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 Mailandt, Martin Mailhot, Dominique Maillet, Elizabeth Maillet, Patrick Mailloux, Saeed Majdnia, Adeleh Majidi, Anita Mak, Maher Makhoul, Mark Makin, Virginia Makowsky, Eduardo Malabad, Tea Malkova, Jaron Mallard, Sean
Mallay, Gilbert Malo, Linda Maloney, Alakbar Mammadov, Dave Mamprin, Fred Manangu, Dennis Mandley, Leonard Mandrusiak, Dennis Manengyao, Jasleen Manhas, Darcy Mann, Darrell Mann, Della Mann, Don Mann, Gavin Mann, Joanne Manning, Vani Manoharan, Adrian Mansell, Allison Mansell, Ian
Manson, Rachelle Mantei, Luis Manzano Weffer, Nathaniel Maralli, Natasha Marchand, Vanessa Marcheggiani-Croden, Darren Marchesi, Michael Marchi, Catherine Marchuk, Lee Marchuk, Rodney Marcichiw, Ronald Marcichiw, Lissete Marcucci, Balamurugan Mariappan, Sandra Marin, Shane Marion,
David Mark, Allan Markin, Kristian Markstrom, Christina Maron, Brian Marsh, Rosemarie Marsh, Dave Marshall, Lynn Marshall, Stephen Marshall, Suzanne Marshall, Simon Marshman, Amanda Martin, Boyd Martin, Cesar Martin, Christopher Martin, Christopher Martin, Claire Martin, Dave Martin, Donald
Martin, Donald Martin, Kevin Martin, Leonie Martin, Regis Martinez, Jason Maruniak, Brendan Maruyama, Keivan Mashayekh, Chad Mason, Justin Mason, Kevin Mason, William Mason, Mandy Massiah, Al Massicotte, Patrick Massicotte, Ada Matchem, Devin Matheson, Kevin Matheson, Chris Mathew,
Liya Mathew, Keith Mathieson, Richard Mathieson, David Matthews, Sherry Maurice, Demetri Mavridis, Adam Mawer, Tim Maxwell, Richard May, Scott Mayer, Tyler Maynard, Kent Mayner, Kevin Mayner, Marie Mazac, Mark McAlpine, Donald McAmmond, Andrew McBoyle, Robin McBrien, Greg McCabe,
Nicole McCabe, Sarah McCaffrey, Shayla McCann, John McCanna, James McClellan, Derek McClelland, Chad McColl, Brent McConachie, Bruce McCormack, John McCoshen, Michelle McCotter, Scott McCracken, Shawn McCracken, Corey McCrea, Benjamin McCullough, Cameron McCullough, Kim McCurry,
Peter McDade, Ken McDavid, Cynthia McDonald, Kevin McDonald, Stewart McDonald, Rod McDougall, Mary McElroy, Josh McEwen, William McEwen, William McEwen, Ryan McFadden, Mark McFarlane, Bruce McFaul, Allan McGann, Daniel McGee, Kyla McGillis, Gerald McGinnis, Frances McGlynn, Terry
McGovern, Robert McGowan, Alan McGrath, Bruce McGrath, Matt McGrath, Jeanette McGregor, Phil McGregor, Steve McGregor, John McGuckin, Sharon McHardy, Gordon McHattie, Alan McIntosh, Graham McIntosh, Alistair McIntyre, Campbell McIver, Tyson McKague, Bernice McKay, Cory McKay, Gordon
McKay, Janet McKay, Jeff McKay, Kelvin McKay, Kim McKay, Robert McKay, Tim McKay, Trenton McKeage, Dennis McKee, Shelley McKee, Ken McKelvey, Brenda McKendry, Neil McKendry, Robert McKendry, Jan McKenna, Mark McKenna, Philip McKenna, Brian McKenzie, Kate McKenzie, Keith McKenzie,
Mike McKenzie, Kevin McKie, Corey McKinney, Stephanie McKinney, Ralph McLaren, Keith McLaughlin, Reginald McLaughlin, Joe McLean, Marla McLean, Nick McLean, Richard McLean, William McLean, Joan McLellan, Tyler McLellan, Charlie McLeman, Mandi McLenehan, Charles McLeod, Ian McLeod,
Kristen McLeod, Eamonn McMahon, Liana McMahon, Bradley McMann, Keith McMann, Blake McManus, John McMaster, Sandra McMichael, Shane McNabb, Rod McNair, David McNamara, Dustin McNamara, Ron McNeil, Robert McNinch, Erma McNulty, Pamela McNulty, Reid McPhail, James McPherson,
Jamie Mcpherson, Halina McQuillen, Lyle McQuiston, Richard McRae, Silas McRitchie, Allan McSharry, Jackie McTamney, Maggie McTurk, Casey McWhan, Marc Meadwell, Manfred Meakes, Nestor Medina, Pouya Mehrabi, Jai Mehta, Nayan Mehta, Corrine Mei, Jessica Meister, Daniel Melanson, Randy
Melanson, Erica Meldrum, Belinda Meller, Luis Mello, Glen Mellom, Marvin Melnyk, Ahmer Memon, Amy Menard, Paul Mendes, Samir Mendiratta, Nelson Meneses, Crystal Mercer, Timothy Merk, Greg Merkel, Danny Merkley, Anthony Merle, Cliff Merritt, Nathaniel Merritt, Anthony Mersich, Udell Meservy,
Marina Mesquita, Stanley Metcalfe, Ryan Metz, Steve Meunier, Emma Meynin, Igor Meynin, Saravanan Meyyappan, Cindy Michalko, Edward Michaluk, Gail Michaud, Kevin Michener, Murray Michie, Jennifer Michiels, Barry Middleton, Tracey Middleton, Dale Midgley, Josif Mihai, Mariela Mihilova, Tatjana
Mijic, Jane Mikalsky, Andrei Mikhailov, Jacqueline Miko, Guillermo Milan Garcia, David Millar, Billy Miller, Derek Miller, Dion Miller, Guy Miller, Jeffrey Miller, Kenneth Miller, Kirsten Miller, Roger Miller, Tony Miller, Vikki Miller, David Milligan, Steven Mills, Colin Milne, June Milne, Terry Milne, James Minard,
Andrew Minett, Marie Mineur, Arvindpal Minhas, Shikha Minhas, Jonathan Minick, Michelle Minick, Wyman Minni, Susan Minns, Denis Mino, Mason Mintenko, Kerry Minter, Alan Minty, Willian Mirabal, Mahmood Mirza, Jan Mistecki, Gregg Mitchell, Neil Mitchell, Sandy Mitchell, Shelby Mitchell, Yvonne
Mitchell, Anar Mitha, Adriana Mitroi, Leon Miura, Dan Mocodean, Gayathri Modekurti, Tom Moen, Emily Moffat, Iain Moffat, John Moffat, Kevin Moffatt, Adnan Moghul, Ashraf Mohamed, Bassam Mohammed, Khuram Mohib, Kim Mohler, Derek Moir, Lydia Mok, Jeff Molde, Nelson Molina, Jelena Molnar,
Robert Monahan, Mike Monias, Monica Monsalve, Pamela Montague, Frances Montefresco-Gentile, Rick Monteith, Floro Montenegro, Vicente Montenegro, Natasha Montes, Nicholas Montevecchi, Mary May Bernadette Montinola, Jennifer Monych, Jeff Moodie, Ken Moon, Christopher Moore, Erica Moore,
Judy Moore, Norma Moore, Luis Mora, Jorge Morales Miller, Claudia Moran, Jason Moravec, Orlando Morean, Amanda Morelli, Jennie Morency-Letto, German Moreno, Gustavo Moreno, Hernan Moreno, Christopher Morgan, Jonathan Morgan, Shaun Morgan, Timothy Morgan, Michael Moriarty, Sherril
Moring, William Morningstar, Kevin Morphy, Karen Morrice, Kyle Morris, Scott Morris, Christopher Morrison, Christopher A Morrison, Darwin Morrison, Denny Morrison, Donald Morrison, Heather Morrison, Jennie Morrison, Randle Morrison, Walter Morrison, Wesley Morrow, Steven Morse, Krista Morton,
Matthew Morvik, Kurtis Moscaluk, Shannon Moseng, Amelia Moslemi, Paul Mossey, Banafsheh Mostaghimi, Lorraine Motowylo, Andrew Mott, Bruce Mottle, John Motuz, Shahar Moudahi, Michael Mousseau, Cheryl Mouta, David Mouton, Gary Mowat, Glenn Moyer, Jillian Muckersie, Wayne Mudryk, Travis
Mueller, Alexander Mugford, Colin Muir, Watson Muir, Siddhartho Mukherjee, Lucy Mulgrew, Dallas Mullaney, Daniel Mullen, Cynthia Mulrooney, Leon Mulrooney, Noella Mulvena, William Munn, Ricardo Munoz, Amanda Munro, Lisa Munro, Maria Munro, Reid Munro, Ryan Munro, Ryan N Munro, Alicia
Murphy, Brian Murphy, Cora Murphy, Ernest Murphy, Jennifer Murphy, John Murphy, Julian Murphy, Kenneth Murphy, Patrick Murphy, Carrie Murray, Cliff Murray, Graham Murray, Justin Murray, Shawn Murray, Terence Murtagh, Aaron Musil, William Muss, Dan Myers, William Myers, Eduard Mykhalchuk,
David Myshak, Melonie Myszczyszyn, Richard Nachtegaele, Mohammad Naderikia, Jerad Nadin, Arshad Nagamia, Amardeep Nagra, Jeannine Nagy, Krishnakumar Nair, Bill Nalder, Israel Nandez Hernandez, Rick Napier, Camille Naqvi, Sajid Naqvi, Kuralenthi Narayanan, Prabhu Narayanasarma, Bill Nash,
Darren Naugler, Patricia Nava, Srimanti Nayak, Marian Neagu, John Neff, Donald Neigum, Allen Neilson, John Nejedlik, Andrew Nelson, Curt Nelson, Derek Nelson, Donna Nelson, Douglas Nelson, Gilbert Nelson, Jessica Nelson, Vincent Nelson, Mark Nergaard, Brad Nessman, Katy Nettesheim, Steven Neu,
Caleb Neufeld, Henry Neufeld, Owen Neufeld, Shelley Neufeld, Guy Neuman, Darrell Nevil, Damien Newbury, Jennifer Newell, Lisa Newman, Michael Newman, Kevin Newton, Rae Newton, Alice Ng, Hannah Ng, Kevin Ng, Kimberly Ng, Hien Ngo, Ngoc Ngo-Schneider, Mpinga Ngoy, Kieu Nguyen, Melissa
Nguyen, Tai Nguyen, Tuyet Ngoc Nguyen, Han Ni, Matteo Niccoli, Fawn Nichol, Jonathan Nicholl, Gary Nichols, James Nichols, Melissa Nichols, James Nicholson, Doris Nickel, Matt Nicol, Josie Nicolajsen, Brenden Nielsen, Wayne Nielsen, Jose Nieto, Orlando Nieto, Wesley Nikiforuk, Chris Nixon, Paul Niziolek,
David Noel, Miguel Nogueira, Roger Nolan, Greg Nolin, Bill Norberg, Alex Norburn, Ernest Nordlund, Nathan Nordstrom, Arcelie Noriel, David Norman, Paul Norman, Robert Norman, Troy Normand, Shawn Normore, David Noseworthy, Allen Noskey, Darcy Novak, Murray Novak, Faleh Novin Pour, Kerry
Novinger, Kelvin Nurkowski, Pam Nwelih, Rachelle Nycholat, Genia Nyenhuis, Tim Nyitrai, David Oake, Donald Oaks, Abdelsalam Obeidat, Christian Oberegger, Blair O’Brien, Ken O’Brien, Tim O’Brien, Jeffery Obrigewitsch, Kolton Obritsch, Pedro Ocana, Joseph O’Connell, Kathleen Odendahl, Rick O’Donnell,
Terry Oele, Samuel Ogali, Julie Oganwu, Jason Ogertschnig, David Ogilvie, Robert Ogilvie, Kevin O’Hearn, Mildred Ohlheiser, Ryan Okada, Charles O’Keefe, Steve O’Keefe, David Oladeji, Paul Olaniyan, Blake Olaski, Daniel O’Leary, Sean O’Leary, Delvin Olesen, Bradley Olheiser, Dianne Oliveira, Jason Ollikka,
Ghasem Oloumi, Amber Olsen, Kevin Olsen, Lonnelle Olsen, Richard Olsen, Brett Olson, Dean Olson, Jared Olson, Stephen Olson, Steven Olson, Warren Olson, Wesley Olson, Yemi Oluwabunkunmi, Olubunmi Oluwole, Kevin Ondic, Dave O’Neil, David O’Neill, Tim O’Neill, Emmanuel Onumonu, Robert Orbeck,
Richard Ordinaria, Steve O’Reardon, Flora O’Reilly, Anna Oreshkova, Doug Orlecki, Alison Orr, Neil Orr, Julian Ortiz Arango, Justin Osadczuk, Jeffrey Osborne, Steven Oslanski, Hecmy Osorio Lobo, Anna Ostrzenski, Darwin Oswell, Pilar Otalora, Jonathan Otis, Wayne Otteson, Tyler Ouart, Mike Ouellet, Denis
Ouellette, Jolanta Ouellette, Steven Ouellette, Jean Francois Ousset, Mark Overwater, Janet Owen, Leonard Owens, Millicent Oyunge, Fabio Pacheco, Ron Pacholuk, Dante Padilla, Ruth Padilla, Doug Page, Matthew Page, Robert Page, Marcus Pagnucco, Shelley Paiement, Randall Paine, John Pak, Vladimir
Pak, Anandakumaran Palani, Ashwini Palatheerdhapu, Elizabeth Palmer, Lee Palmer, Rick Palmer, Glenn Paluck, Jack Panas, Amol Pande, Loredana Pantazi, Francisco Pantilag, William Papineau, Darcy Paquette, Leo Paquin, Alishia Paradis, Theo Paradis, Travis Paradis, Cherri Paranaque, Biju Parathundathil,
Narasimha Paravastu, Gordon Parchewsky, Luis Paredes, Blair Parent, Bernard Parenteau, Clement Parenteau, Joanna Parenteau, Sachin Parikh, Roberto Parillo, Pan Gi Park, Blaine Parker, Darby Parker, John Parker, Tina Parker, Barry Parkin, Randy Parkyn, John Parr, Kyle Parrish, Scott Parry, Cheryl Parsons,
Terry Parsons, Ken Partsch, Gemicane Pascual, Kambiz Pashaei Fakhri, Wesley Pasko, Lawrence Paslawski, Joey Pasos, Randy Passmore, Amit Patel, Anar Patel, Ashish Patel, Ashwin Patel, Atul Patel, Bhaveshkumar Patel, Hasmukhlal Patel, Kaushik Patel, Mahendra Patel, Maheshkumar Patel, Nikunjkumar
Patel, Nirmal Patel, Nisha Patel, Paresh Patel, Pravinchandra Patel, Rajnikant Patel, Sanjaykumar Patel, Sanjaykumar Patel, Narendrasingh Pateliya, Andy Paterson, Richard Patey, Jim Patience, Charles Paton, Brandon Patrick, Stephen Patrick, Brian Patterson, Craig Patterson, Carolyn Pattinson, Colin Paul,
Geoffrey Paul, Joshua Paul, Eric Paulin, Wilma Pauls-Atas, Brent Paulson, Brian Paulssen, Daniel Pavelick, Amy Paxton, David Payne, Dean Payne, Paul Payne, Linda Peachey, Blair Pearson, David Pearson, Edward Pearson, Gerald Pearson, Pam Pearson, Sean Pearson, James Peckford, Chantal Peddle, Philip
Pedersen, Brian Pederson, Lance Pederson, Rita Peel, Cam Peifer, Sean Pell, Brian Pelly-Skinner, Deborah Pemberton, John Pena, John Penman, Stephen Penner, Robert Penney, Kevin Pennington, Burgess Penny, John Penzo, Kyle Pepper, Subodh Peramanu, Richard Perchaylo, Crystal Peregrym, John Perepelecta,
Frank Perez, Luis Alberto Perez, Luis Alfonso Perez, Mark Perkins, Seth Perkins, Julito Peroramas, Nancy Perron, Ashley Perry, Don Perry, Gladys Perry, Meghan Perry, Trevor Perry, Vicki Perry, Tarla Persaud, Bernie Persson, Dimetri Peters, Shelley Peters, Carson Petersen, Casey Petersen, Bill Peterson, Melissa
Peterson, Tracy Peterson, William Petlyk, Rick Petrick, Shauna Petrock, Nicolas Petrola, Priscella Petti, Lucyna Pettigrew, John Pettit, Shawn Pettit, Jonathan Pfeifer, Wyatt Phaff, Lien Pham, Sherry Phan, Byron Philibert, Brent Phillips, Dan Piche, Alain Pickersgill, Doug Pierce, Konstanty Pietka, James Pihowich,
Barbara Pilgrim, Sheldon Pilgrim, Mary Jane Pili, Darren Pilisko, Ron Pilisko, Jodi Pilsner, Gala Pimienta, Dale Pinder, Arturo Pinero, Jose Pinerua, Brendan Pipa, Nelson Pires, Kyle Pisio, Edward Pittman, Sheldon Pittman, Adrian Plaiasu, Julio Plata, Lorrie Player, Daniel Plepelic, Jamie Plessis, Graham Plews,
Ted Plouffe, Kelly Plummer, Imhotep Pocaterra, Shaun Podhorodeski, Jonathan Podolski, Ricot Poitevien, Donna Poitras, Kevin Poitras, Joanna Polacik, David Pole, Christopher Pollard, Dixon Pollard, John Pollock, Lori Pollock, Morgan Pollock, Eleanor Polson, Shane Poluk, Roger Pomerleau, Seward Pon,
Matthew Poncelet, Darcy Poncsak, Bradley Pond, Haripradha Ponnurangan, Marlain Poohachow, Robert Pool, Stephen Poole, Ka Yee Poon, Colleen Popko, Jason Popko, Michael Popowich, Diane Porter, Fred Post, Patti Postlewaite, Ryan Postnikoff, Jeffrey Poth, Carl Potter, Jason Potter, Terry Potter, Randy
Pottle, Ryan Potts, Jesse Poulin, Dave Powell, Donald Power, Laurie Power, Tiffany Power, Mitesh Prajapati, Dhrub Prasad, Gregory Pratch, Jeffrey Pratt, Rodney Pratt, Lindsay Praud, Heather Praznik, Mike Preece, Robert Prefontaine, Adrienne Price, Alanna Price, Rick Price, Dustin Pringle, Travis Prins, Steven
Pritchett, Angela Prive, Doug Proll, Kayla Prowse, Darcy Pruden, Chad Prybylski, Curtis Przybylski, Steve Pshyk, Yesid Edgar Puerto, Justyna Puhl, Miguel Pulgar, Kapil Pupneja, Sachin Pupneja, Rahul Puranik, Shantelle Purcell, Trevor Purves, Darwin Pushak, Trent Pylypow, Teresa Pyo, Justin Pyper, Shoaib
Qaimkhani, Lu Qing, Munawar Quadri, Tony Quan, Duane Quigley, Ron Quiring, Samir Qureshi, Mandi Rabeau, Nathan Rabinovitch, Alexander Raciborski, Warren Raczynski, Joseph Radcliffe, Mihai Radu, Barbara Rae, Christopher Raglan, Jay Raher, Matiur Rahman, Morteza Rahmani, Morteza Rahmanian,
Priya Rai, Shaun Rains, Yina Raisbeck, Daniel Ralph, Dooshyant Ramburrun, Cristina Ramirez, Maruja Ramirez, Wilbert Ramirez, Ruth Ramonas, Carlos Ramos, Colin Ramsaran, Dwight Ramsay, Lorraine Ramsay, Kerri Ramsbottom, Muhammad Rana, Len Rancourt, Heather Randell, Poonam Randhawa,
James Rankin, Dorotea Ranola, Gregory Ransom, Jeremy Ransom, Shahid Rasheed, Tariq Rasheed, Chris Rasko, Shauna Rasmussen, Wade Ratcliffe, Soukseum Rathamone, Stojan Ratkovic, Murray Rattray, Holly Ratzlaff, Rajesh Ravindran, Carrie Rawlake, Pete Rawlinson, Eirenne Rawson, Sanjay Ray, Jason
Rayner, Robert Rayner, Blair Read, Donald Read, Wilfred Read, Wayne Reashore, Ted Reay, Deston Reber, Dana Rechenmacher, Bernie Redlich, Ronald Redmond, Adele Reed, Danielle Reed, Jon Reed, Keith Reed, Scott Reed, Tim Reed, Michael Rees, Carrie Regnier, Duncan Rehm, Karmin Reichle, Cameron
Reid, Chris Reid, Darren Reid, Kerry Reid, Lilian Reid, Marty Reid, Nicole Reid, Sarah Reid-Bicknell, Ian Reimer, John Reiniger, Glenn Reiter, Harvey Reithaug, Wendy Reitmeier, Daniel Rejman, David Rejman, William Remmer, Peter Rempel, Long Ren, Shouhong Ren, George Renfrew, Judith Rennie, Linsey
Rennie, Scott Rennie, Michael Reno, Robert Rentner, Michael Rew, Gregory Reynolds, James Reynolds, Pat Reynolds, Tamara Reynolds, Naseem Rhemtulla, Bruce Rice, Donna Rice, Justin Richard, Tammy Richard, Carolyn Richards, Charles Richards, Gerald Richards, Bill Richardson, Rob Richardson, Sterling
Richardson, Susan Richardson, Wesley Richardson, Lori Richmond, Dean Richter, Jeff Riddell, Robert Riddell, Clarence Ries, Dale Rinas, Carl Ringdahl, Gordon Ringheim, David Ringuette, Mike Rioux, Serge Rioux, Darren Risling, Lawrence Ritchat, Stewart Rivard, Monica Rivas, Ismael Rivera, Sammie Rivet,
Andrew Roach, Tracey Roasting, Jo-Anne Robak, Terrence Robbins, Christopher Roberts, Dale Robertson, John Robertson, Malcolm Robertson, Michael Robertson, Stephen Robertson, Justin 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
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metres
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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.
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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