2012 ANNUAL REPORT
THE PREMIUM VALUE
DEFINED GROWTH
INDEPENDENT
PROVEN
EFFECTIVE
STRATEGY
PROVEN EFFECTIVE STRATEGY
Balance exists throughout our strategy, our portfolio and
our business approach. This balanced approach factors
into the many facets of our capital allocation, allowing
us to prudently balance our resource development,
dividends, share purchases, strategic acquisitions and
debt repayments. With a disciplined approach and
fiscal responsibility, we have generated substantial
free cash flow and maintained a strong balance sheet,
while weathering fluctuations in the marketplace.
DIVERSE BALANCED ASSET PORTFOLIO
Our large and diverse portfolio of high grade assets
provides us opportunities for creating shareholder value,
while transforming to a longer life, low decline asset base.
27
18
%43
12
PROVED PLUS
PROBABLE RESERVES (1)
MINING & UPGRADING
THERMAL IN SITU
CRUDE OIL & NGLs
NATURAL GAS
THERMAL IN SITU
OIL SANDS
MINING & UPGRADING
PRODUCTION
(before royalties)
99 Mbbl/d
PRODUCTION
(before royalties)
86 Mbbl/d
PROVED RESERVES (1) (2)
PROBABLE RESERVES (1) (2)
1,066 MMbbl
1,056 MMbbl
PROVED RESERVES (1) (3)
PROBABLE RESERVES (1) (3)
2,255 MMbbl
1,096 MMbbl
CRUDE OIL & NGLs
NATURAL GAS
PRODUCTION
(before royalties)
266 Mbbl/d
PROVED RESERVES (1)
PROBABLE RESERVES (1)
1,008 MMbbl
440 MMbbl
PRODUCTION
(before royalties)
1,220 MMcf/d
PROVED RESERVES (1)
PROBABLE RESERVES (1)
4,136 Bcf
1,651 Bcf
CANADIAN NATURAL
2012 ANNUAL REPORT
(1) Company Gross
(2) Bitumen
(3) Synthetic Crude Oil
655 (1)
MBOE/D
PRODUCTION
$6.0 (2)
BILLION
CASH FLOW
(1) 9% increase from 2011.
(2) Refer to page 20 for definition.
DISCIPLINED GROWTH
With substantial operating experience in both the Western Canadian Sedimentary basin and the international arena, we
are committed to generating disciplined value growth. Our ability to allocate capital in a flexible manner has enabled us
to reliably grow our presence in both well-known and leading-edge plays. We will maintain this approach in 2013 with
the cost effective expansion of our Horizon Oil Sands project to 250,000 barrels per day of Synthetic Crude Oil (“SCO”).
Additionally, we will commission our 40,000 barrel per day Kirby South Steam Assisted Gravity Drainage (“SAGD”)
project targeted for first steam-in in Q4/13 and advance our deep-water exploratory opportunity in South Africa.
PRODUCTION/PROVED RESERVES HISTORY
(Before royalties)
Daily
Production
(MBOE/d)
700
600
500
400
300
200
100
0
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013F
Production
Reserves
Company Gross Proved. 2009 to 2012 includes Horizon SCO reserves. Reserves prior to 2010 were calculated using constant prices and 2010 calculation
based on escalating prices due to a change in disclosure requirements. 2013F daily production based on midpoint of guidance.
Reserves
(MMBOE)
6,000
5,000
4,000
3,000
2,000
1,000
0
We have an enormous resource base which we are committed to
develop with prudence and discipline. Our proven effective strategy
combined with the execution of our defined growth plan will deliver
premium value to our shareholders.
Our ability to generate free cash flow while ensuring we
economically develop production of high return projects is one of our
main objectives. We are selective in the areas we operate, and are
well-positioned to capture opportunities and generate strong returns.
2012 Performance Highlights
Letter to our Shareholders
TABLE OF CONTENTS
02
04
08 Our World-Class Team
Year-End Reserves
10
18 Management’s Discussion and Analysis
55 Management’s Report
56
Management’s Assessment of Internal Control
over Financial Reporting
Independent Auditor’s Report
Consolidated Financial Statements
57
59
63 Notes to the Consolidated Financial Statements
92
Supplementary Oil and Gas Information
100 Ten-year Review 102 Corporate Information
CANADIAN NATURAL
2012 ANNUAL REPORT
1
2012 PERFORMANCE HIGHLIGHTS
During 2012, the Company made very good progress in our transition to a longer life, low decline
asset base. We continued to balance the development of our large resource base by focusing on
high return assets and the ability to deliver timely results.
FINANCIAL ($ millions, except per common share amounts)
Product sales
Net earnings
Per common share – basic
– diluted
Adjusted net earnings from operations (1)
Per common share – basic
– diluted
Cash flow from operations (2)
Per common share – basic
– diluted
Capital expenditures, net of dispositions
Long-term debt (3)
Shareholders’ equity
OPERATING
Daily production, before royalties
Crude oil and NGLs (Mbbl/d)
North America – excluding Oil Sands Mining and Upgrading
North America – Oil Sands Mining and Upgrading
North Sea
Offshore Africa
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Barrels of oil equivalent (MBOE/d) (5)
$
$
$
$
$
$
$
$
$
$
$
$
$
2012
2011
2010 (4)
$
$
$
$
$
$
$
$
$
$
$
$
$
16,195
1,892
1.72
1.72
1,618
1.48
1.47
6,013
5.48
5.47
6,308
8,736
24,283
326
86
20
19
451
$
$
$
$
$
$
$
$
$
$
$
$
$
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
1,198
1,231
1,217
2
20
1,220
655
7
19
1,257
599
10
16
1,243
632
(1) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation to this measure is discussed in
the Management’s Discussion and Analysis (“MD&A”).
(2) Cash flow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company’s ability to fund capital reinvestment and repay
debt. The derivation of this measure is discussed in the MD&A.
Includes the current portion of long-term debt.
(3)
(4) Comparative figures for 2010 have been restated in accordance with IFRS issued as at December 31, 2011.
(5) 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
2012 ANNUAL REPORT
2012
2013F*
GROSS PRODUCTION MIX (2013F)
DEBT/BOOK 26% 25%
1.1X
DEBT/EBITDA 1.2X
* Based upon average strip pricing of WTI $94.11, AECO $3.10/GJ, and C$/US$0.98 as at Feb. 2013.
Drilling activity (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)
2012
2011
2010
1,271
1,233
1,051
–
–
–
1
1
7
1,271
1,234
1,059
13,775
13,585
12,594
128
4,307
128
4,191
128
4,193
18,210
17,904
16,915
3,999
3,753
3,423
227
103
228
109
252
120
4,329
4,090
3,795
3,985
4,266
4,092
82
69
4,136
5,018
98
83
4,447
4,831
78
92
4,262
4,505
(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.
(3) Year-end proved reserves were prepared using forecast prices and costs.
25
30
%
45
HEAVY CRUDE OIL
LIGHT CRUDE OIL, SCO & NGLs
NATURAL GAS
9%
ANNUAL
PRODUCTION
GROWTH
246%
2P RESERVE
REPLACEMENT
RATIO
CANADIAN NATURAL
2012 ANNUAL REPORT
3
LETTER TO OUR SHAREHOLDERS
We have a proven strategy that works and are focused on effective and efficient operations in all
areas. Our vast resource base, strong technical expertise and financial resources will facilitate our
ability to significantly grow free cash flow and maximize returns for our shareholders.
For over twenty years our balanced approach to creating long-term value through the judicious
development of our diverse long-life assets has proven successful. As a result of our strong,
disciplined business approach and continued focus on our proven and effective strategy, we remain
one of the top independents, delivering premium value and defined growth.
Our strategy works. We have the largest proved plus probable reserve base of our peer group with greater
than 7.8 billion barrels of oil equivalent. Despite our size we remain nimble; able to respond quickly to
changes in the economic landscape to ensure we can continue to maximize shareholder return.
In addition to our vast reserve base, we have one of the largest resource bases in our peer group. We
have significant positions in thermal in situ crude oil and oil sands mining. In addition, we have an
enviable land position in leading edge plays like the Montney and Duvernay. Our large resource base
provides Canadian Natural with the base to exercise our effective capital allocation strategy to maximize
value in the near, mid and long-term. We continue to operate with high working interest and leverage
our dominant land base and infrastructure to maintain effective and efficient operations.
We operate with diligent governance and stewardship throughout our global operations. We recognize
that a focus on safety in our operations and sustainability in our business model will provide long-term
benefit to our corporation, the communities in which we operate and our shareholders. Sustainability,
innovation and minimizing our environmental footprint remain at the forefront of our decision making,
as we strive for operational excellence.
We believe in balance. Balance exists throughout our strategy, our portfolio and our business approach.
We believe in a balanced product mix, producing light crude oil, synthetic crude oil, heavy crude oil and
natural gas. This balanced approach factors into the many facets of our capital allocation, allowing us to
prudently balance our resource development, dividends, share purchases, strategic acquisitions and
debt repayments.
Through our fiscal responsibility, disciplined approach and effective capital allocation we have maintained
a strong balance sheet. Our low debt position allows us to weather fluctuations in the marketplace and
capture opportunities that become available.
Our achievements this year are as a result of the execution of our proven effective strategy. Our strategy
combined with our balanced asset base allows us to mitigate market volatility, generate free cash flow
and maximize returns, while transforming to a longer life, low decline asset base.
17%
ANNUAL
DIVIDEND
GROWTH
4
CANADIAN NATURAL
2012 ANNUAL REPORT
11.0
MILLION
SHARES
PURCHASED
N. MURRAY EDWARDS, Chairman
JOHN G. LANGILLE, Vice-Chairman
STEVE W. LAUT, President
Natural Gas
Our 2013 capital allocations to natural gas development are 5% below 2012 levels. This reflects our capital
allocation discipline, and has resulted in a forecasted 9% reduction in natural gas production levels. Despite
this, we consider natural gas as an important segment of our commodity mix as we are well positioned to
respond to any resurgence in natural gas prices. We remain one of the largest producers of natural gas in
Canada and hold over 16.2 million net acres of land with natural gas potential, including one of Canada’s
largest unproven land positions which we continue to judiciously manage and preserve. This prudent
strategy of efficient and effective development ensures that our cash flow remains strong. Even at today’s
prices, our natural gas segment continues to generate free cash flow. Our premium land position includes
one of the industry’s largest exposures to the Montney and Duvernay plays, which have significant value
potential. Combined with our vast infrastructure and expertise we will be able to leverage our position to
generate significant value upon price recovery.
Light Crude Oil and NGLs
In 2012, we continued to grow our Canadian light crude oil production. We drilled 124 wells in 2012,
which, in conjunction with enhanced oil recovery activities and acquisitions, resulted in 13% annual
growth of North America light crude oil and NGLs production over 2011 production levels. We have
significant expertise in the field of light crude oil development and currently operate over 110 waterfloods
with an additional 22 in the planning phase. We can continue to optimize our land base by leveraging
new technology. In light crude oil we are maximizing recovery in new and mature pools with enhanced
oil recovery techniques, horizontal multi-frac technology and infill drilling, while continuing to explore
for new pool opportunities. With over 500 operated light crude oil pools, we have significant upside
opportunity to improve oil recovery while maximizing value.
Natural gas liquids are an important component to our portfolio. Our investment and operational
excellence in liquids-rich plays generates economic returns. In 2013, we will continue to delineate
Montney pool boundaries and drill to maximize returns. Our Montney play at Septimus will continue to
grow, expanding to 125 million cubic feet of production per day, and increasing to nearly 12,200 barrels
per day in liquids in 2013.
International light crude oil plays in the North Sea and Offshore Africa remain a core portion of the
Canadian Natural portfolio. Our international opportunities provide significant free cash flow, while
exposing us to international pricing, and fostering our offshore expertise. Our ability to optimize costs and
leverage expertise provides a benefit to the Company and its shareholders. Despite the 2011 curtailment
of the North Sea program as a result of United Kingdom tax restructuring, our strict operating standards
have ensured those assets still generate free cash flow. In 2013, we intend to drill additional wells on a
second platform in the North Sea and we will progress Espoir development with an infill drilling program.
We also expect to progress the partnering process on our high potential block located offshore South Africa
in 2013, with the objective to conduct an exploratory drilling program in 2014 or 2015.
CANADIAN NATURAL
2012 ANNUAL REPORT
5
Over the past number of years, Canadian Natural has proactively balanced the allocation of free
cash flow between resource development, dividends, share purchases, acquisitions and debt
repayment. All of these choices have been driven by effective capital allocation and efficient
operations while maximizing shareholder returns.
Heavy Crude Oil
Primary
Canadian Natural is the largest primary heavy crude oil producer in
Canada. In 2012 primary heavy crude oil production grew by 22%,
versus our budgeted target of 15%. Despite pricing volatility, heavy
crude oil continues to yield the highest returns in our asset portfolio.
Our large disciplined drilling programs help to control the capital
inflationary pressures, while we
leverage our dominant
infrastructure to maintain effective and efficient operations. In
addition to our substantial infrastructure and land base, our
inventory of 8,500 drilling locations allow us to high-grade our
capital allocation to deliver consistent, long-term economic returns.
Primary heavy crude oil production volumes are targeted to
increase 13% in 2013 as we target to drill 890 new wells. This,
along with technological advancement, will provide us significant
near term opportunities for production growth.
Pelican Lake
Our leading edge polymer flood at Pelican Lake pool contains
4.1 billion barrels of heavy crude oil initially in place and delivered a
strong response in 2012. A new production facility is currently under
construction to accommodate production increases at both Pelican
Lake and Woodenhouse. As the polymer flood project expands,
capital requirements will decline, increasing our free cash flow
generation. We expect to convert 56% of the pool to polymer flood
by the end of 2013 and target to exit 2013 at 50,000 barrels per day.
Oil Sands
Mining and Upgrading
Horizon Oil Sands operations remain focused on safe, steady and
reliable production. We have a world class asset with over
3.35 billion barrels of proved plus probable synthetic crude oil
reserves, representing decades of fully upgraded light crude oil
production potential without decline.
We have made significant progress in operational discipline and
reliability in 2012. The addition of the third Ore Preparation Plant
has enhanced reliability significantly and allowed the effective
use of intermediate tankage to deliver steady operations in the
upgrader. We expect reliability to continue to increase in 2013,
particularly after we complete our first major turnaround.
6
CANADIAN NATURAL
2012 ANNUAL REPORT
The execution strategy of Phases 2 and 3 at Horizon are delivering
expected results as we continue to track below cost estimates.
Phases 2 and 3 are targeting to bring Horizon production levels to
250,000 barrels per day, with potential for further expansion to
500,000 barrels per day. Production costs at Horizon are largely
fixed; as a result, production costs on a per barrel basis are targeted
to reduce significantly when Phases 2 and 3 come on-stream,
greatly enhancing the plant’s economics and sustainability.
Thermal In Situ
With our vast asset base and ability to achieve effective and
efficient operations, we are an industry leader in thermal in situ
operations. At our Primrose field we grew production in 2012 to
99,000 barrels per day and delivered industry leading per-barrel
production costs. With attractive economics and a significant
drilling inventory, Primrose is expected to add value for decades.
With an extensive inventory of thermal projects, we target to
grow production capacity to 510,000 barrels per day in a
disciplined, stepwise, cost effective approach, adding 40,000 to
60,000 barrels per day of incremental capacity every two to
three years.
The next step of our thermal in situ growth plan is the Kirby
South expansion, which remains on schedule and on budget with
first steam targeted for fourth quarter 2013. Oil production is
targeted to ramp up to 40,000 barrels per day in late 2014.
In 2012, we strategically added 340 million barrels of contingent
resource by acquiring lands contiguous to our Kirby development.
In 2013, we will evaluate the potential to increase the targeted
Kirby development phases to over 140,000 barrels per day.
Marketing
We have a long-term and effective heavy crude oil marketing
strategy which maximizes the realized price for our overall
portfolio regardless of market conditions. This strategy is executed
under a three-pronged approach to ensure we garner the most
value. We blend various crude oil streams and diluents to better
serve the needs of our refining customers. We support the
expansion of pipeline export capacity. And, finally, we support
and participate in projects which add conversion capacity for
bitumen and synthetic crude oil.
RETURN TO SHAREHOLDERS
COMPANY GROSS 2P RESERVES PER SHARE
($ million)
$800
$700
$600
$500
$400
$300
$200
$100
$0
38%
CAGR
Horizon Phase I build years
2005
2003
2004
2006
DIVIDEND
CAGR represents 2008 to 2012 year-end.
2007
2008
2009
SHARE PURCHASE
2010
2011
2012
Heavy crude oil differentials in 2012 averaged 22%, which falls
within our expected long term range of 20-24%. In late 2012 heavy
crude oil differentials widened dramatically as a result of refinery
outages and infrastructure constraints. The increase in heavy crude
oil conversion capacity in the US Midwest and the expansion of
existing transportation infrastructure will again normalize these
differentials. We believe the heavy crude oil differential will return
to our expected range of 20-24% from West Texas Intermediate
pricing during the latter half of 2013 and into 2014.
North West Redwater
Additionally, in 2012 our Board of Directors sanctioned the
Redwater Upgrader/Refinery project, an exciting new facet in our
diverse portfolio. Combining our strengths with the expertise of
Northwest Upgrading Inc., we have formed a partnership which
targets a competitive return on capital. The project targets to add
50,000 barrels of bitumen conversion capacity to the market,
further contributing to improved heavy crude oil pricing.
Our Advantages
Canadian Natural has the largest reserve base in our peer group
bolstered by an exceptional and diverse asset portfolio capable of
generating significant free cash flow. In 2012, our total proved
reserve replacement ratio was 178%, with a total proved reserve
life index of 22.8 years. Additionally, our year over year proved
plus probable reserve replacement ratio was 246% for 2012.
(BOE)
8
7
6
5
4
3
2
1
0
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
Gross proved plus probable reserves prior to 2010 were prepared using constant prices and costs.
Excludes Horizon SCO reserves prior to 2009.
Canadian Natural’s total overall production for 2012 averaged
655 thousand barrels of oil equivalent per day, representing a 9%
increase from 2011. As we transition to a longer life, low decline
asset base, our strong experienced team remains focused on
continuing to deliver on our proven and effective strategy. This,
combined with our strong balance sheet, will allow us to withstand
future commodity price volatility, while we increase our capacity to
generate free cash flow and maximize shareholder value.
We remain committed to our strategy and focused on maximizing
value, which enables us to deliver returns to our shareholders over
the near, mid- and long-term. At Canadian Natural we are all
shareholders, enabling us to remain focused, disciplined and driven.
With this combination of our assets, team and strategy, Canadian
Natural will remain a premium value, defined growth independent.
N. Murray
Edwards
Chairman
John G.
Langille
Vice-Chairman
Steve W.
Laut
President
CANADIAN NATURAL
2012 ANNUAL REPORT
7
OUR WORLD-CLASS TEAM
5,970 STRONG: DIVERSITY, TALENT & EXPERTISE.
To develop people to work together to create value for the Company’s shareholders
by doing it right with fun and integrity.
E. Aasen, L. Abadier, Z. Abbas, C. Abbenhuis, W. Abeda, P. Abercrombie, R. Abrams, J. Abramyk, N. Abro, C. Acharya, D. Acheson, T. Adair, D. Adam, I. Adam, S.
Adam, W. Adam, B. Adams, D. Adams, K. Adams, M. Adams, D. Adamson, C. Adan, D. Addinall, Z. Addington, A. Adebayo, Y. Adebayo, A. Adegoroye, M. Aden,
T. Adenusi, A. Adetowubo, C. Adkins, R. Adzabe Ella, J. Agate, A. Agnihotri, K. Agombar, I. Agu, S. Ahmad, A. Ahmadi, A. Ahmari, A. Ahmed, P. Ahmed, S. Ahmed,
T. Aickelin, R. Aikens, G. Ailsby, J. Airlie, K. Aitken, V. Akella, J. Akeroyd, S. Akinsanya, S. Akolkar, D. Albert, J. Alcala, D. Alderdice, S. AlDhabbi, B. Alexander, J.
Alexander, V. Alexander, W. Alexandru, D. Alfred, E. Algazina, A. Ali, Z. Ali Khani, R. Aliazas, J. Allan, J. Allen, S. Allen, V. Allen, S. Allerton, D. Allibone, K. Almadi,
Y. Alnumi, J. Alonso, H. Al-Saidi, F. AlSakaf, A. Al-Saleem, J. Alvarez, J. Alvarez Luzon, D. Amalaman, J. Aman, T. Amara, D. Ames, D. Amey, G. Amundrud, C. Amy,
W. Amy, K. Andersen, T. Andersen, C. Anderson, G. Anderson, K. Anderson, L. Anderson, M. Anderson, K. Andreas, M. Andreas, P. Andrekson, D. Andreoli, D.
Andrews, L. Andrews, T. Andrews, E. Angel, C. Angeles, P. Angell, N. Ango Mfene, C. Angus, M. Anis, E. Annis, S. Annis, A. Ansell, G. Anstey, J. Antle, K.
Antonishyn, T. Antoniuk, S. Antonuk, J. Apit, P. Appiah, B. April, R. April, D. Aranas, R. Aranguren, F. Arano, L. Arbour, L. Archer, P. Archer, J. Argan, H. Arias, M.
Arias, J. Arizaleta, J. Arkley, A. Armstrong, D. Armstrong, R. Armstrong, S. Arndt, C. Arnold, M. Arsenault, B. Arunachalam, S. Arunachalam, A. Ashley, B. Ashley,
D. Ashley, W. Ashun-Codjiw, W. Aslam, R. Aslin, R. Aspden, S. Aspden, D. Assinger, J. Asso, V. Assohou-Ouattara, F. Assoko-Mve, A. Assoum, S. Assoumane, A.
Astalos, R. Astalos, B. Atkinson, J. Atkinson, E. Au, G. Au, J. Auch, A. Auger, B. Auger, R. Augustyn, C. Aular, J. Austin, R. Austin, L. Avery, M. Avila, C. Aviles, O.
Awodein, E. Awuni, K. Ayers, W. Ayles, J. Ayub, F. Azam, A. Babalola, K. Babu, W. Bachmeier, C. Backus, M. Bacon, M. Baddeley, K. Badmos, J. Badock, M. Baes,
A. Bagnall, B. Bahlieda, D. Baier, K. Baier, R. Bailer, A. Bailey, C. Bailey, D. Bailey, J. Bailey, K. Bailey, R. Bailey, L. Bakaas, A. Baker, C. Baldwin, K. Baldwin, M.
Baldwin, R. Baldwin, V. Baldwin, I. Balicanta, J. Balkam, G. Ball, J. Ball, L. Ball, M. Ball, J. Ballard, G. Ballas, R. Ballas, S. Ballas, T. Ballas, B. Balog, L. Bamba, M.
Bamba, R. Bamotra, C. Banack, J. Banak, S. Banamia, D. Banash, J. Banawa, N. Banerjee, R. Banerjee, L. Banks, B. Bannis, T. Banny, C. Bantaya, L. Barber, G.
Bardoel, L. Bardoel, P. Bare, M. Bari, R. Barker, S. Barker, A. Barley, C. Barnes, D. Barnes, M. Barnes, N. Barnes, B. Barnett, R. Baron, D. Barr, P. Barr, S. Barr, E.
Barreto, D. Barron, L. Barros, R. Barten, B. Bartlett, C. Bartlett, E. Bartlett, M. Bartlett, C. Bartman, D. Bartman, M. Bartman, J. Basabe, J. Basilan, L. Basines, C.
Bast, S. Basu, C. Bateman, G. Bateman, K. Bateman, M. Bates, M. Batovanja, B. Battyanie, J. Batuyong, D. Bauer, L. Bauer, R. Bauer, J. Bauman, C. Baxter, B.
Beach, A. Beacon, C. Beaman, H. Beamish, C. Beaton, A. Beattie, S. Beattie, K. Beatty, A. Beaudoin, C. Beaudoin, J. Beaudoin, R. Beaudoin, B. Beaulac, L.
Beaunoyer, F. Beaver, B. Beck, N. Beck, H. Becker, R. Beckner, S. Beckow, G. Bedi, S. Beebe, M. Beeney, B. Beesley, K. Begg, W. Behnke, A. Belah, G. Belanger,
M. Belanger, R. Belanger, H. Belas, L. Belcourt, R. Belcourt, J. Belik, A. Belisle, C. Bell, D. Bell, J. Bell, N. Bell, S. Bell, R. Bellanger, J. Beller, M. Beller, A. Bellettini,
M. Bembridge, A. Bendahmane, K. Bendahmane, B. Bendick, K. Benner, C. Bennett, E. Bennett, J. Bennett, M. Bennett, R. Bennett, S. Bennett, K. Benoit, B.
Bensmiller, S. Bensmiller, A. Benson- Bartko, C. Bereznicki, D. Berg, J. Berg, K. Bergen, J. Bergeson, B. Bergley, J. Bergstrom, D. Berlinguette, H. Berlinguette, J.
Bernardin, D. Bernardo, P. Berrigan, D. Bershadsky, B. Bertrand, M. Bertsch, C. Best, T. Betteridge, L. Betthel, S. Bettinson, B. Beyer, U. Bhachu, A. Bhadauria, I.
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Gudjonson, J. Guerin, H. Guest, M. Gueye, D. Guglielmin, A. Guillen, A. Gulamhusein, K. Gulamhusein, D. Gulayec, R. Gulutzan, J. Gumbley, C. Gunderson, L. Gunnell, A. Gunst, A. Gupta, S. Gupta, B. Gurba, J. Gurba, M. Gurin, E. Gushnowski, D. Gushue, J. Gushue, T. Gusnowski, G. Gustafson, S. Gustafson,
L. Guzman, S. Gysler, D. Ha, R. Haab, B. Haahr, C. Haas, R. Haberlack, C. Habiak, C. Hachey, J. Hack, V. Haddad, L. Haddleton, L. Hagg, C. Hagstrom, K. Hague, A. Hains, A. Haj Hamdan, S. Hajar, S. Haji, Z. Hajibeygi, D. Halaburda, C. Hales, D. Halewich, J. Halford, D. Hall, E. Hall, J. Hall, M. Hall, R. Hall, T.
Halladay, C. Hallborg, P. Halldorson, D. Hallett, J. Hallett, R. Hallett, P. Hamel, L. Hamende, S. Hamill, J. Hamilton, T. Hamilton, K. Hamm, M. Hammel, G. Hammond, C. Hamori, B. Hamrell, M. Hamula, B. Hancock, B. Hancott, W. Haney, R. Hank, E. Hanlon, E. Hann, K. Hann, G. Hannah, L. Hans, J. Hansen,
M. Hansen, P. Hansen, L. Hanson, B. Harbin, L. Harder, C. Harding, J. Hardy, K. Hargrove, E. Harikumar, J. Harke, K. Harke, J. Harker, B. Harle, B. Harmatiuk, E. Haroldson, G. Harper, A. Harris, B. Harris, J. Harris, M. Harris, S. Harris, C. Harrison, D. Harrison, R. Harsany, D. Hart, D. Harty, J. Harty, T. Harty, A.
Harvey, D. Harvey, G. Harvey, J. Harvey, K. Harvey, R. Harvey, T. Haslanger, M. Hassan, C. Hassenrueck, B. Hassenstein, I. Haston, J. Hatala, C. Hatcher, P. Hatt, G. Hatto, W. Hatton, D. Haub, R. Hauger, W. Hausch, P. Hausmanis, I. Hawco, L. Hawco, S. Hawco, S. Haxton, D. Hayashi, P. HayatNagarkar, B. Hayden,
C. Hayden, C. Hayes, M. Hayes, K. Hayko, D. Haywood, A. Hazen, J. Hazin, T. He, M. Headrick, J. Heagy, A. Heale, B. Hearn, C. Heath, L. Heath, T. Hebel, D. Hebert, L. Hebert, M. Hebert, W. Hebert, T. Heck, J. Hecker, C. Heffner, D. Hefford, C. Hehr, J. Heidinger, S. Heil, C. Hein, R. Hein, R. Heinrichs, T. Helboe,
B. Helliker, R. Helyar, W. Henderson, R. Henley, S. Hennessey, A. Hennig, R. Hennig, A. Henry, R. Henry, D. Herauf, K. Herba, J. Herbison, T. Herdy, B. Herman, J. Herman, J. Hermann, J. Hern, A. Hernandez, G. Hernandez, P. Hernandez, J. Herrada, C. Herring, J. Herron, M. Herron, R. Heska, K. Heslop, B. Hess,
T. Hewitt, D. Hicke, P. Hickey, R. Hickey, K. Hicks, N. Hicks, R. Hicks, M. Hiemstra, T. Hiemstra, R. Higa, A. Higgins, J. Higgins, R. Higgins, D. High, C. Hill, D. Hill, H. Hill, K. Hill, S. Hill, J. Hillier, T. Hillier, T. Hills, R. Hilton, B. Hindmarch, T. Hindson, K. Hingley, K. Hinton, D. Hiscock, D. Hitra, L. Hnatow, G. Ho, M.
Ho, D. Hoar, J. Hoare, W. Hobart, D. Hodder, H. Hodder, J. Hodder, D. Hodge, J. Hoey, B. Hofer, T. Hoff, R. Hoffman, J. Hofmann, S. Hogan, J. Hogg, R. Hogg, S. Hogg, J. Holben, K. Holland, J. Hollas, A. Hollebakken, D. Holley, B. Holloway, D. Holman, R. Holman, H. Holmes, S. Holmes, J. Holowaychuk, D. Holt,
E. Holt, B. Holthe, C. Holthe, J. Holton, D. Hompoth, K. Honar, G. Hook, N. Hook, J. Hooper, Y. Hopkins, N. Hopner, T. Hornberger, K. Hornseth, K. Horvath, R. Horvath, J. Horyn, T. Hoskins, L. Hoskyn, M. Hossain, T. Hostettler, T. Hou, S. Houck, L. Houghton, S. Houle, A. House, T. House, J. Howard, T. Howard,
K. Howe, T. Howell, S. Howlader, D. Howlett, M. Howrish, T. Hoyles, W. Hoyles, R. Hoyt, B. Hoza, T. Hrycay, G. Hu, Y. Hu, H. Huang, J. Huang, N. Huang, Q. Huang, J. Hubelit, K. Huculak, W. Huddlestun, F. Hudec, T. Hudema, D. Hudson, P. Hudson, S. Huebner, K. Huey, D. Hughes, J. Hughes, M. Hughes, E. Huh,
K. Hui, G. Hull, M. Hulme, B. Human, M. Human, J. Humphrey, D. Hunchak, M. Hundal, I. Hundeby, K. Hunter, L. Hunter, R. Hunter, J. Huq, J. Hurd, R. Hurtado, A. Hussain, A. Hussaini, R. Hussynec, L. Huston, D. Hutchinson, K. Hutchinson, R. Hutchinson, C. Hutchison, L. Hutchison, R. Hutscal, E. Hutton, D.
Huxley, A. Huynh, Y. Hwang, A. Hymanyk, S. Hyrcha, G. Iannattone, P. Iannattone, T. Idler, G. Iervella, F. Igbelina, T. Ilie, K. Imlach, G. Imlah, C. Inglis, R. Inglis, S. Inglis, B. Inman, M. Inscho, R. Ireton, M. Irfan, J. Irons, M. Isakeit, C. Isea Natera, D. Isele, M. Ishankuliev, H. Ishaque, F. Isley, G. Ismaguilova, V.
Itulua, A. Ivany, L. Iversen, J. Ivezic, J. Iwamoto, V. Iyengar, L. Jacek, W. Jack, A. Jackson, D. Jackson, K. Jackson, R. Jackson, T. Jackson, M. Jacobs, K. Jacobson, A. Jacula, C. Jacula, M. Jacula, J. Jager, V. Jain, M. Jaindl, R. Jakher, B. Jakulj, S. Jamam, D. Jaman, C. James, J. Jamieson, S. Jamieson, M. Jancewicz,
I. Janeo, A. Janes, L. Janes, J. Jankowski, D. Jans, S. Jansky, P. Janson, S. Janssen, T. Janusc, L. Janzen, I. Jappy, C. Jardine, C. Jarratt, B. Jarvis, J. Jarvis, W. Jarvis, I. Jasper, U. Javaid, R. Jaycock, D. Jeannotte, J. Jeannotte, M. Jegou, W. Jellison, G. Jenkins, T. Jenkins, J. Jenner, D. Jennings, M. Jennings, A. Jensen,
B. Jensen, T. Jensen, D. Jenson, M. Jesso, T. Jessome, D. Jestin, B. Jevne-Dick, P. Jia, S. Jiang, W. Jiang, R. Jimeno, K. Jivraj, M. Joarder, T. Jocksch, G. Joe, J. Joffre, G. Johal, A. Johanness, K. Johannesson, T. Johansen, K. Johansson, B. Johns, D. Johnson, J. Johnson, L. Johnson, M. Johnson, N. Johnson, R.
Johnson, S. Johnson, T. Johnson, A. Johnston, H. Johnston, N. Johnston, C. Johnstone, S. Johnstone, D. Johnston-Watson, V. Jolliffe, J. Jonasson, E. Jones, G. Jones, K. Jones, M. Jones, N. Jones, P. Jones, R. Jones, S. Jones, T. Jones, W. Jones, P. Joo, D. Jordan, L. Jorgensen, A. Joshi, T. Joshi, U. Joshi, J. Josselyn,
S. Josselyn, J. Juan, R. Jubinville, T. Juett, J. Jung, S. Jung, C. Jungen, S. Jungen, R. Jungkind, M. Junio-Read, A. Kachra, C. Kada, T. Kadikoff, M. Kadri, C. Kaglea, R. Kahanyshyn, H. Kahlon, A. Kaid, M. Kalakailo, R. Kalam, S. Kalbag, K. Kalinsky, D. Kalynchuk, Y. Kam, B. Kamath, E. Kaminski, G. Kamon, S.
Kanarek, A. Kandasamy, L. Kane, S. Kane, R. Kanomata, S. Kapeluck, J. Karolat, T. Karpa, J. Karr, K. Kartushyn, D. Kary, J. Kasha, N. Kashirina, L. Kasper, M. Kaspers, S. Kassi, A. Kastelic, M. Kathan, D. Katnick, H. Katrip, A. Katyayan, M. Kaur, S. Kaushik, C. Kavalec, T. Kavalec, R. Kavanagh, O. Kay, G. Kaya,
D. Kazandzhiev, M. Kealey, M. Kearley, K. Kearns, L. Keech, L. Keefe, P. Keele, J. Keith, R. Keith, E. Kellough, M. Kelloway, P. Kelloway, S. Kelsey, S. Kelts, T. Kemmer, A. Kemp, G. Kemp, D. Kendell, R. Kendell, C. Kendrick, R. Kennedy, W. Kennedy, D. Kent, S. Kent, J. Keough, C. Kerpan, C. Kerr, J. Kerr, L. Kerr, R.
Kerr, S. Kerr, S. Kers, B. Kessler, B. Kevol, A. Khan, B. Khan, M. Khan, S. Khan, R. Khatri, S. Khoromskaya, M. Khurshid, S. Kiasosua, G. Kidd, R. Kidmose, K. Kielt, L. Kiez, D. Kilbreath, M. Kilcollins, O. Kilo, S. Kilvington, H. Kim, R. Kim, D. Kimmie, C. Kimura, M. Kinden, B. King, C. King, D. King, G. King, J. King,
K. King, L. King, M. King, R. King, T. King, W. King, T. Kingsbury, P. Kinnear, S. Kinnear, R. Kinney, C. Kinniburgh, M. Kinsman, M. Kinuthia, P. Kip, B. Kirk, M. Kirkwood, B. Kiss, B. Kissel, M. Kissoon, B. Kitsch, C. Kiyawasew, J. Kiziak, C. Klanten, D. Klassen, C. Klatt, B. Klautt, G. Klemak, D. Klimczak, D. Klug,
R. Klys, R. Knee, R. Kneteman, J. Knibbs, M. Kniebel, A. Knight, J. Knight-Ehiwe, W. Knouse, A. Knowles, T. Knox, D. Kobes, R. Kobi, B. Kobzey, B. Koch, P. Koch, E. Koffi, L. Koffi, S. Koffi, B. Koizumi, C. Kolberg, L. Kolberg, R. Kolberg, M. Kolcun, M. Komant, E. Komers, C. Komm, M. Konate, M. Kondor, B.
Kondratowicz, I. Kone, L. Kone, N. Kooistra, J. Kooner, N. Koops, B. Kootenay, S. Korchagin, B. Korolischuk, K. Korotkova, J. Koslowski, B. Kosowan, V. Kostic, D. Kostiuk, K. Kostrub, S. Kostyshen, A. Kostyshyn, B. Kotchi, K. Kotkas, M. Kotty, D. Kotze, M. Koua, P. Kouadio, A. Kouakou, D. Kouame, G. Koumba
Lendoye, M. Koutou, K. Kovac, M. Kovac, R. Kovalenko, R. Kowalski, S. Kowalsky, D. Kowbel, K. Kowbel, D. Kozak, E. Kozakevich, T. Kozina, A. Kozlowski, B. Kozuback, M. Kramer, D. Kramps, T. Kratz, G. Krause, L. Krause, T. Krause, C. Krawchuk, H. Krawec, J. Krawetz, M. Krawetz, T. Kreics, D. Krein, M.
Kreiser, M. Krekhovetski, A. Krentz, D. Krentz, B. Kress, K. Krewulak, C. Kriaski, A. Krishnamoorthy, R. Krishnamurthy, N. Krochmal, D. Kroeger, R. Kroeker, M. Kroetsch, K. Krogh, P. Krol, U. Krstic, R. Krueger, J. Kruse, E. Krywolt, C. Kucinar, G. Kucy, R. Kuka, M. Kulkarni, C. Kully, B. Kumar, J. Kumar, S. Kumar,
V. Kumar, C. Kung, D. Kung, D. Kunitz, D. Kuntz, J. Kuntz, T. Kuntz, J. Kuorikoski, P. Kuppers, M. Kureshi, K. Kursteiner, D. Kurtz, F. Kurucz, J. Kushe, B. Kutash, S. Kuzmak, C. Kwan, K. Kwan, R. Kwan, A. Kwiatkowski, K. Kwiatkowski, R. Kwiatkowski, A. Kwon, K. Kyffin, D. Kyle, B. Kyllo, D. Labby, T. Laberge, J.
Laboucan, R. Laboucan, G. Lacey, A. LaChance, N. Lachance, R. Lackey, G. Lackner, P. Lacoste-Bouchet, M. Lacourciere, D. Lacroix, L. Lacuna, J. Ladner, B. Lafferty, A. Laflamme, L. Lafrance, L. Lafreniere, A. Laguduva, D. Laha, C. Lai, P. Lai, R. Lai, T. Lai, E. Laidlaw, K. Laidler, J. Laight, A. Laing, R. Laing, M.
Lake, J. Lakes, C. Lakshmanan, P. Lalani, M. Lalji, M. Lalonde, C. Lam, E. Lam, I. Lam, R. Lam, S. Lam, K. Lamb, T. Lamb, J. Lambert, D. Lameman, R. Lameman, J. Lamontagne, S. Lamontagne, W. Lamoureux, W. Lamptey, A. Landry, C. Landry, E. Landry, M. Landry, S. Landry, Y. Landry, S. Lane, R. Lanfranchi,
G. Langan, J. Lange, S. Langford, W. Langford, T. Langill, J. Langille, M. Langlois, C. Langpap, B. Lanh, O. Lanktree, T. Lanktree, M. Lanktree-Ray, G. Lanteigne, H. LaPointe, C. Lapp, P. Lapp, G. Laramee, M. LaRochelle, A. Larocque, E. LaRose, L. LaRose, D. Larsh, R. Larson, B. Larsson, R. Laseur, J. LaSha, N.
Lashley, W. Latchuk, C. Latimer, P. Latus, I. Lau, J. Lau, M. Laudel, D. Laurenson, K. Laurenson, P. Laurie, K. Laurin, N. Laustsen, S. Laut, A. Lavallee, R. Lavallee, V. Laviano, A. Lavigne, J. Lavigne, A. Lavoie, I. Law, S. Lawlor, B. Lawrence, D. Lawrence, E. Lawrence, F. Lawrence, L. Lawrence, R. Lawrence, S.
8
CANADIAN NATURAL
2012 ANNUAL REPORT
Lawrence, G. Lawson, J. Laya, D. Laycock, A. Layland, K. Layland, P. Layland, S. Layton, G. Lazaruk, L. Le, M. Le, N. Le, T. Le, W. Lea, B. Leach, T. Leach, K. Leamon,
N. Lebedynsky, E. LeBlanc, R. Leblanc, R. LeBoutillier, C. Lebrun, S. Leckie, S. Leclerc, C. Ledrew, A. Lee, D. Lee, H. Lee, J. Lee, L. Lee, M. Lee, P. Lee, R. Lee, T. Lee,
B. Leeman, D. Lefrancois, F. Legacy, D. Legault, K. Legault, L. Legault, H. Leggett, M. LeGrow, W. Lehman, K. Lehocky, D. Lehouillier, M. Lehouillier, B. Leidal, P.
Leighton, Z. LeMoine, T. Lemon, R. Lendrum, C. Lenz, T. Leon, H. Leonard, A. Leonardo, G. Leong, H. Leong, S. Lepp, P. Lepper, Y. Lerner, E. Leroy, G. Leslie, R.
Leslie, S. Lester, B. Lesyk, M. Lethaby, P. Letkeman, H. Lett, M. Leugner, D. Leung, J. Leung, K. Leung, P. Leung, Y. Leung, K. Levasseur, T. Levasseur, T. Leveille, A.
Leveque, J. Levesque, K. Levesque, R. Levesque, S. Lewchuk, T. Lewis, W. Leyland, J. L’Hirondelle, T. L’Hirondelle, H. Li, J. Li, L. Li, X. Li, C. Liba, Z. Licastro, J. Lieske,
J. Lieverse, D. Lilburn, H. Lim, M. Lim, F. Lin, J. Lin, Q. Lin, B. Lind, T. Lindley, E. Lindsay, S. Lindstrand, D. Linfoot, K. Lingat, R. Lins, J. Linton, M. Liou-McKinstry,
R. Liske, J. Little, S. Little, T. Little, C. Liu, H. Liu, L. Liu, X. Liu, J. Liu Prest, J. Livingston, C. Lizee, D. Lloyd, T. Lloyd, K. Lo, Y. Lo, E. Lobo, C. Loch, F. Locke, L. Lockhart,
C. Loder, J. Lodoen, R. Loewen, J. Lofendale, C. Lofstrom, C. Logan, S. Logan, K. Loganathan, D. Loggie, R. Logozar, K. Lomond, C. Long, L. Long, W. Longmore,
D. Longpre, C. Longston, M. Longtin, K. Loo, W. Lopez, N. Lord, C. Lorenson, N. Lorentz, M. Lorincz, B. Lorinczy, K. Lorteau, A. Lortie, J. Los, J. Lotito, M. Lotito,
M. Lougheed, A. Loughran, S. Lounsbury, W. Loutit, J. Lovas, C. Love, M. Love, E. Lovell, D. Lowe, J. Lowen, L. Loyola, E. Lozano, J. Lu, W. Lu, G. Lucas, S. Lucci,
L. Luciow, E. Ludwig, M. Luery, C. Luk, J. Lukan, W. Lundell, S. Lundquist, E. Lunn, C. Lunzmann, X. Luo, M. Lupul, J. Luscombe, J. Lush, R. Lusk, K. Lussier, L.
Lussier, R. Lutchman, D. Lutwick, J. Lutyck, K. Lutz, G. Lyall, K. Lyall, T. Lychuk, K. Lynam, J. Lyons, N. Lyons, A. Ma, C. Ma, H. Ma, N. Maawia, P. MacCrimmon,
D. MacDermott, A. Macdonald, D. MacDonald, F. MacDonald, J. MacDonald, R. MacDonald, C. MacEachern, Y. Macedo, K. Machado Rodriguez, S. MacHale,
J. Maciejewski, T. MacInnes, A. MacInnis, J. MacInnis, C. Mack, S. Mack, G. MacKay, K. MacKay, R. Mackay, S. MacKay, R. Mackelvie, G. MacKenzie, J.
MacKenzie, K. MacKenzie, S. MacKenzie, T. Mackenzie, B. MacKey, A. MacKinnon, B. MacKinnon, J. MacKinnon, P. MacKinnon, T. MacKinnon, G. Mackintosh,
P. Mackintosh, R. MacKnight, C. MacLean, K. MacLean, M. MacLean, S. MacLean, T. MacLean, G. MacLellan, J. MacLellan, M. MacLellan, J. MacLennan, C.
MacLeod, J. MacLeod, T. MacLeod, W. MacLeod, D. MacMillan, B. MacNeil, D. MacNeil, B. MacNeill, A. MacNiven, S. MacQueen, H. MacRae, R. MacRae, M.
MacRitchie, D. Madoche, G. Madore, H. Madore, R. Madore, T. Madro, G. Madsen, J. Maedel, M. Maennchen, L. Maga, H. Magee, M. Magnusson, V. Magsila,
N. Maguire, S. Maguire, B. Mah, D. Mah, R. Mah, D. Mahal, K. Mahboobi, D. Maidment, T. Mailandt, M. Mailhot, D. Maillet, E. Maillet, P. Mailloux, S. Majdnia,
A. Majidi, A. Mak, M. Makhoul, D. Makin, M. Makin, G. Makumbe, A. Malabad, D. Malabad, E. Malabad, J. Malaryk, M. Malech, T. Malkova, J. Mallard, S.
Mallay, G. Malo, L. Maloney, T. Maloney, A. Maltseva, S. Mamedov, A. Mamfoumbi, F. Manangu, D. Mandley, L. Mandrusiak, D. Manengyao, D. Mann, G. Mann,
J. Manning, A. Mansell, I. Manson, R. Mantei, E. Mantilla, G. Manuel, L. Manzano Weffer, H. Maralli, N. Maralli, N. Marchand, V. Marcheggiani-Croden, C.
Marchuk, L. Marchuk, R. Marcichiw, T. Marcotte, L. Marcucci, S. Marin, P. Marinzi, S. Marion, D. Mark, K. Markstrom, M. Markussen, C. Maron, D. Marr, B.
Marsh, P. Marsh, R. Marsh, D. Marshall, S. Marshall, S. Marshman, L. Martel, B. Martin, C. Martin, D. Martin, K. Martin, L. Martin, R. Martin, H. Martin De
Bartolome, D. Martinez, R. Martinez, M. Martynuik, J. Maruniak, K. Mashayekh, C. Mason, J. Mason, K. Mason, W. Mason, M. Massiah, A. Massicotte, P.
Massicotte, A. Matchem, D. Matheson, K. Matheson, L. Mathew, K. Mathews, K. Mathieson, R. Mathieson, D. Matthews, N. Matthews, S. Maurice, D. Mavridis,
D. Mavuwa, A. Mawer, T. Maxwell, R. May, S. Mayer, T. Maynard, K. Mayner, B. Mayo, M. Mazac, M. McAlpine, N. McBain, A. McBoyle, R. McBrien, G. McCabe,
N. McCabe, S. McCaffrey, R. McCallum, S. McCann, D. McClelland, C. McColl, B. McConachie, B. McCormack, M. McCotter, S. McCracken, K. McCrae, C.
McCrea, B. McCullough, C. McCullough, P. McDade, K. McDavid, C. McDonald, E. McDonald, K. McDonald, S. McDonald, R. McDougall, K. McEachern, M.
McElroy, P. McElwain, J. McEwen, W. McEwen, C. McFarlane, M. McFarlane, B. McFaul, A. McGann, D. McGee, G. McGinnis, F. McGlynn, R. McGowan, A.
McGrath, B. McGrath, C. McGrath, M. McGrath, J. McGregor, P. McGregor, S. McGregor, J. McGuckin, S. McHardy, G. McHattie, L. McHugh, A. McIntosh, G.
McIntosh, J. McIntosh, A. McIntyre, B. McIntyre, J. McIntyre, C. McIver, T. McKague, B. McKay, C. McKay, G. McKay, J. McKay, K. McKay, S. McKay, T. McKay, T.
McKeage, D. McKee, S. McKee, K. McKelvey, B. McKendry, K. McKendry, N. McKendry, R. McKendry, J. McKenna, M. McKenna, P. McKenna, A. McKenzie, B.
McKenzie, K. McKenzie, M. McKenzie, K. McKie, S. McKinney, S. McKinnon, A. McKinstry, K. McLaughlin, M. McLaughlin, J. McLean, M. McLean, N. McLean,
R. McLean, W. Mclean, J. McLellan, T. McLellan, C. McLeman, M. McLenehan, R. McLennan, C. McLeod, D. McLeod, I. McLeod, K. McLeod, S. McLeod, E.
McMahon, L. McMahon, B. McMann, K. McMann, B. McManus, J. McMaster, S. McMichael, C. McNabb, R. McNair, D. McNamara, R. McNeil, S. McNeill, R.
McNinch, E. McNulty, G. McNulty, P. McNulty, R. McPhail, J. McPherson, C. McQuaker, H. McQuillen, L. McQuiston, K. McRae, R. McRae, S. McRitchie, A.
McSharry, J. McTamney, M. McTurk, C. McWhan, M. Meakes, I. Medina, N. Medina, P. Mehrabi, J. Mehta, N. Mehta, R. Mehta, C. Mei, J. Mejia, D. Melanson,
R. Melanson, E. Meldrum, L. Mello, G. Mellom, D. Melnyk, M. Melnyk, A. Menard, P. Mendes, S. Mendiratta, N. Meneses, C. Mercer, T. Merk, G. Merkel, D.
Merkley, A. Merle, J. Merlo, C. Merritt, N. Merritt, U. Meservy, M. Mesquita, S. Metcalfe, R. Metz, R. Meunier, S. Meunier, E. Meynin, I. Meynin, C. Michalko, E.
Michaluk, G. Michaud, K. Michener, C. Michie, M. Michie, J. Michiels, D. Midgley, K. Mielty, J. Mihai, M. Mihilova, T. Mijic, J. Mikalsky, A. Mikhailov, J. Miko, G.
Milan Garcia, A. Milib, C. Millar, D. Millar, B. Miller, D. Miller, G. Miller, J. Miller, L. Miller, R. Miller, T. Miller, V. Miller, D. Milligan, H. Mills, S. Mills, J. Milne, J.
Minard, A. Minett, M. Mineur, F. Mingle, A. Minhas, S. Minhas, J. Minick, M. Minick, W. Minni, D. Mino, M. Mintenko, K. Minter, A. Minty, A. Mir, W. Mirabal,
M. Mirzadeh, J. Mistecki, S. Mistecki, A. Mitangou, C. Mitchell, D. Mitchell, G. Mitchell, J. Mitchell, N. Mitchell, S. Mitchell, W. Mitchell, Y. Mitchell, A. Mitha, G.
Mitha, A. Mitroi, L. Miura, D. Mocodean, T. Moen, I. Moffat, J. Moffat, K. Moffatt, A. Mognin, S. Moh, A. Mohamed, M. Mohamed, B. Mohammed, B. Moini,
D. Moir, L. Mok, N. Molina, J. Moll, J. Molnar, R. Monahan, P. Monette, P. Montague, F. Montefresco-Gentile, N. Monteiro, R. Monteith, F. Montenegro, V.
Montenegro, N. Montes, M. Montinola, J. Moodie, K. Moon, D. Moore, E. Moore, L. Mora, J. Morales Miller, C. Moran, J. Moravec, A. Morelli, J. Morency-Letto,
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Thomas, I. Thomas, L. Thomas, A. Thompson, C. Thompson, D. Thompson, G. Thompson, H. Thompson, I. Thompson, K. Thompson, M. Thompson, S. Thompson,
P. Thomsen, A. Thomson, B. Thomson, J. Thomson, M. Thomson, R. Thomson, T. Thorburn, J. Thorleifson, D. Thorne, E. Thornton, K. Thornton, D. Thurman, S. Tieh,
P. Tieu, B. Tiffin, G. Tighe, R. Tilford-Njaa, M. Tilford-Shaw, D. Tillapaugh, K. Tillotson, T. Tillotson, N. Timm, D. Timms, S. Timothy, N. Tindall, M. Tineo, M. Tinsley,
B. Tipton, D. Tiwary, R. Tiwary, E. To, J. Tobin, N. Tobin, K. Tobler, A. Tokpa, D. Tomar, S. Tomchak, C. Tomlinson, D. Tomlinson, L. Tomlinson, A. Tomszak, M. Tonon,
S. Topolnitsky, K. Tordon, L. Torrance, P. Torrance, C. Torres, D. Torriero, M. Tosio, D. Toullelan, O. Tozser, C. Tran, R. Trant, B. Trask, L. Trautman, J. Trebon, W.
Trelinski, E. Tremblay, J. Tremblay, A. Tremblett, C. Tremblett, D. Trentham, J. Trifaux, W. Trimble, D. Trinh, A. Trombley, S. Trottier, R. Trudel, A. Truefitt, R. Truter, P.
Tso, Y. Tu, R. Tucker, D. Tuite, J. Tuite, S. Tulan, N. Tulloch, B. Tumbach, N. Tumu, T. Turbide, J. Turcotte, T. Turgeon, D. Turnbull, M. Turnbull, B. Turner, D. Turner, R.
Turner, S. Turner, B. Turpin, D. Turpin, V. Turska, S. Turton, M. Tustian, S. Tuttle, I. Tutto, G. Twin, O. Tyan, A. Tyler, E. Tylosky, L. Tymchuk, W. Tymchuk, D. Tyner, P.
Tyrer, I. Uche-Ezeala, E. Ukat, S. Ulloa, E. Ulrich, G. Ulrich, J. Umali, O. Umana, C. Umpherville, J. Underdahl, N. Underwood, T. Ung, K. Unger, J. Unrau, U.
Upadhyaya, L. Urbina, J. Urdaneta, C. Urlacher, A. Vagianou, G. Valiquette, D. Vallee, L. Vallee, M. Vallee, W. Vallee, A. Valmadrid, D. Van Brunt, W. Van den Oever,
M. van der Burgh, V. Van Der Merwe, J. Van Es, L. van Heerden, S. Van Rensburg, C. Van Schoor, C. Vanberg, C. Vander Pyl, M. Vandette, M. Vankosky, C. Vare,
L. Varela Avendano, M. Varga, S. Varga, D. Varty, A. Vasquez, M. Vasquez de Placid, J. Vasseur, A. Vaughan, N. Vaughan, J. Veale, B. Velagapudi, B. Velichka, S.
Venkitadri, J. Vera, S. Verigin, D. Verleyen, A. Verma, B. Verreau, N. Vetrici, C. Viana, G. Vibert, S. Vicic, N. Vick, B. Vickery, J. Villemaire, R. Vinkle, D. Vipond, B.
Virus, G. Virus, M. Virus, A. Visotto, T. Vitkunas, N. Vizcuna Alvarado, M. Vogan, A. Volk, K. Volk, J. Vollman, M. Vollman, W. Volschenk, E. von Hertzberg, L.
Vondermuhll, B. Von-Grat, C. Voortman, A. Votta, B. Vye, G. Wack, E. Waddell, K. Waddell, C. Wadden, K. Waddy, G. Wafler, V. Wagar, T. Waggoner, T. Wagil, C.
Wagner, J. Wagner, A. Waheed, L. Wahl, D. Wakaruk, A. Walchuk, D. Waldner, D. Waldo, D. Walker, J. Walker, T. Walker, D. Wall, B. Wallace, C. Wallace, E. Wallace,
H. Wallace, T. Walle, R. Wallebeck, V. Wallwork, P. Walsh, R. Walsh, S. Walsh, L. Walter, A. Walters, S. Walton, L. Wang, M. Wang, Q. Wang, S. Wang, W. Wang,
X. Wang, Z. Wang, B. Wangler, D. Wannas, K. Warcimaga, D. Ward, K. Ward, S. Warden, W. Warholik, C. Wark, W. Warman, F. Warraich, J. Warren, F. Warrington,
P. Wassell, J. Waterfield, D. Watkin, B. Watson, C. Watson, D. Watson, K. Watson, S. Watson, C. Watt, D. Watt, G. Watt, J. Watts, S. Wayte, H. Weaver, L. Weaving,
A. Webb, B. Webb, G. Webb, P. Webb, D. Webber, K. Webster, B. Wei, J. Weibrecht, D. Weimer, C. Weingarten, R. Weir, G. Weisbeck, B. Weisgerber, M. Welland,
T. Welland, B. Wellman, B. Wells, D. Wells, J. Welsh, L. Welsh, G. Welwood, Z. Wen, G. Weng, M. Wenner, D. Werle, C. Werstiuk, B. Weslake, T. Wesley, D. West, M. Westad, K. Westland, R. Westland, D.
Weston, T. Wetzstein, N. Whalen, T. Whalen, D. Wheating, C. Wheaton, J. Wheaton, A. Wheeler, S. Wheeler, C. Whelan, R. Whelan-Maloney, J. Whidden, P. Whitaker, D. White, F. White, J. White, N. White,
R. White, S. White, T. White, D. Whitehouse, S. Whiteley, C. Whitford, C. Whitson, M. Whittaker, M. Whittingham, H. Whynot, M. Wiebe, T. Wiebe, D. Wiens, C. Wietzel, Z. Wigglesworth, S. Wight, D.
Wijesingha, B. Wilbern, M. Wilcox, B. Wild, R. Wild, D. Wilde, L. Wilde, J. Wilding, D. Wiles, J. Wilhelm, C. Wilk, T. Wilk, C. Wilkes, M. Wilkie, K. Wilkinson, G. Will, P. Will, E. Willard, S. Willette, B. Williams,
D. Williams, G. Williams, J. Williams, S. Williams, T. Williams, W. Williams, A. Williamson, C. Williamson, D. Williamson, K. Williamson, M. Williamson, B. Willick, J. Willick, B. Willis, M. Willis, R. Willis, D.
Willms, C. Willson, C. Wilson, D. Wilson, G. Wilson, J. Wilson, M. Wilson, P. Wilson, R. Wilson, W. Wilson, J. Wilton, A. Winfield, A. Wingert, B. Winiarz, J. Winquist, D. Winship, R. Winslow, C. Winsor, J.
Winsor, G. Winters, G. Wirachowsky, R. Wirtanen, M. Wiseman, P. Wiseman, I. Wishart, M. Witmer, D. Wittman, C. Wlad, K. Woidak, R. Wojtowicz, S. Wolf, E. Wolfe, C. Woloshyn, B. Wolstoncroft, J. Wolter,
R. Wolters, A. Wong, C. Wong, J. Wong, L. Wong, C. Woo, J. Woo, K. Woo, L. Woo, L. Wood, P. Wood, R. Wood, S. Wood, T. Wood, M. Woodfin, T. Woodford, A. Woodger, B. Woodman, A. Woods, T. Woods,
M. Woodske, S. Woolfitt, R. Woolner, L. Worobetz, S. Wosnack, H. Wossey Ogandaga Mbourou, W. Wostradowski, R. Wourms, L. Wright, R. Wright, S. Wright, T. Wruth, B. Wu, J. Wu, M. Wu, K. Wutzke,
B. Wychopen, B. Wyllie, G. Wyndham, V. Wyonzek, L. Wysoki, B. Wyton, J. Xu, Q. Xu, Z. Xu, M. Xue, K. Yakimowich, C. Yang, D. Yang, J. Yang, L. Yang, Z. Yang, M. Yanota, L. Yao, A. Yaremko, R. Yarmuch,
J. Yaroslawsky, S. Yasin, B. Yates, J. Yawney, B. Yeboue, B. Yee, C. Yeoman, J. Yeon, P. Yepes, J. Yip, K. Yip, M. Yobb, Y. Yohanna, D. York, D. Youck, B. Young, C. Young, D. Young, K. Young, L. Young, P. Young,
S. Young, E. Yu, M. Yu, P. Yuan, Q. Yue, C. Yuen, D. Yuill, J. Yuill, W. Yuill, R. Zabek, A. Zacharias, T. Zachoda, C. Zackowski, D. Zahara, K. Zahara, S. Zakeri, G. Zambrano, C. Zaparyniuk, D. Zarowny, K.
Zarowny, L. Zeidler, T. Zeiser, D. Zelman, A. Zenide, W. Zeniuk, G. Zeran, J. Zerpa, K. Zerr, M. Zerr, B. Zevin, K. Zeyha, R. Zgierski, J. Zhang, Q. Zhang, X. Zhang, Y. Zhang, B. Zhao, C. Zhao, D. Zhao, L. Zhao,
M. Zhekov, G. Zheng, S. Zheng, Z. Zheng, S. Zhong, H. Zhou, Q. Zhou, X. Zhou, L. Zhu, W. Zhu, E. Zhuromsky, S. Ziadeh, B. Ziegler, D. Zilinski, M. Ziolkowski, J. Zizek, C. Zoller, L. Zseder, G. Zubiak, A.
Zubot, J. Zuk, N. Zukiwski, J. Zwolak
CANADIAN NATURAL
2012 ANNUAL REPORT
9
YEAR-END RESERVES
Determination of Reserves
For the year ended December 31, 2012 the Company retained
Independent Qualified Reserves Evaluators (“Evaluators”), Sproule
Associates Limited, Sproule International Limited (together as
“Sproule”) and GLJ Petroleum Consultants Ltd. (“GLJ”), to evaluate
and review all of the Company’s proved and proved plus probable
reserves. Sproule evaluated the Company’s North America and
International crude oil, 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
North America Company Gross proved plus probable crude
oil, bitumen and NGL reserves increased 16% to 3.08 billion
barrels. Company Gross proved plus probable natural gas
reserves decreased 5% to 5.57 Tcf. Total proved plus probable
BOE increased 11% to 4.01 billion barrels.
North America Company Gross proved reserve additions and
revisions, including acquisitions, were 230 million barrels of
crude oil, bitumen and NGL and 157 billion cubic feet of natural
gas for 256 million BOE. The total proved reserve replacement
ratio is 133%. The total proved reserve life index in 14.3 years.
North America Company Gross proved plus probable
reserve additions and revisions, including acquisitions, were
548 million barrels of crude oil, bitumen and NGL and
174 billion cubic feet of natural gas for 577 million BOE. The
total proved plus probable reserve replacement ratio was
299%. The total proved plus probable reserve life index is
23.8 years.
Company Gross proved crude oil, SCO, bitumen and NGL
reserves increased 6% to 4.33 billion barrels. Company Gross
proved natural gas reserves decreased 7% to 4.14 Tcf. Total
proved reserves increased 4% to 5.02 billion BOE.
Proved undeveloped crude oil, bitumen and NGL reserves
accounted for 38% of the North America total proved reserves
and proved undeveloped natural gas reserves accounted for 8%
of the North America total proved reserves.
Company Gross proved plus probable crude oil, SCO, bitumen
and NGL reserves increased 6% to 6.92 billion barrels.
Company Gross proved plus probable natural gas reserves
decreased 5% to 5.79 Tcf. Total proved plus probable reserves
increased 5% to 7.89 billion BOE.
Company Gross proved reserve additions and revisions, including
acquisitions, were 404 million barrels of crude oil, SCO, bitumen
and NGL and 135 billion cubic feet of natural gas for 426 million
BOE. The total proved reserve replacement ratio was 178%. The
total proved reserve life index is 22.8 years.
Company Gross proved plus probable reserve additions and
revisions, including acquisitions, were 565 million barrels of
crude oil, bitumen, SCO and NGL and 132 billion cubic feet of
natural gas for 587 million BOE. The total proved plus probable
reserve replacement ratio was 246%. The total proved plus
probable reserve life index is 35.8 years.
Proved undeveloped crude oil, SCO, bitumen and NGL reserves
accounted for 31% 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 7% to 1.74 billion barrels. Company
Gross proved natural gas reserves decreased 7% to 3.99 Tcf. Total
proved BOE increased 3% to 2.41 billion barrels.
Thermal oil Company Gross proved reserves increased 9% to
1,066 million barrels primarily due to category transfers from
probable undeveloped to proved undeveloped at Kirby North
and new proved undeveloped additions at Primrose and Wolf
Lake. Proved bitumen reserve additions and revisions were
128 million barrels. Total proved plus probable bitumen
reserves increased 23% to 2,122 million barrels primarily due
to proved plus probable undeveloped additions at Primrose
and Wolf Lake and probable undeveloped additions at Grouse.
Company Gross proved plus probable bitumen reserves
additions and revisions were 432 million barrels.
North America Oil Sands Mining and Upgrading
Company Gross proved synthetic crude oil reserves increased
6% to 2.26 billion barrels.
Proved reserve additions and revisions were 167 million barrels
primarily due to additional stratigraphic wells drilled in the
north pit.
International Exploration and Production
North Sea Company Gross proved reserves decreased 2%
to 240 million BOE primarily due to production. North
Sea Company Gross proved plus probable reserves are
349 million BOE.
Offshore Africa Company Gross proved reserves decreased
7% to 115 million BOE primarily due to production. Offshore
Africa Company Gross proved plus probable reserves are
177 million BOE.
10
CANADIAN NATURAL
2012 ANNUAL REPORT
Summary of Company Gross Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
Light and
Medium
Crude Oil
(MMbbl)
Primary
Heavy
Crude Oil
(MMbbl)
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
Bitumen
(Thermal
Oil)
(MMbbl)
Synthetic
Crude Oil
(MMbbl)
Natural
Gas
(Bcf)
Natural
Gas
Liquids
(MMbbl)
Barrels
of Oil
Equivalent
(MMBOE)
North America
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
North Sea
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
Offshore Africa
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
Total Company
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
92
2
19
113
51
164
49
14
164
227
105
332
65
–
38
103
55
158
206
16
221
443
211
654
85
23
96
204
80
284
217
11
39
267
105
372
238
104
724
1,066
1,056
2,122
1,837
–
418
2,255
1,096
3,351
2,664
213
1,108
3,985
1,589
5,574
53
3
38
94
44
138
2,966
178
1,519
4,663
2,697
7,360
3
55
24
82
20
102
56
–
13
69
42
111
49
23
168
240
109
349
75
–
40
115
62
177
85
23
96
204
80
284
217
11
39
267
105
372
238
104
724
1,066
1,056
2,122
1,837
–
418
2,255
1,096
3,351
2,723
268
1,145
4,136
1,651
5,787
53
3
38
94
44
138
3,090
201
1,727
5,018
2,868
7,886
CANADIAN NATURAL
2012 ANNUAL REPORT
11
Summary of Company Net Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
Light and
Medium
Crude Oil
(MMbbl)
Primary
Heavy
Crude Oil
(MMbbl)
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
Bitumen
(Thermal
Oil)
(MMbbl)
Synthetic
Crude Oil
(MMbbl)
Natural
Gas
(Bcf)
Natural
Gas
Liquids
(MMbbl)
Barrels
of Oil
Equivalent
(MMBOE)
71
19
82
172
64
236
170
10
32
212
75
287
179
83
564
826
801
1,627
1,516
2,394
–
375
1,891
835
2,726
178
968
3,540
1,367
4,907
37
2
30
69
34
103
2,453
145
1,260
3,858
2,079
5,937
3
55
24
82
20
102
39
–
9
48
28
76
49
23
168
240
109
349
61
–
32
93
47
140
71
19
82
172
64
236
170
10
32
212
75
287
179
83
564
826
801
1,627
1,516
–
375
1,891
835
2,726
2,436
233
1,001
3,670
1,415
5,085
37
2
30
69
34
103
2,563
168
1,460
4,191
2,235
6,426
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
81
1
16
98
42
140
49
14
164
227
105
332
55
–
30
85
42
127
185
15
210
410
189
599
12
CANADIAN NATURAL
2012 ANNUAL REPORT
Reconciliation of Company Gross Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
PROVED
North America
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
North Sea
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
Offshore Africa
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
Total Company
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
Light and
Medium
Crude Oil
(MMbbl)
Primary
Heavy
Crude Oil
(MMbbl)
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
Bitumen
(Thermal
Oil)
(MMbbl)
Synthetic
Crude Oil
(MMbbl)
Natural
Gas
(Bcf)
Natural
Gas
Liquids
(MMbbl)
Barrels
of Oil
Equivalent
(MMBOE)
114
–
4
5
–
1
–
–
4
(15)
113
228
–
–
–
–
–
–
4
2
(7)
227
109
–
–
1
–
–
–
–
–
(7)
103
451
–
4
6
–
1
–
4
6
(29)
443
175
–
24
20
–
–
–
–
31
(46)
204
276
–
1
–
5
–
–
–
(1)
(14)
267
974
–
68
10
–
–
–
–
50
(36)
1,066
2,119
–
–
–
–
–
–
14
153
(31)
2,255
4,266
6
52
16
–
43
(1)
(38)
79
(438)
3,985
98
–
–
–
–
–
–
1
(16)
(1)
82
83
–
–
–
–
–
–
–
(7)
(7)
69
175
–
24
20
–
–
–
–
31
(46)
204
276
–
1
–
5
–
–
–
(1)
(14)
267
974
–
68
10
–
–
–
–
50
(36)
1,066
2,119
–
–
–
–
–
–
14
153
(31)
2,255
4,447
6
52
16
–
43
(1)
(37)
56
(446)
4,136
95
–
2
1
–
1
–
(1)
5
(9)
94
95
–
2
1
–
1
–
(1)
5
(9)
94
4,464
1
107
39
5
9
–
7
255
(224)
4,663
244
–
–
–
–
–
–
4
(1)
(7)
240
123
–
–
1
–
–
–
–
(1)
(8)
115
4,831
1
107
40
5
9
–
11
253
(239)
5,018
CANADIAN NATURAL
2012 ANNUAL REPORT
13
Reconciliation of Company Gross Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
PROBABLE
North America
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
North Sea
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
Offshore Africa
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
Total Company
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
14
CANADIAN NATURAL
2012 ANNUAL REPORT
Light and
Medium
Crude Oil
(MMbbl)
Primary
Heavy
Crude Oil
(MMbbl)
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
Bitumen
(Thermal
Oil)
(MMbbl)
Synthetic
Crude Oil
(MMbbl)
Natural
Gas
(Bcf)
Natural
Gas
Liquids
(MMbbl)
Barrels
of Oil
Equivalent
(MMBOE)
41
–
4
6
–
–
–
–
–
–
51
121
–
–
–
–
–
–
(4)
(12)
–
105
56
–
–
1
–
–
–
–
(2)
–
55
218
–
4
7
–
–
–
(4)
(14)
–
211
74
–
10
8
–
–
–
–
(12)
–
80
112
–
–
–
3
–
–
–
(10)
–
105
752
–
277
5
–
–
–
–
22
–
1,056
1,236
–
–
–
–
–
–
(11)
(129)
–
1,096
1,572
5
38
10
–
15
(2)
(2)
(47)
–
1,589
36
–
–
–
–
–
–
(1)
(15)
–
20
46
–
–
–
–
–
–
–
(4)
–
42
74
–
10
8
–
–
–
–
(12)
–
80
112
–
–
–
3
–
–
–
(10)
–
105
752
–
277
5
–
–
–
–
22
–
1,056
1,236
–
–
–
–
–
–
(11)
(129)
–
1,096
1,654
5
38
10
–
15
(2)
(3)
(66)
–
1,651
39
–
3
–
–
–
–
–
2
–
44
39
–
3
–
–
–
–
–
2
–
44
2,516
1
301
20
3
3
(1)
(11)
(135)
–
2,697
127
–
–
–
–
–
–
(4)
(14)
–
109
64
–
–
1
–
–
–
–
(3)
–
62
2,707
1
301
21
3
3
(1)
(15)
(152)
–
2,868
Reconciliation of Company Gross Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
PROVED PLUS PROBABLE
Light and
Medium
Crude Oil
(MMbbl)
Primary
Heavy
Crude Oil
(MMbbl)
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
Bitumen
(Thermal
Oil)
(MMbbl)
Synthetic
Crude Oil
(MMbbl)
Natural
Gas
(Bcf)
Natural
Gas
Liquids
(MMbbl)
Barrels
of Oil
Equivalent
(MMBOE)
North America
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
North Sea
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
Offshore Africa
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
Total Company
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
155
–
8
11
–
1
–
–
4
(15)
164
349
–
–
–
–
–
–
–
(10)
(7)
332
165
–
–
2
–
–
–
–
(2)
(7)
158
669
–
8
13
–
1
–
–
(8)
(29)
654
249
–
34
28
–
–
–
–
19
(46)
284
388
–
1
–
8
–
–
–
(11)
(14)
372
1,726
–
345
15
–
–
–
–
72
(36)
2,122
3,355
–
–
–
–
–
–
3
24
(31)
3,351
249
–
34
28
–
–
–
–
19
(46)
284
388
–
1
–
8
–
–
–
(11)
(14)
372
1,726
–
345
15
–
–
–
–
72
(36)
2,122
3,355
–
–
–
–
–
–
3
24
(31)
3,351
5,838
11
90
26
–
58
(3)
(40)
32
(438)
5,574
134
–
–
–
–
–
–
–
(31)
(1)
102
129
–
–
–
–
–
–
–
(11)
(7)
111
6,101
11
90
26
–
58
(3)
(40)
(10)
(446)
5,787
134
–
5
1
–
1
–
(1)
7
(9)
138
134
–
5
1
–
1
–
(1)
7
(9)
138
6,980
2
408
59
8
12
(1)
(4)
120
(224)
7,360
371
–
–
–
–
–
–
–
(15)
(7)
349
187
–
–
2
–
–
–
–
(4)
(8)
177
7,538
2
408
61
8
12
(1)
(4)
101
(239)
7,886
CANADIAN NATURAL
2012 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)
2013
2014
2015
2016
2017
$
$
$
$
$
$
$
$
89.63 $
69.33 $
84.55 $
90.53 $
89.93 $
74.57 $
89.84 $
96.19 $
88.29 $
73.21 $
88.21 $
94.44 $
95.52 $
80.17 $
95.43 $
102.18 $
96.96
81.37
96.87
103.71
106.42 $
101.65 $
97.56 $
105.07 $
106.65
3.31 $
3.25 $
3.65 $
3.72 $
3.66 $
4.06 $
3.91 $
3.85 $
4.24 $
4.70 $
4.64 $
5.04 $
5.32
5.26
5.66
Average
annual
increase
thereafter
1.5%
1.5%
1.5%
1.5%
1.5%
1.5%
1.5%
1.5%
A foreign exchange rate of 1.001 US$/Cdn$ was used in the 2012 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.
16
CANADIAN NATURAL
2012 ANNUAL REPORT
Resource Disclosure (1)
Horizon Oil Sands Synthetic Crude Oil
Discovered Bitumen Initially-in-place
Proved Company Gross Reserves
Bitumen volume associated with Proved SCO reserves
Probable Company Gross Reserves
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)
1,096 million barrels of SCO
2,255 million barrels of SCO
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)
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)
(1) All volumes are Company Gross.
(2) A portion may be recoverable with the development of new technology.
Note: Company Gross proved and proved plus probable reserves at December 31, 2012.
Produced to Date is cumulative production to December 31, 2012.
14,400 million barrels
2,626 million barrels of Bitumen
1,209 million barrels of Bitumen
3,315 million barrels of Bitumen
128 million barrels
7,122 million barrels
96,731 million barrels
1,066 million barrels of Bitumen
1,056 million barrels of Bitumen
8,424 million barrels of Bitumen
370 million barrels
85,815 million barrels
4,100 million barrels
267 million barrels of Heavy Crude Oil
105 million barrels of Heavy Crude Oil
204 million barrels of Heavy Crude Oil
181 million barrels
3,343 million barrels
CANADIAN NATURAL
2012 ANNUAL REPORT
17
MANAGEMENT’S DISCUSSION AND ANALYSIS
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this document or documents incorporated
herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking
statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words
“believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”,
“should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule”, “proposed”
or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected
future commodity pricing, forecast or anticipated production volumes, royalties, operating costs, capital expenditures, income
tax expenses and other guidance provided throughout this Management’s Discussion and Analysis (“MD&A”) 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 expansions, Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project,
construction of the proposed Keystone XL Pipeline from Hardisty, Alberta to the US Gulf Coast, the proposed Kinder Morgan Trans
Mountain pipeline expansion from Edmonton, Alberta to Vancouver, British Columbia, 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. The reader should not place undue
reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which
they are based will occur.
In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment
based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are
numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and natural
gas liquids (“NGLs”) reserves and in projecting future rates of production and the timing of development expenditures. The total
amount or timing of actual future production may vary significantly from reserve and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry
in which the Company operates, which speak only as of the date such statements were made or as of the date of the report
or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the
actual results, performance or achievements of the Company to be materially different from any future results, performance or
achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others:
general economic and business conditions which will, among other things, impact demand for and market prices of the Company’s
products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates;
assumptions on which the Company’s current guidance is based; economic conditions in the countries and regions in which the
Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict
including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration
and development activities; impact of competition; the Company’s defense of lawsuits; availability and cost of seismic, drilling and
other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company’s and its subsidiaries’
ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining,
extracting or upgrading of the Company’s bitumen products; potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and
oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude
oil and natural gas and in mining, extracting or upgrading the Company’s bitumen products; availability and cost of financing; the
Company’s and its subsidiaries’ success of exploration and development activities and 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 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
18
CANADIAN NATURAL
2012 ANNUAL REPORT
one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual
results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a
particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and
the Company’s course of action would depend upon its assessment of the future considering all information then available. 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 “Net Earnings and Cash Flow from Operations” 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
This MD&A of the financial condition and results of operations of the Company should be read in conjunction with the Company’s
audited consolidated financial statements and related notes for the year ended December 31, 2012.
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.
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.
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 2012 financial results compared to 2011 and 2010, unless
otherwise indicated. In addition, this MD&A details the Company’s capital program and outlook for 2013. Additional information
relating to the Company, including its quarterly MD&A for the year and three months ended December 31, 2012, its Annual
Information Form for the year ended December 31, 2012, and its audited consolidated financial statements for the year ended
December 31, 2012 is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. This MD&A is dated March 6, 2013.
CANADIAN NATURAL
2012 ANNUAL REPORT
19
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
BOE/d
barrels of oil equivalent per day
Bitumen
Brent
C$
CAGR
CAPEX
CICA
CO2
CO2e
Solid or semi-solid viscous mixture consisting
mainly of pentanes and heavier hydrocarbons
with viscosity greater than 10,000 centipoise
Dated Brent
Canadian dollars
Compound annual growth rate
Capital expenditures
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
Crude Oil
Includes light and medium crude oil, primary
heavy crude oil, Pelican Lake heavy crude oil,
bitumen (thermal oil), and synthetic crude oil
CSS
EOR
E&P
FPSO
GHG
GJ
GJ/d
Cyclic Steam Stimulation
Enhanced oil recovery
Exploration and Production
Floating Production, Storage and
Offloading Vessel
Greenhouse gas
gigajoules
gigajoules per day
Horizon
Horizon Oil Sands
IASB
IFRS
LIBOR
LNG
Mbbl
Mbbl/d
MBOE
International Acounting Standards Board
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
MMBOE
million barrels of oil equivalent
MMBtu
MMcf
MMcf/d
MMcfe
NGLs
million British thermal units
million cubic feet
million cubic feet per day
millions of cubic feet equivalent
Natural gas liquids
NYMEX
New York Mercantile Exchange
NYSE
PRT
SAGD
SCO
SEC
Tcf
TSX
UK
US
New York Stock Exchange
Petroleum Revenue Tax
Steam-Assisted Gravity Drainage
Synthetic crude oil
United States Securities and Exchange
Commission
trillion cubic feet
Toronto Stock Exchange
United Kingdom
United States
US GAAP
Generally accepted accounting principles in the
United States
US$
WCS
United States dollars
Western Canadian Select
WCS Heavy
Differential
WTI
WCS Heavy Differential from WTI
West Texas Intermediate reference location at
Cushing, Oklahoma
20
CANADIAN NATURAL
2012 ANNUAL REPORT
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, 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
hedging program reduces the risk of volatility in commodity prices and supports the Company’s cash flow for its capital
expenditure 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, 2012 include the following:
Achieved net earnings of $1.9 billion, adjusted net earnings from operations of $1.6 billion, and cash flow from operations
of $6.0 billion;
Achieved record yearly crude oil and NGLs production of 326,829 bbl/d in the North America – Exploration and Production segment;
The Company largely maintained its natural gas production levels while strategically reducing its related natural gas capital
expenditure program;
Drilled a record 886 net primary heavy crude oil wells;
The Company focuses on efficient and effective operations at Horizon and continues to place emphasis on safe, steady,
reliable operations;
Purchased 11,012,700 common shares for a total cost of $318 million under the Normal Course Issuer Bid; and
Increased annual per share dividend payment to $0.42 from $0.36, the 12th consecutive year of dividend increases.
CANADIAN NATURAL
2012 ANNUAL REPORT
21
NET EARNINGS AND CASH FLOW FROM OPERATIONS
Financial Highlights
($ millions, except per common share amounts)
Product sales
Net earnings
Per common share – basic
– diluted
Adjusted net earnings from operations (1)
Per common share – basic
– diluted
Cash flow from operations (2)
Per common share – basic
– diluted
Dividends declared per common share
Total assets
Total long-term liabilities
Capital expenditures, net of dispositions
2012
2011
16,195 $
1,892 $
1.72 $
1.72 $
15,507 $
2,643 $
2.41 $
2.40 $
1,618 $
2,540 $
1.48 $
1.47 $
2.32 $
2.30 $
6,013 $
6,547 $
5.48 $
5.47 $
0.42 $
48,980 $
20,721 $
6,308 $
5.98 $
5.94 $
0.36 $
47,278 $
20,346 $
6,414 $
2010
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
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(1) 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” presents the after-tax
effects of certain items of a non-operational nature that are included in the Company’s financial results. Adjusted net earnings from operations may not be
comparable to similar measures presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company
evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company’s
ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Cash Flow from Operations”
presents certain non-cash items that are included in the Company’s financial results. Cash flow from operations may not be comparable to similar measures
presented by other companies.
Adjusted Net Earnings from Operations
($ millions)
Net earnings as reported
Share-based compensation (recovery) expense, net of tax (1)
Unrealized risk management gain, net of tax (2)
Unrealized foreign exchange loss (gain), net of tax (3)
Gabon, Offshore Africa 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)
Adjusted net earnings from operations
2012
2011
$
1,892 $
2,643 $
(214)
(37)
129
–
(102)
(95)
215
–
(210)
(225)
58
104
$
1,618 $
2,540 $
2010
1,673
203
(16)
(142)
594
–
132
2,444
(1) The Company’s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a
liability on the Company’s balance sheets and periodic changes in the fair value are recognized in net earnings 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 the fair value of non-designated hedges recognized in net
earnings. The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items
hedged, primarily crude oil and natural gas and foreign exchange.
(3) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially
offset by the impact of cross currency swaps, and are recognized in net earnings.
(4) During 2012, the Company repaid US$350 million of 5.45% unsecured notes. During 2011, the Company repaid US$400 million of 6.70% unsecured notes.
(5) All substantively enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company’s
balance sheets in determining deferred income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in net earnings during
the period the legislation is substantively enacted. During 2012, the UK government enacted legislation to restrict the combined corporate and supplementary
income tax rate relief on UK North Sea decommissioning expenditures to 50%, resulting in an increase in the Company’s deferred income tax liability of $58 million.
During 2011, the UK government enacted legislation to increase the corporate income tax rate charged on profits from UK North Sea crude oil and natural gas
production from 50% to 62%, resulting in an increase in the Company’s deferred income tax liability of $104 million. During 2010, changes in Canada to the
taxation of stock options surrendered by employees for cash payments resulted in a $132 million charge to deferred income tax expense.
22
CANADIAN NATURAL
2012 ANNUAL REPORT
Cash Flow from Operations
($ millions)
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)
Equity loss from jointly controlled entity
Deferred income tax (recovery) expense
Horizon asset impairment provision
Insurance recovery – property damage
Cash flow from operations
Realized foreign exchange gain on repayment of US dollar debt securities
2012
2011
$
1,892 $
2,643 $
4,328
(214)
151
(42)
129
(210)
9
(30)
–
–
3,604
(102)
130
(128)
215
(225)
–
407
396
(393)
2010
1,673
4,120
203
123
(24)
(161)
–
–
399
–
–
$
6,013 $
6,547 $
6,333
For 2012, the Company reported net earnings of $1,892 million compared with net earnings of $2,643 million for 2011
(2010 – $1,673 million). Net earnings for 2012 included net after-tax income of $274 million related to the effects of share-based
compensation, risk management activities, fluctuations in foreign exchange rates, the impact of a 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 (2011 – $103 million after-tax income; 2010 – $771 million after-tax expenses). Excluding these items, adjusted net
earnings from operations for 2012 decreased to $1,618 million from $2,540 million for 2011 (2010 – $2,444 million).
The decrease in adjusted net earnings for 2012 from 2011 was primarily due to:
lower crude oil and NGLs and natural gas netbacks;
lower realized SCO prices;
higher depletion, depreciation and amortization expense; and
higher realized risk management losses;
partially offset by:
higher crude oil and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments.
The impacts of share-based compensation, 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 2012 decreased to $6,013 million ($5.48 per common share) from $6,547 million
($5.98 per common share) for 2011 (2010 – $6,333 million; $5.82 per common share). The decrease in cash flow from operations
for 2012 from 2011 was primarily due to the factors noted above relating to the decrease in adjusted net earnings, excluding
depletion, depreciation and amortization expense, as well as due to the impact of cash taxes.
In the Company’s Exploration and Production activities, the 2012 average sales price per bbl of crude oil and NGLs decreased 9% to
average $70.24 per bbl from $77.46 per bbl in 2011 (2010 – $65.81 per bbl), and the average natural gas price decreased 35% to
average $2.44 per Mcf from $3.73 per Mcf in 2011 (2010 – $4.08 per Mcf). The Company’s average sales price of SCO decreased
11% to average $88.91 per bbl from $99.74 per bbl in 2011 (2010 – $77.89 per bbl).
Total production of crude oil and NGLs before royalties increased 16% to 451,378 bbl/d from 389,053 bbl/d in 2011
(2010 – 424,985 bbl/d). The increase in crude oil and NGLs production from 2011 was primarily related to additional Horizon production
volumes and the impact of a strong heavy crude oil drilling program.
Total natural gas production before royalties decreased 3% to average 1,220 MMcf/d from 1,257 MMcf/d in 2011 (2010 – 1,243 MMcf/d).
The decrease in natural gas production was primarily a result of a strategic reduction of natural gas drilling as the Company
allocated capital to higher return crude oil projects, as well as expected production declines.
Total crude oil and NGLs and natural gas production volumes before royalties increased 9% to average 654,665 BOE/d from
598,526 BOE/d in 2011 (2010 – 632,191 BOE/d).
CANADIAN NATURAL
2012 ANNUAL REPORT
23
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company’s quarterly results for the eight most recently completed quarters:
($ millions, except per common share amounts)
2012
Product sales
Net earnings
Net earnings per common share
– basic
– diluted
2011
Product sales
Net earnings
Net earnings per common share
– basic
– diluted
Total
16,195
1,892
1.72
1.72
Total
15,507
2,643
2.41
2.40
$
$
$
$
$
$
$
$
Dec 31
4,059
352
0.32
0.32
Dec 31
4,788
832
0.76
0.76
$
$
$
$
$
$
$
$
Sep 30
3,978
360
0.33
0.33
Sep 30
3,690
836
0.76
0.76
$
$
$
$
$
$
$
$
Jun 30
4,187
753
0.68
0.68
Jun 30
3,727
929
0.85
0.84
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Mar 31
3,971
427
0.39
0.39
Mar 31
3,302
46
0.04
0.04
Volatility in the quarterly net earnings 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 from WTI 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.
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, the record heavy crude oil drilling program,
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,
shut-in natural gas production due to pricing 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, acquisitions of
natural gas producing properties in 2011 that had higher operating costs per Mcf than the Company’s existing properties, and
the suspension and recommencement of production at Horizon.
Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes, proved reserves, asset retirement
obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to
develop the Company’s proved undeveloped reserves, and the impact of the suspension and recommencement of production
at Horizon.
Share-based compensation – Fluctuations due to the determination of fair market value based on the Black-Scholes valuation
model of the Company’s share-based compensation liability.
Risk management – Fluctuations due to 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 also recorded with respect to US
dollar denominated debt, partially offset by the impact of cross currency swap hedges.
Income tax expense – Fluctuations in income tax expense include statutory tax rate and other legislative changes substantively
enacted in the various periods.
24
CANADIAN NATURAL
2012 ANNUAL REPORT
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
2012
2011
94.19 $
95.14 $
111.56 $
111.29 $
21.05 $
17.10 $
22%
92.59 $
100.92 $
2.80 $
2.28 $
1.0004 $
1.0051 $
18%
103.63 $
105.38 $
4.07 $
3.48 $
1.0111 $
0.9833 $
$
$
$
$
$
$
$
$
$
2010
79.55
79.50
14.26
18%
78.56
81.81
4.42
3.91
0.9709
1.0054
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 2012, with a high of approximately US$1.03 in September
2012 and a low of approximately US$0.96 in June 2012.
WTI pricing in 2012 was reflective of the political instability in the Middle East, the declining optimism in the United States economy
related to the fiscal cliff, the European debt crisis, and lower than expected growth in Asian demand. For 2012, WTI averaged
US$94.19 per bbl and was comparable with 2011 (2010 – US$79.55 per bbl).
Brent averaged US$111.56 per bbl for 2012 and was comparable with 2011 (2010 – US$79.50 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 Brent pricing relative to WTI in 2012 was due to logistical constraints and high
inventory levels of crude oil at Cushing.
The WCS Heavy Differential averaged 22% for 2012 compared with 18% for 2011 and 2010. The WCS Heavy Differential widened
from the comparable periods as a result of planned and unplanned pipeline outages to key Canadian crude oil markets. The impact
of higher WCS Heavy Differentials in January and February 2013 of 35% and 39% respectively were partially offset by higher
overall WTI benchmark pricing. The WCS Heavy Differential narrowed in March 2013 to average approximately 29%.
The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During 2012 and the comparable
periods, condensate prices traded at a premium to WTI and reflected normal seasonal pricing adjustments.
The Company anticipates continued volatility in crude oil pricing benchmarks due to supply and demand factors, geopolitical
events, and the timing and extent of the economic recovery. The WCS Heavy Differential is expected to continue to reflect seasonal
demand fluctuations, changes in transportation logistics, and refinery utilization and shutdowns.
NYMEX natural gas prices averaged US$2.80 per MMBtu for 2012, a decrease of 31% from US$4.07 per MMBtu for 2011
(2010 – US$4.42 per MMBtu). AECO natural gas pricing averaged $2.28 per GJ for 2012, a decrease of 34% from US$3.48 per GJ
for 2011 (2010 – $3.91 per GJ). While Canadian production has declined in response to low prices, US production has held steady
during 2012. Natural gas pricing continues to be volatile as the market still requires a shift to higher utilization of gas fired electric
generation to offset the strong North America supply position.
Operating and Capital Costs
Strong crude oil commodity prices in recent years have resulted in increased demand for oilfield services worldwide. This has led to
inflationary operating and capital cost pressures, particularly related to drilling activities and oil sands developments.
Continued cost pressures and the final outcome of changes to environmental regulations may adversely impact the Company’s
future net earnings, cash flow and capital projects. For additional details, refer to the “Greenhouse Gas and Other Air Emissions”
section of this MD&A.
CANADIAN NATURAL
2012 ANNUAL REPORT
25
ANALYSIS OF CHANGES IN REVENUE, BEFORE ROYALTIES
AND RISK MANAGEMENT ACTIVITIES
($ millions)
2010
Volumes
Prices
Other
2011 Volumes
Prices
Other
2012
Changes due to
Changes due to
North America
Crude oil and NGLs
$ 7,805 $
708 $ 1,448 $
90 $ 10,051 $ 1,055 $
(583) $
(43) $ 10,480
1,755
11,806
(42)
1,013
(586)
(1,169)
–
1,127
(43)
11,607
Natural gas
North Sea
Crude oil and NGLs
Natural gas
Offshore Africa
Crude oil and NGLs
Natural gas
Subtotal
Crude oil and NGLs
Natural gas
Oil Sands Mining
and Upgrading
Midstream
Intersegment
eliminations
and other (1)
Total
1,908
9,713
1,043
15
1,058
846
38
884
9,694
1,961
11,655
21
729
(139)
(5)
(144)
(191)
9
(182)
378
25
403
(174)
1,274
292
(1)
291
220
21
241
1,960
(154)
1,806
2,649
(1,458)
322
79
(61)
–
–
–
–
–
90
19
–
19
3
–
3
112
–
112
8
9
1,215
9
1,224
878
68
946
12,144
1,832
13,976
1,521
88
(380)
(6)
(386)
(207)
2
(205)
468
(46)
422
16
1
17
36
4
40
(531)
(581)
(1,112)
1,688
(338)
–
–
–
–
73
–
73
(8)
–
(8)
22
–
22
–
5
1
924
4
928
699
74
773
12,103
1,205
13,308
2,871
93
(77)
$ 14,322 $
(1,055) $ 2,128 $
112 $ 15,507 $ 2,110 $ (1,450) $
28 $ 16,195
(17)
(78)
(1) Eliminates internal transportation, electricity charges, and natural gas sales.
Revenue increased 4% to $16,195 million for 2012 from $15,507 million for 2011 (2010 – $14,322 million). The increase was
primarily due to higher crude oil and SCO volumes in North America and Oil Sands Mining and Upgrading segments, partially offset
by a decrease in realized North America crude oil and NGLs and natural gas prices, Oil Sands Mining and Upgrading SCO prices,
and lower International production.
For 2012, 11% of the Company’s crude oil and natural gas revenue was generated outside of North America
(2011 – 14%; 2010 – 13%). North Sea accounted for 6% of crude oil and natural gas revenue for 2012 (2011 – 8%; 2010 – 7%),
and Offshore Africa accounted for 5% of crude oil and natural gas revenue for 2012 (2011 – 6%; 2010 – 6%).
26
CANADIAN NATURAL
2012 ANNUAL REPORT
ANALYSIS OF DAILY PRODUCTION, BEFORE ROYALTIES
2012
2011
2010
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
Total barrels of oil equivalent (BOE/d)
326,829
86,077
19,824
18,648
451,378
1,198
2
20
1,220
654,665
16%
6%
19%
15%
13%
31%
91%
9%
295,618
40,434
29,992
23,009
389,053
1,231
7
19
1,257
598,526
18%
6%
18%
16%
7%
35%
86%
14%
270,562
90,867
33,292
30,264
424,985
1,217
10
16
1,243
632,191
18%
6%
15%
14%
14%
33%
85%
15%
2012
2011
2010
273,374
82,171
19,772
13,628
388,945
1,171
2
17
1,190
587,246
240,006
38,721
29,919
20,532
329,178
1,186
7
16
1,209
530,576
219,736
87,763
33,227
28,288
369,014
1,168
10
15
1,193
567,743
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 2012 production averaged 654,665 BOE/d, a 9% increase from 598,526 BOE/d in 2011 (2010 – 632,191 BOE/d).
Total production of crude oil and NGLs before royalties increased 16% to 451,378 bbl/d for 2012 from 389,053 bbl/d in 2011
(2010 – 424,985 bbl/d). The increase in crude oil and NGLs production from 2011 was primarily related to additional Horizon
production volumes and the impact of a strong heavy crude oil drilling program. Crude oil and NGLs production for 2012 was
slightly below the Company’s previously issued guidance of 452,000 to 460,000 bbl/d.
CANADIAN NATURAL
2012 ANNUAL REPORT
27
Natural gas production continued to represent the Company’s largest product offering, accounting for 31% of the Company’s
total production in 2012 on a BOE basis. Total natural gas production before royalties decreased 3% to 1,220 MMcf/d for 2012
from 1,257 MMcf/d for 2011 (2010 – 1,243 MMcf/d). The decrease in natural gas production from 2011 was primarily a result
of a strategic reduction of natural gas drilling as the Company allocated capital to higher return crude oil projects, as well as
expected production declines. Natural gas production for 2012 was slightly below the Company’s previously issued guidance of
1,222 to 1,229 MMcf/d.
North America – Exploration and Production
North America crude oil and NGLs production for 2012 increased 11% to average 326,829 bbl/d from 295,618 bbl/d for 2011
(2010 – 270,562 bbl/d). The increase in production from 2011 was primarily due to the impact of a strong heavy crude oil
drilling program.
North America natural gas production for 2012 decreased 3% to average 1,198 MMcf/d from 1,231 MMcf/d in 2011
(2010 – 1,217 MMcf/d). The decrease in natural gas production from 2011 was primarily a result of a strategic reduction of natural
gas drilling as the Company allocated capital to higher return crude oil projects, as well as expected production declines.
North America – Oil Sands Mining and Upgrading
Production averaged 86,077 bbl/d for 2012 compared with 40,434 bbl/d for 2011 (2010 – 90,867 bbl/d). Production in 2012
reflected the impact of unplanned maintenance on the fractionator in the Horizon primary upgrading facility.
North Sea
North Sea crude oil production for 2012 was 19,824 bbl/d, a decrease of 34% from 29,992 bbl/d for 2011 (2010 – 33,292 bbl/d).
The decrease in production volumes from 2011 was primarily due to temporary shut ins of the third-party operated pipeline to
Sullom Voe, which caused all Ninian and associated fields to be shut in for a portion of the third and fourth quarters of 2012, the
suspension of production at Banff/Kyle, and natural field declines.
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. The FPSO and associated floating storage unit have subsequently been
removed from the field and the FPSO is currently in dry dock for assessment of damages and repair timeframe. The extent of the
property damage, including associated costs, is not expected to be significant.
Offshore Africa
Offshore Africa crude oil production for 2012 decreased 19% to 18,648 bbl/d from 23,009 bbl/d for 2011 (2010 – 30,264 bbl/d)
due to natural field declines, planned turnaround activity, and the shut in of approximately 1,500 bbl/d of production at the Olowi
field, Gabon. The Company currently has a vessel on-site in Gabon assessing the operability of the midwater arch.
Guidance
The Company targets production levels in 2013 to average between 482,000 bbl/d and 513,000 bbl/d of crude oil and NGLs and
between 1,085 MMcf/d and 1,145 MMcf/d of natural gas.
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
2012
643,758
993,627
77,018
1,036,509
2,750,912
2011
2010
557,475
1,021,236
286,633
527,312
761,351
1,172,200
264,995
404,197
2,392,656
2,602,743
28
CANADIAN NATURAL
2012 ANNUAL REPORT
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
2012
2011
2010
$
70.24 $
77.46 $
$
$
$
$
10.67
16.11
12.30
15.75
43.46 $
49.41 $
2.44 $
3.73 $
0.09
1.31
0.18
1.15
1.04 $
2.40 $
50.81 $
57.16 $
7.07
13.14
8.12
12.42
$
30.60 $
36.62 $
65.81
10.09
14.16
41.56
4.08
0.20
1.09
2.79
49.90
6.72
11.25
31.93
(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.
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)
2012
2011
2010
$
$
$
$
$
$
$
$
$
65.54 $
110.75 $
111.18 $
70.24 $
2.31 $
3.70 $
10.17 $
2.44 $
50.81 $
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
57.16 $
49.90
(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.
Realized crude oil and NGLs prices decreased 9% to average $70.24 per bbl for 2012 from $77.46 per bbl for 2011
(2010 – $65.81 per bbl). The decrease in 2012 was primarily a result of the lower WTI benchmark pricing and the widening of
the WCS Heavy Differential, partially offset by the impact of a weaker Canadian dollar relative to the US dollar.
The Company’s realized natural gas price decreased 35% to average $2.44 per Mcf for 2012 from $3.73 per Mcf for 2011
(2010 – $4.08 per Mcf). The decrease in 2012 was primarily due to lower NYMEX and AECO benchmark pricing related to the
impact of strong supply from US shale projects.
CANADIAN NATURAL
2012 ANNUAL REPORT
29
North America
North America realized crude oil prices decreased 9% to average $65.54 per bbl for 2012 from $72.17 per bbl for 2011
(2010 – $62.28 per bbl). The decrease in 2012 was primarily a result of the lower WTI benchmark pricing and the widening of the
WCS Heavy Differential, partially offset by the impact of a weaker Canadian dollar relative to the US dollar.
North America realized natural gas prices decreased 37% to average $2.31 per Mcf for 2012 from $3.64 per Mcf for 2011
(2010 – $4.05 per Mcf), primarily due to lower NYMEX and AECO benchmark pricing related to the impact of strong supply from
US shale projects.
The Company continues to focus on its crude oil marketing strategy including a blending strategy that expands markets within
current pipeline infrastructure, supporting pipeline projects that will provide capacity to transport crude oil to new markets, and
working with refiners to add incremental heavy crude oil conversion capacity. During 2012, the Company contributed approximately
157,000 bbl/d of heavy crude oil blends to the WCS stream. The Company has entered into a 20 year transportation agreement
to ship 120,000 bbl/d of heavy crude oil on the proposed Keystone XL Pipeline from Hardisty, Alberta to the US Gulf Coast. The
Company also entered into a 20 year crude oil purchase and sales agreement to sell 100,000 bbl/d of heavy crude oil to a major US
refiner. The construction of the Keystone XL Pipeline is dependent on a Presidential Permit. During 2012, the Company entered into
a 20 year transportation agreement to ship 75,000 bbl/d of crude oil on the proposed Kinder Morgan Trans Mountain Expansion
from Edmonton, Alberta to Vancouver, British Columbia. The regulatory approval process will begin in 2013 with a planned
in-service date in 2017.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
(Yearly average)
2012
2011
2010
Wellhead Price (1) (2)
Light and medium crude oil and NGLs (C$/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
$
$
$
$
$
70.58 $
65.43 $
64.21 $
64.03 $
2.31 $
82.01 $
71.45 $
70.51 $
68.55 $
3.64 $
68.02
61.69
62.04
59.55
4.05
North Sea realized crude oil prices increased 2% to average $110.75 per bbl for 2012 from $108.56 per bbl for 2011
(2010 – $82.49 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 slight increase
in realized crude oil prices in the North Sea from 2011 was primarily due to higher Brent benchmark pricing, the impact of the
weaker Canadian dollar, and the timing of liftings.
Offshore Africa
Offshore Africa realized crude oil prices increased 5% to average $111.18 per bbl for 2012 from $105.53 per bbl for 2011
(2010 – $78.93 per bbl). Realized crude oil prices per bbl in any particular year are dependent on the terms of the various sales
contracts, the frequency and timing of liftings of each field, and prevailing crude oil prices at the time of lifting. The increase in
realized crude oil prices in Offshore Africa from 2011 was primarily due to the higher Brent benchmark pricing, the impact of the
weaker Canadian dollar, and the timing of liftings.
30
CANADIAN NATURAL
2012 ANNUAL REPORT
ROYALTIES – EXPLORATION AND PRODUCTION
Crude oil and NGLs ($/bbl) (1)
North America
North Sea
Offshore Africa
Company average
Natural gas ($/Mcf) (1)
North America
Offshore Africa
Company average
Company average ($/BOE) (1)
2012
2011
2010
$
$
$
$
$
$
$
$
10.33 $
0.29 $
29.46 $
10.67 $
0.06 $
1.77 $
0.09 $
7.07 $
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
(1) Amounts expressed on a per unit basis are based on sales volumes.
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”).
Crude oil and NGLs royalties averaged approximately 16% of product sales in 2012 compared with 19% in 2011 (2010 – 19%)
primarily due to lower WTI benchmark pricing and changes in the WCS Heavy Differential. North America crude oil and NGLs
royalties per bbl are anticipated to average 16% to 18% of product sales for 2013.
Natural gas royalties averaged approximately 3% of product sales for 2012 compared with 4% in 2011 (2010 – 5%) primarily due
to lower realized natural gas prices. North America natural gas royalties per Mcf are anticipated to average 4% to 6% of product
sales for 2013.
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, royalty rates fluctuate based on realized commodity pricing, capital
and operating costs, the status of payouts, and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 26% for 2012 compared to 17% for 2011 (2010 – 7%)
primarily due to higher crude oil prices, adjustments to royalties on liftings, and the payout of the Baobab field in May 2011.
Offshore Africa royalty rates are anticipated to average 9% to 11% of product sales for 2013.
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)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2012
2011
2010
13.40 $
53.53 $
23.11 $
16.11 $
1.28 $
3.75 $
2.27 $
1.31 $
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
13.14 $
12.42 $
11.25
$
$
$
$
$
$
$
$
$
CANADIAN NATURAL
2012 ANNUAL REPORT
31
North America
North America crude oil and NGLs production expense for 2012 averaged $13.40 per bbl and was comparable with 2011
(2010 – $12.14 per bbl). North America crude oil and NGLs production expense is anticipated to average $12.00 to $14.00 per
bbl for 2013.
North America natural gas production expense for 2012 increased 14% to $1.28 per Mcf from $1.12 per Mcf for 2011
(2010 – $1.06 per Mcf). Natural gas production expense increased from 2011 due to the impact of lower production volumes
related to the shut in of production and the curtailment of capital expenditures related to natural gas activity. North America
natural gas production expense is anticipated to average $1.30 to $1.40 per Mcf for 2013 due to natural declines.
North Sea
North Sea crude oil production expense for 2012 increased 44% to $53.53 per bbl from $37.06 per bbl for 2011
(2010 – $29.73 per bbl). Production expense increased on a per bbl basis due to the impact of production declines on relatively
fixed costs, temporary shut ins of the third-party operated pipeline to Sullom Voe, and higher maintenance costs related to
turnaround activity in 2012. North Sea crude oil production expense is anticipated to average $62.00 to $66.00 per bbl for 2013
due to natural declines on a relatively fixed cost structure.
Offshore Africa
Offshore Africa crude oil production expense for 2012 increased 12% to $23.11 per bbl from $20.72 per bbl for 2011
(2010 – $14.64 per bbl). Production expense increased due to the timing of liftings from various fields, which have different cost
structures. Offshore Africa crude oil production expense is anticipated to average $33.50 to $37.50 per bbl for 2013 due to timing
of liftings from various fields.
DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Expense
$/BOE (1)
2012
2011
$
3,413 $
2,840 $
296
165
249
242
$
$
3,874 $
18.65 $
3,331 $
16.35 $
2010
2,484
297
935
3,716
18.76
(1) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, depreciation and amortization expense for 2012 increased to $3,874 million from $3,331 million for 2011
(2010 – $3,716 million) primarily due to higher sales volumes in North America associated with heavy crude oil drilling, higher
overall future development costs and the impact of property, plant and equipment amortized on a straight line basis.
ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Expense
$/BOE (1)
2012
2011
85 $
70 $
27
7
119 $
0.57 $
33
7
110 $
0.54 $
2010
52
36
7
95
0.47
$
$
$
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation
due to the passage of time.
32
CANADIAN NATURAL
2012 ANNUAL REPORT
OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING
Operations Update
During 2012, the Company continued to focus on efficient and effective operations at Horizon and place emphasis on safe, steady,
reliable operations. Production in 2012 reflected the impact of unplanned maintenance on the fractionator in the Horizon primary
upgrading facility.
In the second quarter of 2013, Horizon will enter into a 24 day planned maintenance turnaround, resulting in a plant-wide shut down. The
impact of the turnaround has been reflected in the Company’s 2013 production, cash production cost and capital expenditure guidance.
Product Prices and Royalties – Oil Sands Mining and Upgrading
($/bbl) (1)
SCO sales price (2)
Bitumen value for royalty purposes (3)
Bitumen royalties (4)
2012
2011
$
$
$
88.91 $
59.93 $
4.34 $
99.74 $
61.86 $
3.99 $
2010
77.89
56.14
2.72
(1) Amounts expressed on a per unit basis in 2012 and 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 quarterly average of the bitumen valuation methodology price.
(4) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes.
Realized SCO sales prices decreased 11% to average $88.91 per bbl for 2012 from $99.74 per bbl for 2011 (2010 – $77.89 per bbl),
reflecting benchmark pricing and prevailing differentials.
Production Costs – Oil Sands Mining and Upgrading
The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 20 to the Company’s
consolidated financial statements.
($ millions)
Cash production costs
Less: costs incurred during the period of suspension of production
Adjusted cash production costs
Adjusted cash production costs, excluding natural gas costs
Adjusted natural gas costs
Adjusted cash production costs
($/bbl) (1)
Adjusted cash production costs, excluding natural gas costs
Adjusted natural gas costs
Adjusted cash production costs
Sales (bbl/d) (2)
$
$
$
$
$
$
2012
2011
1,504 $
1,127 $
(154)
1,350 $
1,254 $
96
(581)
546 $
502 $
44
1,350 $
546 $
2012
2011
39.79 $
33.68 $
3.04
2.96
42.83 $
36.64 $
2010
1,208
–
1,208
1,082
126
1,208
2010
32.58
3.78
36.36
86,153
40,847
91,010
(1) Adjusted cash production costs on a per unit basis in 2012 and 2011 were based on sales volumes excluding the periods during suspension of production.
(2) Sales on a per unit basis reflect sales volumes including the periods during suspension of production.
Adjusted cash production costs averaged $42.83 per bbl for 2012, an increase of 17% compared with $36.64 per bbl for 2011
(2010 – $36.36 per bbl). The increase in 2012 adjusted cash production costs per bbl was primarily due to higher overall production
costs. Cash production costs are anticipated to average $38.00 to $41.00 per bbl for 2013.
CANADIAN NATURAL
2012 ANNUAL REPORT
33
Depletion, Depreciation and Amortization – Oil Sands Mining and Upgrading
($ millions)
Depletion, depreciation and amortization
Less: depreciation incurred during the period of suspension of production
Adjusted depletion, depreciation and amortization
$/bbl (1)
2012
2011
447 $
(6)
441 $
266 $
(64)
202 $
2010
396
–
396
13.99 $
13.54 $
11.91
$
$
$
(1) Amounts expressed on a per unit basis in 2012 and 2011 are based on sales volumes excluding the period during suspension of production.
Depletion, depreciation and amortization expense for 2012 increased to $447 million from $266 million for 2011 (2010 – $396 million)
primarily due to higher sales volumes.
Asset Retirement Obligation Accretion – Oil Sands Mining and Upgrading
Expense ($ millions)
$/bbl (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2012
2011
$
$
32 $
1.01 $
20 $
1.33 $
2010
28
0.88
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation
due to the passage of time.
MIDSTREAM
($ millions)
Revenue
Production expense
Midstream cash flow
Depreciation
Equity loss from jointly controlled entity
Segment earnings before taxes
2012
2011
2010
$
93 $
88 $
29
64
7
9
26
62
7
–
$
48 $
55 $
79
22
57
8
–
49
The Company’s midstream assets include three crude oil pipeline systems and a 50% working interest in an 84-megawatt
cogeneration plant at Primrose. Approximately 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 a portion
of its own production volumes as well as earn third party revenue. This transportation control enhances the Company’s ability to
manage the full range of costs associated with the development and marketing of its heavier crude oil.
In 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 (“the Project”)
near Redwater, Alberta. In addition, the partnership entered into processing agreements that target to process bitumen for the
Company and the Alberta Petroleum Marketing Commission (“APMC”), an agent of the Government of Alberta, under a 30 year
fee-for-service tolling agreement under the Bitumen Royalty In Kind initiative. In 2012, the Project was sanctioned by the Board
of Directors of each partner of the North West Redwater Partnership (“Redwater”), and the associated target toll amounts were
accepted by Redwater, the Company and the APMC.
34
CANADIAN NATURAL
2012 ANNUAL REPORT
ADMINISTRATION EXPENSE
($ millions, except per BOE amounts)
Expense
$/BOE (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2012
2011
$
$
270 $
1.13 $
235 $
1.07 $
2010
211
0.92
Administration expense for 2012 increased from 2011 primarily due to higher staffing related costs and general corporate costs.
SHARE-BASED COMPENSATION
($ millions)
(Recovery) expense
2012
2011
$
(214) $
(102) $
2010
203
The Company’s stock option plan provides current employees with the right to receive common shares or a direct cash payment in
exchange for stock options surrendered.
The share-based compensation liability at December 31, 2012 reflected the Company’s liability for awards granted to employees at
fair value estimated using the Black-Scholes valuation model. In periods when substantial share price changes occur, the Company’s
net earnings are subject to significant volatility. The Company utilizes its share-based compensation plan to attract and retain
employees in a competitive environment. All employees participate in this plan.
The Company recorded a $214 million share-based compensation recovery for the year ended December 31, 2012, primarily
as a result of remeasurement of the fair value of outstanding stock options at the end of the year related to a decrease in
the Company’s share price, partially 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 year. For the year ended December 31, 2012, a $12 million
recovery was recognized in respect of capitalized share-based compensation to Oil Sands Mining and Upgrading (2011 – $nil;
2010 – $32 million expense capitalized).
During 2012, the Company paid $7 million for stock options surrendered for cash payments (2011 – $14 million; 2010 – $45 million).
INTEREST AND OTHER FINANCING COSTS
($ millions, except per BOE amounts and interest rates)
Expense, gross
Less: capitalized interest
Expense, net
$/BOE (1)
Average effective interest rate
$
$
$
2012
2011
462 $
432 $
98
364 $
1.52 $
59
373 $
1.71 $
4.8%
4.7%
2010
476
28
448
1.94
4.9%
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest and other financing costs for 2012 increased from 2011 due to higher variable interest rates and the impact of a
weaker Canadian dollar, partially offset by lower average debt levels. Capitalized interest of $98 million for 2012 was related to
the Horizon Phase 2/3 expansion and the Kirby Thermal Oil Sands Project (“Kirby Project”).
CANADIAN NATURAL
2012 ANNUAL REPORT
35
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, foreign currency and interest rate
exposures. These derivative financial instruments are not intended for trading or speculative purposes.
($ millions)
2012
2011
2010
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
Net loss (gain)
$
$
$
$
$
65 $
117 $
–
97
–
(16)
162 $
101 $
3 $
(134) $
–
(45)
(42) $
120 $
–
6
(128) $
(27) $
84
(234)
40
(110)
(108)
72
12
(24)
(134)
During 2012, realized risk management losses primarily related to the settlement of crude oil and foreign currency contracts. The
Company recorded a net unrealized gain of $42 million ($37 million after-tax) on its risk management activities (2011 – $128 million
unrealized gain, $95 million after-tax; 2010 – $24 million unrealized gain, $16 million after-tax), related to changes in the fair value
of these contracts.
The cash settlement amount of commodity derivative financial instruments may vary materially depending upon the underlying
crude oil prices at the time of final settlement, as compared to their fair value at December 31, 2012.
Complete details related to outstanding derivative financial instruments at December 31, 2012 are disclosed in note 17 to the
Company’s consolidated financial statements.
FOREIGN EXCHANGE
($ millions)
Net realized gain
Net unrealized loss (gain) (1)
Net (gain) loss
2012
2011
(178) $
(214) $
129
(49) $
215
1 $
2010
(2)
(161)
(163)
$
$
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The Company’s operating results are affected by the fluctuations in the exchange rates between the Canadian dollar, US dollar,
and UK pound sterling. Predominantly all of the Company’s revenue is based on reference to US dollar benchmark prices. An
increase in the value of the Canadian dollar in relation to the US dollar results in decreased revenue from the sale of the Company’s
production. Conversely a decrease in the value of the Canadian dollar in relation to the US dollar results in increased revenue from
the sale of the Company’s production. Production expenses in the North Sea are subject to foreign currency fluctuations due to
changes in the exchange rate of the UK pound sterling to the US dollar. The value of the Company’s US dollar denominated debt
is also impacted by the value of the Canadian dollar in relation to the US dollar.
The net realized foreign exchange gain for 2012 was primarily due to the repayment of US$350 million of 5.45% unsecured notes,
together with the impact of foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars
or UK pounds sterling. The net unrealized foreign exchange loss in 2012 was primarily related to the reversal of the life-to-date
unrealized foreign exchange gain on the repayment of US$350 million of 5.45% unsecured notes; partially offset by the impact
of the strengthening of the Canadian dollar at December 31, 2012 with respect to remaining US dollar debt. Included in the net
unrealized loss for 2012 was an unrealized loss of $53 million (2011 – $42 million unrealized gain, 2010 – $101 million unrealized
loss) related to the impact of cross currency swaps. The US/Canadian dollar exchange rate ended the year at US$1.0051 compared
with US$0.9833 at December 31, 2011 (December 31, 2010 – US$1.0054).
36
CANADIAN NATURAL
2012 ANNUAL REPORT
INCOME TAXES
($ 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
Deferred PRT recovery – North Sea
Deferred income tax (recovery) expense
Income tax rate and other legislative changes
2012
2011
2010
$
366 $
315 $
115
206
44
16
747
–
(30)
(30)
717
(58)
245
140
135
25
860
412
(5)
407
1,267
(104)
431
203
64
68
23
789
408
(9)
399
1,188
(132)
1,056
28.9%
Effective income tax rate on adjusted net earnings from operations (2)
27.8%
27.7%
$
659 $
1,163 $
(1) Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments.
(2) Excludes the impact of current and deferred PRT expense and other current income tax expense.
Current income taxes recognized in each operating segment will vary depending upon available income tax deductions related to
the nature, timing and amount of capital expenditures incurred in any particular year.
During 2012, the UK government enacted legislation to restrict the combined corporate and supplementary income tax relief on
UK North Sea decommissioning expenditures to 50%. As a result of the income tax rate change, the Company’s deferred income
tax liability was increased by $58 million.
During 2011, the UK government enacted legislation to increase 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.
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 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.
During 2012, the Company filed Scientific Research and Experimental Development claims of approximately $300 million
(2011 – $210 million, 2010 – $190 million) relating to qualifying research and development capital and operating expenditures for
Canadian income tax purposes.
For 2013, based on budgeted prices and the current availability of tax pools, the Company expects to incur current income tax
expense of $550 million to $650 million in Canada and $10 million to $100 million in the North Sea and Offshore Africa.
CANADIAN NATURAL
2012 ANNUAL REPORT
37
NET CAPITAL EXPENDITURES (1)
($ millions)
Exploration and Evaluation
Net expenditures
Property, Plant and Equipment
Net property acquisitions
Well drilling, completion and equipping
Production and related facilities
Capitalized interest and other (2)
Net expenditures
Total Exploration and Production
Oil Sands Mining and Upgrading
Horizon Phases 2/3 construction costs
Sustaining capital
Turnaround costs
Capitalized interest and other (2)
Total Oil Sands Mining and Upgrading
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
2012
2011
2010
$
309 $
312 $
572
144
1,902
1,978
111
4,135
4,444
1,315
223
21
51
1,610
–
14
204
36
1,012
1,878
1,690
104
4,684
4,996
481
170
79
48
778
404
5
213
18
6,308 $
6,414 $
1,482
1,499
1,122
92
4,195
4,767
319
128
–
96
543
–
7
179
18
5,514
4,126 $
4,736 $
4,369
254
64
1,610
14
204
36
227
33
1,182
5
213
18
149
249
543
7
179
18
$
$
$
6,308 $
6,414 $
5,514
(1) Net capital expenditures exclude adjustments related to differences between carrying amounts and tax values, and other fair value adjustments.
(2) Capitalized interest and other includes expenditures related to land acquisition and retention, seismic, and other adjustments.
(3) During 2011, 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.
The Company’s strategy is focused on building a diversified asset base that is balanced among various products. In order to
facilitate efficient operations, the Company concentrates its activities in core areas. The Company focuses on 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 2012 were $6,308 million compared with $6,414 million for 2011 (2010 – $5,514 million). The
increase in 2012 capital expenditures in the Exploration and Production and Oil Sands Mining and Upgrading segments from 2011
was primarily due to an increase in production and related facilities spending, partially offset by lower net property acquisition
costs, and the ramp up of Horizon site construction activity.
38
CANADIAN NATURAL
2012 ANNUAL REPORT
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
2012
35
1,203
33
727
1,998
97%
2011
83
1,103
48
657
1,891
96%
2010
92
934
33
491
1,550
97%
North America, excluding Oil Sands Mining and Upgrading, accounted for approximately 69% of the total capital expenditures for
2012 compared to approximately 77% for 2011 (2010 – 83%).
During 2012, the Company targeted 35 net natural gas wells, including 15 wells in Northeast British Columbia and 20 wells in Northwest
Alberta. The Company also targeted 1,236 net crude oil wells. The majority of these wells were concentrated in the Company’s Northern
Plains region where 886 primary heavy crude oil wells, 65 Pelican Lake heavy crude oil wells, 8 light crude oil wells and 161 bitumen
(thermal oil) wells were drilled. Another 116 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 thermal in situ Oil Sands assets, the Company is continuing to develop its Primrose thermal
projects. During 2012, the Company drilled 135 bitumen (thermal oil) wells, and 105 stratigraphic test wells and observation wells.
Overall Primrose thermal production for 2012 averaged approximately 99,000 bbl/d, compared with approximately 98,000 bbl/d
in 2011 (2010 – 90,000 bbl/d). Production volumes were in line with expectations due to the cyclic nature of thermal production
at Primrose. Additional pad drilling was completed and drilled on budget, with these wells coming on production in 2013.
The next planned phase of the Company’s thermal in situ Oil Sands assets expansion is the Kirby South Phase 1 Project. As at
December 31, 2012, the overall project was 81% complete, drilling was completed on the fifth of seven pads, and first steam is
targeted for late 2013. In 2012, the Company acquired approximately 49 sections (12,630 hectares) of additional Oil Sands rights
immediately adjacent to the Kirby Project.
The Company continued to develop the tertiary recovery conversion projects at Pelican Lake throughout 2012. Pelican Lake
production averaged approximately 38,000 bbl/d in 2012 (2011 – 38,000 bbl/d; 2010 – 38,000 bbl/d). The completion of the new
20,000 bbl/d battery expansion is targeted to be on stream in the second quarter of 2013. With this incremental capacity, both
Woodenhouse and Pelican production volumes will no longer be restricted.
For 2013, the Company’s overall drilling activity in North America is expected to be 1,022 net crude oil wells, 132 net bitumen
wells and 30 net natural gas wells, excluding stratigraphic and service wells.
Oil Sands Mining and Upgrading
Phase 2/3 expansion activity during 2012 was focused on the field construction of the gas recovery unit, sulphur recovery unit,
butane treatment unit, tank farms, coker expansion, hydrotransport, tailings, and extraction trains 3 and 4, along with engineering
related to the hydrogen, utilities, hydrotreater, vacuum distillation and diluent recovery units, and permanent camp. Final
commissioning of the third ore preparation plant and associated hydro-transport was completed in January 2012.
North Sea
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. The FPSO and associated floating storage unit have subsequently been
removed from the field and the FPSO is currently in dry dock for assessment of the damage and repair timeframe. The extent of
the property damage, including associated costs, is not expected to be significant.
In 2012, the UK government announced the implementation of the Brownfield Allowance, which allows for an agreed allowance
related to property development for certain pre-approved qualifying field developments. This allowance partially mitigates the
impact of previous tax increases. The Company is currently assessing the impact of this initiative on its future capital programs.
The Company currently plans to decommission the Murchison platform in the North Sea commencing in 2014 and estimates the
decommissioning efforts will continue for approximately 5 years.
CANADIAN NATURAL
2012 ANNUAL REPORT
39
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 drilling rig is on-site in preparation for the commencement of the drilling program in 2013. At the Olowi field in Gabon,
approximately 1,500 bbl/d of production was shut in. The Company currently has a vessel on-site in Gabon assessing the operability
of the midwater arch.
LIQUIDITY AND CAPITAL RESOURCES
($ millions, except ratios)
Working capital (deficit) (1)
Long-term debt (2) (3)
Shareholders’ equity
Share capital
Retained earnings
Accumulated other comprehensive income
Total
2012
2011
$
$
(1,264) $
8,736 $
(894) $
8,571 $
$
3,709 $
3,507 $
20,516
58
19,365
26
2010
(1,200)
8,485
3,147
17,212
9
$
24,283 $
22,898 $
20,368
Debt to book capitalization (3) (4)
Debt to market capitalization (3) (5)
After-tax return on average common shareholders’ equity (6)
After-tax return on average capital employed (3) (7)
26%
22%
8%
7%
27%
17%
12%
10%
29%
15%
8%
7%
(1) Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
(2) Includes the current portion of long-term debt (2012 – $798 million; 2011 – $359 million; 2010 – $397 million).
(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.
At December 31, 2012, 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 ongoing 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. At December 31, 2012, the Company had $3,661 million of available credit under its bank credit facilities.
During 2012, the Company’s $1,500 million revolving syndicated credit facility was extended to June 2016. Additionally, the
Company issued $500 million of 3.05% medium-term notes due June 2019. Proceeds from the securities issued were used to
repay bank indebtedness and for general corporate purposes. After issuing these securities, the Company has $2,500 million
remaining on its outstanding $3,000 million base shelf prospectus that allows for the issue of medium-term notes in Canada,
which expires in November 2013. If issued, these securities will bear interest as determined at the date of issuance.
During 2012, the Company repaid US$350 million of 5.45% unsecured notes. The Company has US$2,000 million remaining on
its outstanding US$3,000 million base shelf prospectus that allows for the issue of US dollar debt securities in the United States,
which expires in November 2013. If issued, these securities will bear interest as determined at the date of issuance.
Subsequent to December 31, 2012, $400 million of 4.50% medium-term notes and US$400 million of 5.15% unsecured notes
were repaid. This indebtedness was retired utilizing cash flow from operations generated in excess of capital expenditures and
available bank credit facilities as necessary, while maintaining the ongoing dividend program. On a pro forma basis, reflecting
the retirement of this indebtedness at December 31, 2012, the available credit under its bank credit facilities would amount to
$2,863 million.
40
CANADIAN NATURAL
2012 ANNUAL REPORT
Long-term debt was $8,736 million at December 31, 2012, resulting in a debt to book capitalization ratio of 26%
(December 31, 2011 – 27%; December 31, 2010 – 29%). This ratio is within the 25% to 45% internal range utilized by management.
This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. The
Company may be below the low end of the targeted range when cash flow from operations is greater than current investment
activities. The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital
structure. The Company has hedged a portion of its crude oil production for 2013 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, 2012 are discussed in note 8 to the Company’s consolidated financial statements.
The Company’s commodity hedge policy reduces the risk of volatility in commodity prices and supports the Company’s cash flow
for its capital expenditure programs. This policy currently allows for the hedging of up to 60% of the near 12 months budgeted
production and up to 40% of the following 13 to 24 months estimated production. For the purpose of this policy, the purchase
of put options is in addition to the above parameters. As at March 6, 2013, approximately 48% of currently forecasted 2013
crude oil volumes were hedged using price collars. Further details related to the Company’s commodity related derivative financial
instruments outstanding at December 31, 2012 are discussed in note 17 to the Company’s consolidated financial statements.
Share Capital
As at December 31, 2012, there were 1,092,072,000 common shares outstanding and 73,747,000 stock options outstanding.
As at March 5, 2013, the Company had 1,092,589,000 common shares outstanding and 68,482,000 stock options outstanding.
During 2012, the Company amended its Articles by special resolution of the shareholders, changing the designation of its Class
1 preferred shares to “Preferred Shares” which may be issuable in series. If issued, the number of shares in each series, and the
designation, rights, privileges, restrictions and conditions attached to the shares will be determined by the Board of Directors of
the Company.
On March 6, 2013, the Company’s Board of Directors approved an increase in the annual dividend to be paid by the Company to
$0.50 per common share for 2013. The increase represents an approximately 19% increase from 2012, recognizing the stability of
the Company’s cash flow and providing a return to shareholders. The dividend policy undergoes periodic review by the Board of
Directors and is subject to change. In March 2012, an increase in the annual dividend paid by the Company to $0.42 per common
share was approved for 2012. The increase represented a 17% increase from 2011.
In 2012, the Company announced a Normal Course Issuer Bid to purchase, through the facilities of the TSX and the NYSE, during
the twelve month period commencing April 2012 and ending April 2013, up to 55,027,447 common shares. The Company’s
Normal Course Issuer Bid announced in 2011 expired April 2012.
During 2012, the Company purchased for cancellation 11,012,700 common shares at a weighted average price of $28.91 per
common share for a total cost of $318 million.
CANADIAN NATURAL
2012 ANNUAL REPORT
41
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various commitments that will have an impact on the Company’s
future operations. As at December 31, 2012, no entities were consolidated under the Standing Interpretations Committee
(“SIC”) 12, “Consolidation – Special Purpose Entities”. The following table summarizes the Company’s commitments as at
December 31, 2012:
($ millions)
2013
2014
2015
2016
2017
Thereafter
Product transportation and pipeline
Offshore equipment operating leases
and offshore drilling
Long-term debt (1)
Interest and other financing costs (2)
Office leases
Other
$
$
$
$
$
$
231 $
218 $
204 $
135 $
117 $
788
156 $
798 $
414 $
33 $
173 $
135 $
846 $
395 $
34 $
95 $
104 $
76 $
57 $
593 $
1,027 $
1,094 $
359 $
338 $
283 $
32 $
43 $
33 $
10 $
35 $
2 $
65
4,430
3,782
262
7
(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, 2012.
In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These contracts can be cancelled by the Company upon notice
without penalty, subject to the costs incurred up to and in respect of the cancellation.
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is a 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, 2012, 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.
42
CANADIAN NATURAL
2012 ANNUAL REPORT
The following tables summarize the company gross proved and proved plus probable reserves using forecast prices and costs as at
December 31, 2012, prepared in accordance with NI 51-101 reserves disclosures:
Proved Reserves
Light and
Medium
Crude Oil
(MMbbl)
Primary
Heavy
Crude Oil
(MMbbl)
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
Bitumen
(Thermal
Oil)
(MMbbl)
Synthetic
Crude Oil
(MMbbl)
Natural
Gas
(Bcf)
Natural
Gas
Liquids
(MMbbl)
Barrels
of Oil
Equivalent
(MMBOE)
December 31, 2011
451
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
Proved Plus
Probable Reserves
December 31, 2011
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2012
–
4
6
–
1
–
4
6
(29)
443
175
–
24
20
–
–
–
–
31
(46)
204
276
974
2,119
4,447
95
4,831
–
1
–
5
–
–
–
(1)
(14)
267
–
68
10
–
–
–
–
50
(36)
–
–
–
–
–
–
14
153
(31)
1,066
2,255
6
52
16
–
43
(1)
(37)
56
(446)
4,136
–
2
1
–
1
–
(1)
5
(9)
94
1
107
40
5
9
–
11
253
(239)
5,018
Light and
Medium
Crude Oil
(MMbbl)
Primary
Heavy
Crude Oil
(MMbbl)
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
Bitumen
(Thermal
Oil)
(MMbbl)
Synthetic
Crude Oil
(MMbbl)
Natural
Gas
(Bcf)
Natural
Gas
Liquids
(MMbbl)
Barrels
of Oil
Equivalent
(MMBOE)
669
–
8
13
–
1
–
–
(8)
(29)
654
249
–
34
28
–
–
–
–
19
(46)
284
388
1,726
3,355
6,101
134
7,538
–
1
–
8
–
–
–
(11)
(14)
372
–
345
15
–
–
–
–
72
(36)
–
–
–
–
–
–
3
24
(31)
2,122
3,351
11
90
26
–
58
(3)
(40)
(10)
(446)
5,787
–
5
1
–
1
–
(1)
7
(9)
2
408
61
8
12
(1)
(4)
101
(239)
138
7,886
At December 31, 2012, the company gross proved crude oil, bitumen, SCO and NGLs reserves totaled 4,329 MMbbl, and gross
proved plus probable crude oil, bitumen, SCO and NGLs reserves totaled 6,921 MMbbl. Proved reserve additions and revisions
replaced 245% of 2012 production. Additions to proved reserves resulting from exploration and development activities, acquisitions
and future offset additions amounted to 143 MMbbl, and additions to proved plus probable reserves amounted to 460 MMbbl.
Net positive revisions amounted to 261 MMbbl for proved reserves and 105 MMbbl for proved plus probable reserves, primarily
due to technical revisions to prior estimates based on improved or better than expected reservoir performance.
At December 31, 2012, the company gross proved natural gas reserves totaled 4,136 Bcf, and gross proved plus probable natural gas
reserves totaled 5,787 Bcf. Proved reserve additions and revisions replaced 30% of 2012 production. Additions to proved reserves
resulting from exploration and development activities, acquisitions and future offset additions amounted to 116 Bcf, and additions to
proved plus probable reserves amounted to 182 Bcf. Net positive revisions amounted to 19 Bcf for proved reserves and net negative
revisions amounted to 50 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 related net present value of future net revenue of the
remaining reserves.
Additional reserves disclosure is annually disclosed in the AIF and the “Supplementary Oil and Gas Information” section of the
Company’s Annual Report.
CANADIAN NATURAL
2012 ANNUAL REPORT
43
RISKS AND UNCERTAINTIES
The Company is exposed to various operational risks inherent in the exploration, development, production and marketing of crude
oil and NGLs and natural gas and the mining and upgrading of bitumen into SCO. These inherent risks include, but are not limited
to, the following 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;
Volatility in the prevailing prices of crude oil and NGLs and natural gas;
Regulatory risk related to approval for exploration and development activities, which can add to costs or cause delays in projects;
Labour risk associated with securing the manpower necessary to complete capital projects in a timely and cost effective manner;
Operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas;
Success of exploration and development activities;
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 predominantly
all sales are based on US dollar denominated benchmarks;
Environmental impact risk associated with exploration and development activities, including GHG;
Geopolitical risks associated with changing governments or governmental policies, social instability and other political,
economic or diplomatic developments in the regions where the Company has its operations;
Future legislative and regulatory developments related to environmental regulation;
Potential actions of governments, regulatory authorities and other stakeholders that may result in costs or restrictions in the
jurisdictions where the Company has operations;
Changing royalty regimes;
Business interruptions because of unexpected events such as fires or explosions whether caused by human error or nature,
severe storms and other calamitous acts of nature, blowouts, freeze-ups, mechanical or equipment failures of facilities and
infrastructure and other similar events affecting the Company or other parties whose operations or assets directly or indirectly
impact the Company and that may or may not be financially recoverable;
The access to markets for the Company’s products; and
Other circumstances affecting revenue and expenses.
The Company uses a variety of means to help mitigate and/or minimize these risks. The Company maintains a comprehensive
property loss and business interruption insurance program to reduce risk 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 price, foreign currency and interest rate exposures. The Company is exposed to possible
losses in the event of non-performance by counterparties to derivative financial instruments; however, the Company manages
this credit risk by entering into agreements with 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.
44
CANADIAN NATURAL
2012 ANNUAL REPORT
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.
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 and support for Canada’s Oil Sands
Innovation Alliance (“COSIA”);
CO2 reduction programs including the injection of CO2 into tailings and for use in enhanced oil recovery;
A program in place related to progressive reclamation and tailings management for the Horizon Oil Sands facility; and
Participation and support for the Joint Oil Sands Monitoring Program.
CANADIAN NATURAL
2012 ANNUAL REPORT
45
For 2012, the Company’s capital expenditures included $204 million for abandonment expenditures (2011 – $213 million;
2010 – $179 million). The Company’s estimated discounted ARO at December 31, 2012 was as follows:
($ millions)
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream
2012
2011
$
2,079 $
1,862
1,030
218
937
2
723
192
798
2
$
4,266 $
3,577
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 Canadian legislators and
regulators as they develop and implement new GHG emission laws and regulations. Internally, the Company is pursuing an
integrated emissions reduction strategy, to ensure that it is able to comply with existing and future emissions reduction requirements,
for both GHGs and air pollutants (such as sulphur dioxide and oxides of nitrogen). The Company continues to develop strategies
that will enable it to deal with the risks and opportunities associated with new GHG and air emissions policies. In addition, the
Company is working with relevant parties to ensure that new policies encourage technological innovation, energy efficiency, and
targeted research and development while not impacting competitiveness.
In Canada, the federal government has indicated its intent to develop regulations 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. Three of the Company’s facilities, the Horizon facility, the Primrose/Wolf Lake in situ heavy crude
oil facilities and the Hays sour natural gas plant are subject to compliance under the regulations. The Kirby South in situ heavy
crude oil facility will be subject to compliance under the regulations in 2016. In the province of British Columbia, carbon tax is
currently being assessed at $30/tonne of CO2e on fuel consumed and gas flared in the province. 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 2015. 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 outcome of which cannot be predicted. The ultimate form of
Canadian regulation is anticipated to be strongly influenced by the regulatory decisions made within the United States. Various
states have enacted or are evaluating low carbon fuel standards, which may affect access to market for crude oil with higher
emissions intensity.
46
CANADIAN NATURAL
2012 ANNUAL REPORT
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, participation in an industry
initiative to promote an integrated CO2 capture and storage network, and participation in organizations that are researching
technologies to reduce GHG emissions (specifically COSIA and Carbon Management Canada (“CMC”)).
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.
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING POLICIES
The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the application
of IFRS that have a significant impact on the financial results of the Company. Actual results could differ from estimated amounts,
and those differences may be material.
Critical accounting 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. E&E assets are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined.
Technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment
of proved reserves is made. The judgements associated with the estimation of proved reserves are described below in “Crude Oil
and Natural Gas Reserves”.
An alternative acceptable accounting method for E&E 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 in estimated probable reserves volumes, significant increases in
estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory
frameworks. The determination of the fair value of CGUs requires the use of assumptions and estimates including 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, except for major components, which are depreciated using a straight-line method over their estimated useful
lives. 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.
CANADIAN NATURAL
2012 ANNUAL REPORT
47
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,
discount rates and income taxes as well as 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
Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and the timing of
future capital expenditures, all of which are subject to many uncertainties, interpretations, and judgements. The Company expects
that, over time, its reserve estimates will be revised upward or downward based on updated information such as the results of
future drilling, testing and production levels, and may be affected by changes in commodity prices. Reserve estimates can have
a significant impact on net earnings, as they are a key component in the calculation of depletion, depreciation and amortization
and for determining potential asset impairment. For example, a revision to 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 property, plant and equipment and E&E carrying amounts.
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 4.3%. 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 likely be due.
48
CANADIAN NATURAL
2012 ANNUAL REPORT
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
estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the
amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties.
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.
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 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, 2012, 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, 2012,
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 2012 that have materially affected, or are reasonably likely to materially affect, internal
control over financial reporting.
While the Company’s management believes that the Company’s disclosure controls and procedures and internal control over
financial reporting provide a reasonable level of assurance they are effective, they recognize that all control systems have
inherent limitations. Because of its inherent limitations, the Company’s control systems may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
CANADIAN NATURAL
2012 ANNUAL REPORT
49
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 was the first year in which the Company prepared its consolidated
financial statements and the related notes 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.
Unless otherwise stated, comparative figures for 2010 have been restated from Canadian GAAP to comply with IFRS.
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
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 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. In a joint operation, the parties with joint control have rights to the assets and obligations for the liabilities of
the joint arrangement and are required to recognize their proportionate interest in the assets, liabilities, revenues and expenses
of the joint arrangement. In a joint venture, the parties have an interest in the net assets of the arrangement and are required
to apply the equity method of accounting.
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 may impact the related disclosures.
Adoption of the above standards is not expected to result in a significant accounting change to the Company’s consolidated
financial statements, but may impact the related disclosures.
In May 2011, the IASB also issued IFRS 13 “Fair Value Measurement”, effective January 1, 2013, which 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. The Company will be required to include its own credit risk in measuring the carrying amount
of a risk management liability. In addition, the new standard may impact certain fair value disclosures.
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. The Company is
currently assessing the impact of this new standard on its consolidated financial statements.
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. Adoption of this amended standard is not expected to result
in a significant change in the presentation of the Company’s consolidated financial statements.
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. Adoption of this standard is not expected to result in a significant change to the Company’s consolidated
financial statements.
50
CANADIAN NATURAL
2012 ANNUAL REPORT
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 2013 to average between 482,000 bbl/d and 513,000 bbl/d
of crude oil and NGLs and between 1,085 MMcf/d and 1,145 MMcf/d of natural gas.
Capital expenditures in 2013 are currently targeted to be as follows:
($ millions)
Exploration and Production
North America natural gas
North America crude oil
International crude oil
Thermal In Situ Oil Sands
Primrose and Future
Kirby South Phase 1
Kirby North Phase 1
Property acquisitions, dispositions and other
Total Exploration and Production
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 Oil Sands Mining and Upgrading
Total
The above capital expenditure 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 / service wells – Oil Sands Mining and Upgrading
Total
2013 Guidance
$
445
1,965
605
770
315
205
85
$
4,390
100
60
180
940
535
20
245
$
2,080
180
105
190
2,555
6,945
$
$
2013 Guidance
30
1,160
218
353
1,761
CANADIAN NATURAL
2012 ANNUAL REPORT
51
North America
The 2013 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
Deep natural gas
Total
2013 Guidance
4
26
30
The 2013 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
Oil Sands Mining and Upgrading
2013 Guidance
889
132
114
19
1,154
The Company continues to execute its disciplined strategy of staged expansion and work remains on track. The budgeted project
capital expenditures reflect the Board of Directors approval of approximately $2.1 billion in targeted strategic expansion.
North Sea
During 2013, capital expenditures will be incurred on drilling programs at Ninian and Tiffany in the North Sea. The Company is
currently targeting to drill 3 net crude oil wells.
Offshore Africa
During 2013, capital expenditures will be incurred on drilling and completions at the Espoir field. The Company is currently
targeting to drill 3 net crude oil wells.
52
CANADIAN NATURAL
2012 ANNUAL REPORT
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 2012, excluding
mark-to-market gains (losses) on risk management activities and is not necessarily indicative of future results. Each separate line
item in the sensitivity analysis shows the effect of a change in that variable only with all other variables being held constant.
Price changes
Crude oil – WTI US$1.00/bbl (1)
Excluding financial derivatives
Including financial derivatives
Natural gas – AECO C$0.10/Mcf (1)
Volume changes
Crude oil – 10,000 bbl/d
Natural gas – 10 MMcf/d
Foreign currency rate change
$0.01 change in US$ (1)
Including financial derivatives
Interest rate change – 1%
Cash flow
from
operations
($ millions)
Cash flow
from
operations
(per common
share, basic)
Net earnings
($ millions)
Net earnings
(per common
share, basic)
$
$
$
$
$
$
$
110 $
110 $
0.10 $
0.10 $
110 $
110 $
24 $
0.02 $
24 $
131 $
4 $
0.12 $
– $
86 $
– $
78 – 79 $
7 $
0.07 $
0.01 $
37 – 38 $
7 $
0.10
0.10
0.02
0.08
–
0.03
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, 2012.
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
Crude oil and NGLs (bbl/d)
North America – Exploration and Production
305,613
316,483
332,895
351,983
326,829
295,618
270,562
Q1
Q2
Q3
Q4
2012
2011
2010
North America – Oil Sands Mining and Upgrading 46,090
115,823
North America – Exploration and Production
519,046
521,472
527,743
537,449
526,460
500,778
473,447
North America – Oil Sands Mining and Upgrading 46,090
115,823
North Sea
Offshore Africa
Total
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Total
Barrels of oil equivalent (BOE/d)
North Sea
Offshore Africa
Total
23,046
20,712
17,619
20,598
99,205
19,502
17,566
83,079
19,140
15,762
86,077
19,824
18,648
40,434
29,992
23,009
90,867
33,292
30,264
395,461
470,523
469,168
469,964
451,378
389,053
424,985
1,281
1,230
1,169
1,113
1,198
1,231
1,217
3
18
2
23
2
20
1
20
2
20
7
19
10
16
1,302
1,255
1,191
1,134
1,220
1,257
1,243
23,509
23,634
17,885
24,427
99,205
19,835
20,833
83,079
19,386
19,059
86,077
20,151
21,977
40,434
31,082
26,232
90,867
34,973
32,904
612,279
679,607
667,616
658,973
654,665
598,526
632,191
CANADIAN NATURAL
2012 ANNUAL REPORT
53
PER UNIT RESULTS – EXPLORATION AND PRODUCTION (1)
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
Netback
Q1
Q2
Q3
Q4
2012
2011
2010
$ 80.08 $ 69.99 $ 67.59 $ 64.23 $ 70.24 $ 77.46 $ 65.81
13.08
16.78
9.18
16.66
12.08
15.79
8.59
15.32
10.67
16.11
12.30
15.75
10.09
14.16
$ 50.22 $ 44.15 $ 39.72 $ 40.32 $ 43.46 $ 49.41 $ 41.56
$
2.47 $
1.90 $
2.28 $
3.16 $
2.44 $
3.73 $
0.05
1.34
0.05
1.15
0.05
1.30
0.21
1.43
0.09
1.31
0.18
1.15
$
1.08 $
0.70 $
0.93 $
1.52 $
1.04 $
2.40 $
4.08
0.20
1.09
2.79
$ 55.21 $ 49.17 $ 49.08 $ 49.83 $ 50.81 $ 57.16 $ 49.90
8.23
13.43
5.93
13.06
7.94
12.97
6.22
13.11
7.07
13.14
8.12
12.42
6.72
11.25
$ 33.55 $ 30.18 $ 28.17 $ 30.50 $ 30.60 $ 36.62 $ 31.93
(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.
PER UNIT RESULTS – OIL SANDS MINING AND UPGRADING (1)
Crude oil and NGLs ($/bbl)
SCO sales price (2)
Bitumen royalties (3)
Adjusted cash production costs (4)
Netback
Q1
Q2
Q3
Q4
2012
2011
2010
$ 97.09 $ 88.11 $ 87.40 $ 87.34 $ 88.91 $ 99.74 $ 77.89
5.16
46.24
5.20
36.98
3.45
42.69
3.80
49.27
4.34
42.83
3.99
36.64
2.72
36.36
$ 45.69 $ 45.93 $ 41.26 $ 34.27 $ 41.74 $ 59.11 $ 38.81
(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 2012 and 2011 are based on sales volumes excluding the period during suspension of production.
TRADING AND SHARE STATISTICS
TSX – C$
Trading volume (thousands)
Share Price ($/share)
High
Low
Close
Market capitalization as at
December 31 ($ millions)
Shares outstanding (thousands)
NYSE – US$
Trading volume (thousands)
Share Price ($/share)
High
Low
Close
Market capitalization as at
December 31 ($ millions)
Shares outstanding (thousands)
54
CANADIAN NATURAL
2012 ANNUAL REPORT
Q1
Q2
Q3
Q4
2012
2011
209,737
185,964
175,483
158,516
729,700
800,044
41.12 $
34.88 $
33.97 $
31.52 $
41.12 $
32.10 $
25.97 $
25.58 $
26.88 $
25.58 $
33.06 $
27.31 $
30.33 $
28.64 $
28.64 $
50.50
27.25
38.15
$
31,277 $
41,830
1,092,072
1,096,460
214,928
221,660
208,889
199,170
844,647
937,481
41.38 $
35.40 $
35.12 $
32.07 $
41.38 $
32.09 $
25.13 $
25.01 $
26.83 $
25.01 $
33.18 $
26.85 $
30.79 $
28.87 $
28.87 $
52.04
25.69
37.37
$
$
$
$
$
$
$
31,528 $
40,975
1,092,072
1,096,460
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 consolidated financial statements as at and for the year ended December 31, 2012; and
the effectiveness of the Company’s internal control over financial reporting as at December 31, 2012.
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, 2013
Douglas A. Proll, CA
Chief Financial Officer and
Senior Vice-President, Finance
Murray G. Harris, CA
Vice-President, Financial Controller
and Horizon Accounting
CANADIAN NATURAL
2012 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 13a–15(f) and 15d–15(f) under the United States Securities Exchange Act of 1934, as amended.
Management, including the Company’s President and the Company’s Chief Financial Officer and Senior Vice-President, Finance,
performed an assessment of the Company’s internal control over financial reporting based on the criteria established in Internal
Control – Integrated Framework 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, 2012. 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, 2012, as stated in their Auditor’s Report.
Steve W. Laut
President
Calgary, Alberta, Canada
March 6, 2013
Douglas A. Proll, CA
Chief Financial Officer and
Senior Vice-President, Finance
56
CANADIAN NATURAL
2012 ANNUAL REPORT
INDEPENDENT AUDITOR’S REPORT
To the Shareholders of Canadian Natural Resources Limited
We have completed integrated audits of Canadian Natural Resources Limited’s 2012 and 2011 consolidated financial statements
and its internal control over financial reporting as at December 31, 2012 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, 2012 and December 31, 2011 and the consolidated statements of earnings,
comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2012, and
the related notes, which comprise a summary of significant accounting policies and other explanatory information.
Management’s responsibility for the consolidated financial statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with
International Financial Reporting Standards as issued by the International Accounting Standards Board and for such internal control
as management determines is necessary to enable the preparation of consolidated financial statements that are free from material
misstatement, whether due to fraud or error.
Auditor’s responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our
audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing
standards also require that we comply with ethical requirements.
An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend on the auditor’s 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, 2012 and December 31, 2011 and its financial performance and its cash flows for
each of the three years in the period ended December 31, 2012 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, 2012,
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.
CANADIAN NATURAL
2012 ANNUAL REPORT
57
Auditor’s responsibility
Our responsibility is to express an opinion on Canadian Natural Resources Limited’s internal control over financial reporting based on
our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was maintained in all material respects.
An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control,
based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances.
We believe that our audit provides a reasonable basis for our audit opinion on Canadian Natural Resources Limited’s internal control
over financial reporting.
Definition of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Inherent limitations
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Opinion
In our opinion, Canadian Natural Resources Limited maintained, in all material respects, effective internal control over financial
reporting as at December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by COSO.
Chartered Accountants
Calgary, Alberta, Canada
March 6, 2013
58
CANADIAN NATURAL
2012 ANNUAL REPORT
CONSOLIDATED BALANCE SHEETS
As at December 31
(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
Commitments and contingencies (note 18)
Approved by the Board of Directors on March 6, 2013
Note
2012
2011
4
5
6
7
8
9
8
9
11
12
13
$
37 $
1,197
554
126
1,914
2,611
44,028
427
$
48,980 $
$
465 $
2,273
285
798
155
3,976
7,938
4,609
8,174
34
2,077
550
120
2,781
2,475
41,631
391
47,278
526
2,347
347
359
455
4,034
8,212
3,913
8,221
24,697
24,380
3,709
20,516
58
24,283
$
48,980 $
3,507
19,365
26
22,898
47,278
Catherine M. Best
Chair of the Audit Committee and Director
N. Murray Edwards
Chairman of the Board of Directors and Director
CANADIAN NATURAL
2012 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 (gain) loss
Horizon asset impairment provision
Insurance recovery – property damage
Insurance recovery – business interruption
Equity loss from jointly controlled entity
Earnings before taxes
Current income tax expense
Deferred income tax (recovery) expense
Net earnings
Net earnings per common share
Basic
Diluted
Note
2012
2011
$
16,195 $
15,507 $
(1,606)
14,589
4,249
2,752
4,328
270
(214)
151
364
120
(49)
–
–
–
9
11,980
2,609
747
(30)
(1,715)
13,792
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
7
11
11
$
1,892 $
2,643 $
15 $
15 $
1.72 $
1.72 $
2.41 $
2.40 $
2010
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
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 income (loss), net of taxes of
$4 million (2011 – $5 million, 2010 – $13 million)
Reclassification to net earnings, net of taxes of
$nil (2011 – $17 million, 2010 – $1 million)
Foreign currency translation adjustment
Translation of net investment
Other comprehensive income (loss), net of taxes
2012
2011
$
1,892 $
2,643 $
2010
1,673
31
(7)
24
8
32
(23)
52
29
(12)
17
(40)
(4)
(44)
(24)
(68)
Comprehensive income
$
1,924 $
2,660 $
1,605
60
CANADIAN NATURAL
2012 ANNUAL REPORT
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
12
12
12
13
2012
2011
2010
$
3,507 $
3,147 $
194
255
45
(37)
3,709
19,365
1,892
(281)
(460)
20,516
26
32
58
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
$
24,283 $
22,898 $
20,368
CANADIAN NATURAL
2012 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
Equity loss from jointly controlled entity
Deferred income tax (recovery) expense
Horizon asset impairment provision
Insurance recovery – property damage
Other
Abandonment expenditures
Net change in non-cash working capital
Financing activities
Issue (repayment) of bank credit facilities, net
Issue (repayment) of medium-term notes, net
(Repayment) 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
2012
2011
2010
$
1,892 $
2,643 $
1,673
4,328
(214)
151
(42)
129
(210)
9
(30)
–
–
(47)
(204)
447
6,209
172
498
(344)
194
(318)
(444)
(37)
(279)
(6,104)
2
175
(5,927)
3
34
37 $
464 $
639 $
$
$
$
6,10
10
19
8
19
19
19
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
62
CANADIAN NATURAL
2012 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(tabular amounts in millions of Canadian dollars, unless otherwise stated)
1. ACCOUNTING POLICIES
Canadian Natural Resources Limited (the “Company”) is a senior independent crude oil and natural gas exploration, development
and production company. The Company’s exploration and production operations are focused in North America, largely in Western
Canada; the United Kingdom (“UK”) portion of the North Sea; and Côte d’Ivoire, Gabon, and South Africa in Offshore Africa.
The Horizon Oil Sands Mining and Upgrading segment (“Horizon”) produces synthetic crude oil through bitumen mining and
upgrading operations.
Within Western Canada, the Company maintains certain midstream activities that include pipeline operations, an electricity co-
generation system and an investment in the North West Redwater Partnership (“Redwater”).
The Company was incorporated in Alberta, Canada. The address of its registered office is 2500, 855-2 Street S.W., Calgary,
Alberta, Canada.
The Company’s consolidated financial statements and the related notes have been prepared in accordance with International
Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The accounting policies
adopted by the Company under IFRS are set out below. The Company has consistently applied the same accounting policies
throughout all periods presented.
(A) Principles of Consolidation
The consolidated financial statements have been prepared under the historical cost convention, unless otherwise required.
The consolidated financial statements include the accounts of the Company and all of its subsidiary companies and wholly
owned partnerships.
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 initial and subsequent investments
are recognized at cost and subsequently adjusted for the Company’s share of the jointly controlled entity’s income or loss, less
dividends received.
(B) Segmented Information
Operating segments have been determined based on the nature of the Company’s activities and the geographic locations in which
the Company operates, and are consistent with the level of information regularly provided to and reviewed by the Company’s chief
operating decision makers.
(C) Cash and Cash Equivalents
Cash comprises cash on hand and demand deposits. Other investments (term deposits and certificates of deposit) with an original
term to maturity at purchase of three months or less are reported as cash equivalents in the consolidated balance sheets.
(D) 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.
CANADIAN NATURAL
2012 ANNUAL REPORT
63
(E) Exploration and Evaluation Assets
Exploration and evaluation (“E&E”) assets consist of the Company’s crude oil and natural gas exploration projects that are pending
the determination of proved reserves.
E&E costs are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies,
seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset
retirement costs. E&E costs do not include general prospecting or evaluation costs incurred prior to having obtained the legal rights
to explore an area. These costs are recognized in net earnings.
Once the technical feasibility and commercial viability of E&E assets are determined and a development decision is made by
management, the E&E assets are tested for impairment upon reclassification to property, plant and equipment. The technical
feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved
reserves is made.
E&E assets are also tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may
exceed their recoverable amount, by comparing the relevant costs to the fair value of Cash Generating Units (“CGUs”), aggregated
at the segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity
prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases
in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or
regulatory frameworks.
(F) Property, Plant and Equipment
Property, plant and equipment is measured at cost less accumulated depletion and depreciation and impairment provisions. Assets
under construction are not depleted or depreciated until available for their intended use. The capitalized value of a finance lease is
included in property, plant and equipment.
Exploration and Production
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.
Crude oil and natural gas properties are depleted using the unit-of-production method over proved reserves, except for major
components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production 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 are amortized on the unit-of-production method based on Horizon proved reserves. Costs of the upgrader and
related infrastructure located on the Horizon site are amortized on the unit-of-production method based on productive capacity
of the upgrader and related infrastructure. Other equipment is depreciated on a straight-line basis over its estimated useful life
ranging from 2 to 15 years.
Midstream and Head Office
The Company capitalizes all costs that expand the capacity or extend the useful life of the 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
2012 ANNUAL REPORT
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.
(G) 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.
(H) 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.
(I) 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.
(J) 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.
CANADIAN NATURAL
2012 ANNUAL REPORT
65
(K) Asset Retirement Obligations
The Company provides for asset retirement obligations on all of its property, plant and equipment based on current legislation and
industry operating practices. Provisions for asset retirement obligations related to property, plant and equipment are recognized
as a liability in the period in which they are incurred. Provisions are measured at the present value of management’s best estimate
of expenditures required to settle the obligation as at the date of the balance sheet. Subsequent to the initial measurement, the
obligation is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future
cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement
obligation accretion expense whereas changes due to discount rates or 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.
(L) 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.
(M) Revenue Recognition and Costs of Goods Sold
Revenue from the sale of crude oil and natural gas is recognized when title passes to the customer, delivery has taken place
and collection is reasonably assured. The Company assesses customer creditworthiness, both before entering into contracts and
throughout the revenue recognition process.
Revenue represents the Company’s share net of royalty payments to governments and other mineral interest owners. Related costs
of goods sold are comprised of production, transportation and blending, and depletion, depreciation and amortization expenses.
These amounts have been separately presented in the consolidated statements of earnings.
(N) Production Sharing Contracts
Production generated from Offshore Africa is shared under the terms of various Production Sharing Contracts (“PSCs”). Product
sales are divided into cost recovery oil and profit oil. Cost recovery oil allows the Company to recover its capital and production
costs and the costs carried by the Company on behalf of the respective Government State Oil Companies (the “Governments”).
Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been
allocated to the Governments. The Governments’ share of profit oil attributable to the Company’s equity interest is allocated to
royalty expense and current income tax expense in accordance with the terms of the respective PSCs.
(O) 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
2012 ANNUAL REPORT
Deferred income tax assets and liabilities are calculated using the substantively enacted income tax rates that are expected to
apply when the asset or liability is recovered. Deferred income tax assets or liabilities are not recognized when they arise on the
initial recognition of an asset or liability in a transaction (other than in a business combination) that, at the time of the transaction,
affects neither accounting nor taxable profit. Deferred income tax assets or liabilities are also not recognized on possible future
distributions of retained earnings of subsidiaries where the timing of the distribution can be controlled by the Company and it
is probable that a distribution will not be made in the foreseeable future, or when distributions can be made without incurring
income taxes.
Deferred income tax assets for deductible temporary differences and tax loss carryforwards are recognized to the extent that it
is probable that future taxable profits will be available against which the temporary differences or tax loss carryforwards can be
utilized. The carrying amount of deferred income tax assets is reviewed at each reporting date, and is reduced if it is no longer
probable that sufficient future taxable profits will be available against which the temporary differences or tax loss carryforwards
can be utilized.
Current income tax is calculated based on net earnings for the period, adjusted for items that are non-taxable or taxed in different
periods, using income tax rates that are substantively enacted at each reporting date.
Income taxes are recognized in net earnings or other comprehensive income, consistent with the items to which they relate.
(P) Share-Based Compensation
The Company’s Stock Option Plan (the “Option Plan”) provides current employees with the right to elect to receive common shares
or a cash payment in exchange for stock options surrendered. The liability for awards granted to employees is initially measured
based on the grant date fair value of the awards and the number of awards expected to vest. The awards are re-measured each
reporting period for subsequent changes in the fair value of the liability. Fair value is determined using the Black-Scholes valuation
model. 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.
(Q) 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 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.
CANADIAN NATURAL
2012 ANNUAL REPORT
67
(R) 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. 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 primarily relied on external,
readily-observable market inputs including quoted commodity prices and volatility, interest rate yield curves, and foreign exchange
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 recognized in risk management
activities in net earnings. All changes in the fair value of non-designated crude oil and natural gas commodity price contracts are
recognized in risk management activities in net earnings.
The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on certain of its
long-term debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. Changes in the fair value of interest rate swap contracts designated as fair
value hedges and corresponding changes in the fair value of the hedged long-term debt are recognized in interest expense in net
earnings. Changes in the fair value of non-designated interest rate swap contracts are recognized in risk management activities in
net earnings.
Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt.
The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal
amounts on which the payments are based. Changes in the fair value of the foreign exchange component of cross currency swap
contracts designated as cash flow hedges related to the notional principal amounts are recognized in foreign exchange gains and
losses in net earnings. The effective portion of changes in the fair value of the interest rate component of cross currency swap
contracts designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to interest
expense when 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 recognized in risk management activities in net earnings.
Realized gains or losses on the termination of financial instruments that have been designated as cash flow hedges are deferred
under accumulated other comprehensive income 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 in net earnings. Realized
gains or losses on the termination of financial instruments that have not been designated as hedges are recognized in net earnings.
Upon termination of an interest rate swap designated as a fair value hedge, the interest rate swap is derecognized 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 non-designated foreign currency forward contracts are recognized in risk management activities in net earnings.
Embedded derivatives are derivatives that are included in a non-derivative host contract. Embedded derivatives are recorded at
fair value separately from the host contract when their economic characteristics and risks are not clearly and closely related to the
host contract.
68
CANADIAN NATURAL
2012 ANNUAL REPORT
(S) Comprehensive Income
Comprehensive income is comprised of the Company’s net earnings and other comprehensive income. Other comprehensive
income includes the effective portion of changes in the fair value of derivative financial instruments designated as cash flow hedges
and foreign currency translation gains and losses arising from the net investment in foreign operations that do not have a Canadian
dollar functional currency. Other comprehensive income is shown net of related income taxes.
(T) Per Common Share Amounts
The Company calculates basic earnings per common share by dividing net earnings by the weighted average number of common
shares outstanding during the period. As the Company’s Option Plan allows for the settlement of stock options in either cash or
shares at the option of the holder, diluted earnings per common share is calculated using the more dilutive of cash settlement or
share settlement under the treasury stock method.
(U) Share Capital
Common shares are classified as equity. Costs directly attributable to the issue of new shares or options are included in equity
as a deduction from proceeds, net of tax. When the Company acquires its own common shares, share capital is reduced by the
average carrying value of the shares purchased. The excess of the purchase price over the average carrying value is recognized as
a reduction of retained earnings. Shares are cancelled upon purchase.
(V) Dividends
Dividends on common shares are recognized in the Company’s financial statements in the period in which the dividends are
approved by the Board of Directors.
2. ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
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. In a joint operation, the parties with joint control have rights to the assets and obligations for the liabilities of
the joint arrangement and are required to recognize their proportionate interest in the assets, liabilities, revenues and expenses
of the joint arrangement. In a joint venture, the parties have an interest in the net assets of the arrangement and are required
to apply the equity method of accounting.
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 may impact the related disclosures.
Adoption of the above standards is not expected to result in a significant accounting change to the Company’s consolidated
financial statements, but may impact the related disclosures.
In May 2011, the IASB also issued IFRS 13 “Fair Value Measurement”, effective January 1, 2013, which 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. The Company will be required to include its own credit risk in measuring the carrying amount
of a risk management liability. In addition, the new standard may impact certain fair value disclosures.
CANADIAN NATURAL
2012 ANNUAL REPORT
69
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. The Company is
currently assessing the impact of this new standard on its consolidated financial statements.
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. Adoption of this amended standard is not expected to result
in a significant change in the presentation of the Company’s consolidated financial statements.
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. Adoption of this standard is not expected to result in a significant change to the Company’s consolidated
financial statements.
3. CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS
The Company has made estimates, assumptions and judgements regarding certain assets, liabilities, revenues and expenses in the
preparation of the consolidated financial statements, primarily related to unsettled transactions and events as of the date of the
consolidated financial statements. Accordingly, actual results may differ from estimated amounts. The estimates, assumptions and
judgements that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the
next financial year are addressed below.
(A) Crude Oil and Natural Gas Reserves
Purchase price allocations, depletion, depreciation and amortization, and amounts used in impairment calculations are based
on estimates of crude oil and natural gas reserves. Reserve estimates are based on engineering data, estimated future prices,
expected future rates of production and the timing of future capital expenditures, all of which are subject to many uncertainties,
interpretations and judgements. The Company expects that, over time, its reserve estimates will be revised upward or downward
based on updated information such as the results of future drilling, testing and production levels, and may be affected by changes
in commodity prices.
(B) Asset Retirement Obligations
The Company provides for asset retirement obligations on its property, plant and equipment based on current legislation and
operating practices. Estimated future costs include assumptions on dates of future abandonment and technological advances
and estimates of future inflation rates and discount rates. Actual costs may vary from the estimated provision due to changes in
environmental legislation, the impact of inflation, changes in technology, changes in operating practices, and changes in the date
of abandonment due to changes in reserve life, and may have a material impact on the estimated provision.
(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 likely be due.
(D) Fair Value of Derivatives and Other Financial Instruments
The fair value of financial instruments that are not traded in an active market is determined using valuation techniques.
The Company uses its judgement to select a variety of methods and make assumptions that are primarily based on market
conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in measuring
the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility, interest
rate yield curves and foreign exchange rates.
70
CANADIAN NATURAL
2012 ANNUAL REPORT
(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
estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the
amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties.
As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the
impact on future depletion, depreciation, and amortization expense and impairment tests.
(F) Share-Based Compensation
The Company has made various assumptions in estimating the fair values of the stock options granted under the Option Plan,
including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding
are remeasured for changes in the fair value of the liability.
(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, discount rates and income taxes 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.
(I) Contingencies
Contingencies are subject to measurement uncertainty as the related financial impact will only be confirmed by the outcome of a
future event. The assessment of contingencies requires the application of judgements and estimates including the determination
of whether a present obligation exists and the reliable estimation of the timing and amount of cash flows required to settle
the contingency.
4. INVENTORY
Product inventory
Materials and supplies
5. EXPLORATION AND EVALUATION ASSETS
2012
315 $
239
554 $
2011
328
222
550
$
$
Exploration and Production
North
America
North
Sea
Offshore
Africa
Oil Sands
Mining and
Upgrading
Total
Cost
At December 31, 2010
Additions
Transfers to property, plant and equipment
At December 31, 2011
Additions
Transfers to property, plant and equipment
$
2,366 $
5 $
31 $
– $
2,402
309
(233)
2,442
295
(173)
1
(6)
–
–
–
2
–
33
14
–
–
–
–
–
–
312
(239)
2,475
309
(173)
At December 31, 2012
$
2,564 $
– $
47 $
– $
2,611
CANADIAN NATURAL
2012 ANNUAL REPORT
71
6. PROPERTY, PLANT AND EQUIPMENT
Oil Sands
Mining
and
Exploration and Production
Upgrading Midstream
North
America
North
Sea
Offshore
Africa
Head
Office
Total
Cost
At December 31, 2010
$ 40,861 $ 3,813 $ 2,928 $ 14,169 $
291 $
216 $ 62,278
Additions
Transfers from E&E assets
Disposals/derecognitions (1)
Foreign exchange adjustments and other
At December 31, 2011
Additions
Transfers from E&E assets
Disposals/derecognitions
Foreign exchange adjustments and other
At December 31, 2012
Accumulated depletion and depreciation
5,026
233
–
–
46,120
4,160
173
(129)
–
235
6
–
93
76
–
(29)
69
4,147
3,044
556
–
(39)
(90)
75
–
(8)
(66)
1,545
–
(503)
–
15,211
1,757
–
(5)
–
$ 50,324 $ 4,574 $ 3,045 $ 16,963 $
7
–
–
–
298
14
–
–
18
6,907
–
–
–
234
36
–
–
239
(532)
162
69,054
6,598
173
(181)
–
312 $
–
(156)
270 $ 75,488
At December 31, 2010
$ 18,895 $ 2,205 $ 1,904 $
607 $
89 $
149 $ 23,849
Expense
Impairment (1)
Disposals/derecognitions (1)
Foreign exchange adjustments and other
At December 31, 2011
Expense
Disposals/derecognitions
Foreign exchange adjustments and other
2,826
–
–
–
21,721
3,399
(129)
–
248
–
–
59
242
–
(29)
35
2,512
2,152
294
(39)
(58)
165
(6)
(38)
266
396
(503)
10
776
447
(5)
(16)
7
–
–
–
96
7
–
–
15
3,604
–
–
2
166
16
–
–
396
(532)
106
27,423
4,328
(179)
(112)
At December 31, 2012
$ 24,991 $ 2,709 $ 2,273 $ 1,202 $
103 $
182 $ 31,460
Net book value
- at December 31, 2012
- at December 31, 2011
$ 25,333 $ 1,865 $
772 $ 15,761 $
209 $
88 $ 44,028
$ 24,399 $ 1,635 $
892 $ 14,435 $
202 $
68 $ 41,631
(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, resulting in an impairment charge of $396 million.
For additional information, refer to note 10.
Horizon project costs not subject to depletion
At December 31, 2012
At December 31, 2011
$
$
2,066
1,443
In addition, the Company has capitalized costs to date of $1,021 million (2011 – $528 million) related to the development of the Kirby
Thermal Oil Sands Project which are not subject to depletion.
During 2012, 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 $144 million (2011 – $1,012 million; 2010 – $1,482 million), net of associated
asset retirement obligations of $12 million (2011 – $79 million; 2010 – $22 million). Interests in jointly controlled assets were acquired
with full tax basis. No working capital or debt obligations were assumed.
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 and the asset is available for
its intended use. During 2012, pre-tax interest of $98 million was capitalized to property, plant and equipment (2011 – $59 million;
2010 – $28 million) using a capitalization rate of 4.8% (2011 – 4.7%; 2010 – 4.9%).
72
CANADIAN NATURAL
2012 ANNUAL REPORT
7. OTHER LONG-TERM ASSETS
Investment in North West Redwater Partnership
Other
2012
310 $
117
427 $
2011
321
70
391
$
$
Other long-term assets include an investment in the 50% owned Redwater. The investment is accounted for using the equity
method. Redwater has entered into an agreement to construct and operate a 50,000 barrel per day bitumen upgrader and refinery
(the “Project”) under processing agreements that target to process 12,500 barrels per day of bitumen feedstock for the Company
and 37,500 barrels per day of bitumen feedstock for the Alberta Petroleum Marketing Commission, an agent of the Government
of Alberta, under a 30 year fee-for-service tolling agreement. During 2012, the Project received board sanction from Redwater and
its partners.
The assets, liabilities, partners’ equity and equity loss related to Redwater and the Company’s 50% interest at December 31, 2012
were comprised as follows:
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Partners’ equity
Equity loss
Redwater
100% interest
Company
50% interest
$
$
$
$
$
$
40 $
810 $
68 $
162 $
620 $
18 $
20
405
34
81
310
9
Non-current liabilities represent interim borrowings by Redwater under credit facilities totaling $600 million which mature no later
than December 2017. These facilities are secured by a floating charge on the assets of Redwater with a mandatory repayment
required from future financing proceeds. At maturity, under its processing agreement, the Company would be obligated to pay
its 25% pro rata share of any shortfall.
Redwater has entered into various agreements related to the engineering and procurement of the Project. These contracts can be
cancelled by Redwater upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation.
CANADIAN NATURAL
2012 ANNUAL REPORT
73
8. LONG-TERM DEBT
Canadian dollar denominated debt
Bank credit facilities
Medium-term notes
4.50% unsecured debentures due January 23, 2013
4.95% unsecured debentures due June 1, 2015
3.05% unsecured debentures due June 19, 2019
US dollar denominated debt
US dollar debt securities
5.45% due October 1, 2012 (2012 – US$ nil; 2011 – US$350 million)
5.15% due February 1, 2013 (US$400 million)
1.45% due November 14, 2014 (US$500 million)
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 (US$500 million)
7.20% due January 15, 2032 (US$400 million)
6.45% due June 30, 2033 (US$350 million)
5.85% due February 1, 2035 (US$350 million)
6.50% due February 15, 2037 (US$450 million)
6.25% due March 15, 2038 (US$1,100 million)
6.75% due February 1, 2039 (US$400 million)
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) (4)
2012
2011
$
971 $
400
400
500
2,271
–
398
498
348
249
796
400
400
–
1,596
356
406
509
356
255
1,094
1,119
398
498
398
348
348
448
1,094
398
(20)
6,497
19
6,516
8,787
(51)
8,736
798
$
7,938 $
406
509
406
356
356
458
1,119
406
(21)
6,996
31
7,027
8,623
(52)
8,571
359
8,212
(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 amount of US$350 million of 4.90% unsecured notes due December 2014 was adjusted by $19 million to reflect the fair value impact of hedge
accounting. At December 31, 2011, the carrying amounts of US$350 million of 5.45% unsecured notes due October 2012 and US$350 million of 4.90%
unsecured notes due December 2014 were adjusted by $31 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.
(4) Subsequent to December 31, 2012, $400 million of 4.50% medium-term notes due January 2013 and US$400 million of 5.15% unsecured notes due February
2013 were repaid. This indebtedness was retired utilizing cash flow from operating activities generated in excess of capital expenditures and available bank credit
facilities as necessary.
74
CANADIAN NATURAL
2012 ANNUAL REPORT
Bank Credit Facilities
As at December 31, 2012, 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 2016; and
a £15 million demand credit facility related to the Company’s North Sea operations.
During 2012, the $1,500 million revolving syndicated credit facility was extended to June 2016. 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 or US dollar bankers’ acceptances, or LIBOR,
US base rate or Canadian prime loans.
The Company’s weighted average interest rate on bank credit facilities outstanding as at December 31, 2012, was 2.2%
(December 31, 2011 – 2.2%), and on long-term debt outstanding for the year ended December 31, 2012 was 4.8%
(December 31, 2011 – 4.7%).
In addition to the outstanding debt, letters of credit and financial guarantees aggregating $467 million, including an $87 million
financial guarantee related to Horizon and $276 million of letters of credit related to North Sea operations, were outstanding at
December 31, 2012. Subsequent to December 31, 2012, the letters of credit related to North Sea operations were increased to
$347 million.
Medium-Term Notes
During 2012, the Company issued $500 million of 3.05% medium-term notes due June 2019. After issuing these securities,
the Company has $2,500 million remaining on its outstanding $3,000 million base shelf prospectus that allows for the issue of
medium-term notes in Canada, which expires in November 2013. If issued, these securities will bear interest as determined at the
date of issuance.
US Dollar Debt Securities
During 2012, the Company repaid US$350 million of 5.45% unsecured notes.
During 2011, the Company repaid US$400 million of 6.70% unsecured notes and 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).
The Company has US$2,000 million remaining on its outstanding US$3,000 million base shelf prospectus that allows for the issue
of US dollar debt securities in the United States, which expires in November 2013. If issued, these securities will bear interest as
determined at the date of issuance.
Scheduled Debt Repayments
Scheduled debt repayments are as follows:
Year
2013
2014
2015
2016
2017
Thereafter
Repayment
798
846
593
1,027
1,094
4,430
$
$
$
$
$
$
CANADIAN NATURAL
2012 ANNUAL REPORT
75
9. OTHER LONG-TERM LIABILITIES
Asset retirement obligations
Share-based compensation
Risk management (note 17)
Other
Less: current portion
Asset Retirement Obligations
2012
$
4,266 $
154
257
87
4,764
155
$
4,609 $
2011
3,577
432
274
85
4,368
455
3,913
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 4.3% (2011 – 4.6%; 2010 – 5.1%). Reconciliations
of the discounted asset retirement obligations were as follows:
Balance – beginning of year
$
3,577 $
2,624 $
2012
2011
Liabilities incurred
Liabilities acquired
Liabilities settled
Asset retirement obligation accretion
Revision of estimates
Change in discount rate
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
51
12
(204)
151
384
315
(20)
42
79
(213)
130
472
422
21
2010
2,214
26
22
(179)
123
49
411
(42)
$
4,266 $
3,577 $
2,624
2012
2011
$
2,079 $
1,862
1,030
218
937
2
723
192
798
2
$
4,266 $
3,577
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.
2012
2011
2010
Balance – beginning of year
$
432 $
663 $
Share-based compensation (recovery) expense
Cash payment for stock options surrendered
Transferred to common shares
(Recovered from) capitalized to Oil Sands Mining and Upgrading
Balance – end of year
Less: current portion
(214)
(7)
(45)
(12)
154
129
(102)
(14)
(115)
–
432
384
$
25 $
48 $
622
203
(45)
(149)
32
663
623
40
The intrinsic value of vested stock options at December 31, 2012 was $36 million (2011 – $173 million; 2010 – $325 million).
76
CANADIAN NATURAL
2012 ANNUAL REPORT
The share-based compensation liability of $154 million at December 31, 2012 (2011 – $432 million; 2010 – $663 million) was
estimated using the Black-Scholes valuation model with the following weighted average assumptions:
Fair value
Share price
Expected volatility
Expected dividend yield
Risk free interest rate
Expected forfeiture rate
Expected stock option life (1)
(1) At original time of grant.
2012
2011
$
$
4.60 $
28.64 $
10.84 $
38.15 $
32.6%
1.5%
1.3%
4.2%
36.9%
0.9%
1.1%
4.7%
2010
16.49
44.35
33.5%
0.7%
1.9%
5.0%
4.5 years
4.5 years
4.5 years
10. HORIZON ASSET IMPAIRMENT PROVISION AND INSURANCE RECOVERY
In 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, related to the property damage resulting from a fire in the Horizon primary
upgrading coking plant. The Company also recorded final property damage insurance recoveries of $393 million and business
interruption insurance recoveries of $333 million in 2011. In 2012, upon final settlement of its insurance claims, all outstanding
insurance proceeds were collected.
11. INCOME TAXES
The provision for income tax was as follows:
2012
2011
2010
Current corporate income tax – North America
$
366 $
315 $
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(1) recovery – North Sea
Deferred income tax (recovery) expense
Income tax expense
(1) Petroleum Revenue Tax.
115
206
44
16
747
–
(30)
(30)
245
140
135
25
860
412
(5)
407
$
717 $
1,267 $
431
203
64
68
23
789
408
(9)
399
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 (gain) loss
Stock options exercised for common shares
Income tax rate and other legislative changes
Non-deductible Offshore Africa impairment charge
Other
Income tax expense
2012
25.1%
2011
26.6%
$
655 $
1,040 $
30
(13)
63
(2)
(56)
58
–
155
(77)
84
6
(31)
104
–
2010
28.1%
802
82
(30)
15
(17)
217
–
130
$
(18)
717 $
(14)
1,267 $
(11)
1,188
CANADIAN NATURAL
2012 ANNUAL REPORT
77
The following table summarizes the temporary differences that give rise to the net deferred income tax liability:
2012
2011
Deferred income tax liabilities
Property, plant and equipment and exploration and evaluation assets
$
8,834 $
Timing of partnership items
Unrealized foreign exchange gain on long-term debt
Deferred PRT
Deferred income tax assets
Asset retirement obligations
Loss carryforwards
Unrealized risk management activities
Other
831
142
42
9,849
(1,362)
(119)
(36)
(158)
(1,675)
Net deferred income tax liability
$
8,174 $
Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows:
8,404
1,065
149
74
9,692
(1,136)
(119)
(40)
(176)
(1,471)
8,221
2012
2011
2010
684
(139)
42
(8)
(127)
132
(60)
(9)
(116)
399
2010
7,462
399
(14)
(59)
–
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
465 $
(234)
(7)
–
(238)
–
–
(30)
14
662 $
77
(45)
44
(321)
–
25
(5)
(30)
The following table summarizes the movements of the net deferred income tax liability during the year:
Balance – beginning of year
$
8,221 $
7,788 $
2012
2011
$
(30) $
407 $
Deferred income tax (recovery) expense
Deferred income tax expense (recovery) included in other
comprehensive income
Foreign exchange adjustments
Other
Balance – end of year
(30)
4
(21)
–
407
12
20
(6)
$
8,174 $
8,221 $
7,788
Current income taxes recognized in each operating segment will vary depending upon available income tax deductions related to
the nature, timing and amount of capital expenditures incurred in any particular year.
During 2012, the UK government enacted legislation to restrict the combined corporate and supplementary income tax relief on
UK North Sea decommissioning expenditures to 50%. As a result of the income tax rate change, the Company’s deferred income
tax liability was increased by $58 million.
During 2011, the UK government enacted legislation to increase 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.
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.
78
CANADIAN NATURAL
2012 ANNUAL REPORT
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 provided that the distributions remain within certain limits.
12. SHARE CAPITAL
Authorized
Preferred shares issuable in a series.
Unlimited number of common shares without par value.
Issued
Common shares
Balance – beginning of year
Issued upon exercise of stock options
Previously recognized liability on stock options exercised for common shares
Purchase of common shares under Normal Course Issuer Bid
Balance – end of year
Preferred Shares
2012
2011
Number
of shares
(thousands)
Number
of shares
(thousands)
Amount
Amount
1,096,460 $
3,507
1,090,848 $
3,147
6,625
–
(11,013)
194
45
(37)
8,683
–
(3,071)
255
115
(10)
1,092,072 $
3,709
1,096,460 $
3,507
During 2012, the Company amended its Articles by special resolution of the shareholders, changing the designation of its
Class 1 preferred shares to “Preferred Shares” which may be issuable in series. If issued, the number of shares in each series, and
the designation, rights, privileges, restrictions and conditions attached to the shares will be determined by the Board of Directors
of the Company.
Dividend Policy
The Company has paid regular quarterly dividends in January, April, July and October of each year since 2001. The dividend policy
undergoes periodic review by the Board of Directors and is subject to change.
On March 6 , 2013, the Board of Directors set the regular quarterly dividend at $0.125 per common share (2012 – $0.105 per
common share; 2011 – $0.09 per common share).
Normal Course Issuer Bid
In 2012, 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 2012 and ending April 2013, up to
55,027,447 common shares. The Company’s Normal Course Issuer Bid announced in 2011 expired April 2012.
During 2012, the Company purchased for cancellation 11,012,700 common shares (2011 – 3,071,100 common shares;
2010 – 2,000,000 common shares) at a weighted average price of $28.91 per common share (2011 – $33.68 per common share;
2010 – $33.77 per common share), for a total cost of $318 million (2011 – $104 million; 2010 – $68 million). Retained earnings
were reduced by $281 million (2011 – $94 million; 2010 – $62 million), representing the excess of the purchase price of the
common shares over their average carrying value.
CANADIAN NATURAL
2012 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, 2012 and 2011:
Outstanding – beginning of year
Granted (1)
Surrendered for cash settlement
Exercised for common shares
Forfeited (1)
Outstanding – end of year
Exercisable – end of year
2012
2011
Stock options
(thousands)
Weighted
average
Stock options
Weighted
average
exercise price
(thousands)
exercise price
73,486 $
14,779 $
(998) $
(6,625) $
(6,895) $
73,747 $
29,366 $
34.85
29.27
29.82
29.19
36.68
34.13
33.73
66,844 $
19,516 $
(1,124) $
(8,683) $
(3,067) $
73,486 $
26,486 $
33.31
37.54
29.84
29.34
35.87
34.85
32.13
(1) Subsequent to December 31, 2012, 3,479,000 stock options at a weighted average exercise price of $28.74 were granted and 8,228,000 stock options at a
weighted average exercise price of $35.27 were forfeited.
The range of exercise prices of stock options outstanding and exercisable at December 31, 2012 was as follows:
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
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
8,690
9,993
17,019
25,583
10,432
2,030
73,747
1.18 $
5.17 $
3.22 $
2.70 $
3.16 $
2.79 $
3.04 $
23.17
28.02
33.45
36.48
42.23
45.68
34.13
6,478 $
98 $
6,289 $
11,926 $
3,757 $
818 $
29,366 $
23.15
29.09
34.07
35.80
42.24
46.22
33.73
80
CANADIAN NATURAL
2012 ANNUAL REPORT
13. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of accumulated other comprehensive income, net of taxes, were as follows:
Derivative financial instruments designated as cash flow hedges
Foreign currency translation adjustment
14. CAPITAL DISCLOSURES
2012
2011
$
$
86 $
(28)
58 $
62
(36)
26
The Company does not have any externally imposed regulatory capital requirements for managing capital. The Company has
defined its capital to mean its long-term debt and consolidated shareholders’ equity, as determined at each reporting date.
The Company’s objectives when managing its capital structure are to maintain financial flexibility and balance to enable the
Company to access capital markets to sustain its on-going operations and to support its growth strategies. The Company primarily
monitors capital on the basis of an internally derived financial measure referred to as its “debt to book capitalization ratio”, which
is the arithmetic ratio of current and long-term debt divided by the sum of the carrying value of shareholders’ equity plus current
and long-term debt. The Company’s internal targeted range for its debt to book capitalization ratio is 25% to 45%. This range may
be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. The Company may
be below the low end of the targeted range when cash flow from operating activities is greater than current investment activities.
At December 31, 2012, the ratio was within the target range at 26%.
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
$
$
2012
8,736 $
24,283 $
26%
2011
8,571
22,898
27%
2012
2011
2010
Weighted average common shares outstanding – basic (thousands of shares)
1,097,084
1,095,582
1,088,096
Effect of dilutive stock options (thousands of shares)
2,435
7,000
7,552
Weighted average common shares outstanding – diluted (thousands of shares)
1,099,519
1,102,582
1,095,648
Net earnings
Net earnings per common share – basic
– diluted
$
$
$
1,892 $
2,643 $
1,673
1.72 $
1.72 $
2.41 $
2.40 $
1.54
1.53
In 2012, the Company excluded 62,400,000 potentially anti-dilutive stock options from the calculation of diluted earnings per
common share.
CANADIAN NATURAL
2012 ANNUAL REPORT
81
16. INTEREST AND OTHER FINANCING COSTS
2012
2011
2010
Interest expense:
Long-term debt
Other financing costs
Less: amounts capitalized on qualifying assets
Total interest and other financing costs
Total interest income
$
464 $
450 $
(1)
463
98
365
(1)
(4)
446
59
387
(14)
Net interest and other financing costs
$
364 $
373 $
17. FINANCIAL INSTRUMENTS
The carrying amounts of the Company’s financial instruments by category were as follows:
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)
2012
Loans and
receivables at
amortized cost
Fair value
through profit
or loss
Derivatives
used for
hedging
Financial
liabilities at
amortized cost
$
1,197 $
– $
– $
– $
–
–
–
–
–
–
4
–
–
–
(261)
–
(465)
(2,273)
(79)
(8,736)
$
1,197 $
4 $
(261) $
(11,553) $
(10,613)
Loans and
receivables at
Fair value
through profit
amortized cost
or loss
2011
Derivatives
used for
hedging
Financial
liabilities at
amortized cost
$
2,077 $
– $
– $
– $
–
–
–
–
–
–
(38)
–
–
–
(236)
–
(526)
(2,347)
(75)
(8,571)
$
2,077 $
(38) $
(236) $
(11,519) $
Total
2,077
(526)
(2,347)
(349)
(8,571)
(9,716)
485
(6)
479
28
451
(3)
448
Total
1,197
(465)
(2,273)
(336)
(8,736)
(1) Includes the current portion of long-term debt.
82
CANADIAN NATURAL
2012 ANNUAL REPORT
The carrying amounts of the Company’s financial instruments approximated their fair value, except for fixed rate long-term debt as
noted below. The fair values of the Company’s other long-term liabilities and fixed rate long-term debt are outlined below:
Asset (liability) (1)
Other long-term liabilities
Fixed rate long-term debt (2) (3) (4)
Asset (liability) (1)
Other long-term liabilities
Fixed rate long-term debt (2) (3) (4)
2012
Carrying
amount
Fair value
Level 1
Level 2
(257) $
(7,765)
– $
(9,118)
(8,022) $
(9,118) $
(257)
–
(257)
Carrying
amount
2011
Fair value
Level 1
Level 2
(274) $
(7,775)
– $
(9,120)
(8,049) $
(9,120) $
(274)
–
(274)
$
$
$
$
(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 amount of US$350 million of 4.90% unsecured notes due December 2014 was adjusted by $19 million to reflect the fair value impact of
hedge accounting. At December 31, 2011, the carrying amounts of US$350 million of 5.45% unsecured notes due October 2012 and US$350 million of
4.90% unsecured notes due December 2014 were adjusted by $31 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.
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
Foreign currency forward contracts
Cash flow hedges
Cross currency swaps
Included within:
Current portion of other long-term liabilities
Other long-term liabilities
2012
2011
$
$
$
$
(16) $
20
(261)
(257) $
(4) $
(253)
(257) $
(13)
(25)
(236)
(274)
(43)
(231)
(274)
During 2012, the Company recognized a gain of $1 million (2011 – loss of $2 million; 2010 – loss of $1 million) related to
ineffectiveness arising from cash flow hedges.
CANADIAN NATURAL
2012 ANNUAL REPORT
83
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)
Balance – beginning of year
Net change in fair value of outstanding derivative financial instruments attributable to:
Risk management activities
Foreign exchange
Other comprehensive income
Balance – end of year
Less: current portion
2012
$
(274) $
42
(53)
28
(257)
(4)
$
(253) $
Net losses (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
Financial Risk Factors
a) Market risk
$
$
2012
162 $
(42)
120 $
2011
101 $
(128)
(27) $
2011
(485)
128
42
41
(274)
(43)
(231)
2010
(110)
(24)
(134)
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, 2012,
the Company had the following derivative financial instruments outstanding to manage its commodity price risk:
Sales contracts
Crude oil
Price collars (1)
Remaining term
Volume Weighted average price
Index
Jan 2013 – Jun 2013
50,000 bbl/d
US$80.00 – US$145.07
Jan 2013 – Dec 2013
50,000 bbl/d
US$80.00 – US$135.59
Jan 2013 – Dec 2013
50,000 bbl/d
US$80.00 – US$97.73
Jan 2013 – Dec 2013
50,000 bbl/d
US$80.00 – US$110.34
Brent
Brent
WTI
WTI
(1) Subsequent to December 31, 2012, the Company entered into an additional 50,000 bbl/d of US$80 – US$111.05 WTI collars for the period April to December
2013 and an additional 50,000 bbl/d of US$80 – US$132.18 Brent collars for the period July to December 2013.
During 2012, US$65 million of put option costs were settled.
The Company’s outstanding commodity derivative financial instruments are expected to be settled monthly based on the applicable
index pricing for the respective contract month.
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its floating
rate long-term debt. The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate
mix on long-term debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of the
notional principal amounts on which the payments are based. At December 31, 2012, the Company had no interest rate swap
contracts outstanding.
84
CANADIAN NATURAL
2012 ANNUAL REPORT
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long-
term debt and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted
in other currencies and in the carrying value of its foreign subsidiaries. The Company periodically enters into cross currency swap
contracts and foreign currency forward contracts to manage known currency exposure on US dollar denominated long-term debt
and working capital. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity
of notional principal amounts on which the payments are based. At December 31, 2012, the Company had the following cross
currency swap contracts outstanding:
Cross currency
Swaps
Remaining term
Amount
Exchange
rate (US$/C$)
Interest
rate (US$)
Interest
rate (C$)
Jan 2013 – Aug 2016
Jan 2013 – May 2017
Jan 2013 – Nov 2021
Jan 2013 – 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%
All cross currency swap derivative financial instruments designated as hedges at December 31, 2012 were classified as cash
flow hedges.
In addition to the cross currency swap contracts noted above, at December 31, 2012, the Company had US$2,821 million of
foreign currency forward contracts outstanding, with terms of approximately 30 days or less.
Financial instrument sensitivities
The following table summarizes the annualized sensitivities of the Company’s 2012 net earnings and other comprehensive income
to changes in the fair value of financial instruments outstanding as at December 31, 2012, resulting from changes in the specified
variable, with all other variables held constant. These sensitivities are prepared on a different basis than those sensitivities disclosed
in the Company’s other continuous disclosure documents, are limited to the impact of changes in a specified variable applied to
financial instruments only and do not represent the impact of a change in the variable on the operating results of the Company
taken as a whole. Further, these sensitivities are theoretical, as changes in one variable may contribute to changes in another
variable, which may magnify or counteract the sensitivities. In addition, changes in fair value generally cannot be extrapolated
because the relationship of a change in an assumption to the change in fair value may not be linear.
Increase (decrease)
Commodity price risk
Increase Brent US$1.00/bbl
Decrease Brent US$1.00/bbl
Increase WTI US$1.00/bbl
Decrease WTI 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
Impact
on other
comprehensive
income
Impact on
net earnings
$
$
$
$
$
$
$
$
(3) $
3 $
(13) $
13 $
(5) $
5 $
(8) $
8 $
–
–
–
–
17
(43)
–
–
CANADIAN NATURAL
2012 ANNUAL REPORT
85
b) Credit risk
Credit risk is the risk that a party to a financial instrument will cause a financial loss to the Company by failing to discharge an obligation.
Counterparty credit risk management
The Company’s accounts receivable are mainly with customers in the crude oil and natural gas industry and are subject to normal
industry credit risks. The Company manages these risks by reviewing its exposure to individual companies on a regular basis and
where appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default.
At December 31, 2012, 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, 2012, the Company had net risk management assets
of $18 million with specific counterparties related to derivative financial instruments (December 31, 2011 – $nil).
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.
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
2 to less
than 2 years
than 5 years
Thereafter
$
$
$
$
$
465 $
2,273 $
4 $
22 $
798 $
– $
– $
53 $
24 $
– $
– $
123 $
33 $
–
–
77
–
846 $
2,714 $
4,430
(1) Long-term debt represents principal repayments only and does not reflect fair value adjustments, interest, original issue discounts or transaction costs.
86
CANADIAN NATURAL
2012 ANNUAL REPORT
18. COMMITMENTS AND CONTINGENCIES
The Company has committed to certain payments as follows:
Product transportation and pipeline
Offshore equipment operating leases
and offshore drilling
Office leases
Other
$
$
$
$
2013
2014
2015
2016
2017
Thereafter
231 $
218 $
204 $
135 $
117 $
788
156 $
33 $
173 $
135 $
104 $
34 $
95 $
32 $
43 $
76 $
33 $
10 $
57 $
35 $
2 $
65
262
7
In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These contracts can be cancelled by the Company upon notice
without penalty, subject to the costs incurred up to and in respect of the cancellation.
The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition, the
Company is subject to certain contractor construction claims. The Company believes that any liabilities that might arise pertaining
to any such matters would not have a material effect on its consolidated financial position.
19. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Changes in non-cash working capital
Accounts receivable
Inventory
Prepaids and other
Accounts payable
Accrued liabilities
Current income tax liabilities
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
Net expenditures on exploration and evaluation assets
and property, plant and equipment
2012
2011
2010
$
869 $
(198) $
(9)
(8)
(64)
(138)
(65)
(72)
(17)
251
627
(83)
585 $
508 $
447 $
(36) $
(37)
175
(15)
559
585 $
508 $
2012
2011
309 $
312 $
5,804
(9)
5,895
(6)
$
$
$
$
(321)
(35)
18
36
232
340
270
136
(12)
146
270
2010
572
4,771
(8)
$
6,104 $
6,201 $
5,335
CANADIAN NATURAL
2012 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. The bitumen in the segment is recovered through mining operations.
North America
North Sea
Offshore Africa
Oil Sands Mining
and Upgrading
Midstream
and other
Inter–segment elimination
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2010
Segmented product sales
$ 11,607 $ 11,806 $ 9,713 $ 928 $ 1,224 $ 1,058 $ 773 $ 946 $ 884
$ 2,871 $ 1,521 $ 2,649 $
93 $
88 $
79 $
(77) $
(78) $
(61) $ 16,195 $ 15,507 $ 14,322
Exploration and Production
(1,268)
(1,538)
(1,267)
10,339
10,268
8,446
(2)
926
(3)
(2)
1,221
1,056
(199)
574
Less: royalties
Segmented revenue
Segmented expenses
Production
Transportation and blending
Depletion, depreciation
and amortization (1)
Asset retirement obligation accretion
Realized risk management activities
Horizon asset impairment provision
Insurance recovery –
property damage (note 10)
Insurance recovery –
business interruption (note 10)
Equity loss from
jointly controlled entity
2,165
2,735
1,933
2,301
1,675
1,761
3,413
2,840
2,484
85
162
70
101
52
(110)
–
–
–
–
–
–
–
–
–
–
–
–
402
10
296
27
–
–
–
–
–
412
13
249
33
–
–
–
–
–
387
8
297
36
–
–
–
–
–
(114)
832
186
1
(62)
822
167
1
163
1
165
242
935
7
–
–
–
–
–
7
–
–
–
–
–
7
–
–
–
–
–
Total segmented expenses
8,560
7,245
5,862
735
707
728
336
436
1,110
2,044
1,145
1,693
33
30
(69)
(63)
(58)
11,651
9,503
9,365
$ 1,779 $ 3,023 $ 2,584 $ 191 $ 514 $ 328 $ 238 $ 396 $
(288)
$ 690 $ 316 $ 866 $
48 $
55 $
49 $
(8) $
(15) $
(3)
2,938
4,289
3,536
Segmented earnings (loss)
before the following
Non–segmented expenses
Administration
Share-based compensation
Interest and other financing costs
Unrealized risk management activities
Foreign exchange (gain) loss
Total non–segmented expenses
Earnings before taxes
Current income tax expense
Deferred income tax (recovery) expense
Net earnings
(1) 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.
88
CANADIAN NATURAL
2012 ANNUAL REPORT
(137)
(60)
(90)
2,734
1,461
2,559
1,504
1,127
1,208
61
62
61
447
32
–
–
–
–
–
266
20
–
396
(393)
(333)
–
396
28
–
–
–
–
–
–
93
29
–
7
–
–
–
–
–
9
45
–
88
26
–
7
–
–
–
–
–
–
–
79
22
–
8
–
–
–
–
–
–
–
(77)
(14)
(55)
–
–
–
–
–
–
–
–
(78)
(13)
(50)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
(1,606)
(1,715)
(1,421)
(61)
14,589
13,792
12,901
(10)
(48)
4,249
2,752
3,671
2,327
3,449
1,783
4,328
3,604
4,120
Total
2011
130
101
396
(393)
(333)
–
235
(102)
373
(128)
1
379
860
407
151
162
–
–
–
9
270
(214)
364
(42)
(49)
329
747
(30)
123
(110)
–
–
–
–
211
203
448
(24)
(163)
675
789
399
2,609
3,910
2,861
$ 1,892 $ 2,643 $ 1,673
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. The bitumen in the segment is recovered through mining operations.
Midstream activities include the Company’s pipeline operations, an electricity co-generation system and Redwater. Production
activities that are not included in the above segments are reported in the segmented information as other. Inter-segment eliminations
include internal transportation and electricity charges.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment
revenue and segment results include transactions between business segments. These transactions and any unrealized profits and
losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales
to external customers are based on the location of the seller.
Operating segments are reported in a manner consistent with the internal reporting provided to senior management.
North America
North Sea
Offshore Africa
Oil Sands Mining
and Upgrading
Midstream
Inter–segment elimination
and other
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
2011
2010
2012
Total
2011
2010
Segmented product sales
$ 11,607 $ 11,806 $ 9,713 $ 928 $ 1,224 $ 1,058 $ 773 $ 946 $ 884
$ 2,871 $ 1,521 $ 2,649 $
93 $
88 $
79 $
(77) $
(78) $
(61) $ 16,195 $ 15,507 $ 14,322
Exploration and Production
(1,268)
(1,538)
(1,267)
10,339
10,268
8,446
(2)
926
(3)
(2)
1,221
1,056
(199)
574
2,165
2,735
1,933
2,301
1,675
1,761
3,413
2,840
2,484
85
162
70
101
52
(110)
–
–
–
–
–
–
–
–
–
–
–
–
402
10
296
27
–
–
–
–
–
412
13
249
33
–
–
–
–
–
387
8
297
36
–
–
–
–
–
163
1
7
–
–
–
–
–
(114)
832
186
1
(62)
822
167
1
7
–
–
–
–
–
7
–
–
–
–
–
165
242
935
(137)
(60)
(90)
2,734
1,461
2,559
1,504
1,127
1,208
61
62
61
447
32
–
–
–
–
–
266
20
–
396
(393)
(333)
–
396
28
–
–
–
–
–
Total segmented expenses
8,560
7,245
5,862
735
707
728
336
436
1,110
2,044
1,145
1,693
–
93
29
–
7
–
–
–
–
–
9
45
–
88
26
–
7
–
–
–
–
–
–
–
79
22
–
8
–
–
–
–
–
–
–
(77)
(14)
(55)
–
–
–
–
–
–
–
–
(78)
(13)
(50)
–
–
–
–
–
–
–
–
(1,606)
(1,715)
(1,421)
(61)
14,589
13,792
12,901
(10)
(48)
4,249
2,752
3,671
2,327
3,449
1,783
–
–
–
–
–
–
–
4,328
3,604
4,120
151
162
–
–
–
9
130
101
396
(393)
(333)
–
123
(110)
–
–
–
–
33
30
(69)
(63)
(58)
11,651
9,503
9,365
$ 1,779 $ 3,023 $ 2,584 $ 191 $ 514 $ 328 $ 238 $ 396 $
(288)
$ 690 $ 316 $ 866 $
48 $
55 $
49 $
(8) $
(15) $
(3)
2,938
4,289
3,536
270
(214)
364
(42)
(49)
329
235
(102)
373
(128)
1
379
211
203
448
(24)
(163)
675
2,609
3,910
2,861
747
(30)
860
407
789
399
$ 1,892 $ 2,643 $ 1,673
CANADIAN NATURAL
2012 ANNUAL REPORT
89
Less: royalties
Segmented revenue
Segmented expenses
Production
Transportation and blending
Depletion, depreciation
and amortization (1)
Asset retirement obligation accretion
Realized risk management activities
Horizon asset impairment provision
Insurance recovery –
property damage (note 10)
Insurance recovery –
business interruption (note 10)
Equity loss from
jointly controlled entity
Segmented earnings (loss)
before the following
Non–segmented expenses
Administration
Share-based compensation
Interest and other financing costs
Unrealized risk management activities
Foreign exchange (gain) loss
Total non–segmented expenses
Earnings before taxes
Current income tax expense
Deferred income tax (recovery) expense
Net earnings
and amortization expense.
(1) During 2010, the Company recognized a $637 million impairment relating to the Gabon CGU, in Offshore Africa, which was included in depletion, depreciation
Capital Expenditures (1)
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
2012
Non cash
and
fair value
changes (2)
Net
expenditures
Capitalized
costs
Net
expenditures
2011
Non cash
and
fair value
changes (2)
Capitalized
costs
$
295
$
(173) $
122 $
309
$
(233) $
–
14
–
–
–
14
1
2
(6)
–
$
309
$
(173) $
136 $
312
$
(239) $
76
(5)
2
73
$
3,831
$
373 $
4,204 $
4,427
$
832 $
5,259
254
50
4,135
1,610
14
36
263
17
653
142
–
–
517
67
4,788
1,752
14
36
226
31
4,684
1,182
5
18
15
16
863
(140)
2
–
241
47
5,547
1,042
7
18
$
5,795
$
795 $
6,590 $
5,889
$
725 $
6,614
(1) This table provides a reconciliation of capitalized costs including derecognitions and does not include the impact of foreign exchange adjustments.
(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 and share-based compensation.
(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
2012
2011
29,012 $
1,993
924
36
16,291
636
88
48,980 $
28,233
1,809
1,070
23
15,433
642
68
47,278
$
$
was included in non cash and fair value changes.
Segmented Assets
Exploration and Production
North America
North Sea
Offshore Africa
Other
Oil Sands Mining and Upgrading
Midstream
Head office
90
CANADIAN NATURAL
2012 ANNUAL REPORT
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
$
$
2012
2011
2 $
2 $
2010
2
2012
2011
2010
2 $
2 $
12
3
9
–
18
2
8
–
$
26 $
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 for the respective years.
CANADIAN NATURAL
2012 ANNUAL REPORT
91
SUPPLEMENTARY OIL & GAS INFORMATION (UNAUDITED)
This supplementary crude oil and natural gas information is provided in accordance with the United States Financial Accounting
Standards Board (“FASB”) Topic 932 – “Extractive Activities – Oil and Gas” and where applicable, financial information is prepared
in accordance with International Financial Reporting Standards (“IFRS”). 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, 2012, 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 prices 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, 2012, 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 2012 reserves for SEC requirements.
Crude Oil and NGLs
Natural Gas
WTI Cushing
Oklahoma
(US$/bbl)
94.71
WCS
(C$/bbl)
73.63
Edmonton
Par
(C$/bbl)
North Sea
Brent
(US$/bbl)
Edmonton
C5+
(C$/bbl)
Henry Hub
Louisiana
(US$/MMbtu)
AECO
(C$/MMbtu)
BC Westcoast
Station 2
(C$/MMbtu)
87.07
111.13
101.31
2.77
2.35
2.27
A foreign exchange rate of US$1.00/C$1.00 was used in the 2012 evaluation, determined on the same basis as the 12-month
average price.
NET PROVED CRUDE OIL AND NATURAL GAS RESERVES
The Company retains Independent Qualified Reserves Evaluators to evaluate the Company’s proved crude oil, bitumen, synthetic
crude oil (“SCO”), natural gas liquids (“NGLs”) and natural gas reserves.
For the years ended December 31, 2012, 2011, 2010, and 2009, the reports by GLJ Petroleum Consultants Ltd. covered 100%
of the Company’s SCO reserves. With the inclusion of non-traditional resources within the definition of “oil and gas producing
activities” in the SEC’s modernization of oil and gas reporting rules (“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, 2012, 2011, 2010, and 2009, the reports by Sproule Associates Limited and Sproule
International Limited covered 100% of the Company’s bitumen, crude oil and NGLs, 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.
92
CANADIAN NATURAL
2012 ANNUAL REPORT
The following table summarizes the Company’s proved and proved developed crude oil and natural gas reserves, net of royalties,
as at December 31, 2012, 2011, 2010, and 2009:
Crude Oil and NGLs (MMbbl)
Crude Oil (1) Bitumen (2)
Synthetic
Crude Oil
and NGLs
North
America
Total
North
Sea
Offshore
Africa
Total
Net Proved Reserves
Reserves, December 31, 2009
1,650
695
319
2,664
240
123
3,027
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
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, 2012
Net proved developed reserves
December 31, 2009
December 31, 2010
December 31, 2011
December 31, 2012
–
–
–
–
(32)
(41)
86
1,663
–
–
–
–
(14)
18
169
1,836
–
–
–
–
(30)
34
134
1,974
1,589
1,546
1,588
1,612
55
22
92
–
(54)
(25)
93
878
78
10
–
–
(60)
(32)
(5)
869
90
25
–
–
(70)
6
79
999
268
262
269
348
9
6
15
–
(26)
–
5
328
28
8
6
–
(28)
1
23
366
5
9
2
–
(31)
(20)
39
370
204
240
269
295
64
28
107
–
(112)
(66)
184
2,869
106
18
6
–
(102)
(13)
187
3,071
95
34
2
–
(131)
20
252
–
–
–
–
(12)
28
1
257
–
–
–
–
(11)
26
(28)
244
–
–
–
–
(7)
4
(6)
3,343
235
2,061
2,048
2,126
2,255
94
94
78
66
–
–
–
–
(10)
–
(11)
102
–
2
–
–
(8)
–
(8)
88
–
1
–
–
(5)
–
1
85
106
83
61
55
64
28
107
–
(134)
(38)
174
3,228
106
20
6
–
(121)
13
151
3,403
95
35
2
–
(143)
24
247
3,663
2,261
2,225
2,265
2,376
(1) Pursuant to the SEC’s Final Rule in effect January 1, 2010, 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
crude oil reserves have been classified as bitumen.
CANADIAN NATURAL
2012 ANNUAL REPORT
93
North
America
North
Sea
Offshore
Africa
3,027
249
19
364
–
(426)
105
83
3,421
154
48
375
(1)
(433)
(104)
39
3,499
50
11
34
(1)
(429)
(596)
79
2,647
2,333
2,557
2,637
2,060
67
–
–
–
–
(4)
6
9
78
–
–
–
–
(2)
3
18
97
–
–
–
–
(1)
1
(14)
83
45
49
60
58
85
–
–
–
–
(5)
–
(4)
76
–
–
–
–
(6)
–
(16)
54
–
–
–
–
(6)
–
–
48
81
72
47
39
Total
3,179
249
19
364
–
(435)
111
88
3,575
154
48
375
(1)
(441)
(101)
41
3,650
50
11
34
(1)
(436)
(595)
65
2,778
2,459
2,678
2,744
2,157
Natural Gas (Bcf)
Net Proved Reserves
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
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, 2012
Net proved developed reserves
December 31, 2009
December 31, 2010
December 31, 2011
December 31, 2012
94
CANADIAN NATURAL
2012 ANNUAL REPORT
CAPITALIZED COSTS RELATED TO CRUDE OIL AND NATURAL GAS ACTIVITIES
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
2012
North
America
North
Sea
Offshore
Africa
$
67,287 $
4,574 $
3,045 $
2,564
69,851
(26,193)
–
4,574
(2,709)
47
3,092
(2,273)
Net capitalized costs
$
43,658 $
1,865 $
819 $
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
2011
North
America
North
Sea
Offshore
Africa
$
61,331 $
4,147 $
3,044 $
2,442
63,773
(22,497)
–
4,147
(2,512)
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
2010 (1)
North
America
North
Sea
Offshore
Africa
$
55,030 $
3,813 $
2,928 $
2,366
57,396
(19,502)
5
3,818
(2,205)
31
2,959
(1,904)
Net capitalized costs
$
37,894 $
1,613 $
1,055 $
(1) Comparative amounts for 2010 have been restated to reflect the adoption of IFRS.
Total
74,906
2,611
77,517
(31,175)
46,342
Total
68,522
2,475
70,997
(27,161)
43,836
Total
61,771
2,402
64,173
(23,611)
40,562
CANADIAN NATURAL
2012 ANNUAL REPORT
95
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
(millions of Canadian dollars)
Property acquisitions
Proved
Unproved
Exploration
Development
Costs incurred
2012
North
America
North
Sea
Offshore
Africa
$
144 $
– $
– $
44
251
5,773
$
6,212 $
3
11
75
89 $
–
–
556
556 $
2011
North
America
North
Sea
Offshore
Africa
$
1,012 $
– $
– $
59
250
5,559
$
6,880 $
–
2
76
78 $
–
1
235
236 $
2010 (1)
North
America
North
Sea
Offshore
Africa
$
1,482 $
– $
– $
522
41
3,332
$
5,377 $
–
6
190
196 $
–
3
254
257 $
Total
144
47
262
6,404
6,857
Total
1,012
59
253
5,870
7,194
Total
1,482
522
50
3,776
5,830
(1) Comparative amounts for 2010 have been restated to reflect the adoption of IFRS.
96
CANADIAN NATURAL
2012 ANNUAL REPORT
royalties and blending costs
$
9,600 $
1,206 $
828 $
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, 2012,
2011 and 2010 are summarized in the following tables:
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of
2012
North
America
North
Sea
Offshore
Africa
royalties and blending costs
$
10,609 $
837 $
574 $
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of
Production
Transportation
Depletion, depreciation and amortization (1)
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
$
1,861 $
33 $
183 $
2,077
(3,669)
(479)
(3,860)
(117)
–
(623)
(402)
(10)
(296)
(27)
(14)
(55)
(163)
(1)
(165)
(7)
–
(55)
2011
North
America
North
Sea
Offshore
Africa
(3,060)
(374)
(3,488)
(90)
–
(688)
(412)
(13)
(248)
(33)
(130)
(218)
(186)
(1)
(242)
(7)
–
(89)
2010 (2)
North
America
North
Sea
Offshore
Africa
(2,883)
(365)
(2,869)
(80)
–
(980)
(387)
(8)
(295)
(36)
(59)
(137)
(167)
(1)
(935)
(7)
–
146
Total
12,020
(4,234)
(490)
(4,321)
(151)
(14)
(733)
Total
11,634
(3,658)
(388)
(3,978)
(130)
(130)
(995)
Total
11,567
(3,437)
(374)
(4,099)
(123)
(59)
(971)
$
1,900 $
152 $
303 $
2,355
$
2,510 $
137 $
(143) $
2,504
(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.
CANADIAN NATURAL
2012 ANNUAL REPORT
97
royalties and blending costs
$
9,687 $
1,059 $
821 $
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
2012
North
America
North
Sea
Offshore
Africa
Total
$
273,167 $
26,922 $
7,985 $
308,074
(114,825)
(9,369)
(2,428)
(126,622)
Future development costs and asset retirement
obligations
Future income taxes
Future net cash flows
10% annual discount for timing of future cash flows
(49,226)
(16,688)
92,428
(61,878)
(7,032)
(7,662)
2,859
(1,330)
(1,640)
(949)
2,968
(1,313)
Standardized measure of future net cash flows
$
30,550 $
1,529 $
1,655 $
(57,898)
(25,299)
98,255
(64,521)
33,734
(millions of Canadian dollars)
Future cash inflows
Future production costs
2011
North
America
North
Sea
Offshore
Africa
Total
$
280,809 $
26,887 $
8,257 $
315,953
(109,586)
(8,908)
(2,058)
(120,552)
Future development costs and asset retirement
obligations
Future income taxes
Future net cash flows
10% annual discount for timing of future cash flows
(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 $
(45,976)
(32,265)
117,160
(78,437)
38,723
98
CANADIAN NATURAL
2012 ANNUAL REPORT
(millions of Canadian dollars)
Future cash inflows
Future production costs
2010
North
America
North
Sea
Offshore
Africa
Total
$
221,337 $
21,117 $
8,268 $
250,722
(96,899)
(8,596)
(1,884)
(107,379)
Future development costs and asset retirement
obligations
Future income taxes
Future net cash flows
10% annual discount for timing of future cash flows
(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 $
(41,560)
(24,581)
77,202
(50,315)
26,887
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)
2012
2011
Sales of crude oil and natural gas produced, net of production costs
$
(7,895) $
(7,727) $
Net changes in sales prices and production costs
Extensions, discoveries and improved recovery
Changes in estimated future development costs
Purchases of proved reserves in place
Sales of proved reserves in place
Revisions of previous reserve estimates
Accretion of discount
Changes in production timing and other
Net change in income taxes
Net change
Balance – beginning of year
Balance – end of year
(7,994)
1,834
(3,492)
83
(1)
4,266
5,110
946
2,154
(4,989)
38,723
15,802
1,328
(2,022)
803
–
4,154
3,648
(1,141)
(3,009)
11,836
26,887
$
33,734 $
38,723 $
2010
(7,641)
14,748
1,636
(5,208)
1,894
–
2,567
2,757
(895)
(4,016)
5,842
21,045
26,887
CANADIAN NATURAL
2012 ANNUAL REPORT
99
TEN YEAR REVIEW
Years ended December 31
2012
2011
2010 (6)
2009 (7)
2008 (7)
2007 (7)
2006 (7)
2005 (7)
2004 (7)
2003 (7)
6,308
6,414
6,547
(894)
2,475
41,631
47,278
8,571
22,898
(1,264)
2,611
44,028
48,980
8,736
24,283
1,892
$ 1.72 $
$ 1.72 $
6,013
$ 5.48 $
$ 5.47 $
FINANCIAL INFORMATION (1) (Cdn $ millions, except per share amounts)
Net earnings
2,643
Per share – basic
Per share – diluted
Cash flow from operations (2)
Per share – basic
Per share – diluted
Capital expenditures, net of dispositions
(including business combinations)
Balance sheet information
Working capital surplus (deficiency)
Exploration and evaluation assets
Property, plant and equipment, net
Total assets
Long-term debt
Shareholders’ equity
SHARE INFORMATION (1)
Common shares outstanding (thousands)
Weighted average shares outstanding –
basic (thousands)
Weighted average shares outstanding –
diluted (thousands)
Dividends declared per common share
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)
Daily production before royalties per ten
thousand common shares (BOE/d) (1)
Total proved plus probable reserves per
common share (BOE) (1)(4)
Net asset value per common share (1)(5)
729,700
844,647
800,044
937,481
26%
6.0
27%
12%
5.5
8%
6.9
2.41 $
2.40 $
5.98 $
5.94 $
1,673
1,580
4,985
2,608
2,524
1,050
1,405
1.54 $
1.53 $
1.46 $
1.46 $
4.61 $
4.61 $
2.42 $
2.42 $
2.35 $
2.35 $
0.98 $
0.98 $
1.31 $
1.30 $
6,333
6,090
6,969
6,198
4,932
5,021
3,769
5.82 $
5.78 $
5.62 $
5.62 $
6.45 $
6.45 $
5.75 $
5.75 $
4.59 $
4.59 $
4.68 $
4.67 $
3.52 $
3.49 $
1,403
1.31
1.27
3,160
2.94
2.88
5,514
2,997
7,451
6,425
12,025
4,932
4,633
2,506
(1,200)
2,402
38,429
42,954
8,485
20,368
(514)
–
39,115
41,024
9,658
19,426
(28)
–
38,966
42,650
12,596
18,374
(1,382)
–
33,902
36,114
10,940
13,321
(832)
–
30,767
33,160
11,043
10,690
(1,774)
–
19,694
21,852
3,321
8,237
(652)
–
17,064
18,372
3,538
7,324
(505)
–
13,714
14,643
2,748
6,006
1,092,072 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
1,097,084 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
1,099,519 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
0.08
$ 0.42 $
0.30 $
0.21 $
0.20 $
0.17 $
0.15 $
0.12 $
0.10 $
0.36 $
661,832 1,040,320 1,359,476
858,068 1,017,870 1,275,984 1,212,048 1,181,404
$ 41.12 $ 50.50 $ 45.00 $ 39.50 $ 55.65 $ 40.01 $ 36.96 $ 31.00 $ 13.79 $
$ 25.58 $ 27.25 $ 31.97 $ 17.93 $ 17.10 $ 26.23 $ 22.75 $ 12.14 $
7.98 $
$ 28.64 $ 38.15 $ 44.35 $ 38.00 $ 24.38 $ 36.29 $ 31.08 $ 28.82 $ 12.82 $
8.41
5.65
8.17
759,327 1,514,614 1,934,456
972,532
803,818
503,108
250,936
93,832
$ 41.38 $ 52.04 $ 44.77 $ 38.26 $ 54.66 $ 43.59 $ 32.19 $ 27.03 $ 11.19 $
5.97 $
$ 25.01 $ 25.69 $ 30.00 $ 13.85 $ 13.22 $ 22.28 $ 20.15 $
$ 28.87 $ 37.37 $ 44.42 $ 35.98 $ 19.99 $ 36.57 $ 26.62 $ 24.81 $ 10.70 $
9.87 $
29%
33%
8%
8%
41%
33%
45%
22%
51%
27%
29%
14%
34%
21%
5.8
5.3
5.2
5.7
5.4
5.2
4.8
4.3
6.43
3.66
6.31
33%
26%
7.2
2.0
$ 62.38 $ 70.37 $ 64.58 $ 64.92 $ 39.89 $ 34.47 $ 28.21 $ 30.22 $ 16.57 $ 11.68
6.3
5.8
3.1
3.2
3.2
2.4
2.2
(1) Restated to reflect two-for-one share splits in May 2010, May 2005 and May 2004.
(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 prices 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.
100
CANADIAN NATURAL
2012 ANNUAL REPORT
Years ended December 31
2012
2011
2010 (6)
2009
2008
2007
2006
2005
2004
2003
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
Company net proved plus probable reserves (after royalties)
North America
North Sea
Offshore Africa
4,907
102
76
5,085
3,268
227
85
3,580
–
5,119
332
127
5,578
–
3,540
82
48
3,670
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
Total proved reserves
(after royalties) (MMBOE)
Total proved plus probable reserves
(after royalties) (MMBOE)
Daily production (before royalties)
Crude oil and NGLs (Mbbl/d)
North America – Exploration and Production
4,191
3,977
3,748
3,557
1,960
1,969
1,949
1,592
1,514
1,320
6,426
6,147
5,666
5,440
2,996
2,937
2,961
2,279
2,115
1,823
North America – Oil Sands Mining and Upgrading
326
296
271
234
244
247
235
222
206
175
North Sea
Offshore Africa
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Total production (before royalties) (MBOE/d)
Product pricing
Average crude oil and NGLs price ($/bbl)
Average natural gas price ($/Mcf)
Average SCO price ($/bbl)
86
20
19
451
1,198
2
20
1,220
655
70.24
2.44
88.91
40
30
23
389
1,231
7
19
1,257
599
77.46
3.73
99.74
91
33
30
425
1,217
10
16
1,243
632
65.81
4.08
77.89
50
38
33
355
1,287
10
18
1,315
575
57.68
4.53
70.83
–
45
27
316
1,472
10
13
1,495
565
82.41
8.39
–
–
56
28
331
1,643
13
12
1,668
609
55.45
6.85
–
–
60
37
332
1,468
15
9
1,492
581
53.65
6.72
–
–
68
23
313
1,416
19
4
1,439
553
46.86
8.57
–
–
65
12
283
1,330
50
8
1,388
514
37.99
6.50
–
–
57
10
242
1,245
46
8
1,299
459
32.66
6.21
–
(8) 2012, 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 seperately 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.
CANADIAN NATURAL
2012 ANNUAL REPORT
101
BOARD OF DIRECTORS
*Catherine M. Best FCA, ICD.D (1)(2)
Corporate Director
Calgary, Alberta
N. Murray Edwards (5)
President, Edco Financial Holdings Ltd.
Calgary/Banff, Alberta
*Timothy W. Faithfull (1)(3)
Corporate Director
Oxford, England
*Honourable Gary A. Filmon, P.C., OC., O.M. (1)(4)
Corporate Director
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 (3)
President,
Canadian Natural Resources Limited
Calgary, Alberta
Keith A. J. MacPhail (3)(5)
Executive Chairman,
Bonavista Energy Corporation
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 and 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 and Chief Executive Officer, Teine Energy Ltd.
Calgary, Alberta
102
CANADIAN NATURAL
2012 ANNUAL REPORT
OFFICERS
N. Murray Edwards
Chairman of the Board
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 and Development Operations
Scott G. Stauth
Senior Vice-President, North American Operations
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
Bruce E. McGrath
Corporate Secretary
(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 2012 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
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
Email: ir@cnrl.com
International Office
CNR International (U.K.) Limited
St. Magnus House, Guild Street
Aberdeen AB11 6NJ Scotland
Registrar and Transfer Agent
Computershare Trust Company of Canada
Calgary, Alberta
Toronto, Ontario
Computershare Investor Services LLC
New York, New York
Auditors
PricewaterhouseCoopers LLP
Calgary, Alberta
Independent Qualified
Reserves Evaluators
GLJ Petroleum Consultants Ltd.
Calgary, Alberta
Sproule Associates Limited
Calgary, Alberta
Sproule International Limited
Calgary, Alberta
Stock Listing – CNQ
Toronto Stock Exchange
The New York Stock Exchange
COMPANY DEFINITION
Throughout the annual report, Canadian Natural Resources Limited
is referred to as “us”, “we”, “our”, “Canadian Natural”, or the
“Company”.
CURRENCY
All amounts are reported in Canadian currency unless otherwise stated.
ABBREVIATIONS
Abbreviations can be found on page 20.
METRIC CONVERSION CHART
To convert
barrels
thousand cubic feet
feet
miles
acres
tonnes
To
cubic metres
cubic metres
metres
kilometres
hectares
tons
COMMON SHARE DIVIDEND
Multiply by
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
2012
2011
2010
$
0.42
$
0.36
$
0.30
NOTICE OF ANNUAL MEETING
Canadian Natural’s Annual and Special Meeting of the Shareholders will be
held on Thursday, May 2, 2013 at 3:00 p.m. Mountain Daylight Time in the
Ballroom of the Metropolitan Centre, Calgary, Alberta.
Printed in Canada by McAra Printing
Design and produced by nonfiction studios inc.
CANADIAN NATURAL
2012 ANNUAL REPORT
103
CANADIAN NATURAL
RESOURCES LIMITED
2500, 855 – 2 Street SW
Calgary, AB T2P 4J8
WWW.CNRL.COM
T
F
E
403.517.6700
403.517.7350
ir@cnrl.com