 increased from the comparable period in 2009 and the prior quarter as higher variable interest rates partially offset the impact of a stronger Canadian dollar on US dollar denominated debt. The Company's average effective interest rate increased from the comparable periods in 2009 and the prior quarter primarily due to an increased weighting of fixed versus floating rate debt and higher variable interest rates. RISK MANAGEMENT ACTIVITIES The Company utilizes various derivative financial instruments to manage its commodity price, currency and interest rate exposures. These derivative financial instruments are not intended for trading or speculative purposes. /T/ Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($ millions) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Crude oil and NGLs financial instruments $ 47 $ 5 $ (148) $ 84 $(1,330) Natural gas financial instruments (53) (85) - (234) (33) Foreign currency contracts and interest rate swaps 32 10 26 54 110 ---------------------------------------------------------------------------- Realized loss (gain) $ 26 $ (70) $ (122) $ (96) $(1,253) ---------------------------------------------------------------------------- Crude oil and NGLs financial instruments $ 108 $ 8 $ 328 $ (108) $ 2,039 Natural gas financial instruments 51 56 (17) 71 (58) Foreign currency contracts and interest rate swaps 14 28 (3) 12 10 ---------------------------------------------------------------------------- Unrealized loss (gain) $ 173 $ 92 $ 308 $ (25) $ 1,991 ---------------------------------------------------------------------------- Net loss (gain) $ 199 $ 22 $ 186 $ (121) $ 738 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Complete details related to outstanding derivative financial instruments at December 31, 2010 are disclosed in note 11 to the Company's unaudited interim consolidated financial statements. For additional information on the Company's risk management activities, refer to the audited consolidated financial statements and the MD&A for the year ended December 31, 2009. The Company recorded a net unrealized gain of $25 million ($16 million after-tax) on its risk management activities for the year ended December 31, 2010, including a $173 million ($131 million after-tax) net unrealized loss for the fourth quarter of 2010 (September 30, 2010 - unrealized loss of $92 million, $71 million after-tax; December 31 2009 - unrealized loss of $308 million, $224 million after-tax), primarily due to changes in crude oil and natural gas forward pricing and the reversal of prior period unrealized gains and losses. /T/ FOREIGN EXCHANGE Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($ millions) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Net realized loss (gain) $ 6 $ 11 $ 4 $ (2) $ 30 Net unrealized gain (1) (120) (75) (88) (180) (661) ---------------------------------------------------------------------------- Net gain $ (114) $ (64) $ (84) $ (182) $ (631) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts are reported net of the hedging effect of cross currency swaps. /T/ The net unrealized foreign exchange gain for the year ended December 31, 2010 was primarily due to the strengthening of the Canadian dollar with respect to US dollar debt, together with the impact of the re-measurement of North Sea future income tax liabilities denominated in UK pounds sterling. The net unrealized gain for the respective periods also included the impact of cross currency swaps (three months ended December 31, 2010 - unrealized loss of $71 million, September 30, 2010 - unrealized loss of $62 million, December 31, 2009 - unrealized loss of $48 million; year ended December 31, 2010 - unrealized loss of $101 million, December 31, 2009 - unrealized loss of $338 million). The net realized foreign exchange gain for the year ended December 31, 2010 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling. The Canadian dollar ended the fourth quarter at US$1.0054 (September 30, 2010 - US$0.9711; December 31, 2009 - US$0.9555). /T/ TAXES Three Months Ended Year Ended ($ millions, except Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 income tax rates) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Current $ 20 $ 10 $ 25 $ 91 $ 91 Deferred 5 11 7 28 15 ---------------------------------------------------------------------------- Taxes other than income tax $ 25 $ 21 $ 32 $ 119 $ 106 ---------------------------------------------------------------------------- North America (1) $ 49 $ 115 $ 11 $ 432 $ 28 North Sea 84 23 60 203 278 Offshore West Africa 23 25 23 63 82 ---------------------------------------------------------------------------- Current income tax 156 163 94 698 388 Future income tax expense (recovery) 58 40 75 364 (99) ---------------------------------------------------------------------------- 214 203 169 1,062 289 Income tax rate and other legislative changes (2) - - - (83) 19 ---------------------------------------------------------------------------- $ 214 $ 203 $ 169 $ 979 $ 308 ---------------------------------------------------------------------------- Effective income tax rate on adjusted net earnings from operations 32.3% 25.9% 28.4% 28.1% 24.3% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments. (2) Future income tax expense in the first quarter of 2010 included a charge of $83 million related to enacted changes in Canada to the taxation of stock options surrendered by employees for cash. Income tax rate changes in the first quarter of 2009 include the effect of a recovery of $19 million due to enacted British Columbia corporate income tax rate reductions. /T/ Taxes other than income tax primarily includes current and deferred Petroleum Revenue Tax ("PRT"), which is charged on certain fields in the North Sea at the rate of 50% of net operating income, after allowing for certain deductions including related capital and abandonment expenditures. Taxable income from the exploration and production business in Canada is primarily generated through partnerships, with the related income taxes payable in subsequent periods. North America current income taxes have been provided on the basis of this corporate structure. In addition, current income taxes in each business segment will vary depending on available income tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year. The Company is subject to income tax reassessments arising in the normal course. The Company does not believe that any liabilities ultimately arising from these reassessments will be material. For 2011, based on budgeted prices and the current availability of tax pools, the Company expects to incur current income tax expense of $350 million to $450 million in Canada and $280 million to $320 million in the North Sea and Offshore West Africa. /T/ NET CAPITAL EXPENDITURES (1) Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 ($ millions) 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Expenditures on property, plant and equipment Net property acquisitions $ 868 $ 51 $ 11 $ 1,904 $ 6 Land acquisition and retention 39 27 28 141 77 Seismic evaluations 19 29 13 100 73 Well drilling, completion and equipping 444 365 291 1,500 1,244 Production and related facilities 311 253 222 1,122 977 ---------------------------------------------------------------------------- Total net reserve replacement expenditures 1,681 725 565 4,767 2,377 ---------------------------------------------------------------------------- Oil Sands Mining and Upgrading: Horizon Phase 1 construction costs - - - - 69 Horizon Phase 1 commissioning and other costs - - - - 202 Horizon Phases 2/3 construction costs 100 92 42 319 104 Capitalized interest, stock-based compensation and other 30 10 12 88 98 Sustaining capital 48 35 53 128 80 ---------------------------------------------------------------------------- Total Oil Sands Mining and Upgrading (2) 178 137 107 535 553 ---------------------------------------------------------------------------- Midstream 3 3 1 7 6 Abandonments (3) 80 45 17 179 48 Head office 5 4 4 18 13 ---------------------------------------------------------------------------- Total net capital expenditures $ 1,947 $ 914 $ 694 $ 5,506 $ 2,997 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- By segment North America $ 1,600 $ 610 $ 436 $ 4,369 $ 1,663 North Sea 38 59 48 149 168 Offshore West Africa 42 55 80 246 544 Other 1 1 1 3 2 Oil Sands Mining and Upgrading 178 137 107 535 553 Midstream 3 3 1 7 6 Abandonments (3) 80 45 17 179 48 Head office 5 4 4 18 13 ---------------------------------------------------------------------------- Total $ 1,947 $ 914 $ 694 $ 5,506 $ 2,997 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) The net capital expenditures exclude adjustments related to differences between carrying value and tax value, and other fair value adjustments. (2) Net expenditures for the Oil Sands Mining and Upgrading assets also include the impact of intersegment eliminations. (3) Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table. /T/ The Company's strategy is focused on building a diversified asset base that is balanced among various products. In order to facilitate efficient operations, the Company concentrates its activities in core regions where it can dominate the land base and infrastructure. The Company focuses on maintaining its land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By dominating infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Net capital expenditures for the year ended December 31, 2010 were $5,506 million compared to $2,997 million for the year ended December 31, 2009. Net capital expenditures for the fourth quarter of 2010 were $1,947 million compared to $694 million for the fourth quarter of 2009 and $914 million in the prior quarter. The increase in capital expenditures from the comparable periods in 2009 was primarily due to the purchase of crude oil and natural gas producing properties and undeveloped land in the Company's core regions in Western Canada, and the increase in the Company's abandonment program. The increase in capital expenditures in the current quarter compared to the prior quarter was due to increased property acquisitions and drilling activities. /T/ Drilling Activity (number of wells) Three Months Ended Year Ended Dec 31 Sep 30 Dec 31 Dec 31 Dec 31 2010 2010 2009 2010 2009 ---------------------------------------------------------------------------- Net successful natural gas wells 18 19 28 92 109 Net successful crude oil wells 318 281 195 934 644 Dry wells 8 9 17 33 46 Stratigraphic test / service wells 171 14 80 491 329 ---------------------------------------------------------------------------- Total 515 323 320 1,550 1,128 Success rate (excluding stratigraphic test / service wells) 98% 97% 93% 97% 94% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ North America North America, excluding Oil Sands Mining and Upgrading, accounted for approximately 83% of the total capital expenditures for the year ended December 31, 2010 compared to approximately 58% for the year ended December 31, 2009. During the fourth quarter of 2010, the Company targeted 19 net natural gas wells, including 1 well in Northeast British Columbia, 12 wells in Northwest Alberta, 5 wells in the Northern Plains region and 1 well in the Southern Plains region. The Company also targeted 323 net crude oil wells. The majority of these wells were concentrated in the Company's Northern Plains region where 257 heavy crude oil wells, 18 Pelican Lake crude oil wells, 5 thermal crude oil wells and 5 light crude oil wells were drilled. Another 38 wells targeting light crude oil were drilled outside the Northern Plains region. As part of the phased expansion of its In Situ Oil Sands Assets, the Company is continuing to develop its Primrose thermal projects. Overall Primrose thermal production for the fourth quarter of 2010 averaged approximately 104,000 bbl/d, compared to approximately 57,000 bbl/d for the fourth quarter of 2009 and approximately 85,000 bbl/d for the prior quarter. The Primrose East expansion was completed and first steaming commenced in September 2008, with first production achieved in the first quarter of 2009. During the first quarter of 2009, operational issues on one of the pads caused steaming to cease on all well pads in the Primrose East project area. The Company received approval from regulators to commence steaming on the next cycle in the third quarter of 2010. The next planned phase of the Company's In Situ Oil Sands Assets expansion is the Kirby Project. Currently the Company is proceeding with the detailed engineering and design work. During the third quarter of 2010, the Company received final regulatory approval for Phase 1 of the Project. During the fourth quarter, the Company's Board of Directors sanctioned Kirby Phase 1. Construction commenced in the fourth quarter of 2010, with first steam targeted in 2013. Development of new pads and tertiary recovery conversion projects at Pelican Lake continued as expected throughout the fourth quarter of 2010. Drilling included 16 horizontal wells in the fourth quarter. The response from the water and polymer flood projects continues to be positive. Pelican Lake production averaged approximately 38,000 bbl/d for the fourth quarter of 2010, and was comparable to the fourth quarter of 2009 and the prior quarter. For the first quarter of 2011, the Company's overall planned drilling activity in North America is expected to be comprised of 30 net natural gas wells and 270 net crude oil wells, excluding stratigraphic and service wells. Oil Sands Mining and Upgrading Phase 2/3 spending during the fourth quarter continued to be focused on construction of the third Ore Preparation Plant, additional product tankage, the butane treatment unit, the sulphur recovery unit and hydro-transport. On January 6, 2011, a fire occurred at the Company's primary upgrading coking plant. The fire was confined to one of the coke drums. Production capacity at Horizon has been suspended during the investigation and repair/rebuild to plant equipment damaged by the fire. A preliminary assessment of the extent of damage and timelines to repair/rebuild indicate that the coke drums are serviceable. The procurement process for all necessary replacement components and parts for the damage caused by the fire has been initiated. Based on preliminary estimates, the first set of coke drums is targeted to resume production in the second quarter of 2011 with production rates of approximately 55,000 bbl/d. The second set of coke drums is currently targeted to be on production in the third quarter of 2011. The Company believes that it has adequate insurance coverage to mitigate all significant property damage related losses. The Company also maintains business interruption coverage, subject to a waiting period, which it believes will mitigate operating losses related to on-going operations. North Sea In the fourth quarter of 2010, the Company continued drilling on the Ninian South Platform, with 0.9 net crude wells drilled in the quarter. The Company plans to continue drilling at Ninian during 2011 and commence drilling at Murchison in the second quarter of 2011. Offshore West Africa At Espoir, incremental production volumes attributable to the facilities upgrades were delivered during the fourth quarter. Drilling continued at the Olowi Field with 1.5 net crude oil wells completed during the quarter. The Company achieved first crude oil production at Platform A in the fourth quarter of 2010. Performance from the Olowi Field continues to be below expectations and, as a result, the Company recognized a pre-tax ceiling test impairment of $726 million ($672 million after-tax) at December 31, 2010. /T/ LIQUIDITY AND CAPITAL RESOURCES Dec 31 Sep 30 Dec 31 ($ millions, except ratios) 2010 2010 2009 ---------------------------------------------------------------------------- Working capital (deficit) (1) $ (984) $ (515) $ (514) Long-term debt (2) $ 8,499 $ 8,490 $ 9,658 Share capital $ 3,147 $ 3,015 $ 2,834 Retained earnings 18,005 18,502 16,696 Accumulated other comprehensive loss (167) (97) (104) ---------------------------------------------------------------------------- Shareholders' equity $ 20,985 $ 21,420 $ 19,426 Debt to book capitalization (2) (3) 29% 28% 33% Debt to market capitalization (2) (4) 15% 18% 19% After tax return on average common shareholders' equity (5) 8% 13% 8% After tax return on average capital employed (2) (6) 7% 10% 6% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Calculated as current assets less current liabilities, excluding the current portion of long-term debt. (2) Long-term debt is stated at its carrying value, net of fair value adjustments, original issue discounts and transaction costs. (3) Calculated as current and long-term debt; divided by the book value of common shareholders' equity plus current and long-term debt. (4) Calculated as current and long-term debt; divided by the market value of common shareholders' equity plus current and long-term debt. (5) Calculated as net earnings for the twelve month trailing period; as a percentage of average common shareholders' equity for the period. (6) Calculated as net earnings plus after-tax interest expense for the twelve month trailing period; as a percentage of average capital employed for the period. /T/ At December 31, 2010, the Company's capital resources consist primarily of cash flow from operations, available bank credit facilities and access to debt capital markets. Cash flow from operations is dependent on factors discussed in the "Risks and Uncertainties" section of the Company's December 31, 2009 annual MD&A. The Company's ability to renew existing bank credit facilities and raise new debt is also dependent upon these factors, as well as maintaining an investment grade debt rating and the condition of capital and credit markets. The Company continues to believe that its internally generated cash flow from operations supported by the implementation of its on-going hedge policy, the flexibility of its capital expenditure programs supported by its multi-year financial plans, its existing bank credit facilities, and its ability to raise new debt on commercially acceptable terms, will provide sufficient liquidity to sustain its operations in the short, medium and long term and support its growth strategy. The Company believes that its capital resources are sufficient to compensate for any short term cash flow reduction arising from Horizon, and accordingly, the Company's targeted capital program currently remains unchanged for 2011. At December 31, 2010, the Company had $2,444 million of available credit under its bank credit facilities. During the fourth quarter of 2010, the Company repaid $400 million of the medium term notes bearing interest at 5.50%. Long-term debt was $8,499 million at December 31, 2010, resulting in a debt to book capitalization ratio of 29% (September 30, 2010 - 28%; December 31, 2009 - 33%). This ratio is below the 35% to 45% internal range utilized by management. This range may be exceeded in periods when a combination of capital projects, acquisitions, and lower commodity prices occur. The Company may be below the low end of the targeted range when cash flow from operating activities is greater than current investment activities. The Company remains committed to maintaining a strong balance sheet and flexible capital structure. The Company has hedged a portion of its crude oil production for 2011 at prices that protect investment returns to ensure ongoing balance sheet strength and the completion of its capital expenditure programs. Further details related to the Company's long-term debt at December 31, 2010 are discussed in note 4 to the Company's unaudited interim consolidated financial statements. The Company's commodity hedging program reduces the risk of volatility in commodity prices and supports the Company's cash flow for its capital expenditures programs. This program currently allows for the hedging of up to 60% of the near 12 months budgeted production and up to 40% of the following 13 to 24 months estimated production. For the purpose of this program, the purchase of put options is in addition to the above parameters. As at December 31, 2010, in accordance with the policy, approximately 11% of budgeted crude oil volumes were hedged using collars for 2011. Further details related to the Company's commodity related derivative financial instruments outstanding at December 31, 2010 are discussed in note 11 to the Company's unaudited interim consolidated financial statements. Share capital The Company's shareholders passed a Special Resolution subdividing the common shares of the Company on a two-for-one basis at the Company's Annual and Special Meeting held on May 6, 2010, with such subdivision taking effect in May 2010. All common share, per common share, and stock option amounts have been restated to reflect the share split. As at December 31, 2010, there were 1,090,848,000 common shares outstanding and 66,844,000 stock options outstanding. As at March 1, 2011, the Company had 1,093,711,000 common shares outstanding and 63,029,000 stock options outstanding. On March 1, 2011, the Company's Board of Directors approved an increase in the annual dividend to be paid by the Company to $0.36 per common share for 2011. The increase represents a 20% increase from 2010, recognizes the stability of the Company's cash flow, and provides a return to Shareholders. The dividend policy undergoes a periodic review by the Board of Directors and is subject to change. In 2010, the Company announced a Normal Course Issuer Bid to purchase, through the facilities of the Toronto Stock Exchange ("TSX") and the New York Stock Exchange ("NYSE"), during the 12 month period commencing April 6, 2010 and ending April 5, 2011, up to 27,163,940 common shares or 2.5% of the common shares of the Company outstanding at March 17, 2010. As at March 1, 2011, 2,000,000 common shares had been purchased for cancellation at an average price of $33.77 per common share, for a total cost of $68 million. COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS In the normal course of business, the Company has entered into various commitments that will have an impact on the Company's future operations. As at December 31, 2010, no entities were consolidated under the Canadian Institute of Chartered Accountants ("CICA") Handbook Accounting Guideline 15, "Consolidation of Variable Interest Entities". The following table summarizes the Company's commitments as at December 31, 2010: /T/ ($ millions) 2011 2012 2013 2014 2015 Thereafter ---------------------------------------------------------------------------- Product transportation and pipeline $ 228 $ 199 $ 172 $ 164 $ 152 $ 932 Offshore equipment operating leases $ 141 $ 98 $ 97 $ 97 $ 81 $ 168 Offshore drilling $ 7 $ - $ - $ - $ - $ - Asset retirement obligations (1) $ 18 $ 17 $ 19 $ 28 $ 27 $ 7,123 Long-term debt (2) $ 398 $ 348 $ 798 $ 348 $ 400 $ 4,774 Interest expense (3) $ 438 $ 400 $ 353 $ 333 $ 307 $ 4,236 Office leases $ 27 $ 27 $ 28 $ 28 $ 32 $ 339 Other $ 102 $ 66 $ 19 $ 16 $ 24 $ 10 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts represent management's estimate of the future undiscounted payments to settle asset retirement obligations related to resource properties, facilities, and production platforms, based on current legislation and industry operating practices. Amounts disclosed for the period 2011 - 2015 represent the estimated minimum expenditures required to meet these obligations. Actual expenditures in any particular year may exceed these minimum amounts. (2) The long-term debt represents principal repayments only and does not reflect fair value adjustments, original issue discounts or transaction costs. No debt repayments are reflected for $1,436 million of revolving bank credit facilities due to the extendable nature of the facilities. (3) Interest expense amounts represent the scheduled fixed rate and variable rate cash payments related to long-term debt. Interest on variable rate long-term debt was estimated based upon prevailing interest rates and foreign exchange rates as at December 31, 2010. /T/ LEGAL PROCEEDINGS AND OTHER CONTINGENCIES The Company is defendant and plaintiff in a number of legal actions arising from the Company's normal operations. In addition, the Company is subject to certain contractor construction claims. The Company believes that any liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position. CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING POLICIES The preparation of financial statements requires the Company to make judgments, assumptions and estimates in the application of Canadian GAAP that have a significant impact on the financial results of the Company. Actual results could differ from those estimates. A comprehensive discussion of the Company's significant accounting policies is contained in the MD&A and the audited consolidated financial statements for the year ended December 31, 2009. INTERNATIONAL FINANCIAL REPORTING STANDARDS In February 2008, the CICA's Accounting Standards Board confirmed that Canadian publicly accountable enterprises will be required to adopt International Financial Reporting Standards ("IFRS") as promulgated by the International Accounting Standards Board ("IASB") in place of Canadian GAAP effective January 1, 2011. The Company has established a formal IFRS project governance structure. The structure includes a Steering Committee, which consists of senior levels of management from finance and accounting, operations and information technology ("IT"). The Steering Committee provides regular updates to the Company's Management and the Audit Committee of the Board of Directors. The Company's IFRS conversion project was broken down into the following phases: - Phase 1 Diagnostic - identification of potential accounting and reporting differences between Canadian GAAP and IFRS. - Phase 2 Planning - establishment of project governance, processes, resources, budget and timeline. - Phase 3 Policy Delivery and Documentation - establishment of accounting policies under IFRS. - Phase 4 Policy Implementation - establishment of processes for accounting and reporting, IT change requirements, and education. - Phase 5 Sustainment - ongoing compliance with IFRS after implementation. The Company has substantially completed its IFRS conversion project. Significant differences were identified in accounting for Property, Plant & Equipment ("PP&E"), including exploration costs, depletion and depreciation, capitalized interest, impairment testing, and asset retirement obligations. Other significant differences were noted in accounting for stock-based compensation, risk management activities, and income taxes. A summary of the significant differences identified is included below. As certain IFRS standards may change during 2011, the Company may be required to recognize additional new and /or amended accounting standards in the preparation of its December 31, 2011 consolidated financial statements prepared in accordance with IFRS. The Company has identified, developed and tested systems and accounting and reporting processes and changes required to capture data required for IFRS accounting and reporting, including 2010 requirements to capture both Canadian GAAP and IFRS data. IT system changes are complete and implemented. Summary of Identified IFRS Accounting Policy Differences Property, Plant & Equipment Adoption of IFRS will significantly impact the Company's accounting policies for PP&E. For Canadian GAAP purposes, the Company followed the full cost method of accounting for its exploration and production properties and equipment as prescribed by Accounting Guideline 16 ("AcG16"). Application of the full cost method of accounting is discussed in the "Critical Accounting Estimates" section of the 2009 annual MD&A. Significant differences in accounting for PP&E under IFRS include: - Pre-exploration costs must be expensed. Under full cost accounting, these costs are currently included in the country cost centre. - Exploration and evaluation costs are initially capitalized as exploration and evaluation assets. In areas where the Company has existing operations, costs associated with reserves that are found to be technically feasible and commercially viable will be transferred to PP&E. If technically feasible and commercially viable reserves are not established in an area and if no further activity is planned in that area, the costs are expensed. Under full cost accounting, exploration and evaluation costs are currently disclosed as PP&E but withheld from depletion. Costs are transferred to the depletable assets when proved reserves are assigned or when it is determined that the costs are impaired. - PP&E for producing properties is depleted at an asset level. Under full cost accounting, PP&E is depleted on a country cost centre basis. - Interest directly attributable to the acquisition or construction of a qualifying asset must be capitalized to the cost of the asset. Under Canadian GAAP, capitalization of interest is not required. - Impairment of PP&E is tested at a cash generating unit level (the lowest level at which cash inflows can be separately identified). Under full cost accounting, impairment is tested at the country cost centre level. IFRS 1 "First-time Adoption of International Financial Reporting Standards" issued by the IASB includes a transition exemption for oil and gas companies following full cost accounting under their previous GAAP. The transition exemption allows full cost companies to allocate their existing full cost PP&E balances using reserve values or volumes to IFRS compliant units of account without requiring retroactive adjustment, subject to an initial impairment test. The Company has adopted this transition exemption. After initial adoption, future impairment charges may be reversed. Asset Retirement Obligations Canadian GAAP accounting requirements for asset retirement obligations ("ARO") are discussed in the "Critical Accounting Estimates" section of the 2009 annual MD&A. A significant difference in accounting for ARO under IFRS is that the liability must be re-measured at each balance sheet date using the current discount rates, whereas under Canadian GAAP the discount rates do not change once the liability is recorded. On transition to IFRS, the increase in ARO liability on PP&E for which the full cost exemption above is applied must be recorded in retained earnings. For the change in ARO liability on other non-full cost PP&E, the increase is adjusted to PP&E in accordance with the general exemption for decommissioning liabilities included in IFRS 1. In future periods, the impact of changes in discount rates on the ARO liability for all PP&E is adjusted to PP&E. Stock-based Compensation Under Canadian GAAP, the Company's stock option plan liability is valued using the intrinsic value method, calculated as the amount by which the market price of the Company's shares exceeds the exercise price of the option for vested options. Under IFRS, the stock option plan liability must be measured using a fair value option pricing model such as the Black-Scholes model. The Company has utilized the exemption in IFRS 1 under which options that were settled prior to January 1, 2010 will not have to be retrospectively restated. On transition to IFRS, the increase in stock-based compensation liability must be recorded in retained earnings. Petroleum Revenue Tax Under Canadian GAAP, the liability for the UK PRT is estimated using proved plus probable reserves and future prices and costs, and apportioned to accounting periods over the life of the field on the basis of total estimated future operating income. Under IFRS, the PRT liability is estimated using the balance sheet method in accordance with IAS 12 Income Taxes, where the liability is based on temporary differences in balance sheet assets and liabilities versus their tax basis. On transition to IFRS, the increase in PRT liability must be recorded in retained earnings. Income Taxes Both Canadian GAAP and IFRS follow the liability method of accounting for income taxes, where tax liabilities and assets are recognized on temporary differences. However, there are certain exceptions to the treatment of temporary differences under IFRS that result in an adjustment to the Company's future tax liability under IFRS. In addition, the Company's future tax liability will be impacted by the tax effects of any changes noted in the above areas. On transition to IFRS, the decrease in the net future income tax liability must be recorded in retained earnings. Other IFRS 1 Exemptions The Company has adopted the following IFRS 1 transition exemptions: - The Company has elected to reset the foreign currency translation adjustment to $nil by transferring the Canadian GAAP balance to retained earnings on January 1, 2010, rather than retrospectively restating the balance. - The Company has adopted the IFRS 1 election to not restate business combinations entered into prior to January 1, 2010. IFRS Transitional Impacts Giving effect to the above-noted transitional impacts, the Company estimates that on adoption of IFRS, total Shareholders' Equity as at January 1, 2010 decreased by less than 4% compared to the balance previously determined under Canadian GAAP, resulting in a marginal increase in the Company's reported debt to book capitalization to 34% from 33%. After the adoption of IFRS, the Company expects that 2010 net earnings decreased by an amount estimated to be between $100 million to $200 million, primarily due to higher depletion, depreciation and amortization, offset by lower UK PRT expense. Further, on adoption of IFRS, the Company does not anticipate any significant differences in cash flow from operations as would have been previously reported. Readers are cautioned that these estimates are subject to change, should underlying IFRS standards and/or the interpretations thereof be revised, prior to the final release of the Company's December 31, 2011 annual consolidated financial statements. SENSITIVITY ANALYSIS The following table is indicative of the annualized sensitivities of cash flow from operations and net earnings from changes in certain key variables. The analysis is based on business conditions and sales volumes during the fourth quarter of 2010, excluding mark-to-market gains (losses) on risk management activities, and is not necessarily indicative of future results. Each separate line item in the sensitivity analysis shows the effect of a change in that variable only with all other variables being held constant. /T/ Cash flow from Net Cash operations earnings flow from (per common Net (per common operations share, earnings share, ($ millions) basic) ($ millions) basic) ---------------------------------------------------------------------------- Price changes Crude oil - WTI US$1.00/bbl (1) Excluding financial derivatives $ 128 $ 0.12 $ 99 $ 0.09 Including financial derivatives $ 128 $ 0.12 $ 99 $ 0.09 Natural gas - AECO C$0.10/Mcf (1) Excluding financial derivatives $ 34 $ 0.03 $ 25 $ 0.02 Including financial derivatives $ 38 $ 0.04 $ 29 $ 0.03 Volume changes Crude oil - 10,000 bbl/d $ 175 $ 0.16 $ 104 $ 0.10 Natural gas - 10 MMcf/d $ 9 $ 0.01 $ 1 $ - Foreign currency rate change $0.01 change in US$ (1) Including financial derivatives $ 101 - 103 $ 0.09 $ 40 - 41 $ 0.04 Interest rate change - 1% $ 9 $ 0.01 $ 9 $ 0.01 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) For details of outstanding financial instruments in place, refer to note 11 of the Company's unaudited interim consolidated financial statements. FINANCIAL STATEMENTS Consolidated Balance Sheets Dec 31 Dec 31 (millions of Canadian dollars, unaudited) 2010 2009 ---------------------------------------------------------------------------- ASSETS Current assets Cash and cash equivalents $ 22 $ 13 Accounts receivable 1,481 1,148 Inventory, prepaids and other 610 584 Future income tax 59 146 ---------------------------------------------------------------------------- 2,172 1,891 Property, plant and equipment (note 13) 40,472 39,115 Other long-term assets (note 3) 25 18 ---------------------------------------------------------------------------- $ 42,669 $ 41,024 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- LIABILITIES Current liabilities Accounts payable $ 274 $ 240 Accrued liabilities 2,163 1,522 Current portion of other long-term liabilities (note 5) 719 643 ---------------------------------------------------------------------------- 3,156 2,405 Long-term debt (note 4) 8,499 9,658 Other long-term liabilities (note 5) 2,130 1,848 Future income tax 7,899 7,687 ---------------------------------------------------------------------------- 21,684 21,598 ---------------------------------------------------------------------------- SHAREHOLDERS' EQUITY Share capital (note 7) 3,147 2,834 Retained earnings 18,005 16,696 Accumulated other comprehensive loss (note 8) (167) (104) ---------------------------------------------------------------------------- 20,985 19,426 ---------------------------------------------------------------------------- $ 42,669 $ 41,024 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Commitments (note 12) Consolidated Statements of Earnings (Loss) (millions of Canadian Three Months Ended Year Ended dollars, except per common Dec 31 Dec 31 Dec 31 Dec 31 share amounts, unaudited) 2010 2009 2010 2009 ---------------------------------------------------------------------------- Revenue $ 3,787 $ 3,319 $ 14,322 $ 11,078 Less: royalties (431) (285) (1,421) (936) ---------------------------------------------------------------------------- Revenue, net of royalties 3,356 3,034 12,901 10,142 ---------------------------------------------------------------------------- Expenses Production 874 819 3,447 2,987 Transportation and blending 460 351 1,783 1,218 Depletion, depreciation and Amortization (note 13) 1,578 836 4,036 2,819 Asset retirement obligation accretion (note 5) 27 23 107 90 Administration 53 49 210 181 Stock-based compensation expense (note 5) 336 87 294 355 Interest, net 120 111 449 410 Risk management activities (note 11) 199 186 (121) 738 Foreign exchange gain (114) (84) (182) (631) ---------------------------------------------------------------------------- 3,533 2,378 10,023 8,167 ---------------------------------------------------------------------------- Earnings (loss) before taxes (177) 656 2,878 1,975 Taxes other than income tax 25 32 119 106 Current income tax expense (note 6) 156 94 698 388 Future income tax expense (recovery) (note 6) 58 75 364 (99) ---------------------------------------------------------------------------- Net earnings (loss) $ (416) $ 455 $ 1,697 $ 1,580 ---------------------------------------------------------------------------- Net earnings (loss) per common share (note 10) Basic and diluted $ (0.38) $ 0.42 $ 1.56 $ 1.46 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Consolidated Statements of Shareholders' Equity Year Ended Dec 31 Dec 31 (millions of Canadian dollars, unaudited) 2010 2009 ---------------------------------------------------------------------------- Share capital (note 7) Balance - beginning of year $ 2,834 $ 2,768 Issued upon exercise of stock options 170 24 Previously recognized liability on stock options exercised for common shares 149 42 Purchase of common shares under Normal Course Issuer Bid (6) - ---------------------------------------------------------------------------- Balance - end of year 3,147 2,834 ---------------------------------------------------------------------------- Retained earnings Balance - beginning of year 16,696 15,344 Net earnings 1,697 1,580 Purchase of common shares under Normal Course Issuer Bid (note 7) (62) - Dividends on common shares (note 7) (326) (228) ---------------------------------------------------------------------------- Balance - end of year 18,005 16,696 ---------------------------------------------------------------------------- Accumulated other comprehensive loss (note 8) Balance - beginning of year (104) 262 Other comprehensive loss, net of taxes (63) (366) ---------------------------------------------------------------------------- Balance - end of year (167) (104) ---------------------------------------------------------------------------- Shareholders' equity $ 20,985 $ 19,426 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Consolidated Statements of Comprehensive Income (Loss) Three Months Ended Year Ended (millions of Canadian Dec 31 Dec 31 Dec 31 Dec 31 dollars, unaudited) 2010 2009 2010 2009 ---------------------------------------------------------------------------- Net earnings (loss) $ (416) $ 455 $ 1,697 $ 1,580 ---------------------------------------------------------------------------- Net change in derivative financial instruments designated as cash flow hedges Unrealized loss during the period, net of taxes of $6 million (2009 - $1 million) - three months ended; $11 million (2009 - $5 million) - year ended (46) (9) (24) (33) Reclassification to net earnings, net of taxes of $nil (2009 - $nil) - three months ended; $1 million (2009 - $1 million) - year ended - - (4) (10) ---------------------------------------------------------------------------- (46) (9) (28) (43) Foreign currency translation adjustment Translation of net investment (24) (34) (35) (323) ---------------------------------------------------------------------------- Other comprehensive loss, net of taxes (70) (43) (63) (366) ---------------------------------------------------------------------------- Comprehensive income (loss) $ (486) $ 412 $ 1,634 $ 1,214 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Consolidated Statements of Cash Flows Three Months Ended Year Ended (millions of Canadian Dec 31 Dec 31 Dec 31 Dec 31 dollars, unaudited) 2010 2009 2010 2009 ---------------------------------------------------------------------------- Operating activities Net earnings (loss) $ (416) $ 455 $ 1,697 $ 1,580 Non-cash items Depletion, depreciation and amortization 1,578 836 4,036 2,819 Asset retirement obligation accretion 27 23 107 90 Stock-based compensation expense 336 87 294 355 Unrealized risk management loss (gain) 173 308 (25) 1,991 Unrealized foreign exchange gain (120) (88) (180) (661) Deferred petroleum revenue tax expense 5 7 28 15 Future income tax expense (recovery) 58 75 364 (99) Other 5 3 (7) 5 Abandonment expenditures (80) (17) (179) (48) Net change in non-cash working capital (63) (180) 149 (235) ---------------------------------------------------------------------------- 1,503 1,509 6,284 5,812 ---------------------------------------------------------------------------- Financing activities Issue (repayment) of bank credit facilities, net 622 (717) (472) (2,021) Repayment of medium-term notes (400) - (400) - Repayment of senior unsecured notes - - - (34) Issue of common shares on exercise of stock options 87 3 170 24 Purchase of common shares under Normal Course Issuer Bid - - (68) - Dividends on common shares (82) (57) (302) (225) Net change in non-cash working capital 31 36 (5) (12) ---------------------------------------------------------------------------- 258 (735) (1,077) (2,268) ---------------------------------------------------------------------------- Investing activities Expenditures on property, plant, and equipment (1,872) (680) (5,335) (2,985) Proceeds on sale of property, plant and equipment 5 3 8 36 ---------------------------------------------------------------------------- Net expenditures on property, plant and equipment (1,867) (677) (5,327) (2,949) Net change in non-cash working capital 101 (98) 129 (609) ---------------------------------------------------------------------------- (1,766) (775) (5,198) (3,558) ---------------------------------------------------------------------------- (Decrease) increase in cash and cash equivalents (5) (1) 9 (14) Cash and cash equivalents - beginning of period 27 14 13 27 ---------------------------------------------------------------------------- Cash and cash equivalents - end of period $ 22 $ 13 $ 22 $ 13 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Interest paid $ 89 $ 83 $ 471 $ 516 Taxes paid Taxes other than income tax $ 33 $ 18 $ 102 $ 52 Current income tax $ 66 $ 88 $ 111 $ 216 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Notes to the consolidated financial statements (tabular amounts in millions of Canadian dollars, unless otherwise stated, unaudited) 1. ACCOUNTING POLICIES The interim consolidated financial statements of Canadian Natural Resources Limited (the "Company") include the Company and all of its subsidiaries and partnerships, and have been prepared following the same accounting policies as the audited consolidated financial statements of the Company as at December 31, 2009. The interim consolidated financial statements contain disclosures that are supplemental to the Company's annual audited consolidated financial statements. Certain disclosures that are normally required to be included in the notes to the annual audited consolidated financial statements have been condensed. These interim financial statements should be read in conjunction with the Company's audited consolidated financial statements and notes thereto for the year ended December 31, 2009. Comparative Figures Certain prior period figures have been reclassified to conform to the presentation adopted in 2010. Common share, per common share, and stock option data has been restated to reflect the two-for-one share split in May 2010. 2. CHANGES IN ACCOUNTING POLICIES International Financial Reporting Standards In February 2008, the Canadian Institute of Chartered Accountants' Accounting Standards Board confirmed that Canadian publicly accountable entities will be required to adopt International Financial Reporting Standards ("IFRS") as promulgated by the International Accounting Standards Board in place of generally accepted accounting principles in Canada ("GAAP") effective January 1, 2011. /T/ 3. OTHER LONG-TERM ASSETS Dec 31 Dec 31 2010 2009 ---------------------------------------------------------------------------- Other $ 25 $ 18 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 4. LONG-TERM DEBT Dec 31 Dec 31 2010 2009 ---------------------------------------------------------------------------- Canadian dollar denominated debt Bank credit facilities (bankers' acceptances) $ 1,436 $ 1,897 Medium-term notes 800 1,200 ---------------------------------------------------------------------------- 2,236 3,097 ---------------------------------------------------------------------------- US dollar denominated debt US dollar debt securities (US$6,300 million) 6,266 6,594 Less: original issue discount on US dollar debt securities (1) (20) (22) ---------------------------------------------------------------------------- 6,246 6,572 Fair value of interest rate swaps on US dollar debt securities (2) 61 38 ---------------------------------------------------------------------------- 6,307 6,610 ---------------------------------------------------------------------------- Long-term debt before transaction costs 8,543 9,707 Less: transaction costs (1) (3) (44) (49) ---------------------------------------------------------------------------- $ 8,499 $ 9,658 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) The Company has included unamortized original issue discounts and directly attributable transaction costs in the carrying value of the outstanding debt. (2) The carrying values of US$350 million of 5.45% notes due October 2012 and US$350 million of 4.90% notes due December 2014 have been adjusted by $61 million (2009 - $38 million) to reflect the fair value impact of hedge accounting. (3) Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees. /T/ Bank credit facilities As at December 31, 2010, the Company had in place unsecured bank credit facilities of $3,953 million, comprised of: - a $200 million demand credit facility; - a revolving syndicated credit facility of $2,230 million maturing June 2012; - a revolving syndicated credit facility of $1,500 million maturing June 2012; and - a Pound Sterling 15 million demand credit facility related to the Company's North Sea operations. The revolving syndicated credit facilities are extendible annually for one year periods at the mutual agreement of the Company and the lenders. If the facilities are not extended, the full amount of the outstanding principal would be repayable on the maturity date. Borrowings under these facilities can be made by way of Canadian dollar and US dollar bankers' acceptances, and LIBOR, US base rate and Canadian prime loans. The Company's weighted average interest rate on bank credit facilities outstanding as at December 31, 2010 was 1.5% (December 31, 2009 - 0.8%), and on total long-term debt outstanding for the three months ended December 31, 2010 was 5.7% (December 31, 2009 - 4.5%). In addition to the outstanding debt, letters of credit and financial guarantees aggregating $283 million, including $205 million related to Horizon, were outstanding at December 31, 2010. Subsequent to December 31, 2010, the financial guarantee related to Horizon was reduced to $190 million. Medium-term notes During the fourth quarter of 2010, the Company repaid $400 million of medium-term notes bearing interest at 5.50%. The Company filed a $3,000 million base shelf prospectus in October 2009 that allows for the issue of medium-term notes in Canada until November 2011. If issued, these securities will bear interest as determined at the date of issuance. US dollar debt securities During the fourth quarter of 2010, the Company unwound the interest rate swaps previously designated as a fair value hedge of US$350 million of 4.90% unsecured notes due December 2014. Accordingly, the Company ceased revaluing the related debt for subsequent changes in fair value from the date of unwind. The fair value adjustment of $55 million at the date of unwind is being amortized to interest expense over the remaining term of the debt. The Company filed a US$3,000 million base shelf prospectus in October 2009 that allows for the issue of US dollar debt securities in the United States until November 2011. If issued, these securities will bear interest as determined at the date of issuance. /T/ 5. OTHER LONG-TERM LIABILITIES Dec 31 Dec 31 2010 2009 ---------------------------------------------------------------------------- Asset retirement obligations $ 1,779 $ 1,610 Stock-based compensation 516 392 Risk management (note 11) 451 309 Other 103 180 ---------------------------------------------------------------------------- 2,849 2,491 Less: current portion 719 643 ---------------------------------------------------------------------------- $ 2,130 $ 1,848 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Asset retirement obligations At December 31, 2010, the Company's total estimated undiscounted costs to settle its asset retirement obligations were approximately $7,232 million (December 31, 2009 - $6,606 million). These costs will be incurred over the lives of the operating assets and have been discounted using a weighted average credit-adjusted risk-free rate of 6.6% (December 31, 2009 - 6.9%). A reconciliation of the discounted asset retirement obligations is as follows: /T/ Year Ended Year Ended Dec 31, 2010 Dec 31, 2009 ---------------------------------------------------------------------------- Balance - beginning of year $ 1,610 $ 1,064 Liabilities incurred (1) 12 299 Liabilities acquired 22 - Liabilities settled (179) (48) Asset retirement obligation accretion 107 90 Revision of estimates 240 276 Foreign exchange (33) (71) ---------------------------------------------------------------------------- Balance - end of year $ 1,779 $ 1,610 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) During 2009, the Company recognized additional asset retirement obligations related to Oil Sands Mining and Upgrading and Gabon, Offshore West Africa. /T/ Stock-based compensation The Company recognizes a liability for the potential cash settlements under its Stock Option Plan. The current portion represents the maximum amount of the liability payable within the next twelve-month period if all vested options are surrendered for cash settlement. /T/ Year Ended Year Ended Dec 31, 2010 Dec 31, 2009 ---------------------------------------------------------------------------- Balance - beginning of year $ 392 $ 171 Stock-based compensation expense 294 355 Cash payments for options surrendered (45) (94) Transferred to common shares (149) (42) Capitalized to Oil Sands Mining and Upgrading 24 2 ---------------------------------------------------------------------------- Balance - end of year 516 392 Less: current portion 472 365 ---------------------------------------------------------------------------- $ 44 $ 27 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 6. INCOME TAXES The provision for income taxes is as follows: Three Months Ended Year Ended Dec 31 Dec 31 Dec 31 Dec 31 2010 2009 2010 2009 ---------------------------------------------------------------------------- Current income tax - North America (1) $ 49 $ 11 $ 432 $ 28 Current income tax - North Sea 84 60 203 278 Current income tax - Offshore West Africa 23 23 63 82 ---------------------------------------------------------------------------- Current income tax expense 156 94 698 388 Future income tax expense (recovery) 58 75 364 (99) ---------------------------------------------------------------------------- Income tax expense $ 214 $ 169 $ 1,062 $ 289 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments. /T/ Taxable income from the exploration and production business in Canada is primarily generated through partnerships, with the related income taxes payable in subsequent periods. North America current income taxes have been provided on the basis of this corporate structure. In addition, current income taxes in each business segment will vary depending upon available income tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year. Future income tax expense in the first quarter of 2010 included a charge of $83 million related to enacted changes in Canada to the taxation of stock options surrendered by employees for cash. During the first quarter of 2009, enacted income tax rate changes resulted in a reduction of future income tax liabilities of $19 million in British Columbia. The Company is subject to income tax reassessments arising in the normal course. The Company does not believe that any liabilities that might ultimately arise from these reassessments will be material. /T/ 7. SHARE CAPITAL Year Ended Dec 31, 2010 Issued Number of shares Common shares (thousands)(1) Amount ---------------------------------------------------------------------------- Balance - beginning of year 1,084,654 $ 2,834 Issued upon exercise of stock options 8,208 170 Previously recognized liability on stock options exercised for common shares - 149 Cancellation of common shares (14) - Purchase of common shares under Normal Course Issuer Bid (2,000) (6) ---------------------------------------------------------------------------- Balance - end of year 1,090,848 $ 3,147 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Restated to reflect two-for-one common share split in May 2010. /T/ Dividend Policy On March 1, 2011, the Board of Directors set the regular quarterly dividend at $0.09 per common share (2010 - $0.075 per common share). The Company has paid regular quarterly dividends in January, April, July, and October of each year since 2001. The dividend policy undergoes a periodic review by the Board of Directors and is subject to change. Normal Course Issuer Bid In 2010, the Company announced a Normal Course Issuer Bid to purchase, through the facilities of the Toronto Stock Exchange and the New York Stock Exchange, during the 12 month period commencing April 6, 2010 and ending April 5, 2011, up to 27,163,940 common shares or 2.5% of the common shares of the Company outstanding at March 17, 2010. As at December 31, 2010, the Company purchased 2,000,000 common shares for cancellation at an average price of $33.77 per common share, for a total cost of $68 million. Retained earnings was reduced by $62 million, representing the excess of the purchase price of the common shares over their average carrying value. Share split The Company's shareholders passed a Special Resolution subdividing the common shares of the Company on a two-for-one basis at the Company's Annual and Special Meeting held on May 6, 2010 with such subdivision taking effect in May 2010. All common share, per common share, and stock option amounts have been restated to reflect the share split. /T/ Year Ended Dec 31, 2010 Weighted average Stock options exercise Stock options (thousands)(1) price(1) ---------------------------------------------------------------------------- Outstanding - beginning of year 64,211 $ 29.27 Granted 16,168 $ 40.68 Surrendered for cash settlement (2,741) $ 21.00 Exercised for common shares (8,208) $ 20.66 Forfeited (2,586) $ 32.30 ---------------------------------------------------------------------------- Outstanding - end of year 66,844 $ 33.31 ---------------------------------------------------------------------------- Exercisable - end of year 23,668 $ 30.64 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Restated to reflect two-for-one common share split in May 2010. 8. ACCUMULATED OTHER COMPREHENSIVE LOSS The components of accumulated other comprehensive loss, net of taxes, were as follows: Dec 31 Dec 31 2010 2009 ---------------------------------------------------------------------------- Derivative financial instruments designated as cash flow hedges $ 48 $ 76 Foreign currency translation adjustment (215) (180) ---------------------------------------------------------------------------- $ (167) $ (104) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ 9. CAPITAL DISCLOSURES The Company does not have any externally imposed regulatory capital requirements for managing capital. The Company has defined its capital to mean its long-term debt and consolidated shareholders' equity, as determined each reporting date. The Company's objectives when managing its capital structure are to maintain financial flexibility and balance to enable the Company to access capital markets to sustain its on-going operations and to support its growth strategies. The Company primarily monitors capital on the basis of an internally derived non-GAAP financial measure referred to as its "debt to book capitalization ratio", which is the arithmetic ratio of current and long-term debt divided by the sum of the carrying value of shareholders' equity plus current and long-term debt. The Company aims over time to maintain its debt to book capitalization ratio in the range of 35% to 45%. However, the Company may exceed the high end of such target range if it is investing in capital projects, undertaking acquisitions, or in periods of lower commodity prices. The Company may be below the low end of the targeted range when cash flow from operating activities is greater than current investment activities. At December 31, 2010, the ratio was below the target range at 29%. Readers are cautioned that the debt to book capitalization ratio is not defined by GAAP and this financial measure may not be comparable to similar measures presented by other companies. Further, there are no assurances that the Company will continue to use this measure to monitor capital or will not alter the method of calculation of this measure in the future. /T/ Dec 31 Dec 31 2010 2009 ---------------------------------------------------------------------------- Long-term debt $ 8,499 $ 9,658 Total shareholders' equity $ 20,985 $ 19,426 Debt to book capitalization 29% 33% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 10. NET EARNINGS (LOSS) PER COMMON SHARE Three Months Ended Year Ended Dec 31 Dec 31 Dec 31 Dec 31 2010 2009 2010 2009 ---------------------------------------------------------------------------- Weighted average common shares outstanding (thousands) - basic and diluted (1) 1,088,993 1,084,600 1,088,096 1,083,850 ---------------------------------------------------------------------------- Net earnings (loss) - basic and diluted $ (416) $ 455 $ 1,697 $ 1,580 ---------------------------------------------------------------------------- Net earnings (loss) per common share - basic and diluted (1) $ (0.38) $ 0.42 $ 1.56 $ 1.46 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Restated to reflect two-for-one common share split in May 2010. 11. FINANCIAL INSTRUMENTS The carrying values of the Company's financial instruments by category are as follows: ---------------------------------------------------- Dec 31, 2010 ---------------------------------------------------------------------------- Loans and Held for Other financial receivables at trading at liabilities at Asset (liability) amortized cost fair value amortized cost ---------------------------------------------------------------------------- Cash and cash equivalents $ - $ 22 $ - Accounts receivable 1,481 - - Accounts payable - - (274) Accrued liabilities - - (2,163) Other long-term liabilities - (451) (91) Long-term debt - - (8,499) ---------------------------------------------------------------------------- $ 1,481 $ (429) $ (11,027) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Dec 31, 2009 ---------------------------------------------------------------------------- Loans and Held for Other financial receivables at trading at liabilities at Asset (liability) amortized cost fair value amortized cost ---------------------------------------------------------------------------- Cash and cash equivalents $ - $ 13 $ - Accounts receivable 1,148 - - Accounts payable - - (240) Accrued liabilities - - (1,522) Other long-term liabilities - (309) (167) Long-term debt - - (9,658) ---------------------------------------------------------------------------- $ 1,148 $ (296) $ (11,587) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- The carrying value of the Company's financial instruments approximates their fair value, except for fixed-rate long-term debt as noted below. The fair values of the Company's financial assets and liabilities are outlined below: ---------------------------------------------------- Dec 31, 2010 ---------------------------------------------------------------------------- Carrying value Fair value ---------------------------------------------------------------------------- Asset (liability) (1) Level 1 Level 2 ---------------------------------------------------------------------------- Other long-term liabilities $ (451) $ - $ (451) Fixed-rate long-term debt(2)(3) (7,063) (7,835) - ---------------------------------------------------------------------------- $ (7,514) $ (7,835) $ (451) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Dec 31, 2009 ---------------------------------------------------------------------------- Carrying value Fair value ---------------------------------------------------------------------------- Asset (liability) (1) Level 1 Level 2 ---------------------------------------------------------------------------- Other long-term liabilities $ (309) $ - $ (309) Fixed-rate long-term debt(2)(3) (7,761) (8,212) - ---------------------------------------------------------------------------- $ (8,070) $ (8,212) $ (309) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Excludes financial assets and liabilities where book value approximates fair value due to the liquid nature of the asset or liability (cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities). (2) The carrying values of US$350 million of 5.45% notes due October 2012 and US$350 million of 4.90% notes due December 2014 have been adjusted by $61 million (2009 - $38 million) to reflect the fair value impact of hedge accounting. (3) The fair value of fixed-rate long-term debt has been determined based on quoted market prices. /T/ Risk management The Company uses derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows and discount rates. In determining these assumptions, the Company primarily relied on external, readily-observable market inputs including quoted commodity prices and volatility, interest rate yield curves, and foreign exchange rates. The resulting fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction and these differences may be material. The changes in estimated fair values of derivative financial instruments included in the risk management asset (liability) were recognized in the financial statements as follows: /T/ Year Ended Year Ended Dec 31, 2010 Dec 31, 2009 ---------------------------------------------------------------------------- Risk management Risk management mark-to- Asset (liability) mark-to-market market ---------------------------------------------------------------------------- Balance - beginning of year $ (309) $ 2,119 Net cost of outstanding put options 106 - Net change in fair value of outstanding derivative financial instruments attributable to: - Risk management activities 25 (1,991) - Interest expense 30 (25) - Foreign exchange (101) (338) - Other comprehensive income (41) (78) - Settlement of interest rate swaps and other (55) 4 ---------------------------------------------------------------------------- (345) (309) Add: put premium financing obligations (1) (106) - ---------------------------------------------------------------------------- Balance - end of year (451) (309) Less: current portion (222) (182) ---------------------------------------------------------------------------- $ (229) $ (127) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) The Company has negotiated payment of put option premiums with various Counterparties at the time of actual settlement of the respective options. These obligations have been reflected in the net risk management asset (liability). Net losses (gains) from risk management activities were as follows: Three Months Ended Year Ended Dec 31 Dec 31 Dec 31 Dec 31 2010 2009 2010 2009 ---------------------------------------------------------------------------- Net realized risk management loss (gain) $ 26 $ (122) $ (96) $ (1,253) Net unrealized risk management loss (gain) 173 308 (25) 1,991 ---------------------------------------------------------------------------- $ 199 $ 186 $ (121) $ 738 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Financial risk factors a) Market risk Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. The Company's market risk is comprised of commodity price risk, interest rate risk, and foreign currency exchange risk. Commodity price risk management The Company uses commodity derivative financial instruments to manage its exposure to commodity price risk associated with the sale of its future crude oil and natural gas production and with natural gas purchases. At December 31, 2010, the Company had the following net derivative financial instruments outstanding: /T/ i) Sales Contracts Weighted average Remaining term Volume price Index ---------------------------------------------------------------------------- Crude oil Crude oil price 50,000 US$70.00 - collars Jan 2011 - Dec 2011 bbl/d US$102.23 WTI Crude oil puts 100,000 Jan 2011 - Dec 2011 bbl/d US$70.00 WTI ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- The cost of outstanding put options and their respective periods of settlement are as follows: Q1 2011 Q2 2011 Q3 2011 Q4 2011 ---------------------------------------------------------------------------- Cost ($ millions) US$26 US$26 US$27 US$27 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ii) Purchase Contracts Weighted Average Floating Remaining term Volume fixed rate Index ---------------------------------------------------------------------------- Natural gas Swaps - floating 125,000 to fixed Jan 2011 - Dec 2011 GJ/d C$4.87 AECO ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ The Company's outstanding commodity derivative financial instruments are expected to be settled monthly based on the applicable index pricing for the respective contract month. The natural gas derivative financial instruments designated as hedges at December 31, 2010 were classified as cash flow hedges. Interest rate risk management The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its floating rate long-term debt. The Company enters into interest rate swap contracts to manage its fixed to floating interest rate mix on long-term debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. At December 31, 2010, the Company had the following interest rate swap contracts outstanding: /T/ Floating Remaining term Amount Fixed rate rate ---------------------------------------------------------------------------- Interest rate (1)(2) Swaps - floating to 3 month Fixed Jan 2011 - Feb 2012 C$200 1.4475% CDOR (3) ---------------------------------------------------------------------------- (1) During the fourth quarter of 2010, the Company unwound US$350 million of 4.9% interest rate swaps for proceeds of US$54 million. (2) During the fourth quarter of 2010, the Company unwound C$300 million of 1.0680% interest rate swaps for nominal consideration. (3) Canadian Dealer Offered Rate. /T/ Foreign currency exchange rate risk management The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long-term debt and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted in other currencies in its subsidiaries and in the carrying value of its self-sustaining foreign subsidiaries. The Company periodically enters into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on US dollar denominated long-term debt and working capital. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. At December 31, 2010 the Company had the following cross currency swap contracts outstanding: /T/ Exchange Interest Interest rate rate rate Remaining term Amount (US$/C$) (US$) (C$) ---------------------------------------------------------------------------- Cross currency Swaps (1) Jan 2011 - Jul 2011 US$150 0.999 6.70% 7.70% Jan 2011 - Aug 2016 US$250 1.116 6.00% 5.40% Jan 2011 - May 2017 US$1,100 1.170 5.70% 5.10% Jan 2011 - Mar 2038 US$550 1.170 6.25% 5.76% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Subsequent to December 31, 2010, the Company entered into cross currency swap contracts for US$50 million with an exchange rate of $0.994 (US$/C$) and average interest rates of 6.70% (US$) and 7.88% (C$) for the period January to July 2011. /T/ All cross currency swap derivative financial instruments designated as hedges at December 31, 2010 were classified as cash flow hedges. In addition to the cross currency swap contracts noted above, at December 31, 2010 the Company had US$1,162 million of foreign currency forward contracts outstanding, with terms of approximately 30 days or less. Financial instrument sensitivities The following table summarizes the annualized sensitivities of the Company's net earnings and other comprehensive income to changes in the fair value of financial instruments outstanding as at December 31, 2010 resulting from changes in the specified variable, with all other variables held constant. These sensitivities are prepared on a different basis than those sensitivities disclosed in the Company's other continuous disclosure documents and do not represent the impact of a change in the variable on the operating results of the Company taken as a whole. Further, these sensitivities are theoretical, as changes in one variable may contribute to changes in another variable, which may magnify or counteract the sensitivities. In addition, changes in fair value generally can not be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear. /T/ Impact on Impact other on net comprehensive earnings income ---------------------------------------------------------------------------- Commodity price risk Increase WTI US$1.00/bbl $ (7) $ - Decrease WTI US$1.00/bbl $ 7 $ - Increase AECO C$0.10/mcf $ - $ 3 Decrease AECO C$0.10/mcf $ - $ (3) Interest rate risk Increase interest rate 1% $ (8) $ 22 Decrease interest rate 1% $ 8 $ (31) Foreign currency exchange rate risk Increase exchange rate by US$0.01 $ (27) $ - Decrease exchange rate by US$0.01 $ 27 $ - ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ b) Credit risk Credit risk is the risk that a party to a financial instrument will cause a financial loss to the Company by failing to discharge an obligation. Counterparty credit risk management The Company's accounts receivable are mainly with customers in the crude oil and natural gas industry and are subject to normal industry credit risks. The Company manages these risks by reviewing its exposure to individual companies on a regular basis and where appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default. At December 31, 2010, substantially all of the Company's accounts receivable were due within normal trade terms. The Company is also exposed to possible losses in the event of non-performance by counterparties to derivative financial instruments; however, the Company manages this credit risk by entering into agreements with counterparties that are substantially all investment grade financial institutions and other entities. At December 31, 2010, the Company had net risk management assets of $nil with specific counterparties related to derivative financial instruments (December 31, 2009 - $7 million). c) Liquidity risk Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources of capital, consisting primarily of cash flow from operating activities, available credit facilities, and access to debt capital markets, to meet obligations as they become due. Due to fluctuations in the timing of the receipt and/or disbursement of operating cash flows, the Company believes it has adequate bank credit facilities to provide liquidity. /T/ The maturity dates for financial liabilities are as follows: Less 1 to 2 to less than less than than 1 year 2 years 5 years Thereafter ---------------------------------------------------------------------------- Accounts payable $ 274 $ - $ - $ - Accrued liabilities $ 2,163 $ - $ - $ - Risk management $ 222 $ 32 $ 96 $ 101 Other long-term liabilities $ 25 $ 25 $ 41 $ - Long-term debt (1) $ 398 $ 348 $ 1,546 $ 4,774 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) The long-term debt represents principal repayments only and does not reflect fair value adjustments, original issue discounts or transaction costs. No debt repayments are reflected for $1,436 million of revolving bank credit facilities due to the extendable nature of the facilities. 12. COMMITMENTS As at December 31, 2010, the Company had committed to certain payments as follows: 2011 2012 2013 2014 2015 Thereafter ---------------------------------------------------------------------------- Product transportation and pipeline $ 228 $ 199 $ 172 $ 164 $ 152 $ 932 Offshore equipment operating leases $ 141 $ 98 $ 97 $ 97 $ 81 $ 168 Offshore drilling $ 7 $ - $ - $ - $ - $ - Asset retirement obligations (1) $ 18 $ 17 $ 19 $ 28 $ 27 $ 7,123 Office leases $ 27 $ 27 $ 28 $ 28 $ 32 $ 339 Other $ 102 $ 66 $ 19 $ 16 $ 24 $ 10 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Amounts represent management's estimate of the future undiscounted payments to settle asset retirement obligations related to resource properties, facilities, and production platforms, based on current legislation and industry operating practices. Amounts disclosed for the period 2011 - 2015 represent the estimated minimum expenditures required to meet these obligations. Actual expenditures in any particular year may exceed these minimum amounts. 13. SEGMENTED INFORMATION Exploration and Production North America North Sea Three Months Three Months (millions of Ended Year Ended Ended Year Ended Canadian dollars, Dec 31 Dec 31 Dec 31 Dec 31 unaudited) 2010 2009 2010 2009 2010 2009 2010 2009 ---------------------------------------------------------------------------- Segmented revenue 2,516 2,220 9,713 7,973 303 295 1,058 961 Less: royalties (385) (244) (1,267) (825) (1) (1) (2) (2) ---------------------------------------------------------------------------- Segmented revenue, net of royalties 2,131 1,976 8,446 7,148 302 294 1,056 959 ---------------------------------------------------------------------------- Segmented expenses Production 416 391 1,675 1,748 105 103 385 376 Transportation and blending 456 346 1,761 1,213 1 2 8 8 Depletion, depreciation and amortization 608 487 2,336 2,060 81 65 303 261 Asset retirement obligation accretion 13 11 46 41 8 5 33 24 Realized risk management activities 26 (78) (96) (880) - (44) - (373) ---------------------------------------------------------------------------- Total segmented expenses 1,519 1,157 5,722 4,182 195 131 729 296 ---------------------------------------------------------------------------- Segmented earnings (loss) before the following 612 819 2,724 2,966 107 163 327 663 ---------------------------------------------------------------------------- Non-segmented expenses Administration Stock-based compensation expense Interest, net Unrealized risk management activities Foreign exchange gain ---------------------------------------------------------------------------- Total non-segmented expenses ---------------------------------------------------------------------------- Earnings (loss) before taxes Taxes other than income tax Current income tax expense Future income tax expense (recovery) ---------------------------------------------------------------------------- Net earnings (loss) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Exploration and Offshore West Africa Production Three Months Three Months (millions of Ended Year Ended Ended Year Ended Canadian dollars, Dec 31 Dec 31 Dec 31 Dec 31 unaudited) 2010 2009 2010 2009 2010 2009 2010 2009 ---------------------------------------------------------------------------- Segmented revenue 261 307 884 913 3,080 2,822 11,655 9,847 Less: royalties (22) (22) (62) (81) (408) (267) (1,331) (908) ---------------------------------------------------------------------------- Segmented revenue, net of royalties 239 285 822 832 2,672 2,555 10,324 8,939 ---------------------------------------------------------------------------- Segmented expenses Production 46 63 167 179 567 557 2,227 2,303 Transportation and blending - - 1 1 457 348 1,770 1,222 Depletion, depreciation and amortization 791 202 1,023 335 1,480 754 3,662 2,656 Asset retirement obligation accretion 1 1 6 4 22 17 85 69 Realized risk management activities - - - - 26 (122) (96) (1,253) ---------------------------------------------------------------------------- Total segmented expenses 838 266 1,197 519 2,552 1,554 7,648 4,997 ---------------------------------------------------------------------------- Segmented earnings (loss) before the following (599) 19 (375) 313 120 1,001 2,676 3,942 ---------------------------------------------------------------------------- Non-segmented expenses Administration Stock-based compensation expense Interest, net Unrealized risk management activities Foreign exchange gain ---------------------------------------------------------------------------- Total non-segmented expenses ---------------------------------------------------------------------------- Earnings (loss) before taxes Taxes other than income tax Current income tax expense Future income tax expense (recovery) ---------------------------------------------------------------------------- Net earnings (loss) ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Oil Sands Mining and Upgrading Midstream Three Months Three Months (millions of Ended Year Ended Ended Year Ended Canadian dollars, Dec 31 Dec 31 Dec 31 Dec 31 unaudited) 2010 2009 2010 2009 2010 2009 2010 2009 ---------------------------------------------------------------------------- Segmented revenue 700 492 2,649 1,253 20 18 79 72 Less: royalties (23) (18) (90) (36) - - - - ---------------------------------------------------------------------------- Segmented revenue, net of royalties 677 474 2,559 1,217 20 18 79 72 ---------------------------------------------------------------------------- Segmented expenses Production 304 259 1,208 683 6 5 22 19 Transportation and blending 15 14 61 41 - - - - Depletion, depreciation and amortization 96 83 366 187 2 3 8 9 Asset retirement obligation accretion 5 6 22 21 - - - - Realized risk management activities - - - - - - - - ---------------------------------------------------------------------------- Total segmented expenses 420 362 1,657 932 8 8 30 28 ---------------------------------------------------------------------------- Segmented earnings (loss) before the following 257 112 902 285 12 10 49 44 ---------------------------------------------------------------------------- Non-segmented expenses Administration Stock-based compensation expense Interest, net Unrealized risk management activities Foreign exchange gain ---------------------------------------------------------------------------- Total non-segmented expenses ---------------------------------------------------------------------------- Earnings (loss) before taxes Taxes other than income tax Current income tax expense Future income tax expense (recovery) ---------------------------------------------------------------------------- Net earnings (loss) ---------------------------------------------------------------------------- Inter-segment elimination and other Total Three Months Three Months (millions of Ended Year Ended Ended Year Ended Canadian dollars, Dec 31 Dec 31 Dec 31 Dec 31 unaudited) 2010 2009 2010 2009 2010 2009 2010 2009 ---------------------------------------------------------------------------- Segmented revenue (13) (13) (61) (94) 3,787 3,319 14,322 11,078 Less: royalties - - - 8 (431) (285) (1,421) (936) ---------------------------------------------------------------------------- Segmented revenue, net of royalties (13) (13) (61) (86) 3,356 3,034 12,901 10,142 ---------------------------------------------------------------------------- Segmented expenses Production (3) (2) (10) (18) 874 819 3,447 2,987 Transportation and blending (12) (11) (48) (45) 460 351 1,783 1,218 Depletion, depreciation and amortization - (4) - (33) 1,578 836 4,036 2,819 Asset retirement obligation accretion - - - - 27 23 107 90 Realized risk management activities - - - - 26 (122) (96) (1,253) ---------------------------------------------------------------------------- Total segmented expenses (15) (17) (58) (96) 2,965 1,907 9,277 5,861 ---------------------------------------------------------------------------- Segmented earnings (loss) before the following 2 4 (3) 10 391 1,127 3,624 4,281 ---------------------------------------------------------------------------- Non-segmented expenses Administration 53 49 210 181 Stock-based compensation expense 336 87 294 355 Interest, net 120 111 449 410 Unrealized risk management activities 173 308 (25) 1,991 Foreign exchange gain (114) (84) (182) (631) ---------------------------------------------------------------------------- Total non-segmented expenses 568 471 746 2,306 ---------------------------------------------------------------------------- Earnings (loss) before taxes (177) 656 2,878 1,975 Taxes other than income tax 25 32 119 106 Current income tax expense 156 94 698 388 Future income tax expense (recovery) 58 75 364 (99) ---------------------------------------------------------------------------- Net earnings (loss) (416) 455 1,697 1,580 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net additions to property, plant and equipment Year Ended Dec 31, 2010 Non Cash/Fair Net Value Capitalized Expenditures Changes(1) Costs ---------------------------------------------------------------------------- North America $ 4,369 $ 386 $ 4,755 North Sea 149 (41) 108 Offshore West Africa 246 (10) 236 Other 3 - 3 Oil Sands Mining and Upgrading(2) 535 (59) 476 Midstream 7 - 7 Head office 18 - 18 ---------------------------------------------------------------------------- $ 5,327 $ 276 $ 5,603 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Dec 31, 2009 Non Cash/Fair Net Value Capitalized Expenditures Changes(1) Costs ---------------------------------------------------------------------------- North America $ 1,663 $ 65 $ 1,728 North Sea 168 146 314 Offshore West Africa 544 111 655 Other 2 - 2 Oil Sands Mining and Upgrading(2) 553 355 908 Midstream 6 - 6 Head office 13 - 13 ---------------------------------------------------------------------------- $ 2,949 $ 677 $ 3,626 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Asset retirement obligations, future income tax adjustments related to differences between carrying value and tax value, and other fair value adjustments. (2) Net expenditures for Oil Sands Mining and Upgrading assets also include capitalized interest, stock-based compensation, and the impact of inter- segment eliminations. Property, plant and equipment Total assets Dec 31 Dec 31 Dec 31 Dec 31 2010 2009 2010 2009 ---------------------------------------------------------------------------- Segmented assets North America $ 24,274 $ 21,834 $ 25,499 $ 22,994 North Sea 1,525 1,812 1,674 1,968 Offshore West Africa (1) 978 1,883 1,186 2,033 Other 31 28 46 42 Oil Sands Mining and Upgrading 13,401 13,295 13,865 13,621 Midstream 202 203 338 306 Head office 61 60 61 60 ---------------------------------------------------------------------------- $ 40,472 $ 39,115 $ 42,669 $ 41,024 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Offshore West Africa property, plant and equipment has been reduced by $726 million (2009 - $115 million) to reflect the impact of a ceiling test impairment charge as at December 31, 2010. /T/ Capitalized interest The Company capitalizes construction period interest to Oil Sands Mining and Upgrading activities based on costs incurred and the Company's cost of borrowing. Interest capitalization on a particular development phase ceases once construction is substantially complete. For the year ended December 31, 2010, pre-tax interest of $28 million was capitalized to Oil Sands Mining and Upgrading (December 31, 2009 - $106 million). 14. SUBSEQUENT EVENTS On January 6, 2011, the Company suspended synthetic crude oil production at its Oil Sands Mining and Upgrading operations due to a fire in the primary upgrading coking plant. Production will recommence once plant operating capacity is restored and all necessary regulatory and operating approvals are received. The Company believes that it has adequate insurance coverage to mitigate all significant property-damage related losses. The Company also maintains business interruption coverage, subject to a waiting period, which it believes will mitigate operating losses related to on-going operations. SUPPLEMENTARY INFORMATION INTEREST COVERAGE RATIOS The following financial ratios are provided in connection with the Company's continuous offering of medium-term notes pursuant to the short form prospectus dated October 2009. These ratios are based on the Company's interim consolidated financial statements that are prepared in accordance with accounting principles generally accepted in Canada. /T/ Interest coverage ratios for the twelve month period ended December 31, 2010: ---------------------------------------------------------------------------- Interest coverage (times) Net earnings (1) 6.7x Cash flow from operations (2) 15.7x ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Net earnings plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest. (2) Cash flow from operations plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest. /T/ CONFERENCE CALL A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, March 3, 2011. The North American conference call number is 1-800-769-8320 and the outside North American conference call number is 001-416-695-6616. Please call in about 10 minutes before the starting time in order to be patched into the call. The conference call will also be broadcast live on the internet and may be accessed through the Canadian Natural website at www.cnrl.com. A taped rebroadcast will be available until 6:00 p.m. Mountain Time, Thursday, March 10, 2011. To access the postview in North America, dial 1-800-408-3053. Those outside of North America, dial 001-905-694-9451. The passcode to use is 4207622. WEBCAST This call is being webcast and can be accessed on Canadian Natural's website at www.cnrl.com.

Contact Information: John G. Langille Vice Chairman or Steve W. Laut President or Corey B. Bieber Vice-President, Finance & Investor Relations or Canadian Natural Resources Limited 2500, 855 2nd Street S.W. Calgary, Alberta, T2P 4J8 Canada (403) 514-7777 Email: ir@cnrl.com Website: www.cnrl.com