Canadian Natural Resources Annual Report 2011

Plain-text annual report

The Premium Value Deﬁned Growth Independent 2011 ANNUAL REPORT TABLE OF CONTENTS 02 2011 Performance Highlights 04 Letter to our Shareholders 08 Our World-Class Team 10 Year-End Reserves 17 Management’s Discussion and Analysis 55 Management’s Report 56 Management’s Assessment of Internal Control over Financial Reporting 57 Independent Auditor’s Report 59 Consolidated Financial Statements 63 Notes to the Consolidated Financial Statements 97 Supplementary Oil and Gas Information 104 Ten-Year Review 106 Corporate Information Canadian the advantages, strengths & strategies Financially Strong Growing Production Economically Strong balance sheet metrics Debt to Book Capital — 27% Debt to EBITDA — 1.1X Balanced asset base provides capital allocation ﬂexibility High working interest and operatorship provides ﬂexibility in capital allocation opportunities Investment grade debt ratings Provides ﬂexibility in access to capital and the ability to capture value added opportunities Strong free cash ﬂow generation Base assets generate strong free cash ﬂow to fund longer term projects 12 years of dividend growth 21% Compound Annual Growth Rate Return on capital focused By owning and operating top quality assets and being the most efﬁcient and effective producer, the Company can maximize return on capital for all projects, with strategies in place to grow production economically Production forecast * (MBOE/d) 1,200 1,000 800 600 400 200 0 2011 2012F 2015F 2018F Light crude oil, NGLs and natural gas net increments Bitumen thermal oil (”Thermal in situ”) increments Horizon increments Primary heavy and Pelican crude oil increments 2011 BOE Canadian Natural Natural to deliver long-term shareholder value Providing Long-Term, Sustainable Production Free Cash Flow Generation Top quality oil sands assets Transforming the Company to a longer life, sustainable asset base Target to generate free cash ﬂow while developing assets for short, mid and long-term value growth Large, diverse portfolio of assets provides a host of opportunities with signiﬁcant upside This free cash ﬂow will support the Company’s ability to: 1. Add to the asset base through opportunistic and accretive acquisitions 2. Invest in long-term developments and projects 3. Increase dividends 4. Reduce debt 5. Purchase common shares While maintaining a balanced production mix One of the advantages of developing both in situ and upgraded mining assets Percent of total liquids production * 60% 50% 40% 30% 20% 10% 0% 2007 2011 2015F 2018F Thermal in situ – sold as heavy crude oil Horizon – sold as synthetic crude oil * Dependent upon economic and regulatory conditions, global economic factors, project sanction and capital allocation. 2011 Annual Report 1 Performance 2011 highlights FINANCIAL ($ millions, except per common share) Product sales Net earnings Per common share – basic – diluted Adjusted net earnings from operations (2) Per common share – basic – diluted Cash ﬂow from operations (3) Per common share – basic – diluted Capital expenditures, net of dispositions Long-term debt (4) 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) (6) $ $ $ $ $ $ $ $ $ $ $ $ $ 2011 2010(5) 2009(1)(5) $ $ $ $ $ $ $ $ $ $ $ $ $ 15,507 2,643 2.41 2.40 2,540 2.32 2.30 6,547 5.98 5.94 6,414 8,571 22,898 296 40 30 23 389 $ $ $ $ $ $ $ $ $ $ $ $ $ 14,322 1,673 1.54 1.53 2,444 2.25 2.23 6,333 5.82 5.78 5,514 8,485 20,368 271 91 33 30 425 11,078 1,580 1.46 1.46 2,689 2.48 2.48 6,090 5.62 5.62 2,997 9,658 19,426 234 50 38 33 355 1,231 1,217 1,287 7 19 1,257 599 10 16 1,243 632 10 18 1,315 575 (1) Per common share amounts have been restated to reﬂect a two-for-one common share split in May 2010. (2) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation to this measure is discussed in the Management’s Discussion and Analysis (“MD&A”). (3) Cash ﬂow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company’s ability to fund capital reinvestment and repay debt. The derivation of this measure is discussed in the MD&A. Includes the current portion of long-term debt. (4) (5) Comparative ﬁgures for 2010 have been restated in accordance with IFRS issued as at December 31, 2011. Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. (6) 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 Drilling activity (net wells) (1) North America North Sea Offshore Africa Core unproved property (thousands of net acres) (2) North America North Sea Offshore Africa Company gross proved reserves (3) 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) 2011 2010 2009 1,233 1,051 - 1 1 7 1,234 1,059 13,585 12,594 128 4,191 128 4,193 17,904 16,915 793 1 5 799 N/A N/A N/A 3,753 3,423 3,116 228 109 252 120 265 136 4,090 3,795 3,517 4,266 4,092 3,731 98 83 4,447 4,831 78 92 4,262 4,505 72 99 3,902 4,167 (1) Excludes net stratigraphic test and service wells. (2) Due to the conversion to NI 51-101 disclosure requirements in 2010, the Company is reporting “unproved property” which is property or part of a property to which no reserves have been speciﬁcally attributed. As a result of the change, 2009 has been excluded as comparisons would not be meaningful. (3) Year-end proved reserves were prepared using forecast prices and costs. Strong balance sheet metrics Balanced production (2012F) Growing reserves per share (BOE/share) 60% 50% 40% 30% 20% 10% 0% 2.0x 1.5x 1.0x 0.5x 0.0x 31 39 % 30 7 6 5 4 3 2 1 0 06 07 08 09 10 11 12F 02 03 04 05 06 07 08 09 10 11 Debt to book capital (LHS) Debt to EBITDA (RHS) Thermal in situ oil and heavy crude oil Light and medium crude oil, NGLs and SCO Natural gas Gross proved plus probable (2P) reserves per share Gross 2P reserves prior to 2010 were prepared using constant prices and costs. Excludes Horizon SCO reserves prior to 2009. 2011 Annual Report 3 Dear Shareholders, Letter to our Shareholders Canadian Natural and its shareholders are in an enviable position. For over 20 years we have built a balanced and diverse portfolio containing high quality, long life assets with signiﬁcant upside. Our deﬁned plan to develop these assets is predicated on leveraging our balanced and diverse portfolio of assets, by allocating capital to the highest return projects, thereby maximizing our asset value for shareholders regardless of commodity price cycles. Our strategy of strong area and infrastructure ownership coupled with our high level of operatorship affords us control and ﬂexibility in how we allocate capital. Our commitment to maintaining a strong balance sheet and a high degree of capital ﬂexibility ensures we can respond quickly to the ever-changing economics of our business. We have experienced operational, technical and ﬁnancial teams dedicated to creating shareholder value through operational excellence. Our experiences and challenges in 2011 will result in even stronger operational discipline, which is essential in building a world class oil and gas company. In 2011, crude oil projects presented the best return opportunities for Canadian Natural and the majority of our capital budget was allocated to these projects. We focused on the continued development of our high quality thermal in situ assets, expanded the Pelican Lake tertiary recovery project and the plans for Horizon oil sands mine expansion – all part of our strategy to transition the Company to a longer-life more sustainable asset mix. In addition, we executed record drilling programs in primary heavy crude oil and North America light crude oil, and generated strong free cash ﬂow from our international operations. Economics of natural gas projects were challenged in comparison to our crude oil projects as a result of low natural gas prices; however, we continued with a modest development project at our liquids rich Montney shale gas development at Septimus and a small drilling program to preserve our premium land base. North America Crude Oil and NGLs We are one of the largest producers of heavy crude oil in North America. In 2011, we grew our heavy crude oil production by 8% over 2010 levels. We have an extensive land position that will allow us to economically grow our heavy crude oil production in the short, mid and long term. Our thermal in situ operations achieved 9% production growth in 2011 over 2010 as a result of excellent operational performance and low cost pad developments at Primrose, our cyclic steam stimulation project. With a substantial number of pads left to develop and the potential to further optimize steaming techniques, we are targeting to grow production by 9% in 2012. At our Kirby South Phase 1 thermal in situ project, we completed two of seven pads on budget and on schedule, further conﬁrming our geological expectations. Kirby South Phase 1 is targeted to add 40,000 barrels per day of production capacity with ﬁrst steam in targeted for late 2013. Engineering progress was made on future Kirby expansions and Grouse in 2011. Regulatory application submissions were made for future Kirby expansions in Q4/11 and for Grouse in Q1/12. With over 78 billion barrels of bitumen Canadian Natural remains committed to investing in projects that provide the highest returns on capital. Our large and diverse portfolio of high quality crude oil and natural gas assets provide opportunities for creating shareholder value today and far into the future. 4 Canadian Natural Allan P. Markin Chairman N. Murray Edwards Vice-Chairman John G. Langille Vice-Chairman Steve W. Laut President initially in place, our deﬁned plan to develop our high quality thermal in situ assets will grow production to 480,000 bbl/d and signiﬁcantly contribute to transitioning the Company to a longer life, more sustainable asset mix. Our high quality and extensive thermal in situ assets will provide value growth for decades to come. Primary heavy crude oil provides excellent short term growth to complement our longer term projects with the capability to further grow in the mid and long term. Our land position, containing a vast amount of oil initially in place, allows us to grow production and maintain efﬁcient and effective operations. In 2011, strong economics and our team’s ability to execute a record primary heavy crude oil drilling program resulted in 11% production growth. In 2012, we are targeting to drill over 800 net wells and target to grow production 15%. Opportunities exist to increase crude oil recoveries so we continue to study new technologies such as ﬂooding techniques and horizontal drilling to further exploit this large resource. Primary heavy crude oil wells provided some of the highest return on capital projects in 2011, and in the current environment look to continue that trend going forward. Our leading edge polymer ﬂood at Pelican Lake has been very successful at increasing oil recoveries. The project represents the largest ﬂood of its kind in North America and second largest in the world. Ultimately we believe this leading edge technology will result in the recovery of an additional 561 million barrels of heavy crude oil reserves and resources from the 4.1 billion barrels of oil initially in place. At the end of 2011, approximately 50% of the pool was under polymer ﬂood. We continue to learn and optimize our execution strategy to further maximize capital and operating efﬁciencies and deliver signiﬁcant value from this world-class oil pool. We have the necessary experience operating mature pools and we continue to look for ways to optimize our light crude oil operations in Western Canada by evaluating and implementing enhanced recovery techniques to increase recoveries. In 2011 we increased our North America light crude oil and NGLs production by 13% on the back of a record drilling program and we are targeting 17% production growth in 2012. We have a large land presence and assets in the light crude oil regions in Western Canada and we will leverage technology to further enhance shareholder value. In 2012 we target to expand light crude oil production with nine new pool developments and target to drill 134 net wells. This signiﬁcant light crude oil growth provides balance in our production proﬁle. North America Natural Gas As one of the largest producers of natural gas in Western Canada, our substantial land and infrastructure base allows us to be one of the most efﬁcient and effective operators. This is the key component in our ability to generate free cash ﬂow in the current price environment. With an average natural gas lifting cost of approximately $1.15/Mcf we are able to generate positive margins from virtually our entire portfolio even in a depressed price environment. Net crude oil and natural gas wells drilled 1,500 1,200 900 600 300 0 06 07 08 09 10 11 12F Net crude oil wells Net natural gas wells Total production per day (MBOE), before royalties 800 700 600 500 400 300 200 100 0 06 07 08 09 10 11 12F Crude oil production Natural gas production 2011 Annual Report 5 Canadian Natural holds one of the largest unproved land bases in Western Canada with exposure to virtually every play type found in the basin. We continue to delineate new and existing plays and further strengthen our unconventional and tight natural gas asset base through the application of new technology. However, we will be selective in our approach to developing these assets until the economics of natural gas becomes favorable and competes with our crude oil assets. In 2011 we focused on the development of our liquids rich Septimus Montney shale gas play in North East British Columbia. We drilled 13 net wells and successfully completed a tie-in to a deep cut gas facility, which provides further value by extracting additional liquids. Septimus continues to exceed expectations and in 2012 we plan to expand the plant and drill 17 additional wells to ensure the plant operates at optimal capacity. International North Sea and Offshore Africa are core operating areas for Canadian Natural. Our international assets provide light crude oil balance to our diverse portfolio and continue to provide free cash ﬂow. We operate the vast majority of our international operations which gives us the offshore expertise necessary to recognize potential development prospects and evaluate new opportunities in the international arena. In 2011 the UK government implemented a tax increase in the North Sea that resulted in a 24% reduction in the UK North Sea after-tax proﬁts. As a result we have curtailed much of the long term volume adding investment in the North Sea. We believe our efﬁcient and effective operations will allow us to create value, but with reduced investment levels in this mature basin, and we will continue to high grade all North Sea prospects for future development opportunities. In Offshore Africa we are maximizing the usage of existing slots and are targeting to begin inﬁll drilling at our Espoir Field in late 2012. We are targeting to add production of 6,500 BOE per day at the completion of this drilling program in 2013. Horizon Oil Sands Production was reduced in 2011 as a result of a ﬁre in the coker unit in primary upgrading that occurred in Q1/11. Full production capacity of 110,000 barrels per day of synthetic crude oil (“SCO”) was restored in Q3/11 and necessary enhancements to ensure a high level of safety were made. Safety is a core value at Canadian Natural and we have leveraged the lessons learned from this experience and have moved forward as a stronger operator in Oil Sands Mining. In 2011 signiﬁcant progress was made towards increasing reliability and redundancy at Horizon. The third ore preparation plant and associated hydro-transport were turned over to operations in Q1/12 and will signiﬁcantly contribute to increased reliability. As part of our staged expansion to 250,000 barrels per day of SCO, the Board of Directors has approved targeted expansion capital expenditures of approximately $2 billion for 2012. While there are still numerous challenges and potential inﬂationary pressures ahead, our team has a strong execution strategy. The expansion has been broken down into smaller more focused projects to allow for greater capital ﬂexibility and increased access to a greater depth of contractors. Detailed front end engineering and design work will be completed prior to awarding work packages to ensure the scope of work is well deﬁned and greater cost certainty and project execution can be achieved. In 2011, projects under construction were running at or below cost estimates. As well, several contracts were awarded in the year which will enhance cost certainty going forward. We will continue to be cost driven not schedule driven as we develop this world class opportunity that will deliver production and positive cash ﬂow to our shareholders for decades. Our plan to economically grow the Company is anchored by our culture, which focuses on developing people to work together, to create value for the Company’s shareholders, by doing it right with fun and integrity. 6 Canadian Natural Marketing Canadian Natural has an effective three pronged marketing strategy to capture access to markets over the short, mid and long term as we unlock the value of our vast crude oil and natural gas reserves. The objective is to ensure the maximum realized price for our portfolio. When considering our large heavy crude oil production, current and forecasted, the ﬁrst key component of our strategy is blending; we blend our crude oil streams to create an attractive, high quality feedstock for reﬁners. In 2011 Canadian Natural was the largest contributor to the Western Canadian Select (“WCS”) blend. The second component of the strategy is to actively support and participate in new pipelines and expansions to existing pipelines. We are a supporter of the Keystone XL pipeline with a 120,000 bbl/d commitment for 20 years, which will give us access to the US Gulf Coast where a large concentration of heavy crude oil reﬁneries exist. The third component is to support and participate in projects that add conversion capacity. In the ﬁrst quarter of 2011, we announced our partnership agreement with North West Upgrading Inc. to move forward with detailed engineering regarding construction and operation of a bitumen upgrader and reﬁnery near Redwater, Alberta. The bitumen upgrader and reﬁnery ﬁts well with Canadian Natural’s strategy to seek additional conversion capacity and remove incremental barrels of bitumen from the market. We are targeting to sanction the project in 2012. Our Disciplined Strategy 2011 was a testament to our ﬁnancial discipline and sound business philosophy. Our continued focus on balance sheet maintenance resulted in improved metrics, increased liquidity and a balanced budget for 2011 despite reduced production from Horizon. We are in an enviable position to generate signiﬁcant free cash ﬂow by allocating capital to the highest return projects. For 2012 our priorities for free cash ﬂow are clear; we will continue to capitalize on opportunistic acquisitions when they become available, add value and compete for capital with our other projects. In 2011, we executed over $1 billion of opportunistic acquisitions that created immediate value by further strengthening our land and infrastructure base and ensuring maximum facility utilizations and minimum operating costs. We will target to increase dividends as we have for the past twelve consecutive years; the Board of Directors has approved a dividend increase of approximately 17% for 2012, representing a 21% compound annual growth rate since the Company ﬁrst paid a dividend. We will further strengthen our balance sheet by reducing debt and we will continue to target common share buybacks to offset dilution. We believe that our ability to grow production in the short, mid and long term while generating free cash ﬂow, increasing dividends and effectively transitioning the Company to a longer life, more sustainable asset base is what sets us apart from our peers. Conﬁdence in our ability to create long term value is shown in our high level of management ownership and our approach to conducting our business in a safe and responsible manner. Our strategy works, our assets are strong and we have the people, systems and expertise to deliver long term shareholder value. Allan P. Markin Chairman N. Murray Edwards Vice-Chairman John G. Langille Vice-Chairman Steve W. Laut President Dividend growth history $0.45 $0.40 $0.35 $0.30 $0.25 $0.20 $0.15 $0.10 $0.05 $0.00 01 02 03 04 05 06 07 08 09 10 11 12F Dividend declared per common share 2011 Annual Report 7 Our World- team 5,276 Strong: Diversity, Talent, Expertise Duncan Aamot, Lonnie Abadier, Zahra Abbas, Christiaan Abbenhuis, John Abbott-Brown, Walday Abeda, Peter Abercrombie, Naeem Abro, Chandresh Acharya, Darren Acheson, Troy Adair, Denis Adam, Shane Adam, Wade Adam, Belinda Adams, Douglas Adams, Mike Adams, David Adamson, Debra Addinall, Zoe Addington, Adetokunbo Adebayo, Yemisi Adebayo, Adebukola Adegoroye, Abdinasir Aden, Adeolu Adetowubo, Jeff Adshade, Katalin Agardi, James Agate, Anurag Agnihotri, Kelly Agombar, Miguel Aguirre, Sarshar Ahmad, Shahzad Ahmad, Adel Ahmari, Pervez Ahmed, Salman Ahmed, Shakeel Ahmed, Dong Ai, Terry Aickelin, Richard Aikens, Garrisen Ailsby, Jason Airlie, Kristy Aitken, Jeffrey Akeroyd, Sina Akinsanya, Sanjay Akolkar, David Albert, Jose Alcala, Suhaib AlDhabbi, Bruce Alexander, Joseph Alexander, Vincent Alexander, Walter Alexandru, Daniel Alfred, Elena Algazina, Mohieddin Alghazali, Arshad Ali, Haider Ali, Ziba Ali Khani, Rachel Aliazas, John Allan, Peter Allard, Geoff Allen, Jill Allen, John Allen, John D Allen, Trent Allen, Simon Allerton, Devin Allibone, Karen Almadi, Jocelyn Alonso, Tarik Alsai, Fadia AlSakaf, Ali Al-Saleem, Khaled Alsouqi, Chris Alston, Arturo Alvarez, Jonny Alvarez, Mathew Alves, Joann Aman, Clark Ambler, Donald Ames, Daniel Amey, Gary Amundrud, Jan Andersen, Troy Andersen, Audrey Anderson, Diane Anderson, Georgina Anderson, Jeremy Anderson, Kelvin Anderson, Kristin Anderson, Leonard Anderson, Marilyn Anderson, Melissa Anderson, Perri Anderson, Steve Anderson, Kristin Andreas, Meghan Andreas, Peter Andrekson, Daniel Andreoli, Cole Andrews, Louise Andrews, Todd Andrews, Evan Angel, Carlo Angeles, Gloria Angeles, Kimberley Anglehart, Carolyn Angus, Muhammad Anis, Emma Annis, Stuart Annis, Greg Anstey, Kathy Antonishyn, Taylor Antoniuk, Shelley Antonuk, Prince Appiah, Brandon April, Richard April, Luc Arbour, LeRoy Archer, John Argan, Humberto Arias, Mirian Arias, Juan Arizaleta, James Arkley, Anthony Armstrong, Darryl Armstrong, Randall Armstrong, Rob Armstrong, Shonn Arndt, Colin Arnold, Jorge Arroyave, Bruce Arscott, Bala Arunachalam, Sudhakar Arunachalam, Arthur Ashley, Donald Ashley, Wilhelmina Ashun-Codjiw, Randy Aslin, Roy Aspden, Steven Aspden, Darrin Assinger, Aymann Assoum, Andrew Astalos, John Atkinson, Edwin Au, Gordon Au, Sarah Aube, Jason Auch, Bernard Auger, Richard Augustyn, Carlos Aular, Ryan Austin, Maria Avila, Carlos Aviles, Oluseyi Awodein, Rajeev Ayachit, Kylan Ayers, Ward Ayles, Jabran Ayub, Farooq Azam, Adediran Babalola, Krishnaswamy Babu, William Bachmeier, Adrian Baciulica, Coleby Backus, Angela Bacon, Michael Baddeley, Kiranjit Badh, Kafayat Badmos, Joan Badock, Vijay Bagde, Babak Baghban, Alex Bagnall, Brian Bahlieda, Dave Baier, Rod Bailer, Alex Bailey, Andrew Bailey, Caleb Bailey, Darrel Bailey, Judy Bailey, Kimberley Bailey, Roysden Bailey, Leon Bakaas, Alysa Baker, Gloria Baker, Sharon Baker, Thomas Balakas, Charity Baldwin, Mark Baldwin, Robert Baldwin, Vaughn Baldwin, Irineo Balicanta, Joel Balkam, Darin Balkwill, Glen Ball, Justin Ball, Michael Ball, Johnathon Ballard, Gary Ballas, Ronnie Ballas, Sheldon Ballas, Tyson Ballas, Brenda Balog, Thomas Ban, Cassandra Banack, Joshua Banak, Neville Banak, Saiyed Banamia, Darwin Banash, Junet Banawa, Mark Bancroft, Nabarun Banerjee, Ritwick Banerjee, Adam Banﬁeld, Lance Banks, Linda Banks, Bennett Bannis, Teresa Banny, Cirilino Bantaya, Inge Bantli, Stephen Barber, Garry Bardoel, Larry Bardoel, Pamala Bare, Muhammad Bari, Ross Barker, Sharon Barker, Andrew Barley, Dennis Barnes, Beata Barnett, Rees Baron, Deborah Barr, Piper Barr, Sean Barr, Eliezer Barreto, Robert Barten, Blair Bartlett, Cynthia Bartlett, Eddie Bartlett, Michael Bartlett, Catlin Bartman, Marty Bartman, Jose Basabe, Lloyd Basines, Calvin Bast, Somnath Basu, Michael Batac, Cheryl Bateman, Gwendolyn Bateman, Kevin Bateman, Mark Batovanja, Brenda Battyanie, Jennifer Batuyong, Jackie Bauer, Lydell Bauer, Ronnie Bauer, Jerry Bauman, Raymond Bazan, Brett Beach, Andrew Beacon, Colin Beaman, Harold Beamish, Chad Beaton, Aura Beattie, Sean Beattie, Kimberly Beatty, Randall Beatty, Erica Beauchamp, Alexandra Beaudoin, Joshua Beaudoin, Justin Beaudoin, Richard Beaudoin, Laurier Beaunoyer, Francis Beaver, Brent Beck, Chris Becker, Robert Beckner, Gurpreet Bedi, Sheldan Beebe, Keith Begg, Walter Behnke, Anhar Belah, Guy Belanger, Kelly Belanger, Lesley Belcourt, Andre Belisle, David Belisle, Calvin Bell, David Bell, Gillian Bell, Joey Bell, Jon Bell, Nicole Bell, Nigel Bell, Stephen Bell, Reg Bellanger, James Beller, Matthew Beller, Michael Bembridge, Ahmed Bendahmane, Khalida Bendahmane, Brad Bendick, Jennifer Benko, Kim Benner, Chris Bennett, Clayton Bennett, Erick Bennett, Jonathan Bennett, Murray Bennett, Robert Bennett, Ruth Bennett, Kenneth Benoit, Brad Bensmiller, Shelly Bensmiller, Amanda Benson- Bartko, Linda Beresh, Conrad Bereznicki, Debbie Berg, Jason Berg, Kevin Bergen, Jeffrey Bergeson, Tyson Bergheim, Becky Bergley, David Berlinguette, Henry Berlinguette, Daniel Bernardo, Dmitry Bershadsky, Bryan Bertrand, Murray Bertsch, Jeffrey Best, Jonathon Best, Judy Best, Tyler Betteridge, Lindsay Betthel, Stewart Bettinson, Bernard Beyer, Umeet Bhachu, Atul Bhadauria, Indu Bhasin, Rupal Bhatt, Sushanta Bhattacharyya, Pareshkumar Bhavsar, Amber Bickerton, Marc Bickham, Corey Bieber, Daniel Bieber, Douglas Bielech, Eugene Bieleski, Derek Biener, Inge Biener, Ahmed Bilal, Geronimo Bilic, Judy Billard-Payne, Roger Binkley, Roger Bintz, John Bird, Sharon Bird, Blaine Bischoff, Robert Bischoff, Shane Bischoff, Christopher Bish, Kathy Bishop, Travis Bishop, Craig Bisschop, Debasis Biswas, Darwin Bittner, Adam Black, Chad Black, David Black, Paul Blackburn, Kenneth Blackhall, Kerri Blackmore, Daniel Blain, Adam Blair, Brittnee Blair, Deana Blais, David Blake, Barton Blakney, Alvaro Blanco, Ulises Blanco, William Blanco, Chris Blatchly, Shawn Blaydes, Zoe Bleackley, Kari Bleile, Juan Carlos Blesa, Parrish Blizard, Ryan Blonar, Rosalie Blondin, Rolland Blouin, Jarett Blume, Gregory Blundon, Curt Blyan, Carlos Boadas Salazar, Henry Bocalan, Allan Boddy, Rodney Bodell, David Bodenham, Adam Bodnar, Dennis Boehmer, Kent Boerrichter, Dean Boettcher, Darcy Boettger, Warren Bogelund, Marty Boggust, Brent Boguslaw, Nathan Bohning, Juan Bohorquez, Gordon Bohrson, Lauren Boida, Claude Boily, Evan Boire, Jeannine Boire, Marc Boisvert, Michael Bolianatz, Greg Bolin, Gregory Bolton, Paul Bond, Shawn Bond, Ariadna Bonilla, Wesley Bonn, Tom Bonwick, Richard Booker, Patricia Booklall, Jim Boomgaarden, Charlene Boraas, Barry Borbely, Adriana Borbon, Keith Bordeleau, Joshua Borg, Robert Borg, Fernando Borjas, Mark Born, Michael Born, Erwin Borsini Marin, Jon Borstel, Blair Bosch, Dave Bosch, Stewart Bosch, Lisa Bosik, Jonathan Bottaro, Rocky Botting, Keith Bottriell, Daniel Bouchard, Maurice Bouchard, Carey Boucher, Suzanne Boudignon, Tyler Bouma, Rick Bourassa, Sheldon Bourassa, Derek Bourgoin, Delwood Bourke, Daryl Bourque, Daniel Boutin, Jason Bouvier, Devrey Bowen, Jonathan Bowen, Robert Bowers, Slade Bowers, Sue-Anne Bowers, Jason Bowie, Bruce Bowles, Clinton Bowles, Clayton Bowman, Ernest Bown, Eric Boy, Dean Boyarski, Tanya Boyce, Philip Boychuk, Doug Boyd, Kristen Boyd, Patrick Boyd, Raymond Boyd, Shirley Boyd, Charline Boyer, Lorraine Boyle, Richard Boyle, Neil Bozak, John Brabec, Dave Bracey, Bryan Bradley, Kenneth Bradley, Peggy Bradner, Jan Bradshaw, Marianne Brady, Mary Jane Brady, Linda Bragg, Derek Braid, Ali Brain, Jo-Ann Brake, Nicholas Brake, Stephen Brake, Tyler Branch, Shaela Brandt, Brian Brant, David Brant, Edna Brant, Myron Brataschuk, Colin Brausen, Luis Bravo, Neil Bray, Tess Bray, Gordon Brecht, Debbie Breen, Sharon Breitkreuz, Paul Breland, Stephen Brent, Barry Brenton, Lori Brenton, Ryan Brenton, Roxane Bretzlaff, Olaf Breukel, Anthony Brewer, Cecil Briggs, David Briggs, Gregory Briggs, Ian Brightmore, Archie Brighton, Lynne Brinkworth, Denis Brisebois, Donald Britton, Shawn Brockhoff, Brian Broda, Kelly Broda, Daniel Broderick, Dwayne Brodziak, John Brogly, Erica Broidioi, Jacobus Bronkhorst, Robert Bronson, Murray Brooker, Andy Brooks, Debbie Brooks, Jeremy Brooks, Tanya Brooks, Kenneth Brosowsky, Christopher Brousseau, Eric Brousseau, Brenda Brown, Carol Brown, Christopher Brown, Curtis Brown, Eugene Brown, Jason Brown, Jennifer Brown, Jeremy Brown, Julie Brown, Leanne Brown, Leroy Brown, Morgan Brown, Thomas Brown, Leo Browne, Robert Brownless, Danny Brownrigg, Chris Bruce, Shelly Bruce, Kyle Bruggencate, Fred Brugger, John Brule, Russell Brundige, Laurie Bryenton, Michelle Bryson, Sean Bryson, Richard Buchanan, Michael Bucholtz, Gordon Buckshaw, Linda Buczkowski, Bill Budd, Tom Budd, Robert Budzen, Raymon Bueckert, Darren Buffett, Wayne Bugiak, Justin Buholzer, Ian Bulloch, Joe Bullock, Don Bumstead, Douglas Bumstead, Danielle Bungay, Sarah Bungay, Clarence Bur, Dion Burak, Jeffrey Burchell, Trevor Burchenski, Jeffrey Burdett, Grant Burgess, Gordon Burhoe, David Burke, Lyle Burke, Graham Burkhart, Glenn Burnett, Ryan Burnham, Jenna Burns, Rob Burns, Allison Burry, Kimberley Burry, Dale Bursey, Mary Beth Bursey, Barry Burt, Shawn Burt, Darryl Burton, Gerard Burton, Robert Busato, Janine Bushey, Colleen Bussey, David Bussey, Juan Bustos, Kimberly Butcher, Cecil Butler, Meghan Butler, Robert Butler, Sharjeel Butt, Bob Butterworth, Ronald Butts, Leanne Butz, Peter Buxton, Ron Buye, Mike Buytels, David Byrnes, Mike Byrtus, Irina Byvald, Moraima Caceres-Centeno, Geoffrey Cahoon, Ling Cai, Simon Cains, Winnie Calabio, Laura Calder, Leslie Calder, Byron Caldwell, James Caldwell, Patrick Caldwell, Tom Callaghan, Patrick Callin, Richard Calliou, Gracell Calonge, Cindy Cameron, Ryan Cameron, Shirley Cameron, Lisa Campacci, Clayton Campbell, Darryl Campbell, David Campbell, Dean Campbell, Doug Campbell, Gwen Campbell, John Campbell, Kyle Campbell, Michael Campbell, Nancy Campbell, Niall Campbell, Andre Campeau, Wayne Campeau, Gregory Cane, Rafael Canelon Oyarzabal, Brad Canning, Nicholas Cantwell, Kelly Cap, Richard Cap, James Capjack, John Capstick, Barry Carabin, Angela Cardenas, Fred Cardinal, Lee Cardinal, Rachel Cardinal, Robert Cardinal, Wayne Cardinal, Mark Carew, Justin Carey, Joey Carifelle, Rodger Carifelle, Jeffery Carlson, Jordan Carlson, Wes Carlson, Dean Carnes, Albert Caron, Rochelle Caron, Yves Caron, Douglas Carr, Luis Carranza, Viridiana Carrasco Rueda, Diego Carrera, Michael Carrier, Wayne Carrigan, Greg Carroll, Ian Carroll, Jason Carroll, Eduardo Cartaya, Christopher Carter, Eric Carter, Marilyn Carter, Nicholas Carter, Jessica Cartwright, Steven Cartwright, Felix Casalla, Gary Case, Mary-Jo Case, Patrick Cashin, Trevor Cassidy, Lance Casson, Zaira Odett Castillo Navarro, Mike Catley, Steve Caven, Richard Cawaling, Ciara Celis, Marco Celis, Ali Centeno, Samuel Cervantes, Rupinder Chahal, Andrew Chaisson, Christopher Chakaipa, Sachi Chakravarty, Harry Chalmers, Mark Chalmers, Samantha Chalmers, Kevin Champagne, Kevin Champagne, Lise Champagne, Alan Chan, Chung Yin Chan, Ivy Chan, Loretta Chan, Mel Chan, Ranee Chan, Sarah Chan, Tim Chan, Wayne Chandler, Alan Chaney, Koh Chang, Kyle Chapman, Kenton Chappell, Darryl Charabin, Christopher Charbonneau, Jeffrey Charpentier, Lance Charrois, Roger Chartrand, Susan Chase, Leon Chateauneuf, Mahesh Chaudhari, Rajesh Chauhan, Robyn Chauvin, Mark Chayko, Carl Cheeseman, Bo Chen, Chung Pin Chen, James Chen, Lulu Chen, Tie Long Chen, Xiping Chen, Daniel Chenier, Mike Chernichen, Tyler Cherry, Benjamin Chester, James Cheung, William Cheung, Hersendeep Chhokar, Bidya Chhualsingh, Kenneth Chia, Joel Chiasson, Gloria Chick, Debbie Chidley, Conal Child, Al Chin, Melaine Chin, Trish Chipiuk, Bradley Chisholm, Thomas Chisholm, Corinne Chong, Raymond Chong, Alexander Choo, Brent Chopping, Brett Chorney, Curtis Chornohos, Sujoy Choudhury, Eddie Chouﬁ, Rashed Chowdhury, Alphonse Chretien, Ryan Christensen, Marianne Christianson, Heather Christie, Shawn Christie, Caroline Christopherson, Andy Chu, Paul Chu, John Chuiko, Peter Chung, Heather Church, Sharon Church, Broc Churchill, Gerald Churchill, Natalie Churchill, Roderick Churchill, Elaine Cissell, Michael Clapham, William Clapperton, Andrea Clark, Janice Clark, Kim Clark, Lynne Clark, Tyson Clark, Bradley Clarke, Ken Clarke, Martha Clarke, Sanja Clarke, William Clarke, Walter Clarkson, Greg Clegg, Reagan Clemmer, Joseph Clevenger, Denise Clifton, George Clutton, Brooke Coburn, John Coers, Cory Coish, Leanne Colborne, Rob Coles, Celibeth del Carmen Colina, Lorne Collard, Patrick Colley, Marc Collie, Grant Collier, Garth Collings, Gary Collings, Curtis Collins, Jayson Collins, Robert Collins, Rod Collins, Simonne Collins, Anne Collison, Gordon Collison, Gordon D Collison, Adam Collyer, Tiffany Collyer, John Commance, Quinn Conacher, John Condie, Mark Connellan, Spencer Constant, David Conybeare, Chris Cook, Gary Cook, Anna Cooke, Justin Cooke, Lori Cookson, Brian Coolen, Rob Coolen, Sean Coolen, Heather Coolidge, Gary Coombe, Robert Coombes, Kent Cooper, Laura Cooper, Uriah Cooper, Michael Copithorne, David Coppard, Robert Coppard, Nicola Corbett, Mark Corell, Elaine Coreman, Clair Cormier, Rocky Cormier, Ronda Cornell, Grant Corner, Alessandro Corradi, David Corson, Jim Corson, Rhys Corson, Shirley Corson, Zaida Cortez, Pierpaolo Corticelli, Harry Costello, Jordan Costley, Brad Cote, Cynthia Cote, John Cote, Dougie Coull, Eric Coulombe, Kim Coulter, Jack Courchene, Robert Courchesne, Gerald Courtney, Kathryn Courtney, Vincent Courville, Dave A Cousins, David H Cousins, Mark Coutu, Peter Covell, Keith Cowger, Cath Cowie, Craig Cowie, Robert Cowley, Brandon Cox, Gemma Cox, Jonathan Cox, Joseph Cox, Randy Cox, Jeffrey Coyle, Edward Cozicor, Nigel Crabb, Harry Crabtree, Richard Craft, Cody Craig, Layne Craig, Raymond Craig, Harlan Craigie, Bruce Crain, Kelly Cramb, Patrick Cramb, Troy Cramm, Marina Crawford, Michael Crawford, Bernette Crawley, Jessica Crawley, Beverley Creed, Paul Crellin, Leanne Cressman, Roger Crichton, Kayla Critch, Wendy Crockford, Kevin Croft, Shane Croft, Stefan Croft-Bednarski, Gordon Crooks, David Crosley, Christopher Cross, Ryan Cross, Amber Croswell, Shawn Crowe, Barbara Crowley, Britney Crowley, Linda Cruttenden, Francisco Cruz, Anthony Csabay, Shawn Cudmore, Edgardo Cuello, Darrel Cunningham, Davis Cunningham, Tara Cunningham-Canﬁeld, Arley Currie, David Currie, Brent Curtis, Troy Curzon, Kenneth Cusack, Pat Cusack, Real Cusson, John Cutler, Daniel Cyr, George Cyr, Bonnie Czaplan, Suzanne Da Costa, Kevin d’Abadie, Victor Daboin, Andrew Dabrowski, Fakhri Dadashov, Gary Dahl, Abdelhamid Dahmani, Mark Dailey, Brittany Dalby, Patrick Dale, Layne Dalgetty-Rouse, Germain Dallaire, Scott Dalrymple, Gary Daly, Noe Damian-Diaz, Stanley Dams, Everett Dana, Walter Danchak, Trevor Daniels, Mike Danis, Islamuddin Dantiwala, Peter Danyluk, Daniel Daraban, Babs Daramola, Andrew Dareichuk, Mark Darling, Wells Darling, Merl Darragh, Martin Darveau, Altaf Dasurkar, Siddhartha Datta, Hareshkumar Dave, Kevin Davey, Sean David, Bruce Davidson, Graham Davidson, Jeffery Davidson, Mike Davidson, Scott Davidson, Thomas Justin Davidson, Todd Davidson, Trevor Davidson, Charlee Davies, Derek Davies, Leah Davies, Lynne Davies, Maxwell Davies, Simon Davies, Frank Davis, Graham Davis, Karen Davis, Kevin Davis, Morley Davis, Randall Davis, Peter Davison, Shari Dawe, Lisa Dawson, David Day, Julia Day, David Daye, Douglas De Avila, Meinrado de Chavez, Raphael De Jesus, Eric de Kock, Ryan De Leeuw, Benito De Lorenzo, Robbert de Ruiter, Albert De Sousa, Brian de Winter, David Dean, Harry Dean, Trevor Debler, Richard deBoer, Ron Erick DeCastro, Derek Dechaine, James Dechaine, Raymond Dechaine, Roland Dechesne, Dave Defoort, Sheldon DeFord, Mervin Degenstien, Barbara Deglow, Eldon DeLaRonde, Mitchell Dell, Michael DeLorme, Michael RJ DeLorme, Ibrahim Deme, Charlene DeMone, Whyman Dempster, Fred Denney, Judy Denney, Geoffrey Dennis, Susan Dennis, Kimberley Dennis-Wood, Shirley Denny, Chris Denslow, Jayme Derix, Amanda Derksen, Timothy Derksen, Greg Derouin, Semir Dervovic, Ajit Desai, Nareshchandra Desai, Heidi Desaulniers, Miles Deschambeau, Darren Deschene, Andre Desharnais, Guillaume Desjardins-Knowlden, Kelsey Deutsch, Laurie Devey, John DeVries, Todd Dewhurst, Dana Dey, Karen Deyaegher, Maldip Dhaliwal, Roseinder Dhaliwal, Pirmohammed Dhalwala, Keith Diakiw, Sumara Diaz, Karen Dickason, Bob Dicken, Garry Dickie, Anthony Dicks, Evan Dicks, Blair Dickson, Cameron Dickson, Francis Dickson, Alexander Didenko, Sue Didyk, Brenda Diebel, David Diebel, Irene Dikau, Anne Dillon, Mike Dingley, Pat Dingley, Robin Dingwell, Ronald Dinkel, Hubert Dinn, Chris Dionne, Michael Dirk, Tim Ditchburn, Robin Dixon, Roderick Dixon, Trent Dixon, Denise Dixson, Jeremy D’Mello, William Dobchuk, Leanne Dobson, Linnae Dobson, Michelle Docherty, Edward Dochuk, Russell Dodd, Ally Dodds, Erin Doepker, Kelly Doepker, Ritchie Doering, Robert Doering, Jared Doetzel, James Doleman, Logan Dolen, Kathy Doll, Brenda Dombrova, Kyle Donald, Scott Donaldson, Claire Dong, Manson Dong, Jason Donovan, Veronica Dooling, Michael Dorcas, Sascha Dorer, Allen Dorey, Mark Dorocicz, Jason Dorusak, Amrit Dosanjh, Real Doucet, David Doucette, Martin Douglas, Scott Douglas, Dahl Dow, Angela Dowd, Jeff Dowd, Andrew Dowman, Melissa Dowman, Phil Downes, Adam Doyer, Richard Doyer, Glen Doyle, John Doyle, Lisa Doyle, Stephen Drake, Darcy Draper, Kevin Draper, Kyle Draper, Todd Draper, Wayne Draper, Kenton Dreger, Brian Drew, Timothy Dreyer, Joshua Driedger, Tanya Driscoll, Elaine Drolet, Chasity Druhan, Colleen Drury, Steven Drysdall, Victoria D’Souza, Mark Du Preez, Calvin Duane, Rafael Duarte, Noel Dube, Sean Dubelt, Troy Dubie, Rosalind Ducey, Rick Ducharme, Peter Duda, Susan Duff, Alan Duffy, Simon Dugdale, Douglas Duguid, Albert Duhaime, David Duke, Doug Duke, Cheryl Dumais, Laurent Dumoulin, Stella Dumoulin, Barry Duncan, Sean Duncan, Gavin Dunn, James Dunn, Krystal Dunn, Robert Dunn, Edward Dunnet, Judy Dunsmuir, Kurt Dupuis, Lyle Dupuis, Michael Durnie, Harvey Dutchak, Oleh Dutka, Robert Duval, Abhishek Dwivedi, Alvin Dyck, Cuyler Dyck, Charles Dyer, Terry Dyer, Eugene Dyjur, Lawrence Dyke, Linzi Dykes, Steven Dykstra, Richard Dyson, Cindy Dzamon, Krzysztof Dzwonek, Julina Eagleson, Gary Earl, Julie Easthope, Brian Eastman, Shauna Eaton, Kevin Eberle, Rosario Ebuna, Greg Ecker, Craig Eddy, James Edens, Malcolm Edirisinghe, Premadasa Edirisinghe, Colin Edlund, John Edmunds, Gordon Edward, Dave Edwards, Michael Edwards, Hazel Egerton, Christopher Ehresman, Ingrid Eichelbaum, Kevin Eike, Theodore Eissfeldt, Brian Eitzen, Devin Ekdahl, Mariam El Gohary, Samuel Eleko, David Eley, Mahmoud Elgebali, Terence Elias, Anthony Ell, Dean Ell, Khalid Elladen, Beverley Ellerton, Diane Elliott, Robert Elliott, Shaun Ellis, Edwin Ellsworth, Matthew Elms, Maritess Eloursa Escanela, Trevor Ely, Heather Emery, Jacqueline Emro, Dean Enberg, Crystal Eng, Rommel Engler, Joanne English, Laura Ennis, Terry Enzsol, Ross Ephgrave, Terry Erickson, Angela Erixon, Michael Ernst, Polina Ersh, Patricia Escalona, Francys Escobar de Serra, Kelly Esquirol, Sarah Esson, Candice Estelle, Oscar Estrada, Andrew Etele, Samantha Etherington, Andrew Evans, Dean Evans, Lee Evans, Randy Evans, Tyler Evans, Susan Eveleigh, Clayton Eves, Doug Eves, Ken Ewach, Laura Ewen, Kris Eyolfson, Veronica Ezeronye, Lawrence Facchina, Randal Faechner, Denis Fagnan, Stephanie Fairﬁeld, Eric Falconer, Romuald Fandio Njantou, Yan Fang, Andy Fankhauser, Douglas Farney, Ali Farokhsiar, Paul Farrell, Greg Farrer, Randy Farrer, Travis Farrer, Barry Fast, Arthur Faucher, Roberto Faustini, Everette Fauth, Karman Fayant, Renee Fayant, Michael Fear, Andrew Fearne, Penny Fedorus, Ella Fedossova, Cody Fedun, Jeremie Feland, Warren Feland, Wallace Feltham, Edwin Fender, Kurt Fenrich, Logan Fentie, Randy Fenton, Ken Ference, Lawrence Ference, Helen Ferguson, Mark Ferguson, Scott Ferguson, Ana Camila Fernandez, Eduardo Fernandez, Sergio Fernandez- Trujillo, Ninfa Ferrer, Brenda Ferris, Michael Ferris, Mark Ferry, Nathan Fester, Ron Fewer, Darren Fichter, Michelle Fielden, Walter Fielding, Bill Fiﬁeld, Chris Filgate, Michael Filipchuk, Neil Findlay, Bob Finlayson, Darren Finnamore, Chad Finnebraaten, Kevin Finnerty, Kathryn Finnigan, Timothy Finnigan, Edesio Finol, Tanya Fir, Lori Fischer, Calvin Fisher, Joel Fisher, David Fittkau, Sandra Fitzpatrick, Karen Flack, Colleen Flamont, Ken Fleck, Doug Fleming, Sean Fleming, Stephen Fleming, Rodney Flett, Bruce Flockhart, Trevor Flood, Eduardo Flores, Reynaldo Flores, Joshua Flynn, Mark Flynn, Kimberley Foisy, David Fokema, Brent Foley, Hop Chi Fong, Yvonne Fong, Gregory Fontaine, Leo Fontaine, Robert Fontaine, Roger Fontaine, Lynn Foo, Randy Foran, Winston Foran, Adele Forcade, David Forfar, Donald Forget, Luc Forget, Curtis Formanek, Randy Formanek, Devon Fornwald, Brett Forrester, Leslie Forrester, Alastair Forsyth, Hugo Forte, Danny Fortin, Colton Foster, Donald Foster, Kevin Foster, Dwayne Fotty, Kevin Foulds, David Fowler, Grant Fowler, Jim Fowler, Sergio Fraino, Donna Frame, Fiona Frame, Roger France, Vicky France, Oscar Franchi, Dustin Francis, Ron Frank, Allan Frankiw, Dru Franklin, James Franks, Shelley Franssen, Randall Frasch, Gary Fraser, Kevin Fraser, Lenny Fraser, Michael Fraser, Ken Frazer, Brent Frechette, Rhonda Free, Ernest French, Peter French, Roger Frere, Jared Frese, Kurt Freyman, Danielle Friedt, David Friesen, Kenneth Friesen, Monte Friesen, David Fritz, Andrei Frizorguer, Frank Frosini, Scott Froude, Andrea Fry, Xiao Wei Fu, Karen Fujimoto, Doug Fukushima, Jason Fung, Jim Fung, Sarina Fung-Yau, Mathew Funk, Danny Furlotte, Hayley Furst, Ted Furuya, Donald Gabruck, Josephine Gaddi, Leonard Gadowski, Sharon Gaehring, Joan Gaeta, Marcel Gagnon, Serge Gagnon, Serge R Gagnon, Brett Galbraith, Jaylyne Galey, Ron Gall, Frederick Gallant, Ryan Gallant, Fabio Gallardo, Michael Gallon, William Galloway, John Galotta, Yoko Galvin, John Galway, Carlos Gamboa, Luis Gamboa, Liz Gammack, Andreas Gamp, Amitkumar Gandhi, Pinal Gandhi, Luis Ganhao, Darren Ganske, Brett Gantz, Vovel Gapaz, Carlos Garcia, Manuel Garcia, Jonathan Gardiner, Kyle Gardiner, Benjamin Gardner, Doug Gardner, Lynette Gardner, Jason Gareau, Jon Gareau, Richard Gareau, Tim Gareau, Rajeev Garg, Linda Garvey, Stan Garwon, Martina Garza, Carlos Garzon, Victoria Gatchalian, Janet Gatrell, Francis Gaudet, Maurice Gauthier, Michelle Gauthier, Neil Gauthier, Klaus Gautschi, Steve Gavronsky, Cheryl Gawley, Rebecca Gayler, James Geddes, Mike Geddes, Cory Geier, David Geleta, Lesley-Ann Gemmell, Tracy General, Michel Genereux, Glenn Genge, Patricia Gentles, Matthew George, Shinil George, James Georget, Jim Gergely, Matthew Gering, Grant Gerla, Jennifer Gerla, Michel Germain, Raymond Germain, Robert Germain, Cameron German, Colin Germaniuk, Kevin Gervais, Paul Gervais, Sheldon Getson, Vanessa Getty, Glenn Getz, Nicole Getz, Stanley Getz, Ken Getzinger, Behnoush Ghashghe, Karim Ghesmat, Mohammad Reza Ghods-Esfahani, Essam Ghoubrial, Nolan Gibbons, Douglas Gibson, Shaun Giefer, Todd Giesbrecht, Dwayne Giggs, Tamara Giles, Kevin Gill, Neelufer Gill, Ralph Gill, Perry Gillam, John Gillatt, John Gillespie, Ron Gillespie, Timothy Gillespie, John Gillingham, Martin Gillund, Mihaela Gillund, Kevin Gilman, Justin Gilmour, Daniel Ginez, Paul Gingras, Kevin Ginter, Todd Ginther, Luz Edlyn Giraldo, Donald Girard, Ben Gisby, Maria Gisondo Crawford, Eugenio Giuliani, Troy Given, Marvin Gladue, Russell Gleed, Ryan Glover, Jason Glubish, Keith Godin, Laurie Godwin, Peter Goetz, John Gogol, Lida Goldchteine, David Golden, Chad Goldie, Alan Goll, Jorge Gomez, Julio Gomez, Cody Gomuwka, Elaine Gong, Kun Gong, Brian Gonsalves, Iride Gonzalez, Jose Gonzalez, Nilda Gonzalez, Yvonne Gonzalez, Craig Good, Christine Goode, James Goodwin, Katherine Goodwin, Wayne Goodwin, Josh Gorai, David Gordon, Ian Gordon, James Gordon, Steven Gordon, Winston Goretsky, Michael Gorman, Jayme Gorski, Trent Gosse, Yvon Gosselin, Kristen Goudie, Allan Gould, Christian Goulet, Pierre Goulet, Henri Gousseau, Rajiv Govil, Britt Gowland, Mini Goyal, John Graca, James Grad, Carl Graham, Craig Graham, David Graham, James Graham, Marah Graham, Stephanie Graham, Trevor Graham, Ed Grams, Bryan Granger, Austin Grant, Harry Grant, Sandra Grant, Anthony Graup, Toby Graveson, Bonnie Gray, Darrell Gray, Jenny Gray, Ronald Gray, Sheila Gray, Steph Gray, Christopher Grayston, Donald Greaves, John Greaves, Edie Green, Wayne Green, Cory Greenawalt, Dallas Greenawalt, Corinne Greene, Theresa Greene, Trevor Greene, Marc Greenwood, Dale Greep, Alexandre Grenier, Joseph Grenier, Richard Grieve, Edmond Grifﬁths, Nathan Grimble, Jacobus Grobbelaar, Robert Groenen, Shaun Grueter, Daryl Grundner, Denis Grzela, Paulette Guard, Daniel Guay, Hiromi Guest, Moustapha Gueye, Don Guglielmin, Clarence Guilderson, Aliya Gulamhusein, Karim Gulamhusein, Donald Gulayec, Robert Gulutzan, Jonathan Gumbley, Carolyn Gunderson, Lauren Gunnell, Alan Gunst, Ashok Gupta, Kaushik Gupta, Bernard Gurba, Mike Gurin, Edward Gushnowski, Dianne Gushue, Terry Gusnowski, Graham Gustafson, Derick Ha, Zhanyao Ha, Bartley Haahr, Cornelius Haas, Rodney Haberlack, Christopher Habiak, Cameron Hachey, Jason Hack, Violet Haddad, Leisa Haddleton, Resad Hadzismajlovic, Kelsey Hagen, Larry Hagg, Chad Hagstrom, Keith Hague, Robert Haigh, Allan Hains, Ahmad Haj Hamdan, Sam Hajar, Shemin Haji, Zohreh Hajibeygi, Mohammadreza Hajimohammadi, Dan Halaburda, Hassan Halepota, Dean Halewich, Ravinder Haley, Jon Halford, Rick Halkow, Barry Hall, Donald Hall, Jordan Hall, Michael Hall, Shane Hall, Todd Halladay, Chris Hallborg, David Hallett, James Hallett, Robert Hallett, Paul Hamel, Larry Hamende, Sacha Hamill, Edson Hamilton, Robert Hamilton, Tim Hamilton, Kevin Hamm, Michael Hammel, Larry Hammell, Gordon Hammond, Rick Hammond, Chrystal Hamori, Brent Hamrell, Michael Hamula, Brad Hancock, Raymond Hank, Tracy Hanline, Ernest Hanlon, Elizabeth Hann, Karl Hann, Alexander Hansen, James Hansen, Poul Hansen, Arthur Hanson, Judy Hanson, Leland Hanson, Brent Harbin, Leon Harder, Ashley Hardes, Carson Harding, Kent Hardisty, Edavazhiyath Harikumar, Joel Harke, Ken Harke, Julia Harker, Brent Harle, Erik Haroldson, Douglas Harpur, Alistair Harris, Bill Harris, Jody Harris, Murray Harris, Roger Harris, Stephen Harris, Clayton Harrison, Dylan Harrison, Randy Harsany, David Hart, Caroline Hartley, Darcy Harty, James Harty, Thomas Harty, Amie Harvey, Douglas Harvey, Greg Harvey, Jerry Harvey, Julie Harvey, Cheryl Hasenclever, Lew Haskewich, Mostafa Hassan, Mubbashar Hassan, Bernd Hassenstein, Iain Haston, Peter Hatt, Christine Hattebuhr, Wayne Hatton, Dave Haub, Jason Haub, Ross Hauger, Wayne Hausch, Paul Hausmanis, Jason Haviland, Lindsay Hawco, Sheila Hawco, Betty Hayden, Cameron Hayden, Kurt Hayden, Craig Hayes, Mark Hayes, Kris Hayko, Dave Haywood, Angela Hazen, Shawn Head, Jay Heagy, Andy Heale, Brad Hearn, Crystal Heath, Larry Heath, David Hebert, Gerald Hebert, Gerald Hebert, Joseph Hebert, Luc Hebert, Maynard Hebert, Wade Hebert, Terry Heck, Jeffrey Hecker, Christopher Heffner, Della Hefford, Christopher Hehr, Sherrie Heil, Robin Hein, Tanner Helboe, Wes Henderson, Randy Henley, Steven Hennessey, Anita Hennig, Alison Henry, Reid Henry, Daniel Herauf, Jeremy Herbison, Brad Herman, James Herman, Judith Hermann, German Hernandez, Pedro Hernandez, Julio Herrada, Luis Herrera, Edwin Herrenschmidt, Coreen Herring, Jeremy Herritt, Joanne Herron, Michele Herron, Ryan Heska, Keith Heslop, Brian Hess, Tyson Hessler, Peter Hickey, Riley Hickey, Kelly Hicks, Kimberley Hicks, Robert Hicks, Timothy Hiemstra, Rodney Higa, Andrew Higgins, Jason Higgins, Matthew Higgins, Rachelle Higgins, Charlene Hill, David-Nelson Hill, Hugh Hill, Kevin Hill, Steven Hill, Jeffrey Hillier, Jody Hillier, Todd Hillier, Robert Hilton, Brent Hindmarch, Ken Hingley, Kelly Hinton, Donald Hiscock, Jodi Hiscock, Darryl Hitra, Godwin Ho, Margaret Ho, Stephen Ho, Donald Hoar, Jonathan Hoare, Dora Hodder, Holly Hodder, Jason Hodder, Jason Hoey, Barbara Hofer, Terry Hoff, Reid Hoffman, Jill Hofmann, Sean Hogan, Joanne Hogg, Robert Hogg, Andrew Hollebakken, Donald Holley, Bradley Holloway, Doug Holman, Richard Holman, David Holt, Brett Holthe, Clayton Holthe, James Holton, Keith Hommy, Daniel Hompoth, Kambiz Honar, Donald Hood, Shannon Hood, Ryan Hoogendam, Graham Hook, Nathan Hook, Joseph Hooper, Loreena Hopkins, Yvonne Hopkins, Noll Hopner, Trevor Hornberger, Keith Hornseth, Kimberley Horvath, Richard Horvath, Jon Horyn, Kenneth Hosker, Lance Hoskyn, Glen Hossack, Iqbal Hossain, Thomas Hostettler, Tony Libo Hou, Jeff Houck, Stephen Houck, Sherri Houle, Justine House, Trent House, Wayne Hovdestad, John Howard, Trapper Howard, Kristy Howe, Sanjib Howlader, Darren Howlett, Michael Howrish, Tyrone Hoyles, Wade Hoyles, Robert Hoyt, Tracy Hrycay, Ai Qun Hu, Guobin Hu, Jianxin Huang, Nicky Huang, Joseph Hubelit, Kyle Huculak, William Huddlestun, Frank Hudec, John Hudec, David Hudson, Denis Hudson, Paul Hudson, Ryan Hudson, Sandy Huebner, Kirby Huey, David Hughes, Jeffery Hughes, Mark Hughes, Virginia Hughes, Megan Hughesman, Michael Hughson, Eun Ju Huh, Marc Human, Jenna Humphrey, Daniel Hunchak, Manpreet Hundal, Ian Hundeby, Jennifer Hunt, Kevin Hunter, Leanne Hunter, Robert Hunter, Rodney Hunter, Javed Huq, Jason Hurd, Robert Hurtubise, Abid Hussain, Abdulrahman Hussaini, Glenn Hussey, Dennis Hutchinson, Robert Hutchinson, Cody Hutchison, Lonnie Hutchison, Ray Hutscal, Bruce Hutt, Ewart Hutton, An Huynh, Yeen Shien Hwang, Adam Hymanyk, Richard Hyndman, David Hynes, Scott Hyrcha, Sarah Hyslop, Gerard Iannattone, Pina Iannattone, Tamara Idler, Nathan Ilchuk, Traian Ilie, Kenneth Imlach, Gregory Imlah, Christopher Inglis, Max Inglis, Rob Inglis, Sandy Inglis, Brad Inman, Matt Inscho, Muhammad Irfan, Jeff Irons, Claudio Rafael Isea Natera, Darren Isele, Murad Ishankuliev, Hamid Ishaque, Floyd Isley, Goulﬁa Ismaguilova, Victor Itulua, Arlette Ivany, Lisa Iversen, Jaclyn Iwamoto, Vijayraghavan Iyengar, Lindsay Jack, Wallace Jack, Dennis Jackson, Kurtis Jackson, Robin Jackson, Ronald Jackson, Russel Jackson, Timothy Jackson, Victoria Jackson, Arne Jacobson, Ken Jacobson, Albert Jacula, Curtis Jacula, Marci Jacula, Todd Jacula, Donald Jaeger, Vivek Jain, Michael Jaindl, Rajesh Jakher, Boris Jakulj, Stephen Jamam, Darryl Jaman, Chris James, Bob Jamieson, Sally Jamieson, Maria Jancewicz, Ian Janeo, Aaron Janes, Lloyd Janes, Marc Janke, Dale Jans, Peter Janson, Simon Janssen, Tristan Janusc, Leonard Janzen, Ian Jappy, Christian Jardine, Nancy Jarman, Calvin Jarratt, Brett Jarvis, Jim Jarvis, Wendy Jarvis, Usman Javaid, Hamid Javarani, Derek Jeannotte, Jamie Jeannotte, Michael Jegou, Wendal Jellison, Greg Jenkins, Tyler Jenkins, Jason Jenner, Daniel Jennings, Michael Jennings, Anthony Jensen, Brent Jensen, Karl Jensen, Kevin Jensen, Parry Jensen, Mark Jespersen, Mary-Ann Jesso, Tristan Jessome, Daryn Jestin, Deshun Jiang, Simon-Xinmin Jiang, Weidong Jiang, David Jimenez, Ramon Jimeno, Mahmud Joarder, Terry Jocksch, Gardner Joe, Juan Joffre, Kristoffer Johansson, Brent Johns, Darrell Johns, Cory Johnson, David Johnson, Dustin Johnson, Jeffrey Johnson, John Johnson, Jordan Johnson, Larry Johnson, Magnus Johnson, Marlene Johnson, Neville Johnson, Richard Johnson, Sally Johnson, Scott Johnson, Stacy Johnson, Theresa Johnson, Neil Johnston, Norman Johnston, Shaun Johnstone, Dan Johnston-Watson, Victoria Jolliffe, Ed Jones, Gareth Jones, Mark Jones, Neil Jones, Pamela Jones, Robert Jones, Tammy Jones, Paul Joo, Damian Jordan, Randolph Joseph, Amola Joshi, Tushar Joshi, Umeshkumar Joshi, Jessica Josselyn, Stuart Josselyn, Puthenchakkalak Joy, Jaime Juan, Richard Jubinville, Tim Juett, James Jung, Sandy Jung, Chris Jungen, Ronald Jungkind, Marjorie Junio-Read, Cassandra Jurick, Edith Kabuthia, Mark Kachmarchyk, Asif Kachra, Alexander Kaczorek, Aliadil Kaderi, Tony Kadikoff, Mary Kadri, Jonathan Kadutski, Chad Kaglea, Raymond Kahanyshyn, Honeyvinder Kahlon, Myra Kalakailo, Sameer Kalbag, Kevin Kalinsky, Sheron Kalirai, Derek Kalynchuk, Yui Kam, Bina Kamath, Eric Kamieniecki, Elizabeth Kaminski, Grzegorz Kamon, Sharon Kanarek, Aravinthan Kandasamy, Larry Kane, Shari Kane, Robert Kanomata, Sheryl Kapeluck, Surshen Karmakar, Tom Karpa, Karen Kartushyn, Doug Kary, Jerome Kasha, Natalia Kashirina, Lynn Kasper, Martinus Kaspers, Nadim Kassam, Amy Kastelic, Myles Kathan, Uma Kathiresan, Deanne Katnick, Hassan Katrip, Amogh Katyayan, Cherie Kavalec, Travis Kavalec, Richard Kavanagh, Rory Kavanagh, Olga Kay, Alwyn Kaye, Diana Kazandzhiev, Mary Kealey, Kelly Kearns, Leigh Keech, Lori Keefe, Philip Keele, John Keith, Joe Kelenc, Marina Keller, Ernest Kellough, Marilyn Kelloway, Paul Kelloway, David Kelly, Tim Kelly, Simon Kelsey, Sherry Kelts, Tyler Kemmer, Greg Kemp, Stephen Kempton, Ross Kendell, Wayne Kennedy, Scott Kent, Val Kenyon, Dan Kenzle, James Keough, Craig Kerpan, Juliana Kerr, Rob Kerr, Shane Kerr, Stephanie Kers, Shaudia Keslick, Blair Kessler, Teena Keswick, Lori Ketchuk, Brian Kevol, Ajmal Khan, Aman Khan, Asadullah Khan, Muhammad Taqdees Khan, Mukhtar Khan, Shaﬁque Khan, Shehnaz Khan, Sadhana Khanolkar, Snezhana Khoromskaya, Muhammad Khurshid, Serge Kiasosua, Roy Kidmose, Kimberly Kielt, Leonard Kiez, Todd Kilback, Michael Kilcollins, Olga Kilo, Susan Kilvington, Heather Kim, Ronald Dae Jung Kim, Mark Kinden, Billie-Jo King, Brian King, Calvin King, Dale King, Justin King, Murray King, Ray King, Richard King, Tony King, Tasha Kingsbury, Peter Kinnear, Stuart Kinnear, Roland Kinney, Cam Kinniburgh, Marvin Kinsman, Mathew Kinuthia, Paul Kip, Brennan Kirk, Brandon Kiss, Brent Kissel, Marlene Kissoon, Bob Kitsch, Curtis Kiyawasew, Jody Kiziak, Cody Klatt, George Klemak, Dawnann Klimczak, Douglas Klug, Robert Kneteman, Julie Knibbs, Allen Knight, Joyce Knight-Ehiwe, Sheryl Knock, Ronald Knoedler, William Knouse, Tamara Knox, Dwayne Kobes, Russ Kobi, Barney Kobzey, Bill Koch, Patricia Koch, Lyle Koehl, Blair Koizumi, Tamer Koksalan, Chase Kolberg, Lutz Kolberg, Roger Kolberg, Michael Kolosky, Eva Komers, Cameron Komm, Martin Kondor, Brent Kondratowicz, Natasha Kooistra, Jasmine Kooner, Herman Koops, Nathan Koops, Bonnie Kootenay, Sergey Korchagin, Brent Korolischuk, Jennifer Koslowski, Brent Kosowan, Vladimir Kostic, Diane Kostiuk, Kevin Kostrub, Ann Kostyshyn, David Kotze, Mladen Kovac, Randall Kovalenko, George Kovalev, Richard Kowalski, Sandra Kowalsky, Kevin Kowbel, Dennis Kozak, Eugene Kozakevich, Teresa Kozina, Margret Kramer, Dillon Kramps, Tina Krasnow, Trevor Kratz, Gary Krause, Lindsay Krause, Trevor Krause, Chris Krawchuk, Harold Krawec, Jessica Krawetz, Todd Kreics, Dee Jay Krein, Murray Kreiser, Kari Kremer, Daniel Krentz, Blayne Kress, Ken Krewulak, Connie Kriaski, Anand Krishnamoorthy, Ravindran Krishnamurthy, Heather Krislock, Donna Kroeger, Ryan Kroeker, Mandy Kroetsch, Peter Krol, Justin Kruse, Cedo Kucinar, George Kucy, Randall Kuka, Chad Kully, Bharat Kumar, Bhesham Kumar, Sudip Kumar, Vikas Kumar, Cindy Kung, David Kung, Dean Kunitz, Jeff Kuntz, Jason Kuorikoski, Mahendi-Ali Kureshi, Kelly Kursteiner, Frank Kurucz, Jyo Kushe, Brian Kutash, Steve Kuzmak, Corinne Kwan, Keith Kwan, Russ Kwan, Amy Kwiatkowski, Kelly Kwiatkowski, Roger Kwiatkowski, Angele Kwon, John Kwon, Karen Kyfﬁn, David Kyle, David Kyle, Bob Kyllo, Dustin Labby, Philippa LaBossiere, Julian Laboucan, Ricky Laboucan, Gordon Lacey, Alan LaChance, Nathalie Lachance, Robert Lackey, Gernot Lackner, Pierre Lacoste-Bouchet, Daniel Lacroix, Liberty Lacuna, Jocelan Ladner, Phillip Laﬂair, Levi Lafrance, Leon Lafreniere, Dilip Laha, Prabal Lahon, Cassandra Lai, Philip Lai, Renkui Lai, Rose Lai, Theresa Lai, Elizabeth Laidlaw, Kevin Laidler, Alison Laing, Ronald Laing, Joshua Lakes, Munira Lalji, Mathieu Lalonde, Eric Lam, Irene Lam, Raymon Lam, Sam Lam, Kurtis Lamb, Terri Lamb, Dee Lambert, Dino Lambert, Dawn Lameman, Richard Lameman, Trevor Lamont, Jonah Lamontagne, Sharon Lamontagne, Anne Landry, Celeste Landry, Eric Landry, Luc Landry, Marcel Landry, Shane Landry, Daniel Lane, Sherry Lane, Steve Lane, Raul Lanfranchi, Renato Lanfranchi, Johan Lange, Stephen Langford, Timothy Langill, John Langille, Michelle Langlois, Carolyn Langpap, Bonnie Lanh, Owen Lanktree, Tammy Lanktree, Pamela Lapp, Gregoire Laramee, Thomas Larnie, Michael LaRochelle, Eugene LaRose, Leon LaRose, Dave Larsh, Rob Larson, Reno Laseur, Jane LaSha, William Latchuk, Caitlin Latimer, Joan Latter, Peter Latus, Ira Lau, Joshua Lau, Michael Laudel, David Laurenson, Patricia Laurie, Karen Laurin, Nicole Laustsen, Steve Laut, Roy Lavallee, Jason Lavigne, Iris Law, Xiao Hua Law, Stephanie Lawlor, Darron Lawrence, Ewen Lawrence, Fred Lawrence, Philip Lawrence, Ray Lawrence, Gordon Lawson, Martin Lawson, Dave Laycock, Andrew Layland, Paul Layland, Sharon Layton, Greg Lazaruk, Lan Le, Mae Yu Le, Wanda Lea, Brian Leach, Trevor Leach, Evelyn LeBlanc, Rodney Leblanc, Trevor LeBoutillier, Susan Leckie, Steven Leclerc, Christopher Ledrew, Annie Lee, Colleen Lee, Dwane Lee, Howard Lee, Jennifer Lee, Linn Lee, Madison Lee, Rayanne Lee, Richard Lee, Roxcie Lee, So Young Lee, Swee Lee, Tim Lee, June Leechuy, Gillian Lefebure, Frank Legacy, Kevin Legault, Heather Leggett, Malcolm LeGrow, Wayne Lehman, Kris Lehocky, Daniel Lehouillier, Mathew Lehouillier, Jeffery Lehr, Brennan Leidal, Thomas Lemon, Robert Lendrum, Jarrod Lengyel, Candace Lenz, Heidi Leonard, Arlene Leonardo, Gary Leong, Hin Leong, Stephen Lepp, Paul Lepper, Yelena Lerner, 8 Canadian Natural Class To develop people to work together to create value for the Company’s shareholders by doing it right with fun and integrity. Erin Leslie, Gerald Leslie, Richard Leslie, Shane Lester, Bridgette Lesyk, Marcus Lethaby, Phil Letkeman, Mike Leugner, Don Leung, Jonathan Leung, Katie Leung, Preeminence Leung, Yiu Bong Leung, Maurice Levac, Kevin Levasseur, Tracy Levasseur, Tommy Leveille, Anna Leveque, Jayme Levesque, Jean Levesque, Kevin Levesque, Raymond Levesque, Shelly Lewchuk, Trevor Lewis, Jason L’Hirondelle, Troy L’Hirondelle, Huan Li, Jing Li, Qingnian Li, Xiaowan Li, Craig Liba, Zachary Licastro, Shu-Hsuan Lien, John Lieske, John Lieverse, David Lilburn, Hout Lim, Bonnie Lind, Jessica Lind, Tyrone Lindley, Ewen Lindsay, Scott Lindstrand, Karl Lingat, Melissa Liou-McKinstry, Jason Little, Melanie Little, Robert Little, Susan Little, Tracey Little, Chengxiang Liu, Ligong Liu, Liping Liu, Xue Bin Liu, Cam Lizee, Dale Lloyd, Tasia Lloyd, Sandi Lloyd-Harasym, Kevin Lo, Yvonne Lo, Elmita Lobo, Conrad Loch, Fred Locke, Laurie Lockhart, Jodie Lodoen, Rod Loewen, Joy Lofendale, Christian Lofstrom, Charlene Logan, Shauna Logan, Kavithaa Loganathan, Della Loggie, Rodney Logozar, Kristen Lomond, Craig Long, Lisa Long, Wade Longmore, Dallas Longshore, Michael Longtin, Kai Loo, Willy Lopez, Nelson Lord, Catlin Lorenson, Matthew Lorincz, Bob Lorinczy, Jennifer Los, Jose Lotito, Michelle Lou, Maria Lougheed, Allan Loughran, Stuart Lounsbury, Wayne Loutit, Christopher Love, Mellodie Love, Dan Lowe, Darryl Lowe, Devin Lowe, Joe Lowen, Leah Loyola, Eduardo Lozano, Jian Lu, Gerd Lucas, Serena Lucci, Laurie Luciow, Mark Luery, Charlene Luk, Joseph Lukan, Wes Lundell, Erin Lunn, Clarence Lunzmann, Xinying Luo, Jeff Luscombe, Jason Lush, Rees Lusk, Kristin Lussier, Darren Lutwick, Dustin Lutwick, Jim Lutyck, Kathy Lutz, Glen Lyall, Kayla Lyall, Todd Lychuk, Ken Lynam, Jason Lyonnais, Jim Lyons, Andy Ma, Christina Ma, Haibin Ma, Hong Ma, Nicky Maawia, Samuel Macarthy, Patricia MacCrimmon, Lindsey Macdearmid, Donald MacDermott, Julie MacDonald, Ray MacDonald, Raymond G MacDonald, William MacDonald, Charles MacEachern, Yun Yun Macedo, Jason Maciejewski, Jeromy Maciejewski, Allister MacInnis, Jennifer MacInnis, Shawn Mack, Brent MacKay, Grant MacKay, Kelsey MacKay, Ruth Mackay, Steven MacKay, Tim MacKellar, Richard Mackelvie, Graeme MacKenzie, Jordan MacKenzie, Ken MacKenzie, Shawn MacKenzie, Todd Mackenzie, Bernard MacKey, Adam MacKinnon, Brandon MacKinnon, Joseph MacKinnon, Trevor MacKinnon, Graham Mackintosh, Pam Mackintosh, Richard MacKnight, Candice MacLean, Kyle MacLean, Mark MacLean, Samantha MacLean, Tyler MacLean, Jamie MacLennan, Angus MacLeod, Callum MacLeod, Jamie MacLeod, Tyler MacLeod, Anne MacNeil, Bradley MacNeill, Angela MacNiven, Shane MacQueen, Hamish Macrae, Heidi MacRae, Kellie Macrae, Murdo MacRitchie, Andrea Maddocks, Dane Madoche, Glenn Madore, Hazel Madore, Robert Madore, Tony Madro, Gary Madsen, Markus Maennchen, Oda-Liz Maestre, Louis Maga, Dominic Magaisa, Mike Magnusson, Victorina Magsila, Sheryl Maguire, Bill Mah, Ray Mah, Tony Mah, Khurram Mahboobi, Tara 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Robichaud, Jasen Robillard, Amber Robinson, David Robinson, Gene Robinson, James Robinson, Julian Robinson, Scott Robson, Aaron Roche, Kelly Roche, Lennon Roche, Lorrie Rochon, Jesse Rockarts, Neal Roculan, Sheila Rodberg, Roger Rodermond, Ray Rodh, Joffre Rodriguez, Joffre A Rodriguez, William Roebuck, Paul Roett, Dean Rogal, Audrey Rogers, Kim Rogers, Martin Rogers, Murray Rogers, Lisbeth Rojas, Mercibeth Rojas- Bouchard, Maria Rojas-Elias, Kevin Roll, Louis Romanchuk, Dwayne Romanovich, Donny Romanyshyn, William Rombough, Allan Romero, Domingo Romero, Joy Romero, Ashleigh Ronald, Brent Ronayne, Claude Rondeau, Darren Rondeau, Lin Rong, Peter Ronnie, Janette Rooney, Jeffrey Rose, Martin Roseke, Moritz Rosenkranz, Samantha Roskey, Andrew Ross, David Ross, Douglas Ross, Jason Ross, Jonathan Ross, Lorna Ross, Patricia Ross, Robert Ross, Ron Ross, Scott Rosser, Worley Rosson, Jason Rostad, Barry Rosychuk, Cheryl Rosychuk, Rick Rosychuk, Roy Roth, Samuel Roth, Tom Roth, Judy Rotzoll, Christian Rounce, James Roussin, Michael Rovers, Natasha Rowden, Cheryl Rowe, Michael Rowe, Scott Rowein, Lara Rowland, Ryan Rowland, Andre Roy, Beverly Roy, Dustin Roy, April Rubia, Zenita Ruda, Vivian Ruddy, Colleen Rudolph, Luis Ruesga, Marie-Louise Ruetz, Adam Ruff, Ian Rugg, Colleen Ruggles, Erika Ruiz, Chad Runcer, Nigel Rusk, Ryan Rusnell, Denise Russell, John Russell, Sandra Russell, Domenic Russomanno, John Rutherford, Scott Rutherford, Doug Rutley, Justin Rutley, Mark Rutter, Hal Rutz, Mary Ryan, Rick Rybchinsky, Collin Ryberg, Craig Ryder, Jeff Ryll, Allison Ryzebol, Rickey Rzyhak, Ryan Saastad, Romulo Sabas, Mikael Sabo, Alexander Sabourov, Adam Saby, Muhammad(Saqib) Saeed, Shea Sagrafena, Tanner Sagrafena, Avijit Saha, Jochi Sahabandu, Aman Saini, Ashok Saini, Poonam Saini, Joseph Sair, Darlene Sakires, Roongrat Sakwattanapong, Rodrigo Sala, Sherrie Salahub, Thaer Salameh, Alba Salazar, Carla Salazar, Diana Salazar, Elena Saleh, John Sali, Cynthia Salisbury, Peter Salomon, Gord Salt, Alireza Samadi, Nathan Samer, Sepideh Samiei, Saravanan Sampanthamoorthy, Lynn Sampsel, Geoff Samuel, Titus Samuel, Chander Sanbhi, Sirena Sanchez, David Sanderson, Sandy Sandhar, Nimrat Sandhawalia, Tom Sanelli, Eddy Sangroniz, Theo Santos, Megan Santucci, Andrea SanVicente-Kraus, Joydip Sanyal, Sameer Saran, John Sargent, Anita Sartori, Martin Sas, Shawn Sauder, Greg Sauer, Rhys Saunders, Chantelle Sauve, Darcy Savard, Stacey Savas, Luc Savoie, Michelle Savoie, Colin Savostianik, Michael Sawaryn, Garth Sawatzky, Jennifer Sawatzky, Chris Sayer, Richard Sayer, Kim Scagliarini, Ryan Scammell, Brian Scarth, Robert Schaap, Kyle Schachtel, Bruce Schade, Judy Schafer, Daryl Schaffer, Brenda Schamehorn, Paul Schaub, Alan Schaufele, Lorne Schaufert, Jonathan Schechtel, Perry Scheffelmaier, Keith Scheidt, Barry Schellenberg, Melvin Schellenberg, Mike Schellenberg, Lance Schelske, David Schenk, Lou Scheper, Sally Schick, Scott Schick, Mike Schiller, Andrew Schindel, Ion Schiopu, Ronald Schlachter, David Schledt, Marcus Schlegel, Helen Schlenker, Casey Schmaltz, Jerry Schmaltz, Jeannette Schmidt, Kelly Schmidt, Joseph Schmitz, Gaetanne Schnarr, Darryl Schneider, David Schneider, Gerald Schneider, Jackie Schneider, Joseph Schneider, Luanne Schneider, Paul Schneider, Sheila Schneider, Sheryl Schneider, Blaine Schnell, Craig Schnepf, Aaron Schnick, Jack Schnieder, Ronald Schnieder, Brian Schnurer, Jesse Schoengut, Braden Schoepp, Stephen Schoﬁeld, Norm Schonhoffer, Sheldon Schroeder, Robert Schuh, Nathan Schuler, Stephen Schultheiss, James Schultz, Randy Schultz, Thomas Schulz, Annick Schumacher, Kevin Schumacher, Derek Schutte, Danielle Schwank, Lorraine Schwetz, Leslie Scory, Curtis Scott, Daniel Scott, Daniel H Scott, Drew Scott, John Scott, John Scott, Rachel Scott, Ronalda Scott, Rodney Scoville, Ashley Scriba, Marc Scrimshaw, Richard Scrimshaw, Ian Scully, Neil Scully, Geordie Seaton, Julia Seaton, Lori Seemann, Morley Seguin, Linda Sehn, Mel Sehn, Kyle Seidel, Paul Seipp, Mike Sell, Kenneth Selman, Leslie Semeniuk, Roland Senecal, Trevor Senger, Francis Sepnio, Nello Serani, Debbie Sereda, Josip Seremet, Derek Serfas, David Sergeant, Edward Serniak, Ligia Serrano, Darren Servatius, Perry Servello, Beverly Severight, James Seward, Wanda Seward, Benjamin Sey, Gianni Sgambaro, Michael Sgambaro, Ryan Sgambaro, Clinton Shackleton, Mohsen Shaﬁzadeh, Hirenkumar Shah, Maulesh Shah, Mitesh Shah, Samir Shah, Sanjay Shah, Sanjay J Shah, Sheing Saeed Ahmed Shahzad, Kaleem Shakir, Philip Shankowski, Kamleshkumar Sharma, Krishan Sharma, Manisha Sharma, Brigitte Shaw, Claire Shaw, Jessica Shaw, Oxana Shaykina, Brian Shearer, Christopher Shears, David Sheaves, Lukas Sheaves, Wayne Sheaves, Jamie Shelfantook, Ben Shenton, Stacy Shepert, Iain Shepherd, Glenn Sheppard, Robert Sheppard, Tim Sheppard, Nehal Sheth, Dean Shewchuk, Clair Shields, Colin Shields, Annette Shillam, Preston Shiner, Gillian Shiskin, Diana Shivas, Liz Shivas, Bill Shmoury, Bryden Shmyr, David Shmyr, Mohammad Shobeiri, Brandon Short, Shawn Short, Dean Shortland, Leonard Shostak, Michael Shukalov, Robert Shumay, Lisa Shute, John Shysh, Indrajit Siddhanta, Adeel Siddiqui, Melanie Siddon, Patricia Sideen, Pritam Sidhu, Matthew Sidney, Colby Sieben, Jason Sieben, John Sieswerda, Wayne Sikorski, Lorraine Silas, Tammy Silbernagel, Douglas Silk, Armindo Silva, Elvin Silva, Ismael Silva, Liana Silva, Cam Simard, Kevin Simard, Vladan Simin, Jamie Simmons, Francesca Simms, Doug Simoneau, Gerald Simpkins, Brad Simpson, Gordon Simpson, Pat Simpson, Melissa Sims, Elisha Sinclair, Garry Sinclair, Rob Sinclair, Jerret Singer, Aman Singh, Devesh Singh, Kirandeep Singh, Sukhdarshan Singh, Sukhwinder Singh, Martin Singher, Darcy Singleton, Maria Sinkova-Hovdestad, David Sirtonski, Richard Sisson, James Sjonnesen, Matt Skanderup, Kelly Skarra, Edward Skarsen, James Skifﬁngton, Geoff Skinner, Michael Skinner, Michael Skipper, Maxim Skliarov, Grace Skoczek, Jerome Skog, Mary Skogland, Michael Skolski, Shirley Skulmoski, Martin Skulski, Nicolas Skulski, Michael Skyrpan, Joe Slanina, Samantha Slater, Michael Slavin, Edward Sleet, Delwin Slemp, Darrell Sleno, Carolyn Slessor, Jennifer Sloan, Kevin Slotwinski, Jason Sloychuk, Shawn Slywka, Doreen Smale, Randolph Smart, Jocelyn Smid, Blair Smith, Carl Smith, David Smith, Derrick Smith, Emily Smith, Eric Smith, Glenn Smith, Jared Smith, Jason Smith, Jay Smith, Jordan Smith, Jos Smith, Kelly Smith, Kenneth Smith, Lawrence Smith, Margaret Smith, Maurice Smith, Michael Smith, Michael B Smith, Mike Smith, Robert Smith, Rory Smith, Ryan Smith, Sandra Smith, Sarah Smith, Scott Smith, Tim Smith, Tina Smith, Tina Smith, Todd Smith, Trevor Smith, Clayton Smitham, Allen Smyl, Richard Smyl, Brad Smylie, Kevin Snaden, Michelle Sneddon, Tenielle Snell, Garry Snider, Vernon Snider, Kurt Snow, William Snow, Douglas Snyder, Darcy Soles, Jennifer Soley, Stephen Soloshy, Kathleen Soltys, Divyesh Soni, Akshay Sonpal, Jessie Sooley, Immanuelraj Soosaiprakasam, Gale Sopczak, Hans Sorensen, Curtis Sorochan, Daryl Soroko, Golam Sorwar, Cindy Sotak, Michelle Soucy, Jaclyn Soulis, Lorraine Soutar, Harouna Sow, Dallas Spagrud, Nicola Spalding, Paul Spavor, Eddie Spearman, Rob Spears, Brent Spendiff, David Spetz, Kelly Spiker, Nicholas Spoletini, Dave Spooner, Christos Sporidis, John Springer, Mike Sprinkle, Andrew Spurrell, Ellis Spurrell, Paul Spurvey, Arthur Squire, Lawson Squire, Mark Squires, Murugan Srinivasan, Eric St Pierre, Gayle St. Croix, Robert St. Martin, Mario St. Pierre, Barry St.Jean, Jonathon Stacey, Ian Stacey-Salmon, Glen Stadnichuk, Stacey Stadnyk, Michael Stafford, Kendall Stagg, Mark Stainthorpe, Karen Stairs, Ernesto Stamile, Randy Stamp, Laura Stang, Cindy Stanway, Lezlie Stark, Christie Starnes, Scott Stauffer, Scott Stauth, Achilles Stavropoulos, Eric Stearns, Don Steele, Peter Steele, Richard Steele, Richard J Steele, Leanne Steeves, Gary Stefan, Silviu Stefan, Wayne Steffen, Ronnie Steinhauer, Allan Stella, Arnold Stella, Robert Stelten, Danniel Stemmann, Peter Stephen, Taryn Stephenson, Austin Stevens, Jane Stevens, Lyle Stevens, James Stevenson, Robert Stevenson, Robert B Stevenson, Carol Stewart, Cody Stewart, Dana Stewart, Douglas Stewart, Jordan Stewart, Karen Stewart, Karen M Stewart, Lorie Stewart, Marc Stewart, Rory Stewart, Wendy Stewart, Rick Stieben, Stewart Stirling, Matthew Stobart, Melissa Stockes, Mark Stockton, Gabriel Stoica, Shaun Stokes, Derek Stokke, Janet Storey, Didier Stout, Suzanne Strachan, Peter Strajt, Wade Strand, Audrey Strang, Robert Strang, Linda Strangway, Tanner Strangway, Brenda Stratichuk, Michael Street, William Stretch, Michael Stroh, Ross Strong, Robert Struski, Dwayne Strynadka, Linda Stuart, Peter Stuart, Russell Stuckless, Christopher Study, Dave Sturrock, Adam Styles, Ravi Subramaniam, Stephen Suche, Leonard Sudermann, Mark Sullivan, Chad Summers, Efﬁe Summers, Lenore Summers, Henan Sun, Tianxiang Sun, Suresh Sundaram, Daniel Sutherland, Lachlan Sutherland, Rick Sutton, Scott Sverdahl, Steven Swain, Neil Sweetapple, Stephen Sweetapple, Nathan Swennumson, Edward Switzer, Stacey Sydia, Don Sylvestre, Natasha Szalay, Catherine Szmata, Derek Sztym, Kyle Szydlik, Jeffrey Ta, Vicky Ta, Mubo Tade, David Taggart, Arash Taghipour, Patrick Taiani, Debra Tainton, Dorothy Tajiri, Sanjay Talati, Dave Talbot, Maria Talerico, Miguel Tamayo, Natalia Tamayo, Kunhao Tan, Mario Tandioy, Liping Tang, Galileo Tangonan, Krystalle Tanner, Michael Tanouye, Cedric Tapley, Crisalida Tarache, Bill Tarkowski, Ron Taron, Darcy Tarrant, Dallas Tatlow, Joanne Taubert, Nader Tavassoli, Ray Taviner, Brian Taylor, Carla Taylor, Chanda Taylor, Colin Taylor, Dawn Taylor, Glen Taylor, Hilary Taylor, James Taylor, Jason Taylor, Jeffrey Taylor, Ken Taylor, Leroy Taylor, Mark-David Taylor, Paul Taylor, Stephen Taylor, Todd Taylor, Joseph Taza, Darryl Tegart, Jenny Tejada, Berhanu Temesgen, Jason Temple, Tammy Temple, Derek Tempro, Jonathan Tempro, Leighton Tenn, Kevin Tennant, Kurt Tenney, Trent Terakita, Allan Terplawy, Gus Teske, Brock Tetz, Shelly Tetz, Terence Tham, Richard Theberge, Jean-Paul Theriault, Mark Theriault, Marc Theroux, Jamie Thibault, Bob Thibodeau, Richard Thibodeau, Ryan Thiessen, Karen Thistleton, Elsa Thomas, Ian Thomas, Laurie Thomas, Arthur Scott Thompson, Craig Thompson, Gerald Thompson, Herb Thompson, Ian Thompson, Kurtis Thompson, Kyle Thompson, Mark Thompson, Sabrina Thompson, Tyler Thompson, Peter Thomsen, Adele Thomson, Billy Thomson, Julie Thomson, Mark Thomson, Rory Thomson, Tyler Thorburn, Jeffrey Thorleifson, Earl Thornton, Keith Thornton, Douglas Thurman, Margaret Thurmeier, Phuc Tieu, Brian Tifﬁn, Gordon Tighe, Rachel Tilford-Njaa, Michelle Tilford-Shaw, Daniel Tillapaugh, Terry Tillotson, Colin Tiltman, David Timms, Simon Timothy, Neil Tindall, Marines Tineo, Maxwell Tinsley, Bruce Tipton, Dharmendra Tiwary, Ravindra Tiwary, Eric To, Carol Tobin, Nelson Tobin, Kevin Tobler, Dominador Tolentino, Dhiraj Tomar, Chris Tomlinson, Dale Tomlinson, Alain Tomszak, Marcela Tonon, Blair Torgerson, Lesley Torrance, Peter Torrance, Claudia Torres, Domenic Torriero, Michael Tosio, Derek Toullelan, David Tovey, Oliver Tozser, Ryan Tracy, Sabrina Traﬁak, James Trahar, Cau Dinh Tran, Brittany Trask, Linda Trautman, Warren Trelinski, Edward Tremblay, Jeannette Tremblay, Josie Tremblay, Chris Tremblett, Jacklynn Trifaux, Wade Trimble, Duc Trinh, Megha Trivedi, Shane Trottier, Rene Trudel, Ruari Truter, Lisa Tsimaras, Patrick Tso, Yun Tu, Ryan Tucker, David Tuite, Sunny Tulan, Brent Tulloch, Neil Tulloch, Chad Tupper, Tommy Turbide, James Turcotte, Terry Turgeon, Trent Turgeon, Dick Turnbull, Matthew Turnbull, Barbara Turner, Dave Turner, Ruth Turner, Stanley Turner, Brian Turpin, Danielle Turpin, Darren Turpin, Emily Turpin, Veronika Turska, Mark Tustian, Stephen Tuttle, Irene Tutto, Gordon Twin, Oleg Tyan, Angela Tyler, Erik Tylosky, Wayne Tymchuk, Don Tyner, Andrew Tyrell, Sarah Tyrell, Peter Tyrer, Ekaide Ukat, Ivan Ulovich, Eric Ulrich, Gregory Ulrich, Joselito Umali, Oscar Umana, Catherine Umpherville, Janis Underdahl, Nathan Underwood, Thang Ung, Karl Unger, Liz Urbina, Jackeline Urdaneta, Anand Vaidyanath, Allan Valentine, Darrel Valin, Darren Vallee, Louis Vallee, Michael Vallee, Anna Valmadrid, Dylan Van Brunt, Wesley Van den Oever, Michelle van der Burgh, John Van Es, Liske van Heerden, Salomon Van Rensburg, Charl Van Schoor, Dale Vande Cappelle, Christina Vander Pyl, Mallary Vankosky, Collin Vare, Michael Varga, Selena Varga, David Varty, Ana Vasquez, Maria Vasquez de Placid, Andy Vaughan, Nicolette Vaughan, Jeff Veale, Blaine Veitch, Bala Velagapudi, Gerrit Veldman, Brandon Velichka, Henry Ventura, Jorge Vera, Sheila Verigin, Natalia Verkhogliad, Dan Verleyen, Brent Verreau, Nancy Tay Vetrici, Cesar Viana, Gordon Vibert, Stanley Vicic, Neil Vick, Bonnie Vickery, Michael Vienneau, Christine Viljoen, Jason Villemaire, Ronald Vinkle, Dean Vipond, Bill Virus, George Virus, Kendall Virus, Mark Virus, Santosh Vishwakarma, Aaron Visotto, Tony Vitkunas, Mitchell Vogan, Andrew Volk, James Vollman, Eric von Hertzberg, Luke Vondermuhll, Blake Von-Grat, Chrystal Voortman, Gary Wack, Richard Wack, Katrina Waddell, Colleen Wadden, Kyle Waddy, Gene Waﬂer, Valerie Wagar, Todd Waggoner, Trevor Wagil, John Wagner, Joy Wagner, Abdul Waheed, Lee Wahl, Donald Wakaruk, Ashley Walchuk, Dave Waldner, Darcy Waldo, David Walker, Julie Walker, Andrew Wall, Brandon Wall, Christopher Wall, Dean Wall, Bruce Wallace, Christopher Wallace, Erin Wallace, Greg Wallace, Kevin Wallace, Tormod Walle, Vince Wallwork, Matthew Walsh, Patrick Walsh, Shannon Walsh, Lorie Walter, Amanda Walters, Steve Walton, John Wandler, Lei Wang, Marilyn Wang, Ping Wang, Qi Wang, Selina Wang, Shili Wang, Wei Wang, Wenyan Wang, Xiang Wang, Xing Zhu Wang, Zhenhui Wang, Blaise Wangler, Kevin Warcimaga, Danny Ward, Kathy Ward, Kirk Ward, Wayne Warholik, Chris Wark, Wanda Warman, Farooq Warraich, Jason Warren, Rob Warren, Michael Warrick, Dalpreet Warring, Faye Warrington, Paul Wassell, James Waterﬁeld, Jamie Watkins, Julie Watkins, Brenden Watson, Devon Watson, Kaye Watson, Ken Watson, Debbie Watt, Gordon Watt, Graham Watt, John Watts, Shayna Wayte, Heather Weaver, Alan Webb, Byron Webb, Geoffrey Webb, Dustin Webber, Keith Webster, Kim Wee, Jeff Weibrecht, Derren Weimer, Randy Weir, Geoffrey Weisbeck, Brock Weisgerber, Darren Welch, Mitchell Welland, Terry Welland, Boyce Wellman, Bonnie Wells, Sheldon Wells, James Welsh, Lisa Welsh, Guy Welwood, Mark Wenner, Jeromy Wenzlawe, Dwayne Werle, Craig Werstiuk, Matthew Werstiuk, Barclay Weslake, Ted Wesley, Darrin West, Michael Westad, Kris Westland, Daniel Weston, Nina Whalen, Troi Whalen, Daniel Wheating, Loyd Wheating, Ceri Wheaton, Joshua Wheaton, Andrew Wheeler, Charmaigne Whelan, Rosemarie Whelan-Maloney, Judd Whidden, Paul Whitaker, David White, David White, Fredrick White, Howard White, Jeffrey White, Jeffrey White, Nicholas White, Ralph White, Robert White, Skyler White, Terence White, Dave Whitehouse, Scot Whiteley, Cory Whitford, Brian Whiting, Michael Whittaker, Michael Whittingham, Heather Whynot, Malcolm Wiebe, Trevor Wiebe, Troy Wielgus, Darrel Wiens, Cameron Wietzel, Zandra Wigglesworth, Steven Wight, Don Wijesingha, Bob Wilbern, Mason Wilcox, Brandon Wild, Darrell Wilde, Lara Wilde, John Wilding, Daryl Wiles, Jason Wilhelm, Chase Wilk, Troy Wilk, Clifton Wilkes, Melanie Wilkie, Kirk Wilkinson, Pauline Will, Peter Will, Elmer Willard, Stanley Willette, Bill Williams, Brandon Williams, Dustin Williams, Grant Williams, Greg Williams, Julian Williams, Sherri Williams, Wes Williams, Andrew Williamson, Curtis Williamson, Kelvin Williamson, Malcolm Williamson, Brennon Willick, Jeff Willick, Mark Willis, Robin Willis, David Willms, Christian Willson, Curtis Wilson, Don Wilson, Glen Wilson, Graham Wilson, Jeff Wilson, Jim Wilson, Mark Wilson, Marty Wilson, Patrick Wilson, Robert Wilson, Tyler Wilson, Woodrow Wilson, Annie Wingert, Betty Winiarz, Catherine Winkelmans, Jodie Winquist, Robert Winslow, Craig Winsor, Jonathon Winsor, Greg Winters, Garrett Wirachowsky, Randy Wirtanen, Morris Wiseman, Paul Wiseman, Ian Wishart, Michael Witmer, Dale Wittman, Cameron Wlad, Kelly Woidak, Edith Wolfe, Colin Woloshyn, Joshua Wolstenholme, Andy Wong, Chee Wong, Jennifer Wong, Joeman Wong, Lilian Wong, Linda Wong, Lisa Wong, Maggie Wong, Wendy Wong, Cam Woo, Julie Woo, Kevin Woo, Leonard Wood, Lynn Wood, Phil Wood, Roxanne Wood, Timothy Wood, Mark Woodﬁn, Bonnie Woodman, Andrea Woods, Travis Woods, Marilyn Woodske, Robin Woolner, Leah Worobetz, Sidney Wosnack, Wade Wostradowski, Raymond Wourms, Mark Woynarowich, Richard Wright, Stephen Wright, Bin Wu, Michael Wu, Kelly Wutzke, Brent Wychopen, Brenda Wyllie, George Wyndham, Valerie Wyonzek, Brenda Wyton, Xiaochao Xie, Jin Xu, Qiang Xu, Zongyu Xu, James Yakemchuk, Kenneth Yakimowich, Canghu Yang, Daniel Yang, Jianting Yang, Lin Yang, Zhen Lin Yang, Mike Yanota, Lan Yao, Andrew Yaremko, Rick Yarmuch, James Yaroslawsky, Salman Yasin, Betty Yee, Christine Yeoman, Claire Yeoman, Justin Yeon, Jeffrey Yip, Kitty Yip, Mark Yobb, Yohanna Yohanna, Darrell York, Daryl Youck, Bradford Young, Corey Young, Dale Young, Kevin Young, Loni Young, Lynn Young, Peter Young, Rob Young, Sylvia Young, Todd Young, Eugene Yu, Clement Yuen, Dustin Yuill, Jeff Yuill, William Yuill, Anson Yukit, Brian Yurchyshyn, Robin Zabek, Armiel Zacharias, Tyler Zachoda, Cam Zackowski, David Zahara, Kent Zahara, Attila Zahorszky, Gabri Zambrano, Doug Zarowny, Kendall Zarowny, Chris Zeebregts, Lynn Zeidler, Tony Zeiser, Aleksandra Zelic, Devon Zell, Warren Zeller, Darcy Zelman, Wesley Zeniuk, Denis Zentner, Jose Zerpa, Kathy Zerr, Michelle Zerr, Boris Zevin, Kendal Zeyha, Rodney Zgierski, Jessica Zhang, Qingan Zhang, Xiaoxing Zhang, Yingte Zhang, Cui Zhao, Dong Po Zhao, Litong Zhao, Martin Zhekov, Gui Rong Zheng, Susan Zheng, Zhenkun Zheng, Shaoyue Zhong, Hong Zhou, Wanli Zhu, Evgeny Zhuromsky, Salam Ziadeh, Brenda Ziegler, Dwayne Zilinski, Robert Zinselmeyer, Mariola Zisi, Esther Zondervan, Livia Zseder, Greg Zubiak, Jeremy Zubiak, Aaron Zubot, Johnathon Zuk, Diana Zurabyan. 2011 Annual Report 9 Year-End Reserves Determination of reserves For the year ended December 31, 2011 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. Corporate Total Company Gross proved crude oil, bitumen, SCO and NGL reserves increased 8% to 4.09 billion barrels. Company Gross proved natural gas reserves increased 4% to 4.45 Tcf. Total proved reserves increased 7% to 4.83 billion BOE. Company Gross proved plus probable crude oil, bitumen, SCO and NGL reserves increased 10% to 6.52 billion barrels. Company Gross proved plus probable natural gas reserves increased 6% to 6.10 Tcf. Total proved plus probable reserves increased 9% to 7.54 billion BOE. Company Gross proved reserve additions, including acquisitions, were 437 million barrels of crude oil, bitumen, SCO and NGL and 644 billion cubic feet of natural gas for 545 million BOE. The total proved reserve replacement ratio was 249%. The total proved reserve life index is 21.4 years. Company Gross proved plus probable reserve additions, including acquisitions, were 722 million barrels of crude oil, bitumen, SCO and NGL and 793 billion cubic feet of natural gas for 855 million BOE. The total proved plus probable reserve replacement ratio was 390%. The total proved plus probable reserve life index is 33.3 years. Proved undeveloped crude oil, bitumen, SCO and NGL reserves accounted for 29% of the corporate total proved reserves and proved undeveloped natural gas reserves accounted for 4% of the corporate total proved reserves. North America Exploration and Production North America Company Gross proved crude oil, bitumen and NGL reserves increased 10% to 1.63 billion barrels. Company Gross proved natural gas reserves increased 4% to 4.27 Tcf. Total proved BOE increased 8% to 2.35 billion barrels. 10 Canadian Natural North America Company Gross proved plus probable crude oil, bitumen and NGL reserves increased 6% to 2.65 billion barrels. Company Gross proved plus probable natural gas reserves increased 6% to 5.84 Tcf. Total proved plus probable BOE increased 6% to 3.63 billion barrels. North America Company Gross proved reserve additions, including acquisitions, were 251 million barrels of crude oil, bitumen and NGL and 623 billion cubic feet of natural gas for 355 million BOE. The total proved reserve replacement ratio is 194%. The total proved reserve life index in 13.9 years. Proved undeveloped crude oil, bitumen and NGL reserves accounted for 39% of the North America total proved reserves and proved undeveloped natural gas reserves accounted for 8% of the North America total proved reserves. Pelican Lake heavy crude oil Company Gross proved reserves increased 15% to 276 million barrels due to continued expansion and improved performance from the polymer ﬂood project. Proved reserve additions were 51 million barrels. Thermal oil Company Gross proved reserves increased 6% to 974 million barrels primarily due to category transfers from probable undeveloped to proved undeveloped at Kirby North and new proved undeveloped additions at Primrose. Proved reserve additions were 91 million barrels. North America Oil Sands Mining and Upgrading Company Gross proved synthetic crude oil reserves increased 10% to 2.12 billion barrels and proved plus probable reserves increased 16% to 3.36 billion barrels. Proved reserve additions were 202 million barrels primarily due to additional stratigraphic wells drilled in the north pit. Probable reserve additions were 280 million barrels from expansion of the north pit. International Exploration and Production North Sea Company Gross proved reserves decreased 8% to 244 million BOE due to cancellation of certain of the Company’s activities that became uneconomic as a result of changes in the UK ﬁscal structure. North Sea Company Gross proved plus probable reserves are 371 million BOE. Offshore Africa Company Gross proved reserves decreased 9% to 123 million BOE due to production and technical revisions. Offshore Africa Company Gross proved plus probable reserves are 187 million BOE. Summary of Company Gross Reserves by Product As of December 31, 2011 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 Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Synthetic Oil) Crude Oil (MMbbl) (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) 94 3 17 114 41 155 59 13 156 228 121 349 73 - 36 109 56 165 76 20 79 175 74 249 204 1 71 276 112 193 1,831 71 710 974 752 - 288 2,119 1,236 2,975 170 1,121 4,266 1,572 56 2 37 95 39 2,950 125 1,389 4,464 2,516 388 1,726 3,355 5,838 134 6,980 7 56 35 98 36 134 74 - 9 83 46 129 60 22 162 244 127 371 85 - 38 123 64 187 226 16 209 451 218 669 76 20 79 175 74 249 204 1 71 276 112 193 71 710 974 752 1,831 - 288 2,119 1,236 3,056 226 1,165 4,447 1,654 56 2 37 95 39 3,095 147 1,589 4,831 2,707 388 1,726 3,355 6,101 134 7,538 2011 Annual Report 11 Summary of Company Net Reserves by Product Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Synthetic Oil) Crude Oil (MMbbl) (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) 79 3 14 96 34 130 59 13 156 228 121 349 60 - 27 87 44 131 198 16 197 411 199 610 63 17 68 148 59 207 155 1 54 210 78 143 51 539 733 575 1,514 - 236 1,750 995 2,663 141 974 3,778 1,347 39 2 29 70 29 2,437 98 1,102 3,637 1,994 288 1,308 2,745 5,125 99 5,631 7 56 35 98 36 134 47 - 7 54 29 83 60 22 162 244 127 371 68 - 28 96 49 145 63 17 68 148 59 207 155 1 54 210 78 143 51 539 733 575 1,514 - 236 1,750 995 2,717 197 1,016 3,930 1,412 39 2 29 70 29 2,565 120 1,292 3,977 2,170 288 1,308 2,745 5,342 99 6,147 As of December 31, 2011 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 12 Canadian Natural Reconciliation of Company Gross Reserves by Product As of December 31, 2011 Forecast Prices and Costs PROVED Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Synthetic Oil) Crude Oil (MMbbl) (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) North America December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 North Sea December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 Offshore Africa December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 Total Company December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 110 - 7 6 - 2 - - 2 (13) 114 252 - - - - - - 28 (41) (11) 228 120 - - 2 - - - - (5) (8) 109 482 - 7 8 - 2 - 28 (44) (32) 451 160 1 47 8 1 - - - (4) (38) 175 239 - 8 - - - - - 43 (14) 276 919 - 20 2 - - - - 69 (36) 974 1,932 - - - - - - 4 198 (15) 2,119 4,092 7 220 55 - 432 - (177) 86 (449) 4,266 63 - 18 3 - 7 - (1) 12 (7) 95 4,105 2 137 28 1 81 - (26) 334 (198) 4,464 78 - - - - - - 3 20 (3) 98 92 - - - - - - - (2) (7) 83 265 - - - - - - 29 (38) (12) 244 135 - - 2 - - - - (5) (9) 123 160 1 47 8 1 - - - (4) (38) 175 239 - 8 - - - - - 43 (14) 276 919 - 20 2 - - - - 69 (36) 974 1,932 - - - - - - 4 198 (15) 2,119 4,262 7 220 55 - 432 - (174) 104 (459) 4,447 63 - 18 3 - 7 - (1) 12 (7) 95 4,505 2 137 30 1 81 - 3 291 (219) 4,831 2011 Annual Report 13 Reconciliation of Company Gross Reserves by Product As of December 31, 2011 Forecast Prices and Costs PROBABLE Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Synthetic Oil) Crude Oil (MMbbl) (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) North America December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 North Sea December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 Offshore Africa December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 Total Company December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 14 Canadian Natural 40 - 3 3 1 - - - (6) - 41 124 - - - - - - (26) 23 - 121 57 - - - - - - - (1) - 56 221 - 3 3 1 - - (26) 16 - 218 57 - 22 4 3 - - - (12) - 74 109 - 6 - - - - - (3) - 112 783 - 17 1 - - - - (49) - 752 956 - 388 - - - - - (108) - 1,236 1,430 1 122 54 - 104 (1) (34) (104) - 1,572 20 - 11 4 - 2 - (1) 3 - 39 2,203 - 468 21 4 19 - (7) (192) - 2,516 29 - - - - - - - 7 - 36 46 - - - - - - - - - 46 129 - - - - - - (26) 24 - 127 65 - - - - - - - (1) - 64 57 - 22 4 3 - - - (12) - 74 109 - 6 - - - - - (3) - 112 783 - 17 1 - - - - (49) - 752 956 - 388 - - - - - (108) - 1,236 1,505 1 122 54 - 104 (1) (34) (97) - 1,654 20 - 11 4 - 2 - (1) 3 - 39 2,397 - 468 21 4 19 - (33) (169) - 2,707 Reconciliation of Company Gross Reserves by Product As of December 31, 2011 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 Synthetic Oil) Crude Oil (MMbbl) (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) North America December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 North Sea December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 Offshore Africa December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 Total Company December 31, 2010 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2011 150 - 10 9 1 2 - - (4) (13) 155 376 - - - - - - 2 (18) (11) 349 177 - - 2 - - - - (6) (8) 165 703 - 10 11 1 2 - 2 (28) (32) 669 217 1 69 12 4 - - - (16) (38) 249 348 - 14 - - - - - 40 (14) 388 1,702 - 37 3 - - - - 20 (36) 2,888 - 388 - - - - 4 90 (15) 5,522 8 342 109 - 536 (1) (211) (18) (449) 83 - 29 7 - 9 - (2) 15 (7) 1,726 3,355 5,838 134 107 - - - - - - 3 27 (3) 134 138 - - - - - - - (2) (7) 129 217 1 69 12 4 - - - (16) (38) 249 348 - 14 - - - - - 40 (14) 388 1,702 - 37 3 - - - - 20 (36) 2,888 - 388 - - - - 4 90 (15) 5,767 8 342 109 - 536 (1) (208) 7 (459) 83 - 29 7 - 9 - (2) 15 (7) 1,726 3,355 6,101 134 6,308 2 605 49 5 100 - (33) 142 (198) 6,980 394 - - - - - - 3 (14) (12) 371 200 - - 2 - - - - (6) (9) 187 6,902 2 605 51 5 100 - (30) 122 (219) 7,538 2011 Annual Report 15 Notes Referring to Reserves Tables (1) Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests. (2) Company Net reserves are working interest share after deduction of royalties and including any royalty interests. (3) Forecast pricing assumptions utilized by the independent qualiﬁed reserves evaluators in the reserve estimates were provided by Sproule Associates Limited: Crude oil and NGLs WTI at Cushing (US$/bbl) Western Canada Select (C$/bbl) Edmonton Par (C$/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) 2012 2013 2014 2015 Average annual increase 2016 thereafter $ 98.07 $ 94.90 $ 92.00 $ 97.42 $ 99.37 $ 82.34 $ 79.69 $ 77.25 $ 81.80 $ 83.44 $ 96.87 $ 93.75 $ 90.89 $ 96.23 $ 98.16 $ 103.57 $ 100.23 $ 97.17 $ 102.89 $ 104.94 $ 106.65 $ 102.15 $ 97.70 $ 103.26 $ 105.32 $ $ $ 3.16 $ 3.10 $ 3.55 $ 3.78 $ 3.72 $ 4.18 $ 4.13 $ 4.07 $ 4.54 $ 5.53 $ 5.47 $ 5.95 $ 5.65 5.59 6.07 2% 2% 2% 2% 2% 2% 2% 2% A foreign exchange rate of US$1.012/C$1.000 was used in the 2011 evaluation. (4) Reserve additions are comprised of all categories of Company Gross reserve changes, exclusive of production. (5) Reserve replacement ratio is the Company Gross reserve additions divided by the Company Gross production in the same period. (6) 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. Resource Disclosure (1) 1. Bitumen (Thermal Oil) Discovered Bitumen Initially-in-place Proved Company Gross Reserves Probable Company Gross Reserves Best Estimate Contingent Resources other than Reserves Bitumen Produced to Date Unrecoverable portion of Discovered Bitumen Initially-in-place (2) 2. Pelican Lake Heavy Crude Oil Pool Discovered Heavy Crude Oil Initially-in-place Proved Company Gross Reserves Probable Company Gross Reserves Best Estimate Contingent Resources other than Reserves Heavy Crude Oil Produced to Date Unrecoverable portion of Discovered Heavy Crude Oil Initially-in-place (2) 3. Horizon Oil Sands Discovered Bitumen Initially-in-place Proved Company Gross Reserves - 2.1 billion barrels of SCO Bitumen volume associated with Proved SCO reserves Probable Company Gross Reserves - 1.3 billion barrels of SCO Bitumen volume associated with Probable SCO reserves Best Estimate Contingent Resources other than Reserves Bitumen Produced to Date Unrecoverable portion of Discovered Bitumen Initially-in-place (2) (1) All volumes are company gross. (2) A portion may be recoverable with the development of new technology. 78.0 1.0 0.7 6.8 0.3 69.2 4,100 261 102 198 166 3,373 billion barrels billion barrels of Bitumen billion barrels of Bitumen billion barrels of Bitumen billion barrels billion barrels million barrels million barrels of heavy crude oil million barrels of heavy crude oil million barrels of heavy crude oil million barrels million barrels 14.4 billion barrels 2.5 billion barrels of Bitumen 1.3 2.6 0.1 7.9 billion barrels of Bitumen billion barrels of Bitumen billion barrels of Bitumen billion barrels 16 Canadian Natural 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” 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”) including the information in the “Outlook” section and the sensitivity analysis 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 expansion, ability to recover insurance proceeds, Primrose, Pelican Lake, the Kirby Thermal Oil Sands Project, the Keystone XL Pipeline US Gulf Coast expansion, and the construction and future operations of the North West Redwater bitumen upgrader and reﬁnery 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 and 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 and natural gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary signiﬁcantly from reserve and production estimates. The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company’s products; volatility of and assumptions regarding crude oil and natural gas prices; ﬂuctuations in currency and interest rates; assumptions on which the Company’s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conﬂict including conﬂict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company’s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company’s and its subsidiaries’ ability to secure adequate transportation for its products; unexpected 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 their ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, natural gas and natural gas liquids (“NGLs”) not currently classiﬁed as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company’s provision for taxes; and other circumstances affecting revenues and expenses. The Company’s operations have been, and in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such 2011 Annual Report 17 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, 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, as determined in accordance with IFRS, in the “Financial Highlights” section of this MD&A. The derivation of cash production costs is included in the “Operating Highlights – Oil Sands Mining and Upgrading” section of this MD&A. The Company also presents certain non-GAAP ﬁnancial ratios and their derivation in the “Liquidity and Capital Resources” section of this MD&A. Management’s Discussion and Analysis 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, 2011. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. Common share data and per common share amounts have been restated to reﬂect the two-for-one common share split in May 2010.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”). Unless otherwise stated, 2010 comparative ﬁgures have been restated in accordance with IFRS issued as at December 31, 2011. Comparative ﬁgures for 2009 have not been restated from Canadian GAAP as previously reported and may not be prepared on a basis consistent with IFRS as adopted. 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 & 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 transportation and blending costs and exclude the effect of risk management activities. Production on an “after royalty” or “net” basis is also presented for information purposes only. The following discussion and analysis refers primarily to the Company’s 2011 ﬁnancial results compared to 2010 and 2009, unless otherwise indicated. In addition, this MD&A details the Company’s capital program and outlook for 2012. Additional information relating to the Company, including its quarterly MD&A for the year and three months ended December 31, 2011, its Annual Information Form for the year ended December 31, 2011, and its audited consolidated ﬁnancial statements for the year ended December 31, 2011 is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. This MD&A is dated March 6, 2012. 18 Canadian Natural Abbreviations AECO Alberta natural gas reference location AIF API ARO bbl bbl/d Bcf Bcf/d BOE Annual Information Form Speciﬁc gravity measured in degrees on the American Petroleum Institute scale Asset retirement obligations barrels barrels per day billion cubic feet billion cubic feet per day barrels of oil equivalent IFRS LIBOR LNG Mbbl Mbbl/d MBOE International Financial Reporting Standards London Interbank Offered Rate Liqueﬁed Natural Gas thousand barrels thousand barrels per day thousand barrels of oil equivalent MBOE/d thousand barrels of oil equivalent per day Mcf Mcf/d MMbbl thousand cubic feet thousand cubic feet per day million barrels BOE/d barrels of oil equivalent per day MMBOE million barrels of oil equivalent Bitumen Solid or semi-solid with viscosity greater than 10,000 centipoise Brent C$ CAGR Dated Brent Canadian dollars Compound annual growth rate CAPEX Capital expenditures CBM CICA CO2 CO2e Coal Bed Methane Canadian Institute of Chartered Accountants Carbon dioxide Carbon dioxide equivalents Canadian GAAP Generally accepted accounting principles in Canada prior to adoption of IFRS on January 1, 2011 CSS EOR E&P FPSO GHG GJ GJ/d Horizon IASB Cyclic steam stimulation Enhanced oil recovery Exploration and Production Floating Production, Storage and Ofﬂoading Vessel Greenhouse gas gigajoules gigajoules per day Horizon Oil Sands MMBtu MMcf MMcf/d MMcfe NGLs NYMEX NYSE PRT SAGD SCO SEC Tcf TSX UK US million British thermal units million cubic feet million cubic feet per day millions of cubic feet equivalent Natural gas liquids New York Mercantile Exchange 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 WCSB WCS Heavy Differential United States dollars Western Canadian Select Western Canadian Sedimentary Basin WCS Heavy Differential from WTI International Acounting Standards Board WTI West Texas Intermediate 2011 Annual Report 19 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. 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 natural gas, light and medium crude oil and NGLs, Pelican Lake heavy crude oil (2), primary heavy crude oil, bitumen (thermal oil) and SCO; Balance among near-, mid- and long-term projects; Balance among acquisitions, exploitation and exploration; and Balance between sources and terms of debt ﬁnancing and maintenance of a strong balance sheet. (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. 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, by dominating core areas 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 all of its growth projects. Additionally, the Company’s risk management hedge program reduces the risk of volatility in commodity prices and supports the Company’s cash ﬂow for its capital expenditures programs. 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. Highlights for the year ended December 31, 2011 include the following: Achieved net earnings of $2.6 billion, adjusted net earnings from operations of $2.5 billion, and cash ﬂow from operations of $6.5 billion; Achieved record yearly crude oil and NGLs production of 295,618 bbl/d in the North America – Exploration and Production segment; Achieved annual crude oil and natural gas production guidance in the Exploration and Production segment; Drilled a record 783 net primary heavy crude oil wells; Successfully and safely recommenced operations at Horizon following the suspension of SCO production due to a ﬁre in the primary upgrading coking plant; Acquired approximately $1 billion of crude oil and natural gas properties in the Company’s core areas in Western Canada; Purchased 3,071,100 common shares for a total cost of $104 million under the Normal Course Issuer Bid; and Increased annual per share dividend payment to $0.36 from $0.30, our 11th consecutive year of dividend increases. 20 Canadian Natural Net Earnings and Cash Flow from Operations Financial Highlights ($ millions, except per common share amounts) Product sales Net earnings Per common share – basic – diluted Adjusted net earnings from operations (2) Per common share – basic – diluted Cash ﬂow from operations (3) Per common share – basic – diluted Dividends declared per common share Total assets Total long-term liabilities Capital expenditures, net of dispositions 2011 2010 2009(1)(4) $ $ $ $ $ $ $ $ $ $ $ $ $ $ 15,507 $ 2,643 $ 2.41 $ 2.40 $ 2,540 $ 2.32 $ 2.30 $ 6,547 $ 5.98 $ 5.94 $ 0.36 $ 47,278 $ 20,346 $ 6,414 $ 14,322 $ 1,673 $ 1.54 $ 1.53 $ 2,444 $ 2.25 $ 2.23 $ 6,333 $ 5.82 $ 5.78 $ 0.30 $ 42,954 $ 18,880 $ 5,514 $ 11,078 1,580 1.46 1.46 2,689 2.48 2.48 6,090 5.62 5.62 0.21 41,024 19,193 2,997 (1) Per common share amounts have been restated to reﬂect a two-for-one common share split in May 2010. (2) Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation “Adjusted Net Earnings from Operations” presented below lists the after-tax effects of certain items of a non-operational nature that are included in the Company’s ﬁnancial results. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies. (3) Cash ﬂow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company evaluates its performance based on cash ﬂow from operations. The Company considers cash ﬂow from operations a key measure as it demonstrates the Company’s ability to generate the cash ﬂow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Cash Flow from Operations” presented below lists certain non-cash items that are included in the Company’s ﬁnancial results. Cash ﬂow from operations may not be comparable to similar measures presented by other companies. (4) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Adjusted Net Earnings from Operations ($ millions) Net earnings as reported Share-based compensation (recovery) expense, net of tax (1)(5) Unrealized risk management (gain) loss, net of tax (2) Unrealized foreign exchange loss (gain), net of tax (3) Gabon, Offshore Africa asset impairment Realized foreign exchange gain on repayment of US dollar debt securities, net of tax (4) Effect of statutory tax rate and other legislative changes on deferred income tax liabilities (5) $ 2011 2010 2009(6) 2,643 $ (102) (95) 215 – (225) 104 1,673 $ 203 (16) (142) 594 – 132 1,580 261 1,437 (570) – – (19) Adjusted net earnings from operations $ 2,540 $ 2,444 $ 2,689 (1) The Company’s employee stock option plan provides for a cash payment option. Accordingly, the fair value of outstanding vested stock options is recorded as a liability on the Company’s balance sheets and periodic changes in the fair value are recognized in net earnings or are capitalized to Oil Sands Mining and Upgrading construction costs. (2) Derivative ﬁnancial instruments are recorded at fair value on the balance sheets, with changes in fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than reﬂected in the ﬁnancial statements due to changes in prices of the underlying items hedged, primarily crude oil and natural gas. (3) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, offset by the impact of cross currency swaps, and are recognized in net earnings. (4) During 2011, the Company repaid US$400 million of US dollar debt securities bearing interest at 6.70%. (5) All substantively enacted or enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company’s 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 during the period the legislation is substantively enacted. During 2011, the UK government enacted an increase to the corporate income tax rate charged on proﬁts from UK North Sea crude oil and natural gas production from 50% to 62%. The Company’s deferred income tax liability was increased by $104 million with respect to this tax rate change. During 2010, changes in Canada to the taxation of stock options surrendered by employees for cash payments resulted in a $132 million charge to deferred income tax expense. During 2009, reductions in the British Columbia corporate income tax rate resulted in one time deferred tax recoveries of $19 million. (6) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. 2011 Annual Report 21 Cash Flow from Operations ($ millions) $ Net earnings Non-cash items: Depletion, depreciation and amortization Share-based compensation (recovery) expense Asset retirement obligation accretion Unrealized risk management (gain) loss Unrealized foreign exchange loss (gain) Realized foreign exchange gain on repayment of US dollar debt securities Deferred income tax expense (recovery) Horizon asset impairment provision Insurance recovery – property damage 2011 2010 2,643 $ 1,673 $ 3,604 (102) 130 (128) 215 (225) 407 396 (393) 4,120 203 123 (24) (161) – 399 – – Cash ﬂow from operations $ 6,547 $ 6,333 $ (1) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. 2009(1) 1,580 2,819 355 90 1,991 (661) – (84) – – 6,090 For 2011, the Company reported net earnings of $2,643 million compared to net earnings of $1,673 million for 2010 (2009 – $1,580 million). Net earnings for 2011 included net unrealized after-tax income of $103 million related to the effects of share-based compensation, risk management activities, ﬂuctuations in foreign exchange rates, the impact of realized foreign exchange gain on repayment of long-term debt and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities (2010 – $771 million after-tax expenses; 2009 – $1,109 million after-tax expenses). Excluding these items, adjusted net earnings from operations for 2011 increased to $2,540 million from $2,444 million for 2010 (2009 – $2,689 million). The increase in adjusted net earnings for 2011 from 2010 was primarily due to: higher North America crude oil and NGL sales volumes; higher crude oil and NGL netbacks; and lower net interest and other ﬁnancing costs; partially offset by: the impact of suspension of production at Horizon, net of business interruption insurance; lower natural gas netbacks; realized risk management losses; and the impact of a stronger Canadian dollar. The impacts of share-based compensation, unrealized risk management activities and changes in foreign exchange rates are expected to continue to contribute to signiﬁcant volatility in consolidated net earnings and are discussed in detail in the relevant sections of this MD&A. Cash ﬂow from operations for 2011 increased to $6,547 million ($5.98 per common share) from $6,333 million ($5.82 per common share) for 2010 (2009 – $6,090 million; $5.62 per common share). The increase in cash ﬂow from operations for 2011 from 2010 was primarily due to: higher North America crude oil and NGL sales volumes; higher crude oil and NGL netbacks; and lower net interest and other ﬁnancing costs; partially offset by: 22 Canadian Natural the impact of suspension of production at Horizon, net of business interruption insurance; lower natural gas netbacks; realized risk management losses; the impact of a stronger Canadian dollar; and higher cash taxes. In the Company’s Exploration and Production activities, the 2011 average sales price per bbl of crude oil and NGLs increased 18% to average $77.46 per bbl from $65.81 per bbl in 2010 (2009 – $57.68 per bbl), and the average natural gas price decreased 9% to average $3.73 per Mcf from $4.08 per Mcf in 2010 (2009 – $4.53 per Mcf). The Company’s average sales price of SCO increased 28% to average $99.74 per bbl from $77.89 per bbl in 2010 (2009 – $70.83). Total production of crude oil and NGLs before royalties decreased 8% to 389,053 bbl/d from 424,985 bbl/d in 2010 (2009 – 355,463 bbl/d). The decrease in crude oil and NGLs production from 2010 was primarily due to the suspension of production at Horizon, partially offset by the impact of a record heavy oil drilling program and the cyclic nature of the Company’s thermal operations. Total natural gas production before royalties increased 1% to average 1,257 MMcf/d from 1,243 MMcf/d in 2010 (2009 – 1,315 MMcf/d). The increase in natural gas production primarily reﬂected new production volumes from natural gas producing properties acquired during 2010 and 2011. Total crude oil and NGLs and natural gas production volumes before royalties decreased 5% to average 598,526 BOE/d from 632,191 BOE/d in 2010 (2009 – 574,730 BOE/d). Total production for 2011 was within the Company’s previously issued guidance. Summary of Quarterly Results The following is a summary of the Company’s quarterly results for the eight most recently completed quarters: ($ millions, except per common share amounts) 2011 Product sales Net earnings Net earnings per common share – basic – diluted 2010 Product sales Net earnings (loss) Net earnings (loss) per common share – basic – diluted Total Dec 31 Sep 30 Jun 30 Mar 31 $ $ $ $ $ $ $ $ 15,507 $ 2,643 $ 4,788 $ 832 $ 3,690 $ 836 $ 3,727 $ 929 $ 2.41 $ 2.40 $ 0.76 $ 0.76 $ 0.76 $ 0.76 $ 0.85 $ 0.84 $ 3,302 46 0.04 0.04 Total Dec 31 Sep 30 Jun 30 Mar 31 (1) 14,322 $ 1,673 $ 3,787 $ (309) $ 3,341 $ 596 $ 3,614 $ 651 $ 1.54 $ 1.53 $ (0.28) $ (0.28) $ 0.54 $ 0.54 $ 0.60 $ 0.60 $ 3,580 735 0.68 0.67 (1) Per common share amounts have been restated to reﬂect a two-for-one common share split in May 2010. 2011 Annual Report 23 Volatility in the quarterly net earnings (loss) over the eight most recently completed quarters was primarily due to: Crude oil pricing – The impact of ﬂuctuating demand, inventory storage levels and geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential (“WCS Differential”) in North America and the impact of the differential between WTI and Dated 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, as well as ﬂuctuations in imports of liqueﬁed natural gas into the US. Crude oil and NGLs sales volumes – Fluctuations in production due to the cyclic nature of the Company’s Primrose thermal projects, the results from the Pelican Lake water and polymer ﬂood projects, and the impact of the suspension and recommencement of production at Horizon. Sales volumes also reﬂected ﬂuctuations due to timing of liftings and maintenance activities in the North Sea and Offshore Africa, and payout of the Baobab ﬁeld in May 2011. Natural gas sales volumes – Fluctuations in production due to the Company’s strategic decision to reduce natural gas drilling activity in North America and the allocation of capital to higher return crude oil projects, as well as natural decline rates and the impact and timing of acquisitions. Production expense – Fluctuations primarily due to the impact of the demand for services, ﬂuctuations in product mix, the impact of seasonal costs that are dependent on weather, production and cost optimizations in North America, and the suspension and recommencement of production at both Horizon and the Olowi ﬁeld in Offshore Gabon. Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes, proved reserves, ﬁnding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company’s proved undeveloped reserves, the impact of the suspension and recommencement of operations at Horizon and the impact of impairments at the Olowi ﬁeld in Offshore Gabon in 2010. Share-based compensation – Fluctuations due to the mark-to-market movements of the Company’s share-based compensation liability. Risk management – Fluctuations due to the recognition of gains and losses from the mark to market and subsequent settlement of the Company’s risk management activities. Foreign exchange rates – Changes in the Canadian dollar relative to the US dollar that 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 or enacted in the various periods. 24 Canadian Natural 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$) Commodity Prices 2011 2010 2009 $ $ $ $ $ $ $ $ $ 95.14 $ 111.29 $ 17.10 $ 18% 103.63 $ 105.38 $ 4.07 $ 3.48 $ 1.0111 $ 0.9833 $ 79.55 $ 79.50 $ 14.26 $ 18% 78.56 $ 81.81 $ 4.42 $ 3.91 $ 0.9709 $ 1.0054 $ 61.93 61.61 9.64 16% 61.51 60.60 4.03 3.91 0.8760 0.9555 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 also highly sensitive to ﬂuctuations in foreign exchange rates. The average value of the Canadian dollar in relation to the US dollar ﬂuctuated signiﬁcantly throughout 2011, with a high of approximately US$1.06 in July 2011 and a low of approximately US$0.95 in October 2011. WTI pricing in 2011 was reﬂective of the political instability in the Middle East and North Africa and continued strong Asian demand. The relative weakness of the US dollar also contributed to higher WTI pricing. For 2011, WTI averaged US$95.14 per bbl, an increase of 20% compared to US$79.55 per bbl for 2010 (2009 – US$61.93 per bbl). Brent averaged US$111.29 per bbl for 2011, an increase of 40% compared to US$79.50 per bbl for 2010 (2009 – US$61.61 per bbl). Crude oil sales contracts for the North Sea and Offshore Africa are typically based on Brent pricing, which is representative of international markets and overall world supply and demand. The higher Dated Brent (“Brent”) pricing relative to WTI in 2011 compared to 2010 was due to the limited pipeline capacity between Petroleum Administration for Defence Districts II (“PADD II”) and the United States Gulf Coast. This logistical constraint is preventing lower WTI priced barrels delivered into PADD II from obtaining United States Gulf Coast Brent-based pricing. The WCS Heavy Differential averaged 18% of WTI for 2011 and 2010 (2009 – 16%). The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During 2011 and 2010, condensate prices traded at a premium to WTI, reﬂecting the tight supply situation. The Company anticipates continued volatility in the crude oil pricing benchmarks due to supply and demand factors, geopolitical events, and the timing and extent of the continuing economic recovery. The WCS Heavy Differential is expected to continue to reﬂect seasonal demand ﬂuctuations, logistics and reﬁnery margins. NYMEX natural gas prices averaged US$4.07 per MMBtu for 2011, a decrease of 8% from US$4.42 per MMBtu for 2010 (2009 – US$4.03 per MMBtu). AECO natural gas pricing averaged $3.48 per GJ for 2011, a decrease of 11% from US$3.91 per GJ for 2010 (2009 – $3.91 per GJ). Natural gas prices continue to be weak in response to the strong North America supply position, primarily from the highly productive shale areas. Operating, Royalty and Capital Costs Strong crude oil commodity prices in recent years have resulted in increased demand for oilﬁeld services worldwide. This has led to inﬂationary operating and capital cost pressures, particularly related to drilling activities and oil sands developments. Continued cost pressures and the ﬁnal outcome of changes to environmental regulations may adversely impact the Company’s future net earnings, cash ﬂow and capital projects. For additional details, refer to the “Greenhouse Gas and Other Air Emissions” section of this MD&A. 2011 Annual Report 25 Analysis of Changes in Revenue, Before Royalties and Risk Management Activities ($ millions) 2009 Volumes Prices Other 2010 Volumes Prices Other 2011 Changes due to Changes due to North America Crude oil and NGLs 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) $ 5,738 $ 2,235 938 $ 1,127 $ (121) (206) 2 $ 7,805 $ – 1,908 7,973 817 921 2 9,713 708 $ 1,448 $ 21 729 (174) 1,274 90 $ 10,051 1,755 – 90 11,806 944 17 961 872 41 913 7,554 2,293 9,847 1,253 72 (71) – (71) (130) (6) (136) 171 (2) 169 104 3 107 737 (127) 1,402 (205) 610 1,197 1,175 – 221 – (1) – (1) 1,043 15 1,058 – – – 1 – 1 – 7 846 38 884 9,694 1,961 11,655 2,649 79 (94) – – 33 (61) (139) (5) (144) (191) 9 (182) 378 25 403 (1,458) – – 292 (1) 291 220 21 241 1,960 (154) 1,806 322 – 19 – 19 3 – 3 1,215 9 1,224 878 68 946 112 – 12,144 1,832 112 13,976 8 9 1,521 88 – (17) (78) Total $ 11,078 $ 1,785 $ 1,418 $ 41 $ 14,322 $ (1,055) $ 2,128 $ 112 $ 15,507 (1) Eliminates internal transportation, electricity charges, and natural gas sales. Revenue increased 8% to $15,507 million for 2011 from $14,322 million for 2010 (2009 – $11,078 million). The increase was primarily due to an increase in realized crude oil and NGL and SCO prices, partially offset by a decrease in realized natural gas prices and Oil Sands Upgrading and Mining sales volumes. For 2011, 14% of the Company’s crude oil and natural gas revenue was generated outside of North America (2010 – 13%; 2009 – 17%). North Sea accounted for 8% of crude oil and natural gas revenue for 2011 (2010 – 7%; 2009 – 9%), and Offshore Africa accounted for 6% of crude oil and natural gas revenue for 2011 (2010 – 6%; 2009 – 8%). 26 Canadian Natural Analysis of Daily Production, Before 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) Product mix Light and medium crude oil and NGLs Pelican Lake heavy crude oil Primary heavy crude oil Bitumen (thermal oil) Synthetic crude oil Natural gas Percentage of gross revenue (1) (excluding midstream revenue) Crude oil and NGLs Natural gas (1) Net of transportation and 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 2011 2010 2009 295,618 40,434 29,992 23,009 389,053 1,231 7 19 1,257 270,562 90,867 33,292 30,264 424,985 1,217 10 16 1,243 234,523 50,250 37,761 32,929 355,463 1,287 10 18 1,315 598,526 632,191 574,730 18% 6% 18% 16% 7% 35% 86% 14% 18% 6% 15% 14% 14% 33% 85% 15% 21% 6% 15% 11% 9% 38% 78% 22% 2011 2010 2009 240,006 38,721 29,919 20,532 329,178 1,186 7 16 1,209 219,736 87,763 33,227 28,288 369,014 1,168 10 15 1,193 201,873 48,833 37,683 29,922 318,311 1,214 10 17 1,241 Total barrels of oil equivalent (BOE/d) 530,576 567,743 525,103 The Company’s business approach is to maintain large project inventories and production diversiﬁcation among each of the commodities it produces; namely natural gas, light and medium crude oil and NGLs, Pelican Lake heavy crude oil, primary heavy crude oil, bitumen (thermal oil), and SCO. Total production averaged 598,526 BOE/d for 2011, a 5% decrease from 632,191 BOE/d in 2010 (2009 – 574,730 BOE/d). Total production of crude oil and NGLs before royalties decreased 8% to 389,053 bbl/d for 2011 from 424,985 bbl/d in 2010 (2009 – 355,463 bbl/d). The decrease in crude oil and NGLs production from 2010 was primarily due to the suspension of production at Horizon, partially offset by the impact of a record heavy crude oil drilling program and the cyclic nature of the Company’s thermal operations. Crude oil and NGLs production for 2011 was within the Company’s previously issued guidance of 385,000 to 393,000 bbl/d. 2011 Annual Report 27 Natural gas production continued to represent the Company’s largest product offering, accounting for 35% of the Company’s total production in 2011 on a BOE basis. Total natural gas production before royalties increased 1% to 1,257 MMcf/d for 2011 from 1,243 MMcf/d for 2010 (2009 – 1,315 MMcf/d). The increase in natural gas production from 2010 primarily reﬂected the new production volumes from Septimus and natural gas producing properties acquired during 2010 and 2011. These increases were partially offset by expected production declines due to the allocation of capital to higher return crude oil projects, which resulted in a strategic reduction of natural gas drilling activity. Natural gas production for 2011 was at the low end of the Company’s issued guidance of 1,256 to 1,263 MMcf/d. North America – Exploration and Production North America crude oil and NGLs production for 2011 increased 9% to average 295,618 bbl/d from 270,562 bbl/d for 2010 (2009 – 234,523 bbl/d). The increase in production from 2010 was primarily due to the impact of a record heavy oil drilling program and the cyclic nature of the Company’s thermal operations. The Company’s heavy oil drilling continues on track and exited 2011 at over 115,000 bbl/d, an increase of approximately 19% compared to the ﬁrst quarter of 2011. North America natural gas production for 2011 increased 1% to average 1,231 MMcf/d from 1,217 MMcf/d in 2010 (2009 –1,287 MMcf/d). The increase in natural gas production from 2010 reﬂected new production volumes from Septimus and natural gas producing properties acquired during 2010 and 2011, offset by the impact of expected production declines due to the allocation of capital to higher return crude oil projects, which resulted in a strategic reduction of natural gas drilling activity. During 2011, the Company completed a pipeline to a deep cut gas facility, which increased Septimus liquids recoveries. North America – Oil Sands Mining and Upgrading As a result of a ﬁre at Horizon’s primary upgrading coking plant on January 6, 2011, all SCO production was suspended. On August 16, 2011, the Company successfully and safely recommenced operations. First pipeline deliveries commenced on August 18, 2011. As a result, production averaged 40,434 bbl/d for 2011, compared to 90,867 bbl/d for 2010. Subsequent to December 31, 2011, the Company temporarily suspended synthetic crude oil production at Horizon on February 5, 2012 to complete unplanned maintenance on the fractionating unit in the primary upgrading facility. The Company has targeted mid to late March to return to full production levels. North Sea North Sea crude oil production for 2011 was 29,992 bbl/d, a decrease of 10% from 33,292 bbl/d for 2010 (2009 – 37,761 bbl/d). The decrease in production volumes from 2010 was due to natural ﬁeld declines and timing of scheduled maintenance shut downs in 2011. In December 2011, the Banff FPSO and subsea infrastructure suffered storm damage. Operations at Banff/Kyle, with combined net production of approximately 3,500 bbl/d, were suspended and appropriate shut down procedures were activated. The FPSO and associated ﬂoating storage unit have subsequently been removed from the ﬁeld, and the extent of the damage, including associated costs and timing of returning to the ﬁeld, is currently being assessed. Offshore Africa Offshore Africa crude oil production for 2011 decreased 24% to 23,009 bbl/d from 30,264 bbl/d for 2010 (2009 – 32,929 bbl/d), due to natural ﬁeld declines and the payout of the Baobab ﬁeld in May 2011. Guidance The Company targets production levels in 2012 to average between 440,000 bbl/d and 480,000 bbl/d of crude oil and NGLs and between 1,247 MMcf/d and 1,297 MMcf/d of natural gas. 28 Canadian Natural Crude Oil Inventory Volumes The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place. Revenue has not been recognized on crude oil volumes that were stored in various tanks, pipelines, or FPSOs as follows: (bbl) North America – Exploration and Production North America – Oil Sands Mining and Upgrading (SCO) North Sea Offshore Africa 2011 2010 2009 557,475 1,021,236 286,633 527,312 761,351 1,172,200 264,995 404,197 1,131,372 1,224,481 713,112 51,103 2,392,656 2,602,743 3,120,068 Operating Highlights – Exploration and Production Crude oil and NGLs ($/bbl) (1) Sales price (2) Royalties Production expense Netback Natural gas ($/Mcf) (1) Sales price (2) Royalties Production expense Netback Barrels of oil equivalent ($/BOE) (1) Sales price (2) Royalties Production expense Netback 2011 2010 2009(3) $ $ $ $ $ $ 77.46 $ 12.30 15.75 49.41 $ 3.73 $ 0.18 1.15 2.40 $ 65.81 $ 10.09 14.16 41.56 $ 4.08 $ 0.20 1.09 2.79 $ 57.16 $ 8.12 12.42 49.90 $ 6.72 11.25 36.62 $ 31.93 $ 57.68 6.73 15.92 35.03 4.53 0.32 1.08 3.13 44.87 4.72 11.98 28.17 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of transportation and blending costs and excluding risk management activities. (3) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. 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) 2011 2010 2009(3) $ $ $ $ $ $ $ $ $ 72.17 $ 108.56 $ 105.53 $ 77.46 $ 3.64 $ 4.07 $ 9.56 $ 3.73 $ 62.28 $ 82.49 $ 78.93 $ 65.81 $ 4.05 $ 3.83 $ 6.63 $ 4.08 $ 54.70 68.84 65.27 57.68 4.51 4.66 6.11 4.53 57.16 $ 49.90 $ 44.87 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of transportation and blending costs and excluding risk management activities. (3) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Realized crude oil and NGLs prices increased 18% to average $77.46 per bbl for 2011 from $65.81 per bbl for 2010 (2009 – $57.68 per bbl). The increase in 2011 was primarily a result of higher WTI and Brent benchmark crude oil prices during the year, partially offset by the impact of a stronger Canadian dollar. The Company’s realized natural gas price decreased 9% to average $3.73 per Mcf for 2011 from $4.08 per Mcf for 2010 (2009 – $4.53 per Mcf). The decrease in 2011 was primarily related to lower NYMEX and AECO benchmark pricing related to the impact of strong supply from US shale projects. 2011 Annual Report 29 North America North America realized crude oil prices increased 16% to average $72.17 per bbl for 2011 from $62.28 per bbl for 2010 (2009 – $54.70 per bbl). The increase in 2011 was primarily a result of higher WTI benchmark pricing, partially offset by the impact of a stronger Canadian dollar. 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 conversion capacity. During 2011, the Company contributed approximately 162,000 bbl/d of heavy crude oil blends to the WCS stream. The Company has entered into a 20 year transportation agreement to ship 120,000 bbl/d of heavy crude oil on the proposed Keystone XL Pipeline from Hardisty, Alberta to the US Gulf Coast. The Company also entered into a 20 year crude oil purchase and sales agreement to sell 100,000 bbl/d of heavy crude oil to a major US reﬁner. In January 2012, the Presidential permit for the Keystone XL pipeline was denied until such time as a new route through Nebraska is determined. Final recommendation from the US State department is anticipated in the ﬁrst quarter of 2013, with an expected pipeline in-service date in 2015. During 2011, the Company announced that it had entered into a partnership agreement with North West Upgrading Inc. to move forward with detailed engineering regarding the construction and operation of a bitumen upgrader and reﬁnery near Redwater, Alberta. In addition, the partnership entered into a 30 year fee-for-service agreement to process bitumen supplied by the Company and the Government of Alberta under the Bitumen Royalty In Kind initiative. Project development is dependent upon completion of detailed engineering and ﬁnal project sanction by the partnership and its partners and approval of the ﬁnal tolls. Board sanction is currently targeted for 2012. North America realized natural gas prices decreased 10% to average $3.64 per Mcf for 2011 from $4.05 per Mcf for 2010 (2009 – $4.51 per Mcf), primarily related to the impact of strong supply from US shale projects. Comparisons of the prices received in North America Exploration and Production by product type were as follows: (Yearly average) Wellhead Price (1)(2) Light and medium crude oil and NGLs (C$/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 transportation and blending costs and excluding risk management activities. North Sea 2011 2010 2009 $ $ $ $ $ 82.01 $ 71.45 $ 70.51 $ 68.55 $ 3.64 $ 68.02 $ 61.69 $ 62.04 $ 59.55 $ 4.05 $ 57.02 55.52 55.66 51.18 4.51 North Sea realized crude oil prices increased 32% to average $108.56 per bbl for 2011 from $82.49 per bbl for 2010 (2009 – $68.84 per bbl). Realized crude oil prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings of each ﬁeld, and prevailing crude oil prices at the time of lifting. The increase in realized crude oil prices in the North Sea from 2010 reﬂected ﬂuctuations in Brent benchmark pricing and the US dollar. Offshore Africa Offshore Africa realized crude oil prices increased 34% to average $105.53 per bbl for 2011 from $78.93 per bbl for 2010 (2009 – $65.27 per bbl). Realized crude oil prices per bbl in any particular year are dependent on the terms of the various sales contracts, the frequency and timing of liftings of each ﬁeld, and prevailing crude oil prices at the time of lifting. The increase in realized crude oil prices in Offshore Africa from 2010 reﬂected ﬂuctuations in Brent benchmark pricing and the US dollar. 30 Canadian Natural Royalties – Exploration and Production Crude oil and NGLs ($/bbl) (1) North America North Sea Offshore Africa Company average Natural gas ($/Mcf) (1) North America Offshore Africa Company average Company average ($/BOE) (1) 2011 2010 2009(2) $ $ $ $ $ $ $ $ 13.51 $ 0.26 $ 12.47 $ 12.30 $ 0.16 $ 1.59 $ 0.18 $ 8.12 $ 11.85 $ 0.16 $ 5.54 $ 10.09 $ 0.20 $ 0.53 $ 0.20 $ 6.72 $ 7.93 0.14 5.79 6.73 0.32 0.53 0.32 4.72 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. 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 (“net proﬁt”). Effective January 1, 2009, changes to the Alberta royalty regime resulted in the implementation of a sliding scale for oil sands royalties ranging from 1% to 9% on a gross revenue basis pre-payout and 25% to 40% on a net revenue basis post-payout, depending on benchmark crude oil pricing. Crude oil and NGLs royalties averaged approximately 19% of product sales in 2011 and were comparable to 2010 (2009 – 14%). North America crude oil and NGLs royalties per bbl are anticipated to average 18% to 21% of gross revenue for 2012. Natural gas royalties averaged approximately 4% of gross revenues for 2011 compared to 5% in 2010 (2009 – 7%), primarily due to lower benchmark natural gas prices. North America natural gas royalties per Mcf are anticipated to average 1% to 3% of gross revenue for 2012. North Sea North Sea 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 (“PSCs”), royalty rates ﬂuctuate based on realized commodity pricing, capital costs, the status of payouts, and the timing of liftings from each ﬁeld. Royalty rates as a percentage of revenue averaged approximately 17% for 2011 compared to 7% for 2010 (2009 – 9%) primarily due to higher crude oil pricing and payout of the Baobab ﬁeld. Offshore Africa royalty rates are anticipated to average 13% to 15% for 2012. 2011 Annual Report 31 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) 2011 2010 2009(2) $ $ $ $ $ $ $ $ $ 13.21 $ 37.06 $ 20.72 $ 15.75 $ 1.12 $ 2.83 $ 2.03 $ 1.15 $ 12.14 $ 29.73 $ 14.64 $ 14.16 $ 1.06 $ 2.91 $ 1.76 $ 1.09 $ 14.63 26.98 12.83 15.92 1.07 2.16 1.23 1.08 12.42 $ 11.25 $ 11.98 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. North America North America crude oil and NGLs production expense for 2011 increased 9% to $13.21 per bbl from $12.14 per bbl for 2010 (2009 – $14.63 per bbl). The increase in production expense per bbl from 2010 was primarily a result of higher overall service costs relating to heavy crude oil production and the timing of thermal steam cycles. North America crude oil and NGLs production expense is anticipated to average $11.00 to $13.00 per bbl for 2012. North America natural gas production expense for 2011 increased 6% to $1.12 per Mcf, from $1.06 per Mcf for 2010 (2009 – $1.07 per Mcf). Natural gas production expense increased from 2010 due to acquisitions of natural gas producing properties that have higher production costs per Mcf than the Company’s existing properties. North America natural gas production expense is anticipated to average $1.10 to $1.20 per Mcf for 2012. North Sea North Sea crude oil production expense for 2011 increased 25% to $37.06 per bbl from $29.73 per bbl for 2010 (2009 - $26.98 per bbl). Production expense increased on a per barrel basis due to lower production volumes on relatively ﬁxed costs and increased fuel prices. North Sea crude oil production expense is anticipated to average $43.00 to $48.00 per bbl for 2012. Offshore Africa Offshore Africa crude oil production expense for 2011 increased 42% to $20.72 per bbl from $14.64 per bbl for 2010 (2009 - $12.83 per bbl). Production expense increased on a per barrel basis due to lower production volumes on relatively ﬁxed costs, and the timing of liftings from each ﬁeld. Offshore Africa crude oil production expense is anticipated to average $27.00 to $29.00 per bbl for 2012. 32 Canadian Natural Depletion, Depreciation and Amortization – Exploration and Production ($ millions, except per BOE amounts) (1) 2011 2010 2009(2) North America North Sea Offshore Africa Expense $/BOE $ $ $ 2,840 $ 249 242 3,331 $ 16.35 $ 2,484 $ 297 935 3,716 $ 18.76 $ 2,060 261 335 2,656 13.82 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Depletion, Depreciation and Amortization expense for 2011 decreased to $3,331 million from $3,716 million for 2010 (2009 – $2,656 million), due to lower sales volumes in the North Sea and Offshore Africa, and the impact of an impairment related to Gabon, Offshore Africa at December 31, 2010, partially offset by higher sales volumes in North America. Asset Retirement Obligation Accretion – Exploration and Production ($ millions, except per BOE amounts) (1) 2011 2010 2009(2) North America North Sea Offshore Africa Expense $/BOE $ $ $ 70 $ 33 7 110 $ 0.54 $ 52 $ 36 7 95 $ 0.47 $ 41 24 4 69 0.36 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Operating Highlights – Oil Sands Mining and Upgrading Operations Update On January 6, 2011, the Company suspended SCO production at its Oil Sands Mining and Upgrading operations due to a ﬁre in the primary upgrading coking plant. The Company successfully and safely recommenced operations on August 16, 2011. First pipeline deliveries commenced on August 18, 2011. As a result, production averaged 40,434 bbl/d for 2011, compared to 90,867 bbl/d for 2010 (2009 – 50,250 bbl/d). Subsequent to December 31, 2011, the Company temporarily suspended synthetic crude oil production at Horizon on February 5, 2012 to complete unplanned maintenance on the fractionating unit in the primary upgrading facility. The Company has targeted mid to late March to return to full production levels. Product Prices and Royalties – Oil Sands Mining and Upgrading ($/bbl) (1) SCO sales price (2) Bitumen value for royalty purposes (3) Bitumen royalties (4) 2011 2010 2009(5) $ $ $ 99.74 $ 61.86 $ 3.99 $ 77.89 $ 56.14 $ 2.72 $ 70.83 56.57 2.15 (1) Amounts expressed on a per unit basis in 2011 are based on sales volumes excluding the period during suspension of production. (2) Net of transportation and excluding risk management activities. (3) Calculated as the simple average of the monthly bitumen valuation methodology price. (4) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes. (5) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Realized SCO sales prices increased 28% to average $99.74 per bbl for 2011 from $77.89 per bbl for 2010 (2009 – $70.83 per bbl). The increase in SCO prices from 2010 was primarily due to the increase in the WTI benchmark price, partially offset by the impact of a stronger Canadian dollar. 2011 Annual Report 33 Production Cost – Oil Sands Mining and Upgrading The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 20 to the Company’s consolidated ﬁnancial statements. ($ millions) Cash costs Less: costs incurred during the period of suspension of production Adjusted cash costs Adjusted cash costs, excluding natural gas costs Adjusted natural gas costs Adjusted cash production costs 2011 2010 2009(1) $ $ $ $ 1,127 $ (581) 1,208 $ – 546 $ 1,208 $ 502 $ 44 546 $ 1,082 $ 126 1,208 $ 683 – 683 599 84 683 (1) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. ($/bbl) (1) Adjusted cash costs, excluding natural gas costs Adjusted natural gas costs Adjusted cash production costs Sales (bbl/d) 2011 2010 2009(2) $ $ 33.68 $ 2.96 36.64 $ 32.58 $ 3.78 36.36 $ 34.97 4.92 39.89 40,847 91,010 46,896 (1) Amounts expressed on a per unit basis in 2011 are based on sales volumes excluding the period during suspension of production. (2) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Adjusted cash production costs averaged $36.64 per bbl for 2011, an increase of 1% compared to $36.36 per bbl for 2010 (2009 – $39.89 per bbl). Depletion, Depreciation and Amortization – Oil Sands Mining and Upgrading ($ millions) Depletion, depreciation and amortization Less: depreciation incurred during the period of suspension of production Adjusted depletion, depreciation and amortization $/bbl (1) 2011 2010 2009(2) 266 $ (64) 202 $ 396 $ – 396 $ 187 – 187 13.54 $ 11.91 $ 10.95 $ $ $ (1) Amounts expressed on a per unit basis in 2011 are based on sales volumes excluding the period during suspension of production. (2) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Depletion, depreciation and amortization expense for 2011 decreased from 2010 primarily due to the impact of the Horizon suspension. Asset Retirement Obligation Accretion – Oil Sands Mining and Upgrading Expense ($ millions) $/bbl (1) 2011 2010 2009(2) $ $ 20 $ 1.33 $ 28 $ 0.88 $ 21 1.22 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Midstream ($ millions) Revenue Production expense Midstream cash ﬂow Depreciation Segment earnings before taxes 2011 2010 2009(1) $ $ 88 $ 26 62 7 79 $ 22 57 8 55 $ 49 $ 72 19 53 9 44 (1) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. 34 Canadian Natural The Company’s midstream assets consist of three crude oil pipeline systems and a 50% working interest in an 84-megawatt cogeneration plant at Primrose. Approximately 80% 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 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. Administration Expense ($ millions, except per BOE amounts) (1) 2011 2010 2009(2) Expense $/BOE $ $ 235 $ 1.07 $ 211 $ 0.92 $ 181 0.87 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Administration expense for 2011 increased from 2010 primarily due to higher stafﬁng and general corporate costs. Share-Based Compensation ($ millions) (Recovery) expense 2011 2010 2009(1) $ (102) $ 203 $ 355 (1) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. 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 Company recorded a $102 million share-based compensation recovery during 2011 primarily as a result of remeasurement of the fair value of outstanding stock options at the end of the period, related to a decrease in the Company’s share price, offset by normal course graded vesting of stock options granted in prior periods and the impact of vested stock options exercised or surrendered during the period. For the year ended December 31, 2011, no net amounts were capitalized in respect of share-based compensation to Oil Sands Mining and Upgrading (2010 – capitalized $32 million; 2009 – capitalized $2 million). The share-based compensation liability at December 31, 2011 reﬂected the Company’s liability for awards granted to employees at fair value estimated using the Black-Scholes valuation model. In periods when substantial stock 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. During 2011, the Company paid $14 million for stock options surrendered for cash payments (2010 – $45 million; 2009 – $94 million). Interest and Other Financing Costs ($ millions, except per BOE amounts and interest rates) (1) 2011 2010 2009(2) Expense, gross Less: capitalized interest Expense, net $/BOE Average effective interest rate $ $ $ 432 $ 59 373 $ 1.71 $ 4.7% 476 $ 28 448 $ 1.94 $ 4.9% 516 106 410 1.96 4.3% (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Gross interest and other ﬁnancing costs for 2011 decreased from 2010 due to the impact of a stronger Canadian dollar on US dollar denominated debt, partially offset by higher average debt levels and variable interest rates. Capitalized interest for 2011 increased from 2010 due to additional amounts relating to Horizon and the Kirby Project. The Company’s average effective interest rate for 2011 decreased from 2010 primarily due to settlement of the US$400 million of 6.70% US dollar denominated debt securities and subsequent issuance of US$500 million of 1.45% unsecured notes due November 2014 and US$500 million of 3.45% unsecured notes due November 2021. 2011 Annual Report 35 Risk Management Activities The Company utilizes various derivative ﬁnancial instruments to manage its commodity price, foreign currency and interest rate exposures. These derivative ﬁnancial instruments are not intended for trading or speculative purposes. ($ millions) 2011 2010 2009(1) Crude oil and NGLs ﬁnancial instruments Natural gas ﬁnancial instruments Foreign currency contracts and interest rate swaps Realized loss (gain) Crude oil and NGLs ﬁnancial instruments Natural gas ﬁnancial instruments Foreign currency contracts and interest rate swaps Unrealized (gain) loss Net (gain) loss $ $ $ $ $ 117 $ – (16) 101 $ (134) $ – 6 (128) $ (27) $ 84 $ (234) 40 (110) $ (108) $ 72 12 (24) $ (134) $ (1,330) (33) 110 (1,253) 2,039 (58) 10 1,991 738 (1) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Complete details related to outstanding derivative ﬁnancial instruments at December 31, 2011 are disclosed in note 17 to the Company’s consolidated ﬁnancial statements. The cash settlement amount of commodity derivative ﬁnancial instruments may vary materially depending upon the underlying crude oil and natural gas prices at the time of ﬁnal settlement, as compared to their fair value at December 31, 2011. Due to changes in crude oil forward pricing and the reversal of prior period unrealized gains and losses related to crude oil and foreign currency contracts, the Company recorded a net unrealized gain of $128 million ($95 million after-tax) on its risk management activities for 2011 (2010 – $24 million unrealized gain, $16 million after-tax; 2009 – $1,991 million unrealized loss, $1,437 million after-tax). Foreign Exchange ($ millions) Net realized (gain) loss Net unrealized loss (gain) (1) Net loss (gain) 2011 2010 2009(2) $ $ (214) $ 215 1 $ (2) $ (161) (163) $ 30 (661) (631) (1) Amounts are reported net of the hedging effect of cross currency swaps. (2) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. The Company’s operating results are affected by the ﬂuctuations in the exchange rates between the Canadian dollar, US dollar, and UK pound sterling. The majority 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 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 unrealized foreign exchange loss in 2011 was primarily due to the reversal of the unrealized foreign exchange gain on the settlement of the US$400 million 6.70% US dollar denominated debt securities, together with the weakening of the Canadian dollar at December 31, 2011 with respect to US dollar denominated debt. Included in the net unrealized loss for 2011 was an unrealized gain of $42 million (2010 – $101 million unrealized loss, 2009 – $338 million unrealized loss) related to the impact of cross currency swaps. The net realized foreign exchange gain for 2011 was primarily due to the settlement of the US$400 million 6.70% US dollar denominated debt securities, partially offset by foreign exchange rate ﬂuctuations on settlement of working capital items denominated in US dollars or UK pounds sterling. The Canadian dollar ended the year at US$0.9833 compared to US$1.0054 at December 31, 2010 (December 31, 2009 – US$0.9555). 36 Canadian Natural Taxes ($ millions, except income tax rates) North America (1) North Sea Offshore Africa PRT expense – North Sea Other taxes Current income tax Deferred income tax expense (recovery) Deferred PRT expense – North Sea Deferred income tax Income tax rate and other legislative changes (2) 2011 2010 2009(4) $ 315 $ 245 140 135 25 860 412 (5) 407 1,267 (104) 431 $ 203 64 68 23 789 408 (9) 399 1,188 (132) $ 1,163 $ 1,056 $ 28 278 82 70 21 479 (99) 15 (84) 395 19 414 Effective income tax rate on adjusted net earnings from operations (3) 27.7% 28.9% 24.3% (1) Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments. (2) Deferred income tax expense in 2011 included a charge of $104 million related to enacted changes in the UK to increase the corporate income tax rate charged on proﬁts from UK North Sea crude oil and natural gas production from 50% to 62%. Deferred income tax expense in 2010 included a charge of $132 million related to changes in Canada to the taxation of stock options surrendered by employees for cash payments. Deferred income tax expense in 2009 included the effects of one time recoveries of $19 million due to British Columbia corporate income tax rate reductions. (3) Excludes the impact of current and deferred PRT expense and other current income tax expense. (4) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Taxable income from the Exploration and Production business in Canada is primarily generated through partnerships, with the related income taxes payable in periods subsequent to the current reporting period. North America current and deferred income taxes have been provided on the basis of this corporate structure. In addition, current income taxes 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 2011, the Canadian Federal government enacted legislation to implement several taxation changes. These changes include a requirement that, beginning in 2012, partnership income must be included in the taxable income of each corporate partner based on the tax year of the partner, rather than the ﬁscal year of the partnership. The legislation includes a ﬁve-year transition provision and has no impact on net earnings. During 2011, the UK government enacted an increase to the supplementary income tax rate charged on proﬁts from UK North Sea crude oil and natural gas production, increasing the combined corporate and supplementary income tax rate from 50% to 62%. As a result of the income tax rate change, the Company’s deferred income tax liability was increased by $104 million. In its 2011 budget, the UK government announced its intention to restrict tax relief on decomisssioning expenditures to 50% for non-PRT ﬁelds and 75% for PRT ﬁelds. The proposed legislation to effect the restriction was released in 2011 for enactment in 2012. This proposed tax change would result in a deferred tax charge currently estimated at $56 million. During 2010, deferred income tax expense included a charge of $132 million related to enacted changes in Canada to the taxation of stock options surrendered by employees for cash. 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. For 2012, based on budgeted prices and the current availability of tax pools, the Company expects to incur current income tax expense of $700 million to $800 million in Canada and $200 million to $300 million in the North Sea and Offshore Africa. 2011 Annual Report 37 Net Capital Expenditures (1) ($ millions) Exploration and Evaluation Net expenditures Property, Plant and Equipment Net property acquisitions Land acquisition and retention Seismic evaluations Well drilling, completion and equipping Production and related facilities Capitalized interest Net expenditures Total Exploration and Production Oil Sands Mining and Upgrading: Horizon Phase 1 construction and commissioning costs and other Horizon Phases 2/3 construction costs Sustaining capital Turnaround costs Capitalized interest, share-based compensation and other Total Oil Sands Mining and Upgrading (2) Horizon coker rebuild and collateral damage costs (3) Midstream Abandonments (4) Head ofﬁce Total net capital expenditures By segment North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream Abandonments (4) Head ofﬁce Total 2011 2010 2009(5) $ 312 $ 572 $ – 1,012 44 47 1,878 1,690 13 4,684 4,996 – 481 170 79 48 778 404 5 213 18 1,482 41 51 1,499 1,122 – 4,195 4,767 – 319 128 – 96 543 – 7 179 18 6 77 73 1,244 977 – 2,377 2,377 271 104 80 – 98 553 – 6 48 13 6,414 $ 5,514 $ 2,997 $ $ 4,736 $ 227 33 1,182 5 213 18 4,369 $ 149 249 543 7 179 18 $ 6,414 $ 5,514 $ 1,663 168 546 553 6 48 13 2,997 (1) Net capital expenditures exclude adjustments related to differences between carrying value and tax value, and other fair value adjustments. (2) Net expenditures for the Oil Sands Mining and Upgrading assets also include the impact of intersegment eliminations. (3) The Company recognized $393 million of property damage insurance recoveries (see note 10 to the Company’s consolidated ﬁnancial statements), offsetting the costs incurred related to the Coker rebuild and collateral damage costs. (4) Abandonments represent expenditures to settle asset retirement obligations and have been reﬂected as capital expenditures in this table. (5) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. The Company’s operating 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 maintaining 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. Net capital expenditures for 2011 were $6,414 million compared to $5,514 million for 2010 (2009 – $2,997 million). The increase in capital expenditures from 2010 was primarily due to an increase in well drilling and completion expenditures related to the Company’s record heavy crude oil drilling program, an increase in the Company’s abandonment program, and costs associated with the coker rebuild and collateral damage resulting from the coker ﬁre, partially offset by lower property acquisitions. 38 Canadian Natural 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. North America 2011 83 1,103 48 657 1,891 96% 2010 2009 92 934 33 491 1,550 97% 109 644 46 329 1,128 94% North America, excluding Oil Sands Mining and Upgrading, accounted for approximately 77% of the total capital expenditures for 2011 compared to approximately 83% for 2010 (2009 – 58%). During 2011, the Company targeted 86 net natural gas wells, including 15 wells in Northeast British Columbia, 57 wells in Northwest Alberta and 14 wells in the Northern Plains. The Company also targeted 1,147 net crude oil wells. The majority of these wells were concentrated in the Company’s Northern Plains region where 783 primary heavy crude oil wells, 66 Pelican Lake heavy crude oil wells, 19 light crude oil wells and 156 bitumen (thermal oil) wells were drilled. Another 123 wells targeting light crude oil were drilled outside the Northern Plains region. The Company continued to access its large crude oil drilling inventory to maximize value in both the short and long term. Due to the Company’s focus on drilling crude oil wells in recent years and low natural gas prices, natural gas drilling activities have been reduced. Deferred natural gas well locations have been retained in the Company’s prospect inventory. As part of the phased expansion of its in situ Oil Sands Assets, the Company is continuing to develop its Primrose thermal projects. During 2011, the Company drilled 141 bitumen (thermal oil) wells, and 111 stratigraphic test wells and observation wells. Overall Primrose thermal production for 2011 averaged approximately 98,000 bbl/d, compared to approximately 90,000 bbl/d in 2010 (2009 – 64,000 bbl/d) The next planned phase of the Company’s in situ Oil Sands Assets expansion is the Kirby South Phase 1 Project. During 2010, the Company received ﬁnal regulatory approval for Phase 1 of the Project, and the Company’s Board of Directors sanctioned Kirby South Phase 1. Construction has commenced, with ﬁrst steam targeted in 2013. Drilling has been completed on the second of seven pads and has commenced on the third pad. The Company continued to develop the tertiary recovery conversion projects at Pelican Lake throughout 2011. Pelican Lake production averaged approximately 38,000 bbl/d in 2011 (2010 – 38,000 bbl/d; 2009 – 37,000 bbl/d). For 2012, planned crude oil drilling activity in North America is comprised of 1,114 net crude oil and bitumen wells and 45 net natural gas wells, excluding stratigraphic and service wells. As a result of lower 2012 natural gas prices than originally anticipated, the Company has reduced its planned natural gas capital expenditures by approximately $170 million, reducing North America natural gas production by approximately 20 MMcf/d. Oil Sands Mining and Upgrading Phase 2/3 spending during 2011 continued to be focused on ﬁnal construction and pre-commissioning of the third ore preparation plant and associated hydro-transport, as well as additional product tankage, the butane treatment unit and the sulphur recovery unit. Final commissioning of the ore preparation plant and associated hydro-transport was completed in January 2012. Due to property damage resulting from a ﬁre in the primary upgrading coking plant at January 6, 2011, the Company recognized a Horizon asset impairment provision of $396 million, net of accumulated depletion and amortization. Insurance proceeds of $393 million were also recognized, offsetting such property damage. Production resumed in August 2011. The Company has ﬁnalized its property damage insurance claim with certain of its insurers. The Company believes that the remaining portion of the property damage insurance claim will be settled without any signiﬁcant adjustments from the $393 million currently recognized. The Company also maintains business interruption insurance to reduce operating losses related to its ongoing Horizon operations. The Company ﬁnalized its business interruption insurance claim related to the ﬁre for proceeds of $333 million. Subsequent to December 31, 2011, the Company temporarily suspended synthetic crude oil production at Horizon on February 5, 2012 to complete unplanned maintenance on the fractionating unit in the primary upgrading facility. The Company has targeted mid to late March to return to full production levels. 2011 Annual Report 39 North Sea During 2011, the Company incurred drilling and capital expenditures on the three Ninian platforms, facilities upgrade projects at Lyell and ongoing capital turnaround projects at Tiffany and Murchison. In December 2011, the Banff FPSO and subsea infrastructure suffered storm damage. Operations at Banff/Kyle, with combined net production of approximately 3,500 bbl/d, were suspended and appropriate shut down procedures were activated. The FPSO and associated ﬂoating storage unit were subsequently removed from the ﬁeld. All personnel on board the FPSO were safe and accounted for. The extent of the damage, including associated costs and timing of returning to the ﬁeld, is currently being assessed. In March 2011, the UK government enacted an increase to the corporate income tax rate charged on proﬁts from UK North Sea crude oil and natural gas production from 50% to 62%. This resulted in an increase to the overall corporate tax rate applicable to net operating income from oil and gas activities to 62% for non-PRT paying ﬁelds and 81% for PRT paying ﬁelds, after allowing for deductions for capital and abandonment expenditures. As a result of the increase in the corporate income tax rate, the Company’s development activities in 2011 in the North Sea were reduced. The Company is continuing to high grade all North Sea prospects for potential development opportunities in 2012 and future years. Offshore Africa During 2011, the Company sanctioned an 8 well drilling program at the Espoir ﬁeld in Côte d’Ivoire. Preparations are ongoing and a rig has been contracted to commence drilling operations targeted for late 2012. 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 (loss) 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 (7) $ $ $ 2011 2010 2009(8) (894) $ 8,571 $ (1,200) $ 8,485 $ (514) 9,658 3,507 $ 3,147 $ 19,365 26 17,212 9 $ 22,898 $ 20,368 $ 27% 17% 12% 10% 29% 15% 8% 7% 2,834 16,696 (104) 19,426 33% 19% 8% 6% (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 (2011 – $359 million; 2010 – $397 million; 2009 – $nil). (3) Long-term debt is stated at its carrying value, net of fair value adjustments, original issue discounts 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 for the twelve month trailing period; as a percentage of average common shareholders’ equity for the year. (7) Calculated as net earnings plus after-tax interest and other ﬁnancing costs for the twelve month trailing period; as a percentage of average capital employed for the year. (8) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. At December 31, 2011, 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 is also dependent upon maintaining an investment grade debt rating and the condition of capital and credit markets. The Company continues to believe that its internally generated cash ﬂow from operations supported by the implementation of its on-going hedge policy, the ﬂexibility of its capital expenditure programs supported by its multi-year ﬁnancial plans, its existing bank credit facilities, and its ability to raise new debt on commercially acceptable terms, will provide sufﬁcient liquidity to sustain its operations in the short, medium and long term and support its growth strategy. 40 Canadian Natural During 2011, the Company ﬁled base shelf prospectuses that allow for the issue 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 2013. Subsequently, the Company issued US$1,000 million of unsecured notes under the US base shelf prospectus, comprised of US$500 million of 1.45% unsecured notes due November 2014 and US$500 million of 3.45% unsecured notes due November 2021. Concurrently, the Company entered into cross currency swaps to ﬁx the Canadian dollar interest and principal repayment amounts on the US$500 million of 3.45% unsecured notes due November 2021 at 3.96% and C$511 million. Proceeds from the securities issued were used to repay bank indebtedness under the Company’s bank credit facilities. After issuing these securities, the Company has US$2,000 million remaining on its outstanding US$3,000 million base shelf prospectus. If issued, these securities will bear interest as determined at the date of issuance. During 2011, the Company repaid US$400 million of US dollar denominated debt securities bearing interest at 6.70%, and the $2,230 million revolving syndicated credit facility was increased to $3,000 million and extended to June 2015. The $1,500 million revolving syndicated credit facility is currently maturing in June 2012. Each of the $3,000 million and $1,500 million facilities is extendible annually for one year periods at the mutual agreement of the Company and the lenders. During 2010, the Company repaid $400 million of the medium-term notes bearing interest at 5.50%. At December 31, 2011, the Company had $3,795 million of available credit under its bank credit facilities. Long-term debt was $8,571 million at December 31, 2011, resulting in a debt to book capitalization ratio of 27% (December 31, 2010 – 29%; December 31, 2009 – 33%). This ratio is below the 35% to 45% internal range utilized by management. This range may be exceeded in periods when a combination of capital projects, acquisitions, 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. The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a ﬂexible capital structure. The Company has hedged a portion of its crude oil production for 2012 at prices that protect investment returns to ensure ongoing balance sheet strength and the completion of its capital expenditure programs. Further details related to the Company’s long-term debt at December 31, 2011 are discussed in note 8 to the Company’s consolidated ﬁnancial statements. The Company’s commodity hedging policy reduces the risk of volatility in commodity prices and supports the Company’s cash ﬂow for its capital expenditures 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. As at March 6, 2012, approximately 40% of currently forecasted 2012 crude oil volumes were hedged using collars and puts. Further details related to the Company’s commodity related derivative ﬁnancial instruments outstanding at December 31, 2011 are discussed in note 17 to the Company’s consolidated ﬁnancial statements. Share Capital As at December 31, 2011, there were 1,096,460,000 common shares outstanding and 73,486,000 stock options outstanding. As at March 6, 2012, the Company had 1,100,567,000 common shares outstanding and 67,574,000 stock options outstanding. On March 6, 2012, the Company’s Board of Directors approved an increase in the annual dividend to be paid by the Company to $0.42 per common share for 2012. The increase represents an approximately 17% increase from 2011, recognizing the stability of the Company’s cash ﬂow and providing a return to shareholders. The dividend policy undergoes a periodic review by the Board of Directors and is subject to change. In March 2011, an increase in the annual dividend paid by the Company to $0.36 per common share was approved for 2011. The increase represented a 20% increase from 2010. On March 31, 2011, the Company announced a Normal Course Issuer Bid to purchase, through the facilities of the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange (“NYSE”), during the 12 month period commencing April 6, 2011 and ending April 5, 2012, up to 27,406,131 common shares or 2.5% of the common shares of the Company outstanding at March 25, 2011. As at December 31, 2011, 3,071,100 common shares had been purchased for cancellation at an average price of $33.68 per common share, for a total cost of $104 million. In 2010, the Company announced a Normal Course Issuer Bid to purchase, through the facilities of the TSX and NYSE during the 12 month period commencing April 6, 2010 and ending April 5, 2011, up to 27,163,940 common shares or 2.5% of the common shares of the Company outstanding at March 17, 2010. A total of 2,000,000 common shares were purchased for cancellation under this Normal Course Issuer Bid at an average price of $33.77 per common share, for a total cost of $68 million. 2011 Annual Report 41 Commitments and Off Balance Sheet Arrangements In the normal course of business, the Company has entered into various commitments that will have an impact on the Company’s future operations. As at December 31, 2011, no entities were consolidated under the Standing Interpretations Committee (“SIC”) 12, “Consolidation – Special Purpose Entities”. The following table summarizes the Company’s commitments as at December 31, 2011: ($ millions) 2012 2013 2014 2015 2016 Thereafter Product transportation and pipeline Offshore equipment operating leases Long-term debt (1) Interest and other ﬁnancing costs (2) Ofﬁce leases Other $ $ $ $ $ $ 247 $ 118 $ 356 $ 442 $ 30 $ 288 $ 210 $ 101 $ 806 $ 403 $ 33 $ 158 $ 199 $ 100 $ 865 $ 384 $ 34 $ 88 $ 185 $ 82 $ 1,196 $ 339 $ 32 $ 24 $ 123 $ 53 $ 255 $ 321 $ 33 $ 2 $ 888 119 5,135 4,116 305 8 (1) Long-term debt represents principal repayments only and does not reﬂect fair value adjustments, original issue discounts or transaction costs. (2) Interest and other ﬁnancing cost 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, 2011. 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, 2011 and 2010, 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. In previous years, the Company was granted an exemption from certain provisions of NI 51-101 allowing the Company to substitute SEC requirements under Regulations S-K and S-X for certain disclosures required under NI 51-101. Such exemption expired on December 31, 2010. 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 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’s gross proved and proved plus probable reserves as at December 31, 2011, prepared in accordance with NI 51-101 reserves disclosures: Pelican Lake Primary Light and Medium Heavy Heavy Crude Oil Crude Oil Crude Oil Bitumen (Thermal Synthetic Crude Oil) Oil Natural Gas Natural Gas Barrels of Oil Liquids Equivalent Proved Reserves (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (Bcf) (MMbbl) (MMBOE) December 31, 2010 482 160 239 919 1,932 4,262 63 4,505 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production – 7 8 – 2 – 28 (44) (32) 1 47 8 1 – – – (4) (38) – 8 – – – – – 43 (14) – 20 2 – – – – 69 (36) – – – – – – 4 198 (15) 7 220 55 – 432 – (174) 104 (459) – 18 3 – 7 – (1) 12 (7) 2 137 30 1 81 – 3 291 (219) December 31, 2011 451 175 276 974 2,119 4,447 95 4,831 42 Canadian Natural Proved plus Probable Reserves Light and Medium Crude Oil Primary Heavy Crude Oil Pelican Lake Heavy Crude Oil Bitumen (Thermal Synthetic Crude Oil) Oil Natural Gas Natural Gas Barrels of Oil Liquids Equivalent (MMbbl) (MMbbl) (MMbbl) (MMbbl) (MMbbl) (Bcf) (MMbbl) (MMBOE) December 31, 2010 703 217 348 1,702 2,888 5,767 83 6,902 Discoveries Extensions Inﬁll Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production – 10 11 1 2 – 2 (28) (32) 1 69 12 4 – – – (16) (38) – 14 – – – – – 40 (14) – 37 3 – – – – 20 (36) – 388 – – – – 4 90 (15) 8 342 109 – 536 (1) (208) 7 (459) – 29 7 – 9 – (2) 15 (7) 2 605 51 5 100 – (30) 122 (219) December 31, 2011 669 249 388 1,726 3,355 6,101 134 7,538 At December 31, 2011, the Company’s gross proved crude oil and NGLs reserves totaled 4,090 MMbbl, and gross proved plus probable crude oil and NGLs reserves totaled 6,521 MMbbl. Proved reserve additions and revisions replaced 308% of 2011 production. Additions to proved reserves resulting from exploration and development activities, acquisitions and future offset additions amounted to 437 MMbbl, and additions to proved plus probable reserves amounted to 722 MMbbl. Net positive revisions amounted to 305 MMbbl for proved reserves and 125 MMbbl for proved plus probable reserves. The net gains were primarily due to technical revisions to prior estimates based on improved or better than expected reservoir performance, partially offset by negative revisions in the North Sea due to cancellation of certain of the Company’s activities that became uneconomic as a result of changes in the UK ﬁscal structure. At December 31, 2011, the Company’s gross proved natural gas reserves totaled 4,447 Bcf, and gross proved plus probable natural gas reserves totaled 6,101 Bcf. Proved reserve additions and revisions replaced 140% of 2011 production. Additions to proved reserves resulting from exploration and development activities, acquisitions and future offset additions amounted to 644 Bcf, and additions to proved plus probable reserves amounted to 793 Bcf. Net negative revisions amounted to 70 Bcf for proved reserves and 201 Bcf for proved plus probable reserves, primarily due to lower estimated future benchmark pricing. 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 net present value of 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 natural gas and the mining and upgrading of bitumen into SCO. These inherent risks include, but are not limited to, the following items: 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; Prevailing prices and volatility 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; Success of exploration and development activities; 2011 Annual Report 43 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; Foreign exchange risk due to ﬂuctuating exchange rates on the Company’s US dollar denominated debt and as the majority of sales are based in US dollars; Environmental impact risk associated with exploration and development activities, including GHG; Mechanical or equipment failure of facilities and infrastructure; Risk of catastrophic loss due to ﬁre, explosion or acts of nature; Geopolitical risks associated with changing governmental policies, social instability and other political, economic or diplomatic developments in the Company’s operations; Future legislative and regulatory developments related to environmental regulation; Potential actions of governments, regulatory authorities and other stakeholders that may impose operating costs or restrictions in the jurisdictions where the Company has operations; Changing royalty regimes; Business interruptions because of unexpected events such as ﬁres, blowouts, freeze-ups, equipment failures and other similar events affecting the Company or other parties whose operations or assets directly or indirectly affect the Company and that may or may not be ﬁnancially recoverable; 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 to an acceptable level. 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. Substantially all of the Company’s accounts receivables are due within normal trade terms. Derivative ﬁnancial instruments are utilized to help ensure targets are met and to manage commodity prices, foreign currency rates and interest rate exposure. 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 substantially all investment grade ﬁnancial institutions and other entities. 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 detail regarding the Company’s risks and uncertainties, refer to the Company’s AIF. 44 Canadian Natural 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. 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; Implementation of a tailings management plan; and CO2 reduction programs including the injection of CO2 into tailings and for use in enhanced oil recovery. For 2011, the Company’s capital expenditures included $213 million for abandonment expenditures (2010 – $179 million; 2009 – $48 million). The Company’s estimated discounted ARO at December 31, 2011 was as follows: Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream December 31 December 31 2010 2011 $ 1,862 $ 723 192 798 2 $ 3,577 $ 1,390 670 137 426 1 2,624 2011 Annual Report 45 The discounted ARO was based on estimates of future costs to abandon and restore wells, production facilities, mine site, 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 (“CAPP”), is working with 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, targeted research and development while not impacting competitiveness. In Canada, the Federal Government has indicated its intent to develop regulations that would be in effect in the near term 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. In the province of Alberta, GHG reduction regulations came into effect July 1, 2007, affecting facilities emitting more than 100 kilotonnes of CO2e annually. Two of the Company’s facilities, the Primrose/Wolf Lake in situ heavy crude oil facilities and the Hays sour natural gas plant are subject to compliance under the regulations. In the province of British Columbia, carbon tax is currently being assessed at $25/tonne of CO2e on fuel consumed and gas ﬂared in the province. This rate is scheduled to increase to $30/tonne on July 1, 2012. As part of its involvement with the Western Climate Initiative, British Columbia may require certain upstream oil and gas facilities to participate in a regional cap and trade system. If such a system is implemented, it is not expected to be in place before 2014. It is estimated that four facilities in British Columbia will be included under the cap and trade system, based on a proposed requirement of 25 kilotonne CO2e annually. The province of Saskatchewan 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 has been decreased below the Company’s estimated current operations emissions. In Phase 3 (2013 – 2020) the Company’s CO2 allocation is expected to be further reduced, although details on Phase 3 have not yet been ﬁnalized. 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 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 enhanced oil recovery, and participation in an industry initiative to promote an integrated CO2 capture and storage network. The additional requirements of enacted or proposed GHG regulations on the Company’s operations will 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. 46 Canadian Natural Critical Accounting Estimates and Change in Accounting Policies The preparation of ﬁnancial statements requires the Company to make estimates, assumptions and judgements 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 estimates are reviewed by the Company’s Audit Committee annually. The Company believes the following are the most critical accounting estimates in preparing its consolidated ﬁnancial statements. Depletion, Depreciation and Amortization and Impairment Exploration and evaluation (“E&E”) asset 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. Exploration and evaluation 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 proved reserves are determined to exist. 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 assets 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 of 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 quantities of recoverable reserves, production quantities, future commodity prices and development and production costs. Changes in any of these assumptions, such as a downward revision in probable reserves volumes, decrease in commodity prices or increase in costs, could impact the fair value. 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. The unit-of-production 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 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 any such indication of impairment exists, the Company performs an impairment test related to the speciﬁc assets. Individual assets are grouped for impairment assessment purposes into CGU’s, 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. The determination of fair value of CGUs requires the use of assumptions and estimates including quantities of recoverable reserves, production quantities, future commodity prices and development and production costs. Changes in any of these assumptions, such as a downward revision in reserves, decrease in commodity prices or increase in costs, could impact the fair value. Crude Oil and Natural Gas Reserves The estimation of reserves involves the exercise of judgement. Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and the cost and timing of future capital expenditures, all of which are subject to many uncertainties and interpretations. The Company expects that, over time, its reserve estimates will be revised either 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 the 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 crude oil and natural gas property, plant and equipment and E&E carrying amounts. 2011 Annual Report 47 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 average credit-adjusted risk-free interest rate, which is currently 4.6%. 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 the 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 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 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 be due. Risk Management Activities The Company uses various derivative ﬁnancial instruments to manage its commodity price, foreign currency and interest rate exposures. These ﬁnancial instruments are entered into solely for hedging purposes and are not used for speculative purposes. The estimated fair value of derivative ﬁnancial instruments has been determined based on appropriate internal valuation methodologies 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 and discount rates. In determining these assumptions, 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. 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 Purchase prices related to business combinations and asset acquisitions 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 assumptions and estimates 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. 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 (a) crude oil and natural gas reserves, and (b) future prices of crude oil and natural gas. 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. 48 Canadian Natural Share-based compensation 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 each reporting period for subsequent changes in the fair value of the liability. 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, 2011, 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. The Company’s management also performed an assessment of internal control over ﬁnancial reporting as at December 31, 2011, 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 2011 that have materially affected, or are reasonably likely to materially affect, internal controls over ﬁnancial reporting. While the Company’s management believes that the Company’s disclosure controls and procedures and internal controls 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. Internal Controls Over Financial Reporting The Company has identiﬁed, developed and tested systems and accounting and reporting processes and changes required to capture data required for IFRS accounting and reporting, including 2010 requirements to capture both Canadian GAAP and IFRS data. International Financial Reporting Standards In 2010, the CICA Handbook was revised to incorporate IFRS and require publicly accountable enterprises to apply IFRS effective for years beginning on or after January 1, 2011. The 2011 ﬁscal year is the ﬁrst year in which the Company has prepared its consolidated ﬁnancial statements in accordance with IFRS as issued by the IASB. The accounting policies adopted by the Company under IFRS are set out in note 1 to the Company’s consolidated ﬁnancial statements and are based on IFRS issued and outstanding as at December 31, 2011. Subject to certain transition elections disclosed in note 22 to the Company’s consolidated ﬁnancial statements, the Company has consistently applied the same accounting policies in its opening IFRS balance sheet at January 1, 2010 and throughout all periods presented, as if these policies had always been in effect. Unless otherwise stated, comparative ﬁgures for 2010 have been restated from Canadian GAAP to comply with IFRS. Note 22 to the Company’s consolidated ﬁnancial statements discloses the impact of the transition to IFRS on the Company’s reported ﬁnancial position, net earnings and cash ﬂows, including the nature and effect of signiﬁcant changes in accounting policies from those used in the Company’s Canadian GAAP consolidated ﬁnancial statements for the year ended December 31, 2010. 2011 Annual Report 49 Accounting Standards Issued but Not Yet Applied The Company is required to adopt IFRS 9, “Financial Instruments”, effective January 1, 2015, with earlier adoption permitted. IFRS 9 replaces existing requirements included in IAS 39, “Financial Instruments - Recognition and Measurement”. The new standard replaces the multiple classiﬁcation and measurement models for ﬁnancial assets and liabilities with a new model that has only two categories: amortized cost and fair value through proﬁt and loss. Under IFRS 9, fair value changes due to credit risk for liabilities designated at fair value through proﬁt and loss would generally be recorded in other comprehensive income. In May 2011, the IASB issued the following new accounting standards, which are required to be adopted effective January 1, 2013: IFRS 10 “Consolidated Financial Statements” replaces IAS 27 “Consolidated and Separate Financial Statements” (IAS 27 still contains guidance for Separate Financial Statements) and Standing Interpretations Committee (“SIC”) 12 “Consolidation – Special Purpose Entities”. IFRS 10 establishes the principles for the presentation and preparation of consolidated ﬁnancial statements. The standard deﬁnes the principle of control and establishes control as the basis for consolidation, as well as providing guidance on how to apply the control principle to determine whether an investor controls an investee. IFRS 11 “Joint Arrangements” replaces IAS 31 “Interests in Joint Ventures” and SIC 13 “Jointly Controlled Entities – Non-Monetary Contributions by Venturers”. The new standard deﬁnes two types of joint arrangements, joint operations and joint ventures, and prescribes the accounting treatment for each type of joint arrangement – recognition of the proportionate interest in the assets, liabilities, revenues and expenses; and equity accounting, respectively. There is no longer a choice of the accounting method. IFRS 12 “Disclosure of Interests in Other Entities”. The standard includes disclosure requirements for investments in subsidiaries, joint arrangements, associates and unconsolidated structured entities. This standard does not impact the Company’s accounting for investments in other entities, but will impact the related disclosures. IFRS 13 “Fair Value Measurement” provides guidance on how fair value should be applied where its use is already required or permitted by other standards within IFRS. The standard includes a deﬁnition of fair value and a single source of fair value measurement and disclosure requirements for use across all IFRSs that require or permit the use of fair value. In June 2011, the IASB issued amendments to IAS 1 “Presentation of Financial Statements” that require items of other comprehensive income that may be reclassiﬁed to net earnings to be grouped together. The amendments also require that items in other comprehensive income and net earnings be presented as either a single statement or two consecutive statements. The standard is effective for ﬁscal years beginning on or after July 1, 2012. In October 2011, the IASB issued IFRS Interpretation Committee (“IFRIC”) 20 “Stripping Costs in the Production Phase of a Surface Mine”. The IFRIC requires overburden removal costs during the production phase to be capitalized and depreciated if the Company can demonstrate that probable future economic beneﬁts will be realized, the costs can be reliably measured, and the Company can identify the component of the ore body for which access has been improved. The IFRIC is effective for ﬁscal periods beginning on or after January 1, 2013. The Company is currently assessing the impact of these new and amended standards on its consolidated ﬁnancial statements. The Company does not plan to early adopt the above noted standards. 50 Canadian Natural 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. The Company targets production levels in 2012 to average between 440,000 bbl/d and 480,000 bbl/d of crude oil and NGLs and between 1,247 MMcf/d and 1,297 MMcf/d of natural gas. Capital expenditures in 2012 are currently targeted to be as follows: ($ millions) Exploration and Production North America natural gas North America crude oil and NGLs North America bitumen (thermal oil) Primrose and future Kirby South Phase 1 North Sea and Offshore Africa Property acquisitions, dispositions and midstream Oil Sands Mining and Upgrading Project capital Reliability – Tranche 2 Directive 74 and Technology Phase 2A Phase 2B Phase 3 Phase 4 Owner’s Costs and Other Total capital projects Sustaining capital Turnarounds and reclamation Capitalized interest and other Total The above capital expenditures budget incorporates the following levels of drilling activity: (Number of wells) Targeting natural gas Targeting crude oil Stratigraphic test / service wells – Exploration and Production Stratigraphic test wells – Oil Sands Mining and Upgrading Total North America Natural Gas 2012 Guidance $ 645 2,010 940 480 480 135 $ 4,690 145 190 300 625 420 30 240 1,950 225 45 135 2,355 $ $ 2012 Guidance 45 1,115 584 230 1,974 The 2012 North America natural gas drilling program is highlighted by the continued high-grading of the Company’s natural gas asset base, as follows: (Number of wells) Conventional natural gas Cardium natural gas Deep natural gas Total 2012 Guidance 4 1 40 45 2011 Annual Report 51 North America Crude Oil and NGLs The 2012 North America crude oil drilling program is highlighted by continued development of the Primrose thermal projects, Pelican Lake, and a strong primary heavy crude oil program, as follows: (Number of wells) Primary heavy crude oil Bitumen (thermal oil) Light and medium crude oil Pelican Lake heavy crude oil Total 2012 Guidance 808 159 134 13 1,114 Oil Sands Mining and Upgrading During 2012, Phase 2/3 will continue to progress engineering and construction activities with respect to extraction, froth treatment, hydrotreatment, the butane storage unit, tailings and the vacuum unit in accordance with the overall Phase 2/3 execution schedule and strategy. North Sea During 2012, the majority of capital expenditures will be incurred to complete necessary sustaining capital activities on North Sea platforms. Offshore Africa During 2012, the majority of capital expenditures will be incurred on drilling and completions at the Espoir ﬁeld. Sensitivity Analysis The following table is indicative of the annualized sensitivities of cash ﬂow from operations and net earnings from changes in certain key variables. The analysis is based on business conditions and sales volumes during the fourth quarter of 2011, excluding 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 (1) Excluding ﬁnancial derivatives Including ﬁnancial derivatives Natural gas – AECO C$0.10/Mcf (1) Excluding ﬁnancial derivatives Including ﬁnancial derivatives 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 Cash ﬂow from operations (per common ($ millions) share, basic) Net earnings ($ millions) Net earnings (per common share, basic) $ $ $ $ $ $ 102 $ 102 $ 21 $ 21 $ 171 $ 6 $ 0.09 $ 0.09 $ 0.02 $ 0.02 $ 0.16 $ 0.01 $ 102 $ 102 $ 21 $ 21 $ 130 $ - $ $ $ 97 - 99 $ 6 $ 0.09 $ 0.01 $ 55 - 56 $ 6 $ 0.09 0.09 0.02 0.02 0.12 - 0.05 0.01 (1) For details of ﬁnancial instruments in place, refer to note 17 to the Company’s consolidated ﬁnancial statements as at December 31, 2011. 52 Canadian Natural Daily Production by Segment, Before Royalties Crude oil and NGLs (bbl/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading North Sea Offshore Africa Total Natural gas (MMcf/d) North America North Sea Offshore Africa Total Q1 Q2 Q3 Q4 2011 2010 2009 290,130 295,715 304,671 291,839 295,618 270,562 234,523 7,269 34,101 25,488 – 32,866 21,334 50,354 26,350 22,525 102,952 26,769 22,726 40,434 29,992 23,009 90,867 33,292 30,264 50,250 37,761 32,929 356,988 349,915 403,900 444,286 389,053 424,985 355,463 1,225 9 22 1,256 1,218 7 15 1,240 1,226 5 21 1,252 1,255 6 19 1,280 1,231 7 19 1,257 1,217 10 16 1,243 1,287 10 18 1,315 Barrels of oil equivalent (BOE/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading North Sea Offshore Africa Total 494,223 498,658 509,080 500,984 500,778 473,447 449,054 7,269 35,563 29,176 – 34,048 23,833 50,354 27,161 25,980 102,952 27,688 25,975 40,434 31,082 26,232 90,867 34,973 32,904 50,250 39,444 35,982 566,231 556,539 612,575 657,599 598,526 632,191 574,730 Per Unit Results – Exploration and Production (1) Q1 Q2 Q3 Q4 2011 2010 2009(3) Crude oil and NGLs ($/bbl) Sales price (2) Royalties Production expense Netback Natural gas ($/Mcf) Sales price (2) Royalties Production expense Netback Barrels of oil equivalent ($/BOE) Sales price (2) Royalties Production expense $ 67.96 $ 82.58 $ 73.80 $ 85.28 $ 77.46 $ 65.81 $ 57.68 6.73 15.92 10.43 14.30 11.62 15.38 15.53 16.85 12.30 15.75 11.52 16.42 10.09 14.16 $ 43.23 $ 55.58 $ 45.86 $ 52.90 $ 49.41 $ 41.56 $ 35.03 $ 3.83 $ 0.13 1.17 3.83 $ 0.24 1.11 3.76 $ 0.17 1.15 3.50 $ 0.18 1.15 3.73 $ 0.18 1.15 4.08 $ 0.20 1.09 4.53 0.32 1.08 $ 2.53 $ 2.48 $ 2.44 $ 2.17 $ 2.40 $ 2.79 $ 3.13 $ 51.33 $ 60.77 $ 55.19 $ 61.21 $ 57.16 $ 49.90 $ 44.87 4.72 11.98 7.59 12.83 7.83 12.12 10.14 13.12 6.72 11.25 8.12 12.42 6.87 11.59 Netback $ 32.87 $ 40.82 $ 34.77 $ 37.95 $ 36.62 $ 31.93 $ 28.17 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of transportation and blending costs and excluding risk management activities. (3) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. 2011 Annual Report 53 Per Unit Results – Oil Sands Mining and Upgrading (1) Q1 Q2 Q3 Q4 2011 2010 2009(5) Crude oil and NGLs ($/bbl) SCO sales price (2) Bitumen royalties (3) Production expense (4) Netback $ 82.93 $ 4.14 45.69 – $ 96.19 $ 103.16 $ 99.74 $ 77.89 $ 70.83 2.15 – 39.89 – 4.21 36.04 2.72 36.36 3.48 35.85 3.99 36.64 $ 33.10 $ – $ 56.86 $ 62.91 $ 59.11 $ 38.81 $ 28.79 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of transportation and excluding risk management activities. (3) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes. (4) Amounts expressed on a per unit basis in 2011 are based on sales volumes excluding the period during suspension of production. (5) Comparative amounts for 2009 are reported in accordance with Canadian generally accepted accounting principles as previously reported. Trading and Share Statistics Q1 Q2 Q3 Q4 2011 2010 $ $ $ 50.50 $ 40.05 $ 47.94 $ 48.41 $ 37.43 $ 40.43 $ 42.14 $ 29.80 $ 30.77 $ 39.41 $ 27.25 $ 38.15 $ 50.50 $ 27.25 $ 38.15 $ 45.00 31.97 44.35 800,044 661,832 $ 41,830 $ 1,096,460 48,379 1,090,848 $ $ $ 52.04 $ 40.42 $ 49.43 $ 50.25 $ 38.18 $ 41.86 $ 44.12 $ 28.77 $ 29.27 $ 38.72 $ 25.69 $ 37.37 $ 52.04 $ 25.69 $ 37.37 $ 44.77 30.00 44.42 937,481 759,327 $ 40,975 $ 1,096,460 48,455 1,090,848 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) 54 Canadian Natural 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 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 2011 consolidated ﬁnancial statements and its internal control over ﬁnancial reporting as at December 31, 2011; and the Company’s 2010 consolidated ﬁnancial statements. 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 6, 2012 Douglas A. Proll, CA Chief Financial Ofﬁcer & Senior Vice-President, Finance Randall S. Davis, CA Vice-President, Finance & Accounting 2011 Annual Report 55 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 13(a)–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 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, 2011. 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 Accountants, has provided an opinion on the Company’s internal control over ﬁnancial reporting as at December 31, 2011, as stated in their Auditor’s Report. Steve W. Laut President Calgary, Alberta, Canada March 6, 2012 Douglas A. Proll, CA Chief Financial Ofﬁcer & Senior Vice-President, Finance 56 Canadian Natural Independent Auditor’s Report To the Shareholders of Canadian Natural Resources Limited We have completed the integrated audits of Canadian Natural Resources Limited’s 2011 consolidated ﬁnancial statements and its internal control over ﬁnancial reporting as at December 31, 2011 and an audit of its 2010 consolidated ﬁnancial statements. 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, 2011, December 31, 2010 and January 1, 2010 and the consolidated statements of earnings, comprehensive income, changes in equity and cash ﬂows for each of the years in the two year period ended December 31, 2011, 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 an audit to obtain reasonable assurance about whether the consolidated ﬁnancial statements are free from material misstatement. Canadian generally accepted auditing standards 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 judgment, 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 the Company’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, 2011, December 31, 2010 and January 1, 2010 and its ﬁnancial performance and cash ﬂows for each of the years in the two year period ended December 31, 2011 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, 2011, based on criteria established in Internal Control - Integrated Framework, 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 report. Auditor’s responsibility Our responsibility is to express an opinion on the Company’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. 2011 Annual Report 57 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 the Company’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, 2011 based on criteria established in Internal Control - Integrated Framework issued by COSO. Chartered Accountants Calgary, Alberta, Canada March 6, 2012 58 Canadian Natural Consolidated Balance Sheets As at (millions of Canadian dollars) ASSETS Current assets Cash and cash equivalents Accounts receivable Inventory Prepaids and other Exploration and evaluation assets Property, plant and equipment Other long-term assets LIABILITIES Current liabilities Accounts payable Accrued liabilities Current income tax liabilities Current portion of long-term debt Current portion of other long-term liabilities Long-term debt Other long-term liabilities Deferred income tax liabilities SHAREHOLDERS’ EQUITY Share capital Retained earnings Accumulated other comprehensive income December 31 2011 December 31 2010 Note January 1 2010 $ 34 $ 22 $ 4 5 6 7 2,077 550 120 2,781 2,475 41,631 391 1,481 477 129 2,109 2,402 38,429 14 $ 47,278 $ 42,954 $ $ 526 $ 274 $ 8 9 8 9 11 12 13 2,347 347 359 455 4,034 8,212 3,913 8,221 1,735 430 397 870 3,706 8,088 3,004 7,788 3,507 19,365 26 22,898 3,147 17,212 9 20,368 13 1,148 438 146 1,745 2,293 37,018 6 41,062 240 1,430 94 400 854 3,018 9,259 2,485 7,462 2,834 15,927 77 18,838 41,062 24,380 22,586 22,224 Commitments and contingencies (note 18) Approved by the Board of Directors on March 6, 2012 $ 47,278 $ 42,954 $ Catherine M. Best Chair of the Audit Committee and Director N. Murray Edwards Vice-Chairman of the Board of Directors and Director 2011 Annual Report 59 Consolidated Statements of Earnings 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 costs Risk management activities Foreign exchange loss (gain) Horizon asset impairment provision Insurance recovery – property damage Insurance recovery – business interruption Earnings before taxes Current income tax expense Deferred income tax expense Net earnings Net earnings per common share Basic Diluted Note 2011 2010 $ 15,507 $ (1,715) 13,792 14,322 (1,421) 12,901 3,671 2,327 3,604 235 (102) 130 373 (27) 1 396 (393) (333) 9,882 3,910 860 407 6 9 9 16 17 10 10 10 11 11 $ 2,643 $ 3,449 1,783 4,120 211 203 123 448 (134) (163) – – – 10,040 2,861 789 399 1,673 15 $ 15 $ 2.41 $ 2.40 $ 1.54 1.53 Consolidated Statements of Comprehensive Income For the years ended December 31 (millions of Canadian dollars) Net earnings Net change in derivative ﬁnancial instruments designated as cash ﬂow hedges Unrealized loss, net of taxes of $5 million (2010 – $13 million) Reclassiﬁcation to net earnings, net of taxes of $17 million (2010 – $1 million) Foreign currency translation adjustment Translation of net investment Other comprehensive income (loss), net of taxes Comprehensive income 2011 2010 $ 2,643 $ 1,673 (23) 52 29 (12) 17 (40) (4) (44) (24) (68) $ 2,660 $ 1,605 60 Canadian Natural Consolidated Statements of Changes in Equity 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 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 Note 2011 2010 12 $ 12 12 13 3,147 $ 255 115 (10) 3,507 17,212 2,643 (94) (396) 19,365 9 17 26 2,834 170 149 (6) 3,147 15,927 1,673 (62) (326) 17,212 77 (68) 9 $ 22,898 $ 20,368 2011 Annual Report 61 Consolidated Statements of Cash Flows For the years ended December 31 (millions of Canadian dollars) Operating activities Net earnings Non-cash items Depletion, depreciation and amortization Share-based compensation Asset retirement obligation accretion Unrealized risk management gain Unrealized foreign exchange loss (gain) Realized foreign exchange gain on repayment of US dollar debt securities Deferred income tax expense Horizon asset impairment provision Insurance recovery – property damage Other Abandonment expenditures Net change in non-cash working capital Financing activities Repayment of bank credit facilities, net Repayment of medium-term notes Issue 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 Expenditures on exploration and evaluation assets and property, plant and equipment Investment in other long-term assets Net change in non-cash working capital Increase in cash and cash equivalents Cash and cash equivalents – beginning of year Cash and cash equivalents – end of year Interest paid Income taxes paid Supplemental disclosure of cash ﬂow information (note 19) Note 2011 2010 $ 2,643 $ 1,673 3,604 (102) 130 (128) 215 (225) 407 396 (393) (55) (213) (36) 6,243 (647) – 621 255 (104) (378) (15) (268) (6,201) (321) 559 (5,963) 12 22 34 $ 456 $ 706 $ 4,120 203 123 (24) (161) – 399 – – (8) (179) 136 6,282 (472) (400) – 170 (68) (302) (12) (1,084) (5,335) – 146 (5,189) 9 13 22 471 213 6, 10 10 19 19 19 19 $ $ $ 62 Canadian Natural 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 and an electricity co-generation system. The Company was incorporated in Alberta, Canada. The address of its registered ofﬁce is 2500, 855-2 Street S.W., Calgary, Alberta. In 2010, the Canadian Institute of Chartered Accountants (“CICA”) Handbook was revised to incorporate International Financial Reporting Standards (“IFRS”) and require publicly accountable enterprises to apply IFRS effective for years beginning on or after January 1, 2011. The 2011 ﬁscal year is the ﬁrst year in which the Company has prepared its consolidated ﬁnancial statements in accordance with IFRS as issued by the International Accounting Standards Board. The accounting policies adopted by the Company under IFRS are set out below and are based on IFRS issued and outstanding as at December 31, 2011. Subject to certain transition elections disclosed in note 22, the Company has consistently applied the same accounting policies in its opening IFRS balance sheet at January 1, 2010 and throughout all periods presented, as if these policies had always been in effect. Comparative information for 2010 has been restated from Canadian Generally Accepted Accounting Principles (“Canadian GAAP”) to comply with IFRS. In these consolidated ﬁnancial statements, Canadian GAAP refers to Canadian GAAP before the adoption of IFRS. Note 22 discloses the impact of the transition to IFRS on the Company’s reported ﬁnancial position, net earnings and cash ﬂows, including the nature and effect of signiﬁcant changes in accounting policies from those used in the Company’s Canadian GAAP consolidated ﬁnancial statements for the year ended December 31, 2010. (A) Principles of Consolidation The consolidated ﬁnancial statements have been prepared under the historical cost convention, unless otherwise required. Certain of the Company’s activities are conducted through joint ventures. Where the Company has a direct ownership interest in jointly controlled assets, the assets, liabilities, revenue and expenses related to the jointly controlled assets are included in the consolidated ﬁnancial statements in proportion to the Company’s interest. Where the Company has an interest in jointly controlled entities, it uses the equity method of accounting. Under the equity method, the Company’s investment is initially recognized at cost and subsequently adjusted for the Company’s share of the jointly controlled entity’s income or loss, less dividends received. Unrealized gains and losses on transactions between the Company and the jointly controlled entity are eliminated. (B) 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. (C) Inventory Inventory is primarily comprised of product inventory and materials and supplies. Product inventory includes crude oil held for sale, 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. 2011 Annual Report 63 (D) 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 immediately 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 proved reserves are determined to exist. 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. (E) Property, Plant and Equipment Exploration and Production Property, plant and equipment is measured at cost less accumulated depletion and depreciation and impairment provisions. 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. The cost of an asset comprises its acquisition, 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. The capitalized value of a ﬁnance lease is also included in property, plant and equipment. The cost of property, plant and equipment at January 1, 2010, the date of transition to IFRS, was determined as described in note 22. Crude oil and natural gas properties are depleted using the unit-of-production method over proved reserves. The unit-of-production 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 property acquisition, construction and development costs, the estimate of any asset retirement costs, and applicable borrowing costs. Mine-related costs and costs of the upgrader and related infrastructure located on the Horizon site are amortized on the unit-of-production method based on Horizon proved reserves or productive capacity, respectively. 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 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 amortized on a declining balance basis. Useful lives The expected useful lives of property, plant and equipment are reviewed on an annual basis, with changes in useful lives accounted for prospectively. 64 Canadian Natural Derecognition An item of property, plant and equipment 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 item) is recognized in net earnings. Major maintenance expenditures Inspection costs associated with major maintenance turnarounds are capitalized and amortized 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 any such indication of impairment exists, the Company performs an impairment test related to the assets. Individual assets are grouped for impairment assessment purposes into CGU’s, 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 to sell 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. 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 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. Such reversal 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. (F) Business Combinations 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. (G) Overburden Removal Costs Overburden removal costs incurred during the initial development of a mine 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 amortized over the life of the mining reserves that directly beneﬁt from the overburden removal activity. (H) Capitalized Borrowing Costs 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. (I) Leases 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. 2011 Annual Report 65 (J) 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 present obligation 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 the 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. (K) Foreign Currency Translation (i) 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. 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. (ii) Transactions and balances Foreign currency transactions are translated into the functional currency 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 of the Company or its subsidiaries are recognized in net earnings. (L) 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. (M) Production Sharing Contracts Production generated from 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 PSCs. (N) Income Tax 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. 66 Canadian Natural 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. (O) 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. 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. (P) Financial Instruments The Company classiﬁes its ﬁnancial instruments into one of the following categories: fair value through proﬁt or loss; held-to-maturity investments; loans and receivables; and ﬁnancial liabilities measured at amortized cost. 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, and accounts receivable are classiﬁed as loans and receivables. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classiﬁed as other ﬁnancial liabilities measured 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 immediately 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 including loans and receivables are calculated as the difference between the amortized cost of the loan or receivable 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. 2011 Annual Report 67 (Q) Risk Management Activities 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 as 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 and discount rates. The Company’s own credit risk is not included in the carrying amount of a risk management liability. 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 immediately 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 included 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 included in interest expense in net earnings. Changes in the fair value of non-designated interest rate swap contracts are included in risk management activities in net earnings. 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 included 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 included in other comprehensive income and is reclassiﬁed to interest expense when realized, 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 included 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 on the consolidated balance sheets 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 immediately in net earnings. Realized gains or losses on the termination of ﬁnancial instruments that have not been designated as hedges are recognized immediately in net earnings. Upon termination of an interest rate swap designated as a fair value hedge, the interest rate swap is derecognized on the consolidated balance sheets and the related long-term debt hedged is no longer revalued for subsequent changes in fair value. The fair value adjustment 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 realized. Changes in the fair value of foreign currency forward contracts not included as hedges are included in risk management activities and recognized immediately 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. 68 Canadian Natural (R) 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 on 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. (S) Per Common Share Amounts The Company calculates basic earnings per 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 share is calculated using the more dilutive of cash settlement or share settlement under the treasury stock method. (T) 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, net of tax, from proceeds. 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. (U) Dividends Dividends on common shares are recognized in the Company’s ﬁnancial statements in the period in which the dividends are approved by the Board of Directors. 2. Accounting Standards Issued but Not Yet Applied The Company is required to adopt IFRS 9, “Financial Instruments”, effective January 1, 2015, with earlier adoption permitted. IFRS 9 replaces existing requirements included in IAS 39, “Financial Instruments - Recognition and Measurement”. The new standard replaces the multiple classiﬁcation and measurement models for ﬁnancial assets and liabilities with a new model that has only two categories: amortized cost and fair value through proﬁt and loss. Under IFRS 9, fair value changes due to credit risk for liabilities designated at fair value through proﬁt and loss would generally be recorded in other comprehensive income. In May 2011, the IASB issued the following new accounting standards, which are required to be adopted effective January 1, 2013: IFRS 10 “Consolidated Financial Statements” replaces IAS 27 “Consolidated and Separate Financial Statements” (IAS 27 still contains guidance for Separate Financial Statements) and Standing Interpretations Committee (“SIC”) 12 “Consolidation – Special Purpose Entities”. IFRS 10 establishes the principles for the presentation and preparation of consolidated ﬁnancial statements. The standard deﬁnes the principle of control and establishes control as the basis for consolidation, as well as providing guidance on how to apply the control principle to determine whether an investor controls an investee. IFRS 11 “Joint Arrangements” replaces IAS 31 “Interests in Joint Ventures” and SIC 13 “Jointly Controlled Entities – Non-Monetary Contributions by Venturers”. The new standard deﬁnes two types of joint arrangements, joint operations and joint ventures, and prescribes the accounting treatment for each type of joint arrangement – recognition of the proportionate interest in the assets, liabilities, revenues and expenses; and equity accounting, respectively. There is no longer a choice of the accounting method. IFRS 12 “Disclosure of Interests in Other Entities”. The standard includes disclosure requirements for investments in subsidiaries, joint arrangements, associates and unconsolidated structured entities. This standard does not impact the Company’s accounting for investments in other entities, but will impact the related disclosures. IFRS 13 “Fair Value Measurement” provides guidance on how fair value should be applied where its use is already required or permitted by other standards within IFRS. The standard includes a deﬁnition of fair value and a single source of fair value measurement and disclosure requirements for use across all IFRSs that require or permit the use of fair value. In June 2011, the IASB issued amendments to IAS 1 “Presentation of Financial Statements” that require items of other comprehensive income that may be reclassiﬁed to net earnings to be grouped together. The amendments also require that items in other comprehensive income and net earnings be presented as either a single statement or two consecutive statements. The standard is effective for ﬁscal years beginning on or after July 1, 2012. 2011 Annual Report 69 In October 2011, the IASB issued IFRS Interpretation Committee (“IFRIC”) 20 “Stripping Costs in the Production Phase of a Surface Mine”. The IFRIC requires overburden removal costs during the production phase to be capitalized and depreciated if the Company can demonstrate that probable future economic beneﬁts will be realized, the costs can be reliably measured, and the Company can identify the component of the ore body for which access has been improved. The IFRIC is effective for ﬁscal periods beginning on or after January 1, 2013. The Company is currently assessing the impact of these new and amended standards on its consolidated ﬁnancial statements. The Company does not plan to early adopt the above noted standards. 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 calculation of asset retirement obligations includes estimates and judgements of the scope, the future costs and the timing of the cash ﬂows to settle the liability, the discount rate used in reﬂecting the passage of time, and future inﬂation rates. (C) Income taxes 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 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 and asset acquisitions 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 assumptions, estimates 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. 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 common stock options granted under the Option Plan, including expected volatility, expected exercise behavior and future forfeiture rates. At each period end, stock options outstanding are remeasured for changes in the fair value of the liability. 70 Canadian Natural (G) Identiﬁcation of CGUs 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. (H) Impairment of Assets 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 to sell 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 and discount rates as well as future development and operating costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGU’s. 4. Inventory Product inventory Materials and supplies Other December 31 December 31 2010 2011 January 1 2010 $ $ 328 $ 222 – 550 $ 286 $ 187 4 477 $ 245 159 34 438 5. Exploration and Evaluation Assets Oil Sands Mining and Upgrading Exploration and Production North America North Sea Offshore Africa Cost At January 1, 2010 Additions Transfers to property, plant and equipment Foreign exchange adjustments At December 31, 2010 Additions Transfers to property, plant and equipment $ 2,102 $ 563 (299) – 2,366 309 (233) At December 31, 2011 $ 2,442 $ – $ 6 – (1) 5 1 (6) – $ 191 $ 3 (154) (9) 31 2 – – $ – – – – – – 33 $ – $ Total 2,293 572 (453) (10) 2,402 312 (239) 2,475 2011 Annual Report 71 6. Property, Plant and Equipment Head Exploration and Production Upgrading Midstream Ofﬁce Oil Sands Mining and Total North North Sea America Offshore Africa Cost At January 1, 2010 Additions Transfers from E&E assets Disposals/ derecognitions Foreign exchange adjustments and other At December 31, 2010 Additions Transfers from E&E assets Disposals/ derecognitions (1) Foreign exchange adjustments and other $ 36,159 $ 3,866 $ 2,666 $ 13,758 $ 4,403 299 – – 40,861 5,026 233 – – 190 – (5) (238) 254 154 – (146) 411 – – – 3,813 235 6 – 93 2,928 76 – (29) 69 14,169 1,545 – (503) – 284 $ 7 – – – 291 7 – – – 214 $ 56,947 5,283 453 (16) (389) 18 – (11) (5) 216 18 – – – 62,278 6,907 239 (532) 162 At December 31, 2011 $ 46,120 $ 4,147 $ 3,044 $ 15,211 $ 298 $ 234 $ 69,054 Accumulated depletion and depreciation At January 1, 2010 Expense Impairment (2) Disposals/ derecognitions Foreign exchange adjustments and other 2,473 – – (5) 295 – (5) (139) $ 16,427 $ 2,054 $ 1,008 $ At December 31, 2010 Expense Impairment (1) Disposals/ derecognitions (1) Foreign exchange adjustments and other 18,895 2,826 – – – 2,205 248 – – 59 298 637 – (39) 1,904 242 – (29) 35 207 $ 396 – – 4 607 266 396 (503) 10 81 $ 8 – – – 89 7 – – – 152 $ 19,929 3,483 637 (16) (184) 13 – (11) (5) 149 15 – – 2 23,849 3,604 396 (532) 106 At December 31, 2011 $ 21,721 $ 2,512 $ 2,152 $ 776 $ 96 $ 166 $ 27,423 Net book value - at December 31, 2011 - at December 31, 2010 - at January 1, 2010 892 $ 14,435 $ $ 24,399 $ 1,635 $ $ 21,966 $ 1,608 $ 1,024 $ 13,562 $ $ 19,732 $ 1,812 $ 1,658 $ 13,551 $ 202 $ 202 $ 203 $ 68 $ 41,631 67 $ 38,429 62 $ 37,018 (1) During 2011, the Company derecognized certain property, plant and equipment related to the coker ﬁre at Horizon in the amount of $411 million based on estimated replacement cost, net of accumulated depletion and depreciation of $15 million. There was a resulting impairment charge of $396 million. For additional information, refer to note 10. (2) During 2010, the Company recognized a $637 million impairment relating to the Gabon CGU, in Offshore Africa, which was included in depletion, depreciation and amortization expense. The impairment was based on the difference between the December 31, 2010 net book value of the assets and their recoverable amounts. The recoverable amounts were determined using fair value less costs to sell based on discounted future cash ﬂows of proved and probable reserves using forecast prices and costs. Development projects not subject to depletion At December 31, 2011 At December 31, 2010 At January 1, 2010 $ $ $ 1,443 934 1,270 The Company acquired a number of producing crude oil and natural gas assets in the North American Exploration and Production segment for total cash consideration of $1,012 million during the year ended December 31, 2011 (2010 – $1,482 million), net of associated asset retirement obligations of $79 million (2010 – $22 million). Interests in jointly controlled assets were acquired with full tax basis. No working capital or debt obligations were assumed. 72 Canadian Natural During the year ended December 31, 2011, the Company capitalized directly attributable administrative costs of $44 million (2010 – $43 million) in the North Sea and Offshore Africa, related to development activities and $60 million (2010 – $33 million) in North America, primarily related to Oil Sands Mining and Upgrading. 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 construction is substantially complete. For the year ended December 31, 2011, pre-tax interest of $59 million was capitalized to property, plant and equipment (2010 – $28 million) using a capitalization rate of 4.7% (2010 – 4.9%). 7. Other Long-Term Assets Investment in North West Redwater Partnership Other December 31 December 31 2010 2011 January 1 2010 $ $ 321 $ 70 391 $ – $ 14 14 $ – 6 6 Other long-term assets include a $321 million investment in the 50% owned North West Redwater Partnership (“Redwater”), of which $97 million was payable to Redwater at December 31, 2011 to fund project development. The investment is accounted for using the equity method. Redwater has entered into an agreement to construct and operate a bitumen upgrader and reﬁnery, which targets to process bitumen for the Company and the Government of Alberta under a 30 year fee-for-service contract. Project development is dependent upon completion of detailed engineering and ﬁnal project sanction by Redwater and its partners, and approval of the ﬁnal tolls. The Company’s share of assets and liabilities of Redwater at December 31, 2011 was comprised as follows: Current assets Non-current assets Current liabilities Non-current liabilities December 31 2011 $ $ $ $ 108 233 117 – 2011 Annual Report 73 8. Long-Term Debt Canadian dollar denominated debt Bank credit facilities Medium-term notes 5.50% unsecured debentures due December 17, 2010 4.50% unsecured debentures due January 23, 2013 4.95% unsecured debentures due June 1, 2015 US dollar denominated debt US dollar debt securities 6.70% due July 15, 2011 (2011 – US$ nil; 2010 – US$400 million) 5.45% due October 1, 2012 (US$350 million) 5.15% due February 1, 2013 (US$400 million) 1.45% due November 14, 2014 (2011 – US$500 million; 2010 – US$ nil) 4.90% due December 1, 2014 (US$350 million) 6.00% due August 15, 2016 (US$250 million) 5.70% due May 15, 2017 (US$1,100 million) 5.90% due February 1, 2018 (US$400 million) 3.45% due November 15, 2021 (2011 – US$500 million; 2010 – US$ nil) 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) Less: original issue discount on US dollar debt securities (1) Fair value impact of interest rate swaps on US dollar debt securities (2) Long-term debt before transaction costs Less: transaction costs (1) (3) Less: current portion (1) (2) December 31 December 31 2010 2011 January 1 2010 $ 796 $ 1,436 $ 1,897 – 400 400 – 400 400 1,596 2,236 – 356 406 509 356 255 1,119 406 509 406 356 356 458 1,119 406 (21) 6,996 31 7,027 8,623 398 348 398 – 348 249 1,094 398 – 398 348 348 447 1,094 398 (20) 6,246 47 6,293 8,529 (52) (44) 8,571 359 8,485 397 $ 8,212 $ 8,088 $ 400 400 400 3,097 419 366 419 – 366 262 1,151 419 – 419 366 366 471 1,151 419 (22) 6,572 39 6,611 9,708 (49) 9,659 400 9,259 (1) The Company has included unamortized original issue discounts and directly attributable transaction costs in the carrying amount of the outstanding debt. (2) The carrying amounts of US$350 million of 5.45% notes due October 2012 and US$350 million of 4.90% notes due December 2014 were adjusted by $31 million (December 2010 – $47 million; January 2010 – $39 million) to reﬂect the fair value impact of hedge accounting. (3) Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees. Bank Credit Facilities As at December 31, 2011, the Company had in place unsecured bank credit facilities of $4,724 million, comprised of: a $200 million demand credit facility; a revolving syndicated credit facility of $3,000 million maturing June 2015; a revolving syndicated credit facility of $1,500 million maturing June 2012; and a £15 million demand credit facility related to the Company’s North Sea operations. During 2011, the $2,230 million revolving syndicated credit facility was increased to $3,000 million and extended to June 2015. Each of the $3,000 million and $1,500 million facilities is extendible annually for one-year periods at the mutual agreement of the Company and the lenders. If the facilities are not extended, the full amount of the outstanding principal would be repayable on the maturity date. Borrowings under these facilities may be made by way of pricing referenced to Canadian dollar and US dollar bankers’ acceptances, and LIBOR, US base rate and Canadian prime loans. 74 Canadian Natural The Company’s weighted average interest rate on bank credit facilities outstanding as at December 31, 2011, was 2.2% (December 31, 2010 – 1.5%), and on long-term debt outstanding for the year ended December 31, 2011 was 4.7% (December 31, 2010 – 4.9%). In addition to the outstanding debt, letters of credit and ﬁnancial guarantees aggregating $436 million, including $127 million related to Horizon and $174 million related to North Sea operations, were outstanding at December 31, 2011. Medium-Term Notes In November 2011, the Company ﬁled a base shelf prospectus that allows for the issue of up to $3,000 million of medium-term notes in Canada until November 2013. If issued, these securities will bear interest as determined at the date of issuance. During 2010, the Company repaid $400 million of medium-term notes bearing interest at 5.50%. US Dollar Debt Securities In July 2011, the Company repaid US$400 million of US dollar debt securities bearing interest at 6.70%. In November 2011, the Company ﬁled a base shelf prospectus that allows for the issue of up to US$3,000 million of debt securities in the United States until November 2013. Subsequently, the Company issued US$1,000 million of unsecured notes under the US base shelf prospectus, comprised of US$500 million of 1.45% unsecured notes due November 2014 and US$500 million of 3.45% unsecured notes due November 2021. Concurrently, the Company entered into cross currency swaps to ﬁx the Canadian dollar interest and principal repayment amounts on the US$500 million of 3.45% unsecured notes due November 2021 at 3.96% and C$511 million (note 17). Proceeds from the securities issued were used to repay bank indebtedness. After issuing these securities, the Company has US$2,000 million remaining on its outstanding US$3,000 million base shelf prospectus, which expires in November 2013. If issued, these securities will bear interest as determined at the date of issuance. Required Debt Repayments Required debt repayments are as follows: Year 2012 2013 2014 2015 2016 Thereafter 9. Other Long-Term Liabilities Asset retirement obligations Share-based compensation Risk management (note 17) Other Less: current portion Repayment $ $ $ $ $ $ 356 806 865 1,196 255 5,135 December 31 December 31 2010 2011 January 1 2010 $ 3,577 $ 432 274 85 4,368 455 2,624 $ 663 485 102 3,874 870 $ 3,913 $ 3,004 $ 2,214 622 325 178 3,339 854 2,485 2011 Annual Report 75 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 4.6% (December 31, 2010 – 5.1%; January 1, 2010 – 5.8%). A reconciliation of the discounted asset retirement obligations is as follows: Balance – beginning of year Liabilities incurred Liabilities acquired Liabilities settled Asset retirement obligation accretion Revision of estimates Foreign exchange adjustments Balance – end of year Segmented asset retirement obligations Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream Share-based compensation $ 2011 2,624 $ 12 79 (213) 130 924 21 $ 3,577 $ 2010 2,214 12 22 (179) 123 474 (42) 2,624 December 31 December 31 2010 2011 January 1 2010 $ 1,862 $ 723 192 798 2 1,390 $ 670 137 426 1 905 630 129 549 1 $ 3,577 $ 2,624 $ 2,214 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 Capitalized to Oil Sands Mining and Upgrading Balance – end of year Less: current portion 2011 2010 $ 663 $ (102) (14) (115) – 432 384 $ 48 $ 622 203 (45) (149) 32 663 623 40 The share-based compensation liability of $432 million at December 31, 2011 (2010 – $663 million) was estimated using the Black-Scholes valuation model and 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. 76 Canadian Natural 2011 2010 $ $ 10.84 $ 38.15 $ 36.94% 0.94% 1.13% 4.65% 4.5 years 16.49 44.35 33.47% 0.68% 1.91% 4.96% 4.5 years 10. Horizon Asset Impairment Provision and Insurance Recovery Due to property damage resulting from a ﬁre in the Horizon primary upgrading coking plant on January 6, 2011, the Company recognized an asset impairment provision in the Oil Sands Mining and Upgrading segment of $396 million, net of accumulated depletion and amortization. Insurance proceeds of $393 million were also recognized, offsetting the property damage. Production resumed in August 2011. As at December 31, 2011, the Company ﬁnalized its property damage insurance claim with certain of its insurers. The Company believes that the remaining portion of the property damage insurance claim will be settled without further adjustment. The Company also maintains business interruption insurance to reduce operating losses related to its ongoing Horizon operations. The Company ﬁnalized its business interruption insurance claim for $333 million. 11. Income Taxes The provision for income tax is as follows: Current corporate income tax – North America Current corporate income tax – North Sea Current corporate income tax – Offshore Africa Current PRT(1) expense – North Sea Other taxes Current income tax expense Deferred corporate income tax expense Deferred PRT recovery – North Sea Deferred income tax expense Income tax expense (1) Petroleum Revenue Tax $ 2011 2010 315 $ 245 140 135 25 860 412 (5) 407 431 203 64 68 23 789 408 (9) 399 $ 1,267 $ 1,188 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 foreign exchange loss (gain) Stock options exercised for common shares Income tax rate and other legislation changes Non-deductible Offshore Africa impairment charge Other Income tax expense 2011 26.6% $ 1,040 $ 155 (77) 84 6 (31) 104 – (14) 2010 28.1% 802 82 (30) 15 (17) 217 – 130 (11) $ 1,267 $ 1,188 2011 Annual Report 77 The following table summarizes the temporary differences that give rise to the net deferred income tax asset and liability: December 31 December 31 2010 2011 January 1 2010 Deferred income tax liabilities Property, plant and equipment and exploration and evaluation assets Timing of partnership items $ Unrealized foreign exchange gain on long-term debt Deferred PRT Deferred income tax assets Asset retirement obligations Loss carryforwards Share-based compensation Unrealized risk management activities Other 8,404 $ 1,065 149 74 9,692 (1,136) (119) – (40) (176) (1,471) 7,719 $ 988 194 78 8,979 (806) (144) – (96) (145) (1,191) Net deferred income tax liability $ 8,221 $ 7,788 $ Movements in deferred tax liabilities and assets recognized in net earnings during the year were as follows: 7,107 1,127 152 91 8,477 (695) (84) (132) (74) (30) (1,015) 7,462 2011 2010 Property, plant and equipment and exploration and evaluation assets Timing of partnership items Unrealized foreign exchange (gain) loss on long-term debt Unrealized risk management activities Asset retirement obligations Share-based compensation Loss carryforwards Deferred PRT Other $ $ The following table summarizes the movements of deferred income tax liability during the year: Balance – beginning of year Deferred income tax expense Deferred income tax expense (recovery) included in other comprehensive income $ Foreign exchange adjustments Other Balance – end of year 662 $ 77 (45) 44 (321) – 25 (5) (30) 407 $ 2011 7,788 $ 407 12 20 (6) 684 (139) 42 (8) (127) 132 (60) (9) (116) 399 2010 7,462 399 (14) (59) – 7,788 $ 8,221 $ Taxable income from the Exploration and Production business in Canada is primarily generated through partnerships, with the related income taxes payable in periods subsequent to the current reporting period. North America current and deferred income taxes have been provided on the basis of this corporate structure. In addition, current income taxes 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 2011, the Canadian Federal government enacted legislation to implement several taxation changes. These changes include a requirement that, beginning in 2012, partnership income must be included in the taxable income of each corporate partner based on the tax year of the partner, rather than the ﬁscal year of the partnership. The legislation includes a ﬁve-year transition provision and has no impact on net earnings. During 2011, the UK government enacted an increase to the supplementary income tax rate charged on proﬁts from UK North Sea crude oil and natural gas production, increasing the combined corporate and supplementary income tax rate from 50% to 62%. As a result of the income tax rate change, the Company’s deferred income tax liability was increased by $104 million. 78 Canadian Natural During 2010, deferred income tax expense included a charge of $132 million related to enacted changes in Canada to the taxation of stock options surrendered by employees for cash. 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 did not recognize 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. 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 as long as the distributions remain within certain limits. 12. Share Capital Authorized 200,000 Class 1 preferred shares with a stated value of $10.00 each. 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 Cancellation of common shares Purchase of common shares under Normal Course Issuer Bid Balance – end of year 2011 2010 Number of shares (thousands) 1,090,848 8,683 $ – – (3,071) 1,096,460 $ Amount 3,147 255 115 – (10) 3,507 Number of shares (thousands) (1) 1,084,654 8,208 $ – (14) (2,000) 1,090,848 $ Amount 2,834 170 149 – (6) 3,147 (1) Restated to reﬂect two-for-one common share split in May 2010. Dividend Policy The Company has paid regular quarterly dividends in January, April, July and October of each year since 2001. The dividend policy undergoes a periodic review by the Board of Directors and is subject to change. On March 6, 2012, the Board of Directors set the Company’s regular quarterly dividend at $0.105 per common share (2011 – $0.09 per common share; 2010 – $0.075 per common share). Normal Course Issuer Bid In 2011, the Company announced a Normal Course Issuer Bid to purchase, through the facilities of the Toronto Stock Exchange and the New York Stock Exchange, during the twelve month period commencing April 6, 2011 and ending April 5, 2012, up to 27,406,131 common shares or 2.5% of the common shares of the Company outstanding at March 25, 2011. During 2011, the Company purchased 3,071,100 common shares (2010 – 2,000,000 common shares) at an average price of $33.68 per common share (2010 – $33.77 per common share), for a total cost of $104 million (2010 – $68 million). Retained earnings were reduced by $94 million (2010 – $62 million), representing the excess of the purchase price of the common shares over their average carrying value. 2011 Annual Report 79 Share split The Company’s shareholders passed a Special Resolution subdividing the common shares of the Company on a two-for-one basis at the Company’s Annual and Special Meeting held on May 6, 2010 with such subdivision taking effect on May 21, 2010. All common share, per common share, and stock option amounts were restated to reﬂect the common share split. 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, 2011 and 2010: 2011 2010 Stock options (thousands) 66,844 19,516 (1,124) (8,683) (3,067) 73,486 26,486 $ $ $ $ $ $ $ Weighted average exercise price 33.31 37.54 29.84 29.34 35.87 34.85 32.13 Stock options (thousands) (1) 64,211 16,168 (2,741) (8,208) (2,586) 66,844 23,668 $ $ $ $ $ $ $ Weighted average exercise price(1) 29.27 40.68 21.00 20.66 32.30 33.31 30.64 Outstanding – beginning of year Granted Surrendered for cash settlement Exercised for common shares Forfeited Outstanding – end of year Exercisable – end of year (1) Restated to reﬂect two-for-one common share split in May 2010. The range of exercise prices of stock options outstanding and exercisable at December 31, 2011 was as follows: Stock options outstanding Stock options exercisable Stock options outstanding (thousands) Weighted average remaining term (years) Weighted average exercise price Stock options exercisable (thousands) Weighted average exercise price 10,180 2,300 18,034 28,650 11,782 2,540 73,486 2.16 $ 1.06 $ 2.63 $ 3.71 $ 4.18 $ 3.87 $ 3.23 $ 23.21 28.10 33.33 36.49 42.23 45.65 34.85 5,486 $ 2,079 $ 8,507 $ 7,697 $ 2,064 $ 653 $ 26,486 $ 23.19 28.02 32.44 35.37 42.24 46.25 32.13 Range of exercise prices $22.98 – $24.99 $25.00 – $29.99 $30.00 – $34.99 $35.00 – $39.99 $40.00 – $44.99 $45.00 – $46.25 80 Canadian Natural 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 December 31 December 31 2010 2011 January 1 2010 $ $ 62 $ (36) 26 $ 33 $ (24) 9 $ 77 – 77 During the next twelve months, $6 million is expected to be reclassiﬁed to net earnings from accumulated other comprehensive income. 14. Capital Disclosures The Company does not have any externally imposed regulatory capital requirements for managing capital. The Company has deﬁned its capital to mean its long-term debt and consolidated shareholders’ equity, as determined 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 35% 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, 2011, the ratio was below the target range at 27%. 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 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 Net earnings per common share – basic – diluted December 31 December 31 2010 2011 January 1 2010 $ $ 8,571 $ 22,898 $ 27% 8,485 $ 20,368 $ 29% 9,659 18,838 34% 2011 2010 1,095,582 7,000 1,088,096 7,552 1,102,582 1,095,648 $ $ $ 2,643 $ 1,673 2.41 $ 2.40 $ 1.54 1.53 For the year ended December 31, 2011, 5,610,000 stock options (2010 – 3,338,000) were excluded from the calculation as their effect on per common share amounts was not dilutive. 2011 Annual Report 81 16. Interest and Other Financing Costs Interest expense: Long-term debt Other ﬁnancing costs Less: amounts capitalized on qualifying assets Total interest and other ﬁnancing costs Interest income: Interest income on cash and cash equivalents Total interest income Net interest and other ﬁnancing costs 17. Financial Instruments The carrying values of the Company’s ﬁnancial instruments by category are as follows: $ 2011 2010 450 $ (4) 446 59 387 (14) (14) 485 (6) 479 28 451 (3) (3) $ 373 $ 448 December 31, 2011 Loans and receivables at amortized cost Fair value through proﬁt or loss Derivatives used for hedging Financial liabilities at amortized cost $ $ 2,077 $ – – – – 2,077 $ – $ – – (38) – (38) $ – $ – – (236) – – $ (526) (2,347) (75) (8,571) (236) $ (11,519) $ December 31, 2010 Loans and receivables at amortized cost Fair value through proﬁt or loss Derivatives used for hedging Financial liabilities at amortized cost $ $ 1,481 $ – – – – 1,481 $ – $ – – (167) – (167) $ – $ – – (318) – – $ (274) (1,735) (91) (8,485) (318) $ (10,585) $ January 1, 2010 Loans and receivables at amortized cost Fair value through proﬁt or loss Derivatives used for hedging Financial liabilities at amortized cost $ $ 1,148 $ – – – – 1,148 $ – $ – – (182) – (182) $ – $ – – (143) – – $ (240) (1,430) (167) (9,659) (143) $ (11,496) $ (10,673) Total 2,077 (526) (2,347) (349) (8,571) (9,716) Total 1,481 (274) (1,735) (576) (8,485) (9,589) Total 1,148 (240) (1,430) (492) (9,659) Asset (liability) Accounts receivable Accounts payable Accrued liabilities Other long-term liabilities Long-term debt (1) Asset (liability) Accounts receivable Accounts payable Accrued liabilities Other long-term liabilities Long-term debt (1) Asset (liability) Accounts receivable Accounts payable Accrued liabilities Other long-term liabilities Long-term debt (1) (1) Includes the current portion of long-term debt. 82 Canadian Natural The carrying amount of the Company’s ﬁnancial instruments approximates their fair value, except for ﬁxed rate long-term debt as noted below. The fair values of the Company’s other long-term liabilities and ﬁxed rate long-term debt are outlined below: Liability (1) Other long-term liabilities Fixed rate long-term debt (2) (3) (4) Liability (1) Other long-term liabilities Fixed rate long-term debt (2) (3) (4) Liability (1) Other long-term liabilities Fixed rate long-term debt (2) (3) (4) December 31, 2011 Carrying amount Fair value Level 1 Level 2 $ $ (274) $ (7,775) – $ (9,120) (8,049) $ (9,120) $ (274) – (274) December 31, 2010 Carrying amount Fair value Level 1 Level 2 $ $ (485) $ (7,049) – $ (7,835) (7,534) $ (7,835) $ (485) – (485) January 1, 2010 Carrying amount Fair value Level 1 Level 2 $ $ (325) $ (7,762) – $ (8,212) (8,087) $ (8,212) $ (325) – (325) (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) The carrying amounts of US$350 million of 5.45% notes due October 2012 and US$350 million of 4.90% notes due December 2014 have been adjusted by $31 million (December 31, 2010 – $47 million; January 1, 2010 – $39 million) to reﬂect the fair value impact of hedge accounting. (3) The fair value of ﬁxed rate long-term debt has been determined based on quoted market prices. (4) Includes the current portion of long-term debt. 2011 Annual Report 83 The following provides a summary of the carrying amounts of derivative contracts held and a reconciliation to the Company’s consolidated balance sheets. Asset (liability) Derivatives held for trading Crude oil price collars Crude oil put options Natural gas price collars Interest rate swaps Foreign currency forward contracts Cash ﬂow hedges Natural gas swaps Cross currency swaps Fair value hedges Interest rate swaps Included within: Current portion of other long-term liabilities Other long-term liabilities December 31 December 31 2010 2011 January 1 2010 $ $ $ $ (13) $ – – – (25) (64) $ (83) – – (20) – (236) (49) (269) – – (274) $ (485) $ (43) $ (231) (274) $ (222) $ (263) (485) $ (256) – 72 11 (9) – (158) 15 (325) (182) (143) (325) Ineffectiveness arising from cash ﬂow hedges recognized in net earnings for the year ended December 31, 2011 resulted in a loss of $2 million (December 31, 2010 – loss of $1 million). Risk Management 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) 2011 2010 Balance – beginning of year Net cost of outstanding put options Net change in fair value of outstanding derivative ﬁnancial instruments attributable to: $ (485) $ – Risk management activities Interest expense Foreign exchange Other comprehensive income Settlement of interest rate swaps and other Add: put premium ﬁnancing obligations (1) Balance – end of year Less: current portion 128 – 42 41 – (274) – (274) (43) $ (231) $ (325) 106 24 30 (101) (58) (55) (379) (106) (485) (222) (263) (1) The Company had negotiated payment of put option premiums with various counterparties at the time of actual settlement of the respective options. These obligations were reﬂected in the net risk management asset (liability). Net gains from risk management activities for the years ended December 31 were as follows: Net realized risk management loss (gain) Net unrealized risk management gain 2011 101 $ (128) (27) $ 2010 (110) (24) (134) $ $ 84 Canadian Natural 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, 2011, the Company had the following derivative ﬁnancial instruments outstanding to manage its commodity price risk: Sales contracts Crude oil (1) Crude oil price collars (2) Remaining term Volume Weighted average price Index Jan 2012 – Dec 2012 50,000 bbl/d US$80.00 – US$134.87 Brent (1) Subsequent to December 31, 2011, the Company entered into 50,000 bbl/d of US$80 WTI put options for the month of February 2012 for a total cost of US$3 million and 100,000 bbl/d of US$80 WTI put options for the period March to December 2012 for a total cost of US$62 million. (2) Subsequent to December 31, 2011, the Company entered into an additional 50,000 bbl/d of US$80-US$136.06 Brent collars for the period February to December 2012. During 2011, US$106 million of put option costs were settled. The Company’s outstanding commodity derivative ﬁnancial instruments are expected to be settled monthly based on the applicable index pricing for the respective contract month. 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. 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. During 2011, the Company unwound C$200 million of 1.4475% interest rate swaps with an original maturity of February 2012 for nominal consideration. At December 31, 2011, the Company had no interest rate swap contracts outstanding. Foreign currency exchange rate risk management The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long-term debt and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted in other currencies in its subsidiaries and in the carrying value of its foreign subsidiaries. The Company periodically enters into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on US dollar denominated long-term debt and working capital. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. At December 31, 2011, the Company had the following cross currency swap contracts outstanding: Cross currency Swaps (1) Remaining term Amount Exchange rate (US$/C$) Interest rate (US$) Interest rate (C$) Jan 2012 – Aug 2016 Jan 2012 – May 2017 Jan 2012 – Nov 2021 Jan 2012 – Mar 2038 US$250 US$1,100 US$500 US$550 1.116 1.170 1.022 1.170 6.00% 5.70% 3.45% 6.25% 5.40% 5.10% 3.96% 5.76% (1) The cross currency swaps that had been designated as cash ﬂow hedges of US $400 million of 6.70% debt securities were settled, resulting in a realized loss of $9 million. All cross currency swap derivative ﬁnancial instruments designated as hedges at December 31, 2011 were classiﬁed as cash ﬂow hedges. In addition to the cross currency swap contracts noted above, at December 31, 2011, the Company had US$2,043 million of foreign currency forward contracts outstanding, with terms of approximately 30 days or less. 2011 Annual Report 85 Financial instrument sensitivities The following table summarizes the annualized sensitivities of the Company’s net earnings and other comprehensive income to changes in the fair value of ﬁnancial instruments outstanding as at December 31, 2011, 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 cannot be linear. Commodity price risk Increase Brent US$1.00/bbl Decrease Brent US$1.00/bbl 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 b) Credit Risk Impact on other Impact on comprehensive income net earnings $ $ $ $ $ $ (4) $ 4 $ (5) $ 5 $ (22) $ 22 $ – – 16 (23) – – 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, 2011, 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 and other entities. At December 31, 2011, the Company had net risk management assets of $nil with speciﬁc counterparties related to derivative ﬁnancial instruments (December 31, 2010 – $nil; January 1, 2010 – $7 million). The carrying amount of ﬁnancial assets approximates the maximum credit exposure. c) Liquidity Risk Liquidity risk is the risk that the Company will encounter difﬁculty in meeting obligations associated with ﬁnancial liabilities. Management of liquidity risk requires the Company to maintain sufﬁcient cash and cash equivalents, along with other sources of capital, consisting primarily of cash ﬂow from operating activities, available credit facilities, and access to debt capital markets, to meet obligations as they become due. 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. 86 Canadian Natural The maturity dates for ﬁnancial liabilities are as follows: Accounts payable Accrued liabilities Risk management Other long-term liabilities Long-term debt (1) Less than 1 year 1 to less than 2 years 2 to less than 5 years Thereafter $ $ $ $ $ 526 2,347 43 28 356 $ $ $ $ $ – – 40 13 806 $ $ $ $ $ – – 120 34 2,316 $ $ $ $ $ – – 71 – 5,135 (1) Long-term debt represents principal repayments only and does not reﬂect fair value adjustments, original issue discounts or transaction costs. 18. Commitments and Contingencies The Company has committed to certain payments as follows: 2012 2013 2014 2015 2016 Thereafter Product transportation and pipeline Offshore equipment operating leases Ofﬁce leases Other $ $ $ $ 247 $ 118 $ 30 $ 288 $ 210 $ 101 $ 33 $ 158 $ 199 $ 100 $ 34 $ 88 $ 185 $ 82 $ 32 $ 24 $ 123 $ 53 $ 33 $ 2 $ 888 119 305 8 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. 19. Supplemental Disclosure of Cash Flow Information 2011 2010 Changes in non-cash working capital Accounts receivable (1) Inventory Prepaids and other Accounts payable Accrued liabilities Current income tax liabilities Net changes in non-cash working capital Relating to: Operating activities Financing activities Investing activities Expenditures on exploration and evaluation assets Expenditures on property, plant and equipment Net proceeds on sale of property, plant and equipment $ $ $ $ $ (198) $ (72) (17) 251 627 (83) 508 $ (36) $ (15) 559 508 $ 2011 312 $ 5,895 (6) Net expenditures on exploration and evaluation assets and property, plant and equipment $ 6,201 $ (1) Adjusted for the working capital impact of insurance recoveries related to property damage. (321) (35) 18 36 232 340 270 136 (12) 146 270 2010 572 4,771 (8) 5,335 2011 Annual Report 87 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 as the bitumen will be recovered through mining operations. Exploration and Production North America North Sea Offshore Africa 2011 2010 2011 2010 2011 2010 Segmented product sales Less: royalties $ Segmented revenue Segmented expenses Production Transportation and blending Depletion, depreciation and amortization Asset retirement obligation accretion Realized risk management activities Horizon asset impairment provision Insurance recovery – property damage (note 10) Insurance recovery – business interruption (note 10) 11,806 $ (1,538) 10,268 1,933 2,301 2,840 70 101 – – – 9,713 $ (1,267) 1,224 $ 1,058 $ (3) (2) 946 $ (114) 8,446 1,221 1,056 1,675 1,761 2,484 52 (110) – – – 412 13 249 33 – – – – 387 8 297 36 – – – – 832 186 1 242 7 – – – – 884 (62) 822 167 1 935 7 – – – – Total segmented expenses 7,245 5,862 707 728 436 1,110 Segmented earnings (loss) before the following $ 3,023 $ 2,584 $ 514 $ 328 $ 396 $ (288) Non–segmented expenses Administration Share-based compensation Interest and other ﬁnancing costs Unrealized risk management activities Foreign exchange loss (gain) Total non–segmented expenses Earnings before taxes Current income tax expense Deferred income tax expense Net earnings 88 Canadian Natural Midstream activities include the Company’s pipeline operations and an electricity co-generation system. Production activities that are not included in the above segments are reported in the segmented information as other. Inter-segment eliminations include internal transportation, electricity charges and natural gas sales. Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues 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 senior management. Oil Sands Mining and Upgrading Midstream Inter–segment elimination and other Total 2011 2010 2011 2010 2011 2010 2011 2010 $ 1,521 $ (60) 1,461 2,649 $ (90) 2,559 1,127 62 266 20 – 396 (393) (333) 1,145 1,208 61 396 28 – – – – 88 $ – 79 $ – 88 26 – 7 – – – – – 79 22 – 8 – – – – – (78) $ – (78) (13) (50) (61) $ – (61) (10) (48) – – – – – – – – – – – – 15,507 $ (1,715) 13,792 14,322 (1,421) 12,901 3,671 2,327 3,449 1,783 3,604 4,120 130 101 396 (393) (333) 123 (110) – – – 1,693 33 30 (63) (58) 9,503 9,365 $ 316 $ 866 $ 55 $ 49 $ (15) $ (3) 4,289 3,536 235 (102) 373 (128) 1 379 3,910 860 407 $ 2,643 $ 211 203 448 (24) (163) 675 2,861 789 399 1,673 2011 Annual Report 89 Capital Expenditures (1) 2011 2010 Non cash and fair value expenditures changes(2) Net Non cash and fair value Net costs expenditures changes(2) Capitalized Capitalized costs Exploration and evaluation assets Exploration and Production North America North Sea Offshore Africa Property, plant and equipment Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading (3) (4) Midstream Head ofﬁce $ $ $ 309 $ 1 2 312 $ (233) $ (6) – (239) $ 76 $ (5) 2 73 $ 563 $ 6 3 572 $ (299) $ – (154) (453) $ 264 6 (151) 119 4,427 $ 226 31 4,684 1,182 5 18 832 $ 15 16 863 (140) 2 – 5,259 $ 241 47 3,806 $ 143 246 5,547 1,042 7 18 4,195 543 7 18 896 $ 42 162 1,100 (132) – (11) $ 5,889 $ 725 $ 6,614 $ 4,763 $ 957 $ 4,702 185 408 5,295 411 7 7 5,720 (1) This table provides a reconciliation of capitalized costs and does not include the impact of accumulated depletion and depreciation. (2) 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. (3) Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest, share-based compensation, and the impact of intersegment eliminations. (4) During 2011, the Company derecognized certain property, plant and equipment related to the coker ﬁre at Horizon in the amount of $411 million. This amount has been included in non cash and fair value changes. $ 2011 2010 28,554 $ 1,809 1,070 23 15,433 321 68 25,486 1,759 1,263 15 14,026 338 67 $ 47,278 $ 42,954 Segmented Assets Exploration and Production North America North Sea Offshore Africa Other Oil Sands Mining and Upgrading Midstream Head ofﬁce 90 Canadian Natural 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 2011 2010 $ 2 $ 2 2011 2010 $ 2 $ 18 2 8 – $ 30 $ 2 30 3 16 2 53 (1) Senior management identiﬁed above are consistent with the disclosure on Named Executive Ofﬁcers provided in the Company’s Information Circular to shareholders. 22. Transition to IFRS The effect of the Company’s transition to IFRS, described in note 1, is summarized below: (i) Transition elections The Company has applied the following transition exceptions and exemptions to full retrospective application of IFRS as described below: Deemed cost of property, plant and equipment Leases Share-based compensation Borrowing costs Asset retirement obligations Cumulative translation adjustment Business combinations (ii) Transition adjustments The Company has recorded the following transition adjustments upon adoption of IFRS: Risk management Petroleum Revenue Tax UK deferred income tax liabilities Reclassiﬁcation of current portion of deferred income tax Horizon major maintenance costs Long-term debt Note (A) (B) (C) (D) (E) (F) (G) Note (H) (I) (J) (K) (L) (M) 2011 Annual Report 91 Reconciliations of the Consolidated Balance Sheets (millions of Canadian dollars) December 31, 2010 January 1, 2010 Canadian GAAP Note Adj IFRS Canadian GAAP Adj IFRS ASSETS Current assets Cash and cash equivalents Accounts receivable Inventory Prepaids and other Deferred income tax assets $ 22 $ 1,481 481 129 59 (A) (K) – $ – (4) – (59) 1,481 477 129 – Exploration and evaluation assets Property, plant and equipment Other long-term assets 2,172 – (A) (A)(C)(E)(L) 40,472 25 (63) 2,109 2,402 2,402 (2,043) 38,429 14 (11) 1,148 438 146 146 1,891 – 39,115 18 22 $ 13 $ – $ – – – (146) 13 1,148 438 146 – (146) 1,745 2,293 2,293 (2,097) 37,018 6 (12) $ 42,669 $ 285 $ 42,954 $ 41,024 $ 38 $ 41,062 LIABILITIES Current liabilities Accounts payable Accrued liabilities Current income tax liabilities Current portion of long-term debt Current portion of other long-term liabilities Long-term debt Other long-term liabilities Deferred income tax liabilities (H)(M) (C)(E)(H) (I)(J)(K) $ 274 $ (M) (C) 1,733 430 – 719 3,156 8,499 2,130 7,899 – $ 2 – 397 151 550 (411) 874 (111) 274 $ 240 $ 1,735 430 397 870 3,706 8,088 3,004 7,788 1,428 94 – 643 2,405 9,658 1,848 7,687 – $ 2 – 400 211 613 (399) 637 (225) 240 1,430 94 400 854 3,018 9,259 2,485 7,462 SHAREHOLDERS’ EQUITY Share capital Retained earnings Accumulated other comprehensive 21,684 902 22,586 21,598 626 22,224 3,147 18,005 – 3,147 (793) 17,212 2,834 16,696 – 2,834 (769) 15,927 (loss) income (F)(H) (167) 176 9 (104) 181 77 20,985 (617) 20,368 19,426 (588) 18,838 $ 42,669 $ 285 $ 42,954 $ 41,024 $ 38 $ 41,062 92 Canadian Natural Reconciliation of the Consolidated Statements of Earnings For the year ended December 31 (millions of Canadian dollars, except per common share amounts) 2010 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 costs Risk management activities Foreign exchange gain Earnings before taxes Taxes other than income tax Current income tax expense Deferred income tax expense Net earnings Net earnings per common share Basic Diluted Note $ Canadian GAAP $ 14,322 (1,421) 12,901 (A) (A)(E)(L) (A) (C) (E) (H) (H) (J) (I)(J) $ $ $ 3,447 1,783 4,036 210 294 107 449 (121) (182) 10,023 2,878 119 698 364 1,697 1.56 1.56 $ $ $ $ Adj – – – 2 – 84 1 (91) 16 (1) (13) 19 17 (17) (119) 91 35 (24) $ IFRS 14,322 (1,421) 12,901 3,449 1,783 4,120 211 203 123 448 (134) (163) 10,040 2,861 – 789 399 1,673 (0.02) (0.03) $ $ 1.54 1.53 Reconciliation of the Consolidated Statements of Comprehensive Income For the year ended December 31 (millions of Canadian dollars) 2010 Note Canadian GAAP Adj Net earnings $ 1,697 $ (24) $ (H) Net change in derivative ﬁnancial instruments designated as cash ﬂow hedges Unrealized loss Income tax Unrealized loss, net of tax Reclassiﬁcation to net earnings Income tax Reclassiﬁcation to net earnings, net of taxes Foreign currency translation adjustment Translation of net investment Other comprehensive loss, net of taxes Comprehensive income (35) 11 (24) (5) 1 (4) (28) (35) (63) (18) 2 (16) – – – (16) 11 (5) IFRS 1,673 (53) 13 (40) (5) 1 (4) (44) (24) (68) $ 1,634 $ (29) $ 1,605 2011 Annual Report 93 Notes: (A) Deemed cost of property, plant and equipment In accordance with IFRS transitional provisions, the Company elected to use the deemed cost of property, plant and equipment for its exploration and production assets, which allowed the Company to measure its exploration and evaluation assets at the amounts capitalized under Canadian GAAP at the date of transition to IFRS. Additionally, under the transitional provision, the Company elected to allocate the carrying amount of property, plant and equipment in the development or production phases under Canadian GAAP to IFRS applicable assets pro rata using proved reserve values as at January 1, 2010, subject to impairment tests. The impairment tests compared the carrying amount of the assets to their recoverable amounts. The recoverable amount is the higher of fair value less costs to sell or value in use. The impairment tests conducted by the Company at the date of transition resulted in a $62 million reduction to the carrying amount of property, plant and equipment in the Gabon CGU in Offshore Africa. At January 1, 2010, retained earnings were reduced by $53 million, net of income taxes of $9 million. For the year ended December 31, 2010, net earnings decreased by $119 million, net of taxes of $27 million, to reﬂect the impact of higher depletion charges, partially offset by $78 million, net of taxes of $11 million, to reﬂect the impact of a lower impairment charge on the Gabon CGU in Offshore Africa. (B) Leases The Company elected under IFRS 1 not to reassess whether an arrangement contains a lease under IFRIC 4 for contracts that were assessed under Canadian GAAP. Arrangements entered into before the effective date of Canadian GAAP Emerging Issues Committee (“EIC”) 150 that had not subsequently been assessed under EIC 150, were assessed under IFRIC 4, and no additional leases were identiﬁed. (C) Share-based compensation The Company has granted stock options to all employees, which may be settled in either cash or shares at the holder’s option. The Company accounted for these stock options by reference to their intrinsic value under Canadian GAAP. Under IFRS, the related liability has been adjusted to reﬂect the fair value of the outstanding share-based compensation. The Company elected to use the IFRS 1 exemption to not retrospectively restate stock option transactions that were settled before the date of transition to IFRS. This adjustment increased the share-based compensation liability by $230 million (December 31, 2010 – $147 million). Included in this amount was $11 million (December 31, 2010 – $19 million) capitalized to Oil Sands Mining and Upgrading. At January 1, 2010, retained earnings were reduced by $170 million, net of income taxes of $49 million. For the year ended December 31, 2010, net earnings increased by $91 million to reﬂect differences in share-based compensation expense. In addition, during the year ended December 31, 2010, deferred income tax expense included an additional charge of $49 million related to the change to the taxation of stock options surrendered by employees for cash. (D) Borrowing costs Under Canadian GAAP, the Company was not required to capitalize all borrowing costs in respect of constructed assets. At the date of transition, the Company elected to capitalize borrowing costs in respect of all qualifying assets effective January 1, 2010. (E) Asset retirement obligations In accordance with IFRS transitional provisions for assets described in (A) above, the Company remeasured the liability associated with asset retirement obligation activities for the North America, North Sea and Offshore Africa Exploration and Production segments at the date of transition, resulting in an increase in asset retirement obligations of $338 million. At January 1, 2010, retained earnings were reduced by $210 million, net of income taxes of $128 million. In addition, the Company remeasured the liability related to asset retirement obligation activities in the Oil Sands Mining and Upgrading segment at the date of transition. These assets were not subject to the election in (A) above and accordingly, the difference in the liability between Canadian GAAP and IFRS of $266 million was recognized in property, plant and equipment in accordance with IFRS transitional provisions. Additional accumulated depletion of $2 million was recognized in retained earnings. The difference between Canadian GAAP and IFRS asset retirement obligations related primarily to the method of applying discount rates. As at December 31, 2010, an additional liability of $234 million was recognized in property, plant and equipment. For the year ended December 31, 2010, net earnings decreased by $15 million, net of taxes of $6 million, to reﬂect the impact of higher depletion and accretion charges. 94 Canadian Natural (F) Cumulative translation adjustment In accordance with IFRS transitional provisions, the Company elected to reset the cumulative translation adjustment account, which includes gains and losses arising from the translation of foreign operations, to $nil at the date of transition to IFRS. Accordingly, accumulated other comprehensive income increased by $180 million and retained earnings were reduced by $180 million. (G) Business combinations In accordance with IFRS transitional provisions, the Company elected to apply IFRS relating to business combinations prospectively from January 1, 2010. As such, Canadian GAAP balances relating to business combinations entered into before that date have been carried forward without adjustment. (H) Risk management Under Canadian GAAP, the Company was required to adjust the carrying amount of the liability for risk management derivative ﬁnancial instruments by the Company’s own credit risk. Under IFRS, this adjustment is not required. The reversal of the credit risk adjustment for IFRS on January 1, 2010 resulted in an increase in the carrying amount of the risk management liability of $16 million (December 31, 2010 – increase of $34 million) and an increase in accumulated comprehensive income of $1 million (December 31, 2010 – decrease of $15 million). At January 1, 2010, retained earnings were reduced by $13 million, net of income taxes of $5 million. Further, differences in applying fair value hedge accounting between Canadian GAAP and IFRS resulted in an increase to the carrying value of hedged long-term debt by $1 million (December 31, 2010 – decrease of $14 million). For the year ended December 31, 2010, net earnings increased by $10 million, net of income taxes of $4 million and other comprehensive income decreased by $16 million, net of income taxes of $2 million. (I) Petroleum Revenue Tax Under Canadian GAAP, the Company calculated its deferred PRT liability using the life-of-ﬁeld method. Under IFRS, the Company calculates its deferred PRT liability based on temporary differences arising between the tax base of assets and liabilities of PRT paying ﬁelds and their carrying amounts in the consolidated balance sheets. As a result of this adjustment, the deferred income tax liability was increased by $116 million ($58 million after-tax) at January 1, 2010 (December 31, 2010 – $80 million, $40 million after-tax). At January 1, 2010, retained earnings were reduced by $58 million. For the year ended December 31, 2010, net earnings increased by $18 million, net of taxes of $18 million, to reﬂect the impact of lower PRT charges. (J) UK deferred income tax liabilities Under Canadian GAAP, the Company calculated the future income tax liabilities of its UK subsidiaries in UK pounds sterling, and converted the resultant liability to its US dollar functional currency. Under IFRS, the Company calculates its UK-based deferred income tax liabilities directly in the functional US dollar currency. This adjustment resulted in an increase in the deferred income tax liability of $61 million at January 1, 2010 (December 31, 2010 – $80 million). At January 1, 2010, retained earnings were reduced by $61 million. For the year ended December 31, 2010, net earnings decreased by $19 million. (K) Reclassiﬁcation of current portion of deferred income tax Under Canadian GAAP, deferred income tax relating to current assets or current liabilities were classiﬁed as current. Under IFRS, deferred income tax balances are classiﬁed as long-term, irrespective of the classiﬁcation of the assets or liabilities to which the deferred income tax relates or the expected timing of reversal. Accordingly, current deferred income tax assets reported under Canadian GAAP of $146 million at January 1, 2010 (December 31, 2010 – current deferred income tax assets of $59 million) were reclassiﬁed as non-current under IFRS. (L) Horizon major maintenance costs Under Canadian GAAP, the Company would have deferred and amortized major maintenance turnaround costs on a straight-line basis over the period to the next scheduled major maintenance turnaround. Under IFRS, the Company has identiﬁed capitalized components of the original cost of an asset, which have a shorter useful life, and has amortized the costs of these components over the period to the next turnaround. At January 1, 2010, retained earnings decreased by $14 million, net of taxes of $5 million. For the year ended December 31, 2010, net earnings decreased by $19 million, net of taxes of $6 million, to reﬂect the impact of higher depletion charges. 2011 Annual Report 95 (M) Long-term debt Under Canadian GAAP, debt maturities within one year of the date of the balance sheet were classiﬁed as non-current on the basis that the Company had the intent and ability to reﬁnance these obligations with its existing long-term credit facilities. Under IFRS, as the long-term debt maturing within one year was not payable to the same counterparty lenders as the long-term debt facility, $400 million was reclassiﬁed to current at January 1, 2010 (December 31, 2010 – $397 million). Deferred income tax liabilities have been adjusted to give effect to adjustments as follows: Asset (liability) Deferred income tax assets as reported under Canadian GAAP Deferred income tax liabilities as reported under Canadian GAAP Deferred income tax, net IFRS adjustments Deemed cost of property, plant and equipment Share-based compensation Asset retirement obligations Risk management PRT UK deferred income tax liabilities Horizon maintenance costs Foreign exchange and other December 31 2010 Note January 1 2010 $ 59 $ (7,899) (7,840) 146 (7,687) (7,541) (A) (C) (E) (H) (I) (J) (L) 25 – 134 3 (40) (80) 11 (1) 9 49 128 5 (58) (61) 5 2 Deferred income tax liabilities as reported under IFRS $ (7,788) $ (7,462) The following is a summary of transition adjustments, net of tax, to the Company’s accumulated other comprehensive income from Canadian GAAP to IFRS: Accumulated other comprehensive income as reported under Canadian GAAP IFRS adjustments Cumulative translation adjustment on transition Risk management Translation of net investment Accumulated other comprehensive income as reported under IFRS $ 9 $ December 31 2010 Note January 1 2010 $ (167) $ (104) (F) (H) 180 (15) 11 180 1 – 77 The following is a summary of transition adjustments, net of tax, to the Company’s retained earnings from Canadian GAAP to IFRS: Retained earnings as reported under Canadian GAAP IFRS adjustments Deemed cost of property, plant and equipment Share-based compensation Asset retirement obligations Cumulative translation adjustment Risk management PRT UK deferred income tax liabilities Horizon maintenance costs Other December 31 2010 Note January 1 2010 $ 18,005 $ 16,696 (A) (C) (E) (F) (H) (I) (J) (L) (94) (128) (227) (180) (3) (40) (80) (33) (8) (53) (170) (212) (180) (13) (58) (61) (14) (8) Retained earnings as reported under IFRS $ 17,212 $ 15,927 Adjustments to the statements of cash ﬂows The transition from Canadian GAAP to IFRS had no signiﬁcant impact on cash ﬂows generated by the Company. 96 Canadian Natural Supplementary Oil and 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”). In addition, comparative ﬁnancial information for 2010 has been restated from generally accepted accounting principles in the United States to reﬂect the adoption of IFRS. For the years ended December 31, 2011 and 2010, 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. For years prior to 2010, the Company was granted an exemption from certain provisions of NI 51-101 allowing the Company to substitute SEC requirements under Regulations S-K and S-X for certain disclosures required under NI 51-101. Such exemption expired on December 31, 2010. There are signiﬁcant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the 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, 2011 and 2010, 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 2011 reserves for SEC requirements. Crude Oil and NGLs WTI Cushing Oklahoma (US$/bbl) WCS (C$/bbl) Edmonton Par North Sea Brent Edmonton C5+ Henry Hub Louisiana BC Westcoast Station 2 AECO (C$/bbl) (US$/bbl) (C$/bbl) (US$/MMbtu) (C$/MMbtu) (C$/MMbtu) Natural Gas 96.19 77.74 96.03 110.96 104.60 4.12 3.77 3.33 A foreign exchange rate of US$1.0158/C$1.00 was used in the 2011 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 and natural gas reserves. For the years ended December 31, 2011, 2010, 2009 and 2008, the reports by GLJ Petroleum Consultants Ltd. (“GLJ”) covered 100% of the Company’s synthetic crude oil 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 (“Final Rule”), 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, 2011, 2010, 2009 and 2008, the reports by Sproule Associates Limited and Sproule International Limited (together as “Sproule”) covered 100% of the Company’s bitumen, crude oil and natural gas liquids and natural gas reserves. Proved crude oil and natural gas reserves, as deﬁned within the SEC’s Regulation S-X under the Final Rule, are the estimated quantities of oil and gas that 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. Proved developed reserves are reserves 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. 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. 2011 Annual Report 97 The following table summarizes the Company’s proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2011, 2010, 2009, and 2008: Crude Oil & NGLs (MMbbl) Net Proved Reserves Reserves, December 31, 2008 Extensions and discoveries Improved recovery SEC reliable technology (3) SEC rule transition (4) Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2009 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, 2010 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, 2011 Net proved developed reserves December 31, 2008 December 31, 2009 December 31, 2010 December 31, 2011 North America Synthetic Crude Oil (1) Crude Oil and Bitumen (2) NGLs North America Total North Offshore Africa Sea – – – – 1,650 – – – – – 1,650 – – – – (32) (41) 86 1,663 – – – – (14) 18 169 1,836 690 24 8 7 – – – (49) (64) 79 695 55 22 92 – (54) (25) 93 878 78 10 – – (60) (32) (5) 869 258 6 75 – – 1 – (24) (8) 11 319 9 6 15 – (26) – 5 328 28 8 6 – (28) 1 23 948 30 83 7 1,650 1 – (73) (72) 90 2,664 64 28 107 – (112) (66) 184 2,869 106 18 6 – (102) (13) 187 366 3,071 1,589 1,546 1,588 268 262 269 204 240 269 428 2,061 2,048 2,126 256 – – – – – – (14) 57 (59) 240 – – – – (12) 28 1 257 – – – – (11) 26 (28) 244 97 94 94 78 142 – – – – – – (11) (4) (4) 123 – – – – (10) – (11) 102 – 2 – – (8) – (8) 88 107 106 83 61 Total 1,346 30 83 7 1,650 1 – (98) (19) 27 3,027 64 28 107 – (134) (38) 174 3,228 106 20 6 – (121) 13 151 3,403 632 2,261 2,225 2,265 (1) Prior to December 31, 2009, the Company’s Oil Sands Mining and Upgrading 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. (2) Bitumen as deﬁned by the SEC under the Final Rule, “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 oil reserves have been classiﬁed as bitumen. Prior to December 31, 2009, these reserves would have been classiﬁed within the Company’s conventional crude oil and NGL totals. (3) SEC reliable technology accounts for reserves volumes added due to the reserves rule changes. (4) For continuity purposes, with respect to the transition from Industry Guide 7 to the SEC’s Final Rule, the following SCO table has been provided to illustrate the changes in the Company’s Oil Sands Mining and Upgrading SCO reserves for the 2009 year. Oil Sands Mining and Upgrading SCO Reserves Net proved (MMbbl) Reserves, December 31, 2008 Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2009 98 Canadian Natural 1,946 (18) (307) 29 1,650 Natural Gas (Bcf) Net Proved Reserves Reserves, December 31, 2008 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, 2009 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, 2010 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, 2011 Net proved developed reserves December 31, 2008 December 31, 2009 December 31, 2010 December 31, 2011 North America North Sea Offshore Africa 3,523 92 11 15 (6) (443) (335) 170 3,027 249 19 364 – (426) 105 83 3,421 154 48 375 (1) (433) (104) 39 3,499 2,690 2,333 2,557 2,637 67 – – – – (4) 12 (8) 67 – – – – (4) 6 9 78 – – – – (2) 3 18 97 45 45 49 60 94 – – – – (6) (4) 1 85 – – – – (5) – (4) 76 – – – – (6) – (16) 54 89 81 72 47 Capitalized Costs Related to Crude Oil and Natural Gas Activities (millions of Canadian dollars) Proved properties Unproved properties $ Less: accumulated depletion and depreciation North America 61,331 2,442 63,773 (22,497) $ 2011 North Sea 4,147 – 4,147 (2,512) $ Offshore Africa (1) $ 3,044 33 3,077 (2,152) Net capitalized costs $ 41,276 $ 1,635 $ 925 $ (millions of Canadian dollars) Proved properties Unproved properties $ Less: accumulated depletion and depreciation North America 55,030 2,366 57,396 (19,502) $ 2010(2) North Sea 3,813 5 3,818 (2,205) $ Offshore Africa (1) 2,928 31 2,959 (1,904) $ Net capitalized costs $ 37,894 $ 1,613 $ 1,055 $ (1) As at December 31, 2011 and 2010, the Company’s Other segment has been included in Offshore Africa. (2) Comparative amounts for 2010 have been restated to reﬂect the adoption of IFRS. Total 3,684 92 11 15 (6) (453) (327) 163 3,179 249 19 364 – (435) 111 88 3,575 154 48 375 (1) (441) (101) 41 3,650 2,824 2,459 2,678 2,744 Total 68,522 2,475 70,997 (27,161) 43,836 Total 61,771 2,402 64,173 (23,611) 40,562 2011 Annual Report 99 Costs Incurred in Crude Oil and Natural Gas Activities (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred 2011 North America North Sea Offshore Africa (1) $ $ $ $ 1,012 59 250 5,559 6,880 North America 1,482 522 41 3,332 5,377 $ $ $ $ – – 1 235 236 $ $ 2010(2) – – 2 76 78 North Sea Offshore Africa (1) – – 6 190 196 $ $ – – 3 254 257 $ $ $ $ Total 1,012 59 253 5,870 7,194 Total 1,482 522 50 3,776 5,830 (1) As at December 31, 2011 and 2010, the Company’s Other segment has been included in Offshore Africa. (2) Comparative amounts for 2010 have been restated to reﬂect the adoption of IFRS. 100 Canadian Natural 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, 2011 and 2010 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 Asset retirement obligation accretion Petroleum revenue tax Income tax 2011 North America North Sea Offshore Africa $ 9,600 (3,060) (374) (3,488) (90) – (688) $ 1,206 (412) (13) (248) (33) (130) (218) $ 828 (186) (1) (242) (7) – (89) Results of operations $ 1,900 $ 152 $ 303 $ (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 $ North America 9,687 (2,883) (365) (2,869) (80) – (980) 2010(2) $ North Sea 1,059 (387) (8) (295) (36) (59) (137) Results of operations $ 2,510 $ 137 $ (1) Includes the impact of an impairment relating to Gabon, Offshore Africa at December 31, 2010 of $637 million. (2) Comparative amounts for 2010 have been restated to reﬂect the adoption of IFRS. Offshore Africa 821 (167) (1) (935) (7) – 146 (143) $ $ Total 11,634 (3,658) (388) (3,978) (130) (130) (995) 2,355 Total 11,567 (3,437) (374) (4,099) (123) (59) (971) 2,504 2011 Annual Report 101 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 2011 North America North Sea Offshore Africa Total 280,809 (109,586) $ 26,887 (8,908) $ 8,257 (2,058) $ 315,953 (120,552) (37,486) (23,100) 110,637 (75,438) (6,821) (8,095) 3,063 (1,376) (1,669) (1,070) 3,460 (1,623) Standardized measure of future net cash ﬂows $ 35,199 $ 1,687 $ 1,837 $ (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 2010 North America North Sea Offshore Africa Total 221,337 (96,899) $ 21,117 (8,596) $ 8,268 (1,884) $ 250,722 (107,379) (35,424) (17,249) 71,765 (47,687) (5,448) (5,572) 1,501 (722) (688) (1,760) 3,936 (1,906) Standardized measure of future net cash ﬂows $ 24,078 $ 779 $ 2,030 $ 102 Canadian Natural (45,976) (32,265) 117,160 (78,437) 38,723 (41,560) (24,581) 77,202 (50,315) 26,887 (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 2009 North America North Sea Offshore Africa Total 176,866 (88,134) $ 16,304 (6,929) $ 8,305 (3,255) $ 201,475 (98,318) (22,767) (11,237) 54,728 (35,526) (5,271) (3,487) 617 (275) (975) (1,229) 2,846 (1,345) (29,013) (15,953) 58,191 (37,146) 21,045 Standardized measure of future net cash ﬂows $ 19,202 $ 342 $ 1,501 $ 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) 2011 2010 2009 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 SEC reliable technology SEC rule transition Changes in production timing and other Net change in income taxes Net change Balance – beginning of year Balance – end of year $ (7,727) $ 15,802 1,328 (2,022) 803 – 4,154 3,648 – – (1,141) (3,009) 11,836 26,887 (7,641) $ 14,748 1,636 (5,208) 1,894 – 2,567 2,757 – – (895) (4,016) 5,842 21,045 $ 38,723 $ 26,887 $ (5,437) 16,808 4,222 (2,752) 53 (7) 220 1,375 254 7,332 (2,788) (8,622) 10,658 10,387 21,045 2011 Annual Report 103 Ten-year review Years ended December 31 2011 2010 (6) 2009 (7) 2008 (7) 2007 (7) 2006 (7) 2005 (7) 2004 (7) 2003 (7) 2002 (7) 1,580 1,673 FINANCIAL INFORMATION (1) (Cdn $ millions, except per share amounts) 2,643 Net earnings $ Per share - basic Per share - diluted $ Cash ﬂow from operations (2) 5.98 $ $ Per share - basic Per share - diluted 5.94 $ $ Capital expenditures, net of dispositions (including business combinations) 7,451 5.62 $ 5.62 $ 1.54 $ 1.53 $ 5.82 $ 5.78 $ 2.41 $ 2.40 $ 1.46 $ 1.46 $ 6,547 6,333 6,090 6,969 5,514 6,414 2,997 4,985 4.61 $ 4.61 $ 6.45 $ 6.45 $ 2,608 2,524 1,050 1,405 1,403 2.42 $ 2.42 $ 2.35 $ 2.35 $ 0.98 $ 0.98 $ 1.31 $ 1.30 $ 1.31 $ 1.27 $ 6,198 4,932 5,021 3,769 3,160 5.75 $ 5.75 $ 4.59 $ 4.59 $ 4.68 $ 4.67 $ 3.52 $ 3.49 $ 2.94 $ 2.88 $ 539 0.53 0.51 2,254 2.21 2.13 6,425 12,025 4,932 4,633 2,506 4,069 Balance sheet information Working capital surplus (deﬁciency) Exploration and evaluation assets 2,475 2,402 - - - - - - - - (894) (1,200) (514) (28) (1,382) (832) (1,774) (652) (505) (14) Property, plant and equipment, net 41,631 47,278 8,571 22,898 Total assets Long-term debt Shareholders’ equity SHARE INFORMATION (1) Common shares outstanding (thousands) 38,429 42,954 8,485 20,368 39,115 41,024 9,658 19,426 38,966 42,650 12,596 18,374 33,902 36,114 10,940 13,321 30,767 33,160 11,043 10,690 19,694 21,852 3,321 8,237 17,064 18,372 3,538 7,324 13,714 14,643 2,748 6,006 12,934 13,793 4,200 4,754 1,096,460 1,090,848 1,084,654 1,081,982 1,079,458 1,075,806 1,072,696 1,072,722 1,069,852 1,070,208 Weighted average shares outstanding - basic (thousands) Weighted average shares outstanding - diluted (thousands) 1,095,582 1,088,096 1,083,850 1,081,294 1,078,672 1,074,678 1,073,300 1,072,446 1,073,880 1,023,064 1,102,582 1,095,648 1,083,850 1,081,294 1,078,672 1,074,678 1,076,850 1,081,368 1,099,290 1,066,464 Dividends declared per common share $ 0.36 $ 0.30 $ 0.21 $ 0.20 $ 0.17 $ 0.15 $ 0.12 $ 0.10 $ 0.08 $ 0.07 1,040,320 1,359,476 858,068 1,017,870 1,275,984 1,212,048 1,181,404 1,238,632 661,832 800,044 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 shareholders’ equity, after tax (3) 937,481 759,327 27% 29% $ 50.50 $ 45.00 $ 39.50 $ 55.65 $ 40.01 $ 36.96 $ 31.00 $ 13.79 $ 7.98 $ $ 27.25 $ 31.97 $ 17.93 $ 17.10 $ 26.23 $ 22.75 $ 12.14 $ $ 38.15 $ 44.35 $ 38.00 $ 24.38 $ 36.29 $ 31.08 $ 28.82 $ 12.82 $ 8.41 $ 5.65 $ 8.17 $ 6.82 4.70 5.85 1,514,614 1,934,456 972,532 803,818 503,108 250,936 93,832 63,728 $ 52.04 $ 44.77 $ 38.26 $ 54.66 $ 43.59 $ 32.19 $ 27.03 $ 11.19 $ $ 25.69 $ 30.00 $ 13.85 $ 13.22 $ 22.28 $ 20.15 $ 5.97 $ $ 37.37 $ 44.42 $ 35.98 $ 19.99 $ 36.57 $ 26.62 $ 24.81 $ 10.70 $ 9.87 $ 6.43 $ 3.66 $ 6.31 $ 4.36 2.95 3.71 33% 41% 45% 51% 29% 34% 33% 47% Daily production before royalties per ten thousand common shares (BOE/d) (1) 12% 8% 8% 33% 22% 27% 14% 21% 26% 13% 5.3 Total proved plus probable reserves per common share (BOE) (1)(4) 5.8 5.5 6.3 5.8 6.9 Net asset value per common share (1)(5) 5.2 3.1 5.7 3.2 5.4 3.2 5.2 2.4 4.8 2.2 4.3 2.0 4.1 1.7 $ 70.37 $ 64.58 $ 64.92 $ 39.89 $ 34.47 $ 28.21 $ 30.22 $ 16.57 $ 11.68 $ 9.79 (1) Restated to reﬂect two-for-one share splits in May 2010, May 2004 and May 2005. (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) Calculated as the net present value of future net revenue of the Company’s total proved plus probable reserves prepared using forecast prices and costs discounted at 10%, as reported in the Company’s AIF, with $300/acre added for core unproved property ($250/acre for core undeveloped land from 2005 to 2009, $75/acre for core undeveloped land for all years prior to 2005), less net debt and using year end common shares outstanding. Net debt is the Company’s long-term debt plus/minus the working capital deﬁcit/surplus. Excludes Horizon SCO reserves prior to 2009. Future development costs and associated material well abandonment costs 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. 104 Canadian Natural Years ended December 31 2011 2010 (6) 2009 2008 2007 2006 2005 2004 2003 2002 OPERATING INFORMATION Crude oil and NGLs (MMbbl) (8) Company net proved reserves (after royalties) North America North Sea Offshore Africa Horizon SCO (8) Company net proved plus probable reserves (after royalties) North America North Sea Offshore Africa Horizon SCO (8) Natural gas (Bcf) (8) Company net proved reserves (after royalties) North America North Sea Offshore Africa 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 5,049 694 290 134 1,118 1,626 1,035 417 206 1,658 2,566 2,741 29 72 2,842 3,548 69 110 3,727 648 303 115 1,066 - 926 415 196 1,537 - 2,591 27 72 2,690 3,319 57 90 3,466 588 222 85 895 - 857 317 133 1,307 - 2,426 62 64 2,552 2,919 102 72 3,093 571 202 75 848 - 636 277 121 1,034 - 2,446 71 71 2,588 2,765 89 90 2,944 Company net proved plus probable reserves (after royalties) North America North Sea Offshore Africa Total proved reserves (after royalties) (MMBOE) Total proved plus probable reserves (after royalties) (MMBOE) 3,977 3,748 3,557 1,960 1,969 1,949 1,592 1,514 1,320 1,279 6,147 5,666 5,440 2,996 2,937 2,961 2,279 2,115 1,823 1,525 Daily production (before royalties) Crude oil and NGLs (Mbbl/d) North America - Exploration and Production North America - Oil Sands Mining and Upgrading 296 271 234 244 247 235 222 206 175 169 North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa 40 30 23 389 1,231 7 19 1,257 91 33 30 425 1,217 10 16 1,243 50 38 33 355 1,287 10 18 1,315 - 45 27 316 1,472 10 13 1,495 - 56 28 331 1,643 13 12 1,668 - 60 37 332 1,468 15 9 1,492 - 68 23 313 1,416 19 4 1,439 - 65 12 283 1,330 50 8 1,388 - 57 10 242 1,245 46 8 1,299 - 39 7 215 1,204 27 1 1,232 Total production (before royalties) (MBOE/d) 599 632 575 565 609 581 553 514 459 421 Product Pricing Average crude oil and NGLs price ($/bbl) 77.46 65.81 57.68 82.41 55.45 53.65 46.86 37.99 32.66 31.22 Average natural gas price ($/Mcf) Average SCO price ($/bbl) 3.73 99.74 4.08 77.89 4.53 70.83 8.39 - 6.85 - 6.72 - 8.57 - 6.50 - 6.21 - 3.77 - (8) 2011 and 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. 2011 Annual Report 105 Board of Directors Management Committee *Catherine M. Best, FCA, ICD.D (1)(2) Corporate Director Calgary, Alberta N. Murray Edwards (5) President, Edco Financial Holdings Ltd. Calgary, Alberta *Timothy W. Faithfull (1)(3) Corporate Director Oxford, England *Honourable Gary A. Filmon, P.C., OC., O.M. (1)(4) Consultant, The Exchange Group Winnipeg, Manitoba *Christopher L. Fong (3)(5) Corporate Director Calgary, Alberta *Ambassador Gordon D. Gifﬁn (1)(4) Senior Partner, McKenna Long & Aldridge LLP Atlanta, Georgia *Wilfred A. Gobert (2)(4) Corporate Director Calgary, Alberta Steve W. Laut President, Canadian Natural Resources Limited Calgary, Alberta Keith A. J. MacPhail (3)(5) Chairman & Chief Executive Ofﬁcer, Bonavista Energy Corporation Calgary, Alberta Allan P. Markin, OC., A.O.E. (3) Chairman of the Board, Canadian Natural Resources Limited Calgary, Alberta *Honourable Frank J. McKenna, P.C., OC., O.N.B., Q.C. (2)(4) Deputy Chair, TD Bank Group Cap Pelé, New Brunswick *James S. Palmer, C.M., A.O.E., Q.C. (5) Chairman Emeritus & Partner, Burnet, Duckworth & Palmer LLP Calgary, Alberta *Dr. Eldon R. Smith, OC., M.D. (2)(3) President of Eldon R. Smith & Associates Ltd. Emeritus Professor of Medicine and Former Dean, Faculty of Medicine, University of Calgary Calgary, Alberta *David A. Tuer (1)(5) Vice-Chairman & Chief Executive Ofﬁcer, Teine Energy Ltd. Calgary, Alberta 106 Canadian Natural Allan P. Markin Chairman of the Board N. Murray Edwards Vice-Chairman John G. Langille Vice-Chairman Steve W. Laut President Tim S. McKay Chief Operating Ofﬁcer Douglas A. Proll Chief Financial Ofﬁcer & Senior Vice-President, Finance Réal M. Cusson Senior Vice-President, Marketing Réal J.H. Doucet Senior Vice-President, Horizon Projects Peter J. Janson Senior Vice-President, Horizon Operations Terry J. Jocksch Senior Vice-President, Thermal & International Allen M. Knight Senior Vice-President, International & Corporate Development Bill R. Peterson Senior Vice-President, Production, Drilling & Completions Scott G. Stauth Senior Vice-President, Operations Field, Facilities & Pipelines Lyle G. Stevens Senior Vice-President, Exploitation Jeff W. Wilson Senior Vice-President, Exploration Corey B. Bieber Vice-President, Finance & Investor Relations Mary-Jo E. Case Vice-President, Land Randall S. Davis Vice-President, Finance & Accounting (1) Audit Committee member (2) Compensation Committee member (3) Health, Safety and Environmental Committee member (4) Nominating and Corporate Governance Committee member (5) Reserves Committee member * Determined to be independent by the Nominating and Corporate Governance 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. 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 share bonus plan pursuant to which common shares are purchased through the TSX. This is not a new issue of securities under the share bonus 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 2011 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. Corporate Ofﬁces Head Ofﬁce Company Deﬁnition Canadian Natural Resources Limited 2500, 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 Facsimile: (403) 514-7888 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 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 19. Metric Conversion Chart To convert To Multiply by barrels thousand cubic feet cubic metres cubic metres feet miles acres tonnes metres kilometres hectares tons Common Share Dividend 0.159 28.174 0.305 1.609 0.405 1.102 The Company paid its ﬁrst dividend on its common shares on April 1, 2001. Since then, dividends have been paid on the ﬁrst day of every January, April, July and October. 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 and is restated for the two-for- one subdivision of the common shares which occurred in May 2010. Cash dividends declared per common share Notice of Annual Meeting 2011 $ 0.36 2010 $ 0.30 2009 $ 0.21 Canadian Natural’s Annual and Special Meeting of the Shareholders will be held on Thursday, May 3, 2012 at 3:00 p.m. Mountain Daylight Time in the Ballroom of the Metropolitan Centre, Calgary, Alberta. Stock Listing - CNQ Toronto Stock Exchange The New York Stock Exchange Printed in Canada by McAra Printing // Designed and produced by nonﬁction studios inc 2011 Annual Report 107 Canadian Natural Resources Limited 2500, 855 – 2 Street S.W. Calgary, AB T2P 4J8 telephone: 403.517.6700 facsimile: 403.517.7350 email: ir@cnrl.com

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