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