Canadian Natural Resources
Annual Report 2015

Plain-text annual report

PREMIUM VALUE. DEFINED GROWTH. INDEPENDENT. 2015 ANNUAL REPORT LARGE, BALANCED, HIGH QUALITY, DIVERSE ASSET BASE Over two and a half decades, Canadian Natural has built a tremendous reserve base through organic growth and opportunistic acquisitions. As at December 31, 2015, Canadian Natural’s Company Gross proved and probable reserves were 9.04 billion BOE, with an NPV10 reserve value of $89.0 billion. This reserve base represents an asset portfolio that ranges from dry and liquids-rich natural gas to light, heavy, and synthetic crude oil assets with varying project time horizons from near-, mid- to long-term. This diverse asset strategy allows us to make balanced capital allocation decisions through all phases of the commodity price cycle. Importantly, our large, diverse, balanced asset portfolio allows us to effectively allocate capital to our highest return assets, while maximizing shareholder value in the near-, mid- and long-term. LARGE ASSET BASE NORTH AMERICA NORTH SEA OFFSHORE AFRICA 27 17 %40 16 PROVED PLUS PROBABLE RESERVES (1) OIL SANDS MINING & UPGRADING THERMAL IN SITU CRUDE OIL & NGLs NATURAL GAS (1) Company Gross. EFFECTIVE AND EFFICIENT OPERATIONS The market conditions in 2015 precipitated a global response to volatile and sharply changing commodity prices. Canadian Natural increased its focus on enhancing the effectiveness and efficiency of our operating and capital cost structures while at the same time, maintaining a commitment to safety and environmental standards. The strides made in enhancing effective and efficient operations were a result of comprehensive, detailed operational evaluations and a focus on continuous improvement. As a result, we were able to capture efficiencies, optimize proactive maintenance work, deliver productivity enhancements, strengthen our proactive safety culture and performance, and apply practical technological developments. We accomplished significant annual reductions of approximately $1.1 billion in operating costs, on a unit cost basis, and implemented capital cost cutting measures throughout 2015, totalling $3.4 billion of reductions. Effective and efficient operations remain the cornerstone of our value-driven and robust strategy. Facilitated by our high-quality and diverse land base, significant infrastructure, and area knowledge, we are nimble, and flexible in allocating our capital. In 2016, Canadian Natural will continue to focus on enhancing our effectiveness and efficiency across all our cost structures in a methodical and structured manner to ensure we can profitably develop our assets ensuring long-term success. $1.1 BILLION* 2015 OPERATING COST REDUCTIONS *FROM 2014 TO 2015 ON A UNIT COST BASIS 2015 Performance Highlights Letter to our Shareholders TABLE OF CONTENTS 02 04 08 Our World-Class Team 12 Year-End Reserves 20 Management’s Discussion and Analysis 54 Management’s Report 55 Management’s Assessment of Internal Control over Financial Reporting Independent Auditor’s Report Consolidated Financial Statements 56 58 62 Notes to the Consolidated Financial Statements 92 Supplementary Oil and Gas Information 100 Ten-Year Review 102 Corporate Information OUR TRANSITION TO A LONGER-LIFE, LOW DECLINE ASSET BASE In 2015, approximately 54% of our crude oil and natural gas liquids (“NGL”) production came from longer-life assets. Over the course of 2015, Canadian Natural advanced the completion of the Horizon Oil Sands expansion, achieved ramp-up at Kirby South toward plant capacity and increased production at Pelican Lake without drilling any wells. In 2016, we will complete a major milestone in our transition to a longer-life, low decline asset base with commissioning and startup of Phase 2B at Horizon in Q4/16 adding 45,000 bbl/d of synthetic crude oil (“SCO”). In Q4/17, Phase 3 of the expansion will add 80,000 bbl/d SCO and in 2018, longer-life, low decline production is targeted to constitute more than 67% of overall crude oil and NGLs production. Our transition is targeted to result in increasing, sustainable cash flow generation for years to come, significantly increasing the robustness of the Company and our ability to thrive through all commodity price cycles. (% OF CRUDE OIL AND NGL PRODUCTION)* 70% 60% 50% 40% 30% 20% 10% 0% 2007 2011 2015 2018F TOTAL LOW DECLINE PRODUCTION *2018F based on company internal forecast as at February 2016. Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. See forward-looking disclosures on page 20 of the Management’s Discussion and Analysis (“MD&A”). OUR FINANCIAL STRENGTH Canadian Natural’s financial objectives remain consistent and straightforward. We are committed to maintaining a strong balance sheet through flexible capital allocation and a continued focus on effective and efficient operations in all areas of our business. Our strong operational performance in 2015 supplemented by a continued focus on cost control, resulted in exit debt to book capitalization of 38%, well within our targeted operating range of 25% to 45%. With a proactive debt management program, continuous engagement with the financial community and a large, diverse asset base, we are able to react quickly to ever changing market conditions and have retained our investment grade credit ratings. UNLOCKING SHAREHOLDER VALUE Canadian Natural has a proven and value-driven strategy founded on safe, effective, efficient, and environmentally responsible operations of our diversified and balanced reserve base. A reserve base that delivers strong cash flow and is complemented by a balanced financial strategy that enables us to proactively react to all commodity price cycles. Our business is driven by our strong teams and leadership focused on execution and cost control. These facets characterize the Company’s success and our commitment to maximize value for our shareholders. We are only months away from completing the Horizon expansion, a major component in our transition to a long-life, low decline asset base; a transition that will continue to unlock significant, sustainable cash flow for our shareholders for decades to come. $0.92*/SHARE DECLARED IN 2015 *ON AN ANNUALIZED BASIS 28% CAGR INCREASE 2009 – 2015 RETURN TO SHAREHOLDERS (DIVIDENDS) C$ Million $1,000 $800 $600 $400 $200 $0 Horizon Phase I build years 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 1 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.2015 PERFORMANCE HIGHLIGHTS Canadian Natural demonstrated strong operational performance throughout 2015 despite significantly reducing our 2015 drilling programs for both crude oil and natural gas as a result of sharply declining commodity prices. The Company continues to progress its transition to a longer-life, low decline asset base while executing a balanced disciplined business approach. FINANCIAL ($ millions, except per common share amounts) Product sales Net earnings Per common share – basic – diluted Adjusted net earnings from operations (1) Per common share – basic – diluted Cash flow from operations (2) Per common share – basic – diluted Capital expenditures, net of dispositions Long-term debt (3) Shareholders’ equity OPERATING Daily production, before royalties Crude oil and NGLs (Mbbl/d) North America – excluding Oil Sands Mining and Upgrading North America – Oil Sands Mining and Upgrading North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa Barrels of oil equivalent (MBOE/d) (4) 2015 2014 2013 $ $ $ $ $ $ $ $ $ $ $ $ $ 13,167 $ 21,301 $ 17,945 (637) $ 3,929 $ 2,270 (0.58) $ (0.58) $ 3.60 $ 3.58 $ 2.08 2.08 263 $ 3,811 $ 2,435 0.24 $ 0.24 $ 3.49 $ 3.47 $ 5,785 $ 9,587 $ 5.29 $ 5.28 $ 8.78 $ 8.74 $ 3,853 $ 11,744 $ 2.24 2.23 7,477 6.87 6.86 7,274 16,794 $ 14,002 $ 9,661 27,381 $ 28,891 $ 25,772 400 123 22 19 564 391 111 17 12 531 344 100 18 16 478 1,663 1,527 1,130 36 27 1,726 852 7 21 1,555 790 4 24 1,158 671 (1) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation to this measure is discussed in the MD&A. (2) 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 repay debt. The derivation of this measure is discussed in the MD&A. (3) Includes the current portion of long-term debt. (4) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. 2 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. 179% PDP RESERVE REPLACEMENT RATIO 14.5 YEARS PDP RESERVE LIFE INDEX Drilling activity (net wells) (1) North America North Sea Offshore Africa Core unproved property (thousands of net acres) North America North Sea Offshore Africa Company Gross proved plus probable reserves (2) Crude oil and NGLs (MMbbl) North America North Sea Offshore Africa Natural gas (Bcf) North America North Sea Offshore Africa Barrels of oil equivalent (MMBOE) (1) Excludes net stratigraphic test and service wells. (2) Year-end proved plus probable reserves were prepared using forecast prices and costs. 2015 2014 2013 134 – 6 140 1,112 1,190 5 – 1 – 1,117 1,191 18,961 20,583 93 2,439 21,493 93 2,467 23,143 14,672 110 2,467 17,249 7,197 284 142 7,623 8,338 96 74 8,508 9,041 7,078 308 149 7,535 7,926 114 98 8,138 8,891 6,495 325 153 6,973 5,881 125 103 6,109 7,991 3 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.LETTER TO OUR SHAREHOLDERS In 2015, low commodity prices created a challenging environment for the entire crude oil and natural gas industry. For Canadian Natural, this challenging environment emphasized the effectiveness of our proven strategy. We believe in balance and capital flexibility. In 2015, we successfully reduced our capital spending by $3.4 billion in response to commodity price deterioration. Our enhanced focus on being effective and efficient allowed us to reduce our top-tier operating costs by approximately $1.1 billion, on a unit cost basis, while increasing production by 8% year-over-year. As a result, we delivered strong operating efficiencies, while maintaining operational discipline and a focus on value creation. We continued to add value in 2015 with the advancement of the Horizon Oil Sands Expansion Project (“Horizon”) Phases 2B and 3 towards completion. This project expansion brings another sustainable cash flow source closer to being realized. As at December 31, 2015, Horizon Phases 2B and 3 are 79% and 74% complete respectively, and Phase 2B is now approximately seven months away from adding 45,000 bbl/d of production to our long-life, low decline production mix. In 2015, we also monetized roughly 80% of our royalty lands in a cash and stock deal equating to $1.66 billion, improving our balance sheet, as well as providing the opportunity to return value to shareholders and participate in the upside of the royalty asset business. Offshore Africa had a successful year as we continued with our development drilling programs in Côte d’Ivoire, adding significant value with additional light crude oil production. We increased our dividend for the 15th consecutive year while maintaining the optionality of our diverse asset base and preserving value growth for shareholders in the years to come. We have a large, balanced and diversified asset base which facilitates flexible capital allocation decisions. Our significant ownership and operatorship in our core areas allows us to be nimble, and effective and efficient in our operations. We have a strong financial position which allows us to execute on value creation opportunities as they arise and weather market volatility. Our transition to a long-life, low decline asset base demonstrates our belief in value growth and in turn will result in maximizing shareholder value well into the future. NATURAL GAS Canadian Natural is the largest producer of natural gas in Canada and one of the largest landholders throughout Western Canada. Maintaining our strategic footprint in land and infrastructure enables us to operate effectively and efficiently while allocating capital to the projects which garner the highest returns. In 2015, we continued to target liquid-rich assets with additional focus on cost saving opportunities. We were able to reduce our North American natural gas unit operating costs by 11% while increasing production 9% year-over-year. Our Montney Septimus play has the lowest operating costs within our entire portfolio at $0.20/Mcfe, adding significant value even at low natural gas prices. In 2016, we will continue with the strategy to preserve our large, undeveloped land base through disciplined spending and investment in our liquids rich assets in the Montney in Northeast British Columbia and in our Spirit River plays in Northwest Alberta. LIGHT OIL AND NGLS NORTH AMERICA 2015 was a successful year for light crude oil and NGLs as our company-wide well review and optimization program delivered strong results. We optimized our existing operations, improved operating costs and strengthened our netbacks while maximizing value for our shareholders with low cost production adds. Strong efficiencies were gained year-over-year as unit operating costs were reduced by 14%. 2016 will see continued focus on further improving our effective and efficient operations, and production optimization of our assets. INTERNATIONAL Canadian Natural’s International assets remain an important component of our balanced strategy. Côte d’Ivoire assets in Offshore Africa generate amongst the highest returns in our portfolio. Canadian Natural’s cost advantage continued for Offshore Africa where unit operating cost reductions of 24% were achieved compared to 2014. In Côte d’Ivoire, infill drilling programs at the Espoir and Baobab fields continued to be successfully executed with results exceeding expectations. A total of ten gross producing wells came on stream in 2015 resulting in a light crude oil production increase of 54% over 2014 levels. 4 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.852 MBOE/D $5.8 BILLION PRODUCTION CASH FLOW FROM OPERATIONS continues to improve reservoir performance with production increasing by 1% to annual average production volumes of approximately 51,000 bbl/d in 2015, without drilling a single well. Strong netbacks and cash flow are generated from Pelican Lake driven by our focus on effective and efficient operations. Pelican Lake’s per barrel operating costs are the lowest in our crude oil portfolio at approximately $7.00/bbl with a year-over-year reduction of 15%. The ongoing success of our polymer flood will generate value for shareholders for years to come. In 2016, we will monitor the effectiveness of our polymer flood on the reservoir looking for additional optimization opportunities to drive down costs further. We will target to increase production without drilling any new wells until such time that positive economics warrant reinvestment. HEAVY CRUDE OIL MARKETING As expected, 2015 was a volatile year for commodities. Canadian Natural, as in previous years, continues to adopt our proven three pronged strategy to maximize realized pricing for our overall portfolio. We blend various crude oil streams and diluents to better serve the needs of our refining customers. Canadian Natural supports the expansion of export pipeline capacity, and we support and participate in projects which add conversion capacity for heavy crude oil and bitumen. in Canadian Natural looks forward to additional balance in the Alberta crude oil market through our participation in the Redwater refinery project. Canadian Natural owns 50% of the 50,000 bbl/d bitumen refinery project through the Redwater Partnership, which its participation is currently on schedule for its fourth quarter 2017 refinery will add bitumen completion. The Redwater conversion capacity in Alberta, contributing to improved heavy crude oil pricing, while generating value for our shareholders. OIL SANDS THERMAL IN SITU Canadian Natural’s portfolio of thermal assets adds further balance to our asset mix and supports our transition to improved long-life, efficiencies led to cost reductions across our in situ projects, lowering unit operating expenses 17% over 2014 levels. We continue to successfully progress our low pressure steamflood operations at Primrose East Area 1 and the low pressure cyclic steam stimulation (“CSS”) low decline asset base. In 2015, 5 In the North Sea, annual light crude oil production increased by 28% year-over-year due to the successful reinstatement of the Banff/Kyle Floating Production Storage and Offtake vessel in late 2014. Additionally, the Company reduced unit operating costs by 14% from 2014 levels. In 2016, we will continue to focus on reducing our overall cost structure by improving our effectiveness and efficiency. In addition, we will continue to build our inventory of value adding opportunities, providing additional capital flexibility to our portfolio. HEAVY CRUDE OIL PRIMARY PRODUCTION Canadian Natural has maintained its position as the largest primary heavy crude oil producer in Canada. Our operations teams deliver repeatable and proven performance with flexible and effective drilling programs. As a result, industry leading capital efficiencies and low operating costs deliver strong netbacks and significant cash flow with ample future opportunities given our significant undeveloped land base. In 2015, we continued to leverage our experience while displaying our highly flexible operations with proven performance techniques. We effectively reduced capital spending in response to commodity prices and drilled 108 net wells, a strategic 788 net well reduction year-over-year. repeatable production and During the year, we enhanced our focus on effective and efficient operations by lowering our cost structures as we moved forward with well optimizations, zone recompletions and enhanced crude oil recovery opportunities, allowing primary heavy crude oil to continue to deliver economic production and significant cash flow. In 2015, we were able to reduce unit operating costs in primary heavy crude oil by 15%. During 2016, Canadian Natural will be patient, waiting for economic conditions to improve before deploying capital in the area. Once commodity prices recover, our advantage of an extensive inventory of quality drilling locations enables significant low cost production to be added. PELICAN LAKE Pelican Lake, our leading edge polymer flood and a component of our transition to a long-life, low decline asset base, continues to exceed expectations. The polymer flood Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.HIGH QUALITY, DIVERSIFIED PORTFOLIO EFFECTIVE AND EFFICIENT OPERATIONS DISCIPLINED BUSINESS APPROACH CAPITAL AND OPERATIONAL FLEXIBILITY operations at Primrose East Area 2. At our Primrose North and Primrose South fields, optimized steaming strategies were utilized, meeting expectations with strong results in 2015. Our overall 2015 Primrose production increased by 8% over 2014 to approximately 100,000 bbl/d. At Kirby South, our large commercial steam assisted gravity drainage (“SAGD”) project, operations continued ramp-up to the targeted 40,000 bbl/d facility capacity with November 2015 volumes exceeding 41,000 bbl/d. Average production of approximately 29,500 bbl/d was achieved in 2015 and the reservoir performed as expected with strong thermal efficiencies. In early 2015, Kirby North was delayed as a result of decreasing oil prices, further demonstrating our capital flexibility and discipline. In total, thermal in situ added approximately 130,000 bbl/d of annual average production. Once favorable economic conditions return, Canadian Natural has the ability to increase thermal in situ facility capacity by 40,000 bbl/d to 60,000 bbl/d every two to three years increasing total production to approximately 520,000 bbl/d. MINING AND UPGRADING Horizon continues to be a key component in our strategy to transition to a longer-life, low decline asset base. In 2015, we continued with our enhanced focus on safe, steady, and reliable production and meaningful improvement to plant performance. Horizon, once again, achieved an industry incorporating leading average utilization rate of 90%, turnaround downtime activity, which demonstrates improved reliability for the entire year. Canadian Natural’s cost advantage continued in 2015 at Horizon. Our effective and efficient operations decreased our industry leading unit operating costs by 23% year-over-year to $28.61/bbl, on an adjusted basis. Major achievements in our cost reductions were driven by increasing throughput and continuous improvement activities. In addition, significant savings and efficiencies are being realized at Horizon due to our upgrader’s ability to produce its own diesel on site, which is used by our trucks in the mining operations. Our Horizon operations team will continue to maximize performance of the plant and are targeting unit operating costs below $25.00/bbl once Phase 3 is fully operational in 2018. Canadian Natural’s phased expansion strategy continues to be effective. Phases 2B and 3 expansions are on schedule and costs are coming in as expected, further demonstrating our team’s ability to execute under the defined plan. At year-end 2015, Phase 2B and Phase 3 are 79% and 74% 6 is during thirty-five day ramp-up physically complete, respectively. We are now approximately seven months away from a significant step-change in our long-life, low decline production profile and the sustainability of our cash flow. Phase 2B construction is on schedule for the planned tie-in of critical equipment during the turnaround. Following mid-year 2016 the targeted commissioning, fourth quarter of 2016, which will add an incremental 45,000 bbl/d of SCO at Horizon. Phase 3 completion is targeted for the fourth quarter of 2017 with the addition of 80,000 bbl/d of SCO, bringing the total Horizon productive capacity to 250,000 bb/d of SCO. With approximately $3 billion remaining to be invested in aggregate over 2016 and 2017, the completion of the staged expansion to 250,000 bbl/d of SCO is in sight. As the major component of our longer-life, low decline asset base, Horizon will generate significant sustainable cash flow and value for our shareholders for many years to come. FINANCE In 2015, we were proactive in managing our balance sheet while maintaining our capital discipline, given the significant decline in commodity prices. At year-end 2015, we had strong liquidity with approximately $3.5 billion available on our combined bank facilities of approximately $7.4 billion. Over the course of the year, we improved liquidity via our royalty land monetization transaction and opportunistic access to the debt capital markets. We are committed to maintaining our investment grade credit ratings. Its importance is demonstrated by our on-going proactive communications with rating agencies to ensure they understand our strategy, business plan and our ability to react to ever changing market conditions as they arise, while focusing on our ability to execute to strong financial metrics. In 2016, we will remain committed to maintaining a strong financial position while returning value to shareholders through our sustainable dividend policy. CANADIAN NATURAL’S STRATEGIC ADVANTAGE The execution of our proven strategy and commitment to our balanced business approach has not wavered in the current low commodity price environment. Canadian Natural is built for low commodity prices. In 2015, we reduced approximately $1.1 billion over 2014 levels, on a unit cost basis, and experienced production growth of 8%. In 2016, we remain committed to lowering our cost structures as our production and facility teams strive for new efficiency targets operating costs unit by Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.N. MURRAY EDWARDS, Executive Chairman STEVE W. LAUT, President TIM S. MCKAY, Chief Operating Officer COREY B. BIEBER, Chief Financial Officer and Senior Vice-President, Finance and cost savings. Commodity prices cannot be controlled, however, we can control our operations and execution of our strategy, while maximizing value. In 2015, we continued to add value for our shareholders through the optimization of our Kirby South project and the progression of both expansion Phases 2B and 3 at Horizon. These two projects represent major components of our progression to a longer-life, low decline asset base, an asset base that will yield increased sustainable cash flow for decades to come. This sustainable cash flow will support a strong balance sheet, returns to shareholders, acquisition opportunities and further value-adding resource development. This type. balanced commodity 2016 will be no different; Canadian Natural is positioned to withstand the uncertainties and volatility of today’s market. We have built a large, diversified asset base that provides a balanced production mix varied by region production and mix gives us the flexibility to allocate capital to the highest return projects In 2015, we carried out our strategy by allocating capital to our assets in Côte d’Ivoire, while maintaining our commitment to advancing the completion of the Horizon expansion. We are now approximately seven months away from a significant step-change in the sustainability of the Company’s cash flow with the completion of Horizon Phase 2B. We are committed to completing the Horizon expansion in our portfolio. which is targeted for a 2017 exit productive capacity of 250,000 bbl/d of 34 degree API light sweet SCO. Our capital and operating flexibility and the ability to react quickly are fundamental to the Company’s overall success and more specifically, the success of our world class assets, like Horizon. This success maximizes long-term shareholder value in any commodity price environment. In 2016, the Company will continue to focus on maintaining a strong financial position. We have clear longstanding financial objectives, which are to protect our balance sheet and maintain effective and efficient operations with a focus on cost control. We are committed to maintaining our investment grade credit ratings. Canadian Natural is well positioned to execute upon our defined plans and deliver significant and sustainable cash flow for years to come. Our teams are dedicated and committed, and we have an experienced management team to support them as we continue to build a world class company. We strive to deliver long-term value for our shareholders by focusing on effective and efficient operations and as such, we will remain the Premium Value, Defined Growth Independent. N. MURRAY EDWARDS Executive Chairman STEVE W. LAUT President TIM S. MCKAY Chief Operating Officer COREY B. BIEBER Chief Financial Officer and Senior Vice-President, Finance 7 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.OUR WORLD-CLASS TEAM G. Aalders, E. Aasen, A. Abadier, L. Abadier, Z. Abbas, T. Abbasi, D. Abbott, I. Abdi, A. Abeda, M. Abeda, W. Abeda, D. Abel, R. Abel, P. Abercrombie, R. Abrams, J. Abramyk, N. Abro, S. Abroskin, C. Acharya, D. Acheson, J. Acosta, T. Adair, I. Adam, S. Adam, W. Adam, B. Adams, D. Adams, K. Adams, M. Adams, D. Adamson, C. Adan, R. Adan, D. Addinall, A. Adebayo, Y. Adebayo, B. Adeleye, M. Aden, A. Adesanya, M. Aditiakusuma, R. Adzabe Ella, J. Agate, A. Agnihotri, K. Agombar, I. Agu, U. Agu, A. Agustin, M. Ahmad, S. Ahmad, A. Ahmadi, M. Ahmadi, F. Ahmadloo, A. Ahmari, A. Ahmed, R. Ahmed, T. Aickelin, R. Aidoo, R. Aikens, G. Ailsby, K. Airth, J. Airton, K. Aitchison, K. Aitken, T. Ajayi, V. Akella, S. Akhtar, K. Akinde, A. Akinsanya, R. Akkineni, J. Akolkar, S. Akolkar, K. Akpan, J. Alcala, E. Alconcel, D. Alderdice, S. AlDhabbi, J. Aleman, B. Alexander, D. Alexander, J. Alexander, P. Alexander, V. Alexander, E. Algazina, A. Ali, G. Ali, K. Ali, S. Ali, R. Aliazas, H. Aljanabi, M. Al-Kaisy, J. Allan, E. Allard, J. Allen, S. Allerton, D. Allin, S. Allport, J. Allsop, M. Almestar Bustamante, Y. Alnumi, J. Alonso, A. Al-Saleem, R. Al-Samarrai, S. Al-Siani, A. Alstad, J. Alvarez, J. Alvarez Luzon, D. Amalaman, J. Aman, M. Amar, T. Amara, A. Amay, K. Amer, D. Ames, E. Amos, G. Amundrud, W. Amy, D. Andersen, T. Andersen, B. Anderson, C. Anderson, D. Anderson, G. Anderson, J. Anderson, K. Anderson, M. Anderson, N. Anderson, P. Anderson, W. Anderson, M. Andreas, P. Andrekson, D. Andreoli, C. Andres, J. Andres, D. Andrews, E. Andrews, L. Andrews, T. Andrews, C. Angeles, P. Angell, L. Angen, K. Angerman, N. Ango Mfene, C. Angus, M. Anis, E. Annis, S. Annis, L. Anongba, A. Ansell, D. Ansorger, R. Anstett, G. Anstey, L. Antal, K. Antonishyn, T. Antoniuk, S. Antonuk, H. Aparicio Ramos, P. Appiah, B. April, R. April, J. Aquila, R. Aranguren, F. Arano, L. Arbour, C. Arcand, L. Archer, P. Archer, J. Argan, M. Arguin, H. Arias, L. Arias, J. Arizaleta, J. Arkley, T. Armfelt, A. Armstrong, D. Armstrong, J. Armstrong, K. Armstrong, P. Armstrong, R. Armstrong, T. Armstrong, J. Arnault, C. Arnold, F. Arrieta, M. Arsenault, L. Arthur, A. Ashley, D. Ashley, W. Ashun-Codjiw, R. Aslin, R. Aspden, S. Aspden, M. Asselstine, D. Assinger, J. Asso, V. Assohou-Ouattara, F. Assoko-Mve, A. Assoum, S. Assoumane, A. Astalos, R. Astalos, N. Athavan, A. Atienza, R. Atkins, B. Atkinson, J. Atkinson, L. Attreo, E. Au, G. Au, C. Aube, J. Auch, A. Auger, B. Auger, D. Auger, C. Aular, D. Austin, R. Austin, J. Avedon-Savage, L. Avery, M. Avila, C. Aviles, O. Awodein, E. Awuni, A. Ayasse, W. Ayles, J. Ayub, F. Azam, C. Babos, K. Babu, C. Bachelet, W. Bachmeier, T. Bachmier, A. Baciulica, O. Baddar, M. Baddeley, W. Bader, J. Badock, N. Bagheri, A. Bagnall, M. Bahiraei, B. Bahlieda, D. Baichev, D. Baier, J. Baier, K. Baier, N. Baier, M. Bailer, R. Bailer, A. Bailey, B. Bailey, J. Bailey, K. Bailey, B. Bain, D. Baird, G. Baird, B. Bairstow, D. Baisley, C. Bak, A. Baker, C. Baker, D. Baker, G. Baker, F. Bakita, K. Bakker, J. Balacang, B. Baldonado, J. Baldonado, M. Baldwin, R. Baldwin, I. Balicanta, J. Balkam, D. Ball, G. Ball, P. Ball, J. Ballard, G. Ballas, S. Ballas, B. Balog, D. Balson, B. Baluyot, R. Bama, L. Bamba, R. Bamotra, J. Banak, D. Banash, J. Banawa, N. Banerjee, A. Banfield, R. Banfield, O. Bango, L. Banks, M. Banks, B. Bannis, T. Banny, C. Bantaya, Y. Bao, G. Bardoel, L. Bardoel, F. Bardoux, K. Barham, M. Bari, R. Barker, S. Barker, A. Barley, C. Barnes, D. Barnes, M. Barnes, N. Barnes, R. Barnes, V. Barnes, B. Barnett, E. Barns, D. Barr, P. Barr, S. Barr, E. Barreto, R. Barrett, T. Barrett, C. Barrie, D. Barron, R. Barron, L. Barros, C. Barth, B. Bartlett, C. Bartlett, E. Bartlett, M. Bartlett, C. Bartman, D. Bartman, M. Bartman, J. Basabe, K. Basarab, J. Basilan, R. Basile, L. Basines, C. Basque, S. Basso, C. Bast, A. Bastin, S. Basu, M. Batac, B. Bate, C. Bateman, K. Bateman, T. Bateman, G. Bates, M. Batovanja, D. Batt, U. Batta, B. Battyanie, J. Batuyong, D. Bauer, L. Bauer, R. Bauer, T. Bauld, J. Bauman, C. Baumgardner, C. Baxter, A. Bazowski, B. Beach, A. Beacon, W. Beals, C. Beaman, J. Beamish, D. Bean, C. Beaton, G. Beaton, N. Beaton, A. Beattie, C. Beattie, G. Beattie, S. Beattie, A. Beatty, K. Beatty, S. Beauchamp, A. Beaudoin, C. Beaudoin, J. Beaudoin, R. Beaudoin, B. Beaulac, L. Beaunoyer, F. Beaver, D. Bechtel, N. Beck, C. Becker, R. Becker, R. Beckner, S. Beckow, A. Bedi, G. Bedi, M. Bednarchuk, S. Beebe, T. Beebe, J. Been, B. Beesley, K. Begg, W. Behnke, A. Belah, P. Belair, G. Belanger, R. Belanger, H. Belas, L. Belcourt, R. Belcourt, J. Belik, R. Belisle, D. Bell, J. Bell, N. Bell, S. Bell, R. Bellanger, J. Beller, M. Beller, E. Bellerose, A. Bellettini, A. Bellows, K. Belyea, M. Belzile, M. Bembridge, A. Bendahmane, K. Bendahmane, K. Benner, C. Bennett, E. Bennett, J. Bennett, M. Bennett, R. Bennett, S. Bennett, K. Benoit, M. Benoit, P. Benoit, S. Bensmiller, R. Benson, A. Benson- Bartko, J. Bent, A. Bentley, C. Bereznicki, D. Berg, K. Bergen, J. Bergeson, M. Bergeson, B. Bergley, D. Berisha, D. Berlinguette, H. Berlinguette, J. Bernardin, D. Bernardo, D. Berry, D. Bershadsky, S. Bertelmann, B. Bertrand, M. Bertsch, B. Berube, W. Berube, R. Bessey, C. Best, J. Best, D. Beswatherick, T. Betteridge, S. Bettinson, W. Bewski, B. Beyer, J. Beytell, S. Bezpalchuk, J. Bezruchak, N. Bhachu, U. Bhachu, A. Bhadauria, A. Bhaduri, R. Bhagat, I. Bhasin, H. Bhatia, J. Bhatt, K. Bhatt, R. Bhatt, V. Bhekare, L. Bianco, M. Bibars, A. Bibo, C. Bieber, D. Bieber, D. Bielech, E. Bieleski, D. Biendarra, D. Biener, V. Biesinger, C. Biggin, M. Biggs, A. Bilal, B. Bill, T. Billard, J. Billard-Payne, J. Bilodeau, J. Bilous, T. Binczyk, W. Binda, R. Bintz, S. Bird, B. Bischoff, C. Bischoff, R. Bischoff, S. Bischoff, C. Bish, H. Bishop, J. Bishop, K. Bishop, T. Bishop, C. Bisschop, L. Bissell, K. Bissett, C. Bisson, D. Bittner, A. Black, B. Black, C. Black, D. Black, J. Black, R. Black, N. Blackburn, P. Blackburn, T. Blackett, K. Blackhall, K. Blackmore, R. Blackmore, T. Blackwell, D. Blain, A. Blair, K. Blair, J. Blais, E. Blake, B. Blakney, D. Blanchard, J. Blanche, R. Blanchett, K. Blanchette, A. Blanco, G. Blanco, U. Blanco, W. Blanco, S. Blaydes, A. Blesa, R. Blondin, J. Blume, C. Blyan, C. Boadas Salazar, M. Bobb, A. Bobrowski, H. Bocalan, D. Bochek, A. Boddy, G. Boddy, R. Bodell, S. Bodell, A. Bodnar, B. Bodnar, J. Bodnarchuk, H. Bodry, D. Boehmer, D. Boettcher, D. Boettger, M. Boggust, T. Bohach, N. Bohning, J. Bohorquez, G. Bohrson, C. Boisvert, M. Boisvert, D. Bolch, C. Boleski, G. Bolin, D. Bolster, G. Bolton, D. Boman, C. Bombay, J. Bonami-McRae, K. Bond, N. Bond, S. Bond, T. Bond, T. Bondaruk, C. Bonebrake, A. Bonilla, W. Bonn, C. Bonogofski, R. Booker, P. Booklall, J. Boomgaarden, B. Boone, C. Boos, J. Boos, M. Booth, B. Borbely, A. Borbon, K. Bordeleau, J. Borg, C. Borgel, C. Borgland, J. Borland, M. Borlaza, M. Born, D. Borowski Grimaldi, E. Borsini Marin, K. Borysiuk, B. Bosch, S. Bosch, J. Boschman, L. Bosma, L. Bosoi, H. Botha, K. Bothwell, J. Botterill, R. Botting, K. Bottomley, K. Bottriell, D. Bouchard, C. Boucher, R. Boucher, S. Boudignon, K. Boudreau, J. Boudreault, J. Bouffard, K. Bougie, L. Boulianne, J. Boulton, R. Bourassa, S. Bourassa, J. Bourgeois, D. Bourgoin, C. Bourlon, D. Bourque, S. Bourrie, C. Boussougou Mayagui, C. Boutier Becerra, D. Boutin, C. Bowditch, D. Bowen, J. Bowen, R. Bowers, S. Bowers, D. Bowes, J. Bowie, M. Bowles, C. Bowman, N. Bowman, W. Bowman, E. Bown, W. Bowness, M. Bowry, D. Boyarski, T. Boyce, D. Boyd, P. Boyd, R. Boyd, S. Boyd, C. Boyer, M. Boyer, D. Boyle, L. Boyle, R. Boyle, K. Bradbury, B. Bradley, P. Bradner, J. Bradshaw, C. Bradt, M. Brady, C. Bragg, L. Bragg, D. Braid, A. Brain, J. Brake, N. Brake, S. Brake, T. Branch, P. Brand, B. Brant, D. Brant, E. Brant, T. Brant, A. Brar, M. 8 TO DEVELOP PEOPLE TO WORK TOGETHER TO CREATE VALUE FOR THE COMPANY’S SHAREHOLDERS BY DOING IT RIGHT WITH FUN AND INTEGRITY. Brar, P. Brar, C. Brassard, M. Brataschuk, R. Brattston, C. Brausen, J. Bravo, K. Bravo, L. Bravo, J. Brawn, K. Bray, N. Bray, T. Bray, A. Brazeau, G. Brecht, M. Brecht, D. Bredy, J. Breen, S. Breitkreuz, P. Breland, L. Brennan, B. Brenton, R. Brenton, T. Brettnell, R. Bretzlaff, O. Breukel, A. Brewer, W. Briand, S. Briard, C. Bridger, M. Bridger, H. Brietzke, M. Brietzke, C. Briggs, G. Briggs, A. Brighton, L. Brinkworth, S. Brinson, C. Brisebois, V. Brisebois, P. Britton, P. Brochu, E. Brock, J. Brock, K. Brocke, B. Broda, D. Broderick, S. Broderick, S. Broderson, D. Brodziak, E. Broidioi, K. Bromley, J. Bronkhorst, J. Brooks, R. Brooks, T. Brooks, K. Brosowsky, K. Brosseau, T. Brosseau, J. Broughton, B. Brousseau, C. Brousseau, E. Brousseau, C. Brow, N. Brow, A. Brown, B. Brown, C. Brown, D. Brown, E. Brown, J. Brown, K. Brown, M. Brown, R. Brown, S. Brown, T. Brown, D. Brownrigg, C. Bruce, J. Bruce, A. Brucker, K. Bruggencate, F. Brugger, J. Brule, K. Brule, V. Brule, S. Brulotte, N. Brummitt, R. Brundige, K. Bruner, B. Bryant, R. Bryant, T. Bryant, G. Brydges, T. Brydges, H. Bryenton, J. Bryla, S. Bryson, G. Buchan, P. Buchanan, M. Bucholtz, M. Bucke, D. Buckley, G. Buckshaw, D. Budalich, T. Budd, B. Budgell, R. Budzen, R. Bueckert, W. Bugiak, J. Buholzer, S. Bukhari, B. Bulbuck, R. Bullen, T. Bullen, I. Bulloch, J. Bullock, D. Bumstead, S. Bungay, B. Bunz, C. Bur, D. Burak, J. Burchell, T. Burchenski, A. Burden, K. Burden, J. Burdett, C. Burge, G. Burgess, G. Burkart, L. Burke, G. Burkhart, D. Burnell, R. Burnham, B. Burr, D. Bursey, M. Bursey, A. Burt, B. Burt, S. Burt, G. Burton, R. Burton, R. Busato, K. Bush, D. Bushey, J. Bushey, D. Bussey, N. Bussiere, J. Bustamante, J. Bustos, M. Butchart, K. Butcher, C. Butler, I. Butler, M. Butler, R. Butler, C. Butt, Q. Butt, S. Butt, B. Butterworth, I. Butterworth, M. Buttigieg, K. Butts, R. Butts, P. Buxton, W. Bykewich, J. Byrne, M. Byrne, T. Byrnell, I. Byvald, L. Cabatuando, A. Cabral, M. Caceres-Centeno, E. Cadieux, K. Cadieux, T. Cadieux, G. Cahoon, L. Cai, H. Cairns, E. Caissie, W. Calabio, B. Calder, L. Calder, B. Caldwell, J. Caldwell, P. Caldwell, C. Caleffi, C. Callihoo, P. Callin, R. Calliou, R. Cameron, S. Cameron, B. Campbell, C. Campbell, D. Campbell, E. Campbell, F. Campbell, J. Campbell, K. Campbell, M. Campbell, N. Campbell, S. Campbell, W. Campbell, A. Campeau, N. Campeau, W. Campeau, M. Canchica, G. Cane, R. Canelon Oyarzabal, M. Canning, R. Canning, J. Cannon, B. Cant, E. Cantlon, N. Cantwell, G. Cao, M. Cao, A. Caouette, K. Cap, M. Capitaneanu, A. Caplette, J. Capstick, B. Carabin, A. Cardenas, F. Cardinal, L. Cardinal, R. Cardinal, S. Cardinal, W. Cardinal, A. Carefoot, M. Carew, W. Carey, R. Carifelle, T. Carleton, K. Carlos, F. Carlos Sanchez, J. Carlson, W. Carlson, D. Carmichael, D. Carnes, A. Carnochan, A. Caron, D. Caron, P. Caron, R. Caron, S. Caron, Y. Caron, D. Carr, J. Carr, L. Carranza, V. Carrasco Rueda, M. Carrier, D. Carroll, I. Carroll, J. Carroll, C. Carsh, E. Cartaya, A. Carter, D. Carter, J. Carter, K. Carter, N. Carter, C. Cartier, X. Cartron, J. Cartwright, G. Case, P. Cashin, T. Cassidy, L. Casson, H. Castillo Leon, K. Castle, J. Castro, N. Catley, S. Catley, L. Catto, B. Cave, D. Cavers, R. Cawaling, G. Cawthorn, C. Cayer, C. Celis, A. Centeno, S. Cervantes, D. Chadwick, A. Chaisson, S. Chakravarty, C. Chalifoux, J. Chalmers, M. Chalmers, S. Chalmers, K. Champagne, L. Champagne, A. Chan, C. Chan, D. Chan, I. Chan, L. Chan, M. Chan, S. Chan, T. Chan, V. Chan, A. Chaney, K. Chang, T. Chantler, K. Chapman, B. Chapple, W. Charanek, S. Charette, J. Charlebois, M. Charles, T. Charlton, Y. Charniauski, L. Charrois, C. Chartrand, R. Chartrand, A. Chatman, A. Chatterjee, L. Chau, M. Chaudhari, M. Chaudhry, R. Chauhan, J. Chaval, M. Chawla, M. Chayko, T. Chayko, C. Chaytor, M. Chaytor, O. Chebli, E. Chebunina, S. Checkley, C. Cheeseman, B. Chen, C. Chen, O. Chen, T. Chen, X. Chen, Z. Chen, C. Cheng, J. Cheng, L. Cheng, N. Cheng, D. Chenier, N. Cheraghi, M. Chernichen, T. Cherry, O. Chervyakova, B. Chester, A. Chesterman, D. Chetcuti, P. Chetram, A. Cheung, K. Cheung, W. Cheung, B. Cheyne, B. Chhualsingh, B. Chichak, D. Chick, G. Chick, T. Chick, B. Chicoine, D. Chidley, K. Chilibeck, A. Chin, S. Chin, T. Chipiuk, B. Chisholm, T. Chisholm, P. Chiu, R. Chmelyk, J. Chohan, J. Cholka, R. Chong, P. Choo, B. Chopping, B. Chorney, C. Chornohos, M. Chornohus, S. Choudhury, R. Chowdhury, G. Choy, A. Chretien, L. Christensen, R. Christensen, T. Christensen, J. Christian, S. Christiansen, M. Christianson, S. Christianson, H. Christie, R. Christie, S. Christie, R. Christopher, A. Chu, C. Chua, V. Chui, L. Chung, P. Chung, W. Chung, H. Church, B. Churchill, G. Churchill, R. Churchill, K. Chychul, V. Cimon, K. Cisse- Banny, E. Cissell, R. Clancy, W. Clapperton, T. Clare, A. Clark, B. Clark, J. Clark, K. Clark, L. Clark, T. Clark, B. Clarke, D. Clarke, J. Clarke, K. Clarke, M. Clarke, R. Clarke, S. Clarke, W. Clarke, W. Clarkson, D. Clavier, G. Clegg, J. Clelland, T. Clelland, R. Clemmer, J. Clevenger, D. Clifton, Z. Closter, W. Clough, R. Cloutier, J. Clowater, M. Cnossen, R. Coates, E. Cobaj, M. Cochet, F. Codd, J. Coers, C. Coffey, L. Colborne, J. Colbourne, A. Coles, M. Coles, R. Coles, C. Colina, L. Collard, P. Colley, D. Collicutt, M. Collie, G. Collings, G. Collins, J. Collins, R. Collins, A. Collison, G. Collison, A. Collyer, E. Comeau, J. Commance, C. Compton, Q. Conacher, W. Conacher, J. Condie, A. Connell, M. Connellan, D. Conrad, S. Constant, D. Conybeare, C. Cook, G. Cook, L. Cook, N. Cook, A. Cooke, H. Cooke, K. Cookson, L. Cookson, R. Coolen, H. Coolidge, J. Coombs, L. Coonan, L. Cooper, C. Copeland, M. Copithorne, R. Copland, D. Coppard, D. Corbett, N. Corbett, J. Corcoran, M. Corell, E. Coreman, I. Cormier, R. Cormier, R. Cornell, C. Corpe, S. Correll, D. Corrigan, R. Corrigan, J. Corson, S. Corson, P. Corticelli, H. Costello, J. Costello, J. Costigan, J. Costley, B. Cote, E. Cote, J. Cote, M. Cote, A. Cote Simard, L. Cottreau, S. Coulibaly, D. Coull, K. Coulombe, M. Courage, J. Courchene, R. Courchesne, G. Courtney, P. Cousin, D. Cousins, M. Cousins, P. Covell, D. Coward, K. Cowger, C. Cowie, C. Cowley, R. Cowley, A. Cox, B. Cox, E. Cox, G. Cox, J. Cox, R. Cox, R. Coyer, E. Cozicor, N. Crabb, R. Craft, C. Craig, D. Craig, G. Craig, R. Craig, H. Craigie, B. Crain, K. Cramb, P. Cramb, S. Cramm, M. Crane, A. Crawford, B. Crawley, J. Crawley, G. Crayford, B. Creed, L. Cressman, R. Crichton, D. Crittall, W. Crockford, A. Croft, S. Croft, G. Crooks, D. Crosley, C. Cross, T. Cross, S. Croteau, T. Crouser, A. Croutch, S. Crowe, D. Crowle, B. Crowley, R. Cruickshank, D. Crum, K. Crutchley, L. Cruttenden, C. Cruz, F. Cruz, A. Csabay, S. Cseke, E. Cuello, Y. Cui, V. Culina, M. Culligan, A. Cunanan, A. Cunningham, D. Cunningham, R. Cunningham, S. Cunningham, E. Cupac-Cingel, J. Curran, A. Currie, M. Currie, R. Currier, K. Cursley, K. Cusack, M. Cusson, R. Cusson, J. Cutler, D. Cyr, G. Cyr, J. Czarnecki, L. Czernicki, M. Czerwinski, K. d’Abadie, V. Daboin, A. Dabrowski, M. Dacillo-Basallajes, G. Dacyk, F. Dadashov, R. Dadey, M. Dadi, G. Dafoe, W. Dagley, A. Dahmani, C. Daigle, B. Daignault, E. Dakaud, P. Dakin, P. Dale, L. Dalgetty-Rouse, G. Dallaire, J. Dallaire, S. Dalrymple, M. Dalton, N. Damian-Diaz, S. Dams, E. Dana, C. Danaher, T. Danbrook, W. Danchak, J. Daniels, T. Daniels, D. Danilkewich, I. Dantiwala, P. Danyluk, S. Daqamseh, D. Daraban, M. D’arcangelo, A. Dareichuk, V. Darel, M. Darling, W. Darling, C. DaRosa, F. Daub, D. Dave, H. Dave, M. Dave, L. David, W. David, B. Davidson, G. Davidson, J. Davidson, M. Davidson, S. Davidson, T. Davidson, C. Davies, D. Davies, L. Davies, M. Davies, S. Davies, J. Davis, K. Davis, P. Davison, R. Daw, D. Dawe, K. Dawe, S. Dawe, M. Dawes, C. Day, D. Day, J. Daye, P. De Castro, M. de Chavez, S. de Groot, S. De Gruchy, R. De Jesus, E. de Kock, C. de la Salle, R. De Leeuw, B. De Lorenzo, R. de Ruiter, V. de Ruiter, A. De Sousa, J. de Villiers, B. de Winter, B. de Witt, B. Deacon, M. Dean, G. Dearden, C. Deaver, T. Debler, R. deBoer, N. Debogorski, W. DeBona, D. Dechaine, J. Dechaine, P. Dechaine, R. Dechaine, P. Dechant, R. Dechesne, B. Decker, M. Decker, R. Decker, J. Decoeur, W. Dedam, N. Deeney, L. Deep, M. Deering, D. Defoort, L. Defoort, S. DeFord, B. DeGagne, M. Degenstien, B. DeHaan, A. Deibert, R. Deitz, N. Dela Cruz, D. DelaCruz, I. Delaney, E. DeLaRonde, J. Delaurier, N. Delibasic, M. Dell, F. Dell’Ovo, M. DelMastro, P. DelMastro, M. Delorme, A. Demaiter, M. Demers, C. DeMone, M. Demou, C. Dempsey, F. Denney, S. Dennis, D. Dennison, S. Denny, C. Denslow, J. Dent, H. Derakhshan, D. Derbyshire, M. Derry, A. Desai, C. Desai, D. Desai, R. Desai, C. Desaulniers, M. Deschambeau, T. Deschamps, D. Deschenes, A. Desharnais, C. Desjardins-Knowlden, G. Desjardins-Knowlden, C. Desjarlais, C. Desmarais, J. Desnoyers, M. Detta, K. Deutsch, S. Deval, L. Devey, J. DeVries, B. Dew, J. Dewar, T. Dewhurst, D. Dey, K. Deyaegher, G. Dhaliwal, H. Dhaliwal, M. Dhaliwal, R. Dhaliwal, P. Dhalwala, B. Dhanesha, P. Dhanjal, J. Dharamsi, M. Dhariwal, M. Dhere, G. Diack, K. Diakiw, K. Diallo, D. Diaz, L. Diaz, K. Diaz Garcia, D. DiBenedetto, R. Dicken, A. Dicks, E. Dicks, J. Dicks, N. Dicks, B. Dickson, C. Dickson, F. Dickson, G. Dickson, A. Didenko, D. Diebel, J. Diederich, I. Dikau, R. Dillman, A. Dillon, A. Dimapilis, M. Dingley, P. Dingley, R. Dinkel, H. Dinn, S. Dionne, R. Diputado, M. Dirk, S. Dirk, T. Ditchburn, A. Dixit, C. Dixon, R. Dixon, T. Dixon, D. Dixson, K. Do, M. Doak, W. Dobchuk, C. Dobek, L. Dobson, E. Dochuk, R. Docksteader, L. Dodd, R. Dodd, M. Doepel, E. Doepker, R. Doering, J. Doetzel, B. Doherty, J. Doiron, K. Doiron, E. Doleman, J. Doleman, K. Doll, B. Dombrova, D. Domin, K. Donald, S. Donaldson, R. Donaleshen, C. Dong, M. Dong, J. Donohoe, J. Donovan, N. Donovan, J. Doonanco, T. Dootka, S. Dorer, A. Dorey, T. Dorgeles, S. Dorie, M. Dorocicz, J. Dorusak, A. Dosanjh, M. Doucet, R. Doucet, D. Doucette, K. Doucette, S. Douglas, R. Dow, A. Dowd, J. Dowd, E. Dowell, S. Dowell, M. Dowman, P. Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.7,568 STRONG DIVERSITY. TALENT. EXPERTISE. Our proven strategy and disciplined business approach are supported by our dedicated people and experienced management team. Downes, J. Downey, A. Downs, A. Doyer, R. Doyer, G. Doyle, L. Doyle, S. Drake, P. Drapeau, K. Draper, T. Draper, W. Draper, D. Draycott, K. Dreger, C. Drescher, D. Dressler, B. Drew, J. Dreyer, T. Dreyer, A. Driemel, A. Drier, T. Driscoll, E. Drolet, R. Drummond, C. Drury, D. Drury, S. Drysdall, V. D’Souza, M. Du, Y. Du, M. Du Preez, C. Duane, R. Duarte, M. Dube, N. Dube, T. Dube, D. Dubeau, J. Dubeau, S. Dubelt, T. Dubie, G. Dubois, J. Dubois, J. Dubuc, L. Dubuc, D. Duby, R. Ducharme, P. Duchesnay, J. Duchscherer, J. Duczek, P. Duda, S. Dudley, R. Dueck, G. Duff, S. Duff, L. Duffy, E. Dufour, S. Dugdale, C. Duggan, D. Duguid, A. Duhaime, D. Duke, J. Dul, C. Dumais, T. Dumba, G. Dumont, Y. Dumont, L. Dumoulin, B. Duncan, J. Duncan, S. Duncan, B. Dunn, J. Dunn, P. Dunn, R. Dunn, S. Dunn, E. Dunnet, J. Dunsmuir, K. Dupuis, M. Durnie, H. Dutchak, J. Dutchak, O. Dutka, R. Duval, C. Dwyer, A. Dyck, C. Dyck, C. Dyer, J. Dyer, T. Dyer, E. Dyjur, L. Dyke, S. Dykstra, R. Dyson, K. Dzwonek, J. Eagleson, G. Earl, R. Earl, J. Easthope, B. Eastman, K. Eberle, R. Ebuna, G. Ecker, C. Eddy, E. Edeonu, P. Edirisinghe, J. Edmunds, A. Edoukou, J. Edoukou, D. Edwards, J. Edwards, M. Edwards, F. Eefting, T. Eeuwes, T. Egan, L. Egeland, R. Eggen, C. Ehresman, I. Eichelbaum, R. Eisawy, T. Eissfeldt, B. Eitzen, D. Ekdahl, C. Ekpekurede, M. El Gohary, R. Elaschuk, D. Eley, M. Elgarni, M. El-Harakeh, D. Elia, T. Elias, R. Elko, D. Ell, K. Elladen, R. Elliott, S. Elliott, W. Elliott, D. Ellis, K. Ellis, S. Ellis, C. Ellsworth, E. Ellsworth, M. Elms, M. Eloursa Escanela, O. El-Sayed, E. Elson, J. Elson, T. Ely, V. Embleton, H. Emery, J. Emro, J. Engel, R. Engler, J. English, L. Ennis, R. Enns, B. Ens, R. Ephgrave, J. Erasmus, S. Erb, D. Ereaut, B. Eresman, C. Erfle, B. Erickson, T. Erickson, N. Erixon, M. Ernst, P. Ersh, C. Erskine, D. Ertmoed, P. Escalona, F. 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Johnson, T. Johnson, A. Johnston, D. Johnston, N. Johnston, R. Johnston, B. Johnstone, C. Johnstone, S. Johnstone, D. Johnston-Watson, V. Jolliffe, J. Jonasson, B. Jones, C. Jones, D. Jones, E. Jones, G. Jones, K. Jones, M. Jones, N. Jones, R. Jones, S. Jones, V. Jones, W. Jones, P. Joo, J. Jorawsky, D. Jordan, D. Jordison, C. Jorgensen, D. Jorgensen, L. Jorgensen, D. Joseph, P. Joseph, A. Joshi, T. Joshi, U. Joshi, S. Josselyn, F. Josue, D. Jowsey, J. Juan, M. Juanerio, R. Jubinville, T. Juett, J. Jung, S. Jung, C. Jungen, R. Jungkind, M. Junio-Read, C. Jurgenliemk, K. Jurouloff, A. Kachra, C. Kada, L. Kada, T. Kadikoff, C. Kaglea, R. Kahanyshyn, A. Kaid, K. Kajorinne, R. Kalam, S. Kalbag, A. Kalmet, D. Kalynchuk, Y. Kam, A. Kamate, B. Kamath, A. Kamke, G. Kamon, S. Kanarek, A. Kandasamy, S. Kandulva Chakrapany, L. Kane, S. Kane, N. Kang, Z. Kanji, R. Kanomata, D. Kantz, S. Kapeluck, Y. Karayan Moosafi, R. Karlowsky, R. Karlson, S. Karmakar, C. Karpiak, J. Karr, K. Kartushyn, D. 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Matychuk, P. Maurice, S. Maurice, D. Mavridis, D. Mavuwa, A. Mawer, K. Maxwell, A. May, R. May, J. Mayer, S. Mayer, T. Mayhew, A. Maynard, T. Maynard, K. Mayner, A. Mayo, B. Mayo, C. Mays, C. Mazuryk, D. McAlister, M. McAlpine, D. McArthur, K. McArthur, N. McBain, A. McBoyle, R. McBrien, D. McCabe, G. McCabe, J. McCaffrey, R. McCallum, S. McCann, D. McCarvill, S. McClellan, D. McClelland, I. McClelland, B. McConachie, B. McCormack, C. McCormick, M. McCotter, S. McCracken, B. McCrady, K. McCrae, C. McCrea, B. McCullough, C. McCullough, R. McCullough, P. McDade, A. 10 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.Rattray, H. Ratzlaff, A. Rau, L. Ravoy, P. Rawlinson, E. Rawson, D. Ray, S. Ray, J. Rayner, R. Rayner, M. Raza, B. Read, D. Read, W. Read, G. Reader, W. Reashore, R. Reaume, T. Reay, C. Reber, D. Reber, D. Rechenmacher, K. Reddekopp, B. Redlich, C. Redmond, R. Redmond, C. Redpath, A. Reed, D. Reed, J. Reed, K. Reed, S. Reed, C. Regnier, R. 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Saini, J. Sair, K. Saiyed, D. Sakires, K. Sakowsky, R. Sakwattanapong, R. Sala, A. Salakunov, A. Salazar, C. Salazar, D. Salazar, E. Salazar, E. Saleh, O. Saleh, M. Salehi, J. Sali, C. Salim, C. Salisbury, E. Saller, M. Salman, E. Salmon, P. Salomon, A. Salonga, G. Salt, S. Saltwater, B. Saluk, A. Samadi, N. Samer, S. Samimi, A. Samoisette, S. Sampanthamoorthy, H. Sampson, S. Samy, V. Sanchala, R. Sanchez Hernandez, P. Sanders, D. Sanderson, L. Sanderson, S. Sanderson, S. Sandhar, N. Sandhawalia, J. Sandie, G. Sando, T. Sanelli, G. Sanford, E. Sangroniz, N. Sankaran, R. Sanregret, T. Santos, M. Santucci, J. Sanyal, A. Saran, S. Saran, Z. Saran, R. Sarauskas, D. Saretsky, S. Sarkar, D. Sarmiento, A. Sartori, M. Sartoris, M. Sas, S. Sashuk, T. Sather, W. Sather, M. Satra, E. Saucier, J. Saucier, S. Sauder, G. Saunders, L. Saunders, R. Saunders, S. Saurette, C. Sauve, J. Savage, B. Savla, D. Savoie, L. Savoie, M. Savoie, C. Savostianik, M. Sawka, B. Sawler, C. Sayer, R. Sayer, K. 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Sheaves, L. Sheaves, W. Sheaves, A. Shehata, J. Shelfantook, B. Shenton, I. Shepherd, G. Sheppard, J. Sheppard, R. Sheppard, T. Sheppard, A. Shergill, M. Sherman, S. Sherman, I. Sherr, M. Sheth, N. Sheth, D. Shewchuk, J. Shewchuk, L. Shewchuk, L. Shi, A. Shideler, C. Shields, N. Shihinski, S. Shiledarbaxi, K. Shill, A. Shillam, P. Shiner, W. Shipley, J. Shire, V. Shirhatti, B. Shmoury, B. Shmyr, D. Shmyr, C. Shmyrko, M. Shobeiri, S. Short, D. Shortland, D. Shortreed, J. Shortt, L. Shostak, M. Shukalov, K. Shukla, D. Shular, J. Shumate, T. Shymko, S. Shymoniak, D. Shypitka, J. Shysh, I. Siddhanta, M. Siddiqui, M. Sideroff, P. Sidhu, M. Sidney, C. Sieben, D. Sieben, J. Sieben, R. Sigsworth, W. Sikorski, L. Silas, T. Silbernagel, B. Silue, E. Silva, I. Silva, L. Silva, H. Simani, C. Simard, D. Simard, K. Simard, C. Simcock, G. Simmelink, J. Simmons, A. Simms, F. Simms, R. Simms, G. Simpkins, D. Simpson, G. Simpson, P. Simpson, R. Simpson, S. Simpson, W. Simpson, E. Sinclair, R. Sinclair, S. Sinclair, D. Sine, A. Singh, D. Singh, K. Singh, S. Singh, Y. Singh, M. Singher, S. Singla, M. Sinkova-Hovdestad, A. Sinnett, J. Sisson, J. Sjonnesen, D. Skanderup, W. Skaret, K. Skarra, E. Skarsen, M. Skinner, M. Skipper, G. Skoczek, J. Skog, M. Skolski, R. Skrepnek, S. Skulmoski, M. Skulski, M. Skyrpan, R. Slade, M. Slavin, E. Sleet, K. Slemko, D. Slemp, C. Slessor, J. Sloan, M. Sloan, K. Slotwinski, J. Sloychuk, W. Slunt, S. Slywka, P. Smart, R. Smart, J. Smid, S. Smiegielski, S. Smigelski, B. Smith, C. Smith, D. Smith, E. Smith, F. Smith, G. Smith, J. Smith, K. Smith, L. Smith, M. Smith, R. Smith, S. Smith, T. Smith, C. Smitham, E. Smolyaninova, A. Smyl, K. Smyl, R. Smyl, B. Smylie, K. Snaden, T. Snell, G. Snider, J. Snider, J. Snow, K. Snow, R. Snow, W. Snow, J. Snowdon, D. Snyder, D. Sohlbach, D. Sokoloski, J. Soley, V. Sollid, M. Sollows, S. Soloshy, L. Somerville, R. Somji, L. Sommer, D. Soni, A. Sonpal, M. Soolagallu, T. Sopatyk, G. Sopczak, H. Sorensen, L. Soriano, I. Soro, C. Sorochan, D. Soroko, M. Soucy, R. Soucy, J. Soulis, L. Soutar, H. Sow, D. Spagrud, E. Spagrud, D. Spanics, E. Spearman, G. Speer, L. Speer, C. Spencer, D. Spencer, S. Spencer, B. Spendiff, D. Spetz, J. Spetz, K. Spiker, J. Springer, M. Sprinkle, A. Spurrell, D. Spurrell, E. Spurrell, R. Spurrell, P. Spurvey, L. Squire, R. Sran, E. St Pierre, F. St. Goddard, R. St. Martin, E. St. Pierre, L. St. Pierre, M. St. Pierre, B. St.Jean, R. St.Pierre, L. Staats, A. Stacey, J. Stacey, I. Stacey- Salmon, G. Stadnichuk, S. Stadnichuk, S. Stadnyk, K. Stagg, M. Stainthorpe, K. Stairs, R. Stamp, R. Stanford, C. Stang, R. Stanger, A. Stanley, J. Stanley, L. Stark, D. Staszewski, S. Stauth, A. Stavropoulos, E. Stearns, M. Stec, D. Steele, R. Steele, B. Steeves, L. Steeves, G. Stefan, S. Stefan, T. Stefansson, W. Steffen, M. Stein, H. Steinbach, J. Steinkey, S. Steinkey, A. Stella, R. Stelten, D. Stemmann, P. Stephen, R. Stephens, T. Stephens, K. Stephenson, G. Stevens, J. Stevens, L. Stevens, N. Stevens, A. Stevens-Dicks, H. Stevenson, J. Stevenson, N. Stevenson, R. Stevenson, R. Steward, C. Stewart, D. Stewart, I. Stewart, J. Stewart, K. Stewart, L. Stewart, M. Stewart, R. Stewart, W. Stewart, R. Stieben, M. Stiefel, D. Stinn, S. Stirling, M. Stobart, D. Stobbe, J. Stober, M. Stockes, M. Stockton, S. Stokes, T. Stolz, M. Stordahl, J. Storey, B. Stortz, D. Stout, R. Stoutenberg, S. Strachan, W. Strand, J. Strandquist, D. Strang, R. Strang, N. Strantz, B. Stratichuk, M. Street, S. Street, R. Stretch, W. Stretch, R. Striegler, J. Strilchuk, M. Stroh, J. Strong, R. Strong, G. Stroud, K. Struck, R. Struski, J. Struthers, D. Strynadka, L. Stuart, P. Stuart, G. Stuber, R. Stuckless, C. Study, J. Stuebing, P. Sturgeon, D. Sturrock, A. Styles, M. Styles, P. Su, M. Suarez, V. Subasic, R. Subramaniam, S. Suche, R. Sukkel, J. Sullivan, M. Sullivan, N. Sullivan, C. Summers, E. Summers, T. Sun, U. Sundaram, P. Sundaravadivelu, C. Surgenor, R. Suriyanarayanan, G. Surugiu, D. Sutherland, K. Sutherland, L. Sutherland, S. Sutherland, C. Suttie, B. Sutton, S. Sverdahl, T. Svoboda, S. Swain, D. Swan, M. Swan, J. Swannack, J. Swanson, W. Swanson, R. Swarnkar, S. Sweetapple, N. Swennumson, D. Swiegocki, E. Switzer, A. Sychak, K. Sydorko, D. Syed, J. Sykes, T. Sylvester, D. Sylvestre, G. Sylvestre, T. Sypher-Michel, N. Szalay, E. Szeto, C. Szmata, C. Szpecht, D. Sztym, K. Szydlik, J. Ta, M. Tade, A. Taghipour, A. Taguinod, P. Taiani, D. Tainton, D. Tait, G. Tait, O. Tait, D. Tajiri, D. Takala, S. Takala, G. Talati, S. Talati, D. Talbot, M. Talerico, D. Tallas, B. Talma, K. Tam, N. Taman, B. Tan, C. Tan, K. Tan, M. Tanasescu, E. Tang, L. Tang, X. Tang, G. Tangonan, T. Tanigami, M. Tapley, C. Tarache, A. Tarasenco, C. Tardif, G. Tarditi, K. Targett, B. Tarkowski, K. Tarkowski, R. Taron, H. Tarraf, D. Tarrant, J. Tatarin, J. Taubert, N. Tavassoli, A. Taylor, B. Taylor, C. Taylor, G. Taylor, H. Taylor, J. Taylor, K. Taylor, L. Taylor, M. Taylor, N. Taylor, P. Taylor, R. Taylor, S. Taylor, M. Teeple, S. Tejpar, M. Teleptean, B. Temesgen, G. Temple, J. Temple, C. Templeton, K. Tenney, J. Teppin, G. Teske, W. Tetachuk, C. Tetreau, J. Tettensor, B. Tetz, J. Tetz, S. Tetz, F. Thaddaues, L. Thai, T. Tham, C. Thatcher, G. Theriault, M. Theroux, G. Therriault, R. Thibodeau, J. Thiessen, W. Thijs, P. Thimaiah, S. Thind, K. Thistleton, M. Thoen, E. Thomas, I. Thomas, L. Thomas, N. Thomas, P. Thomas, J. Thomas Cotton, A. Thompson, C. Thompson, D. Thompson, E. Thompson, H. Thompson, I. Thompson, J. Thompson, L. Thompson, M. Thompson, R. Thompson, S. Thompson, T. Thompson, J. Thomsen, P. Thomsen, A. Thomson, J. Thomson, K. Thomson, T. Thomson, W. Thomson, J. Thorleifson, D. Thorne, K. Thorne, L. Thorne, A. Thornton, E. Thornton, K. Thornton, N. Thorp, D. Thurman, M. Thyer, S. Tieh, P. Tieu, V. Tiffen, B. Tiffin, D. Tillapaugh, M. Tilley, K. Tillotson, T. Tillotson, D. Timms, S. Timothy, N. Tindall, M. Tineo, D. Tipper, D. Tiwary, R. Tiwary, E. To, B. Tobin, V. Tobin, K. Tobler, B. Todd, C. Todd, N. Tolley, D. Tomar, R. Tomiak, C. Tomlinson, D. Tomlinson, A. Tomszak, N. Tomte, M. Tonon, S. Tookey, V. Topacio, S. Topolnitsky, K. Tordon, P. Torrance, N. Torres, D. Torriero, M. Tosio, L. Tough, D. Toullelan, O. Tozser, C. Tran, R. Trant, L. Trautman, M. Travers, J. Trelinski, W. Trelinski, J. Treliving, E. Tremblay, J. Tremblay, C. Tremblett, D. Trentham, M. Tribiger, J. Trieu-Ly, J. Trifaux, P. Trifaux, A. Trinh, D. Trinh, J. Trinier, J. Trto, R. Trudel, A. Truefitt, A. Truong, S. Truong, C. Tse, Y. Tse, G. Tsemenko, M. Tsineli, P. Tso, Y. Tu, R. Tucker, C. Tuffs, A. Tuico, D. Tuite, J. Tuite, S. Tulan, N. Tulloch, B. Tumbach, T. Turbide, J. Turcotte, T. Turgeon, R. Turnbull, B. Turner, C. Turner, D. Turner, J. Turner, K. Turner, R. Turner, B. Turpin, D. Turpin, V. Turska, S. Turton, S. Tutkaluk, S. Tuttle, I. Tutto, W. Twin, T. Twist, M. Twomey, O. Tyan, A. Tyler, E. Tylosky, L. Tymchuk, W. Tymchuk, D. Tymchyna, D. Tyner, S. Tyrell, P. Tyrer, S. Udupa, D. Uduwara Merennage, L. Uhrich, T. Uhrich, S. Ulloa, E. Ulrich, G. Ulrich, J. Umali, O. Umana, U. Umoh, K. Underwood, N. Underwood, R. Underwood, T. Ung, K. Unger, B. Unrath, J. Unrau, H. Unruh, U. Upadhyaya, C. Upham, D. Urban, J. Urbankowska, L. Urbina, J. Urdaneta, C. Urlacher, A. Ustariz, R. Vachon, S. Vadnai, A. Valentine, D. Valin, T. Valin, G. Valiquette, L. Vallee, M. Vallee, W. Vallee, A. Valmadrid, C. Valois, W. Van den Oever, M. van der Burgh, V. Van Der Merwe, B. van Dyke, N. Van Dyke, P. van Eerde, L. van Heerden, S. Van Jaarsveld, C. van Niekerk, S. Van Rensburg, C. Van Schoor, C. Vanberg, M. Vanberg, J. Vandeligt, R. Vandemark, T. Vandemark, C. Vare, L. Varela Avendano, M. Varga, D. Varty, A. Vasquez, M. Vasquez-Placid, J. Vasseur, R. Vaudan, A. Vaughan, J. Veale, S. Vekved, B. Velagapudi, M. Velez, B. Velichka, S. Venkatesh, R. Venn, D. Venning, J. Vera, D. Verbicky, N. Veriotes, A. Verma, S. Veroba, J. Verot, N. Vetrici, K. Veysey, J. Vezina, C. Viana, G. Vibert, J. Vicic, S. Vicic, N. Vick, B. Vickery, R. Villanueva, J. Villemaire, P. Villeneuve, R. Vinkle, R. Vinnakota, B. Vinoly, J. Virtanen, G. Virus, K. Virus, C. Visan, A. Visotto, D. Vitali, N. Vizcuna Alvarado, M. Vogan, R. Volkmann, J. Vollman, W. Volschenk, E. von Hertzberg, L. Vondermuhll, B. Von-Grat, A. Voth, A. Votta, A. Vredegoor, J. Vrolson, N. Vucic, J. Vuong, Q. Vuong, B. Vye, G. Wack, E. Waddell, K. Waddell, C. Wadden, K. Waddy, J. Wade, T. Waggoner, T. Wagil, C. Wagner, D. Wagner, G. Wagner, J. Wagner, K. Wagner, M. Wahl, D. Wakaruk, A. Walchuk, D. Waldner, D. Waldo, D. Walker, G. Walker, H. Walker, J. Walker, S. Walker, T. Walker, K. Walko, D. Wall, B. Wallace, C. Wallace, E. Wallace, H. Wallace, K. Wallace, G. Wallin, N. Wallin, M. Wallis, V. Wallwork, A. Walsh, B. Walsh, P. Walsh, R. Walsh, T. Walsh, L. Walter, C. Walters, S. Walton, D. Wanchuk, C. Wang, H. Wang, J. Wang, L. Wang, R. Wang, S. Wang, T. Wang, W. Wang, X. Wang, Y. Wang, B. Wangler, D. Wannas, T. Warburton, D. Ward, E. Ward, K. Ward, W. Warholik, C. Wark, W. Warman, F. Warraich, G. Warren, J. Warren, R. Warren, P. Wassell, C. Wasylciw, L. Wasylciw, L. Watchorn, J. Waterfield, M. Waterfield, J. Watkins, C. Watson, D. Watson, E. Watson, G. Watson, J. Watson, K. Watson, S. Watson, D. Watt, G. Watt, J. Watts, D. Weatherby, C. Weatherhead, H. Weaver, L. Weaving, A. Webb, B. Webb, G. Webb, P. Webb, D. Webber, J. Webber, D. Weber, J. Webster, K. Webster, D. Weed, M. Weekes, E. Weening, E. Weenink, B. Wegenast, B. Wei, Z. Wei, J. Weibrecht, J. Weigl, J. Weik, D. Weimer, C. Weingarten, J. Weir, R. Weir, G. Weisbeck, R. Weisbrot, M. Weishaar, C. Weiss, D. Welch, T. Welland, B. Wellman, C. Wells, D. Wells, R. Wells, J. Welsh, W. Welte, G. Welwood, Z. Wen, G. Weng, M. Wenger, P. Wenger, J. Wenisch, M. Wenner, K. Wenzel, D. Werle, C. Werner, H. Werner, C. Werstiuk, N. Wert, B. Weslake, D. West, M. Westad, D. Westbrook, R. Westbrook, K. Westland, R. Westland, B. Wetthuhn, N. Whalen, D. Wheating, L. Wheating, C. Wheaton, J. Wheaton, A. Wheeler, N. Wheeler, S. Wheeler, C. Whelan, M. Whelan, R. Whelan, R. Whelan-Maloney, G. Whelen, M. Whelen, S. Whelen, J. Whidden, B. White, F. White, J. White, M. White, D. Whitehouse, S. Whiteley, A. Whiteside, C. Whitford, H. Whitmore, M. Whittaker, A. Whitten, H. Whitten, H. Whynot, R. Whyte, A. Wickins, C. Wickwire, D. Wiebe, M. Wiebe, T. Wiebe, D. Wiege, T. Wielgus, D. Wiens, S. Wiens, C. Wietzel, Z. Wigglesworth, S. Wight, S. Wightman, D. Wijesingha, M. Wilcox, B. Wild, R. Wild, D. Wilde, L. Wilde, E. Wildeman, M. Wilders, J. Wilding, D. Wiles, J. Wilhelm, C. Wilk, T. Wilk, C. Wilkes, M. Wilkie, C. Wilkin, D. Wilkins, K. Wilkinson, P. Will, E. Willard, B. Willburn, B. Willcott, B. Williams, C. Williams, D. Williams, G. Williams, L. Williams, M. Williams, N. Williams, R. Williams, S. Williams, W. Williams, A. Williamson, C. Williamson, D. Williamson, K. Williamson, M. Williamson, J. Willick, M. Willis, R. Willis, D. Willms, S. Wills, C. Willson, D. Willson, C. Wilson, D. Wilson, G. Wilson, J. Wilson, M. Wilson, R. Wilson, W. Wilson, J. Wilton, S. Wilton, L. Wilyman, A. Winfield, A. Wingert, J. Winia, B. Winiarz, J. Winquist, R. Winslow, C. Winsor, J. Winsor, A. Winter, G. Winters, R. Winters, G. Wirachowsky, J. Wirachowsky, T. Wire, R. Wirtanen, P. Wiseman, I. Wishart, M. Witmer, Z. Witt, B. Wittenborn, D. Wittman, C. Wlad, A. Wocknitz, K. Woidak, D. Woitas, T. Woitte, R. Wojtowicz, D. Wold, S. Wolf, C. Woloshyn, J. Wolstenholme, B. Wolstoncroft, J. Wolter, R. Wolters, A. Wong, J. Wong, L. Wong, N. Wong, C. Woo, J. Woo, K. Woo, L. Woo, L. Wood, P. Wood, R. Wood, S. Wood, M. Woodfin, F. Woodford, S. Woodford, T. Woodford, A. Woodger, D. Woods, J. Woods, M. Woods, S. Woods, T. Woods, M. Woodske, J. Wooldridge, S. Woolfitt, R. Woolner, M. Woroniuk, C. Worthman, H. Wossey Ogandaga Mbourou, B. Wright, L. Wright, R. Wright, S. Wright, G. Wrinn, T. Wruth, B. Wu, J. Wu, M. Wu, J. Wurzer, K. Wutzke, B. Wychopen, G. Wyndham, D. Wyshynski, L. Wysocki, Y. Xia, Y. Xie, H. Xu, J. Xu, Q. Xu, Y. Xu, Z. Xu, D. Yackel, K. Yakimowich, L. Yakiwchuk, C. Yang, D. Yang, J. Yang, L. Yang, X. Yang, M. Yanota, A. Yaremko, K. Yaremko, R. Yarmuch, J. Yaroslawsky, S. Yasin, B. Yeboue, B. Yee, G. Yee, R. Yee, C. Yeoman, D. Yep, J. Yeske, J. Yip, K. Yip, L. Yip, L. Yogasundaram, I. Yohanna, F. Yohannes, D. York, F. York, A. Yoshikawa, D. Youck, B. Young, C. Young, D. Young, K. Young, L. Young, M. Young, N. Young, P. Young, V. Young, R. Yowney, M. Yu, P. Yuan, D. Yuill, J. Yuill, R. Yuristy, R. Zabek, A. Zacharias, T. Zachoda, C. Zackowski, J. Zaderey, N. Zaderey, E. Zahacy, D. Zahara, K. Zahara, A. Zahorszky, B. Zaitsoff, S. Zakeri, D. Zambrano Suarez, C. Zaparyniuk, D. Zarowny, K. Zarowny, K. Zayac, T. Zeiser, D. Zelman, B. Zeng, A. Zenide, W. Zeniuk, G. Zeran, J. Zerpa, K. Zerr, M. Zerr, S. Zgurski, J. Zhang, M. Zhang, Q. Zhang, W. Zhang, X. Zhang, Y. Zhang, B. Zhao, C. Zhao, L. Zhao, T. Zhao, M. Zhekov, G. Zheng, S. Zheng, Z. Zheng, H. Zhou, Q. Zhou, X. Zhou, L. Zhu, W. Zhu, E. Zhuromsky, S. Ziadeh, B. Ziegler, D. Zilinski, E. Zilinski, E. Zimmer, M. Zisi, M. Zoladz, C. Zoller, L. Zseder, G. Zubiak, A. Zubot, J. Zuk, N. Zukiwski, J. Zur, J. Zwolak 11 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.YEAR-END RESERVES DETERMINATION OF RESERVES For the year ended December 31, 2015 the Company retained Independent Qualified Reserves Evaluators, Sproule Associates Limited, Sproule International Limited and GLJ Petroleum Consultants Ltd., 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, bitumen, natural gas and NGL 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”). The reserves disclosure is presented in accordance with NI 51-101 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. All reserve values are Company Gross unless stated otherwise. Corporate Total ■■ Proved developed producing ("PDP") reserve additions and revisions, including acquisitions and dispositions, were 468 million barrels of crude oil, SCO, bitumen and NGL and 527 billion cubic feet of natural gas. The total proved developed producing reserves replacement ratio was 179%. The total proved developed producing reserve life index is 14.5 years. ■■ Proved crude oil, SCO, bitumen and NGL reserves increased 4% to 4.70 billion barrels. Proved natural gas reserves increased 2% to 6.11 Tcf. Total proved reserves increased 4% to 5.71 billion BOE. ■■ Proved plus probable crude oil, SCO, bitumen and NGL reserves increased 1% to 7.62 billion barrels. Proved plus probable natural gas reserves increased 5% to 8.51 Tcf. Total proved plus probable reserves increased 2% to 9.04 billion BOE. ■■ Proved reserve additions and revisions, including acquisitions and dispositions, were 390 million barrels of crude oil, SCO, bitumen and NGL and 735 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio was 165%. The total proved BOE reserve life index is 21.5 years. ■■ Proved plus probable reserve additions and revisions, including acquisitions and dispositions, were 294 million barrels of crude oil, bitumen, SCO and NGL and 1.0 trillion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 148%. The total proved plus probable BOE reserve life index is 34.0 years. ■■ Proved undeveloped crude oil, SCO, bitumen and NGL reserves accounted for 25% of the corporate total proved reserves and proved undeveloped natural gas reserves accounted for 6% of the corporate total proved reserves. North America Exploration and Production ■■ Proved crude oil, bitumen and NGL reserves decreased 1% to 2.04 billion barrels. Proved natural gas reserves increased 3% to 6.04 Tcf. Total proved BOE increased slightly from 3.03 billion barrels to 3.05 billion barrels. ■■ Proved plus probable crude oil, bitumen and NGL reserves increased 2% to 3.56 billion barrels. Proved plus probable natural gas reserves increased 5% to 8.34 Tcf. Total proved plus probable BOE increased 3% to 4.95 billion barrels. ■■ Proved reserve additions and revisions, including acquisitions and dispositions, were 132 million barrels of crude oil, bitumen and NGL and 776 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio is 106%. The total proved BOE reserve life index in 14.5 years. ■■ Proved plus probable reserve additions and revisions, including acquisitions and dispositions, were 225 million barrels of crude oil, bitumen and NGL and 1,019 billion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 160%. The total proved plus probable BOE reserve life index is 23.6 years. North America Oil Sands Mining and Upgrading ■■ Proved SCO reserves increased 12% to 2.41 billion barrels, primarily due to a revised mine plan allowing mining to a Total Volume : Bitumen In Place (“TV:BIP”) of 13 versus 12 in the original plan. International Exploration and Production ■■ North Sea proved reserves decreased 24% to 165 million BOE. North Sea proved plus probable reserves decreased 8% to 300 million BOE. ■■ Offshore Africa proved reserves decreased 9% to 95 million BOE. Offshore Africa proved plus probable reserves decreased 7% to 154 million BOE. 12 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.SUMMARY OF COMPANY GROSS RESERVES As of December 31, 2015 Forecast Prices and Costs Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) North America Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable North Sea Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Offshore Africa Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Total Company Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable 102 8 28 138 54 192 3 21 134 158 126 284 50 1 39 90 52 142 155 30 201 386 232 618 112 20 81 213 81 294 222 4 42 268 120 388 351 – 874 1,225 1,182 2,407 2,283 – 125 2,408 1,225 3,633 3,848 270 1,920 6,038 2,300 8,338 99 6 90 195 88 283 3,810 83 1,560 5,453 3,134 8,587 26 9 4 39 57 96 22 – 7 29 45 74 7 23 135 165 135 300 54 1 40 95 59 154 112 20 81 213 81 294 222 4 42 268 120 388 351 – 874 1,225 1,182 2,407 2,283 – 125 2,408 1,225 3,633 3,896 279 1,931 6,106 2,402 8,508 99 6 90 195 88 283 3,871 107 1,735 5,713 3,328 9,041 13 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.  Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) 90 7 25 122 45 167 3 21 134 158 126 284 43 – 31 74 39 113 136 28 190 354 210 564 96 16 69 181 66 247 168 3 33 204 82 286 276 – 700 976 908 1,884 1,926 – 87 2,013 993 3,006 3,495 239 1,649 5,383 1,978 7,361 73 5 71 149 67 216 3,211 71 1,260 4,542 2,491 7,033 26 9 4 39 57 96 15 – 6 21 29 50 7 22 135 164 136 300 46 – 32 78 43 121 96 16 69 181 66 247 168 3 33 204 82 286 276 – 700 976 908 1,884 1,926 – 87 2,013 993 3,006 3,536 248 1,659 5,443 2,064 7,507 73 5 71 149 67 216 3,264 93 1,427 4,784 2,670 7,454 SUMMARY OF COMPANY NET RESERVES As of December 31, 2015 Forecast Prices and Costs North America Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable North Sea Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Offshore Africa Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Total Company Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable 14 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. RECONCILIATION OF COMPANY GROSS RESERVES As of December 31, 2015 Forecast Prices and Costs PROVED North America December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 North Sea December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 Offshore Africa December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 Total Company December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) 145 1 1 4 – 5 (3) (6) 10 (19) 138 204 – – – – – – (2) (36) (8) 158 96 – – – – – – 1 – (7) 90 445 1 1 4 – 5 (3) (7) (26) (34) 386 229 – 4 10 – 4 – (3) 16 (47) 213 274 – – – 2 – – – 10 (18) 268 1,217 – 23 – 26 7 – – (1) (47) 1,225 2,158 – 220 – – – – 7 68 (45) 2,408 5,869 14 252 298 – 414 (7) (385) 190 (607) 6,038 188 2 10 7 – 8 – (6) 1 (15) 195 83 – – – – – – (7) (24) (13) 39 49 – – – – – – – (10) (10) 29 229 – 4 10 – 4 – (3) 16 (47) 213 274 – – – 2 – – – 10 (18) 268 1,217 – 23 – 26 7 – – (1) (47) 1,225 2,158 – 220 – – – – 7 68 (45) 2,408 6,001 14 252 298 – 414 (7) (392) 156 (630) 6,106 188 2 10 7 – 8 – (6) 1 (15) 195 5,189 5 300 71 28 93 (4) (72) 135 (292) 5,453 218 – – – – – – (3) (40) (10) 165 104 – – – – – – 1 (1) (9) 95 5,511 5 300 71 28 93 (4) (74) 94 (311) 5,713 15 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. RECONCILIATION OF COMPANY GROSS RESERVES As of December 31, 2015 Forecast Prices and Costs PROBABLE North America December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 North Sea December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 Offshore Africa December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 Total Company December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 16 Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) 58 – 1 4 – 1 (2) – (8) – 54 104 – – – – – – – 22 – 126 53 – – – – – – (1) – 52 215 – 1 4 – 1 (2) (1) 14 – 232 88 – 2 3 – 1 – – (13) – 81 121 – – – 1 – – – (2) – 120 1,095 – 88 – 14 2 – – (17) – 1,182 1,435 – (175) – – – – – (35) – 1,225 2,057 3 106 444 1 101 (2) (117) (293) – 2,300 31 – – – – – – 7 19 – 57 49 – – – – – – 1 (5) – 45 88 – 2 3 – 1 – – (13) – 81 121 – – – 1 – – – (2) – 120 1,095 – 88 – 14 2 – – (17) – 1,182 1,435 – (175) – – – – – (35) – 1,225 2,137 3 106 444 1 101 (2) (109) (279) – 2,402 70 – 5 22 – 2 – (2) (9) – 88 70 – 5 22 – 2 – (2) (9) – 88 3,210 1 (61) 103 15 23 (3) (22) (132) – 3,134 109 – – – – – – 1 25 – 135 61 – – – – – – (1) (1) – 59 3,380 1 (61) 103 15 23 (3) (22) (108) – 3,328 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. RECONCILIATION OF COMPANY GROSS RESERVES As of December 31, 2015 Forecast Prices and Costs PROVED PLUS PROBABLE Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) North America December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 North Sea December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 Offshore Africa December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 Total Company December 31, 2014 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 203 1 2 8 – 6 (5) (6) 2 (19) 192 308 – – – – – – (2) (14) (8) 284 149 – – – – – – – – (7) 142 660 1 2 8 – 6 (5) (8) (12) (34) 618 317 – 6 13 – 5 – (3) 3 (47) 294 395 – – – 3 – – – 8 (18) 388 2,312 – 111 – 40 9 – – (18) (47) 2,407 3,593 – 45 – – – – 7 33 (45) 3,633 7,926 17 358 742 1 515 (9) (502) (103) (607) 8,338 258 2 15 29 – 10 – (8) (8) (15) 283 114 – – – – – – – (5) (13) 96 98 – – – – – – 1 (15) (10) 74 317 – 6 13 – 5 – (3) 3 (47) 294 395 – – – 3 – – – 8 (18) 388 2,312 – 111 – 40 9 – – (18) (47) 2,407 3,593 – 45 – – – – 7 33 (45) 3,633 8,138 17 358 742 1 515 (9) (501) (123) (630) 8,508 258 2 15 29 – 10 – (8) (8) (15) 283 8,399 6 239 174 43 116 (7) (94) 3 (292) 8,587 327 – – – – – – (2) (15) (10) 300 165 – – – – – – – (2) (9) 154 8,891 6 239 174 43 116 (7) (96) (14) (311) 9,041 17 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. RESERVES NOTES: (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) BOE values may not calculate due to rounding. (4) Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserve estimates were provided by Sproule Associates Limited: Average annual increase Crude oil and NGL WTI at Cushing (US$/bbl) Western Canada Select (C$/bbl) Canadian Light Sweet (C$/bbl) Cromer LSB (C$/bbl) Edmonton Pentanes+ (C$/bbl) North Sea Brent (US$/bbl) Natural gas AECO (C$/MMBtu) BC Westcoast Station 2 (C$/MMBtu) Henry Hub Louisiana (US$/MMBtu) 2016 2017 2018 2019 2020 thereafter $ $ $ $ $ $ $ $ $ 45.00 $ 60.00 $ 70.00 $ 80.00 $ 45.26 $ 57.96 $ 65.88 $ 75.11 $ 55.20 $ 69.00 $ 78.43 $ 89.41 $ 54.20 $ 68.00 $ 77.43 $ 88.41 $ 59.10 $ 73.88 $ 83.98 $ 95.73 $ 45.00 $ 60.00 $ 70.00 $ 80.00 $ 2.25 $ 1.45 $ 2.25 $ 2.95 $ 2.55 $ 3.00 $ 3.42 $ 3.02 $ 3.50 $ 3.91 $ 3.51 $ 4.00 $ 81.20 77.03 91.71 90.71 98.19 81.20 4.20 3.80 4.25 1.50% 1.50% 1.50% 1.50% 1.50% 1.50% 1.50% 1.50% 1.50% A foreign exchange rate of 0.7500 US$/C$ for 2016, 0.8000 US$/C$ for 2017, 0.8300 US$/C$ for 2018 and 0.8500 US$/C$ after 2018 was used in the 2015 evaluation. (5) Reserve additions and revisions are comprised of all categories of Company Gross reserve changes, exclusive of production. (6) Reserve replacement ratio is the Company Gross reserve additions and revisions, for the relevant reserve category, divided by the Company Gross production in the same period. (7) Reserve Life Index is based on the amount for the relevant reserve category divided by the 2016 proved developed producing production forecast prepared by the Independent Qualified Reserve Evaluators. (8) Finding, Development and Acquisition (FD&A) costs are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2015 by the sum of total additions and revisions for the relevant reserve category. (9) FD&A costs including change in Future Development Capital (FDC) are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2015 and net change in FDC from December 31, 2014 to December 31, 2015 by the sum of total additions and revisions for the relevant reserve category. FDC excludes all abandonment and reclamation costs. (10) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. 18 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. This page left intentionally blank. 19 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.MANAGEMENT’S DISCUSSION AND ANALYSIS SPECIAL NOTE REGARDING 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”, “proposed” 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, 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 operations and future expansions, Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the construction and future operations of the North West Redwater bitumen upgrader and refinery, and construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas or synthetic crude oil (“SCO”) that the Company may be reliant upon to transport its products to market, and the “Outlook” section of this MD&A, particularly in reference to the 2016 guidance provided with respect to budgeted capital expenditures, 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 and proved plus probable crude oil, natural gas and natural gas liquids (“NGLs”) 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 disruptions or delays in the resumption of the mining, extracting or upgrading of 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 and in mining, extracting or upgrading the Company’s bitumen products; availability and cost of financing; the Company’s and its subsidiaries’ success of exploration and development activities and its 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, natural gas and 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 20 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.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. For additional information, refer to the “Risks and Uncertainties” section of this MD&A. 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, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or Management’s estimates or opinions change. SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES 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, adjusted cash production costs and net asset value. These financial measures are not defined by International Financial Reporting Standards (“IFRS”) 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 IFRS, 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 (loss), as determined in accordance with IFRS, in the “Net Earnings (Loss) and Cash Flow from Operations” section of this MD&A. The derivation of adjusted cash production costs and adjusted depreciation, depletion and amortization are 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. MANAGEMENT’S DISCUSSION AND ANALYSIS This MD&A of the financial condition and results of operations of the Company should be read in conjunction with the Company’s audited consolidated financial statements and related notes for the year ended December 31, 2015. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company’s consolidated financial statements and this MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (“IASB”). A Barrel of Oil Equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic crude oil. Production volumes and per unit statistics are presented throughout this MD&A on a “before royalty” or “gross” basis, and realized prices are net of 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 and analysis refers primarily to the Company’s 2015 financial results compared to 2014 and 2013, unless otherwise indicated. In addition, this MD&A details the Company’s capital program for 2016. Additional information relating to the Company, including its quarterly MD&A for the year and three months ended December 31, 2015, its Annual Information Form for the year ended December 31, 2015, and its audited consolidated financial statements for the year ended December 31, 2015 is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. This MD&A is dated March 2, 2016. 21 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.DEFINITIONS AND ABBREVIATIONS AECO Alberta natural gas reference location AIF API ARO bbl bbl/d Bcf Bcf/d BOE BOE/d Bitumen Brent C$ CAGR CAPEX CO2 CO2e Crude oil CSS EOR E&P FPSO GHG GJ GJ/d Annual Information Form specific gravity measured in degrees on the American Petroleum Institute scale asset retirement obligations barrel barrels per day billion cubic feet billion cubic feet per day barrels of oil equivalent barrels of oil equivalent per day solid or semi-solid viscous mixture consisting mainly of pentanes and heavier hydrocarbons with viscosity greater than 10,000 centipoise Dated Brent Canadian dollars compound annual growth rate capital expenditures carbon dioxide carbon dioxide equivalents includes light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic crude oil Cyclic Steam Stimulation Enhanced Oil Recovery Exploration and Production Floating Production, Storage and Offloading Vessel greenhouse gas gigajoules gigajoules per day Horizon Horizon Oil Sands IASB IFRS LIBOR International Accounting Standards Board International Financial Reporting Standards London Interbank Offered Rate Mbbl Mbbl/d MBOE thousand barrels thousand barrels per day thousand barrels of oil equivalent MBOE/d thousand barrels of oil equivalent per day Mcf Mcfe Mcf/d MMbbl MMBOE MMBtu MMcf thousand cubic feet thousands of cubic feet equivalent thousand cubic feet per day million barrels million barrels of oil equivalent million British thermal units million cubic feet MMcf/d million cubic feet per day NGLs natural gas liquids NYMEX New York Mercantile Exchange NYSE PRT SAGD SCO SEC Tcf TSX UK US New York Stock Exchange Petroleum Revenue Tax Steam-Assisted Gravity Drainage synthetic crude oil United States Securities and Exchange Commission trillion cubic feet Toronto Stock Exchange United Kingdom United States US GAAP generally accepted accounting principles in the United States US$ WCS United States dollars Western Canadian Select WCS Heavy Differential WTI WCS Heavy Differential from WTI West Texas Intermediate reference location at Cushing, Oklahoma 22 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.OBJECTIVES AND STRATEGY The Company’s objectives are to increase crude oil and natural gas production, reserves, cash flow and net asset value (1) on a per common share basis through the development of its existing crude oil and natural gas properties and through the discovery and/or acquisition of new reserves. The Company strives to meet these objectives by having a defined growth and value enhancement plan for each of its products and segments while transitioning to a long-life, low decline asset base. The Company takes a balanced approach to growth and investments and focuses on creating long-term shareholder value. The Company allocates its capital by maintaining: ■■ Balance among its products, namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil (2), bitumen (thermal oil), SCO and natural gas; ■■ A large, balanced, diversified, high quality asset base; ■■ Balance among acquisitions, exploitation and exploration; and ■■ Balance between sources and terms of debt financing and a strong financial position. (1) Discounted value of crude oil and natural gas reserves plus value of unproved land, less net debt. (2) Pelican Lake heavy crude oil is 14–17º API oil, which receives medium quality crude netbacks due to lower production costs and lower royalty rates. The Company’s three-phase crude oil marketing strategy includes: ■■ Blending various crude oil streams with diluents to create more attractive feedstock; ■■ Supporting and participating in pipeline expansions and/or new additions; and ■■ Supporting and participating in projects that will increase the downstream conversion capacity for heavy crude oil and bitumen (thermal oil). Operational discipline, safe, effective and efficient operations as well as cost control are fundamental to the Company. By consistently managing costs throughout all cycles of the industry, the Company believes it will achieve continued growth. Effective and efficient operations and cost control are attained by developing area knowledge, and by maintaining high working interests and operator status in its properties. The Company is committed to maintaining a strong balance sheet and flexible capital structure. The Company believes it has built the necessary financial capacity to complete its growth projects. Strategic accretive acquisitions are a key component of the Company’s strategy. The Company has used a combination of internally generated cash flows and debt financing to selectively acquire properties generating future cash flows in its core areas. NET EARNINGS (LOSS) AND CASH FLOW FROM OPERATIONS FINANCIAL HIGHLIGHTS ($ millions, except per common share amounts) Product sales Net earnings (loss) Per common share – basic – diluted Adjusted net earnings from operations (1) Per common share – basic – diluted Cash flow from operations (2) Per common share – basic – diluted Dividends declared per common share (3) Total assets Total long-term liabilities Capital expenditures, net of dispositions 2015 2014 2013 13,167 $ 21,301 $ 17,945 (637) $ 3,929 $ 2,270 (0.58) $ (0.58) $ 3.60 $ 3.58 $ 2.08 2.08 263 $ 3,811 $ 2,435 0.24 $ 0.24 $ 3.49 $ 3.47 $ 2.24 2.23 5,785 $ 9,587 $ 7,477 5.29 $ 5.28 $ 0.92 $ 8.78 $ 8.74 $ 6.87 6.86 0.90 $ 0.575 59,275 $ 60,200 $ 51,754 27,299 $ 26,167 $ 20,748 3,853 $ 11,744 $ 7,274 $ $ $ $ $ $ $ $ $ $ $ $ $ $ (1) Adjusted net earnings from operations is a non-GAAP measure that represents net earnings (loss) 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” presents 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. (2) Cash flow from operations is a non-GAAP measure that represents net earnings (loss) 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” presents 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. (3) On March 2, 2016, the Board of Directors declared a quarterly dividend of $0.23 per common share, beginning with the dividend payable on April 1, 2016. In 2015, the Board of Directors declared a quarterly dividend of $0.23 per common share, beginning with the dividend payable on April 1, 2015. In 2014, the Board of Directors approved a quarterly dividend of $0.225 per common share, beginning with the dividend payable on April 1, 2014. In 2013, the Board of Directors approved a dividend of $0.20 per common share on November 5, 2013, beginning with the dividend payable on January 1, 2014 ($0.125 per common share, approved on March 6, 2013, beginning with the dividend payable on April 1, 2013). 23 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. Adjusted Net Earnings from Operations ($ millions) Net earnings (loss) Share-based compensation, net of tax (1) Unrealized risk management loss (gain), net of tax (2) Unrealized foreign exchange loss, net of tax (3) Realized foreign exchange loss (gain) on repayment of US dollar debt securities, net of tax (4) Loss from investments, net of tax (5) (6) Gains on disposition of properties and corporate acquisitions, net of tax (7) Derecognition of exploration and evaluation assets, net of tax (8) Effect of statutory tax rate and other legislative changes on deferred income tax liabilities (9) Adjusted net earnings from operations 2015 2014 $ (637) $ 3,929 $ (46) 275 858 – 55 (663) 70 351 66 (339) 256 36 – (137) – – 2013 2,270 135 32 226 (12) – (231) – 15 $ 263 $ 3,811 $ 2,435 (1) The Company’s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a liability on the Company’s balance sheets and periodic changes in the fair value are recognized in net earnings (loss) or are capitalized to Oil Sands Mining and Upgrading construction costs. (2) Derivative financial instruments are recorded at fair value on the Company’s balance sheets, with changes in the 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, natural gas and foreign exchange. (3) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings (loss). (4) During 2014, the Company repaid US$500 million of 1.45% debt securities and US$350 million of 4.90% debt securities. During 2013, the Company repaid US$400 million of 5.15% debt securities. (5) The Company’s investment in the 50% owned North West Redwater Partnership (“Redwater Partnership”) is accounted for using the equity method of accounting. Included in the non-cash loss from investments is the Company’s pro-rata share of the Redwater Partnership’s accounting loss. (6) The Company’s investment in PrairieSky Royalty Ltd. (“PrairieSky”) has been accounted for at fair value through profit and loss and is remeasured each period with changes in fair value recognized in net earnings. (7) During 2015, the Company recorded a pre-tax gain of $739 million ($663 million after-tax) related to the disposition of a number of North America royalty income assets and crude oil and natural gas properties. During 2014, the Company recorded an after-tax gain of $137 million related to the acquisition of certain producing crude oil and natural gas properties. During 2013, the Company recorded an after-tax gain of $231 million related to the acquisition of Barrick Energy Inc. and the disposition of a 50% interest in an exploration right in South Africa. (8) In connection with the Company’s notice of withdrawal from Block CI-514 in Côte d’Ivoire, Offshore Africa in 2015, the Company derecognized $96 million ($70 million after-tax) of exploration and evaluation assets through depletion, depreciation and amortization expense. (9) All substantively enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company’s balance sheets in determining deferred income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in net earnings (loss) during the period the legislation is substantively enacted. During 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12%. As a result of this income tax rate increase, the Company’s deferred income tax liability was increased by $579 million. In addition, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and the PRT, and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company’s deferred income tax liability of $228 million. During 2013, the British Columbia government substantively enacted legislation to increase its provincial corporate income tax rate, resulting in an increase in the Company’s deferred income tax liability of $15 million. Cash Flow from Operations ($ millions) Net earnings (loss) Non-cash items: Depletion, depreciation and amortization Share-based compensation Asset retirement obligation accretion Unrealized risk management loss (gain) Unrealized foreign exchange loss Realized foreign exchange loss (gain) on repayment of US dollar debt securities Loss from investments Deferred income tax expense Gains on disposition of properties and corporate acquisitions Current income tax on disposition of properties 2015 2014 $ (637) $ 3,929 $ 2013 2,270 5,483 (46) 173 374 858 – 55 231 (739) 33 4,880 4,844 66 193 (451) 256 36 8 807 (137) – 135 171 39 226 (12) 4 31 (289) 58 Cash flow from operations $ 5,785 $ 9,587 $ 7,477 For 2015, the Company reported a net loss of $637 million compared with net earnings of $3,929 million for 2014 (2013 – $2,270 million net earnings). The net loss for 2015 included net after-tax expenses of $900 million related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of realized foreign exchange losses and gains on repayment of long-term debt, loss from investments, gains on disposition of properties and corporate acquisitions, derecognition of exploration and evaluation assets and the impact of statutory tax 24 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.rate and other legislative changes on deferred income tax liabilities (2014 – $118 million after-tax income; 2013 – $165 million after-tax expenses). Excluding these items, adjusted net earnings from operations for 2015 were $263 million compared with $3,811 million for 2014 (2013 – $2,435 million). The decrease in adjusted net earnings for 2015 compared to 2014 was primarily due to: ■■ ■■ ■■ lower crude oil and NGLs netbacks in the Exploration and Production segments; lower realized SCO prices; lower natural gas netbacks in the North America segment; and ■■ higher depletion, depreciation and amortization expense; partially offset by: ■■ higher crude oil and NGLs, SCO and natural gas sales volumes across all segments; ■■ higher realized risk management gains; and ■■ the impact of a weaker Canadian dollar relative to the US dollar. The impacts of share-based compensation, risk management activities and fluctuations in foreign exchange rates are expected to continue to contribute to significant volatility in consolidated net earnings (loss) and are discussed in detail in the relevant sections of this MD&A. Cash flow from operations for 2015 decreased to $5,785 million ($5.29 per common share) from $9,587 million for 2014 ($8.78 per common share) (2013 – $7,477 million; $6.87 per common share). The decrease in cash flow from operations for 2015 from 2014 was primarily due to the factors noted above relating to the decrease in adjusted net earnings, as well as due to the impact of cash taxes. In the Company’s Exploration and Production activities, the 2015 average sales price per bbl of crude oil and NGLs decreased 47% to average $41.13 per bbl from $77.04 per bbl in 2014 (2013 – $73.81 per bbl), and the 2015 average natural gas price decreased 35% to average $3.16 per Mcf from $4.83 per Mcf in 2014 (2013 – $3.58 per Mcf). In the Oil Sands Mining and Upgrading segment, the Company’s 2015 SCO sales price decreased 39% to average $61.39 per bbl from $100.27 per bbl in 2014 (2013 – $100.75 per bbl). Total production of crude oil and NGLs before royalties increased 6% to 564,188 bbl/d from 531,194 bbl/d in 2014 (2013 – 478,240 bbl/d). The increase in crude oil and NGLs production from 2014 was primarily due to increased production in the Horizon and International segments as well as from acquisitions of producing Canadian crude oil properties in 2014. Total natural gas production before royalties increased 11% to average 1,726 MMcf/d from 1,555 MMcf/d in 2014 (2013 – 1,158 MMcf/d). The increase in natural gas production was primarily a result of the acquisitions of producing Canadian natural gas properties in 2014 and growth in production volumes in the North Sea. Total crude oil and NGLs and natural gas production volumes before royalties increased 8% to average 851,901 BOE/d from 790,410 BOE/d in 2014 (2013 – 671,162 BOE/d). SUMMARY OF QUARTERLY RESULTS The following is a summary of the Company's quarterly results for the eight most recently completed quarters: ($ millions, except per common share amounts) 2015 Product sales Net earnings (loss) Net earnings (loss) per common share – basic – diluted ($ millions, except per common share amounts) 2014 Product sales Net earnings (loss) Net earnings (loss) per common share – basic – diluted Total Dec 31 Sep 30 Jun 30 Mar 31 13,167 $ 2,963 $ 3,316 $ 3,662 $ 3,226 (637) $ 131 $ (111) $ (405) $ (252) (0.58) $ (0.58) $ 0.12 $ 0.12 $ (0.10) $ (0.37) $ (0.10) $ (0.37) $ (0.23) (0.23) Total Dec 31 Sep 30 Jun 30 Mar 31 21,301 $ 4,850 $ 5,370 $ 6,113 $ 4,968 3,929 $ 1,198 $ 1,039 $ 1,070 $ 622 3.60 $ 3.58 $ 1.10 $ 1.09 $ 0.95 $ 0.94 $ 0.98 $ 0.97 $ 0.57 0.57 $ $ $ $ $ $ $ $ 25 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.Volatility in the quarterly net earnings (loss) over the eight most recently completed quarters was primarily due to: ■■ Crude oil pricing – The impact of increased shale oil production in North America, fluctuating global supply/demand including the Organization of the Petroleum Exporting Countries’ (“OPEC”) decision not to curtail crude oil production to offset the excess world supply, the impact of geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential from WTI in North America and the impact of the differential between WTI and Brent benchmark pricing in the North Sea and Offshore Africa. ■■ Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, and the impact of increased shale gas production in the US. ■■ Crude oil and NGLs sales volumes – Fluctuations in production due to the cyclic nature of the Company’s Primrose thermal projects, production from Kirby South, the results from the Pelican Lake water and polymer flood projects, fluctuations in the Company’s drilling program in North America, the impact and timing of acquisitions, the impact of turnarounds at Horizon and higher drilling in Côte d’Ivoire in Offshore Africa. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore Africa. ■■ Natural gas sales volumes – Fluctuations in production due to the Company’s allocation of capital to higher return crude oil projects, as well as natural decline rates, shut-in natural gas production due to third party pipeline restrictions and related pricing impacts, and the impact and timing of acquisitions. ■■ Production expense – Fluctuations primarily due to the impact of the demand and cost for services, fluctuations in product mix and production, the impact of seasonal costs that are dependent on weather, cost optimizations across all segments, the impact and timing of acquisitions, and turnarounds at Horizon. ■■ Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes including the impact and timing of acquisitions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company’s proved undeveloped reserves, fluctuations in international sales volumes subject to higher depletion rates, and the impact of turnarounds at Horizon. ■■ Share-based compensation – Fluctuations due to the determination of fair market value based on the Black-Scholes valuation model of the Company’s share-based compensation liability. ■■ Risk management – Fluctuations due to commodity volumes hedged and the recognition of gains and losses from the mark to market and subsequent settlement of the Company’s risk management activities. ■■ Foreign exchange rates – Fluctuations in the Canadian dollar relative to the US dollar, which 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 realized and unrealized foreign exchange gains and losses are recorded with respect to US dollar denominated debt, partially offset by the impact of cross currency swap hedges. ■■ Income tax expense – Fluctuations in income tax expense include statutory tax rate and other legislative changes substantively enacted in the various periods. ■■ Gains on disposition of properties and corporate acquisitions – Fluctuations due to the recognition of gains on disposition of properties in the third and fourth quarters of 2015 and acquisitions in the fourth quarter of 2014. BUSINESS ENVIRONMENT (Yearly average) WTI benchmark price (US$/bbl) Dated Brent benchmark price (US$/bbl) WCS blend differential from WTI (US$/bbl) WCS blend differential from WTI (%) SCO price (US$/bbl) Condensate benchmark price (US$/bbl) NYMEX benchmark price (US$/MMBtu) AECO benchmark price (C$/GJ) US / Canadian dollar average exchange rate (US$) US / Canadian dollar year end exchange rate (US$) 2015 2014 48.76 $ 92.92 $ 2013 98.00 52.40 $ 98.85 $ 108.62 13.51 $ 19.41 $ 28% 21% 48.59 $ 91.35 $ 25.11 26% 98.18 47.34 $ 92.84 $ 101.67 2.67 $ 2.62 $ 4.37 $ 4.19 $ 3.67 3.00 0.7820 $ 0.9054 $ 0.9710 0.7225 $ 0.8620 $ 0.9402 $ $ $ $ $ $ $ $ $ Substantially all of the Company’s production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based on WTI and Brent indices. Canadian natural gas pricing is primarily based on Alberta AECO reference pricing, which is derived from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at Henry Hub. The Company’s realized prices are highly sensitive to fluctuations in foreign exchange rates. Realized prices in 2015 continued to be supported by the weak Canadian dollar, which increased the Canadian dollar sales price the Company received for its crude oil and natural gas sales, as realized pricing is based on US dollar denominated benchmarks. The average value of the Canadian dollar in relation to the US dollar fluctuated significantly throughout 2015, with a high of approximately US$0.85 in January 2015 and a low of approximately US$0.71 in December 2015. 26 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. For 2015, WTI averaged US$48.76 per bbl, a decrease of 48% from US$92.92 per bbl for 2014 (2013 – US$98.00 per bbl). Crude oil sales contracts for the Company’s North Sea and Offshore Africa segments are typically based on Brent pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$52.40 per bbl for 2015, a decrease of 47% from US$98.85 per bbl for 2014 (2013 – US$108.62 per bbl). WTI and Brent pricing continued to reflect volatility in supply and demand factors and geopolitical events. An oversupply of crude oil in the world market contributed to a significant decrease in crude oil benchmark pricing in 2015. OPEC‘s decision not to curtail crude oil production to offset the excess world supply continues to put downward pressure on benchmark pricing. The WCS Heavy Differential averaged 28% for 2015 compared with 21% for 2014 (2013 – 26%). Fluctuations in the WCS Heavy Differential reflect seasonal demand, changes in transportation logistics, and refinery utilization and shutdowns. The SCO price averaged US$48.59 per bbl in 2015, a decrease of 47% from US$91.35 per bbl for 2014 (2013 – US$98.18 per bbl). The decrease in SCO pricing for 2015 was primarily due to lower WTI benchmark pricing and the impact of industry wide unplanned upgrader outages. NYMEX natural gas prices averaged US$2.67 per MMBtu for 2015, a decrease of 39% from US$4.37 per MMBtu for 2014 (2013 – US$3.67 per MMBtu). AECO natural gas pricing averaged $2.62 per GJ for 2015, a decrease of 37% from $4.19 per GJ for 2014 (2013 – $3.00 per GJ). Natural gas prices were lower in 2015 reflecting strong natural gas production and lower demand as North America experienced warmer than normal winter temperatures in 2015. In addition, 2014 prices were higher due to lower than average storage levels in 2014 due to colder than normal winter temperatures. ANALYSIS OF CHANGES IN PRODUCT SALES ($ millions) North America Changes due to Changes due to 2013 Volumes Prices Other 2014 Volumes Prices Other 2015 Crude oil and NGLs $ 11,246 $ 1,527 $ 585 $ (26) $ 13,332 $ 402 $ (6,378) $ 96 $ 7,452 1,413 12,659 497 2,024 721 1,306 – 2,631 (26) 15,963 Natural gas North Sea Crude oil and NGLs Natural gas Offshore Africa Crude oil and NGLs Natural gas Subtotal Crude oil and NGLs Natural gas Oil Sands Mining and Upgrading Midstream Intersegment eliminations and other (1) Total 795 10 805 733 91 824 12,774 1,514 14,288 3,631 110 (84) (3) 8 5 (264) (10) (274) (37) 1 (36) (52) 12 (40) (73) – (73) (7) – (7) 682 19 701 410 93 503 1,260 495 1,755 496 734 1,230 (106) 14,424 – (106) 2,743 17,167 234 636 137 73 210 185 24 209 724 331 1,055 (1,095) (7,473) (317) 34 (283) (214) (24) (238) – 96 10 – 10 8 – 8 1,770 9,222 512 126 638 389 93 482 (6,909) (1,085) (7,994) 114 – 114 8,353 1,989 10,342 463 (20) – – – – 21 10 4,095 120 3 (81) 435 (1,749) – – – – (17) 16 2,764 136 6 (75) $ 17,945 $ 2,218 $ 1,210 $ (72) $ 21,301 $ 1,490 $ (9,743) $ 119 $ 13,167 (1) Eliminates internal transportation and electricity charges. Product sales decreased 38% to $13,167 million for 2015 from $21,301 million for 2014 (2013 – $17,945 million). The decrease was primarily due to lower realized prices, partially offset by higher crude oil and NGLs, natural gas, and SCO sales volumes in all segments. For 2015, 9% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America (2014 – 6%; 2013 – 9%). North Sea accounted for 5% of crude oil and NGLs and natural gas product sales for 2015 (2014 – 3%; 2013 – 4%), and Offshore Africa accounted for 4% of crude oil and NGLs and natural gas product sales for 2015 (2014 – 3%; 2013 – 5%). 27 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.ANALYSIS OF DAILY PRODUCTION, BEFORE ROYALTIES Crude oil and NGLs (bbl/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading (1) North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa Total barrels of oil equivalent (BOE/d) Product mix Light and medium crude oil and NGLs Pelican Lake heavy crude oil Primary heavy crude oil Bitumen (thermal oil) Synthetic crude oil (1) Natural gas Percentage of gross revenue (1) (2) (excluding Midstream revenue) Crude oil and NGLs Natural gas 2015 2014 2013 399,982 122,911 22,216 19,079 390,814 110,571 17,380 12,429 343,699 100,284 18,334 15,923 564,188 531,194 478,240 1,663 1,527 1,130 36 27 7 21 4 24 1,726 1,555 1,158 851,901 790,410 671,162 16% 6% 15% 15% 14% 34% 82% 18% 15% 6% 18% 14% 14% 33% 85% 15% 15% 7% 20% 14% 15% 29% 90% 10% (1) 2015 SCO production before royalties excludes 2,122 bbl/d of SCO consumed internally as diesel (2014 – 545 bbl/d; 2013 – nil). (2) Net of blending costs and excluding risk management activities. ANALYSIS OF DAILY PRODUCTION, NET OF ROYALTIES Crude oil and NGLs (bbl/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa Total barrels of oil equivalent (BOE/d) 2015 2014 2013 350,451 121,208 22,164 18,209 318,291 104,095 17,313 11,500 287,428 95,098 18,279 12,973 512,032 451,199 413,778 1,606 1,407 1,080 36 25 7 18 4 20 1,667 1,432 1,104 789,799 689,893 597,835 The Company’s business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO and natural gas. Total 2015 production averaged 851,901 BOE/d, an 8% increase from 790,410 BOE/d in 2014 (2013 – 671,162 BOE/d). Total production of crude oil and NGLs before royalties increased 6% to 564,188 bbl/d for 2015 from 531,194 bbl/d in 2014 (2013 – 478,240 bbl/d). The increase in crude oil and NGLs production from 2014 was primarily due to increased production in the Horizon and International segments as well as from acquisitions of producing Canadian crude oil properties in 2014. Crude oil and NGLs production for 2015 was within the Company’s previously issued guidance of 555,000 to 591,000 bbl/d. 28 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.Natural gas production continued to represent the Company’s largest product offering, accounting for 34% of the Company’s total production in 2015 on a BOE basis. Total natural gas production before royalties increased 11% to 1,726 MMcf/d for 2015 from 1,555 MMcf/d for 2014 (2013 – 1,158 MMcf/d). The increase in natural gas production from 2014 was primarily a result of acquisitions of producing Canadian natural gas properties in 2014 and growth in production volumes in the North Sea. Annual 2015 natural gas production reflected the impact of third party pipeline transportation restrictions in Northwest Alberta during the second half of 2015, including both temporary and permanent shut-ins of volumes in the fourth quarter of 2015 due to the impact of low natural gas prices resulting from these restrictions. As a result, 2015 natural gas production of 1,726 MMcf/d was slightly below the Company’s previously issued guidance of 1,730 to 1,770 MMcf/d. NORTH AMERICA – EXPLORATION AND PRODUCTION North America crude oil and NGLs production for 2015 increased 2% to average 399,982 bbl/d from 390,814 bbl/d for 2014 (2013 – 343,699 bbl/d). The increase in production from 2014 was primarily due to increased production in the Company’s thermal areas, including Kirby South, and increased production related to the acquisitions of producing Canadian crude oil properties in 2014. North America natural gas production for 2015 increased 9% to average 1,663 MMcf/d from 1,527 MMcf/d in 2014 (2013 – 1,130 MMcf/d). The increase in natural gas production from 2014 was primarily a result of acquisitions of producing Canadian natural gas properties in 2014, offset by the impact of third party transportation restrictions during the second half of 2015. NORTH AMERICA – OIL SANDS MINING AND UPGRADING SCO production for 2015 increased 11% to average 122,911 bbl/d compared with 110,571 bbl/d for 2014 (2013 – 100,284 bbl/d). Production in 2015 continued to reflect high utilization rates and reliability, following the completion of the planned turnaround during the year and the coker expansion tie-in in 2014. NORTH SEA North Sea crude oil production for 2015 was 22,216 bbl/d, an increase of 28% from 17,380 bbl/d for 2014 (2013 – 18,334 bbl/d). The increase in production from 2014 primarily reflected the reinstatement of production from both the Banff FPSO and the Tiffany platform in 2014 and the impact of planned turnarounds completed at the Ninian platforms in 2015. OFFSHORE AFRICA Offshore Africa crude oil production for 2015 increased 54% to 19,079 bbl/d from 12,429 bbl/d for 2014 (2013 – 15,923 bbl/d) primarily due to new wells on stream at both the Espoir and the Baobab fields throughout 2015, partially offset by natural field declines. In late December 2015, the Baobab field was temporarily shut-in due to a riser failure and after inspection of the riser system, production was reinstated in late January 2016. CORPORATE PRODUCTION GUIDANCE FOR 2016 The Company targets production levels in 2016 to average between 514,000 bbl/d and 563,000 bbl/d of crude oil and NGLs and between 1,770 MMcf/d and 1,830 MMcf/d of natural gas. INTERNATIONAL 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 in the International business segments on crude oil volumes that were stored in various storage facilities or FPSOs, as follows: (bbl) North Sea Offshore Africa 2015 835,806 1,271,170 2,106,976 2014 368,808 461,997 830,805 2013 385,073 185,476 570,549 29 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback Natural gas ($/Mcf) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback Barrels of oil equivalent ($/BOE) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of blending costs and excluding risk management activities. ANALYSIS OF PRODUCT PRICES – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) (2) North America North Sea Offshore Africa Company average Natural gas ($/Mcf) (1) (2) North America North Sea Offshore Africa Company average Company average ($/BOE) (1) (2) 2015 2014 2013 $ 41.13 $ 77.04 $ 73.81 2.60 38.53 4.30 15.74 2.41 74.63 12.99 18.25 2.22 71.59 11.13 17.14 18.49 $ 43.39 $ 43.32 3.16 $ 4.83 $ 0.38 2.78 0.10 1.34 0.27 4.56 0.38 1.48 1.34 $ 2.70 $ 3.58 0.28 3.30 0.18 1.42 1.70 32.60 $ 58.48 $ 56.46 $ $ $ $ 2.56 30.04 2.85 12.70 2.18 56.30 8.90 14.67 $ 14.49 $ 32.73 $ 2.10 54.36 7.74 14.24 32.38 2015 2014 2013 $ $ $ $ $ $ $ $ $ 38.96 $ 75.09 $ 69.90 65.13 $ 106.63 $ 112.46 63.13 $ 97.81 $ 110.21 41.13 $ 77.04 $ 73.81 2.91 $ 9.66 $ 9.53 $ 3.16 $ 4.72 $ 7.07 $ 11.98 $ 4.83 $ 32.60 $ 58.48 $ 3.43 5.69 10.45 3.58 56.46 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of blending costs and excluding risk management activities. Realized crude oil and NGLs prices decreased 47% to average $41.13 per bbl for 2015 from $77.04 per bbl for 2014 (2013 – $73.81 per bbl). The decrease in 2015 was primarily due to lower benchmark pricing and a widening WCS Heavy Differential as a percentage of WTI, partially offset by the impact of a weakening Canadian dollar. The Company’s realized natural gas price decreased 35% to average $3.16 per Mcf for 2015 from $4.83 per Mcf for 2014 (2013 – $3.58 per Mcf). The decrease in 2015 was due to strong natural gas production and lower demand as North America experienced warmer than normal winter temperatures in 2015. In addition, 2014 prices were higher due to lower than average storage levels in 2014 due to colder than normal winter temperatures. NORTH AMERICA North America realized crude oil prices decreased 48% to average $38.96 per bbl for 2015 from $75.09 per bbl for 2014 (2013 – $69.90 per bbl), primarily due to lower WTI benchmark pricing and a widening WCS Heavy Differential as a percentage of WTI, partially offset by the impact of a weakening Canadian dollar. North America realized natural gas prices decreased 38% to average $2.91 per Mcf for 2015 from $4.72 per Mcf for 2014 (2013 – $3.43 per Mcf), primarily due to strong natural gas production and lower demand as North America experienced 30 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.warmer than normal winter temperatures in 2015. In addition, 2014 prices were higher due to lower than average storage levels in 2014 due to colder than normal winter temperatures. The Company continues to focus on its crude oil marketing strategy including a blending strategy that expands markets within current pipeline infrastructure, supporting pipeline projects that will provide capacity to transport crude oil to new markets, and working with refiners to add incremental heavy crude oil and bitumen (thermal oil) conversion capacity. During 2015, the Company contributed approximately 183,000 bbl/d of heavy crude oil blends to the WCS stream. During 2013, the Company entered into a 20 year transportation agreement to ship 80,000 bbl/d of crude oil on the proposed Energy East pipeline originating at Hardisty, Alberta with delivery points in Quebec City, Quebec and Saint John, New Brunswick. This pipeline is subject to regulatory approval. The Company previously entered into a 20 year transportation agreement to ship 75,000 bbl/d of crude oil on the proposed Kinder Morgan Trans Mountain Expansion from Edmonton, Alberta to Vancouver, British Columbia. This pipeline is subject to regulatory approval. Comparisons of the prices received in North America Exploration and Production by product type were as follows: (Yearly average) Wellhead Price (1) (2) Light and medium crude oil and NGLs (C$/bbl) Pelican Lake heavy crude oil (C$/bbl) Primary heavy crude oil (C$/bbl) Bitumen (thermal oil) (C$/bbl) Natural gas (C$/Mcf) (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of blending costs and excluding risk management activities. 2015 2014 2013 $ $ $ $ $ 41.88 $ 76.94 $ 41.09 $ 77.58 $ 40.71 $ 76.29 $ 34.37 $ 2.91 $ 70.78 $ 4.72 $ 76.44 70.62 69.06 66.14 3.43 NORTH SEA North Sea realized crude oil prices decreased 39% to average $65.13 per bbl for 2015 from $106.63 per bbl for 2014 (2013 – $112.46 per bbl). Realized crude oil prices per bbl in any particular year are dependent on the terms of the various sales contracts, the frequency and timing of liftings of each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The decrease in realized crude oil prices in 2015 reflected prevailing Brent benchmark pricing at the time of liftings, partially offset by the weaker Canadian dollar. OFFSHORE AFRICA Offshore Africa realized crude oil prices decreased 35% to average $63.13 per bbl for 2015 from $97.81 per bbl for 2014 (2013 – $110.21 per bbl). Realized crude oil prices per bbl in any particular year are dependent on the terms of the various sales contracts, the frequency and timing of liftings of each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The decrease in realized crude oil prices in 2015 reflected prevailing Brent benchmark pricing at the time of liftings, partially offset by the weaker Canadian dollar. ROYALTIES – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) North America North Sea Offshore Africa Company average Natural gas ($/Mcf) (1) North America Offshore Africa Company average Company average ($/BOE) (1) (1) Amounts expressed on a per unit basis are based on sales volumes. 2015 2014 2013 $ $ $ $ $ $ $ $ 4.57 $ 0.14 $ 2.87 $ 13.74 $ 0.33 $ 6.83 $ 4.30 $ 12.99 $ 0.09 $ 0.46 $ 0.10 $ 2.85 $ 0.36 $ 1.74 $ 0.38 $ 8.90 $ 11.30 0.33 18.18 11.13 0.14 1.83 0.18 7.74 31 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.NORTH AMERICA Government royalties on a significant portion of North America crude oil and NGLs production fall under the oil sands royalty regime and are calculated on a project by project basis as a percentage of gross revenue less operating, capital and abandonment costs incurred (“net profit”). Crude oil and NGLs royalties averaged approximately 13% of product sales for 2015 compared with 19% in 2014 (2013 – 17%) primarily due to lower realized crude oil prices. North America crude oil and NGLs royalties per bbl are anticipated to average 7% to 9% of product sales for 2016. Natural gas royalties averaged approximately 4% of product sales for 2015 compared with 8% in 2014 (2013 – 5%) primarily due to lower realized natural gas prices. North America natural gas royalties per Mcf are anticipated to average 1.5% to 2.5% of product sales for 2016. NORTH SEA The UK government royalties on crude oil were eliminated effective January 1, 2003. The remaining royalty is a gross overriding royalty on the Ninian field. OFFSHORE AFRICA Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital and operating costs, the status of payouts, and the timing of liftings from each field. Royalty rates as a percentage of product sales averaged approximately 5% for 2015 compared with 8% for 2014 (2013 – 17%). The decrease in royalties was primarily a result of the timing of liftings and the status of payout in the various fields. Offshore Africa royalty rates are anticipated to average 6% to 8% of product sales for 2016. PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) North America North Sea Offshore Africa Company average Natural gas ($/Mcf) (1) North America North Sea Offshore Africa Company average Company average ($/BOE) (1) 2015 2014 2013 $ $ $ $ $ $ $ $ $ 12.51 $ 14.98 $ 63.67 $ 74.04 $ 33.32 $ 43.97 $ 15.74 $ 18.25 $ 1.27 $ 4.41 $ 1.76 $ 1.34 $ 1.42 $ 9.10 $ 3.22 $ 1.48 $ 14.20 66.19 25.32 17.14 1.39 4.67 2.53 1.42 12.70 $ 14.67 $ 14.24 (1) Amounts expressed on a per unit basis are based on sales volumes. NORTH AMERICA North America crude oil and NGLs production expense for 2015 decreased 16% to $12.51 per bbl from $14.98 per bbl for 2014 (2013 – $14.20 per bbl), reflecting continued reductions in production expense in 2015, as a result of the Company’s ongoing focus on cost control and efficiencies across the asset base, together with lower industry service costs. North America crude oil and NGLs production expense is anticipated to average $11.25 to $12.25 per bbl for 2016. North America natural gas production expense for 2015 decreased 11% to $1.27 per Mcf from $1.42 per Mcf for 2014 (2013 – $1.39 per Mcf), reflecting continued reductions in production expense in 2015, as a result of the Company’s ongoing focus on cost control and efficiencies across the asset base, together with lower industry service costs. North America natural gas production expense is anticipated to average $1.10 to $1.30 per Mcf for 2016. NORTH SEA North Sea crude oil production expense for 2015 decreased 14% to $63.67 per bbl from $74.04 per bbl for 2014 (2013 – $66.19 per bbl). The decrease was primarily due to higher production volumes on a relatively fixed cost structure and reflected the Company’s continuous focus on cost control and efficiencies, partially offset by the impact of the weaker Canadian dollar in 2015 and the impact of product inventory valuation adjustments. North Sea crude oil production expense is anticipated to average $47.00 to $53.00 per bbl for 2016. 32 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.OFFSHORE AFRICA Offshore Africa crude oil production expense for 2015 decreased 24% to $33.32 per bbl from $43.97 per bbl for 2014 (2013 – $25.32 per bbl). The decrease in production expense was primarily due to the impact of higher production volumes and the timing of liftings from various fields, including the Olowi field, which have different cost structures, offset by the impact of the weaker Canadian dollar in 2015 and the impact of product inventory valuation adjustments in the Olowi field. Annual 2015 Offshore Africa production expense exceeded the Company's previously issued guidance of $24.00 to $28.00 and is expected to average $18.00 to $22.00 per bbl for 2016. DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION ($ millions, except per BOE amounts) North America North Sea Offshore Africa Expense $/BOE (1) 2015 2014 $ 4,248 $ 3,901 $ 388 273 269 105 $ $ 4,909 $ 4,275 $ 18.50 $ 17.27 $ 2013 3,568 552 134 4,254 20.38 (1) Amounts expressed on a per unit basis are based on sales volumes. Depletion, depreciation and amortization expense for 2015 increased 7% to $18.50 per BOE from $17.27 per BOE for 2014 (2013 – $20.38 per BOE). The increase primarily reflected increased sales volumes in the International segments which have higher associated depletion rates, together with the impact of depletion expense resulting from the Company’s derecognition of exploration and evaluation assets in Block CI-514 in Côte d’Ivoire, Offshore. ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION ($ millions, except per BOE amounts) North America North Sea Offshore Africa Expense $/BOE (1) 2015 2014 2013 $ $ $ 93 $ 98 $ 39 10 38 10 142 $ 0.54 $ 146 $ 0.59 $ 92 35 10 137 0.66 (1) Amounts expressed on a per unit basis are based on sales volumes. Asset retirement obligation accretion expense decreased 8% to $0.54 per BOE from $0.59 per BOE for 2014 (2013 – $0.66 per BOE) primarily due to the impact of increased sales volumes. OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING OPERATIONS UPDATE The Company continues to focus on reliable and efficient operations. During 2015, operating performance continued to be strong, leading to average production of 122,911 bbl/d, reflecting high utilization rates and reliability. PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING ($/bbl) SCO sales price (1) Bitumen value for royalty purposes (1) (2) Bitumen royalties (1) (3) Transportation 2015 2014 2013 61.39 $ 100.27 $ 100.75 32.14 $ 67.63 $ 65.48 1.08 $ 1.81 $ 5.77 $ 1.85 $ 5.11 1.57 $ $ $ $ (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Calculated as the quarterly average of the bitumen valuation methodology price. (3) Calculated based on actual bitumen royalties expensed during the year; divided by the corresponding SCO sales volumes. Realized SCO sales prices averaged $61.39 per bbl for 2015, a decrease of 39% compared with $100.27 per bbl in 2014 (2013 – $100.75 per bbl), reflecting lower WTI benchmark pricing and the impact of industry wide unplanned upgrader outages. 33 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.CASH PRODUCTION COSTS – OIL SANDS MINING AND UPGRADING The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 20 to the Company’s consolidated financial statements. ($ millions) Cash production costs Less: costs incurred during turnaround periods Adjusted cash production costs Adjusted cash production costs, excluding natural gas costs Adjusted natural gas costs Adjusted cash production costs ($/bbl) (1) Adjusted cash production costs, excluding natural gas costs Adjusted natural gas costs Adjusted cash production costs Sales (bbl/d) (1) Amounts expressed on a per unit basis are based on sales volumes. $ $ $ $ $ $ 2015 2014 1,332 $ 1,609 $ (45) (98) 1,287 $ 1,511 $ 1,212 $ 1,395 $ 75 116 2013 1,567 (104) 1,463 1,359 104 1,287 $ 1,511 $ 1,463 2015 2014 26.95 $ 34.33 $ 1.66 2.85 2013 37.68 2.89 28.61 $ 37.18 $ 40.57 123,231 111,351 98,757 Adjusted cash production costs averaged $28.61 per bbl for 2015, a decrease of 23% compared with $37.18 per bbl for 2014 (2013 – $40.57 per bbl). The decrease in 2015 adjusted cash production costs primarily reflected the Company’s continuous focus on cost control and efficiencies, high utilization rates and reliability, and lower industry service costs, resulting in annual cash production costs being below the Company’s previously issued guidance of $29.00 to 32.00 per bbl. Cash production costs are anticipated to average $27.00 to $30.00 per bbl for 2016. DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING ($ millions, except per bbl amounts) Depletion, depreciation and amortization Less: depreciation incurred during turnaround periods Adjusted depletion, depreciation and amortization $/bbl (1) 2015 562 (5) 557 12.37 $ $ $ 2014 $596 (28) $568 $13.97 2013 $582 (79) $503 $13.95 (1) Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. Adjusted depletion, depreciation and amortization expense on a per barrel basis for 2015 decreased 11% to $12.37 per bbl from $13.97 per bbl for 2014 (2013 – $13.95 per bbl), primarily reflecting a lower depletion rate associated with the increase in productive capacity of the upgrader and related infrastructure. ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING ($ millions, except per bbl amounts) Expense $/bbl (1) 2015 2014 $ $ 31 $ 0.69 $ 47 $ 1.16 $ 2013 34 0.94 (1) Amounts expressed on a per unit basis are based on sales volumes. Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion on a per barrel basis for the year ended December 31, 2015 decreased 41% to $0.69 from $1.16 per bbl for the year ended December 31, 2014 (2013 – $0.94 per bbl). 34 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.MIDSTREAM ($ millions) Revenue Production expense Midstream cash flow Depreciation Equity loss from Redwater Partnership Segment earnings before taxes 2015 2014 2013 $ 136 $ 120 $ 32 104 12 44 34 86 9 8 $ 48 $ 69 $ 110 34 76 8 4 64 The Company’s Midstream assets include three crude oil pipeline systems and a 50% working interest in an 84-megawatt cogeneration plant at Primrose. Approximately 85% of the Company’s heavy crude oil production is transported to international mainline liquid pipelines via the 100% owned and operated ECHO Pipeline, the 62% owned and operated Pelican Lake Pipeline and the 15% owned Cold Lake Pipeline. The Midstream pipeline assets allow the Company to control the transport of a portion of its own production volumes as well as earn third party revenue. This transportation control enhances the Company’s ability to manage the full range of costs associated with the development and marketing of its heavier crude oil. The Company has a 50% interest in the Redwater Partnership. Redwater Partnership has entered into agreements to construct and operate a 50,000 barrel per day bitumen upgrader and refinery (the "Project") under processing agreements that target to process 12,500 barrels per day of bitumen feedstock for the Company and 37,500 barrels per day of bitumen feedstock for the Alberta Petroleum Marketing Commission (“APMC”), an agent of the Government of Alberta, under a 30 year fee-for-service tolling agreement. During 2013, the Company, along with APMC, each committed to provide funding up to $350 million by January 2016 in the form of subordinated debt bearing interest at prime plus 6%. During 2015, the Company and APMC each provided $112 million of subordinated debt (year ended December 31, 2014 – $113 million). Subsequent to December 31, 2015, the Company and APMC each provided an additional $99 million in subordinated debt. Should final Project costs exceed the revised cost estimate, the Company and APMC have agreed, subject to the Company being able to meet certain funding conditions, to fund any shortfall in available third party commercial lending required to attain Project completion. During 2015, Redwater Partnership issued $500 million of 2.10% series C senior secured bonds due February 2022, $500 million of 3.70% series D senior secured bonds due February 2043, $500 million of 3.20% series E senior secured bonds due April 2026 and $300 million of senior secured bonds through the reopening of its previously issued 4.05% series B senior secured bonds due July 2044. As at December 31, 2015, Redwater Partnership had borrowings of $1,417 million under its secured $3,500 million syndicated credit facility. Subsequent to December 31, 2015, the Partnership issued $550 million of 4.25% series F senior secured bonds due June 2029, and $300 million of 4.75% series G senior secured bonds due June 2037. Under its processing agreement, beginning on the earlier of the commercial operations date of the refinery and June 1, 2018, the Company is unconditionally obligated to pay its 25% pro rata share of the debt portion of the monthly cost of service toll, including interest, fees and principal repayments, of the syndicated credit facility and bonds, over the tolling period of 30 years. Redwater Partnership has entered into various agreements related to the engineering, procurement and construction of the Project. These contracts can be cancelled by Redwater Partnership upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation. ADMINISTRATION EXPENSE ($ millions, except per BOE amounts) Expense $/BOE (1) 2015 2014 $ $ 390 $ 1.26 $ 367 $ 1.28 $ 2013 335 1.37 (1) Amounts expressed on a per unit basis are based on sales volumes. Administration expense for 2015 decreased 2% to $1.26 per BOE from $1.28 per BOE for 2014 (2013 – $1.37 per BOE) primarily due to lower staffing related costs and general corporate costs, partially offset by the impact of lower recoveries due to the reduction in the capital expenditure program. 35 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.SHARE-BASED COMPENSATION ($ millions) (Recovery) expense 2015 2014 $ (46) $ 66 $ 2013 135 The Company’s stock option plan provides current employees with the right to receive common shares or a cash payment in exchange for stock options surrendered. The share-based compensation liability at December 31, 2015 reflected the Company’s liability for awards granted to employees at fair value estimated using the Black-Scholes valuation model. In periods when substantial share price changes occur, the Company’s net earnings are subject to significant volatility. The Company utilizes its share-based compensation plan to attract and retain employees in a competitive environment. All employees participate in this plan. The Company recorded a $46 million share-based compensation recovery for 2015, primarily as a result of remeasurement of the fair value of outstanding stock options related to the impact of normal course graded vesting of stock options granted in prior periods, the impact of vested stock options exercised or surrendered during the period and changes in the Company’s share price. During 2015, the Company recovered $10 million of share-based compensation costs to property, plant and equipment in the Oil Sands Mining and Upgrading segment (2014 – $14 million costs capitalized; 2013 – $25 million costs capitalized). During 2015, the Company paid $1 million for stock options surrendered for cash settlement (2014 – $8 million; 2013 – $4 million). INTEREST AND OTHER FINANCING EXPENSE ($ millions, except per BOE amounts and interest rates) Expense, gross Less: capitalized interest Expense, net $/BOE (1) Average effective interest rate $ $ $ 2015 2014 566 $ 527 $ 244 322 $ 1.04 $ 204 323 $ 1.12 $ 3.9% 3.9% 2013 454 175 279 1.14 4.4% (1) Amounts expressed on a per unit basis are based on sales volumes. Gross interest and other financing expense for 2015 increased from 2014 primarily due to the impact of higher overall debt levels. Capitalized interest of $244 million for 2015 was primarily related to the Horizon Phase 2/3 expansion. Net interest and other financing expense on a per BOE basis for 2015 decreased 7% to $1.04 per BOE from $1.12 per BOE for 2014 (2013 – $1.14 per BOE) primarily due to the impact of higher sales volumes. The Company’s average effective interest rate for 2015 was comparable with 2014. RISK MANAGEMENT ACTIVITIES The Company periodically utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These derivative financial instruments are not intended for trading or speculative purposes. ($ millions) Crude oil and NGLs financial instruments Natural gas financial instruments Foreign currency contracts Realized gain Crude oil and NGLs financial instruments Natural gas financial instruments Foreign currency contracts Unrealized loss (gain) Net gain 2015 2014 $ (599) $ (284) $ – (244) 34 (99) $ (843) $ (349) $ $ 394 $ (427) $ – (20) (3) (21) $ $ 374 $ (451) $ (469) $ (800) $ 2013 44 – (160) (116) 17 3 19 39 (77) During 2015, net realized risk management gains were related to the settlement of crude oil and foreign currency contracts. The Company recorded a net unrealized loss of $374 million ($275 million after-tax) on its risk management activities (2014 – $451 million unrealized gain, $339 million after-tax; 2013 – $39 million unrealized loss, $32 million after-tax), primarily related to changes in the fair value of these contracts. 36 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.The cash settlement amount of outstanding derivative financial instruments as at December 31, 2015 may vary materially depending upon the underlying foreign exchange and interest rates at the time of final settlement, as compared to their fair value at December 31, 2015. Complete details related to outstanding derivative financial instruments at December 31, 2015 are disclosed in note 17 to the Company’s consolidated financial statements. FOREIGN EXCHANGE ($ millions) Net realized (gain) loss Net unrealized loss (1) Net loss 2015 2014 (97) $ 47 $ 858 256 761 $ 303 $ 2013 (16) 226 210 $ $ (1) Amounts are reported net of the hedging effect of cross currency swaps. The Company’s operating results are significantly impacted by fluctuations in the exchange rates between the Canadian dollar, US dollar, and UK pound sterling. Predominantly all of the Company’s revenue is based on reference to US dollar benchmark prices. An increase in the value of the Canadian dollar in relation to the US dollar results in decreased revenue from the sale of the Company’s production. Conversely a decrease in the value of the Canadian dollar in relation to the US dollar results in increased revenue from the sale of the Company’s production. Production expenses in the North Sea are subject to foreign currency fluctuations due to changes in the exchange rate of the UK pound sterling to the US and Canadian dollars. Production expenses in Offshore Africa are subject to foreign currency fluctuations due to changes in the exchange rate of the US dollar to the Canadian dollar. The value of the Company’s US dollar denominated debt is also impacted by the value of the Canadian dollar in relation to the US dollar. The net realized foreign exchange gain for 2015 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling. The net unrealized foreign exchange loss in 2015 was primarily related to the impact of the weakening Canadian dollar with respect to outstanding US dollar debt. Included in the net unrealized loss for 2015 was an unrealized gain of $649 million (2014 – $259 million unrealized gain, 2013 – $165 million unrealized gain) related to the impact of cross currency swaps. The US/Canadian dollar exchange rate at December 31, 2015 was US$0.7225 (December 31, 2014 – US$0.8620; December 31, 2013 – US$0.9402). 37 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.INCOME TAXES ($ millions, except income tax rates) North America (1) North Sea Offshore Africa (2) PRT recovery – North Sea Other taxes Current income tax (recovery) expense Deferred income tax expense Deferred PRT expense (recovery) – North Sea Deferred income tax expense Income tax rate and other legislative changes (3) 2015 2014 $ 86 $ 702 $ (117) 17 (258) 11 (261) 216 15 231 (30) (351) (68) 43 (273) 23 427 681 126 807 1,234 – Effective income tax rate on adjusted net earnings from operations (4) 61% 25% $ (381) $ 1,234 $ 2013 544 23 202 (56) 22 735 163 (132) 31 766 (15) 751 26% (1) Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments. (2) Includes current income taxes relating to disposition of properties in 2013. (3) During 2015, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and PRT, and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company’s deferred income tax liability of $228 million. During 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12%. As a result of this income tax rate increase, the Company’s deferred income tax liability was increased by $579 million. During 2013, the British Columbia government substantively enacted legislation to increase its provincial corporate income tax rate. As a result of the income tax rate change, the Company’s deferred income tax liability was increased by $15 million. (4) Excludes the impact of current and deferred PRT expense and other current income tax expense. Current income taxes recognized in each operating segment will vary depending upon available income tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year. The current PRT recovery in the North Sea in 2015 and 2014 reflected the impact of abandonment expenditures on the Murchison platform. During 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015. As a result of this income tax rate increase, the Company’s deferred income tax liability was increased by $579 million. During 2015, the UK government enacted legislation that reduced the supplementary charge on oil and gas profits from 32% to 20% effective January 1, 2015. In addition, the legislation reduced the PRT rate from 50% to 35% effective January 1, 2016. Allowable abandonment expenditures eligible for carryback to prior taxation years for PRT purposes are still recoverable at the previous tax rate of 50%. The legislation also replaced the existing Brownfield Allowance with a new Investment Allowance on qualifying capital expenditures, effective April 1, 2015. The new Investment Allowance is deductible for supplementary charge purposes, subject to certain restrictions. As a result of the income tax changes, the Company’s deferred income tax liability was reduced by $217 million and the deferred PRT liability was reduced by $11 million. During 2013, the British Columbia government substantively enacted legislation to increase its provincial corporate income tax rate effective April 1, 2013. As a result of the income tax rate change, the Company’s deferred income tax liability was increased by $15 million. The Company files income tax returns in the various jurisdictions in which it operates. These tax returns are subject to periodic examinations in the normal course by the applicable tax authorities. The tax returns as prepared may include filing positions that could be subject to differing interpretations of applicable tax laws and regulations, which may take several years to resolve. The Company does not believe the ultimate resolution of these matters will have a material impact upon the Company’s results of operations, financial position or liquidity. During 2015, the Company filed Scientific Research and Experimental Development claims of approximately $527 million (2014 – $450 million; 2013 – $390 million) relating to qualifying research and development expenditures for Canadian income tax purposes. For 2016, based on forward commodity prices and the current availability of tax pools, the Company expects to incur current income tax recoveries of $260 million to $320 million in Canada and recoveries of $250 million to $300 million in the North Sea and Offshore Africa. 38 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.NET CAPITAL EXPENDITURES (1) ($ millions) Exploration and Evaluation Net (proceeds) expenditures (2) (3) (4) Property, Plant and Equipment Net property (disposals) acquisitions (2) (3) (4) Well drilling, completion and equipping Production and related facilities Capitalized interest and other (5) Net (proceeds) expenditures Total Exploration and Production Oil Sands Mining and Upgrading Horizon Phases 2/3 construction costs Sustaining capital Turnaround costs Capitalized interest and other (5) Total Oil Sands Mining and Upgrading Midstream Abandonments (6) Head office Total net capital expenditures By segment North America (2) (3) (4) North Sea Offshore Africa (3) Oil Sands Mining and Upgrading Midstream Abandonments (6) Head office Total 2015 2014 2013 $ (805) $ 1,190 $ (144) (451) 965 908 102 1,524 719 2,893 2,162 1,830 106 6,991 8,181 246 2,140 1,878 120 4,384 4,240 2,187 2,502 2,057 301 18 224 352 29 227 278 100 157 2,730 3,110 2,592 8 370 26 62 346 45 197 207 38 3,853 $ 11,744 $ 7,274 (119) $ 7,500 $ 4,026 230 608 2,730 8 370 26 400 281 3,110 62 346 45 334 (120) 2,592 197 207 38 $ $ $ 3,853 $ 11,744 $ 7,274 (1) Net capital expenditures exclude adjustments related to differences between carrying amounts and tax values, and other fair value adjustments. (2) Includes Business Combinations. (3) Includes proceeds from the Company’s dispositions of properties. (4) The above noted figures include non-cash share consideration of $985 million received from PrairieSky on the disposition of royalty income assets in 2015 and the impact of other pre-tax gains on the sale of other properties totaling $49 million recognized in 2015. (5) Capitalized interest and other includes expenditures related to land acquisition and retention, seismic, and other adjustments. (6) Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table. 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 areas. The Company focuses on managing its land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. reflected for 2015 Net capital expenditures for 2015 were $3,853 million compared with $11,744 million for 2014 (2013 – $7,274 million). Capital expenditures the Company's capital program by approximately in $3,400 million, as well as changes to its capital allocation strategy, including the decrease in drilling activity in North America, partially offset by the planned drilling activities in Offshore Africa. Capital expenditures for 2015 also reflected the disposition of a number of North America royalty income assets on December 16, 2015, including exploration and evaluation assets of $488 million and property, plant and equipment of $480 million, for total consideration of $1,658 million. Total consideration on the disposition was comprised of $673 million in cash, together with $985 million of non-cash share consideration of approximately 44.4 million common shares of PrairieSky. reductions 39 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.During 2014, the Company completed the acquisition of certain Canadian crude oil and natural gas properties, including exploration and evaluation assets of $823 million, for cash consideration of $3,110 million, subject to final closing adjustments. During 2014, the Company also acquired a number of additional producing crude oil and natural gas properties in the North American Exploration and Production segment for net cash consideration of $643 million, resulting in a non-cash gain of $137 million. During 2013, the Company disposed of a 50% interest in its exploration right in South Africa, for net cash consideration of US$255 million, including a recovery of US$14 million of past incurred costs, resulting in an after-tax gain on sale of exploration and evaluation property of $166 million. In the event that a commercial crude oil or natural gas discovery occurs on this exploration right, resulting in the exploration right being converted into a production right, an additional cash payment would be due to the Company at such time, amounting to US$450 million for a commercial crude oil discovery and US$120 million for a commercial natural gas discovery. As at December 31, 2015, the Company assessed the recoverability of its property, plant and equipment and its exploration and evaluation assets, and determined carrying amounts to be recoverable. Drilling Activity (number of wells) Net successful natural gas wells Net successful crude oil wells (1) Dry wells Stratigraphic test / service wells Total Success rate (excluding stratigraphic test / service wells) (1) Includes bitumen wells. 2015 19 115 6 166 306 96% 2014 75 1,023 19 437 1,554 98% 2013 44 1,117 30 384 1,575 97% NORTH AMERICA North America, excluding Oil Sands Mining and Upgrading, accounted for approximately 1% of the total net capital expenditures for 2015 compared with approximately 66% for 2014 (2013 – 59%). During 2015, the Company targeted 19 net natural gas wells, including 14 wells in Northwest Alberta, 3 wells in Northeast British Columbia, and 2 wells in Northern Plains. The Company also targeted 108 net primary heavy crude oil wells in the Company’s Northern Plains region. Overall thermal oil production for 2015 averaged approximately 129,800 bbl/d, compared with approximately 107,800 bbl/d in 2014 (2013 – 96,500 bbl/d). Production volumes reflected the cyclic nature of thermal oil production at Primrose and production at Kirby South. Operating performance at the Pelican Lake tertiary recovery project continued to be strong, leading to average production of approximately 50,800 bbl/d in 2015 (2014 – 50,100 bbl/d); 2013 – 42,900 bbl/d). OIL SANDS MINING AND UPGRADING Phase 2/3 expansion activity in 2015 continued to focus on field construction of the hydrogen unit, hydrotreater unit, vacuum distillation unit and distillation recovery unit, tank farms, tailings re-handling plant, froth treatment, froth tank, tailings transfer pumphouses and pipelines, extraction plant, ore preparation plants, and superpot along with engineering, procurement and construction related to tailings retrofit, sour water concentrator, combined hydrotreater and sulphur recovery units. In addition, the new Extraction trains 3 and 4 were commissioned. The Company targets to complete Phase 2B in 2016. NORTH SEA During 2015, the Company completed one injection well and no further drilling activities are currently planned for 2016. The decommissioning activities at the Murchison platform are ongoing and are expected to continue for approximately five years. OFFSHORE AFRICA During 2015, at the Espoir field, Côte d’Ivoire, the Company drilled 5 gross producing wells and 1 injector well, adding net production volumes of approximately 6,900 bbl/d to date. In 2016, upon completion of the sixth gross producing well, no additional wells will be drilled in the program. The infill drilling program is currently tracking to below its original sanction costs and above original sanction production. During 2015, at the Baobab field, Côte d’Ivoire, the Company drilled 5 gross wells, adding net production volumes of approximately 13,400 bbl/d to date. In late December, the Baobab field was temporarily shut-in due to a riser failure, delaying first oil on the fifth gross well. After inspection of the riser system, production was reinstated in late January 2016. In 2016, upon completion of the sixth gross well, no additional wells will be drilled in the program. The drilling program is currently tracking to below its original sanction costs and above original sanction production. During 2015, the Company provided notice of its withdrawal from Block CI-514 in Côte d’Ivoire, Offshore Africa. 40 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.LIQUIDITY AND CAPITAL RESOURCES ($ millions, except ratios) Working capital (deficit) (1) Long-term debt (2) (3) Shareholders’ equity Share capital Retained earnings Accumulated other comprehensive income Total Debt to book capitalization (3) (4) Debt to market capitalization (3) (5) After-tax return on average common shareholders’ equity (6) After-tax return on average capital employed (3) (7) 2015 2014 2013 1,193 $ (673) $ (1,574) 16,794 $ 14,002 $ 9,661 $ $ $ 4,541 $ 4,432 $ 3,854 22,765 24,408 21,876 75 51 42 $ 27,381 $ 28,891 $ 25,772 38% 34% (2%) (1%) 33% 26% 14% 10% 27% 20% 9% 7% (1) Calculated as current assets less current liabilities, excluding the current portion of long-term debt. (2) Includes the current portion of long-term debt (2015 – $1,729 million; 2014 – $980 million; 2013 – $1,444 million). (3) Long-term debt is stated at its carrying value, net of fair value adjustments, original issue discounts and premiums and transaction costs. (4) Calculated as current and long-term debt; divided by the book value of common shareholders’ equity plus current and long-term debt. (5) Calculated as current and long-term debt; divided by the market value of common shareholders’ equity plus current and long-term debt. (6) Calculated as net earnings (loss) for the year; as a percentage of average common shareholders’ equity for the year. (7) Calculated as net earnings (loss) plus after-tax interest and other financing expense for the year; as a percentage of average capital employed for the year. At December 31, 2015, the Company’s capital resources consisted primarily of cash flow from operations, available bank credit facilities and access to debt capital markets. Cash flow from operations and the Company’s ability to renew existing bank credit facilities and raise new debt is dependent on factors discussed in the “Risks and Uncertainties” section of this MD&A. In addition, the company’s ability to renew existing bank credit facilities and raise new debt reflects current credit ratings as determined by independent rating agencies, and the conditions of the market. The Company continues to believe that its internally generated cash flow from operations, 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. On an ongoing basis the Company continues to focus on its balance sheet strength and available liquidity by: ■■ Monitoring cash flow from operations, which is the primary source of funds; ■■ Actively managing the allocation of maintenance and growth capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. In response to the decline in commodity prices, the Company continues to exercise its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments and long-term debt; ■■ Reviewing the Company's borrowing capacity: ■● During 2015, the Company filed base shelf prospectuses that allow for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada and US$3,000 million of debt securities in the United States until November 2017. If issued, these securities may be offered separately or together, in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance; ■● During 2015, the Company issued $500 million of series 2 medium-term notes, due August 2020, through the reopening of its previously issued 2.89% notes. In addition, the $1,500 million revolving syndicated credit facility was increased to $2,425 million and the maturity date was extended to June 2019 from June 2016. The $3,000 million revolving syndicated credit facility was reduced to $2,425 million and the maturity date was extended to June 2020 from June 2017. As a result, the Company's available liquidity increased by $350 million; ■● The Company's borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million. The Company reserves capacity under its bank credit facilities for amounts outstanding under the US commercial paper program; 41 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.■● During 2015, the Company extended its existing $1,000 million non-revolving term credit facility to January 2017. In addition, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018. Both facilities were fully drawn at December 31, 2015. Subsequent to December 31, 2015, the Company prepaid $250 million of the borrowings outstanding under the $1,000 million non-revolving term credit facility and extended the facility to February 2019 from January 2017. Subsequent to December 31, 2015, the Company also entered into a new $125 million non-revolving term credit facility maturing February 2019, which was fully drawn. Borrowings under this new facility may be made by way of pricing referenced to Canadian dollar bankers' acceptances or Canadian prime loans; ■● Subsequent to December 31, 2015, the Company retained its investment grade ratings with both Standard & Poor's Rating Services and DBRS Limited. In addition, Moody's Investors Service, Inc. downgraded the Company's credit ratings within the investment grade debt rating scale. The current changes in the Company's credit ratings are not expected to have a significant impact on the Company's access to debt capital markets, its US commercial paper program or on its overall cost of borrowing. ■■ Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages. Beginning in 2015, all of the Company's credit facilities are now subject to a financial covenant that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 0.65 to 1.0; and ■■ Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place to minimize the impact in the event of a default. During 2015, the Company repaid $400 million of 4.95% medium term notes. At December 31, 2015, the Company had in place bank credit facilities of $7,481 million, of which approximately $3,495 million, net of commercial paper issuances of $692 million, was available for general corporate purposes. At December 31, 2015, the Company had long-term debt with a carrying amount of $1,037 million maturing over the next 12 months (US$500 million of debt securities at three-month LIBOR plus 0.375% due March 2016 and US$250 million of 6.00% debt securities due August 2016). These debt securities have been hedged by way of cross currency swaps with principal repayment amounts fixed at $555 million and $279 million respectively. At December 31, 2015, the Company had total US dollar denominated debt with a carrying amount of $11,981 million (US$8,657 million). This included $5,615 million (US$4,057 million) hedged by way of cross currency swaps (US$2,900 million) and foreign currency forwards (US$1,157 million). The fixed repayment amount of these hedging instruments is $4,845 million, resulting in a notional reduction of the carrying amount of the Company's US dollar denominated debt by approximately $770 million to $11,211 million as at December 31, 2015. Long-term debt was $16,794 million at December 31, 2015, resulting in a debt to book capitalization ratio of 38% (December 31, 2014 – 33%; December 31, 2013 – 27%). This ratio is within the 25% to 45% internal range utilized by management. This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. The Company may be below the low end of the targeted range when cash flow from operations is greater than current investment activities. The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital structure. Further details related to the Company’s long-term debt at December 31, 2015 are discussed in note 9 to the Company’s consolidated financial statements. The Company’s commodity hedge policy reduces the risk of volatility in commodity prices and supports the Company’s cash flow for its capital expenditure programs. This policy 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 policy, the purchase of put options is in addition to the above parameters. At March 2, 2016 the Company had no commodity derivative financial instruments outstanding. SHARE CAPITAL As at December 31, 2015, there were 1,094,668,000 common shares outstanding (December 31, 2014 – 1,091,837,000 common shares) and 74,615,000 stock options outstanding. As at March 1, 2016, the Company had 1,094,704,000 common shares outstanding and 71,353,000 stock options outstanding. On March 2, 2016, the Board of Directors declared a regular quarterly dividend of $0.23 per common share. On an annualized basis, the dividend of $0.92 per common share remains unchanged from the previous annual dividend rate. This reflects confidence in the Company’s cash flow and provides a return to shareholders. The dividend policy undergoes periodic review by the Board of Directors and is subject to change. During 2015, the Company announced a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock Exchange (“TSX”), alternative Canadian trading platforms, and the New York Stock Exchange (“NYSE”), during the twelve month period commencing April 2015 and ending April 2016, up to 54,640,607 common shares. The Company’s Normal Course Issuer Bid announced in 2014 expired April 2015. During 2015, the Company did not purchase any common shares for cancellation. 42 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS In the normal course of business, the Company has entered into various commitments that will have an impact on the Company’s future operations. The following table summarizes the Company’s commitments as at December 31, 2015: ($ millions) Product transportation and pipeline Offshore equipment operating leases and offshore drilling Long-term debt (1) (2) Interest and other financing expense (3) Office leases Other 2016 2017 2018 2019 2020 Thereafter 423 $ 341 $ 303 $ 261 $ 246 $ 1,304 247 $ 93 $ 71 $ 22 $ – $ – $ $ $ 1,730 $ 2,522 $ 2,899 $ 1,353 $ 1,427 $ 6,935 $ $ $ 649 $ 564 $ 478 $ 437 $ 408 $ 4,608 42 $ 141 $ 42 $ 38 $ 42 $ 48 $ 43 $ 1 $ 42 $ 193 - $ - (1) Long-term debt represents principal repayments only and does not reflect original issue discounts and premiums or transaction costs. (2) At December 31, 2015, the Company had US$500 million of debt securities at three-month LIBOR plus 0.375% due March 2016 and US$250 million of 6.00% debt securities due August 2016. These debt securities have been hedged by way of cross currency swaps with principal repayment amounts fixed at $555 million and $279 million respectively. (3) Interest and other financing expense amounts represent the scheduled fixed rate and variable rate cash interest 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, 2015. In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and construction of subsequent phases of Horizon. These contracts can be cancelled by the Company upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation. LEGAL PROCEEDINGS AND OTHER CONTINGENCIES The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. 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. RESERVES For the years ended December 31, 2015, 2014 and 2013, the Company retained Independent Qualified Reserves Evaluators to evaluate and review all of the Company’s proved and proved plus probable crude oil, NGLs and natural gas reserves. The evaluation and review was conducted in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and disclosed in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) requirements. The Company annually discloses net proved reserves and the standardized measure of discounted future net cash flows using 12-month average prices and current costs in accordance with United States FASB Topic 932 “Extractive Activities – Oil and Gas” in the Company’s annual report on Form 40-F filed with the SEC and in the “Supplementary Oil and Gas Information” section of the Company’s Annual Report. The following tables summarize the company gross proved and proved plus probable reserves using forecast prices and costs as at December 31, 2015, prepared in accordance with NI 51-101 reserves disclosures: Light and Medium Crude Oil Primary Heavy Crude Oil Pelican Lake Heavy Crude Oil Proved Reserves (MMbbl) (MMbbl) (MMbbl) December 31, 2014 445 229 274 Bitumen (Thermal Oil) (MMbbl) 1,217 Synthetic Crude Oil Natural Gas Natural Gas Liquids Barrels of Oil Equivalent (Bcf) (MMbbl) (MMBOE) Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 1 1 4 – 5 (3) (7) (26) (34) 386 – 4 10 – 4 – (3) 16 (47) 213 – – – 2 – – – 10 (18) 268 (MMbbl) 2,158 – 220 – – – – 7 68 (45) 6,001 14 252 298 – 414 (7) (392) 156 (630) – 23 – 26 7 – – (1) (47) 1,225 2,408 6,106 188 2 10 7 – 8 – (6) 1 (15) 195 5,511 5 300 71 28 93 (4) (74) 94 (311) 5,713 43 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. Light and Medium Crude Oil Primary Heavy Crude Oil Pelican Lake Heavy Crude Oil Bitumen (Thermal Oil) Synthetic Crude Oil Natural Gas Natural Gas Liquids Barrels of Oil Equivalent Proved Plus Probable Reserves December 31, 2014 660 317 395 (MMbbl) (MMbbl) (MMbbl) (MMbbl) 2,312 (MMbbl) 3,593 (Bcf) (MMbbl) (MMBOE) 8,138 258 8,891 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2015 1 2 8 – 6 (5) (8) (12) (34) 618 – 6 13 – 5 – (3) 3 (47) 294 – – – 3 – – – 8 (18) 388 – 111 – 40 9 – – (18) (47) – 45 – – – – 7 33 (45) 17 358 742 1 515 (9) (501) (123) (630) 2,407 3,633 8,508 2 15 29 – 10 – (8) (8) (15) 283 6 239 174 43 116 (7) (96) (14) (311) 9,041 At December 31, 2015, the company gross proved crude oil, bitumen (thermal oil), SCO and NGLs reserves totaled 4,695 MMbbl, and company gross proved plus probable crude oil, bitumen (thermal oil), SCO and NGLs reserves totaled 7,623 MMbbl. Proved reserve additions and revisions replaced 189% of 2015 production. Additions to proved reserves resulting from exploration and development activities, acquisitions and future offset additions amounted to 331 MMbbl, and additions to proved plus probable reserves amounted to 300 MMbbl. Net positive revisions amounted to 59 MMbbl for proved reserves and net negative revisions amounted to 6 MMbbl for proved plus probable reserves, primarily due to technical revisions to prior estimates. At December 31, 2015, the company gross proved natural gas reserves totaled 6,106 Bcf, and company gross proved plus probable natural gas reserves totaled 8,508 Bcf. Proved reserve additions and revisions replaced 117% of 2015 production. Additions to proved reserves resulting from exploration and development activities, acquisitions and future offset additions amounted to 971 Bcf, and additions to proved plus probable reserves amounted to 1,624 Bcf. Net negative revisions amounted to 236 Bcf for proved reserves and 624 Bcf for proved plus probable reserves, primarily due to economic factors. The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with each of the Company’s Independent Qualified Reserves Evaluators to review the qualifications of and procedures used by each evaluator in determining the estimate of the Company’s quantities and related net present value of future net revenue of the remaining reserves. Additional reserves disclosure is annually disclosed in the AIF and the “Supplementary Oil and Gas Information” section of the Company’s Annual Report. RISKS AND UNCERTAINTIES The Company is exposed to various operational risks inherent in the exploration, development, production and marketing of crude oil and NGLs and natural gas and the mining and upgrading of bitumen into SCO. These inherent risks include, but are not limited to, the following: ■■ The ability to find, produce and replace reserves, whether sourced from exploration, improved recovery or acquisitions, at a reasonable cost, including the risk of reserve revisions due to economic and technical factors. Reserve revisions can have a positive or negative impact on asset valuations, ARO and depletion rates; ■■ Reservoir quality and uncertainty of reserve estimates; ■■ Volatility in the prevailing prices of crude oil and NGLs and natural gas; ■■ Regulatory risk related to approval for exploration and development activities, which can add to costs or cause delays in projects; ■■ Labour risk associated with securing the manpower necessary to complete capital projects in a timely and cost effective manner; ■■ Operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company’s bitumen products; ■■ Timing and success of integrating the business and operations of acquired properties and/or companies; ■■ Credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts, including derivative financial instruments and physical sales contracts as part of a hedging program; ■■ Interest rate risk associated with the Company’s ability to secure financing on commercially acceptable terms; 44 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. ■■ Foreign exchange risk due to fluctuating exchange rates on the Company’s US dollar denominated debt and as all sales are predominantly based on US dollar denominated benchmarks; ■■ Environmental impact risk associated with exploration and development activities, including GHG; ■■ Geopolitical risks associated with changing governments or governmental policies, social instability and other political, economic or diplomatic developments in the regions where the Company has its operations; ■■ Future legislative and regulatory developments related to environmental regulation; ■■ Potential actions of governments, regulatory authorities and other stakeholders that may result in costs or restrictions in the jurisdictions where the Company has operations; ■■ Changing royalty regimes, including final resolution of the Alberta provincial royalty review; ■■ Business interruptions because of unexpected events such as fires or explosions whether caused by human error or nature, severe storms and other calamitous acts of nature, blowouts, freeze-ups, mechanical or equipment failures of facilities and infrastructure and other similar events affecting the Company or other parties whose operations or assets directly or indirectly impact the Company and that may or may not be financially recoverable; ■■ The ability to secure adequate transportation for products which could be affected by pipeline constraints, the construction by third parties of new or expansion of existing pipeline capacity and other factors; ■■ The access to markets for the Company’s products; and ■■ Other circumstances affecting revenue and expenses. The Company uses a variety of means to help mitigate and/or minimize these risks. The Company maintains a comprehensive property loss and business interruption insurance program to reduce risk. Operational control is enhanced by focusing efforts on large core areas with high working interests and by assuming operatorship of key facilities. Product mix is diversified, consisting of the production of natural gas and the production of crude oil of various grades. The Company believes this diversification reduces price risk when compared with over-leverage to one commodity. Accounts receivable from the sale of crude oil and natural gas 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. Derivative financial instruments are utilized to help ensure targets are met and to manage commodity price, foreign currency and interest rate exposures. The Company is 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. The arrangements and policies concerning the Company’s financial instruments are under constant review and may change depending upon the prevailing market conditions. The Company’s capital structure mix is also monitored on a continual basis to ensure that it optimizes flexibility, minimizes cost and offers the greatest opportunity for growth. This includes the determination of a reasonable level of debt and any interest rate exposure risk that may exist. For additional details regarding the Company’s risks and uncertainties, refer to the Company’s AIF for the year ended December 31, 2015. ENVIRONMENT The Company continues to invest in people, technologies, facilities and infrastructure to recover and process crude oil and natural gas resources efficiently and in an environmentally sustainable manner. The crude oil and natural gas industry is experiencing incremental increases in costs related to environmental regulation, particularly in North America and the North Sea. Existing and expected legislation and regulations require the Company to address and mitigate the effect of its activities on the environment. Increasingly stringent laws and regulations may have an adverse effect on the Company’s future net earnings and cash flow from operations. The Company’s associated environmental risk management strategies focus on working with legislators and regulators to ensure that any new or revised policies, legislation or regulations properly reflect a balanced approach to sustainable development. Specific measures in response to existing or new legislation include a focus on the Company’s energy efficiency, air emissions management, released water quality, reduced fresh water use and the minimization of the impact on the landscape. Training and due diligence for operators and contractors are key to the effectiveness of the Company’s environmental management programs and the prevention of incidents. The Company’s environmental risk management strategies employ an Environmental Management Plan (the “Plan”). Details of the Plan, along with performance results, are presented to, and reviewed by, the Board of Directors quarterly. 45 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.The Company’s Plan and operating guidelines focus on minimizing the impact of operations while meeting regulatory requirements, regional management frameworks, industry operating standards and guidelines, and internal corporate standards. The Company, as part of this Plan, has implemented a proactive program that includes: ■■ An internal environmental compliance audit and inspection program of the Company’s operating facilities; ■■ A suspended well inspection program to support future development or eventual abandonment; ■■ Appropriate reclamation and decommissioning standards for wells and facilities ready for abandonment; ■■ An effective surface reclamation program; ■■ A due diligence program related to groundwater monitoring; ■■ An active program related to preventing and reclaiming spill sites; ■■ A solution gas conservation program; ■■ A program to replace the majority of fresh water for steaming with brackish water; ■■ Water programs to improve efficiency of use, recycle rates and water storage; ■■ Environmental planning for all projects to assess impacts and to implement avoidance and mitigation programs; ■■ Reporting for environmental liabilities; ■■ A program to optimize efficiencies at the Company’s operated facilities; ■■ Continued evaluation of new technologies to reduce environmental impacts and support for Canada’s Oil Sands Innovation Alliance (“COSIA”); ■■ CO2 reduction programs including carbon capture at hydrotreaters, the injection of CO2 into tailings and for use in EOR; ■■ A program in place related to progressive reclamation and tailings management at Horizon including low fines mining; and ■■ Participation and support for the Joint Oil Sands Monitoring Program. The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and have been discounted using a weighted average discount rate of 5.9% (2014 – 4.6%; 2013 – 5.0%). For 2015, the Company’s capital expenditures included $370 million for abandonment expenditures (2014 – $346 million; 2013 – $207 million). The Company’s estimated discounted ARO at December 31, 2015 was as follows: ($ millions) Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream 2015 2014 $ 1,114 $ 975 266 594 1 2,012 1,169 255 783 2 $ 2,950 $ 4,221 The discounted ARO was based on estimates of future costs to abandon and restore wells, production facilities, mine sites, upgrading facilities and tailings, and offshore production platforms. Factors that affect costs include number of wells drilled, well depth, facility size and the specific environmental legislation. The estimated future costs are based on engineering estimates of current costs in accordance with present legislation, industry operating practice and the expected timing of abandonment. The Company’s strategy in the North Sea consists of developing commercial hubs around its core operated properties with the goal of increasing production and extending the economic lives of its production facilities, thereby delaying the eventual abandonment dates. GREENHOUSE GAS AND OTHER AIR EMISSIONS The Company, through the Canadian Association of Petroleum Producers, is working with Canadian legislators and regulators as they develop and implement new GHG emission laws and regulations. Internally, the Company is pursuing an integrated emissions reduction strategy, to ensure that it is able to comply with existing and future emissions reduction requirements, for both GHGs and air pollutants (such as sulphur dioxide and oxides of nitrogen). The Company continues to develop strategies that will enable it to deal with the risks and opportunities associated with new GHG and air emissions policies. In addition, the Company is working with relevant parties to ensure that new policies encourage technological innovation, energy efficiency, and targeted research and development while not impacting competitiveness. In Canada, the federal government has indicated its intent to develop regulations to address industrial GHG emissions, as part of the national GHG reduction target. The federal government is also developing a comprehensive management system for air pollutants, and has released draft regulations pertaining to certain boilers, heaters and compressor engines operated by the Company. In Alberta, the provincial government has implemented increases in both the carbon price and stringency of the existing large-emitter regulatory system for 2016 and 2017. The Alberta government has also announced additional changes to this system after 2017, as well as a program to reduce methane emissions from the upstream oil and gas sector, and a carbon 46 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.price on combustion emissions from the upstream oil and gas sector beginning in 2023. In British Columbia, the provincial government is reviewing its climate change strategy with announcements on future changes expected in 2016. In Alberta, GHG reduction regulations came into effect July 1, 2007, affecting facilities emitting more than 100 kilotonnes of CO2e annually. Five of the Company’s facilities, the Horizon facility, the Primrose/Wolf Lake in situ heavy crude oil facilities, the Kirby South in situ heavy crude oil facility, the Hays sour natural gas plant, and the Wapiti gas plant are subject to compliance under the regulations. In British Columbia, carbon tax is currently being assessed at $30/tonne of CO2e on fuel consumed and gas flared in the province. The Saskatchewan government released draft GHG regulations that regulate facilities emitting more than 50 kilotonnes of CO2e annually and will likely require the North Tangleflags in situ heavy oil facility to meet the reduction target for its GHG emissions once the governing legislation comes into force. In the UK, GHG regulations have been in effect since 2005. In Phase 1 (2005 – 2007) of the UK National Allocation Plan, the Company operated below its CO2 allocation. In Phase 2 (2008 – 2012) the Company’s CO2 allocation was decreased below the Company’s operations emissions. In Phase 3 (2013 – 2020) the Company’s CO2 allocation was further reduced. The Company continues to focus on implementing reduction programs based on efficiency audits to reduce CO2 emissions at its major facilities and on trading mechanisms to ensure compliance with requirements now in effect. The United States Environmental Protection Agency (“EPA”) is proceeding to regulate GHGs under the Clean Air Act. This EPA action has been subject to legal and political challenges, the outcome of which cannot be predicted. The ultimate form of Canadian regulation is anticipated to be strongly influenced by the regulatory decisions made within the United States. Various states have enacted or are evaluating low carbon fuel standards, which may affect access to market for crude oil with higher emissions intensity. There are a number of unresolved issues in relation to Canadian federal and provincial GHG regulatory requirements. Key among them is the form of regulation, an appropriate common facility emission level, availability and duration of compliance mechanisms, and resolution of federal/provincial harmonization agreements. The Company continues to pursue GHG emission reduction initiatives including: solution gas conservation, compressor optimization to improve fuel gas efficiency, CO2 capture and sequestration in oil sands tailings, CO2 capture and storage in association with EOR, and participation in COSIA. The additional requirements of enacted or proposed GHG regulations on the Company’s operations may increase capital expenditures and operating expenses, including those related to Horizon and the Company’s other existing and certain planned oil sands projects. This may have an adverse effect on the Company’s future net earnings and cash flow from operations. Air pollutant standards and guidelines are being developed federally and provincially and the Company is participating in these discussions. Ambient air quality and sector based reductions in air emissions are being reviewed. Through Company and industry participation with stakeholders, guidelines are being developed that adopt a structured process to emission reductions that is commensurate with technological development and operational requirements. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the application of IFRS that have a significant impact on the financial results of the Company. Actual results could differ from estimated amounts, and those differences may be material. Critical accounting policies and estimates are reviewed by the Company’s Audit Committee annually. The Company believes the following are the most critical accounting policies and estimates in preparing its consolidated financial statements. A) DEPLETION, DEPRECIATION AND AMORTIZATION AND IMPAIRMENT Exploration and evaluation (“E&E”) costs relating to activities to explore and evaluate crude oil and natural gas properties are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E assets are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined. Technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved reserves is made. The judgements associated with the estimation of proved reserves are described below in “Crude Oil and Natural Gas Reserves”. An alternative acceptable accounting method for E&E costs under IFRS 6 “Exploration for and Evaluation of Mineral Resources” is to charge exploratory dry holes and geological and geophysical exploration costs incurred after having obtained the legal rights to explore an area against net earnings in the period incurred rather than capitalizing to E&E assets. E&E assets are tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount, by comparing the relevant costs to the fair value of Cash Generating Units (“CGUs”), aggregated at the segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. The determination of the fair value of CGUs requires the use of assumptions and estimates including future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations, future development and production costs, discount rates and income taxes. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs. 47 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.Property, plant and equipment is measured at cost less accumulated depletion and depreciation and impairment provisions. Crude oil and natural gas properties in the Exploration and Production segments are depleted using the unit-of-production method over proved reserves, except for major components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with future estimated development expenditures required to develop proved reserves. Estimates of proved reserves have a significant impact on net earnings, as they are a key input to the calculation of depletion expense. The Company assesses property, plant and equipment for impairment discounted at rates currently ranging from 9.5% to 12% whenever events or changes in circumstances indicate that the carrying value of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low commodity prices for an extended period, significant downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the Company performs an impairment test related to the specific assets at the CGU level. CRUDE OIL AND NATURAL GAS RESERVES B) Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to many uncertainties, interpretations, and judgements. The Company expects that, over time, its reserve estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels, and may be affected by changes in commodity prices. Reserve estimates can have a significant impact on net earnings, as they are a key component in the calculation of depletion, depreciation and amortization and for determining potential asset impairment. For example, a revision to proved reserve estimates would result in a higher or lower depletion, depreciation and amortization charge to net earnings. Downward revisions to reserve estimates may also result in an impairment of E&E and property, plant and equipment carrying amounts as depletion, depreciation and amortization expense. C) ASSET RETIREMENT OBLIGATIONS The Company is required to recognize a liability for ARO associated with its property, plant and equipment. An ARO liability associated with the retirement of a tangible long-lived asset is recognized to the extent of a legal obligation resulting from an existing or enacted law, statute, ordinance or written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel. The ARO is based on estimated costs, taking into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site. Since these estimates are specific to the sites involved, there are many individual assumptions underlying the Company’s total ARO amount. These individual assumptions can be subject to change. The estimated present values of ARO related to long-term assets are recognized as a liability in the period in which they are incurred. The provision for the ARO is estimated by discounting the expected future cash flows to settle the ARO at the Company’s weighted average credit-adjusted risk-free interest rate, which is currently 5.9%. Subsequent to initial measurement, the ARO is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense whereas changes in discount rates or estimated future cash flows are capitalized to or derecognized from property, plant and equipment. Changes in estimates would impact accretion and depletion expense in net earnings. In addition, differences between actual and estimated costs to settle the ARO, timing of cash flows to settle the obligation and future inflation rates may result in gains or losses on the final settlement of the ARO. INCOME TAXES D) The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying value of assets and liabilities in the consolidated financial statements and their respective tax bases, using income tax rates substantively enacted as at the date of the balance sheet. Accounting for income taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes liabilities for potential tax audit issues based on assessments of whether additional taxes will likely be due. RISK MANAGEMENT ACTIVITIES E) 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. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions, the Company primarily relied on external, readily-observable quoted market inputs including crude oil and natural gas forward benchmark commodity prices and volatility, Canadian and United States forward interest rate yield curves, and Canadian and 48 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.United States foreign exchange rates, discounted to present value as appropriate. The carrying amount of a risk management liability is adjusted for the Company’s own credit risk. 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. PURCHASE PRICE ALLOCATIONS F) Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties, together with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future depletion, depreciation and amortization expense and impairment tests. The Company has made various assumptions in determining the fair values of the acquired assets and liabilities. The most significant assumptions and judgements relate to the estimation of the fair value of the crude oil and natural gas properties. To determine the fair value of these properties, the Company estimates crude oil and natural gas reserves. Reserve estimates are based on the work performed by the Company’s internal engineers and outside consultants. The judgements associated with these estimated reserves are described above in “Crude Oil and Natural Gas Reserves”. Estimates of future prices are based on prices derived from price forecasts among industry analysts and internal assessments. The Company applies estimated future prices to the estimated reserves quantities acquired, and estimates future operating and development costs, to arrive at estimated future net revenues for the properties acquired. SHARE-BASED COMPENSATION G) The Company has made various assumptions in estimating the fair values of stock options granted including expected volatility, expected exercise behavior and future forfeiture rates. At each period end, stock options outstanding are remeasured for subsequent changes in the fair value of the liability. ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers” to provide guidance on the recognition of revenue and cash flows arising from an entity’s contracts with customers, and related disclosures. The new standard replaces several existing standards related to recognition of revenue and states that revenue should be recognized as performance obligations related to the goods or services delivered are settled. IFRS 15 also provides revenue accounting guidance for contract modifications and multiple-element contracts and prescribes additional disclosure requirements. In 2015, the IASB deferred the effective date for the new standard to January 1, 2018. The new standard is required to be adopted retrospectively, with earlier adoption permitted. The Company is assessing the impact of IFRS 15 on its consolidated financial statements. In May 2014, the IASB issued an amendment to IFRS 11 “Joint Arrangements” to clarify the accounting treatment when an entity acquires interests in joint ventures and joint operations. The amendment requires these acquisitions to be accounted for as business combinations. This amendment is effective January 1, 2016 and is to be applied prospectively. Adoption of this amended standard is not expected to result in a significant impact to the Company’s consolidated financial statements. Effective January 1, 2014, the Company adopted the version of IFRS 9 “Financial Instruments” issued November 2013. In July 2014, the IASB issued amendments to IFRS 9 to include accounting guidance to assess and recognize impairment losses on financial assets based on an expected loss model. The amendments are effective January 1, 2018. The Company is assessing the impact of this amendment on its consolidated financial statements. Subsequent to December 31, 2015, the IASB issued IFRS 16 “Leases”, which provides guidance on accounting for leases. The new standard replaces IAS 17 “Leases” and related interpretations. IFRS 16 eliminates the distinction between operating leases and financing leases for lessees. The new standard is effective January 1, 2019 with, earlier adoption permitted providing that IFRS 15 has been adopted. The new standard is required to be applied retrospectively, with a policy alternative of restating comparative prior periods or recognizing the cumulative adjustment in opening retained earnings at the date of adoption. The Company is assessing the impact of this standard on its consolidated financial statements. CONTROL ENVIRONMENT The Company’s management, including the President and the Chief Financial Officer and Senior Vice-President, Finance, evaluated the effectiveness of disclosure controls and procedures as at December 31, 2015, and concluded that disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual filings and other reports filed with securities regulatory authorities in Canada and the United States is recorded, processed, summarized and reported within the time periods specified and such information is accumulated and communicated to the Company’s management to allow timely decisions regarding required disclosures. 49 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.The Company’s management also performed an assessment of internal control over financial reporting as at December 31, 2015, and concluded that internal control over financial reporting is effective. Further, there were no changes in the Company’s internal control over financial reporting during 2015 that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting. While the Company’s management believes that the Company’s disclosure controls and procedures and internal control over financial reporting provide a reasonable level of assurance they are effective, they recognize that all control systems have inherent limitations. Because of its inherent limitations, the Company’s control systems may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. OUTLOOK The Company continues to implement its strategy of maintaining a large portfolio of varied projects, which the Company believes will enable it, over an extended period of time, to provide consistent growth in production and create shareholder value. Annual budgets are developed, scrutinized throughout the year and revised if necessary in the context of targeted financial ratios, project returns, product pricing expectations, and balance in project risk and time horizons. The Company maintains a high ownership level and operatorship level in all of its properties and can therefore control the nature, timing and extent of capital expenditures in each of its project areas. Capital expenditures in 2016 are currently targeted to be as follows: 2016 $ 160 – 195 305 – 435 450 – 495 120 –140 10 – 16 25 –34 15 –20 $ 1,085 –1,335 50 – 60 1,180 410 – 460 250 – 290 $ 1,890 – 1,990 5 280 – 310 110 – 120 130 – 140 $ 2,415 – 2,565 $ 3,500 – 3,900 ($ millions) Exploration and Production North America natural gas and NGLs North America crude oil International crude oil Thermal In Situ Oil Sands Primrose and future Kirby South Kirby North Phase 1 Midstream and other Total Exploration and Production Oil Sands Mining and Upgrading Project Capital Directive 74 Phase 2B Phase 3 Owner’s Costs and Other Total Project Capital Technology and Phase 4 Sustaining capital Turnarounds and reclamation Capitalized interest and other Total Oil Sands Mining and Upgrading Total 50 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. SENSITIVITY ANALYSIS The following table is indicative of the annualized sensitivities of cash flow from operations and net earnings (loss) from changes in certain key variables. The analysis is based on business conditions and sales volumes during the fourth quarter of 2015, 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. Price changes Crude oil – WTI US$1.00/bbl Natural gas – AECO C$0.10/Mcf Volume changes Crude oil – 10,000 bbl/d Natural gas – 10 MMcf/d Foreign currency rate change $0.01 change in US$ (1) Including financial derivatives Interest rate change – 1% Cash flow from operations ($ millions) Cash flow from operations (per common share, basic) Net earnings ($ millions) Net earnings (per common share, basic) $ $ $ $ $ $ 198 $ 38 $ 72 $ 3 $ 0.18 $ 0.03 $ 0.07 $ – $ 194 $ 37 $ 27 $ – $ 78 – 81 $ 30 $ 0.07 $ 0.03 $ 9 $ 30 $ 0.18 0.03 0.02 – 0.01 0.03 (1) For details of financial instruments in place, refer to note 17 to the Company’s consolidated financial statements as at December 31, 2015. DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES Crude oil and NGLs (bbl/d) North America – Exploration and Production 432,419 375,040 397,892 395,008 399,982 390,814 343,699 Q1 Q2 Q3 Q4 2015 2014 2013 North America – Oil Sands Mining and Upgrading North Sea Offshore Africa Total Natural gas (MMcf/d) North America North Sea Offshore Africa Total Barrels of oil equivalent (BOE/d) 134,166 96,607 131,779 129,050 122,911 110,571 100,284 23,036 13,188 20,330 17,070 22,387 21,077 23,110 24,832 22,216 19,079 17,380 12,429 18,334 15,923 602,809 509,047 573,135 572,000 564,188 531,194 478,240 1,713 1,716 1,592 1,635 1,663 1,527 1,130 34 24 38 25 35 26 36 32 36 27 7 21 4 24 1,771 1,779 1,653 1,703 1,726 1,555 1,158 North America – Exploration and Production 718,050 660,975 663,260 667,504 677,270 645,227 531,961 North America – Oil Sands Mining and Upgrading North Sea Offshore Africa Total 134,166 96,607 131,779 129,050 122,911 110,571 100,284 28,692 17,145 26,737 21,228 28,195 25,467 29,135 30,111 28,191 23,529 18,629 15,983 19,029 19,888 898,053 805,547 848,701 855,800 851,901 790,410 671,162 51 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. PER UNIT RESULTS – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback Natural gas ($/Mcf) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback Barrels of oil equivalent ($/BOE) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback Q1 Q2 Q3 Q4 2015 2014 2013 $ 37.03 $ 53.09 $ 41.55 $ 33.90 $ 41.13 $ 77.04 $ 73.81 2.46 34.57 3.83 16.10 2.80 50.29 5.91 17.01 2.56 38.99 4.09 15.70 2.61 31.29 3.49 14.26 2.60 38.53 4.30 15.74 2.41 74.63 12.99 18.25 2.22 71.59 11.13 17.14 $ 14.64 $ 27.37 $ 19.20 $ 13.54 $ 18.49 $ 43.39 $ 43.32 $ 3.38 $ 3.06 $ 3.22 $ 2.96 $ 3.16 $ 4.83 $ 0.36 3.02 0.12 1.44 0.38 2.68 0.05 1.39 0.39 2.83 0.11 1.31 0.38 2.58 0.10 1.22 0.38 2.78 0.10 1.34 0.27 4.56 0.38 1.48 $ 1.46 $ 1.24 $ 1.41 $ 1.26 $ 1.34 $ 2.70 $ 3.58 0.28 3.30 0.18 1.42 1.70 $ 30.57 $ 38.85 $ 33.46 $ 27.79 $ 32.60 $ 58.48 $ 56.46 2.44 28.13 2.65 13.20 2.67 36.18 3.58 13.39 2.56 30.90 2.81 12.68 2.59 25.20 2.38 11.55 2.56 30.04 2.85 12.70 2.18 56.30 8.90 14.67 2.10 54.36 7.74 14.24 $ 12.28 $ 19.21 $ 15.41 $ 11.27 $ 14.49 $ 32.73 $ 32.38 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of blending costs and excluding risk management activities. PER UNIT RESULTS – OIL SANDS MINING AND UPGRADING Crude oil and NGLs ($/bbl) (1) SCO sales price Bitumen royalties (2) Transportation Q1 Q2 Q3 Q4 2015 2014 2013 $ 56.75 $ 73.05 $ 60.66 $ 57.49 $ 61.39 $ 100.27 $ 100.75 1.01 1.83 0.99 1.98 1.32 1.82 27.04 0.99 1.66 1.08 1.81 28.56 28.61 5.77 1.85 37.18 5.11 1.57 40.57 Adjusted cash production costs 29.73 29.25 Netback $ 24.18 $ 40.83 $ 30.48 $ 26.28 $ 29.89 $ 55.47 $ 53.50 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes. 52 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.TRADING AND SHARE STATISTICS TSX – C$ Trading volume (thousands) Share Price ($/share) High Low Close Market capitalization as at December 31 ($ millions) Shares outstanding (thousands) NYSE – US$ Trading volume (thousands) Share Price ($/share) High Low Close Market capitalization as at December 31 ($ millions) Shares outstanding (thousands) Q1 Q2 Q3 Q4 2015 2014 188,056 136,582 193,335 210,061 728,034 717,580 $ 40.80 $ 42.46 $ 34.01 $ 34.51 $ 42.46 $ $ 31.20 $ 33.61 $ 25.01 $ 25.32 $ 25.01 $ $ 38.82 $ 33.90 $ 25.99 $ 30.22 $ 30.22 $ 49.57 31.00 35.92 $ 33,081 $ 39,219 1,094,668 1,091,837 229,008 150,833 296,623 274,847 951,311 812,521 $ 32.57 $ 34.46 $ 27.23 $ 26.24 $ 34.46 $ $ 26.13 $ 26.93 $ 18.94 $ 19.12 $ 18.94 $ $ 30.71 $ 27.16 $ 19.45 $ 21.83 $ 21.83 $ 46.65 26.53 30.88 $ 23,897 $ 33,716 1,094,668 1,091,837 53 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. MANAGEMENT’S REPORT The accompanying consolidated financial statements and all other information contained elsewhere in this Annual Report are the responsibility of management. The consolidated financial statements have been prepared by management in accordance with the accounting policies described in the accompanying notes. Where necessary, management has made informed judgements and estimates in accounting for transactions that were not complete at the balance sheet date. In the opinion of management, the financial statements have been prepared in accordance with International Financial Reporting Standards appropriate in the circumstances. The financial information presented elsewhere in the Annual Report has been reviewed to ensure consistency with that in the consolidated financial statements. Management maintains appropriate systems of internal control. Policies and procedures are designed to give reasonable assurance that transactions are appropriately authorized and recorded, assets are safeguarded from loss or unauthorized use and financial records are properly maintained to provide reliable information for preparation of financial statements. PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, has been engaged, as approved by a vote of the shareholders at the Company’s most recent Annual General Meeting, to audit and provide their independent audit opinions on the following: ■■ ■■ the Company’s consolidated financial statements as at and for the year ended December 31, 2015; and the effectiveness of the Company’s internal control over financial reporting as at December 31, 2015. Their report is presented with the consolidated financial statements. The Board of Directors (the “Board”) is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal controls. The Board exercises this responsibility through the Audit Committee of the Board, which is comprised entirely of independent directors. The Audit Committee meets with management and the independent auditors to satisfy itself that management responsibilities are properly discharged and to review the consolidated financial statements before they are presented to the Board for approval. The consolidated financial statements have been approved by the Board on the recommendation of the Audit Committee. STEVE W. LAUT President Calgary, Alberta, Canada March 2, 2016 COREY B. BIEBER, CA Chief Financial Officer and Senior Vice-President, Finance MURRAY G. HARRIS, CA Vice-President, Financial Controller and Horizon Accounting 54 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a–15(f) and 15d–15(f) under the United States Securities Exchange Act of 1934, as amended. Management, including the Company’s President and the Company’s Chief Financial Officer and Senior Vice-President, Finance, performed an assessment of the Company’s internal control over financial reporting based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on the assessment, management has concluded that the Company’s internal control over financial reporting is effective as at December 31, 2015. Management recognizes that all internal control systems have inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, has provided an opinion on the Company’s internal control over financial reporting as at December 31, 2015, as stated in their Auditor’s Report. STEVE W. LAUT President COREY B. BIEBER, CA Chief Financial Officer and Senior Vice-President, Finance Calgary, Alberta, Canada March 2, 2016 55 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.INDEPENDENT AUDITOR’S REPORT TO THE SHAREHOLDERS OF CANADIAN NATURAL RESOURCES LIMITED We have completed integrated audits of Canadian Natural Resources Limited’s 2015, 2014, and 2013 consolidated financial statements and its internal control over financial reporting as at December 31, 2015. Our opinions, based on our audits are presented below. REPORT ON THE CONSOLIDATED FINANCIAL STATEMENTS We have audited the accompanying consolidated financial statements of Canadian Natural Resources Limited, which comprise the consolidated balance sheets as at December 31, 2015 and December 31, 2014 and the consolidated statements of earnings (loss), comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2015, and the related notes, which comprise a summary of significant accounting policies and other explanatory information. MANAGEMENT’S RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. AUDITOR’S RESPONSIBILITY Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing standards also require that we comply with ethical requirements. An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgement, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to Canadian Natural Resources Limited's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion on the consolidated financial statements. OPINION In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Canadian Natural Resources Limited as at December 31, 2015 and December 31, 2014 and its financial performance and its cash flows for each of the three years in the period ended December 31, 2015 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING We have also audited Canadian Natural Resources Limited’s internal control over financial reporting as at December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). MANAGEMENT’S RESPONSIBILITY FOR INTERNAL CONTROL OVER FINANCIAL REPORTING Management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. 56 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.AUDITOR’S RESPONSIBILITY Our responsibility is to express an opinion on Canadian Natural Resources Limited's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control, based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our audit opinion on Canadian Natural Resources Limited’s internal control over financial reporting. DEFINITION OF INTERNAL CONTROL OVER FINANCIAL REPORTING A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. INHERENT LIMITATIONS Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. OPINION In our opinion, Canadian Natural Resources Limited maintained, in all material respects, effective internal control over financial reporting as at December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO. Chartered Professional Accountants Calgary, Alberta, Canada March 2, 2016 57 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.Note 2015 2014 $ 69 $ 1,277 677 525 162 974 375 4,059 2,586 51,475 1,155 $ 59,275 $ $ 571 $ 2,089 1,729 206 4,595 15,065 2,890 9,344 31,894 4,541 22,765 75 27,381 $ 59,275 $ 4 7 8 5 6 8 9 10 9 10 11 12 13 25 1,889 228 665 172 – 510 3,489 3,557 52,480 674 60,200 564 3,279 980 319 5,142 13,022 4,175 8,970 31,309 4,432 24,408 51 28,891 60,200 CONSOLIDATED BALANCE SHEETS As at December 31 (millions of Canadian dollars) ASSETS Current assets Cash and cash equivalents Accounts receivable Current income taxes Inventory Prepaids and other Investment in PrairieSky Royalty Ltd. Current portion of other long-term assets Exploration and evaluation assets Property, plant and equipment Other long-term assets LIABILITIES Current liabilities Accounts payable Accrued liabilities Current portion of long-term debt Current portion of other long-term liabilities Long-term debt Other long-term liabilities Deferred income taxes SHAREHOLDERS’ EQUITY Share capital Retained earnings Accumulated other comprehensive income Commitments and contingencies (note 18). Approved by the Board of Directors on March 2, 2016 CATHERINE M. BEST Chair of the Audit Committee and Director N. MURRAY EDWARDS Executive Chairman of the Board of Directors and Director 58 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) For the years ended December 31 (millions of Canadian dollars, except per common share amounts) Product sales Less: royalties Revenue Expenses Production Transportation and blending Depletion, depreciation and amortization Administration Share-based compensation Asset retirement obligation accretion Interest and other financing expense Risk management activities Foreign exchange loss Gains on disposition of properties and corporate acquisitions Loss from investments Earnings (loss) before taxes Current income tax (recovery) expense Deferred income tax expense Net earnings (loss) Net earnings (loss) per common share Basic Diluted Note $ 2015 13,167 $ (804) 12,363 2014 21,301 $ (2,438) 18,863 4,726 2,379 5,483 390 (46) 173 322 (469) 761 (739) 50 13,030 (667) (261) 231 5,265 3,232 4,880 367 66 193 323 (800) 303 (137) 8 13,700 5,163 427 807 5, 6 10 10 16 17 5, 6 7, 8 11 11 $ (637) $ 3,929 $ 15 $ 15 $ (0.58) $ (0.58) $ 3.60 $ 3.58 $ 2013 17,945 (1,800) 16,145 4,559 2,938 4,844 335 135 171 279 (77) 210 (289) 4 13,109 3,036 735 31 2,270 2.08 2.08 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the years ended December 31 (millions of Canadian dollars) Net earnings (loss) Items that may be reclassified subsequently to net earnings Net change in derivative financial instruments designated as cash flow hedges Unrealized income (loss), net of taxes of $2 million (2014 – $nil, 2013 – $nil) Reclassification to net earnings (loss), net of taxes of $2 million (2014 – $1 million, 2013 – $nil) Foreign currency translation adjustment Translation of net investment Other comprehensive income (loss), net of taxes 2015 2014 $ (637) $ 3,929 $ 2013 2,270 (23) (13) (36) 60 24 5 8 13 (4) 9 (4) (1) (5) (11) (16) Comprehensive income (loss) $ (613) $ 3,938 $ 2,254 59 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY Note 12 2015 2014 $ 4,432 $ 3,854 $ 91 18 – 4,541 24,408 (637) – (1,006) 22,765 51 24 75 488 129 (39) 4,432 21,876 3,929 (414) (983) 24,408 42 9 51 2013 3,709 130 50 (35) 3,854 20,516 2,270 (285) (625) 21,876 58 (16) 42 $ 27,381 $ 28,891 $ 25,772 For the years ended December 31 (millions of Canadian dollars) Share capital Balance – beginning of year Issued upon exercise of stock options Previously recognized liability on stock options exercised for common shares Purchase of common shares under Normal Course Issuer Bid Balance – end of year Retained earnings Balance – beginning of year Net earnings (loss) Purchase of common shares under Normal Course Issuer Bid Dividends on common shares Balance – end of year Accumulated other comprehensive income Balance – beginning of year Other comprehensive income (loss), net of taxes Balance – end of year Shareholders’ equity 12 12 13 60 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31 (millions of Canadian dollars) Operating activities Net earnings (loss) Non-cash items Depletion, depreciation and amortization Share-based compensation Asset retirement obligation accretion Unrealized risk management loss (gain) Unrealized foreign exchange loss Realized foreign exchange loss (gain) on repayment of US dollar debt securities Loss from investments Deferred income tax expense Gains on disposition of properties and corporate acquisitions Current income tax on disposition of properties Other Abandonment expenditures Net change in non-cash working capital Financing activities Issue of bank credit facilities and commercial paper, net Issue of medium-term notes, net Issue (repayment) of US dollar debt securities, net Issue of common shares on exercise of stock options Purchase of common shares under Normal Course Issuer Bid Dividends on common shares Net change in non-cash working capital Investing activities Net proceeds (expenditures) on exploration and evaluation assets (1) Net expenditures on property, plant and equipment (1) Current income tax on disposition of properties Investment in other long-term assets Net change in non-cash working capital Increase (decrease) in cash and cash equivalents Cash and cash equivalents – beginning of year Cash and cash equivalents – end of year Interest paid, net Income taxes paid Note 2015 2014 2013 $ (637) $ 3,929 $ 2,270 5,483 (46) 173 374 858 – 55 231 (739) 33 (22) (370) 239 5,632 970 107 – 91 – (1,251) (40) (123) 236 (4,704) (33) (112) (852) 4,880 66 193 (451) 256 36 8 807 (137) – (38) (346) (744) 8,459 1,195 992 1,482 488 (453) (955) (22) 2,727 (1,190) (10,208) – (113) 334 7, 8 19 9 9 19 19 19 19 (5,465) (11,177) 44 25 69 $ 541 $ 42 $ 9 16 25 $ 521 $ 792 $ $ $ $ 4,844 135 171 39 226 (12) 4 31 (289) 58 (19) (207) (33) 7,218 803 98 (398) 130 (320) (523) (23) (233) 144 (7,211) (58) – 119 (7,006) (21) 37 16 460 357 (1) Net proceeds on exploration and evaluation assets and net expenditures on property, plant and equipment in 2015 exclude non-cash share consideration of $985 million received from PrairieSky Royalty Ltd. (“PrairieSky”) on the disposition of royalty income assets. 61 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (tabular amounts in millions of Canadian dollars, unless otherwise stated) 1. ACCOUNTING POLICIES Canadian Natural Resources Limited (the “Company”) is a senior independent crude oil and natural gas exploration, development and production company. The Company’s exploration and production operations are focused in North America, largely in Western Canada; the United Kingdom (“UK”) portion of the North Sea; and Côte d’Ivoire, Gabon, and South Africa in Offshore Africa. The Horizon Oil Sands Mining and Upgrading segment (“Horizon”) produces synthetic crude oil through bitumen mining and upgrading operations. Within Western Canada, the Company maintains certain midstream activities that include pipeline operations, an electricity co-generation system and an investment in the North West Redwater Partnership ("Redwater Partnership"), a general partnership formed in the Province of Alberta. The Company was incorporated in Alberta, Canada. The address of its registered office is 2100, 855 - 2 Street S.W., Calgary, Alberta, Canada. The Company’s consolidated financial statements and the related notes have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The accounting policies adopted by the Company under IFRS are set out below. The Company has consistently applied the same accounting policies throughout all periods presented, except where IFRS permits new accounting standards to be adopted prospectively. (A) PRINCIPLES OF CONSOLIDATION The consolidated financial statements have been prepared under the historical cost basis, unless otherwise required. The consolidated financial statements include the accounts of the Company and all of its subsidiary companies and wholly owned partnerships. Subsidiaries are all entities over which the Company has control. Subsidiaries are consolidated from the date on which the Company obtains control. They are deconsolidated from the date that control ceases. Certain of the Company’s activities are conducted through joint arrangements in which two or more parties have joint control. Where the Company has a direct ownership interest in jointly controlled assets and obligations for the liabilities (a “joint operation”), the assets, liabilities, revenue and expenses related to the joint operation are included in the consolidated financial statements in proportion to the Company’s interest. Where the Company has an interest in jointly controlled entities (a “joint venture”), it uses the equity method of accounting. Under the equity method, the Company’s initial and subsequent investments are recognized at cost and subsequently adjusted for the Company’s share of the joint venture’s income or loss, less distributions received. Joint ventures accounted for using the equity method of accounting are tested for impairment whenever objective evidence indicates that the carrying amount of the investment may not be recoverable. Indications of impairment include a history of losses, significant capital expenditure overruns, liquidity concerns, financial restructuring of the investee or significant adverse changes in the technological, economic or legal environment. The amount of the impairment is measured as the difference between the carrying amount of the investment and the higher of its fair value less costs of disposal and its value in use. Impairment losses are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized. (B) SEGMENTED INFORMATION Operating segments have been determined based on the nature of the Company’s activities and the geographic locations in which the Company operates, and are consistent with the level of information regularly provided to and reviewed by the Company’s chief operating decision makers. (C) CASH AND CASH EQUIVALENTS Cash comprises cash on hand and demand deposits. Other investments (term deposits and certificates of deposit) with an original term to maturity at purchase of three months or less are reported as cash equivalents in the consolidated balance sheets. INVENTORY (D) Inventory is primarily comprised of product inventory and materials and supplies. Product inventory is comprised of crude oil held for sale, including pipeline linefill and crude oil stored in floating production, storage and offloading vessels. Inventories are carried at the lower of cost and net realizable value. Cost consists of purchase costs, direct production costs, directly attributable overhead and depletion, depreciation and amortization and is determined on a first-in, first-out basis. Net realizable value for product inventory is determined by reference to forward prices, and for materials and supplies is based on current market prices as at the date of the consolidated balance sheets. 62 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.(E) EXPLORATION AND EVALUATION ASSETS Exploration and evaluation (“E&E”) assets consist of the Company’s crude oil and natural gas exploration projects that are pending the determination of proved reserves. E&E costs are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E costs do not include general prospecting or evaluation costs incurred prior to having obtained the legal rights to explore an area. These costs are recognized in net earnings. Once the technical feasibility and commercial viability of E&E assets are determined and a development decision is made by management, the E&E assets are tested for impairment upon reclassification to property, plant and equipment. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved reserves is made. An E&E asset is derecognized upon disposal or when no future economic benefits are expected to arise from its use. Any gain or loss arising on derecognition of the asset is recognized in net earnings within depletion, depreciation and amortization. E&E assets are also tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount, by comparing the relevant costs to the fair value of Cash Generating Units (“CGUs”), aggregated at the segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. (F) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is measured at cost less accumulated depletion and depreciation and impairment provisions. Assets under construction are not depleted or depreciated until available for their intended use. The capitalized value of a finance lease is included in property, plant and equipment. Exploration and Production The cost of an asset comprises its acquisition costs, construction and development costs, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Property acquisition costs are comprised of the aggregate amount paid and the fair value of any other consideration given to acquire the asset. When significant components of an item of property, plant and equipment, including crude oil and natural gas interests, have different useful lives, they are accounted for separately. Crude oil and natural gas properties are depleted using the unit-of-production method over proved reserves, except for major components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with future development expenditures required to develop proved reserves. Oil Sands Mining and Upgrading Capitalized costs for the Oil Sands Mining and Upgrading segment are reported separately from the Company’s North America Exploration and Production segment. Capitalized costs include acquisition costs, construction and development costs, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Mine-related costs are depleted using the unit-of-production method based on Horizon proved reserves. Costs of the upgrader and related infrastructure located on the Horizon site are depreciated on the unit-of-production method based on productive capacity of the upgrader and related infrastructure. Other equipment is depreciated on a straight-line basis over its estimated useful life ranging from 2 to 15 years. Midstream and Head Office The Company capitalizes all costs that expand the capacity or extend the useful life of the midstream and head office assets. Midstream assets are depreciated on a straight-line basis over their estimated useful lives ranging from 5 to 30 years. Head office assets are depreciated on a declining balance basis. Useful lives The depletion rates and expected useful lives of property, plant and equipment are reviewed on an annual basis, with changes in depletion rates and useful lives accounted for prospectively. Derecognition A property, plant and equipment asset is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is recognized in net earnings within depletion, depreciation and amortization. 63 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.Major maintenance expenditures Inspection costs associated with major maintenance turnarounds are capitalized and depreciated over the period to the next major maintenance turnaround. All other maintenance costs are expensed as incurred. Impairment The Company assesses property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low benchmark commodity prices for an extended period of time, significant downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the Company performs an impairment test related to the assets. Individual assets are grouped for impairment assessment purposes into CGUs, which are the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets. A CGU’s recoverable amount is the higher of its fair value less costs of disposal and its value in use. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount through depletion, depreciation and amortization expense. In subsequent periods, an assessment is made at each reporting date to determine whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the recoverable amount is re-estimated and the net carrying amount of the asset is increased to its revised recoverable amount. The revised recoverable amount cannot exceed the carrying amount that would have been determined, net of depletion, had no impairment loss been recognized for the asset in prior periods. A reversal of impairment is recognized in net earnings. After a reversal, the depletion charge is adjusted in future periods to allocate the asset’s revised carrying amount over its remaining useful life. BUSINESS COMBINATIONS (G) Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed in a business combination are recognized at their fair value at the date of the acquisition. Any excess of the consideration paid over the fair value of the net assets acquired is recognized as an asset. Any excess of the fair value of the net assets acquired over the consideration paid is recognized in net earnings. (H) OVERBURDEN REMOVAL COSTS Overburden removal costs incurred during the initial development of a mine at Horizon are capitalized to property, plant and equipment. Overburden removal costs incurred during the production of a mine are included in the cost of inventory, unless the overburden removal activity has resulted in a probable inflow of future economic benefits to the Company, in which case the costs are capitalized to property, plant and equipment. Capitalized overburden removal costs are depleted over the life of the mining reserves that directly benefit from the overburden removal activity. CAPITALIZED BORROWING COSTS (I) Borrowing costs attributable to the acquisition, construction or production of qualifying assets are capitalized to the cost of those assets until such time as the assets are substantially available for their intended use. Qualifying assets are comprised of those significant assets that require a period greater than one year to be available for their intended use. All other borrowing costs are recognized in net earnings. LEASES (J) Finance leases, which transfer substantially all of the risks and rewards incidental to ownership of the leased item to the Company, are capitalized at the commencement of the lease term at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term. Operating lease payments are recognized in net earnings over the lease term. (K) ASSET RETIREMENT OBLIGATIONS The Company provides for asset retirement obligations on all of its property, plant and equipment based on current legislation and industry operating practices. Provisions for asset retirement obligations related to property, plant and equipment are recognized as a liability in the period in which they are incurred. Provisions are measured at the present value of management’s best estimate of expenditures required to settle the obligation as at the date of the balance sheet. Subsequent to the initial measurement, the obligation is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense whereas changes due to discount rates or estimated future cash flows are capitalized to or derecognized from property, plant, and equipment. Actual costs incurred upon settlement of the asset retirement obligation are charged against the provision. (L) FOREIGN CURRENCY TRANSLATION Functional and presentation currency Items included in the financial statements of the Company’s subsidiary companies and partnerships are measured using the currency of the primary economic environment in which the subsidiary operates (the “functional currency”). The consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. 64 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.The assets and liabilities of subsidiaries that have a functional currency different from that of the Company are translated into Canadian dollars at the closing rate at the date of the balance sheet, and revenue and expenses are translated at the average rate for the period. Cumulative foreign currency translation adjustments are recognized in other comprehensive income. When the Company disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in other comprehensive income related to the foreign operation are recognized in net earnings. Transactions and balances Foreign currency transactions are translated into the functional currency of the Company and its subsidiaries and partnerships using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of foreign currency transactions and from the translation at balance sheet date exchange rates of monetary assets and liabilities denominated in currencies other than the functional currency are recognized in net earnings. (M) REVENUE RECOGNITION AND COSTS OF GOODS SOLD Revenue from the sale of crude oil and natural gas is recognized when title passes to the customer, delivery has taken place and collection is reasonably assured. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process. Revenue represents the Company’s share net of royalty payments to governments and other mineral interest owners. Related costs of goods sold are comprised of production, transportation and blending, and depletion, depreciation and amortization expenses. These amounts have been separately presented in the consolidated statements of earnings. (N) PRODUCTION SHARING CONTRACTS Production generated from Côte d’Ivoire and Gabon in Offshore Africa is shared under the terms of various Production Sharing Contracts (“PSCs”). Product sales are divided into cost recovery oil and profit oil. Cost recovery oil allows the Company to recover its capital and production costs and the costs carried by the Company on behalf of the respective Government State Oil Companies (the “Governments”). Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the Governments. The Governments’ share of profit oil attributable to the Company’s equity interest is allocated to royalty expense and current income tax expense in accordance with the terms of the respective PSCs. INCOME TAX (O) The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized based on the estimated tax effects of temporary differences in the carrying amount of assets and liabilities in the consolidated financial statements and their respective tax bases. Deferred income tax assets and liabilities are calculated using the substantively enacted income tax rates that are expected to apply when the asset or liability is recovered. Deferred income tax assets or liabilities are not recognized when they arise on the initial recognition of an asset or liability in a transaction (other than in a business combination) that, at the time of the transaction, affects neither accounting nor taxable profit. Deferred income tax assets or liabilities are also not recognized on possible future distributions of retained earnings of subsidiaries where the timing of the distribution can be controlled by the Company and it is probable that a distribution will not be made in the foreseeable future, or when distributions can be made without incurring income taxes. Deferred income tax assets for deductible temporary differences and tax loss carryforwards are recognized to the extent that it is probable that future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. The carrying amount of deferred income tax assets is reviewed at each reporting date, and is reduced if it is no longer probable that sufficient future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. Current income tax is calculated based on net earnings for the period, adjusted for items that are non-taxable or taxed in different periods, using income tax rates that are substantively enacted at each reporting date. Income taxes are recognized in net earnings or other comprehensive income, consistent with the items to which they relate. (P) SHARE-BASED COMPENSATION The Company’s Stock Option Plan (the “Option Plan”) provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered. The liability for awards granted to employees is initially measured based on the grant date fair value of the awards and the number of awards expected to vest. The awards are re-measured each reporting period for subsequent changes in the fair value of the liability. Fair value is determined using the Black-Scholes valuation model under a graded vesting method. Expected volatility is estimated based on historic results. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares under the Option Plan, consideration paid by the employee and any previously recognized liability associated with the stock options are recorded as share capital. The unamortized costs of employer contributions to the Company’s share bonus program are included in other long-term assets. 65 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.(Q) FINANCIAL INSTRUMENTS The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost; financial liabilities at amortized cost; and fair value through profit or loss. All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. Fair value through profit or loss financial instruments are subsequently measured at fair value with changes in fair value recognized in net earnings. All other categories of financial instruments are measured at amortized cost using the effective interest method. Cash, cash equivalents, accounts receivable and certain other long-term assets are classified as financial assets at amortized cost since it is the Company’s intention to hold these assets to maturity and the related cash flows are mainly payments of principal and interest. Investments in publicly traded shares are classified as fair value through profit or loss. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as financial liabilities at amortized cost. Risk management assets and liabilities are classified as fair value through profit or loss. Financial assets and liabilities are also categorized using a three-level hierarchy that reflects the significance of the inputs used in making fair value measurements for these assets and liabilities. The fair values of financial assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair values of financial assets and liabilities in Level 2 are based on inputs other than Level 1 quoted prices that are observable for the asset or liability either directly (as prices) or indirectly (derived from prices). The fair values of Level 3 financial assets and liabilities are not based on observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value approximates fair value due to the liquid nature of the asset or liability. Transaction costs in respect of financial instruments at fair value through profit or loss are recognized in net earnings. Transaction costs in respect of other financial instruments are included in the initial measurement of the financial instrument. Impairment of financial assets At each reporting date, the Company assesses whether there is objective evidence that a financial asset is impaired. If such evidence exists, an impairment loss is recognized. Impairment losses on financial assets carried at amortized cost are calculated as the difference between the amortized cost of the financial asset and the present value of the estimated future cash flows, discounted using the instrument’s original effective interest rate. Impairment losses on financial assets carried at amortized cost are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized. (R) RISK MANAGEMENT ACTIVITIES The Company periodically 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. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. 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 carrying amount of a risk management liability is adjusted for the Company’s own credit risk. The Company documents all derivative financial instruments that are formally designated as hedging transactions at the inception of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the hedging relationship is evaluated, both at inception of the hedge and on an ongoing basis. The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil and natural gas in order to protect its cash flow for its capital expenditure programs. The effective portion of changes in the fair value of derivative commodity price contracts formally designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to risk management activities in net earnings in the same period or periods in which the commodity is sold or purchased. The ineffective portion of changes in the fair value of these designated contracts is recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural gas commodity price contracts are recognized in risk management activities in net earnings. The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on certain of its 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. Changes in the fair value of interest rate swap contracts designated as fair value hedges and corresponding changes in the fair value of the hedged long-term debt are recognized in interest expense in net earnings. Changes in the fair value of non-designated interest rate swap contracts are recognized in risk management activities in net earnings. 66 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt. 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. Changes in the fair value of the foreign exchange component of cross currency swap contracts designated as cash flow hedges related to the notional principal amounts are recognized in foreign exchange gains and losses in net earnings. The effective portion of changes in the fair value of the interest rate component of cross currency swap contracts designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to interest expense when the hedged item is recognized in net earnings, with the ineffective portion recognized in risk management activities in net earnings. Changes in the fair value of non-designated cross currency swap contracts are recognized in risk management activities in net earnings. Realized gains or losses on the termination of financial instruments that have been designated as cash flow hedges are deferred under accumulated other comprehensive income and amortized into net earnings in the period in which the underlying hedged items are recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized derivative gain or loss is recognized in net earnings. Realized gains or losses on the termination of financial instruments that have not been designated as hedges are recognized in net earnings. Upon termination of an interest rate swap designated as a fair value hedge, the interest rate swap is derecognized in the consolidated balance sheets and the related long-term debt hedged is no longer revalued for subsequent changes in fair value due to interest rates changes. The fair value adjustment due to interest rates on the long-term debt at the date of termination of the interest rate swap is amortized to interest expense over the remaining term of the long-term debt. Foreign currency forward contracts are periodically used to manage foreign currency cash requirements. The foreign currency forward contracts involve the purchase or sale of an agreed upon amount of US dollars at a specified future date at forward exchange rates. Changes in the fair value of foreign currency forward contracts designated as cash flow hedges are initially recorded in other comprehensive income and are reclassified to foreign exchange gains and losses when the hedged item is recognized in net earnings. Changes in the fair value of non-designated foreign currency forward contracts are recognized in risk management activities in net earnings. Embedded derivatives are derivatives that are included in a non-derivative host contract. Embedded derivatives are recorded at fair value separately from the host contract when their economic characteristics and risks are not clearly and closely related to the host contract, except when the host contract is an asset. (S) COMPREHENSIVE INCOME Comprehensive income is comprised of the Company’s net earnings and other comprehensive income. Other comprehensive income includes the effective portion of changes in the fair value of derivative financial instruments designated as cash flow hedges and foreign currency translation gains and losses arising from the net investment in foreign operations that do not have a Canadian dollar functional currency. Other comprehensive income is shown net of related income taxes. (T) PER COMMON SHARE AMOUNTS The Company calculates basic earnings per common share by dividing net earnings by the weighted average number of common shares outstanding during the period. As the Company’s Option Plan allows for the settlement of stock options in either cash or shares at the option of the holder, diluted earnings per common share is calculated using the more dilutive of cash settlement or share settlement under the treasury stock method. (U) SHARE CAPITAL Common shares are classified as equity. Costs directly attributable to the issue of new shares or options are included in equity as a deduction from proceeds, net of tax. When the Company acquires its own common shares, share capital is reduced by the average carrying value of the shares purchased. The excess of the purchase price over the average carrying value is recognized as a reduction of retained earnings. Shares are cancelled upon purchase. (V) DIVIDENDS Dividends on common shares are recognized in the Company’s financial statements in the period in which the dividends are declared by the Board of Directors. 2. ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers” to provide guidance on the recognition of revenue and cash flows arising from an entity’s contracts with customers, and related disclosures. The new standard replaces several existing standards related to recognition of revenue and states that revenue should be recognized as performance obligations related to the goods or services delivered are settled. IFRS 15 also provides revenue accounting guidance for contract modifications and multiple-element contracts and prescribes additional disclosure requirements. In 2015, the IASB deferred the effective date for the new standard to January 1, 2018. The new standard is required to be adopted retrospectively, with earlier adoption permitted. The Company is assessing the impact of IFRS 15 on its consolidated financial statements. In May 2014, the IASB issued an amendment to IFRS 11 “Joint Arrangements” to clarify the accounting treatment when an entity acquires interests in joint ventures and joint operations. The amendment requires these acquisitions to be accounted 67 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.for as business combinations. This amendment is effective January 1, 2016 and is to be applied prospectively. Adoption of this amended standard is not expected to result in a significant impact to the Company’s consolidated financial statements. Effective January 1, 2014, the Company adopted the version of IFRS 9 “Financial Instruments” issued November 2013. In July 2014, the IASB issued amendments to IFRS 9 to include accounting guidance to assess and recognize impairment losses on financial assets based on an expected loss model. The amendments are effective January 1, 2018. The Company is assessing the impact of this amendment on its consolidated financial statements. Subsequent to December 31, 2015, the IASB issued IFRS 16 “Leases”, which provides guidance on accounting for leases. The new standard replaces IAS 17 “Leases” and related interpretations. IFRS 16 eliminates the distinction between operating leases and financing leases for lessees. The new standard is effective January 1, 2019 with earlier adoption permitted providing that IFRS 15 has been adopted. The new standard is required to be applied retrospectively, with a policy alternative of restating comparative prior periods or recognizing the cumulative adjustment in opening retained earnings at the date of adoption. The Company is assessing the impact of this standard on its consolidated financial statements. 3. CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS The Company has made estimates, assumptions and judgements regarding certain assets, liabilities, revenues and expenses in the preparation of the consolidated financial statements, primarily related to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts. The estimates, assumptions and judgements that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below. (A) CRUDE OIL AND NATURAL GAS RESERVES Purchase price allocations, depletion, depreciation and amortization, and amounts used in impairment calculations are based on estimates of crude oil and natural gas reserves. Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to many uncertainties, interpretations and judgements. The Company expects that, over time, its reserve estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels, and may be affected by changes in commodity prices. (B) ASSET RETIREMENT OBLIGATIONS The Company provides for asset retirement obligations on its property, plant and equipment based on current legislation and operating practices. Estimated future costs include assumptions of dates of future abandonment and technological advances and estimates of future inflation rates and discount rates. Actual costs may vary from the estimated provision due to changes in environmental legislation, the impact of inflation, changes in technology, changes in operating practices, and changes in the date of abandonment due to changes in reserve life. These differences may have a material impact on the estimated provision. INCOME TAXES (C) The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes liabilities for potential tax audit issues based on assessments of whether additional taxes will likely be due. (D) FAIR VALUE OF DERIVATIVES AND OTHER FINANCIAL INSTRUMENTS The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The Company uses its judgement to select a variety of methods and make assumptions that are primarily based on market conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in measuring the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility, interest rate yield curves and foreign exchange rates. (E) PURCHASE PRICE ALLOCATIONS Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties together with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future depletion, depreciation, and amortization expense and impairment tests. (F) SHARE-BASED COMPENSATION The Company has made various assumptions in estimating the fair values of the stock options granted under the Option Plan, including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding are remeasured for changes in the fair value of the liability. 68 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.IDENTIFICATION OF CGUs (G) CGUs are defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into CGUs requires significant judgement and interpretations with respect to the integration between assets, the existence of active markets, shared infrastructures, and the way in which management monitors the Company’s operations. IMPAIRMENT OF ASSETS (H) The recoverable amount of a CGU or an individual asset has been determined as the higher of the CGU’s or the asset’s fair value less costs of disposal and its value in use. These calculations require the use of estimates and assumptions and are subject to change as new information becomes available, including information on future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations, future development and operating costs, after-tax discount rates currently ranging from 9.5% to 12%, and income taxes. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs. CONTINGENCIES (I) Contingencies are subject to measurement uncertainty as the related financial impact will only be confirmed by the outcome of a future event. The assessment of contingencies requires the application of judgements and estimates including the determination of whether a present obligation exists and the reliable estimation of the timing and amount of cash flows required to settle the contingency. 4. INVENTORY Product inventory Materials and supplies $ $ 2015 186 $ 339 525 $ 2014 332 333 665 As a result of a decline in crude oil prices, the Company recorded a write-down of its product inventory of $174 million from cost to net realizable value as at December 31, 2015 (2014 – $70 million). 69 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.5. EXPLORATION AND EVALUATION ASSETS Cost At December 31, 2013 Additions Transfers to property, plant and equipment Foreign exchange adjustments At December 31, 2014 Additions Transfers to property, plant and equipment Disposals/derecognitions (1) Foreign exchange adjustments Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading $ 2,570 $ – $ 39 $ – $ 1,103 (247) – 3,426 132 (567) (491) – – – – – – – – 87 – 5 131 35 – (96) 16 – – – – – – – Total 2,609 1,190 (247) 5 3,557 167 (567) (587) 16 At December 31, 2015 $ 2,500 $ – $ 86 $ – $ 2,586 (1) Refer to note 6 regarding the disposition of exploration and evaluation assets in the North America segment. In connection with the Company’s notice of withdrawal from Block CI-514 in Côte d’Ivoire, Offshore Africa in 2015, the Company derecognized $96 million of exploration and evaluation assets. During 2013, the Company disposed of a 50% interest in its exploration right in South Africa, for net cash consideration of US$255 million, including a recovery of US$14 million of past incurred costs, resulting in a pre-tax gain on sale of exploration and evaluation property of $224 million ($166 million after-tax). In the event that a commercial crude oil or natural gas discovery occurs on this exploration right, resulting in the exploration right being converted into a production right, an additional cash payment would be due to the Company at such time, amounting to US$450 million for a commercial crude oil discovery and US$120 million for a commercial natural gas discovery. 70 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. 6. PROPERTY, PLANT AND EQUIPMENT Oil Sands Mining and Upgrading Midstream Head Office Total Exploration and Production North America North Sea Offshore Africa Cost At December 31, 2013 $ 53,810 $ 5,200 $ 3,356 $ 19,366 $ 508 $ 308 $ 82,548 6,858 486 193 2,728 Additions Transfers from E&E assets Disposals/derecognitions Foreign exchange adjustments and other At December 31, 2014 Additions Transfers from E&E assets Disposals/derecognitions 247 (309) – 60,606 691 567 (1,324) – – 496 6,182 13 – – – – 309 3,858 524 – – Foreign exchange adjustments and other – 1,219 791 – (146) – 21,948 2,523 – (128) – 62 – – – 570 7 – – – 45 – (1) – 352 26 – – – 10,372 247 (456) 805 93,516 3,784 567 (1,452) 2,010 At December 31, 2015 $ 60,540 $ 7,414 $ 5,173 $ 24,343 $ 577 $ 378 $ 98,425 Accumulated depletion and depreciation At December 31, 2013 $ 28,315 $ 3,467 $ 2,551 $ 1,414 $ 111 $ 203 $ 36,061 Expense Disposals/derecognitions Foreign exchange adjustments and other At December 31, 2014 Expense Disposals/derecognitions Foreign exchange adjustments and other 3,880 (309) – 31,886 4,226 (758) (7) 265 – 317 4,049 383 – 832 105 – 234 596 (146) – 2,890 1,864 177 – 592 562 (128) (4) 9 – – 120 12 – – 25 (1) – 227 27 – – 4,880 (456) 551 41,036 5,387 (886) 1,413 At December 31, 2015 Net book value – at December 31, 2015 – at December 31, 2014 $ 35,347 $ 5,264 $ 3,659 $ 2,294 $ 132 $ 254 $ 46,950 $ 25,193 $ 2,150 $ 1,514 $ 22,049 $ $ 28,720 $ 2,133 $ 968 $ 20,084 $ 445 $ 450 $ 124 $ 51,475 125 $ 52,480 Project costs not subject to depletion and depreciation Horizon Kirby Thermal Oil Sands – North 2015 2014 6,017 $ 5,492 816 $ 681 $ $ During 2015, the Company acquired a number of producing crude oil and natural gas properties in the North America Exploration and Production segment, including exploration and evaluation assets of $37 million, for net cash consideration of $406 million (2014 – $3,753 million; 2013 – $252 million). These transactions were accounted for using the acquisition method of accounting. In connection with these acquisitions, the Company assumed associated asset retirement obligations of $133 million (2014 – $404 million; 2013 – $131 million), other long-term liabilities of $nil (2014 – $49 million; 2013 – $nil) and recognized net deferred income tax assets of $nil (2014 – $91 million; 2013 – $75 million) related to temporary differences in the carrying amount of certain of the acquired properties and their tax bases. No debt obligations were assumed and no working capital was acquired (2014 – $28 million; 2013 – $nil). No pre-tax gains were recognized on these acquisitions in 2015 (2014 – $137 million; 2013 – $65 million). On December 16, 2015, the Company disposed of a number of North America royalty income assets, including exploration and evaluation assets of $488 million and property, plant and equipment of $480 million, for total consideration of $1,658 million, resulting in a pre-tax gain on sale of properties of $690 million. Total consideration on the disposition was comprised of $673 million in cash, together with $985 million of non-cash share consideration of approximately 44.4 million common shares of PrairieSky Royalty Ltd. (“PrairieSky”) with a value of $22.16 per common share, determined as of the closing date. The cash consideration received on the disposition is an estimate, and may be subject to change based on the receipt of new information. 71 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. In addition, during 2015 the Company disposed of a number of North America crude oil and natural gas properties, including exploration and evaluation assets of $3 million and property, plant and equipment of $86 million, for total cash consideration of $134 million, together with associated asset retirement obligations of $4 million, resulting in a pre-tax gain on sale of properties of $49 million. As at December 31, 2015, the Company assessed the recoverability of its property, plant and equipment and its exploration and evaluation assets, and determined the carrying amounts to be recoverable. The Company capitalizes construction period interest for qualifying assets based on costs incurred and the Company’s cost of borrowing. Interest capitalization to a qualifying asset ceases once the asset is substantially available for its intended use. During 2015, pre-tax interest of $244 million (2014 – $204 million; 2013 – $175 million) was capitalized to property, plant and equipment using a weighted average capitalization rate of 3.9% (2014 – 3.9%; 2013 – 4.4%). 7. INVESTMENT IN PRAIRIESKY ROYALTY LTD. On December 16, 2015, as partial consideration for the disposal of a number of North America royalty income assets, the Company received non-cash share consideration of $985 million, comprised of approximately 44.4 million common shares of PrairieSky, at $22.16 per common share determined as of the closing date (refer to Note 6). PrairieSky is in the business of acquiring and managing oil and gas royalty income assets through indirect third-party oil and gas development. As the Company’s investment constitutes less than 20% of the outstanding shares of PrairieSky, the investment is accounted for at fair value through profit or loss and is remeasured at each reporting date. As at December 31, 2015, the Company’s investment in PrairieSky of $974 million has been classified as a current asset. Subject to certain conditions, including applicable regulatory and/or Shareholder approvals, the Company has agreed with PrairieSky that, by no later than December 31, 2016, it will distribute sufficient common shares of PrairieSky to the Company’s shareholders so that the Company, after such distribution, will hold less than 10% of the issued and outstanding common shares of PrairieSky. The loss from investment related to PrairieSky was comprised as follows: 2015 2014 2013 Fair value loss from PrairieSky Dividend income from PrairieSky 8. OTHER LONG-TERM ASSETS Investment in North West Redwater Partnership North West Redwater Partnership subordinated debt (1) Risk Management (note 17) Other Less: current portion (1) Includes accrued interest. $ $ 11 $ (5) 6 $ – $ – – $ $ 2015 254 $ 254 854 168 1,530 375 $ 1,155 $ – – – 2014 298 120 599 167 1,184 510 674 The Company’s 50% interest in Redwater Partnership is accounted for using the equity method based on Redwater Partnership’s voting and decision-making structure and legal form. Redwater Partnership has entered into agreements to construct and operate a 50,000 barrel per day bitumen upgrader and refinery (the "Project") under processing agreements that target to process 12,500 barrels per day of bitumen feedstock for the Company and 37,500 barrels per day of bitumen feedstock for the Alberta Petroleum Marketing Commission (“APMC”), an agent of the Government of Alberta, under a 30 year fee-for-service tolling agreement. During 2013, the Company, along with APMC, each committed to provide funding up to $350 million by January 2016 in the form of subordinated debt bearing interest at prime plus 6%. During 2015, the Company and APMC each provided $112 million of subordinated debt (2014 – $113 million, 2013 – $nil). Subsequent to December 31, 2015, the Company and APMC each provided an additional $99 million in subordinated debt. Should final Project costs exceed the revised cost estimate, the Company and APMC have agreed, subject to the Company being able to meet certain funding conditions, to fund any shortfall in available third party commercial lending required to attain Project completion. 72 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.During 2015, Redwater Partnership issued $500 million of 2.10% series C senior secured bonds due February 2022, $500 million of 3.70% series D senior secured bonds due February 2043, $500 million of 3.20% series E senior secured bonds due April 2026, and $300 million of senior secured bonds through the reopening of its previously issued 4.05% series B senior secured bonds due July 2044. Subsequent to December 31, 2015, Redwater Partnership issued $550 million of 4.25% series F senior secured bonds due June 2029, and $300 million of 4.75% series G senior secured bonds due June 2037. During 2014, Redwater Partnership issued $500 million of 3.20% series A senior secured bonds due July 2024 and $500 million of 4.05% series B senior secured bonds due July 2044. During 2014, Redwater Partnership also executed a $3,500 million syndicated credit facility with a group of financial institutions maturing June 2018 and repaid and cancelled its $1,200 million credit facility previously in place. As at December 31, 2015, Redwater Partnership had borrowings of $1,417 million under its secured $3,500 million syndicated credit facility. Under its processing agreement, beginning on the earlier of the commercial operations date of the refinery and June 1, 2018, the Company is unconditionally obligated to pay its 25% pro rata share of the debt portion of the monthly cost of service toll, including interest, fees and principal repayments, of the syndicated credit facility and bonds, over the tolling period of 30 years. Redwater Partnership has entered into various agreements related to the engineering, procurement and construction of the Project. These contracts can be cancelled by Redwater Partnership upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation. The assets, liabilities, partners’ equity and equity loss related to Redwater Partnership and the Company’s 50% interest at December 31, 2015 were comprised as follows: 2015 Redwater Partnership Company 2014 Redwater Partnership Company 50% interest 100% interest 50% interest Current assets Non-current assets Current liabilities Non-current liabilities Partners’ equity Equity loss 100% interest $ 138 $ $ $ $ $ $ 5,834 $ 678 $ 4,786 $ 508 $ 88 $ 69 $ 2,917 $ 339 $ 2,393 $ 254 $ 44 $ 132 $ 3,062 $ 454 $ 2,144 $ 596 $ 16 $ 66 1,531 227 1,072 298 8 73 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. 9. LONG-TERM DEBT Canadian dollar denominated debt, unsecured Bank credit facilities Medium-term notes 4.95% debentures due June 1, 2015 3.05% debentures due June 19, 2019 2.60% debentures due December 3, 2019 2.89% debentures due August 14, 2020 3.55% debentures due June 3, 2024 US dollar denominated debt, unsecured Bank credit facilities (December 31, 2015 – US$657 million; December 31, 2014 – $nil) Commercial paper (US$500 million) US dollar debt securities Three-month LIBOR plus 0.375% due March 30, 2016 (US$500 million) 6.00% due August 15, 2016 (US$250 million) 5.70% due May 15, 2017 (US$1,100 million) 1.75% due January 15, 2018 (US$600 million) 5.90% due February 1, 2018 (US$400 million) 3.45% due November 15, 2021 (US$500 million) 3.80% due April 15, 2024 (US$500 million) 3.90% due February 1, 2025 (US$600 million) 7.20% due January 15, 2032 (US$400 million) 6.45% due June 30, 2033 (US$350 million) 5.85% due February 1, 2035 (US$350 million) 6.50% due February 15, 2037 (US$450 million) 6.25% due March 15, 2038 (US$1,100 million) 6.75% due February 1, 2039 (US$400 million) Long-term debt before transaction costs and original issue discounts, net Less: original issue discounts, net (1) transaction costs (1) (2) Less: current portion of commercial paper current portion of long-term debt (1) (2) 2015 2014 $ 2,385 $ 2,404 – 500 500 1,000 500 4,885 909 692 692 346 1,523 830 554 692 692 830 554 484 484 622 1,523 554 11,981 16,866 (10) (62) 16,794 692 1,037 400 500 500 500 500 4,804 – 580 580 290 1,276 696 464 580 580 696 464 406 406 523 1,276 464 9,281 14,085 (21) (62) 14,002 580 400 (1) The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the outstanding debt. (2) 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. BANK CREDIT FACILITIES AND COMMERCIAL PAPER As at December 31, 2015, the Company had in place bank credit facilities of $7,481 million available for general corporate purposes, comprised of: $ 15,065 $ 13,022 a $100 million demand credit facility; a $1,000 million non-revolving term credit facility maturing January 2017; a $1,500 million non-revolving term credit facility maturing April 2018; a $2,425 million revolving syndicated credit facility maturing June 2019; a $2,425 million revolving syndicated credit facility maturing June 2020; and, a £15 million demand credit facility related to the Company’s North Sea operations. ■■ ■■ ■■ ■■ ■■ ■■ 74 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. During 2015, the previously existing $1,500 million revolving syndicated credit facility was increased to $2,425 million and the maturity date was extended to June 2019 from June 2016. The previously existing $3,000 million revolving syndicated credit facility was reduced to $2,425 million and the maturity date was extended to June 2020 from June 2017. Each of the $2,425 million revolving facilities is extendible annually 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 may be made by way of pricing referenced to Canadian dollar or US dollar bankers’ acceptances, or LIBOR, US base rate or Canadian prime loans. During 2015, the $1,000 million non-revolving term credit facility originally maturing March 2016 was extended to January 2017. The facility was fully drawn as at December 31, 2015. Borrowings under this facility may be made by way of pricing referenced to Canadian dollar bankers’ acceptances or Canadian prime loans. Subsequent to December 31, 2015, the Company prepaid $250 million of the borrowings then outstanding and extended the facility to February 2019 from January 2017. Subsequent to December 31, 2015, the Company also entered into a new $125 million non-revolving term credit facility maturing February 2019, which was fully drawn. Borrowings under this facility may be made by way of pricing referenced to Canadian dollar bankers’ acceptances or Canadian prime loans. In addition, during 2015, the Company entered into a new $1,500 million non-revolving credit facility maturing April 2018. Borrowings under this facility may be made by way of pricing referenced to Canadian dollar or US dollar bankers’ acceptances, or LIBOR, US base rate or Canadian prime loans. The facility was fully drawn as at December 31, 2015. During 2015, all of the Company’s credit facilities became subject to a revised financial covenant that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 0.65 to 1.0. The Company’s borrowings under its US commercial paper program are authorized up to a maximum US$2,500 million. The Company reserves capacity under its bank credit facilities for amounts outstanding under this program. The Company’s weighted average interest rate on bank credit facilities and commercial paper outstanding as at December 31, 2015, was 1.7% (December 31, 2014 – 2.2%), and on long-term debt outstanding for the year ended December 31, 2015 was 3.9% (December 31, 2014 – 3.9%). At December 31, 2015 letters of credit and guarantees aggregating $335 million, including a $39 million financial guarantee related to Horizon and $175 million of letters of credit related to North Sea operations, were outstanding. The letters of credit are supported by dedicated credit facilities. MEDIUM-TERM NOTES During 2015, the Company issued $500 million of series 2 medium-term notes, due August 2020, through the reopening of its previously issued 2.89% notes under a previous base shelf prospectus and repaid $400 million of 4.95% medium term notes. In October 2015, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada, which expires in November 2017. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance. During 2014, the Company issued $500 million of 2.60% medium-term notes due December 2019 and $500 million of 3.55% medium-term notes due June 2024. US DOLLAR DEBT SECURITIES In October 2015, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to US$3,000 million of debt securities in the United States, which expires in November 2017. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance. During 2014, the Company issued US$500 million of three-month LIBOR plus 0.375% notes due March 2016, and concurrently entered into cross currency swaps to fix the foreign currency exchange rate risk at three-month CDOR plus 0.309% and $555 million (note 17). In addition, the Company issued US$500 million of 3.80% notes due April 2024, US$600 million of 1.75% notes due January 2018, and US$600 million of 3.90% notes due February 2025. In addition, the Company repaid US$500 million of 1.45% notes and US$350 million of 4.90% notes. 75 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.SCHEDULED DEBT REPAYMENTS Scheduled debt repayments are as follows: Year 2016 2017 2018 2019 2020 Thereafter 10. OTHER LONG-TERM LIABILITIES Asset retirement obligations Share-based compensation Other Less: current portion $ $ $ $ $ $ 2015 $ 2,950 $ 128 18 3,096 206 $ 2,890 $ Repayment 1,730 2,522 2,899 1,353 1,427 6,935 2014 4,221 203 70 4,494 319 4,175 ASSET RETIREMENT OBLIGATIONS The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and have been discounted using a weighted average discount rate of 5.9% (2014 – 4.6%; 2013 – 5.0%). Reconciliations of the discounted asset retirement obligations were as follows: Balance – beginning of year Liabilities incurred Liabilities acquired, net Liabilities settled Asset retirement obligation accretion Revision of cost, inflation rates and timing estimates Change in discount rate Foreign exchange adjustments Balance – end of year Less: current portion SEGMENTED ASSET RETIREMENT OBLIGATIONS Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream 2015 2014 $ 4,221 $ 4,162 $ 7 129 (370) 173 (313) (1,150) 253 2,950 101 41 404 (346) 193 (907) 558 116 4,221 121 $ 2,849 $ 4,100 $ 2015 $ 1,114 $ 975 266 594 1 2013 4,266 62 131 (207) 171 375 (723) 87 4,162 – 4,162 2014 2,012 1,169 255 783 2 $ 2,950 $ 4,221 76 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.SHARE-BASED COMPENSATION As the Company’s Option Plan provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered, a liability for potential cash settlements is recognized. The current portion represents the maximum amount of the liability payable within the next twelve month period if all vested stock options are surrendered for cash settlement. Balance – beginning of year Share-based compensation (recovery) expense Cash payment for stock options surrendered Transferred to common shares (Recovered from) capitalized to Oil Sands Mining and Upgrading Balance – end of year Less: current portion $ 2015 203 $ 2014 260 $ (46) (1) (18) (10) 128 105 66 (8) (129) 14 203 158 $ 23 $ 45 $ 2013 154 135 (4) (50) 25 260 216 44 The share-based compensation liability of $128 million at December 31, 2015 (2014 – $203 million; 2013 – $260 million) was estimated using the Black-Scholes valuation model with the following weighted average assumptions: Fair value Share price Expected volatility Expected dividend yield Risk free interest rate Expected forfeiture rate Expected stock option life (1) (1) At original time of grant. $ $ 2015 3.06 $ 30.22 $ 2014 5.51 $ 35.92 $ 28.6% 3.0% 0.6% 4.8% 4.5 years 25.1% 2.5% 1.2% 4.7% 4.5 years 2013 7.08 35.94 27.2% 2.2% 1.5% 4.6% 4.5 years The intrinsic value of vested stock options at December 31, 2015 was $10 million (2014 – $40 million; 2013 – $72 million). 11. INCOME TAXES The provision for income tax was as follows: Current corporate income tax expense – North America $ Current corporate income tax (recovery) expense – North Sea Current corporate income tax expense – Offshore Africa (1) Current PRT(2) recovery – North Sea Other taxes Current income tax (recovery) expense Deferred corporate income tax expense Deferred PRT(2) expense (recovery) – North Sea Deferred income tax expense Income tax (recovery) expense (1) Includes current income taxes relating to disposition of properties in 2013. (2) Petroleum Revenue Tax. 2015 86 $ 2014 702 $ (117) 17 (258) 11 (261) 216 15 231 (68) 43 (273) 23 427 681 126 807 $ (30) $ 1,234 $ 2013 544 23 202 (56) 22 735 163 (132) 31 766 77 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. The provision for income tax is different from the amount computed by applying the combined statutory Canadian federal and provincial income tax rates to earnings before taxes. The reasons for the difference are as follows: Canadian statutory income tax rate Income tax provision at statutory rate Effect on income taxes of: UK PRT and other taxes Impact of deductible UK PRT and other taxes on corporate income tax Foreign and domestic tax rate differentials Non-taxable portion of capital gains/losses Stock options exercised for common shares Income tax rate and other legislative changes Non-taxable gain on corporate acquisitions Revisions arising from prior year tax filings Other Income tax (recovery) expense 2015 26.0% 2014 25.1% $ (173) $ 1,296 $ (232) 119 (157) 36 (12) 362 – 32 (5) (124) 85 (61) 36 14 – (34) 5 17 $ (30) $ 1,234 $ 2013 25.1% 762 (166) 111 (66) 14 33 15 (16) 57 22 766 The following table summarizes the temporary differences that give rise to the net deferred income tax liability: Deferred income tax liabilities Property, plant and equipment and exploration and evaluation assets $ 10,257 $ 9,985 2015 2014 Timing of partnership items Unrealized risk management activities Unrealized foreign exchange gain on long-term debt Deferred PRT Investment in PrairieSky Deferred income tax assets Asset retirement obligations Loss carryforwards Unrealized foreign exchange loss on long-term debt PRT deduction for corporate income tax Other Net deferred income tax liability $ 9,344 $ Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows: Property, plant and equipment and exploration and evaluation assets $ 2015 (7) $ 2014 647 $ Timing of partnership items Unrealized foreign exchange loss on long-term debt Unrealized risk management activities Asset retirement obligations Loss carryforwards Investment in PrairieSky Deferred PRT PRT deduction for corporate income tax Other (176) (222) (5) 522 (53) 60 15 (5) 102 (195) (77) 142 119 109 – 126 (77) 13 $ 231 $ 807 $ 78 261 111 – 65 60 437 120 10 37 – 10,754 10,589 (976) (170) (212) (33) (19) (1,410) (1,362) (117) – (23) (117) (1,619) 8,970 2013 250 (199) (55) 13 76 25 – (132) 78 (25) 31 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. The following table summarizes the movements of the net deferred income tax liability during the year: Balance – beginning of year Deferred income tax expense Deferred income tax (recovery) expense included in other comprehensive income Foreign exchange adjustments Business combinations Balance – end of year 2015 2014 $ 8,970 $ 8,183 $ 231 (4) 147 – 807 1 70 (91) 2013 8,174 31 – 53 (75) $ 9,344 $ 8,970 $ 8,183 Current income taxes recognized in each operating segment will vary depending upon available income tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year. During 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015. As a result of this income tax rate increase, the Company’s deferred income tax liability was increased by $579 million. During 2015, the UK government enacted legislation that reduced the supplementary charge on oil and gas profits from 32% to 20% effective January 1, 2015. In addition, the legislation reduced the PRT rate from 50% to 35% effective January 1, 2016. Allowable abandonment expenditures eligible for carryback to prior taxation years for PRT purposes are still recoverable at the previous tax rate of 50%. The legislation also replaced the existing Brownfield Allowance with a new Investment Allowance on qualifying capital expenditures, effective April 1, 2015. The new Investment Allowance is deductible for supplementary charge purposes, subject to certain restrictions. As a result of these income tax changes, the Company’s deferred income tax liability was reduced by $217 million and the deferred PRT liability was reduced by $11 million. During 2013, the British Columbia government substantively enacted legislation to increase its provincial corporate income tax rate effective April 1, 2013. As a result of this income tax rate change, the Company’s deferred income tax liability was increased by $15 million. The Company files income tax returns in the various jurisdictions in which it operates. These tax returns are subject to periodic examinations in the normal course by the applicable tax authorities. The tax returns as prepared may include filing positions that could be subject to differing interpretations of applicable tax laws and regulations, which may take several years to resolve. The Company does not believe the ultimate resolution of these matters will have a material impact upon the Company’s results of operations, financial position or liquidity. Deferred income tax assets are recognized for temporary differences to the extent that the realization of the related tax benefit through future taxable profits is probable. The Company has not recognized deferred income tax assets with respect to taxable capital loss carryforwards in excess of $1,000 million in North America, which can be carried forward indefinitely and only applied against future taxable capital gains. In addition, the Company has not recognized deferred income tax assets related to North American tax pools of approximately $650 million, which can only be claimed against income from certain oil and gas properties. Deferred income tax liabilities have not been recognized on the unremitted net earnings of wholly controlled subsidiaries. The Company is able to control the timing and amount of distributions and no taxes are payable on distributions from these subsidiaries provided that the distributions remain within certain limits. 12. SHARE CAPITAL AUTHORIZED Preferred shares issuable in a series. Unlimited number of common shares without par value. ISSUED Common shares Balance – beginning of year Issued upon exercise of stock options Previously recognized liability on stock options exercised for common shares Purchase of common shares under Normal Course Issuer Bid 2015 2014 Number of shares Number of shares (thousands) Amount (thousands) Amount 1,091,837 $ 4,432 1,087,322 $ 3,854 2,831 – – 91 18 14,610 – (10,095) 488 129 (39) Balance – end of year 1,094,668 $ 4,541 1,091,837 $ 4,432 79 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. PREFERRED SHARES Preferred shares are issuable in a series. If issued, the number of shares in each series, and the designation, rights, privileges, restrictions and conditions attached to the shares will be determined by the Board of Directors of the Company. DIVIDEND POLICY The Company has paid regular quarterly dividends in each year since 2001. The dividend policy undergoes periodic review by the Board of Directors and is subject to change. On March 2, 2016, the Board of Directors declared a quarterly dividend of $0.23 per common share, beginning with the dividend payable on April 1, 2016. On March 4, 2015, the Board of Directors declared a quarterly dividend of $0.23 per common share, beginning with the dividend payable on April 1, 2015. On March 5, 2014, the Board of Directors declared a quarterly dividend of $0.225 per common share, beginning with the dividend payable on April 1, 2014. On November 5, 2013, the Board of Directors declared a dividend of $0.20 per common share, beginning with the dividend payable on January 1, 2014 ($0.125 per common share, declared on March 6, 2013, beginning with the dividend payable on April 1, 2013). NORMAL COURSE ISSUER BID In 2015, the Company announced a Normal Course Issuer Bid to purchase, through the facilities of the Toronto Stock Exchange, alternative Canadian trading platforms, and the New York Stock Exchange, during the twelve month period commencing April 2015 and ending April 2016, up to 54,640,607 common shares. The Company’s Normal Course Issuer Bid announced in 2014 expired April 2015. During 2015, the Company did not purchase any common shares for cancellation. During 2014, the Company purchased for cancellation 10,095,000 common shares (2013 – 10,164,800 common shares) at a weighted average price of $44.85 per common share (2013 – $31.46 per common share), for a total cost of $453 million (2013 – $320 million). Retained earnings were reduced by $414 million (2013 – $285 million), representing the excess of the purchase price of common shares over their average carrying value. STOCK OPTIONS The Company’s Option Plan provides for the granting of stock options to employees. Stock options granted under the Option Plan have terms ranging from five to six years to expiry and vest over a five-year period. The exercise price of each stock option granted is determined at the closing market price of the common shares on the Toronto Stock Exchange on the day prior to the grant. Each stock option granted provides the holder the choice to purchase one common share of the Company at the stated exercise price or receive a cash payment equal to the difference between the stated exercise price and the market price of the Company’s common shares on the date of surrender of the stock option. The Option Plan is a "rolling 9%" plan, whereby the aggregate number of common shares that may be reserved for issuance under the plan shall not exceed 9% of the common shares outstanding from time to time. The following table summarizes information relating to stock options outstanding at December 31, 2015 and 2014: Outstanding – beginning of year Granted Surrendered for cash settlement Exercised for common shares Forfeited Outstanding – end of year Exercisable – end of year 2015 2014 Stock options (thousands) Weighted average Stock options exercise price (thousands) Weighted average exercise price 71,708 $ 13,310 $ (185) $ (2,831) $ (7,387) $ 74,615 $ 30,567 $ 35.60 30.56 33.30 32.31 35.12 34.88 36.19 72,741 $ 18,517 $ (1,047) $ (14,610) $ (3,893) $ 71,708 $ 23,717 $ 34.36 38.70 33.74 33.40 36.00 35.60 36.27 80 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. The range of exercise prices of stock options outstanding and exercisable at December 31, 2015 was as follows: Stock options outstanding Stock options exercisable Range of exercise prices $27.72-$29.99 $30.00-$34.99 $35.00-$39.99 $40.00-$44.99 $45.00-$45.09 Stock options outstanding (thousands) Weighted average remaining term (years) Weighted average Stock options exercisable Weighted average exercise price $28.53 3.47 $ 3.26 $ 2.54 $ 1.76 $ 3.03 $ 2.84 $ $33.18 $36.48 $42.71 $45.07 $34.88 (thousands) exercise price 4,919 $ 6,598 $ 11,053 $ 7,434 $ 563 $ 30,567 $ $28.25 $33.48 $36.82 $42.23 $45.05 $36.19 17,849 20,255 22,793 12,152 1,566 74,615 13. ACCUMULATED OTHER COMPREHENSIVE INCOME The components of accumulated other comprehensive income, net of taxes, were as follows: Derivative financial instruments designated as cash flow hedges Foreign currency translation adjustment 14. CAPITAL DISCLOSURES $ $ 2015 58 $ 17 75 $ 2014 94 (43) 51 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 at 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 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’s internal targeted range for its debt to book capitalization ratio is 25% to 45%. This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. 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, 2015, the ratio was within the target range at 38%. Readers are cautioned that the debt to book capitalization ratio is not defined by IFRS 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. Long-term debt (1) Total shareholders’ equity Debt to book capitalization (1) Includes the current portion of long-term debt. 15. NET EARNINGS (LOSS) PER COMMON SHARE Weighted average common shares outstanding – basic (thousands of shares) Effect of dilutive stock options (thousands of shares) Weighted average common shares outstanding – diluted (thousands of shares) Net earnings (loss) Net earnings (loss) per common share – basic – diluted $ $ 2015 16,794 $ 27,381 $ 38% 2014 14,002 28,891 33% 2015 2014 2013 1,093,862 1,091,754 1,088,682 – 5,068 1,859 1,093,862 1,096,822 1,090,541 $ $ $ (637) $ (0.58) $ (0.58) $ 3,929 $ 3.60 $ 3.58 $ 2,270 2.08 2.08 In 2015, the Company excluded 62,757,000 potentially anti-dilutive stock options from the calculation of diluted earnings per common share. 81 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. 457 (2) 455 175 280 (1) 279 Total 1,277 974 1,108 (571) (2,089) (16,794) (16,095) Total 1,889 719 (564) (3,279) (40) (14,002) (15,277) 16. INTEREST AND OTHER FINANCING EXPENSE Interest and other financing expense: Long-term debt Other (1) Less: amounts capitalized on qualifying assets Total interest and other financing expense Total interest income 2015 2014 2013 $ 618 $ 542 $ 1 619 244 375 (53) (7) 535 204 331 (8) Net interest and other financing expense $ 322 $ 323 $ (1) Includes the fair value impact of interest rate swaps on US dollar debt securities. 17. FINANCIAL INSTRUMENTS The carrying amounts of the Company’s financial instruments by category were as follows: Financial assets at Fair value through profit or loss 2015 Derivatives used for hedging Financial liabilities at amortized cost Asset (liability) Accounts receivable Investment in PrairieSky Other long-term assets Accounts payable Accrued liabilities Long-term debt (1) amortized cost $ 1,277 $ – 254 – – – – $ – $ – $ 974 36 – – – – 818 – – – – – (571) (2,089) (16,794) $ 1,531 $ 1,010 $ 818 $ (19,454) $ Financial assets at Fair value through profit amortized cost $ 1,889 $ 120 – – – – or loss – $ 415 – – – – 2014 Derivatives used for hedging Financial liabilities at amortized cost – $ 184 – $ – – – – – (564) (3,279) (40) (14,002) $ 2,009 $ 415 $ 184 $ (17,885) $ Asset (liability) Accounts receivable Other long-term assets Accounts payable Accrued liabilities Other long-term liabilities Long-term debt (1) (1) Includes the current portion of long-term debt. 82 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. The carrying amounts of the Company’s financial instruments approximated their fair value, except for fixed rate long-term debt as noted below. The fair values of the Company’s recurring other long-term assets and fixed rate long-term debt are outlined below: Carrying amount 2015 Fair value Asset (liability) (1) (2) Investment in PrairieSky (3) Other long-term assets (4) Fixed rate long-term debt (5) (6) Level 1 Level 2 Level 3 $ $ $ 974 $ 1,108 $ 974 $ – $ (12,808) $ (12,431) $ – $ 854 $ – $ – 254 – Carrying amount 2014 Fair value Asset (liability) (1) (2) Other long-term assets (4) Fixed rate long-term debt (5) (6) Level 1 Level 2 Level 3 $ $ 719 $ – $ (11,018) $ (11,855) $ 599 $ – $ 120 – (1) Excludes financial assets and liabilities where the carrying amount 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) There were no transfers between Level 1, 2 and 3 financial instruments. (3) The fair value of the investment in PrairieSky is based on quoted market prices. (4) The fair value of North West Redwater Partnership subordinated debt is based on the present value of future cash receipts. (5) The fair value of fixed rate long-term debt has been determined based on quoted market prices. (6) Includes the current portion of fixed rate long-term debt. The following provides a summary of the carrying amounts of derivative financial instruments held and a reconciliation to the Company’s consolidated balance sheets. Asset (liability) Derivatives held for trading Crude oil price collars Crude oil WCS (1) differential swaps Foreign currency forward contracts Cash flow hedges Foreign currency forward contracts Cross currency swaps Included within: Current portion of other long-term assets Other long-term assets (1) Western Canadian Select. 2015 2014 $ – $ – 36 30 788 854 $ 305 $ 549 854 $ $ $ $ 410 (16) 21 11 173 599 436 163 599 During 2015, the Company recognized a gain of $5 million (2014 – loss of $3 million; 2013 – gain of $4 million) related to ineffectiveness arising from cash flow hedges. The estimated fair value of derivative financial instruments in Level 2 at each measurement date have been determined based on appropriate internal valuation methodologies and/or third party indications. Level 2 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 quoted market inputs including crude oil and natural gas forward benchmark commodity prices and volatility, Canadian and United States forward interest rate yield curves, and Canadian and United States foreign exchange rates, discounted to present value as appropriate. 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. 83 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. RISK MANAGEMENT The Company periodically uses derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. 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: Asset (liability) Balance – beginning of year $ 2015 599 $ 2014 (136) Net change in fair value of outstanding derivative financial instruments recognized in: Risk management activities Foreign exchange Other comprehensive (loss) income Balance – end of year Less: current portion (374) 669 (40) 854 305 $ 549 $ Net (gains) losses from risk management activities for the years ended December 31 were as follows: Net realized risk management gain Net unrealized risk management loss (gain) $ $ 2015 (843) $ 374 (469) $ 2014 (349) $ (451) (800) $ 451 270 14 599 436 163 2013 (116) 39 (77) 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 periodically 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, 2015, the Company had no commodity derivative financial instruments outstanding. 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 periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on long-term debt. 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, 2015, the Company had no interest rate swap contracts outstanding. 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, commercial paper and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted in other currencies and in the carrying value of its 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, commercial paper 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. 84 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.At December 31, 2015, the Company had the following cross currency swap contracts outstanding: Cross currency Swaps Remaining term Amount Exchange rate (US$/C$) Interest rate (US$) Interest rate (C$) Jan 2016 – Mar 2016 Jan 2016 – Aug 2016 US$500 US$250 Jan 2016 – May 2017 US$1,100 Jan 2016 – Nov 2021 Jan 2016 – Mar 2038 US$500 US$550 Three-month LIBOR Three-month CDOR (1) plus 0.375% plus 0.309% 6.00% 5.70% 3.45% 6.25% 5.40% 5.10% 3.96% 5.76% 1.109 1.116 1.170 1.022 1.170 (1) Canadian Dealer Offered Rate (“CDOR”). All cross currency swap derivative financial instruments were designated as hedges at December 31, 2015 and were classified as cash flow hedges. In addition to the cross currency swap contracts noted above, at December 31, 2015, the Company had US$2,357 million of foreign currency forward contracts outstanding, with terms of approximately 30 days or less, including US$1,157 million designated as cash flow hedges. Financial instrument sensitivities The following table summarizes the annualized sensitivities of the Company’s 2015 net loss and other comprehensive loss to changes in the fair value of financial instruments outstanding as at December 31, 2015, 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, are limited to the impact of changes in a specified variable applied to financial instruments only 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 cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear. Interest rate risk Increase interest rate 1% Decrease interest rate 1% Foreign currency exchange rate risk Increase exchange rate by US$0.01 Decrease exchange rate by US$0.01 (Increase) decrease (Increase) decrease to other to net loss comprehensive loss $ $ $ $ (17) $ 15 $ (70) $ 68 $ (41) 46 – – 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, 2015, 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 nonperformance 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. At December 31, 2015, the Company had net risk management assets of $854 million with specific counterparties related to derivative financial instruments (December 31, 2014 – $622 million). The carrying amount of financial assets approximates the maximum credit exposure. 85 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. 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, commercial paper and access to debt capital markets, to meet obligations as they become due. The Company believes it has adequate bank credit facilities to provide liquidity to manage fluctuations in the timing of the receipt and/or disbursement of operating cash flows. The maturity dates for financial liabilities were as follows: Accounts payable Accrued liabilities Long-term debt (1) Less than 1 to less than 2 to less than 1 year 2 years 5 years Thereafter $ $ $ 571 $ 2,089 $ 1,730 $ – $ – $ – $ – $ – – 2,522 $ 5,679 $ 6,935 (1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums, or transaction costs. 18. COMMITMENTS AND CONTINGENCIES The Company has committed to certain payments as follows: Product transportation and pipeline Offshore equipment operating leases and offshore drilling Office leases Other $ $ $ $ 2016 2017 2018 2019 2020 Thereafter 423 $ 341 $ 303 $ 261 $ 246 $ 1,304 247 $ 42 $ 141 $ 93 $ 42 $ 38 $ 71 $ 42 $ 48 $ 22 $ 43 $ 1 $ – $ 42 $ – $ – 193 – In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and construction of subsequent phases of Horizon. These contracts can be cancelled by the Company upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation. The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. 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. 86 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. 19. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Changes in non-cash working capital Accounts receivable Inventory Prepaids and other Accounts payable Accrued liabilities Current income tax (liabilities) assets Net changes in non-cash working capital Relating to: Operating activities Financing activities Investing activities Expenditures on exploration and evaluation assets Net proceeds on sale of exploration and evaluation assets (1) Net (proceeds) expenditures on exploration and evaluation assets Expenditures on property, plant and equipment Net proceeds on sale of property, plant and equipment (1) Net expenditures on property, plant and equipment 2015 2014 2013 $ 615 $ (456) $ 142 11 7 (981) (447) (31) (30) (70) 741 (586) (653) $ (432) $ 239 $ (744) $ (40) (852) (22) 334 (653) $ (432) $ 2015 180 $ (416) (236) $ 2014 1,190 $ – 1,190 $ 5,118 $ 10,252 $ (414) (44) 4,704 $ 10,208 $ $ $ $ $ $ $ $ (243) (76) (14) 175 127 94 63 (33) (23) 119 63 2013 119 (263) (144) 7,249 (38) 7,211 (1) Net proceeds on exploration and evaluation assets and net expenditures on property, plant and equipment in 2015 exclude non-cash share consideration of $985 million received from PrairieSky on the disposition of royalty income assets. 87 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.20. SEGMENTED INFORMATION The Company’s exploration and production activities are conducted in three geographic segments: North America, North Sea and Offshore Africa. These activities include the exploration, development, production and marketing of crude oil, natural gas liquids and natural gas. The Company’s Oil Sands Mining and Upgrading activities are reported in a separate segment from exploration and production activities. Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream and other Inter–segment elimination Segmented product sales $ 9,222 $ 15,963 $ 12,659 $ 638 $ 701 $ 805 $ 482 $ 503 $ 824 $ 2,764 $ 4,095 $ 3,631 $ 136 $ 120 $ 110 $ (75) $ (81) $ (84) $ 13,167 $ 21,301 $ 17,945 2015 2014 2013 2015 2014 2013 2015 2014 2013 2015 2014 2013 2015 2014 2013 2015 2014 2013 2015 2013 Less: royalties Segmented revenue Segmented expenses Production Transportation and blending (732) (2,159) (1,477) 8,490 13,804 11,182 2,603 2,309 2,924 3,228 2,351 2,939 (1) 637 544 61 (2) 699 496 5 (2) 803 431 6 (22) 460 223 2 (43) 460 212 1 (137) 687 191 1 (49) (234) (184) 2,715 3,861 3,447 – 136 1,332 1,609 1,567 82 75 63 4,248 3,901 3,568 388 269 552 273 105 134 562 596 582 Depletion, depreciation and amortization Asset retirement obligation accretion Realized risk management activities Gains on disposition of properties and corporate acquisitions Loss from investments 93 98 92 39 38 35 10 10 (843) (349) (116) (739) (137) 6 – (65) – – – – – – – – – – – – – – – – 10 – (224) – 112 Total segmented expenses 7,677 9,665 8,769 1,032 808 1,024 508 328 $ 813 $ 4,139 $ 2,413 $ (395) $ (109) $ (221) $ (48) $ 132 $ 575 $ 708 $ 1,534 $ 1,201 $ 48 $ 69 $ 64 $ 8 $ 6 $ 2 1,134 5,771 4,034 Segmented earnings (loss) before the following Non–segmented expenses Administration Share-based compensation Interest and other financing expense Unrealized risk management activities Foreign exchange loss Total non–segmented expenses Earnings (loss) before taxes Current income tax (recovery) expense Deferred income tax expense Net earnings (loss) 88 – 120 34 – 9 – – – 8 – 110 34 – 8 – – – 4 – (75) (8) (75) – – – – – – (81) (10) (77) – – – – – 32 – 12 – – – 44 88 31 47 34 – – – – – – – – – 2,007 2,327 2,246 51 46 (83) (87) (86) 11,229 13,092 12,111 Total 2014 – (804) (2,438) (1,800) (84) 12,363 18,863 16,145 (15) (71) 4,726 2,379 5,265 3,232 4,559 2,938 – – – – – 5,483 4,880 4,844 173 193 171 (843) (349) (116) (739) 50 (137) (289) 8 4 390 (46) 367 66 335 135 322 323 279 374 761 1,801 (451) 303 608 (667) 5,163 3,036 39 210 998 735 31 (261) 231 427 807 $ (637) $ 3,929 $ 2,270 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. 20. SEGMENTED INFORMATION liquids and natural gas. production activities. The Company’s exploration and production activities are conducted in three geographic segments: North America, North Sea and Offshore Africa. These activities include the exploration, development, production and marketing of crude oil, natural gas The Company’s Oil Sands Mining and Upgrading activities are reported in a separate segment from exploration and Midstream activities include the Company’s pipeline operations, an electricity co-generation system and Redwater Partnership. Production activities that are not included in the above segments are reported in the segmented information as other. Inter- segment eliminations include internal transportation and electricity charges. Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenue and segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers are based on the location of the seller. Operating segments are reported in a manner consistent with the internal reporting provided to the Company’s chief operating decision makers. Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream and other Inter–segment elimination 2015 2014 2013 2015 2014 2013 2015 2014 2013 2015 2014 2013 2015 2014 2013 2015 2014 2013 2015 Total 2014 2013 Segmented product sales $ 9,222 $ 15,963 $ 12,659 $ 638 $ 701 $ 805 $ 482 $ 503 $ 824 $ 2,764 $ 4,095 $ 3,631 $ 136 $ 120 $ 110 $ (75) $ (81) $ (84) $ 13,167 $ 21,301 $ 17,945 Less: royalties Segmented revenue Segmented expenses Production Transportation and blending (732) (2,159) (1,477) 8,490 13,804 11,182 2,603 2,309 2,924 3,228 2,351 2,939 (1) 637 544 61 (2) 699 496 5 (2) 803 431 6 (22) 460 223 2 (43) 460 212 1 (49) (234) (184) 2,715 3,861 3,447 – 136 4,248 3,901 3,568 388 269 552 273 105 134 562 596 582 93 98 92 39 38 35 10 10 31 47 34 (843) (349) (116) (739) (137) 6 – (65) – – – – – – – – – – – – – – – – – – – – – – – – – Total segmented expenses 7,677 9,665 8,769 1,032 808 1,024 508 328 2,007 2,327 2,246 1,332 1,609 1,567 82 75 63 32 – 12 – – – 44 88 (137) 687 191 1 10 – (224) – 112 – 120 34 – 9 – – – 8 – 110 34 – 8 – – – 4 – (75) (8) (75) – – – – – – (81) (10) (77) – – – – – – (804) (2,438) (1,800) (84) 12,363 18,863 16,145 (15) (71) 4,726 2,379 5,265 3,232 4,559 2,938 – – – – – 5,483 4,880 4,844 173 193 171 (843) (349) (116) (739) 50 (137) (289) 8 4 51 46 (83) (87) (86) 11,229 13,092 12,111 before the following $ 813 $ 4,139 $ 2,413 $ (395) $ (109) $ (221) $ (48) $ 132 $ 575 $ 708 $ 1,534 $ 1,201 $ 48 $ 69 $ 64 $ 8 $ 6 $ 2 1,134 5,771 4,034 390 (46) 367 66 335 135 322 323 279 374 761 1,801 (451) 303 608 39 210 998 (667) 5,163 3,036 (261) 231 427 807 735 31 $ (637) $ 3,929 $ 2,270 89 Depletion, depreciation and amortization Asset retirement obligation accretion Realized risk management activities Gains on disposition of properties and corporate acquisitions Loss from investments Segmented earnings (loss) Non–segmented expenses Administration Share-based compensation Interest and other financing expense Unrealized risk management activities Foreign exchange loss Total non–segmented expenses Earnings (loss) before taxes Current income tax (recovery) expense Deferred income tax expense Net earnings (loss) Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. Capital Expenditures (1) Net expenditures (proceeds) (2) 2015 Non-cash and fair value changes (3) Capitalized Net costs expenditures and fair value changes (3) Capitalized costs 2014 Non-cash Exploration and evaluation assets Exploration and Production North America (4) North Sea Offshore Africa Property, plant and equipment Exploration and Production North America (4) North Sea Offshore Africa Oil Sands Mining and Upgrading (5) Midstream Head office $ $ (260) $ (666) $ (926) $ 1,103 $ (247) $ – 35 – (96) – (61) – 87 – – (225) $ (762) $ (987) $ 1,190 $ (247) $ $ 1,171 $ (1,237) $ (66) $ 6,397 $ 399 $ 230 573 1,974 2,730 8 26 (217) (49) (1,503) (335) (1) – 13 524 471 2,395 7 26 400 194 6,991 3,110 62 45 86 (1) 484 (528) – (1) 856 – 87 943 6,796 486 193 7,475 2,582 62 44 $ 4,738 $ (1,839) $ 2,899 $ 10,208 $ (45) $ 10,163 (1) This table provides a reconciliation of capitalized costs including derecognitions and does not include the impact of foreign exchange adjustments. (2) Net expenditures (proceeds) in 2015 do not include non-cash share consideration of $985 million received from PrairieSky on the disposition of royalty income assets. (3) Asset retirement obligations, deferred income tax adjustments related to differences between carrying amounts and tax values, transfers of exploration and evaluation assets, and other fair value adjustments. (4) The above noted figures in 2015 do not include the impact of other pre-tax gains on the sale of other properties totaling $49 million recognized in 2015. (5) Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest and share-based compensation. 2015 2014 $ 30,937 $ 34,382 2,734 1,755 73 22,598 1,054 124 $ 59,275 $ 2,711 1,214 18 20,702 1,048 125 60,200 SEGMENTED ASSETS Exploration and Production North America North Sea Offshore Africa Other Oil Sands Mining and Upgrading Midstream Head office 90 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. 21. REMUNERATION OF DIRECTORS AND SENIOR MANAGEMENT REMUNERATION OF NON-MANAGEMENT DIRECTORS Fees earned REMUNERATION OF SENIOR MANAGEMENT (1) Salary Common stock option based awards Annual incentive plans Long-term incentive plans Other compensation $ $ 2015 2 $ 2014 3 $ 2015 3 $ 2014 3 $ 7 2 6 – 8 4 17 – $ 18 $ 32 $ 2013 2 2013 3 11 3 14 1 32 (1) Senior management identified above are consistent with the disclosure on Named Executive Officers provided in the Company’s Information Circular to shareholders for the respective years. 91 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.SUPPLEMENTARY OIL & GAS INFORMATION (unaudited) This supplementary crude oil and natural gas information is provided in accordance with the United States Financial Accounting Standards Board (“FASB”) Topic 932 – “Extractive Activities – Oil and Gas” and where applicable, financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”). For the years ended December 31, 2015, 2014, 2013, and 2012 the Company filed its reserves information under National Instrument 51-101 – “Standards of Disclosure of Oil and Gas Activities” (“NI 51-101”), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. There are significant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission (“SEC”) requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, using forecast pricing and costs. Therefore the difference between the reported numbers under the two disclosure standards can be material. For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2015, 2014, 2013, and 2012 the Company used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The Company has used the following 12-month average benchmark prices to determine its 2015 reserves for SEC requirements. Crude Oil and NGLs WTI Cushing Oklahoma WCS Canadian Light Sweet Cromer LSB North Sea Brent Edmonton C5+ (US$/bbl) (C$/bbl) 50.28 46.83 (C$/bbl) 58.81 (C$/bbl) 57.06 (US$/bbl) 55.57 (C$/bbl) 62.57 Henry Hub Louisiana (US$/MMBtu) 2.63 Natural Gas BC Westcoast Station 2 AECO (C$/MMBtu) (C$/MMBtu) 2.68 1.75 A foreign exchange rate of US$1.00/C$1.2706 was used in the 2015 evaluation, determined on the same basis as the 12-month average price. NET PROVED CRUDE OIL AND NATURAL GAS RESERVES The Company retains Independent Qualified Reserves Evaluators to evaluate the Company’s proved crude oil, bitumen, synthetic crude oil (“SCO”), natural gas, and natural gas liquids (“NGLs”) reserves. ■■ For the years ended December 31, 2015, 2014, 2013, and 2012, the reports by GLJ Petroleum Consultants Ltd. covered 100% of the Company’s SCO reserves. With the inclusion of non-traditional resources within the definition of “oil and gas producing activities” in the SEC’s modernization of oil and gas reporting rules, effective January 1, 2010 these reserves volumes are included within the Company’s crude oil and natural gas reserves totals. ■■ For the years ended December 31, 2015, 2014, 2013, and 2012, the reports by Sproule Associates Limited and Sproule International Limited covered 100% of the Company’s crude oil, bitumen, natural gas and NGLs reserves. Proved crude oil and natural gas reserves, as defined within the SEC’s Regulation S-X, are the estimated quantities of oil and gas that by analysis of geoscience and engineering data demonstrate with reasonable certainty to be economically producible, from a given date forward, from known reservoirs under existing economic conditions, operating methods and government regulations. Developed crude oil and natural gas reserves are reserves of any category that can be expected to be recovered from existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of drilling a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped crude oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Estimates of crude oil and natural gas reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change. 92 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. The following tables summarize the Company’s proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2015, 2014, 2013, and 2012: North America Synthetic Crude Oil Bitumen (1) Crude Oil & NGLs North America Total North Sea Offshore Africa Total Crude Oil and NGLs (MMbbl) Net Proved Reserves 3,343 235 85 3,663 Reserves, December 31, 2012 1,974 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates – – – – (35) (10) (4) 999 76 9 – – (71) (1) 56 Reserves, December 31, 2013 1,925 1,068 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2014 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates – – – – (38) (89) (18) 1,780 208 – – – (44) 339 – 112 10 – – (76) 11 23 1,148 25 17 9 – (84) 153 (5) 370 13 7 8 – (33) 4 11 380 11 29 54 – (40) – 47 481 10 9 11 (7) (44) 5 6 89 16 8 – (139) (7) 63 3,373 123 39 54 – (154) (78) 52 3,409 243 26 20 (7) (172) 497 1 Reserves, December 31, 2015 2,283 1,263 471 4,017 Net proved developed reserves December 31, 2012 December 31, 2013 December 31, 2014 December 31, 2015 1,612 1,621 1,631 2,194 348 431 401 411 295 298 358 341 2,255 2,350 2,390 2,946 – – 6 – (7) – (2) 232 – – – – (6) (9) (6) 211 – – – – (8) (51) (33) 119 66 59 39 3 – – – – (5) (2) 2 80 – – – – (4) 1 – 77 – – – – (6) 2 – 73 55 30 21 41 89 16 14 – (151) (9) 63 3,685 123 39 54 – (164) (86) 46 3,697 243 26 20 (7) (186) 448 (32) 4,209 2,376 2,439 2,450 2,990 (1) Bitumen as defined by the SEC, “is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.” Under this definition, all the Company’s thermal and primary heavy crude oil reserves have been classified as bitumen. 93 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. North America North Sea Offshore Africa 2,647 126 62 99 (1) (394) 489 206 3,234 119 443 1,229 – (514) 576 (70) 5,017 237 242 344 (35) (587) (935) 240 4,523 2,060 2,342 3,585 2,883 83 – – 14 – (1) – (4) 92 – – – – (2) (6) – 84 – – – – (13) (8) (25) 38 58 72 64 26 48 – – – – (8) (2) (1) 37 – – – – (6) 1 2 34 – – – – (9) 3 (7) 21 39 27 22 15 Total 2,778 126 62 113 (1) (403) 487 201 3,363 119 443 1,229 – (522) 571 (68) 5,135 237 242 344 (35) (609) (940) 208 4,582 2,157 2,441 3,671 2,924 Natural Gas (Bcf) Net Proved Reserves Reserves, December 31, 2012 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2013 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2014 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2015 Net proved developed reserves December 31, 2012 December 31, 2013 December 31, 2014 December 31, 2015 94 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. CAPITALIZED COSTS RELATED TO CRUDE OIL AND NATURAL GAS ACTIVITIES (millions of Canadian dollars) Proved properties Unproved properties Less: accumulated depletion and depreciation 2015 North America North Sea Offshore Africa $ 84,883 $ 7,414 $ 5,173 $ 2,500 87,383 (37,641) – 7,414 (5,264) 86 5,259 (3,659) Net capitalized costs $ 49,742 $ 2,150 $ 1,600 $ (millions of Canadian dollars) Proved properties Unproved properties Less: accumulated depletion and depreciation 2014 North America North Sea Offshore Africa $ 82,554 $ 6,182 $ 3,858 $ 3,426 85,980 (33,750) – 6,182 (4,049) 131 3,989 (2,890) Net capitalized costs $ 52,230 $ 2,133 $ 1,099 $ (millions of Canadian dollars) Proved properties Unproved properties Less: accumulated depletion and depreciation 2013 North America North Sea Offshore Africa $ 73,176 $ 5,200 $ 3,356 $ 2,570 75,746 (29,729) – 5,200 (3,467) 39 3,395 (2,551) Net capitalized costs $ 46,017 $ 1,733 $ 844 $ Total 97,470 2,586 100,056 (46,564) 53,492 Total 92,594 3,557 96,151 (40,689) 55,462 Total 81,732 2,609 84,341 (35,747) 48,594 95 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. COSTS INCURRED IN CRUDE OIL AND NATURAL GAS ACTIVITIES 2015 North America North Sea Offshore Africa $ (556) $ – $ – $ (446) 87 2,845 – – 13 – 35 524 $ 1,930 $ 13 $ 559 $ 2014 North America North Sea Offshore Africa $ 3,323 $ 1 $ – $ 873 230 6,263 $ 10,689 $ – 87 193 280 $ – – 485 486 $ 2013 North America North Sea Offshore Africa $ 250 $ 2 $ – $ 92 (2) 6,152 $ 6,492 $ – – 297 299 $ 4 25 97 126 $ Total (556) (446) 122 3,382 2,502 Total 3,324 873 317 6,941 11,455 Total 252 96 23 6,546 6,917 (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred 96 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. RESULTS OF OPERATIONS FROM CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES The Company’s results of operations from crude oil and natural gas producing activities for the years ended December 31, 2015, 2014, and 2013 are summarized in the following tables: (millions of Canadian dollars) Crude oil and natural gas revenue, net of royalties and blending costs Production Transportation Depletion, depreciation and amortization (1) Asset retirement obligation accretion Petroleum Revenue Tax Income tax Results of operations 2015 North America North Sea Offshore Africa $ 10,362 $ 623 $ 460 $ (3,935) (674) (4,810) (124) – (214) (544) (61) (388) (39) 243 83 (223) (2) (273) (10) – 20 $ 605 $ (83) $ (28) $ Total 11,445 (4,702) (737) (5,471) (173) 243 (111) 494 (1) Includes the impact of the derecognition of $96 million of exploration and evaluation assets related to the Company’s withdrawal from Block CI-514 in Côte d’Ivoire, Offshore Africa. (millions of Canadian dollars) Crude oil and natural gas revenue, net of royalties and blending costs Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum Revenue Tax Income tax Results of operations (millions of Canadian dollars) Crude oil and natural gas revenue, net of royalties and blending costs Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum Revenue Tax Income tax Results of operations 2014 North America North Sea Offshore Africa $ 15,385 $ 696 $ 460 $ (4,533) (593) (4,497) (145) – (1,411) (496) (5) (269) (38) 147 (22) (212) (1) (105) (10) – (29) $ 4,206 $ 13 $ 103 $ 2013 North America North Sea Offshore Africa $ 12,274 $ 726 $ 687 $ (3,918) (483) (4,150) (126) – (903) (436) (6) (552) (35) 188 71 (191) (1) (134) (10) – (88) $ 2,694 $ (44) $ 263 $ Total 16,541 (5,241) (599) (4,871) (193) 147 (1,462) 4,322 Total 13,687 (4,545) (490) (4,836) (171) 188 (920) 2,913 97 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED CRUDE OIL AND NATURAL GAS RESERVES AND CHANGES THEREIN The following standardized measure of discounted future net cash flows from proved crude oil and natural gas reserves has been computed using the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day- of-the-month price for each month within the 12-month period prior to the end of the reporting period, costs as at the balance sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair value of the crude oil and natural gas properties. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including: ■■ Future production will include production not only from proved properties, but may also include production from probable and possible reserves; ■■ Future production of crude oil and natural gas from proved properties will differ from reserves estimated; ■■ Future production rates will vary from those estimated; ■■ Future prices and costs rather than 12-month average prices and costs as at the balance sheet date will apply; ■■ Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will change; ■■ Future estimated income taxes do not take into account the effects of future exploration and evaluation expenditures; and ■■ Future development and asset retirement obligations will differ from those estimated. Future net revenues, development, production and asset retirement obligation costs have been based upon the estimates referred to above. The following tables summarize the Company’s future net cash flows relating to proved crude oil and natural gas reserves based on the standardized measure as prescribed in FASB Topic 932 – “Extractive Activities – Oil and Gas”: (millions of Canadian dollars) Future cash inflows Future production costs Future development costs and asset retirement obligations Future income taxes Future net cash flows 10% annual discount for timing of future cash flows 2015 North America North Sea Offshore Africa Total $ 225,032 $ 10,258 $ 4,936 $ 240,226 (100,924) (5,973) (2,026) (108,923) (47,323) (16,173) 60,612 (34,050) (5,228) 791 (152) 213 (1,297) (430) 1,183 (270) Standardized measure of future net cash flows $ 26,562 $ 61 $ 913 $ (millions of Canadian dollars) Future cash inflows Future production costs Future development costs and asset retirement obligations Future income taxes Future net cash flows 10% annual discount for timing of future cash flows 2014 North America North Sea Offshore Africa $ 322,100 $ 24,786 $ 8,853 $ (123,055) (9,708) (2,171) (56,651) (24,578) 117,816 (67,899) (8,515) (4,816) 1,747 (813) (1,863) (1,178) 3,641 (1,672) Standardized measure of future net cash flows $ 49,917 $ 934 $ 1,969 $ 98 (53,848) (15,812) 61,643 (34,107) 27,536 Total 355,739 (134,934) (67,029) (30,572) 123,204 (70,384) 52,820 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. (millions of Canadian dollars) Future cash inflows Future production costs Future development costs and asset retirement obligations Future income taxes Future net cash flows 10% annual discount for timing of future cash flows 2013 North America North Sea Offshore Africa $ 290,892 $ 26,378 $ 9,146 $ (116,984) (9,921) (2,560) (51,749) (20,384) 101,775 (65,063) (7,602) (6,586) 2,269 (976) (1,840) (1,154) 3,592 (1,755) Standardized measure of future net cash flows $ 36,712 $ 1,293 $ 1,837 $ Total 326,416 (129,465) (61,191) (28,124) 107,636 (67,794) 39,842 The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the following table: (millions of Canadian dollars) Sales of crude oil and natural gas produced, net of production costs Net changes in sales prices and production costs Extensions, discoveries and improved recovery Changes in estimated future development costs Purchases of proved reserves in place Sales of proved reserves in place Revisions of previous reserve estimates Accretion of discount Changes in production timing and other Net change in income taxes Net change Balance – beginning of year Balance – end of year 2015 2014 2013 $ (5,107) $ (10,321) $ (43,489) 3,201 5,204 624 (165) 5,298 6,645 (3,452) 5,957 (25,284) 52,820 8,575 4,428 (2,821) 4,425 – (1,306) 5,154 5,895 (1,051) 12,978 39,842 $ 27,536 $ 52,820 $ (8,525) 6,992 2,304 (1,536) 638 (1) 622 4,388 2,341 (1,115) 6,108 33,734 39,842 99 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. TEN-YEAR REVIEW 2015 Years ended December 31 2014 FINANCIAL INFORMATION (1) (Cdn $ millions, except per share amounts) Net earnings 3,929 Per share - basic ($/share) Per share - diluted ($/share) Cash flow from operations (2) Per share - basic ($/share) Per share - diluted ($/share) Capital expenditures, net of dispositions (including business combinations) (637) (0.58) $ (0.58) $ 5,785 5.29 $ 5.28 $ 11,744 9,587 3,853 $ $ $ $ 3.60 $ 3.58 $ 8.78 $ 8.74 $ 2013 2012 2011 2010 (6) 2009 (7) 2008 (7) 2007 (7) 2006 (7) 2,270 1,892 2,643 1,673 1,580 4,985 2,608 2.08 $ 2.08 $ 1.72 $ 1.72 $ 2.41 $ 2.40 $ 1.54 $ 1.53 $ 1.46 $ 1.46 $ 4.61 $ 4.61 $ 2.42 $ 2.42 $ 7,477 6,013 6,547 6,333 6,090 6,969 6,198 6.87 $ 6.86 $ 5.48 $ 5.47 $ 5.98 $ 5.94 $ 5.82 $ 5.78 $ 5.62 $ 5.62 $ 6.45 $ 6.45 $ 5.75 $ 5.75 $ 2,524 2.35 2.35 4,932 4.59 4.59 7,274 6,308 6,414 5,514 2,997 7,451 6,425 12,025 Balance sheet information Working capital surplus (deficiency) Exploration and evaluation assets Property, plant and equipment, net Total assets Long-term debt Shareholders’ equity SHARE INFORMATION (1) Common shares outstanding (thousands) Weighted average shares outstanding - basic (thousands) Weighted average shares outstanding - diluted (thousands) Dividends declared ($/share) (8) Trading statistics (1) TSX – C$ Trading volume (thousands) Share Price ($/share) High Low Close NYSE – US$ Trading volume (thousands) Share Price ($/share) High Low Close RATIOS Debt to book capitalization (3) Return on average common 1,193 2,586 51,475 59,275 16,794 27,381 (673) 3,557 52,480 60,200 14,002 28,891 (1,574) 2,609 46,487 51,754 9,661 25,772 (1,264) 2,611 44,028 48,980 8,736 24,283 (894) 2,475 41,631 47,278 8,571 22,898 (1,200) 2,402 38,429 42,954 8,485 20,368 (514) - 39,115 41,024 9,658 19,426 (28) - 38,966 42,650 12,596 18,374 (1,382) - 33,902 36,114 10,940 13,321 (832) - 30,767 33,160 11,043 10,690 1,094,668 1,091,837 1,087,322 1,092,072 1,096,460 1,090,848 1,084,654 1,081,982 1,079,458 1,075,806 1,093,862 1,091,754 1,088,682 1,097,084 1,095,582 1,088,096 1,083,850 1,081,294 1,078,672 1,074,678 1,093,862 1,096,822 1,090,541 1,099,519 1,102,582 1,095,648 1,083,850 1,081,294 1,078,672 1,074,678 0.15 0.36 $ $ 0.575 $ 0.92 $ 0.30 $ 0.90 $ 0.20 $ 0.21 $ 0.42 $ 0.17 $ 728,034 717,580 683,003 729,700 800,044 661,832 1,040,320 1,359,476 858,068 1,017,870 $ 42.46 $ $ 25.01 $ $ 30.22 $ 41.12 $ 49.57 $ 36.04 $ 31.00 $ 28.44 $ 25.58 $ 35.92 $ 35.94 $ 28.64 $ 39.50 $ 50.50 $ 45.00 $ 27.25 $ 17.93 $ 31.97 $ 38.15 $ 44.35 $ 38.00 $ 55.65 $ 17.10 $ 24.38 $ 40.01 $ 26.23 $ 36.29 $ 36.96 22.75 31.08 951,311 812,521 645,403 844,647 937,481 759,327 1,514,614 1,934,456 972,532 803,818 $ 34.46 $ $ 18.94 $ 26.53 $ $ 46.65 $ 33.92 $ 26.98 $ 21.83 $ 30.88 $ 33.84 $ 44.77 $ 38.26 $ 54.66 $ 41.38 $ 52.04 $ 13.85 $ 25.69 $ 25.01 $ 30.00 $ 35.98 $ 37.37 $ 44.42 $ 28.87 $ 43.59 $ 13.22 $ 22.28 $ 36.57 $ 19.99 $ 32.19 20.15 26.62 38% 33% 27% 26% 27% 29% 33% 41% 45% 51% shareholders’ equity, after tax (3) (2%) 14% Daily production before royalties per ten thousand common shares (BOE/d) (1) Total proved plus probable reserves per 7.8 7.2 9% 6.2 8% 6.0 common share (BOE) (1)(4) Net asset value ($/share) (1)(5) 8.3 73.39 $ 8.1 78.99 $ 7.3 72.41 $ 7.2 62.38 $ $ 12% 8% 8% 33% 22% 27% 5.5 5.8 5.3 5.2 5.7 5.4 6.9 6.3 70.37 $ 64.58 $ 64.92 $ 5.8 3.1 39.89 $ 3.2 34.47 $ 3.2 28.21 (1) Restated to reflect two-for-one share splits in May 2010. (2) 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. Cash flow from operations may not be comparable to similar measures used by other companies. (3) Refer to the "Liquidity and Capital Resources" section of the MD&A for the definitions of these items. (4) Based upon company gross reserves (forecast price and costs, before royalties), using year-end common shares outstanding. Excludes Horizon SCO reserves prior to 2009. Prior to 2010, Company gross reserves were prepared using constant prices and costs. (5) Net present value, discounted at 10%, of the future net revenue (before income tax and excluding the ARO for development existing as at December 31, 2015) of the Company’s total proved plus probable crude oil, natural gas and NGL reserves prepared using forecast prices and costs, as reported in the Company's AIF, plus the estimated market value of core unproved property at $285/acre ($300/acre for core unproved property from 2014 to 2010, $250/acre for core undeveloped land from 2006 to 2009), less net debt and using common shares outstanding. Net debt is long term debt plus/minus the working capital deficit/surplus. Future development costs and abandonment and reclamation costs attributable to future development activity have been applied against the future net revenue. (6) 2010 comparative figures have been restated in accordance with IFRS issued at December 31, 2011. (7) Comparative figures for years prior to 2010 are in accordance with Canadian GAAP as previously reported and may not be prepared on a basis consistent with IFRS as adopted. (8) On March 3, 2016, the Board of Directors approved a quarterly dividend of $0.23 per common share, beginning with the dividend payable on April 1, 2016. 100 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. 2015 2014 2013 2012 2011 2010 (6) 2009 2008 2007 2006 Years ended December 31 OPERATING INFORMATION Crude oil and NGLs (MMbbl) (9) Company net proved reserves (after royalties) North America North Sea Offshore Africa 3,645 158 74 3,877 Horizon SCO (9) Company net proved and probable reserves (after royalties) North America North Sea Offshore Africa 5,806 284 113 6,203 Horizon SCO (9) Natural gas (Bcf) (9) Company net proved reserves (after royalties) North America North Sea Offshore Africa 5,383 39 21 5,443 Company net proved plus probable reserves (after royalties) North America North Sea Offshore Africa 7,361 96 50 7,507 3,380 204 78 3,662 - 5,609 308 119 6,036 5,054 83 36 5,173 6,791 114 68 6,973 3,290 224 80 3,594 - 5,135 325 122 5,582 3,684 91 38 3,813 5,138 125 70 5,333 3,268 227 85 3,580 - 5,119 332 127 5,578 - 3,540 82 48 3,670 4,907 102 76 5,085 3,007 228 87 3,322 - 4,777 349 131 5,257 - 3,778 98 54 3,930 5,125 134 83 5,342 2,763 252 101 3,116 - 4,293 376 149 4,818 - 3,638 78 76 3,792 4,870 107 113 5,090 2,664 240 123 3,027 - 4,172 387 179 4,738 - 3,027 67 85 3,179 3,992 94 124 4,210 948 256 142 1,346 1,946 1,599 399 191 2,189 2,944 3,523 67 94 3,684 4,619 94 131 4,844 920 310 128 1,358 1,761 1,545 405 186 2,136 2,680 3,521 81 64 3,666 4,602 113 88 4,803 887 299 130 1,316 1,596 1,502 422 195 2,119 2,542 3,705 37 56 3,798 4,857 93 99 5,049 Total proved reserves (after royalties) (MMBOE) Total proved plus probable reserves (after royalties) (MMBOE) Daily production (before royalties) Crude oil and NGLs (Mbbl/d) North America - Exploration and Production North America - Oil Sands Mining and Upgrading North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa Total production (before royalties) (MBOE/d) Product pricing Average crude oil and NGLs price ($/bbl) (10) Average natural gas price ($/Mcf) (10) Average SCO price ($/bbl) (10) 4,784 4,524 4,230 4,191 3,977 3,748 3,557 1,960 1,969 1,949 7,454 7,198 6,471 6,426 6,147 5,666 5,440 2,996 2,937 2,961 400 123 22 19 564 1,663 36 27 1,726 852 41.13 3.16 61.39 391 111 17 12 531 1,527 7 21 1,555 790 344 100 18 16 478 1,130 4 24 1,158 671 77.04 4.83 100.27 73.81 3.58 100.75 326 86 20 19 451 1,198 2 20 1,220 655 72.44 2.70 90.74 296 271 234 244 247 235 40 30 23 389 1,231 7 19 1,257 599 79.16 3.99 101.48 91 33 30 425 1,217 10 16 1,243 632 65.81 4.08 77.89 50 38 33 355 1,287 10 18 1,315 575 57.68 4.53 70.83 - 45 27 316 1,472 10 13 1,495 565 - 56 28 331 1,643 13 12 1,668 609 - 60 37 332 1,468 15 9 1,492 581 82.41 8.39 - 55.45 6.85 - 53.65 6.72 - (9) For the years 2015 to 2010, company net reserves were prepared using forecast prices and costs; prior to 2010, company net reserves were prepared using constant prices and costs. Prior to December 31, 2009, the Company's Horizon SCO reserves were reported separately in accordance with the SEC's Industry Guide 7. With the SEC's Final Rule in effect January 1, 2010, this SCO is now included in the Company's crude oil and natural gas reserves totals. (10) For the years 2011 to 2015, product prices reflect realized product prices before transportation costs. Prior to 2011, product prices were reported net of transportation costs. 101 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent. CORPORATE INFORMATION BOARD OF DIRECTORS *Catherine M. Best, FCA, ICD.D (1)(2) Corporate Director Calgary, Alberta N. Murray Edwards, O.C. (5) President, Edco Financial Holdings Ltd. London, England *Timothy W. Faithfull (1)(3) Corporate Director London, England *Honourable Gary A. Filmon, P.C., O.C., O.M. (1)(4) Corporate Director Winnipeg, Manitoba *Christopher L. Fong (3)(5) Corporate Director Calgary, Alberta *Ambassador Gordon D. Giffin (1)(4) Partner, Dentons US LLP Atlanta, Georgia *Wilfred A. Gobert (2)(4)(5) Corporate Director Calgary, Alberta Steve W. Laut (3) President, Canadian Natural Resources Limited Calgary, Alberta *Honourable Frank J. McKenna, P.C., O.C., O.N.B., Q.C. (2)(4) Deputy Chair, TD Bank Group Cap Pelé, New Brunswick *David A. Tuer (1)(5) Chairman, Optiom Inc. Calgary, Alberta *Annette M. Verschuren, O.C. (2)(3) Chairman and Chief Executive Officer, NRSTOR Inc. Toronto, Ontario SENIOR OFFICERS N. Murray Edwards Executive Chairman Steve W. Laut President Tim S. McKay Chief Operating Officer Lyle G. Stevens Executive Vice-President, Canadian Conventional Corey B. Bieber Chief Financial Officer and Senior Vice-President, Finance Réal M. Cusson Senior Vice-President, Marketing Réal J.H. Doucet Senior Vice-President, Horizon Projects Darren M. Fichter Senior Vice-President, Exploitation Terry J. Jocksch Senior Vice-President, Thermal Ron K. Laing Senior Vice-President, Corporate Development and Land Paul M. Mendes Vice-President, Legal, General Counsel and Corporate Secretary Bill R. Peterson Senior Vice-President, Production and Development Operations Ken W. Stagg Senior Vice-President, Exploration Scott G. Stauth Senior Vice-President, North American Operations Betty Yee Vice-President, Land (1) Audit Committee member (2) Compensation Committee member (3) Health, Safety, Asset Integrity and Environmental Committee member (4) Nominating, Governance and Risk Committee member (5) Reserves Committee member * Determined to be independent by the Nominating, Governance and Risk Committee and the Board of Directors and pursuant to the independent standards established under National Instrument 58-101 and the New York Stock Exchange Corporate Governance Listing Standards. 102 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.CORPORATE OFFICES HEAD OFFICE Canadian Natural Resources Limited 2100, 855 - 2 Street S.W. Calgary, AB T2P 4J8 Telephone: (403) 517-6700 Facsimile: (403) 517-7350 Website: www.cnrl.com INVESTOR RELATIONS Telephone: (403) 514-7777 Email: ir@cnrl.com INTERNATIONAL OFFICE CNR International (U.K.) Limited St. Magnus House, Guild Street Aberdeen AB11 6NJ Scotland REGISTRAR AND TRANSFER AGENT Computershare Trust Company of Canada Calgary, Alberta Toronto, Ontario Computershare Investor Services LLC New York, New York AUDITORS PricewaterhouseCoopers LLP Calgary, Alberta INDEPENDENT QUALIFIED RESERVES EVALUATORS GLJ Petroleum Consultants Ltd. Calgary, Alberta Sproule Associates Limited Calgary, Alberta Sproule International Limited Calgary, Alberta STOCK LISTING - CNQ Toronto Stock Exchange The New York Stock Exchange COMPANY DEFINITION Throughout the annual report, Canadian Natural Resources Limited is referred to as “us”, “we”, “our”, “Canadian Natural”, or the “Company”. CURRENCY All amounts are reported in Canadian currency unless otherwise stated. ABBREVIATIONS Abbreviations can be found on page 22. METRIC CONVERSION CHART To convert Multiply by To barrels thousand cubic feet feet miles acres tonnes cubic metres cubic metres metres kilometres hectares tons 0.159 28.174 0.305 1.609 0.405 1.102 COMMON SHARE DIVIDEND The Company paid its first dividend on its common shares on April 1, 2001. Since then, dividends have been paid quarterly. The following table shows the aggregate amount of the cash dividends declared per common share of the Company and accrued in each of its last three years ended December 31, 2015. 2015 2014 2013 Cash dividends declared per common share $ 0.92(1) $ 0.90 $ 0.575 (1) Annualized dividend value. On December 31, 2015, the Company paid the dividend that would have been paid in January, 2016. NOTICE OF ANNUAL MEETING Canadian Natural’s Annual and Special Meeting of the Shareholders will be held on Thursday, May 5, 2016 at 1:00 p.m. Mountain Daylight Time in the Ballroom of the Metropolitan Centre, Calgary, Alberta. CORPORATE GOVERNANCE Canadian Natural’s corporate governance practices and disclosure of those practices are in compliance with National Policy 58-201 Corporate Governance Guidelines and National Instrument 58-101 Disclosure of Corporate Governance Practices. Canadian Natural, as a “foreign private issuer” in the United States, may rely on home jurisdiction listing standards for compliance with most of the New York Stock Exchange (“NYSE”) Corporate Governance Listing Standards but must disclose any significant differences between its corporate governance practices and those required for U.S. companies listed on the NYSE. Canadian Natural follows Toronto Stock Exchange (“TSX”) rules with respect to shareholder approval of equity compensation plans and material revisions to such plans. TSX rules provide that only the creation of or material amendments to equity compensation plans which provide for new issuance of securities are subject to shareholder approval. However, the NYSE requires shareholder approval of all equity compensation plans whether they provide for the delivery of newly issued securities, or rely on securities acquired in the open market by the issuing company for the purposes of redistribution to plan beneficiaries, and material revisions to such plans. Canadian Natural has a performance share unit plan pursuant to which common shares are purchased through the TSX. This is not a new issue of securities under the performance share unit plan and under TSX rules the plan is not subject to shareholder approval. Canadian Natural has included as exhibits to its Annual Report on Form 40-F for the 2015 fiscal year filed with the United States Securities and Exchange Commission certificates of the Chief Executive Officer and Chief Financial Officer certifying as to disclosure controls and procedures and internal control over financial reporting. Printed in Canada by McAra Printing. Design and produced by nonfiction studios inc. 103 Canadian Natural 2015 Annual ReportPremium Value. Defined Growth. Independent.Canadian Natural Resources Limited T 403.517.6700 F 403.517.7350 ir@cnrl.com E 2100, 855 – 2 Street SW Calgary, AB T2P 4J8 www.cnrl.com 

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