Premium Value. Defined Growth. Independent.
2016 ANNUAL REPORT
2016 Performance Highlights
Canadian Natural demonstrated strong operational performance throughout 2016 despite significantly
reducing its 2016 drilling programs in both its crude oil and natural gas assets as a result of sharply
declining commodity prices. In 2016, the Company continued to progress its transition to a longer-life, low
decline asset base, while executing on its balanced disciplined business approach.
FINANCIAL ($ millions, except per common share amounts)
Product sales
Net earnings (loss)
Per common share – basic
– diluted
Adjusted net earnings (loss) from operations (1)
Per common share – basic
– diluted
Funds 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)
2016
2015
2014
$
$
$
$
$
$
$
$
$
$
$
$
$
11,098 $
13,167 $
21,301
(204) $
(637) $
3,929
(0.19) $
(0.58) $
(0.19) $
(0.58) $
3.60
3.58
(669) $
(0.61) $
(0.61) $
263 $
3,811
0.24 $
0.24 $
3.49
3.47
4,293 $
5,785 $
9,587
3.90 $
3.89 $
5.29 $
5.28 $
8.78
8.74
3,794 $
3,853 $
11,744
16,805 $
16,794 $
14,002
26,267 $
27,381 $
28,891
351
123
24
26
524
400
123
22
19
564
391
111
17
12
531
1,622
1,663
1,527
38
31
1,691
806
36
27
1,726
852
7
21
1,555
790
(1) Adjusted net earnings (loss) 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) Funds 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.
TABLE OF CONTENTS
Letter to our Shareholders
IFC 2016 Performance Highlights
02
06 Our World-Class Team
10 Year-End Reserves
18 Management’s Discussion and Analysis
54 Management’s Report
55
Management’s Assessment of Internal Control over Financial Reporting
56
Independent Auditor’s Report
58 Consolidated Financial Statements
62 Notes to the Consolidated Financial Statements
92 Supplementary Oil and Gas Information
100 Ten-Year Review
102 Corporate Information
Canadian Natural 2016 Annual Report
Premium Value. Defined Growth. Independent.
193%
14.6 years
PDP PRODUCTION
REPLACEMENT
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.
2016
2015
2014
188
1
1
190
134
-
6
140
1,112
5
-
1,117
17,579
18,961
20,583
78
2,194
19,851
93
2,439
21,493
93
2,467
23,143
7,281
253
133
7,667
7,197
284
142
7,623
8,911
8,338
85
80
9,076
9,179
96
74
8,508
9,041
7,078
308
149
7,535
7,926
114
98
8,138
8,891
1
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Letter to our Shareholders
The pricing environment in 2016 began on an uneasy note as WTI crude oil benchmark pricing reached
lows not seen since 2004. Our flexible capital program and business strategy enabled us to respond
quickly to these unfavorable market changes during the first half of the year. As a result, we retained
our investment grade ratings without issuing equity or decreasing our dividend, and stayed on course to
maintain a resilient financial position.
industry
As the year progressed, the Company was driven by the maxim
the “Year of Excellence”, as we leveraged the strength of our
unique corporate culture and our diversified, balanced asset
base. Throughout 2016, we continued to focus on furthering
our
incorporated
leading cost reductions and
process improvements that could be sustained through
any commodity price cycle. In addition to savings achieved
in 2015, the Company captured cost reductions totaling
$562 million in 2016, a 14% reduction over 2015 levels on a
per unit basis. For a company with Company Gross proved
plus probable reserves of approximately 9.18 billion BOE and
7,270 employees, this has been a great accomplishment.
During the last four months of the year, we augmented
our long-life, low decline asset base as the Horizon Oil
Sands (“Horizon”) project ramped up to over 182,000 bbl/d
of synthetic crude oil (“SCO”) after the on time and on
budget completion of Phase 2B. Our thermal in situ oil sands
(“thermal”) assets and Horizon now constitute 67% of
the Company’s total reserves. As a result of the increased
production from Horizon and our positive production results
from our other low decline assets, our corporate decline rate
in 2016 was 13.6%. In 2018, we target an 11.7% decline rate
once the final phase of Horizon is complete with the addition
of 80,000 bbl/d of SCO in Q4/17.
Our balanced business approach drives how we do business
and it is ultimately geared toward maximizing shareholder value.
In addition to the Company’s 16th consecutive annual dividend
increase, we distributed approximately 21.8 million PrairieSky
common shares during the second quarter to our shareholders.
In December of 2016, we monetized our non-core ownership
interest in the Cold Lake Pipeline with cash proceeds of
$350 million and approximately 6.4 million shares of Inter
Pipeline, totaling approximately $539 million in value. In 2016,
we captured opportunities, continued to transform the Company
to a longer life lower decline production base and continued
to drive our business to maximize value for shareholders.
NATURAL GAS
As the largest producer of natural gas in Canada, our vast
network of owned infrastructure and undeveloped land,
provides Canadian Natural a competitive advantage. Through
capturing third party processing opportunities and optimizing
the Company’s own operations, we can continue to maximize
value for our shareholders.
Despite third party pipeline facility restrictions throughout 2016,
Canadian Natural continued to focus on being the most effective
and efficient operator. As a result, the Company was able to
achieve unit operating cost savings in our North American natural
gas of 12% over 2015 levels. Canadian Natural is the largest
Montney acreage holder in Canada and holds significant land
in the liquids rich plays of the Deep Basin. Operating costs in
these areas are industry leading and driving significant returns as
we continue to leverage our owned and operated infrastructure.
In 2017, we will continue to look for similar opportunities as we
target to drill 21 net wells and manage our natural gas production
across Western Canada within a backdrop of transportation
challenges for natural gas in Western Canada.
LIGHT CRUDE OIL AND NGLS
NORTH AMERICA
2016 was a successful year for light crude oil and NGLs as
results of the Company’s focus on lowering cost structures
across the basin with effective and efficient operations and
production enhancements continues to create significant
value. Strong efficiencies were gained year-over-year as unit
operating costs were reduced by 19% from 2015 levels.
Production volumes in light crude oil and NGLs reflect
Canadian Natural's continued focus on optimization of existing
operations, as they have been essentially flat since 2014,
strong results given minimal drilling as a result of strategic
capital allocation decisions. 2017 will see continued focus on
further improvement on our effective and efficient operations,
and optimization of our assets, with targeted drilling of 43 net
wells, resulting in targeted production growth.
INTERNATIONAL
Canadian Natural’s International assets remain an important
component of our balanced strategy. These assets provide
exposure to International pricing and provide offshore expertise
to the Company from our strategically located office in Aberdeen.
The Company’s Côte d’Ivoire assets in Offshore Africa
generate amongst the highest returns in our portfolio
and are considered one of our key light crude oil low capital
exposure opportunities. Canadian Natural’s cost reduction
focus continued in Offshore Africa where unit operating
cost reductions of 46% were achieved compared to 2015
levels. In early 2016, infill drilling programs at the Espoir
and Baobab fields were completed with results exceeding
expectations, resulting in an average 7,000 bbl/d production
increase or 37% over 2015 levels.
2
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 806 MBOE/d
$4.3 billion
PRODUCTION
FUNDS FLOW
FROM OPERATIONS
In the North Sea, annual light crude oil production increased
by 6% year-over-year, due to the Company’s focus on
production enhancements, increased reliability and water
flood optimization. As a result, Canadian Natural reduced
annual unit operating costs by 33% from 2015 levels.
In 2017, reducing overall cost structures will continue to be
our focus. Our International assets continue to create value
adding opportunities and enhance capital flexibility, balance
and diversity of plays within the Company’s current portfolio.
We target to drill 3 net producing wells in the North Sea in
2017, as changes in the UK tax regime introduced in 2016 have
resulted in more favorable economics in the region.
HEAVY CRUDE OIL
PRIMARY PRODUCTION
Canadian Natural is the largest primary heavy crude oil
producer in Canada. Our experienced teams deliver repeatable
and proven performance with this flexible and low cost asset.
As a result our continued focus on operations optimization in
2016, operating costs were reduced 10% from 2015 levels,
delivering solid netbacks and cash flow. In 2016, we leveraged
our experience and our highly flexible operations, as we
effectively managed capital spending in the area, holding
key land positions and developing those locations with the
highest returns.
2017 will mark a return to investment into this key asset in
our portfolio, as the Company plans to drill 427 net wells,
a significant increase from 2015 levels. In addition to our
budgeted drilling program, drilling capital expenditures could
be increased if commodity prices increase. Also, if commodity
prices deteriorate, we have the ability to rollback 2017 primary
heavy crude oil capital expenditures, demonstrating the
strength of these truly flexible, strong netback and low capital
exposure asset.
PELICAN LAKE
Pelican Lake, our leading edge polymer flood and a component
of our long-life, low decline asset base, continues to
meet expectations. The polymer flood continues to drive
exceptional
reservoir performance holding production
volumes to a minimal decline even though there has been only
2 wells drilled since 2014. Production volumes were down
year-over-year by approximately 6% due to natural declines
and wellhead cleanouts being completed to improve polymer
flood conformance. Pelican Lake’s per barrel operating costs
are the lowest in our crude oil portfolio and are industry
leading at $6.60/bbl with a year-over-year reduction of 9%.
The ongoing success of our effective and efficient polymer
flood will generate significant free cash flow in the near-, mid-
and long-term.
In 2017, we will monitor the effectiveness of the polymer
flood on the reservoir looking for additional optimization
opportunities to drive down costs further. We target to increase
production through continued optimizations and a modest
drilling program of 15 net wells. Additional opportunities exist
at Pelican Lake as only about half of the field is currently under
polymer flood, allowing for future value adding opportunities
to convert more of this world class pool to polymer flood.
HEAVY CRUDE OIL MARKETING
As expected, 2016 was another volatile year for commodities.
Canadian Natural, as in previous years, continues to adopt a
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.
We support the expansion of export pipeline capacity and
finally, we support and participate in projects which add
conversion capacity for heavy crude oil and bitumen.
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 its participation
in the Redwater Partnership, which is currently on schedule
for completion in late 2017. The Redwater refinery will add
bitumen 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 long-life, low decline assets
include its thermal operations. This asset provides further
balance as the Company employs three steaming and
production variations; cyclic steam stimulation (“CSS”),
steamflood and steam assisted gravity drainage (“SAGD”).
In total, annual thermal in situ production was approximately
111,000 bbl/d on average in 2016. At Primrose, we continued
to successfully progress our low pressure steamflood
3
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. HIGH QUALITY
DIVERSIFIED
PORTFOLIO
EFFECTIVE
AND EFFICIENT
OPERATIONS
DISCIPLINED
BUSINESS
APPROACH
CAPITAL AND
OPERATIONAL
FLEXIBILITY
operations and achieved better than expected results
through continued optimization of our steaming strategies.
Production from our low pressure steamflood increased
in 2016, to approximately 32,000 bbl/d, a 154% increase
over 2015 levels. Additionally with increased monitoring in
our high pressure CSS areas, steaming has become more
effective and efficient as we can better optimize steaming
pressures and quantities due to increased reservoir data.
Overall production volumes at Primrose have declined in
2016 to approximately 73,000 bbl/d, an expected result due
to natural declines, capital allocation decisions and the timing
of production cycles. In 2017, the Company targets to drill
28 net wells late in the year, as a part of a 128 well program at
Primrose North that is targeted to add 29,000 bbl/d in 2019.
At Kirby South, our commercial SAGD project, operations
ramped up to the targeted 40,000 bbl/d facility capacity with
Q4/16 average volumes exceeding 39,000 bbl/d. Average
production of approximately 38,000 bbl/d was achieved in
2016 and the reservoir performed as expected with strong
thermal efficiencies and low annual steam to oil ratio
(“SOR”) of 2.6. In late 2016, development of Kirby North,
our second SAGD project with targeted facility capacity of
40,000 bbl/d was re-initiated. Canadian Natural will spend
minimal capital in 2017 to ensure engineering and the current
economic environment is fully understood. The majority of
the approximate $650 million remaining will be invested in
2018 and 2019 with first steam targeted for late 2019 and first
oil targeted in early 2020.
MINING AND UPGRADING
At Horizon, Canadian Natural’s world class oil sands mining
and upgrading operations, the final component of our
transition to a long-life, low decline asset base is progressing
and performing as planned. The Company continues to
be focused on safe, steady, and reliable production and
continued improvements in plant performance. In 2016,
Horizon achieved record annual production of approximately
123,000 bbl/d of synthetic crude oil (“SCO”) as the successful
ramp-up of the Phase 2B expansion was completed on
time and budget in Q4/16. Incorporating planned downtime,
Horizon, once again achieved an industry leading average
utilization rate of 92%, demonstrating strong reliability for the
entire year. Strong operations in 2016 supported record low
annual average operating costs of $25.20/bbl, after adjusting
for planned downtime, a 12% reduction from 2015 levels.
Strong production volumes at Horizon continued late in the
year, as production was above nameplate capacity of 182,000
bbl/d, reaching approximately 188,000 bbl/d and 184,000
bbl/d of SCO, in November and December, respectively. In
4
early 2017 this strong performance continued with January
and February production levels of approximately 195,000
bbl/d and 202,600 bbl/d of SCO, respectively.
Canadian Natural’s phased expansion strategy continues to
deliver strong results, with the successful Phase 2B tie-in and
ramp-up in late 2016 and the continued advancement of the
Phase 3 expansion, which reached 89% physical completion
in 2016. In 2016, Horizon project capital expenditures totaled
$1.92 billion, below the Company's 2015 estimate and the
2016 capital budget, strong results given the challenges faced
in the region. In 2017, Horizon project capital expenditures
are targeted to be approximately $1.05 billion to complete
the Phase 3 expansion. The start-up of Phase 3 is targeted
to add incremental production of 80,000 bbl/d of SCO in
late 2017, with targeted operating costs in the $20.00/bbl
to $25.00/bbl range. As the final component of our long-life,
low decline asset base, Horizon production is targeted to
generate significant sustainable cash flow and value for our
shareholders for decades to come.
FINANCE
In 2016, we were proactive in managing our balance sheet
and maintained our capital discipline, in a low commodity
price environment. Over the course of the year, we improved
liquidity via the monetization of our non-operated 15%
ownership in the Cold Lake Pipeline and opportunistic access
to the debt capital markets. At year-end 2016, we had strong
liquidity with approximately $3.0 billion available on our
combined bank facilities of approximately $7.4 billion. Balance
sheet strength continues to be a focus of the Company with
debt to book capitalization of 39% at December 31, 2016,
within the Company's targeted operating range.
We are committed to maintaining our investment grade
credit ratings. We continue to have on-going and 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 maintaining strong financial metrics. In
early 2017, as a result of the Board of Directors confidence
in the Company’s ability to generate sustainable cash flow,
the Company’s dividend was increased for the seventeenth
consecutive year to an annualized value of $1.10 per
common share. Additionally, as a result of strong cash flow
and operating results, the Board of Directors approved the
Company to purchase up to 2.5% of the available common
shares through the application for a normal course issuer bid.
Canadian Natural 2016 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 &
Senior Vice-President, Finance
CANADIAN NATURAL’S STRATEGIC
ADVANTAGE
The execution of our proven strategy and commitment to our
balanced business approach has not wavered in the current
commodity price environment. Canadian Natural is built
for low commodity prices. In 2016, we lowered operating
costs per BOE on a corporate level by 11% and in 2017 we
remain committed to continue to lower our cost structures
as our production and facility teams strive for new efficiency
targets and cost savings. Importantly Canadian Natural has
kept our teams together with no layoffs, keeping culture
strong, enabling knowledge sharing amongst employees and
allowing for time to review current and future opportunities.
Commodity prices cannot be controlled, however, we can
control how we react, with effective and efficient operations
and an execution strategy that maximizes value.
In 2016, we continued to add value for our shareholders through
the completion of the Phase 2B expansion and the progression of
the Phase 3 expansion at Horizon. These two projects represent
the final part of our transition to a longer-life, low decline asset
base, an asset base that will yield growing, and sustainable cash
flow for decades to come. This sustainable cash flow will support
a strong balance sheet, returns to shareholders, acquisition
opportunities and further resource development.
2017 will see Canadian Natural utilize its large, diversified asset
base to provide a balanced production mix varied by region
and commodity type. This balanced production mix gives us
the flexibility to allocate capital to the highest return projects
in our portfolio. The Company’s drilling program is targeted to
increase in 2017, providing value in the short- and mid-term as
we take advantage of our vast low capital exposure project
base to provide quicker payout and greater returns from
our infrastructure advantaged assets. Additionally, we are
committed to complete Horizon Phase 3 in late 2017 and are
targeting to proceed with the development of our thermal in
situ SAGD project at Kirby North. Our capital and operating
flexibility and our ability to react quickly are fundamental to
the Company’s overall success. This success maximizes long-
term shareholder value in any commodity price environment.
A trademark of Canadian Natural is our capital flexibility.
Excluding the recently announced Athabasca Oil Sands Project
acquisition, in 2017, the Company's capital budget is targeted
to be $3.9 billion. Within the budget, the Company has the
ability to roll back approximately $900 million of capital if
market conditions deteriorate or alternatively add $525 million
to our capital program if we see more robust sustainable
economic conditions. Overall, 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 remain committed to maintaining our
investment grade credit ratings, and will maintain flexibility
to proactively manage these financial objectives to remain
financially and operationally sound.
Canadian Natural is well positioned to continue 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 continue to strive to deliver long-term value
for our shareholders by focusing on effective and efficient
operations and as such, we will continue to 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
5
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Our World-Class Team
Our proven strategy and disciplined business approach are supported by our dedicated teams and
experienced management 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, T. Abercrombie, R. Abrams, J. Abramyk, N. Abro, S. Abroskin, C. Acharya, D. Acheson,
J. Acosta, N. Adair, T. Adair, I. Adam, S. Adam, W. Adam, D. Adams, K. Adams, M. Adams, D. Adamson, P. Adamson,
C. Adan, D. Addinall, A. Adebayo, Y. Adebayo, S. Adel, 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, T. Ailsby, K. Airth, J. Airton, K.
Aitchison, T. Ajayi, R. Akers, 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, E. Algazina,
A. Ali, G. Ali, K. Ali, S. Ali, R. Aliazas, H. Aljanabi, M. Al-Kaisy, J. Allan, R. Allan, E. Allard, J. Allen, T. Allen, W.
Allerton, D. Allibone, S. Allport, J. Allsop, M. Almestar Bustamante, Y. Alnumi, J. Alonso, A. Al-Saleem, R. Al-
Samarrai, S. Al-Siani, A. Alstad, J. Alvarez Luzon, D. Amalaman, J. Aman, M. Amar, T. Amara, A. Amay, B. Amer, K.
Amer, D. Ames, E. Amos, 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, P. Andrekson, D. Andreoli, C. Andres, J.
Andres, D. Andrews, L. Andrews, T. Andrews, R. Andriekus, C. Angeles, P. Angell, L. Angen, K. Angerman, N. Ango
Mfene, C. Angus, M. Anis, S. Annis, L. Anongba, A. Ansell, D. Ansorger, R. Anstett, G. Anstey, L. Antal, J. Antle, M.
Antoine, K. Antonishyn, T. Antoniuk, H. Aparicio Ramos, P. Appiah, B. April, R. April, J. Aquila, D. Aranas, R. Aranguren,
F. Arano, L. Arbour, C. Arcand, L. Archer, J. Argan, M. Arguin, H. Arias, L. Arias, J. Arizaleta, J. Arkley, T. Armfelt, A.
Armstrong, D. Armstrong, J. Armstrong, P. Armstrong, R. Armstrong, T. Armstrong, J. Arnault, C. Arnold, F. Arrieta, M.
Arsenault, L. Arthur, S. Arunachalam, B. Ashley, D. Ashley, Z. Ashmore, W. Ashun-Codjiw, R. Aslin, R. Asmundson, 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, 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, W. Ayles, J. Ayub, F. Azam, C. Babos, K. Babu, C. Bachelet, C. Bachman, W. Bachmeier, A.
Baciulica, J. Bacon, O. Baddar, M. Baddeley, W. Bader, K. Badmos, O. Baffoh, 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, B. Bain, D.
Baird, G. Baird, B. Bairstow, D. Baisley, C. Bak, L. Bakaas, A. Baker, C. Baker, D. Baker, G. Baker, F. Bakita, J. Balacang,
B. Baldonado, J. Baldonado, C. Baldwin, K. Baldwin, 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, R. Banfield, O. Bango, J. Banks, L. Banks, B. Bannis, C. Bantaya, G. Bardoel, L.
Bardoel, K. Barham, M. Bari, R. Barker, S. Barker, A. Barley, D. Barnes, M. Barnes, N. Barnes, R. Barnes, V. Barnes, B.
Barnett, D. Barr, S. Barr, E. Barreto, R. Barrett, T. Barrett, C. Barrie, D. Barron, R. Barron, L. Barros, C. Barth, B. Bartlett,
C. Bartlett, C. Bartman, D. Bartman, M. Bartman, J. Basabe, K. Basarab, J. Basilan, R. Basile, L. Basines, S. Basso, C.
Bast, S. Basu, M. Batac, B. Bate, C. 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, C. Beaton, G. Beaton, N. Beaton, A. Beattie, C. Beattie, S. Beattie, A. Beatty,
S. Beauchamp, C. Beaudoin, J. Beaudoin, R. Beaudoin, B. Beaulac, L. Beaunoyer, F. Beaver, D. Bechtel, N. Beck, C.
Becker, H. 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, W. Bell, R. Bellanger, J. Beller, M. Beller, E. Bellerose, A. Bellettini, A. Bellows,
S. Belseck, 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, P. Benoit, S. Bensmiller, R. Benson, A. Benson- Bartko, J.
Bent, A. Bentley, J. Benyon, C. Bereznicki, D. Berg, K. Bergen, J. Bergeson, M. Bergeson, B. Bergley, D. Berisha, D.
Berlinguette, H. Berlinguette, J. Bernardin, D. Bernardo, W. Berscht, D. Bershadsky, S. Bertelmann, B. Bertrand, M.
Bertsch, B. Berube, W. Berube, R. Bessey, C. Best, J. Best, 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, J. Bianchini, 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, D. Biles, B. Bill, T. Billard, J. Bilodeau, J. Bilous, T.
Binczyk, W. Binda, B. Binns, R. Bintz, A. 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, L. Blackburn, N. Blackburn, P.
Blackburn, T. Blackett, K. Blackhall, K. Blackmore, R.
Blackmore, T. Blackwell, A. Blacquiere, D. Blain, A. Blair, L.
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, J. Blomdal, R. Blondin,
J. Blume, C. Blyan, C. Boadas Salazar, M. Bobb, H.
Bocalan, D. Bochek, R. Bock, 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, J. Boire, C. Boisvert,
M. Boisvert, E. Bo-Lassen, D. Bolch, C. Boleski, G. Bolin, D.
Bolster, G. Bolton, D. Boman, J. Bonami-McRae, N. Bond,
S. Bond, T. Bond, T. Bondaruk, C. Bonebrake, A. Bonilla, C.
Bonogofski, T. Bonwick, 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.
6
Borgland, J. Borland, M. Borlaza, M. Born, D. Borowski Grimaldi, E. Borsini Marin, J. Borstel, K. Borysiuk, B. Bosch, D.
Bosch, S. Bosch, J. Boschman, L. Bosma, L. Bosoi, H. Botha, K. Bothwell, J. Botterill, R. Botting, D. Bouchard, L.
Bouchard, C. Boucher, S. Boudignon, K. Boudreau, J. Boudreault, K. Bougie, J. Boulton, T. Bouma, L. Bourassa, R.
Bourassa, S. Bourassa, J. Bourgeois, D. Bourgoin, D. Bourke, C. Bourlon, S. Bourrie, C. Boussougou Mayagui, C. Boutier
Becerra, D. Boutin, C. Bowditch, D. Bowen, J. Bowen, P. Bowering, R. Bowers, S. Bowers, D. Bowes, B. Bowie, J.
Bowie, M. Bowles, C. Bowman, K. Bowman, N. Bowman, W. Bowman, E. Bown, W. Bowness, M. Bowry, J. Boxer, D.
Boyarski, T. Boyce, D. Boyd, R. Boyd, S. Boyd, C. Boyer, D. Boyle, L. Boyle, K. Bradbury, B. Bradley, P. Bradner, J.
Bradshaw, C. Bradt, M. Brady, C. Bragg, J. Bragg, L. Bragg, D. Braid, A. Brain, J. Brake, N. Brake, S. Brake, T. Branch,
P. Brand, B. Brant, D. Brant, E. Brant, A. Brar, M. 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, C. Brenton, R. Brenton, T. Brettnell, R. Bretzlaff, O. Breukel, A. Brewer,
W. Briand, S. Briard, C. Bridger, H. Brietzke, M. Brietzke, C. Briggs, G. Briggs, J. Bright, L. Brinkworth, S. Brinson, C.
Brisebois, V. Brisebois, P. Britton, E. Brock, J. Brock, K. Brocke, B. Broda, D. Broderick, S. Broderick, S. Broderson, D.
Brodziak, E. Broidioi, K. Bromley, J. Bronkhorst, C. Bronneberg, J. Brooks, R. Brooks, K. Brosowsky, 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, N. Brown, R. Brown, S. Brown, T. Brown, D. Brownrigg, 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, M. Bryson, S. Bryson, G. Buchan, P. Buchanan, M.
Bucholtz, D. Buckley, G. Buckshaw, D. Budalich, T. Budd, B. Budgell, R. Budzen, R. Bueckert, W. Bugiak, J. Buholzer, S.
Bukhari, R. Bullen, T. Bullen, I. Bulloch, J. Bullock, D. Bumstead, S. Bungay, B. Bunz, D. Burak, J. Burchell, T. Burchenski,
A. Burden, K. Burden, J. Burdett, C. Burge, G. Burgess, G. Burkart, L. Burke, G. Burkhart, R. Burnham, B. Burr, K. Burry,
D. Bursey, M. Bursey, A. Burt, B. Burt, S. Burt, T. Burt, D. Burton, G. Burton, R. Burton, R. Busato, K. Bush, D. Bushey, D.
Bussey, N. Bussiere, J. Bustamante, M. Butchart, K. Butcher, C. Butler, I. Butler, M. Butler, R. Butler, C. Butt, Q. Butt, S.
Butt, B. 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, 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, N.
Cambridge, R. Cameron, S. Cameron, B. Campbell, C. Campbell, D. Campbell, E. Campbell, F. 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, N. Cantwell, 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, R. Carifelle, D. Carleton, 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, Z. Castillo Navarro, K. Castle, J. Castro, N. Catley, S. Catley, L. Catto, D. Cavacciuti, A. Cavanagh, 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. Challoner, J. Chalmers, M. Chalmers, S. Chalmers, C. Chambers, K. Champagne, L.
Champagne, A. Chan, C. Chan, D. Chan, I. Chan, J. 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,
B. Chen, C. Chen, O. Chen, T. Chen, X. Chen, Z. Chen, C. Cheng, J. Cheng, N. Cheng, D. Chenier, N. Cheraghi, M.
Chernichen, T. Cherry, O. Chervyakova, B. Chester, A. Chesterman, D. Chetcuti, A. Cheung, I. 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, A. Chisholm, 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, J. Christian, N. Christian, S. Christiansen, M. Christianson, S. Christianson, R. Christie, S.
Christie, A. Chu, C. Chua, V. Chui, K. Chunduri, P. Chung, W. Chung, H. Church, G. 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,
J. Coates, R. Coates, E. Cobaj, M. Cochet, D. Cockerill, F. Codd, J. Coers, B. Colaco, L. Colborne, J. Colbourne, B. Cole,
A. Coles, M. Coles, R. Coles, L. Collard, P. Colley, D. Collicutt, M. Collie, G. Collings, J. Collins, R. Collins, C. Collinson,
A. Collison, G. Collison, A. Collyer, E. Comeau, J. Commance, C. Compton, Q. Conacher, J. Condie, A. Connell, M.
Connellan, D. Conrad, S. Constant, D. Conybeare, C. Cook, G. Cook, L. Cook, N. Cook, H. Cooke, K. Cookson, L. Cookson,
R. Coolen, J. Coombs, L. Coonan, C. Copeland, M. Copithorne, R. Copland, D. Coppard, D. Corbett, N. Corbett, J.
Corcoran, M. Corell, E. Coreman, I. Cormier, R. Cornell, 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, E. Cotten, L. Cottreau, S. Coulibaly,
D. Coull, K. Coulombe, M. Courage, J. Courchene, R. Courchesne, G. Courtney, P. Cousin, D. Cousins, M. Cousins, P.
Covell, K. Cowan, D. Coward, K. Cowger, I. Cowie, C. Cowley, R. Cowley, A. Cox, B. Cox, E. Cox, G. Cox, J. Cox, R. Cox,
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, R. Crichton, D. Crittall, A. Critten, W. Crockford,
A. Croft, S. Croft, G. Crooks, D. Crosley, T. Crosley, C. Cross, T. Cross, S. Croteau, T. Crouser, A. Croutch, S. Crowe, D.
Crowle, R. Crowle, B. Crowley, R. Cruickshank, D. Crum, K. Crutchley, L. Cruttenden, C. Cruz, A. Csabay, S. Cseke, E.
Cuello, Y. Cui, M. Culligan, A. Cunanan, A. Cunningham, D. Cunningham, R. Cunningham, E. Cupac-Cingel, J. Curran, A.
Currie, R. Currier, K. Cursley, D. Curtis, K. Cusack, M. Cusson, R. Cusson, J. Cutler, C. Cyr, D. Cyr, G. Cyr, K. Cytko, J.
Czarnecki, L. Czernicki, M. Czerwinski, K. d'Abadie, V. Daboin, A. Dabrowski, G. Dacyk, F. Dadashov, R. Dadey, M. Dadi,
G. Dafoe, W. Dagley, A. Dahmani, C. Daigle, B. Daignault, E. Dakaud, P. Dale, L. Dalgetty-Rouse, G. Dallaire, J. Dallaire,
S. Dalrymple, M. Dalton, S. Dams, E. Dana, C. Danaher, A. Danbrook, T. Danbrook, W. Danchak, J. Daniels, T. Daniels,
D. Danilkewich, I. Dantiwala, C. Danyluk, 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, M. Davidson, S. Davidson,
T. Davidson, C. Davies, D. Davies, L. Davies, M. Davies, S. Davies, H. Davis, J. Davis, K. Davis, R. Davis, P. Davison, B.
Davis-Sorochuk, 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, R. De Jesus, 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, P. Deagle, M. Dean, G. Dearden, C. Deaver, T. Debler, R. deBoer, W.
DeBona, S. DeBruycker, D. Dechaine, J. Dechaine, P. Dechaine, R. Dechaine, P. Dechant, R. Dechesne, B. Decker, M.
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, N. Dela Cruz, D. DelaCruz, I. Delaney, E. DeLaRonde, J. Delaurier, N. Delibasic, M.
Dell, F. Dell'Ovo, M. DelMastro, M. Delorme, A. Demaiter, M. Demers, C. DeMone, M. Demou, C. Dempsey, F. Denney,
C. Dennis, S. Dennis, D. Dennison, S. Denny, C. Denslow, J. Dent, H. Derakhshan, D. Derbyshire, J. Derix, M. Derry, A.
Desai, C. Desai, D. Desai, R. Desai, 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, T. Dew, C. Dewar, J. Dewar, T. Dewhurst, D. Dey, K. Deyaegher, K. Deyan, M. Deyan, 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, M. Dibus, L. Dick, R. Dicken, A.
Dicks, E. Dicks, J. Dicks, N. Dicks, C. Dickson, F. Dickson, G. Dickson, A. Didenko, D. Diebel, J. Diederich, I. Dikau, R.
Dillman, A. Dimapilis, M. Dingley, P. Dingley, R. Dingwell, R. Dinkel, H. Dinn, R. 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,
R. Docksteader, L. Dodd, R. Dodd, M. Doepel, R. Doering, J. Doetzel, J. Doiron, K. Doiron, E. Doleman, J. Doleman, K.
Doll, D. Dolynchuk, B. Dombrova, D. Domin, K. Donald, S. Donaldson, R. Donaleshen, C. Dong, M. Dong, J. Donohoe,
J. Donovan, N. Donovan, C. Doo, J. Doonanco, T. Dootka, S. Dorer, A. Dorey, S. Dorie, M. Dorocicz, J. Dorusak, A.
Dosanjh, M. Doucet, R. Doucet, D. Doucette, K. Doucette, J. Douglas, R. Dow, A. Dowd, J. Dowd, E. Dowell, S. Dowell,
M. Dowman, P. Downes, J. Downey, A. Downs, A. Doyer, R. Doyer, G. Doyle, L. Doyle, S. Drake, P. Drapeau, K. Draper,
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 7,270
Strong
DIVERSITY. TALENT.
EXPERTISE.
To develop people to work
together to create value for the
Company’s shareholders by
doing it right with fun
and integrity.
T. Draper, W. Draper, D. Draycott, K. Dreger, C. Drescher, D. Dressler, B. Drew, J. Dreyer, T. Dreyer, C. Driedger, A.
Driemel, A. Drier, S. Driscoll, T. Driscoll, E. Drolet, B. Drover, R. Drummond, C. Drury, D. Drury, S. Drysdall, V. D'Souza,
M. Du, M. Du Preez, C. Duane, R. Duarte, M. Dube, N. Dube, R. Dube, T. Dube, J. Dubeau, T. Dubie, G. Dubois, J.
Dubois, J. Dubuc, D. Duby, R. Ducharme, P. Duchesnay, J. Duchscherer, J. Duczek, P. Duda, S. Dudley, R. Dueck, G. Duff,
E. Dufour, S. Dugdale, C. Duggan, W. Duggan, D. Duguid, A. Duhaime, J. Dul, C. Dumais, T. Dumba, G. Dumont, Y.
Dumont, L. Dumoulin, B. Duncan, H. Duncan, J. Duncan, S. Duncan, B. Dunn, D. Dunn, J. Dunn, P. Dunn, R. Dunn, S.
Dunn, E. Dunnet, J. Dunsmuir, K. Dupuis, H. Dutchak, J. Dutchak, O. Dutka, C. Dwyer, A. Dyck, C. Dyck, C. Dyer, J. Dyer,
T. Dyer, E. Dyjur, L. Dyke, S. Dykstra, R. Dyson, K. Dzwonek, J. Eagleson, G. Earl, R. Earl, J. Easthope, B. Eastman, K.
Eberle, R. Ebuna, T. Eburne, G. Ecker, E. Edeonu, P. Edirisinghe, J. Edmunds, A. Edoukou, J. Edoukou, D. Edwards, J.
Edwards, F. Eefting, T. Eeuwes, T. Egan, L. Egeland, R. Eggen, C. Ehresman, I. Eichelbaum, T. Eissfeldt, B. Eitzen, D.
Ekdahl, C. Ekpekurede, R. Elaschuk, D. Eley, M. Elgarni, M. El-Harakeh, D. Elia, T. Elias, M. Elias-Neira, R. Elko, K.
Elladen, R. Elliott, S. Elliott, W. Elliott, D. Ellis, K. Ellis, S. Ellis, C. Ellsworth, E. Ellsworth, M. Elms, M. Eloursa Escanela,
O. El-Sayed, E. Elson, J. Elson, T. Ely, V. Embleton, H. Emery, J. Emro, J. Engel, R. Engler, J. English, R. Enns, R.
Ephgrave, J. Epp, J. Erasmus, S. Erb, D. Ereaut, B. Eresman, C. Erfle, B. Erickson, D. Erickson, T. Erickson, N. Erixon, M.
Ernst, P. Ersh, C. Erskine, D. Ertmoed, P. Escalona, F. Escobar de Serra, G. Eskandari, A. Espindola, R. Esslemont, J.
Esteves, O. Estrada, S. Etherington, J. Eunson, A. Evans, D. Evans, R. Evans, T. Evans, K. Evdokimoff, J. Eveleigh, S.
Eveleigh, C. Eves, K. Ewach, J. Ewen, R. Ewing, V. Ezeronye, P. Ezumah, R. Faechner, D. Fagnan, S. Fairfield, S. Faizal,
E. Falconer, S. Fallahi, Y. Fang, D. Fanning, D. Farney, A. Farokhsiar, A. Farquhar, Z. Farrales, D. Farrell, T. Farrell, R.
Farrer, T. Farrer, S. Faruqi, B. Fast, R. Fast, S. Fast, A. Faucher, C. Faucher, R. Faustini, E. Fauth, C. Fayant, R. Fayant, M.
Fear, R. Featherstone, S. Feaver, M. Federucci, D. Fedoruk, E. Fedossova, C. Fedun, T. Fedyna, B. Feil, D. Feland, I.
Feland, J. Feland, E. Fender, B. Fenrich, K. Fenrich, L. Fentie, A. Ferbey, K. Ferdous, S. Ferenc, K. Ference, L. Ference, B.
Ferguson, C. Ferguson, H. Ferguson, M. Ferguson, R. Ferguson, S. Ferguson, B. Fernandes, A. Fernandez, E. Fernandez,
L. Fernandez Exposito, B. Ferris, M. Ferris, M. Ferry, D. Fichter, J. Fidler, B. Field, M. Fielden, K. Fielding, W. Fielding, W.
Fields, B. Fifield, C. Filgate, M. Filipchuk, I. Filipescu, T. Fillmore, S. Filteau, B. Finch, N. Findlay, T. Findlay, A. Fink, B.
Finlayson, D. Finnamore, C. Finnebraaten, K. Finnerty, R. Finney, E. Finnigan, K. Finnigan, T. Finnigan, E. Finol, T. Fir, L.
Fischer, J. Fish, C. Fisher, L. Fisher, A. Fisk, S. Fitzgerald, S. Fitzpatrick, K. Flack, M. Flahr, C. Flamont, J. Flamont, B.
Fleck, M. Flegel, A. Fleming, D. Fleming, S. Fleming, T. Fleming, L. Fletcher, R. Flett, B. Flier, B. Flockhart, I. Florea, L.
Florinski, J. Flynn, S. Flynn, K. Foisy, D. Fokema, R. Folmer, Y. Fong, B. Fontaine, D. Fontaine, G. Fontaine, L. Fontaine,
R. Fontaine, B. Foord, R. Foran, D. Forbes, M. Forbes, A. Forcade, T. Ford, L. Forget, C. Formanek, R. Formanek, T.
Fornwald, B. Forrester, G. Forrester, L. Forrester, B. Forrister, J. Forsberg, M. Forster, S. Forster, S. Forsyth, H. Forte, A.
Fortier, C. Fortier, D. Fortin, S. Foss, C. Foster, D. Foster, K. Foster, R. Foster, S. Foster, V. Foster, D. Fotty, A. Fougere, K.
Foulds, R. Foulkes, G. Fountain, L. Fournier, H. Fowell, G. Fowler, J. Fowler, D. Fox, J. Fox, R. Fox, M. Foxton, S. Fraino,
R. France, M. Francescone, O. Franchi, D. Francis, N. Franck, C. Frank, A. Frankiw, P. Fransen, K. Franson, W. Franson,
S. Franssen, R. Frasch, S. Frasch, B. Fraser, G. Fraser, K. Fraser, L. Fraser, M. Fraser, R. Fraser, K. Frazer, B. Frechette, S.
Freckelton, A. Freeman, M. Freeman, J. Freer, U. Freiberg, J. French, R. Frere, J. Frese, L. Freund, K. Freyman, K.
Friedrich, D. Friedt, W. Friend, D. Friesen, H. Friesen, J. Friesen, K. Friesen, N. Friesen, T. Friesen, K. Frith, A. Frizorguer,
J. Froc, C. Frosini, C. Froude, S. Froude, A. Fry, T. Fryer, X. Fu, K. Fujimoto, D. Fukushima, W. Fulkerson, D. Fuller, J. Fuller,
D. Fung, J. Fung, S. Fung-Yau, C. Funk, R. Funk, A. Furgiuele, G. Furlong, H. Furst, T. Furuya, C. Fuster, R. Fyfe, R.
Gaboury, K. Gabrielson, D. Gabruck, L. Gadowski, J. Gaeta, R. Gaetz, N. Gafuik, A. Gage, C. Gagne, J. Gagnon, S.
Gagnon, W. Gail, B. Galbraith, M. Galea, J. Galey, R. Gall, R. Gallagher, S. Gallamore, F. Gallant, M. Gallant, R. Gallant,
F. Gallardo, M. Gallon, K. Galloway, J. Galotta, B. Gamble, C. Gamboa, L. Gamboa, W. Gamp, F. Gan, A. Gandhi, P.
Gandhi, V. Gandhi, D. Ganske, B. Gantz, Y. Gao, V. Gapaz, A. Garcia, C. Garcia, A. Garden, K. Gardiner, S. Gardiner, L.
Gardner, S. Gardner, J. Gareau, R. Gareau, T. Gareau, R. Garg, V. Garg, K. Garland, A. Garneau, W. Garner, E. Garrison,
L. Garvey, S. Garwon, C. Garzon, C. Gascon, V. Gatchalian, L. Gates, J. Gatrell, S. Gatt, F. Gaudet, W. Gaugler, L. Gauld,
G. Gaulin, K. Gaulton, C. Gauthier, D. Gauthier, M. Gauthier, N. Gauthier, P. Gauthier, K. Gautschi, S. Gavronsky, C.
Gawley, T. Gaydos, R. Gayler, C. Geddes, J. Geddes, D. Geleta, O. Gelowitz, L. Gemmell, M. Genereux, G. Genge, N.
Genge, P. Gentles, M. George, R. Georgescu, J. Georget, J. Gerein, S. Geremia, J. Gergely, B. Gerke, G. Gerla, J.
Gerlinger, M. Germain, R. Germain, C. German, K. Gerow, S. Gerow, E. Gervais, K. Gervais, M. Gervais, P. Gervais, K.
Gessner, S. Getson, G. Getz, K. Getzinger, L. Ghasem Rashid, K. Ghesmat, E. Ghoubrial, I. Gibbon, S. Gibbon, C. Gibson,
D. Gibson, J. Giebelhaus, S. Giefer, D. Giesbrecht, J. Giesbrecht, T. Giesbrecht, K. Gifford, J. Gigg, D. Giggs, G. Gilbert,
J. Gilbert, K. Gilbertson, S. Giles, V. Giles, P. Gilhespy, K. Gill, N. Gill, S. Gill, J. Gillatt, V. Gillespie, E. Gillingham, J.
Gillingham, M. Gillund, C. Gilman, K. Gilman, E. Gimenez, R. Gimoro, G. Gin, P. Gingras, K. Ginter, T. Ginther, D. Girard,
G. Girard, S. Girbav, R. Girletz, J. Girouard, B. Gisby, M. Gisondo Crawford, S. Gist, E. Giuliani, S. Glazier, R. Gleasure,
R. Gleed, G. Glenn, D. Gliddon, D. Gloade, D. Glover, R. Glover, J. Gnam, R. Gnatovski, J. Godin, K. Godin, D. Godwin,
L. Godwin, L. Goerzen, C. Gogol, J. Gogol, B. Gogowich, D. Golden, A. Goll, M. Gomaa, R. Goman, E. Gomez, J. Gomez,
C. Gomuwka, E. Gong, K. Gong, M. Gonzales, I. Gonzalez, N. Gonzalez, Y. Gonzalez, P. Gonzalez Sierra, C. Good, C.
Goodall, C. Goodman, A. Goodwin, W. Goodwin, J. Gorai, K. Gordeyko, D. Gordon, I. Gordon, J. Gordon, K. Gordon, L.
Gordon, S. Gordon, J. Gorgichuk, D. Gorrie, J. Gorski, M. Gorski, R. Gosse, T. Gosse, Y. Gosselin, K. Goudie, A. Gould,
B. Gould, I. Gould, R. Gould, H. Gouldie, G. Goulding, M. Goulding, C. Goulet, D. Goulet, J. Gourlie, J. Gover, R. Govil,
N. Govindarajan Prithivirajan, M. Govindaswamy Krishnamoorthy, M. Goyal, J. Graca, C. Graham, D. Graham, G.
Graham, J. Graham, S. Graham, T. Graham, B. Granger, J. Granger, A. Grant, C. Grant, H. Grant, J. Grant, M. Grant, R.
Grant, S. Grant, A. Graup, R. Gravell, T. Graveson, C. Gray, D. Gray, J. Gray, R. Gray, S. Gray, C. Grayston, J. Greaves, G.
Grebowski, A. Greeley, C. Green, E. Green, J. Green, K. Green, M. Green, W. Green, C. Greenawalt, D. Greenawalt, C.
Greene, D. Greene, T. Greene, A. Greenfield, R. Greening, R. Greenwood, D. Greep, T. Greig, A. Grenier, A. Grewal, R.
Griemann, R. Grieve, M. Griffin, P. Griffin, E. Griffiths, J. Griffiths, K. Griffiths, R. Groenen, Z. Groom, M. Grosseth, A.
Grossi, P. Grove, D. Grundner, D. Grzela, S. Gu, C. Guay, C. Gudjonson, P. Guedez, J. Guerin, E. Guerra, M. Gueye, D.
Guglielmin, A. Guillen, R. Guinup, A. Gulamhusein, K. Gulamhusein, R. Gulati, D. Gulayec, R. Gulutzan, J. Gumbley, C.
Gunderson, R. Gunn, L. Gunnell, I. Gunning, A. Gupta, S. Gupta, J. Gurba, M. Gurin, C. Gursky, E. Gushnowski, J.
Gushue, T. Gushue, R. Gussen, G. Gustafson, G. Gygi, D. Ha, T. Ha, E. Haag, B. Haahr, B. Haas, C. Haas, S. Haas, R.
Haberlack, C. Habiak, S. Habiby, R. Hache, C. Hachey, K. Hachey-Lalonde, J. Hack, E. Hadada, V. Haddad, N. Hadskis,
K. Hagan, L. Hagg, C. Hagstrom, K. Hague, O. Haight, A. Hains, A. Haj Hamdan, S. Hajar, S. Haji, C. Hales, D. Halewich,
B. Haley, R. Haley, J. Halford, A. Hall, B. Hall, C. Hall, D. Hall, J. Hall, R. Hall, S. Hall, T. Hall, S. Halland, S. Hallas, C.
Hallborg, B. Hallett, G. Hallett, J. Hallett, O. Hallmark, R. Hallock, A. Halvorson, C. Hambly, J. Hamel, P. Hamel, J.
Hamelin, B. Hamer, D. Hamilton, J. Hamilton, T. Hamilton, K. Hamm, M. Hammel, D. Hammerlindl, G. Hammond, J.
Hammond, C. Hamori, C. Hampton, B. Hamrell, G. Hanas, B. Hancock, B. Hancott, F. Hanif, E. Hanlon, S. Hanlon, E.
Hann, K. Hann, B. Hanna, A. Hansen, D. Hansen, J. Hansen, K. Hansen, M. Hansen, P. Hansen, R. Hansen, D. Hanson,
L. Hanson, T. Hanson, B. Harbin, L. Harder, C. Harding, F. Hardy, J. Hardy, K. Hargrove, E. Harikumar, J. Harke, K. Harke,
J. Harker, J. Harland, B. Harle, D. Harley, E. Haroldson, G. Harper, A. Harris, B. Harris, J. Harris, M. Harris, S. Harris, C.
Harrison, D. Harrison, R. Harsany, D. Harty, J. Harty, B. Harvey, D. Harvey, G. Harvey, J. Harvey, K. Harvey, R. Harvey, S.
Harvey, I. Hashi, H. Hashmi, M. Hassan, O. Hassan, B. Hassen, C. Hassenrueck, J. Hatala, F. Hategan, P. Hatt, G. Hatto,
W. Hatton, D. Haub, R. Hauger, T. Hauger, W. Hausch, J. Haviland, A. Hawthorne, S. Haxton, N. Hay, S. Hay, D. Hayashi,
B. Hayden, C. Hayden, J. Hayden, C. Hayes, M. Hayes, K. Hayko, J. Haynes, L. Haynes, A. Hayward, R. Hayward, J.
Hazin, S. He, T. He, Y. He, M. Headrick, J. Heagy, A. Heale, B. Hearn, C. Heath, D. Heath, L. Heath, T. Heath, B. Heatley,
S. Heawood, T. Hebel, B. Hebert, D. Hebert, G. Hebert, J. Hebert, M. Hebert, W. Hebert, B. Hebner, S. Heck, T. Heck, D.
Heemeryck, C. Heffner, D. Hefford, C. Hehr, J. Heidinger, M. Heigl, C. Hein, F. Hein, R. Hein, R. Heinrichs, B. Heise, S.
Heiskanen, B. Helliker, M. Helman, R. Helyar, C. Hemington, B. Hemstock, P. Henderson, S. Henderson, W. Henderson,
E. Hendrickson, K. Hendrickson, R. Henley, K. Hennessey, E. Henriquez, C. Henry, R. Henry, T. Henry, H. Henschel, D.
Herauf, K. Herba, B. Herman, A. Hernandez, G. Hernandez, M. Hernandez, P. Hernandez, C. Herring, R. Herrington, D.
Heshka, R. Heska, K. Heslop, B. Heugh, J. Hevey, J. Hewitt, T. Hewitt, J. Hewlett, D. Hicke, P. Hickey, R. Hickey, C.
Hicks, K. Hicks, R. Hicks, L. Hiebert, M. Hiemstra, T. Hiemstra, E. Hietanen, R. Higa, A. Higgins, J. Higgins, L. Higgins,
M. Higgins, R. Higgins, P. Higgitt, C. Hildahl, T. Hildebrand, D. Hill, H. Hill, K. Hill, R. Hill, S. Hill, J. Hillier, S. Hillier, T.
Hillier, T. Hills, R. Hilton, B. Hindmarch, T. Hindson, K. Hingley, K. Hinton, D. Hiscock, D. Hitra, G. Ho, M. Ho, T. Ho, D.
Hoar, J. Hoare, R. Hoath, W. Hobart, G. Hodder, J. Hodder, D. Hodge, L. Hodge, P. Hodgkinson, A. Hoey, L. Hoff, T. Hoff,
R. Hoffman, M. Hofstrand, S. Hogan, A. Hogg, J. Hogg, R. Hogg, B. Holaki, M. Holland, A. Hollebakken, I. Hollenbeck,
D. Holley, G. Holloway, C. Holman, D. Holman, R. Holman, J. Holmes, K. Holmes, T. Holmes, D. Holt, B. Holthe, J.
Holton, J. Holuk, G. Homann, L. Hominiuk, K. Honar, D. Honing, A. Hood, C. Hood, D. Hood, F. Hood, G. Hook, J. Hooper,
R. Hooper, D. Hope, S. Hopkins, Y. Hopkins, C. Hopps, A. Hordy, D. Horlick, R. Horn, T. Hornberger, K. Hornseth, K.
Horvath, R. Horvath, J. Horyn, K. Hosker, A. Hoskins, M. Hossain, T. Hou, S. Houck, L. Houghton, C. Houle, A. House, G.
House, T. House, J. Howard, T. Howard, C. Howden, R. Howden, J. Howell, T. Howell, P. Howie, S. Howlader, M.
Howrish, J. Howse, T. Hoyles, W. Hoyles, D. Hoyt, R. Hoyt, B. Hoza, D. Hrycak, T. Hrycay, V. Hrycuik, B. Hryniw, N.
Hryniw, B. Hu, J. Hu, D. Huang, J. Huang, N. Huang, Q. Huang, G. Huber, T. Huckabone, K. Huculak, W. Huddlestun, T.
Hudema, A. Hudson, D. Hudson, J. Hudson, P. Hudson, S. Huebner, K. Huey, J. Huff, A. Hughes, B. Hughes, D. Hughes,
J. Hughston-Bulmer, E. Huh, M. Hulan, D. Hull, B. Human, M. Human, D. Hunchak, M. Hunchak, M. Hundal, I. Hundeby,
M. Hung, C. Hunt, M. Hunt, D. Hunter, K. Hunter, L. Hunter, P. Hunter, R. Hunter, W. Hunter, M. Hupchuk, K. Hupp, J.
Hurd, K. Hurd, G. Hurley, R. Hurtado, R. Hurtado Urdaneta, A. Hussain, S. Hussaini, R. Hussynec, L. Huston, A.
Hutchinson, D. Hutchinson, R. Hutchinson, C. Hutchison, L. Hutchison, R. Hutscal, E. Hutton, A. Huynh, C. Huynh, S.
Hwang, S. Hyatt, A. Hymanyk, D. Hynes, N. Hynes, S. Hynes, S. Hyrcha, K. Iampen, G. Iannattone, L. Iannattone, P.
Iannattone, R. Ibbotson, T. Idler, A. Idowu, G. Iervella, H. Iftemie, N. Ilchuk, T. Ilie, E. Imbery, W. Imeson, K. Imlach, M.
Imran, S. Imrie, A. Inglis, R. Inglis, E. Ingram, G. Ingram, J. Inlow, B. Inman, M. Inscho, M. Ippolito, R. Irani, R. Ireton,
M. Irfan, J. Irons, K. Ironstand, S. Irwin, J. Isaacs, B. Isbister, C. Isea Natera, D. Isele, H. Ishaque, M. Islam, F. Isley, G.
Ismaguilova, A. Ivany, L. Iversen, J. Ivezic, I. Jabbar, C. Jabusch, L. Jacek, D. Jackson, K. Jackson, R. Jackson, S.
Jackson, T. Jackson, S. Jacob, J. Jacobs, M. Jacobs, K. Jacobson, A. Jacques, A. Jacula, C. Jacula, M. Jacula, D.
Jaeger, M. Jahangiri, R. Jahanshahi, V. Jain, M. Jaindl, R. Jakher, R. Jakubowski, B. Jakulj, G. Jaleel, L. Jama, M.
Jama, S. Jamam, D. Jaman, A. James, D. James, R. James, W. James, J. Jamieson, M. Jamieson, R. Jamieson, S.
Jamieson, A. Janes, J. Jankowski, Z. Janosova, D. Jans, S. Jansky, S. Janssen, T. Janusc, A. Janzen, L. Janzen, M.
Janzen, L. Jardie, C. Jardine, C. Jarratt, B. Jarvis, J. Jarvis, K. Jaschke, I. Jasper, R. Jaycock, J. Jeannotte, A. Jegou,
W. Jellison, G. Jenkins, T. Jenkins, J. Jenner, R. Jenniex, D. Jennings, A. Jensen, B. Jensen, K. Jensen, L. Jensen, T.
Jensen, D. Jenson, M. Jeroncic, R. Jeronymo, T. Jervis, C. Jesso, M. Jesso, T. Jessome, J. Jesson, S. Jevne, B. Jevne-
Dick, P. Jia, S. Jiang, R. Jimeno, X. Jing, K. Jivraj, D. Joa, M. Joarder, P. Jobin, K. Jochaud du Plessix, J. Jocksch, D.
Jodoin, G. Joe, J. Joffre, G. Johal, K. Johansson, B. Johns, D. Johns, B. Johnson, C. Johnson, D. Johnson, G. Johnson,
J. Johnson, M. Johnson, N. Johnson, P. Johnson, R. Johnson, S. Johnson, T. Johnson, A. Johnston, D. Johnston, H.
Johnston, N. Johnston, R. Johnston, B. Johnstone, C. Johnstone, R. Johnstone, S. Johnstone, D. Johnston-Watson, V.
Jolliffe, J. Jonasson, A. Jones, B. Jones, C. Jones, D. Jones, E. Jones, G. Jones, K. Jones, M. Jones, N. Jones, R.
Jones, S. Jones, V. Jones, W. Jones, P. Joo, J. Jorawsky, D. Jordan, D. Jordison, C. Jorgensen, D. Jorgensen, L.
Jorgensen, D. Joseph, K. Joseph, A. Joshi, T. Joshi, U. Joshi, S. Josselyn, F. Josue, D. Jowsey, J. Juan, M. Juanerio,
R. Jubinville, T. Juett, J. Jung, S. Jung, C. Jungen, R. Jungkind, C. Jurgenliemk, K. Jurouloff, A. Kachra, C. Kada, L.
Kada, T. Kadikoff, C. Kaglea, R. Kahanyshyn, A. Kaid, K. Kajorinne, R. Kalam, S. Kalbag, A. Kalmet, D. Kalynchuk, A.
Kamate, B. Kamath, A. Kamke, G. Kamon, S. Kanarek, A. Kandasamy, S. Kandulva Chakrapany, L. Kane, S. Kane, N.
Kang, Z. Kanji, R. Kanomata, D. Kantz, S. Kapeluck, Y. Karayan Moosafi, R. Karlowsky, R. Karlson, S. Karmakar, M.
Karpan, C. Karpiak, J. Karr, K. Kartushyn, D. Kary, J. Kasha, N. Kashirina, C. Kaskiw, M. Kaspers, S. Kassi, M. Kassim,
M. Kathan, D. Katnick, H. Katrip, A. Katyayan, J. Kaufman, M. Kaur, S. Kaushik, C. Kavalec, T. Kavalec, K. Kay, O. Kay,
G. Kaya, L. Kayyali, G. Kazimirowich, M. Kealey, M. Kearley, B. Keddie, A. Keebler, L. Keech, M. Keefe, C. Keehn, H.
Keele, J. Keenon, P. Keglowitsch, P. Kehler, C. Keil, J. Kelenc, C. Kellogg, E. Kellough, M. Kelloway, M. Kelly, S. Kelsey,
T. Kemmer, G. Kemp, M. Kemp, S. Kempner, R. Kendall, D. Kendell, R. Kendell, C. Kendrick, B. Kennedy, G. Kennedy, L.
Kennedy, M. Kennedy, R. Kennedy, S. Kennedy, W. Kennedy, D. Kent, R. Kent, S. Kent, D. Kenyon, V. Kenyon, P.
Kernaghan, C. Kerpan, A. Kerr, D. Kerr, J. Kerr, R. Kerr, S. Kerr, S. Kers, D. Ketchum, B. Kevol, M. Khan, S. Khan, N.
Khatri, R. Khatri, S. Khong, S. Kiasosua, I. Kidd, R. Kidd, D. Kidger, B. Kidmose, K. Kielt, L. Kiez, D. Kilbreath, M.
Kilcollins, C. Killick, O. Kilo, H. Kim, R. Kim, D. Kimmie, C. Kimura, M. Kinden, B. King, C. King, D. King, G. King, I. King,
J. King, M. King, R. King, T. King, W. King, R. Kingcott, T. Kingsbury, J. Kingsmith, K. Kinnaird, C. Kinniburgh, T.
Kinniburgh, M. Kinsman, P. Kip, T. Kirchner, D. Kirkham, L. Kirkpatrick, M. Kirkwood, A. Kiss, B. Kiss, K. Kiss, B. Kissel,
M. Kissoon, B. Kiyawasew, C. Kiyawasew, G. Kjelshus, J. Klaffl, A. Klassen, D. Klassen, J. Klassen, R. Klassen, S.
Klassen, C. Klatt, D. Klause, A. Klein, D. Klimczak, C. Knapper, R. Knee, W. Knelson, R. Kneteman, J. Knibbs, M.
Kniebel, J. Knight, J. Knight-Ehiwe, J. Knipe, B. Knopf, D. Knott, W. Knouse, G. Knowlton, J. Knox, T. Knox, M. Kobagi,
D. Kobes, B. Kobzey, B. Koch, M. Koch, R. Koenig, K. Koffi, L. Koffi, S. Koffi, K. Koger, C. Kohls, B. Koizumi, M. Kokorudz,
J. Kolba, C. Kolberg, L. Kolberg, M. Kolenchuk, B. Koma, M. Komant, E. Komers, M. Konate, M. Kondor, B. Kondratowicz,
B. Kone, L. Kone, R. Konrad, B. Kootenay, S. Korchagin, M. Koren, P. Kornacki, B. Korolischuk, J. Kosanovich, A.
Kosasih, R. Kosheiff, 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.
7
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. K. Mashayekh, B. Mason, J. Mason, K. Mason, W. Mason, M. Massiah, 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,
B. Matthews, D. Matthews, N. Matthews, J. Matthiessen, J. Mattiussi, R. Matychuk, P. Maurice, S. Maurice, D.
Mavridis, D. Mavuwa, A. Mawer, C. Maxsom, K. Maxwell, A. May, R. May, J. Mayer, S. Mayer, T. Mayhew, A.
Maynard, K. Mayner, A. Mayo, B. Mayo, C. Mays, D. Mazur, D. Mazurek, C. Mazuryk, D. McAlister, M. McAlpine, D.
McArthur, K. McArthur, N. McBain, A. McBoyle, T. McBride, R. McBrien, D. McCabe, G. McCabe, J. McCaffrey, R.
McCallum, S. McCann, D. McCarry, D. McCarvill, D. McClelland, I. McClelland, B. McClure, 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. McDaniel, C. McDonald, D. 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, F. McGaw, D. McGee, L. McGee, G.
McGinnis, C. McGovern, A. McGrath, C. McGrath, M. McGrath, T. McGrath, P. McGregor, S. McGregor, T. McGregor, J.
McGuckin, S. McHardy, L. McHugh, A. McIntosh, D. McIntosh, G. McIntosh, A. McIntyre, C. McIntyre, P. McIntyre, R.
McIntyre, C. McIver, T. McKague, B. McKay, C. McKay, G. McKay, J. McKay, K. McKay, L. McKay, S. McKay, T. McKay,
N. McKeachnie, D. McKee, S. McKee, B. McKendry, K. McKendry, N. McKendry, M. McKenna, P. McKenna, B.
McKenzie, K. McKenzie, M. McKenzie, C. McKersie, R. McKiel, C. McKim, S. McKinney, J. McKinnon, S. McKinnon, R.
McLachlen, M. McLane, C. McLaren, H. McLarty, K. McLaughlin, M. McLaughlin, R. McLaughlin, C. McLean, M.
McLean, N. McLean, R. McLean, W. Mclean, A. McLellan, C. McLellan, J. McLellan, T. McLellan, C. McLenaghan, 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, S. McMillan, C. McNabb, R. McNabb, R. McNair,
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Croden, M. Marchi, R. Marcichiw, H. Marcott, T. Marcotte, L. Marcucci, W. Margison, H. Maric, V. Maries, E. Marilao,
R. 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, T. Martin, S.
Martinella, D. Martinez, R. Martinez, Z. Martinez, D. Martinez Gomez, O. Martis, M. Martynuik, B. Martz, J. Maruniak,
8
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Pratt, S. Pratt, L. Praud, D. Prediger, M. Preece, A. Preston, J. Preston, R. Preteau, A. Price, J. Priest, D. Pringle, T. Prins,
M. Prior, M. Pritchard, S. Pritchett, K. Proceviat, G. Prochner, 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, G. Quan, L. Quan, A. Quarin, R.
Quartermain, K. Quaschnick, J. Quiba, D. Quigley, S. Quigley, J. Quinn, G. Quinton, R. Quiring, S. Qureshi, J. Raban
Mardelli, L. Rabbitt, B. Rabusic, D. Rach, D. Rachkewich, D. Raciborski, W. Raczynski, L. Radesh, K. Radke, R. Radke,
M. Radu, J. Rae, R. Rae, I. Rafiyev, G. Raghavan Nair, J. Raher, A. Rahmani, M. Rahmani, M. Rahmanian, P. Rai, J.
Rainnie, Y. Raisbeck, M. Raisinghani, M. Raistrick, A. Raivio, K. Raj, 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. Randell, M. Randell, J. Rankin, M. Rankin, D. Ranola, J. Ransom, S. Rapin, S. Rasch, T. Rasheed, C. Rasko, S.
Rasmussen, R. Raso, H. Rassi, W. Ratcliffe, S. Rathamone, R. Rathburn, J. Rattray, M. Rattray, H. Ratzlaff, A. Rau, L.
Ravoy, P. Rawlinson, D. Ray, K. Ray, S. Ray, J. Rayner, R. Rayner, M. Raza, B. Read, D. Read, G. Reader, W. Reashore,
R. Reaume, C. Reber, D. Reber, D. Rechenmacher, G. Redding, B. Redlich, C. Redmond, R. Redmond, 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, S. Reid, T. Reid, V. Reid, J. Reierson, T. Reilly, I. Reimer,
M. Reimer, M. Reinders, J. Reiniger, T. Reiniger, E. Reis, G. Reiter, H. Reithaug, M. Reithaug, D. Rejman, B. Relland, B.
Rellosa, T. Remington, W. Remmer, L. Rempel, P. Rempel, L. Ren, S. Ren, R. Renaud, G. Renfrew, T. Renkema, A. Rennie,
J. 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, D. Rice, 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, S. Richardson, T. Richardson, W. Richardson, D. Richter, W. Ricker, C. Ricketson, M.
Ricketts, C. Rico-Ospina, R. Riddell, J. Riddle, T. Rider, 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, E. Rivera, J.
Rivera, G. Rivest, A. Roach, J. Robak, A. Robert, C. Roberts, J. Roberts, M. Roberts, A. Robertson, D. Robertson, J.
Robertson, O. Robertson, S. Robertson, J. Robichaud, A. Robinson, B. 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, Y. Rohner, L. Rojas, M. Rojas- Bouchard, K. Roll, L. Romanchuk, C. Romano, D. Romanyshyn, M. Rombough, W.
Rombough, A. Romero, G. Romero, J. Romero, D. Rondeau, J. Roney, L. Rong, P. Ronnie, B. Ronspies, A. Rook, J.
Rooney, M. 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, R. Ross, S. Rosser, W. Rosson, J. Rostad, B. Rosychuk, R. Rosychuk, R. Roth, T. Roth,
T. Rotzien, J. Rotzoll, J. Rouleau, G. Rousselle, A. Routhier, D. Routhier, R. Routhier, R. Routley, A. Rowbottom, E. Rowe,
M. Rowe, S. Rowein, C. Rowland, A. Rowsell, F. Roxas, A. Roy, B. Roy, C. Roy, D. Roy, R. Roy, S. Roy, J. Rozema, Z. Ruda,
S. Ruddy, V. Ruddy, D. Rudkevitch, C. Rudolph, K. Rudra, L. Ruesga, M. Ruetz, A. Ruff, I. Rugg, M. Ruggles, M. Ruiz, T.
Rumbolt, J. Rumjan, D. Rumohr, S. Ruparell, T. Ruptash, N. Rusk, C. Russell, D. Russell, E. Russell, J. Russell, M.
Russell, S. Russell, T. Russell, D. Rutberg, J. Rutherford, M. Rutherford, S. Rutherford, D. Rutley, M. Rutter, H. Rutz, A.
Ryan, D. Ryan, R. Ryan, R. Rybachuk, 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, H. Sadiq, A. Sadr Mir Hosseini, E. Saenz de Santa Maria,
S. Sagrafena, A. Saha, S. Sahoo, A. Saini, P. Saini, J. Sair, K. Saiyed, D. Sakires, K. Sakowsky, R. Sakwattanapong, R.
Sala, A. Salakunov, A. Salazar, C. Salazar, D. Salazar, N. Salazar, E. Saleh, O. Saleh, M. Salehi, R. Salehipour, J. Sali,
C. Salim, C. Salisbury, E. Saller, M. Salman, E. Salmon, A. Salonga, G. Salt, S. Saltwater, B. Saluk, R. Salyn, A. Samadi,
N. Samer, A. Samoisette, S. Sampanthamoorthy, T. Samuelson, 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, D. Sargent, S. Sarkar, D. Sarmiento, A. Sartori, M. Sartoris, M. Sas, S. Sashuk, T. Sather, W.
Sather, M. Satra, E. Saucier, J. Saucier, G. Saunders, L. Saunders, R. Saunders, S. Saurette, C. Sauve, J. Savage, B.
Savla, D. Savoie, K. Savoie, L. Savoie, M. Savoie, C. Savostianik, A. Savtchenko, 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, T. Schatkoske, R. Schatschneider, C. Schaub, P. Schaub, A. Schaufele, J.
Schechtel, K. Scheiris, M. Schellenberg, L. Schelske, L. Scheper, C. Scherger, K. Scherger, C. Scheu, D. Schick, S.
Schick, L. Schiller, M. Schiller, R. Schlachter, G. Schlamp, D. Schledt, B. Schmaltz, L. Schmaus, J. Schmidt, K. Schmidt,
N. Schmidt, J. Schmitz, P. Schmuland, D. Schneider, G. Schneider, J. Schneider, P. Schneider, S. Schneider, B. Schnell,
C. Schnepf, A. Schnick, J. Schnieder, R. Schnieder, C. Schnurer, K. Schnurer, J. Schoengut, B. Schoepp, S. Schofield, R.
Schonheiter, L. Schonhoffer, R. Schrage, K. Schroeder, S. Schroeder, R. Schuh, N. Schuler, E. Schulte, S. Schultheiss, J.
Schultz, T. Schulz, K. Schumacher, D. Schwank, L. Schwetz, J. Schwindt, J. Scollard, C. Scott, D. Scott, E. Scott, H.
Scott, J. Scott, K. Scott, M. Scott, R. Scott, S. Scott, R. Scoville, M. Scragg, A. Scriba, R. Scrimshaw, C. Scullion, S.
Seabrook, M. Seafoot, G. Seal, G. Seaton, J. Sebastian, M. Sebastian, D. Seel, C. Seely, B. Seewitz, M. Seguin, J.
Segynola, S. Sehgal, L. Sehn, K. Seidel, P. Seipp, K. Seitz, 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, B. Senkow, 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, P. Sexton, A. Seyyed Najafi, G. Sgambaro, M. Sgambaro, R. Sgambaro, C.
Shackleton, 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, N. Sharp,
J. Sharpe, T. Sharpe, T. Shatosky, B. Shaw, D. Shaw, M. Shaw, R. Shaw, O. Shaykina, K. Shea, L. Shea, R. Shea, C.
Shears, D. Sheaves, L. Sheaves, W. Sheaves, A. Shehata, O. Sheikh, 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. Shott, G. Shrafnagle, M. Shukalov, K. Shukla, D. Shular, J. Shumate, T. Shymko, S.
Shymoniak, D. Shypitka, J. Shysh, I. Siddhanta, M. Siddiqui, M. Sideroff, M. Sidney, C. Sieben, D. Sieben, J. Sieben,
R. Sigsworth, W. Sikorski, L. Silas, T. Silbernagel, A. Sillito, B. Silue, E. Silva, I. Silva, L. Silva, H. Simani, C. Simard, D.
Simard, K. Simard, C. Simcock, G. Simmelink, J. Simmons, A. Simms, B. Simms, F. Simms, R. Simms, G. Simpkins, D.
Simpson, G. Simpson, J. 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, R. Skinner, M. Skipper, G. Skoczek, 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, K.
Smigelski, S. Smigelski, A. Smith, 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, L. Smollet, E. Smolyaninova, A. Smyl, K. Smyl, R. Smyl, K.
Snaden, T. Snell, G. Snider, J. Snider, J. Snow, K. Snow, R. Snow, W. Snow, D. Snowdon, 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, P. 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,
D. Spencer, S. Spencer, B. Spendiff, R. Sperling, J. Spetz, D. Spidell, K. Spiker, C. Sporidis, J. Springer, M. Sprinkle, A.
Spurrell, D. Spurrell, E. Spurrell, R. Spurrell, P. Spurvey, N. Squarek, L. Squire, M. Squires, R. Sran, E. Sribney, E. St
Pierre, F. St. Goddard, R. St. Martin, J. St. Onge, E. St. Pierre, L. St. Pierre, M. St. Pierre, B. St.Jean, R. St.Pierre, L.
Staats, A. Stacey, C. Stacey, J. Stacey, I. Stacey-Salmon, G. Stadnichuk, S. Stadnichuk, S. Stadnyk, K. Stagg, M.
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Staszewski, S. Stauth, A. Stavropoulos, K. Stawinski, E. Stearns, M. Stec, D. Steele, R. Steele, L. Steeves, G. Stefan,
S. Stefan, T. Stefansson, W. Steffen, M. Stein, J. Steinkey, S. Steinkey, A. Stella, R. Stelten, D. Stemmann, P. Stephen,
R. Stephens, T. Stephens, G. Stevens, J. Stevens, L. Stevens, N. Stevens, A. Stevens-Dicks, H. Stevenson, J.
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Stober, M. Stockes, M. Stockton, T. Stolz, R. Stoner, 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, R. Struski, J. Struthers, D. Strynadka, L.
Stuart, P. Stuart, G. Stuber, R. Stuckless, C. Study, J. Stuebing, G. Sturdy, J. Sturgeon, P. Sturgeon, D. Sturrock, A.
Styles, P. Su, 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, G. Surugiu, D. Sutherland, K. Sutherland, L.
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K. Walko, D. Wall, C. Wallace, E. Wallace, H. Wallace, K. Wallace, G. Wallin, N. Wallin, M. Wallis, V. Wallwork, T.
Walraven, A. Walsh, B. Walsh, P. Walsh, R. Walsh, S. Walsh, T. Walsh, L. Walter, A. Walters, C. Walters, K. Walters,
S. Walton, D. Wanchuk, C. Wang, H. Wang, J. Wang, L. Wang, R. Wang, S. Wang, T. Wang, W. Wang, X. Wang, B.
Wangler, D. Wannas, T. Warburton, D. Ward, E. Ward, K. Ward, W. Warholik, C. Wark, W. Warman, K. Warnica, F.
Warraich, G. Warren, J. Warren, R. Warren, P. Wassell, C. Wasylciw, L. Wasylciw, L. Watchorn, J. Watkins, 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, 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, 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, D. Wheating, L. Wheating, C. Wheaton, J. Wheaton, A. Wheeler,
S. Wheeler, C. Whelan, M. Whelan, R. Whelan, R. Whelan-Maloney, G. Whelen, S. Whelen, J. Whidden, B. White, D.
White, F. White, J. White, K. White, M. White, J. Whitehead, D. Whitehouse, S. Whiteley, A. Whiteside, C. Whitford,
H. Whitmore, M. Whittaker, A. Whitten, H. Whitten, R. Whyte, A. Wickins, C. Wickwire, A. Wiebe, 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, C. Wilkin, D. Wilkins, K. Wilkinson, P. Will, E. Willard, B. Willburn, B. Willcott, C.
Willey, B. Williams, C. Williams, D. Williams, G. Williams, L. Williams, M. Williams, N. Williams, S. Williams, W.
Williams, C. Williamson, D. Williamson, J. Williamson, M. Williamson, J. Willick, M. Willis, R. Willis, J. Williston, D.
Willms, S. Wills, C. Willson, D. Willson, A. Wilson, B. Wilson, C. Wilson, J. Wilson, K. Wilson, M. Wilson, R. Wilson,
W. Wilson, J. Wilton, S. Wilton, A. Wingert, J. Winia, B. Winiarz, R. Winnicky, J. Winquist, R. Winslow, J. Winsor, A.
Winter, G. Winters, R. Winters, G. Wirachowsky, J. Wirachowsky, T. Wire, P. Wiseman, I. Wishart, M. Witmer, Z. Witt,
B. Wittenborn, C. Wlad, K. Woidak, D. Woitas, T. Woitte, R. Wojtowicz, D. Wold, S. Wolf, J. Wolfe, 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, S. Woods, T. Woods, M. Woodske, J. Wooldridge, S. Woolfitt, R. Woolner, M. Workman, M.
Woroniuk, C. Worthman, H. Wossey Ogandaga Mbourou, B. Wright, C. Wright, L. Wright, R. Wright, S. Wright, G.
Wrinn, T. Wruth, B. Wu, J. Wu, M. Wu, Y. Wu, B. Wurzer, K. Wutzke, B. Wychopen, G. Wyndham, D. Wyshynski, L.
Wysocki, Y. Xia, Y. Xie, H. Xu, J. Xu, Q. Xu, Z. Xu, D. Yackel, K. Yakimowich, L. Yakiwchuk, C. Yang, J. Yang, M. Yanota,
H. Yare, A. Yaremko, K. Yaremko, J. Yaroslawsky, S. Yasin, B. Yeboue, B. Yee, G. Yee, R. Yee, C. Yeoman, D. Yep, P.
Yepes, 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, K. Yousaf, R. Yowney, E. Yu, M.
Yu, P. Yuan, C. Yuen, 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, 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, L. Zhao, T. Zhao, G. Zheng, S. Zheng, Z. Zheng,
H. Zhou, Q. Zhou, X. Zhou, L. Zhu, W. Zhu, E. Zhuromsky, P. Zia, S. Ziadeh, B. Ziegler, A. Zielke, D. Zilinski, E. Zilinski, E.
Zimmer, M. Zoladz, L. Zseder, G. Zubiak, A. Zubot, J. Zuk, N. Zukiwski, J. Zwolak
9
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 2016 Year-End Reserves
DETERMINATION OF RESERVES
For the year ended December 31, 2016, the Company retained Independent Qualified Reserves Evaluators (IQREs), Sproule
Associates Limited, Sproule International Limited and GLJ Petroleum Consultants Limited, 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 IQREs conducted the evaluation and review in accordance with the standards contained in the Canadian Oil and Gas
Evaluation 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 IQREs as to the Company’s reserves. All reserves values are Company Gross unless stated otherwise.
Corporate Total
■■
Canadian Natural’s 2016 performance has resulted in another year of excellent finding and development costs:
■● Finding, Development and Acquisition (“FD&A“) costs, excluding the change in Future Development Capital (“FDC“),
were $7.34/BOE for proved reserves and $9.34/BOE for proved plus probable reserves.
■● FD&A costs, including the change in FDC, were $3.72/BOE for proved reserves and $5.66/BOE for proved plus
probable reserves.
■■ Proved reserves additions and revisions replaced 2016 production by 187%. Proved plus probable reserves additions and
revisions replaced 2016 production by 147%.
■■ Recycle ratios of 1.9 times and 1.5 times were achieved for proved and proved plus probable reserves respectively,
excluding the change in FDC. Including the change in FDC, recycle ratios improve to 3.8 times and 2.5 times for proved
and proved plus probable reserves respectively.
■■ Proved reserves increased 4% to 5.969 billion BOE with reserve additions and revisions (including acquisitions and
dispositions) of 551 million BOE. Proved plus probable reserves increased 2% to 9.179 billion BOE with reserve additions
and revisions (including acquisitions and dispositions) of 433 million BOE.
■■ The proved BOE reserve life index is 21.0 years and the proved plus probable BOE reserve life index is 32.3 years.
■■ The net present value of future net revenues, before income tax, discounted at 10%, increased 6% to $69.3 billion for
proved reserves and increased 4% to $92.3 billion for proved plus probable reserves. Net present value of future net
revenues, before income tax, discounted at 10%, for proved developed producing reserves increased 26% to $46.7 billion
reflecting the completion of Horizon Phase 2B.
10
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. North America Exploration and Production
■■ Canadian Natural’s North America conventional and thermal assets delivered strong reserves results in 2016:
■● FD&A costs, excluding the change in FDC, were $2.91/BOE for proved reserves and $2.40/BOE for proved plus
probable reserves.
■● FD&A costs, including the change in FDC, were $5.97/BOE for proved reserves and $5.42/BOE for proved plus
probable reserves.
■■ On a proved reserves basis Canadian Natural replaced 158% of 2016 production. On a proved plus probable reserves
basis, 191% of 2016 production was replaced.
■■ Proved reserves increased 4% to 3.177 billion BOE. This is comprised of 2.086 billion bbl of crude oil, bitumen, and NGL
reserves and 6.545 Tcf of natural gas reserves.
■■ Proved plus probable reserves increased 4% to 5.162 billion BOE. This is comprised of 3.677 billion bbl of crude oil,
bitumen, and NGL reserves and 8.911 Tcf of natural gas reserves.
■■ Proved reserves additions and revisions, including acquisitions and dispositions, were 176 million bbl of crude oil, bitumen
and NGL and 1.101 Tcf of natural gas. Proved plus probable reserves additions and revisions, including acquisitions and
dispositions, were 242 million bbl of crude oil, bitumen and NGL and 1.167 Tcf of natural gas.
■■ The proved BOE reserve life index is 15.6 years and the proved plus probable BOE reserve life index is 25.4 years.
North America Oil Sands Mining and Upgrading
■■ Canadian Natural’s Horizon oil sands mining and upgrading delivered strong reserves results in 2016:
■● FD&A costs, excluding the change in FDC, were $13.87/bbl for proved reserves and $169.88/bbl for proved plus
probable reserves.
■● FD&A costs, including the change in FDC, were $5.92/bbl for proved reserves and $81.38/bbl for proved plus
probable reserves.
■■ Horizon proved Synthetic Crude Oil ("SCO") reserves increased 6% to 2.559 billion bbl. Proved plus probable SCO reserves
decreased 1% to 3.604 billion bbl.
■■ SCO proved developed producing reserves increased 11% to 2.544 billion bbl largely as a result of the completion of
Phase 2B.
■■ SCO reserves accounts for 43% of the Company’s proved BOE reserves and 39% of the proved plus probable
BOE reserves.
International Exploration and Production
■■ North Sea proved reserves decreased 15% to 141 million BOE due to 2016 production and the planned abandonment
of the Ninian North platform, commencing in 2017. North Sea proved plus probable reserves decreased 11% to
267 million BOE.
■■ Offshore Africa proved reserves decreased 3% to 92 million BOE largely due to 2016 production. Offshore Africa proved
plus probable reserves decreased 5% to 146 million BOE.
11
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Summary of Company Gross Reserves
As of December 31, 2016
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)
95
16
76
187
72
259
211
3
50
264
120
384
322
13
934
1,269
1,248
2,517
2,544
–
15
2,559
1,045
3,604
4,074
369
2,102
6,545
2,366
8,911
100
9
89
198
86
284
4,066
113
1,557
5,736
3,030
8,766
31
2
8
41
44
85
24
–
7
31
49
80
33
2
106
141
126
267
46
–
46
92
54
146
95
16
76
187
72
259
211
3
50
264
120
384
322
13
934
1,269
1,248
2,517
2,544
–
15
2,559
1,045
3,604
4,129
371
2,117
6,617
2,459
9,076
100
9
89
198
86
284
4,145
115
1,709
5,969
3,210
9,179
115
10
43
168
65
233
28
2
104
134
119
253
42
–
45
87
46
133
185
12
192
389
230
619
North America
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
North Sea
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
Offshore Africa
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
Total Company
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
12
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Summary of Company Net Reserves
As of December 31, 2016
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
104
9
38
151
55
206
28
2
104
134
118
252
39
–
35
74
34
108
171
11
177
359
207
566
80
14
65
159
59
218
164
3
41
208
83
291
257
11
767
1,035
976
2,011
2,186
–
9
2,195
864
3,059
3,682
331
1,832
5,845
2,043
7,888
78
7
76
161
69
230
3,483
99
1,301
4,883
2,447
7,330
31
2
8
41
44
85
17
–
6
23
32
55
33
2
106
141
125
266
42
–
36
78
39
117
80
14
65
159
59
218
164
3
41
208
83
291
257
11
767
1,035
976
2,011
2,186
–
9
2,195
864
3,059
3,730
333
1,846
5,909
2,119
8,028
78
7
76
161
69
230
3,558
101
1,443
5,102
2,611
7,713
13
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Reconciliation of Company Gross Reserves
As of December 31, 2016
Forecast Prices and Costs
PROVED
North America
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
North Sea
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
Offshore Africa
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
Total Company
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
14
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)
138
1
7
7
–
15
–
(5)
23
(18)
168
158
–
–
1
–
–
–
–
(16)
(9)
134
90
–
–
1
–
–
–
–
5
(9)
87
386
1
7
9
–
15
–
(5)
12
(36)
389
213
–
9
5
–
–
–
(3)
1
(38)
187
268
–
–
–
6
–
–
–
7
(17)
264
1,225
–
53
–
–
3
–
–
29
(41)
1,269
2,408
–
–
–
–
–
–
–
196
(45)
2,559
6,038
3
196
224
–
103
(4)
(102)
681
(594)
6,545
195
–
9
4
–
5
–
(1)
1
(15)
198
39
–
–
–
–
–
–
–
16
(14)
41
29
–
–
1
–
–
–
–
12
(11)
31
213
–
9
5
–
–
–
(3)
1
(38)
187
268
–
–
–
6
–
–
–
7
(17)
264
1,225
–
53
–
–
3
–
–
29
(41)
1,269
2,408
–
–
–
–
–
–
–
196
(45)
2,559
6,106
3
196
225
–
103
(4)
(102)
709
(619)
6,617
195
–
9
4
–
5
–
(1)
1
(15)
198
5,453
2
111
53
6
40
(1)
(26)
371
(273)
5,736
165
–
–
1
–
–
–
–
(14)
(11)
141
95
–
–
1
–
–
–
–
7
(11)
92
5,713
2
111
55
6
40
(1)
(26)
364
(295)
5,969
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Reconciliation of Company Gross Reserves
As of December 31, 2016
Forecast Prices and Costs
PROBABLE
North America
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
North Sea
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
Offshore Africa
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
Total Company
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
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)
54
–
8
3
–
4
–
(1)
(3)
–
65
126
–
–
1
–
–
–
–
(8)
–
119
52
–
–
–
–
–
–
–
(6)
–
46
232
–
8
4
–
4
–
(1)
(17)
–
230
81
–
4
2
–
–
–
–
(15)
–
72
120
–
–
–
1
–
–
–
(1)
–
120
1,182
–
29
1
–
1
–
–
35
–
1,248
1,225
–
–
–
–
–
–
–
(180)
–
1,045
2,300
2
106
64
–
22
(3)
(32)
(93)
–
2,366
88
1
8
2
–
1
–
(2)
(12)
–
86
57
–
–
–
–
–
–
–
(13)
–
44
45
–
–
–
–
–
–
–
4
–
49
81
–
4
2
–
–
–
–
(15)
–
72
120
–
–
–
1
–
–
–
(1)
–
120
1,182
–
29
1
–
1
–
–
35
–
1,248
1,225
–
–
–
–
–
–
–
(180)
–
1,045
2,402
2
106
64
–
22
(3)
(32)
(102)
–
2,459
88
1
8
2
–
1
–
(2)
(12)
–
86
3,134
1
66
19
1
10
–
(8)
(193)
–
3,030
135
–
–
1
–
–
–
–
(10)
–
126
59
–
–
–
–
–
–
–
(5)
–
54
3,328
1
66
20
1
10
–
(8)
(208)
–
3,210
15
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Reconciliation of Company Gross Reserves
As of December 31, 2016
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, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
North Sea
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
Offshore Africa
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
Total Company
December 31, 2015
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
16
192
1
15
10
–
19
–
(6)
20
(18)
233
284
–
–
2
–
–
–
–
(24)
(9)
253
142
–
–
1
–
–
–
–
(1)
(9)
133
618
1
15
13
–
19
–
(6)
(5)
(36)
619
294
–
13
7
–
–
–
(3)
(14)
(38)
259
388
–
–
–
7
–
–
–
6
(17)
384
2,407
–
82
1
–
4
–
–
64
(41)
2,517
3,633
–
–
–
–
–
–
–
16
(45)
3,604
8,338
5
302
288
–
125
(7)
(134)
588
(594)
8,911
283
1
17
6
–
6
–
(3)
(11)
(15)
284
96
–
–
–
–
–
–
–
3
(14)
85
74
–
–
1
–
–
–
–
16
(11)
80
294
–
13
7
–
–
–
(3)
(14)
(38)
259
388
–
–
–
7
–
–
–
6
(17)
384
2,407
–
82
1
–
4
–
–
64
(41)
2,517
3,633
–
–
–
–
–
–
–
16
(45)
3,604
8,508
5
302
289
–
125
(7)
(134)
607
(619)
9,076
283
1
17
6
–
6
–
(3)
(11)
(15)
284
8,587
3
177
72
7
50
(1)
(34)
178
(273)
8,766
300
–
–
2
–
–
–
–
(24)
(11)
267
154
–
–
1
–
–
–
–
2
(11)
146
9,041
3
177
75
7
50
(1)
(34)
156
(295)
9,179
Canadian Natural 2016 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)
$
$
$
$
$
$
$
$
$
2017
2018
2019
2020
2021
thereafter
55.00 $
65.00 $
70.00 $
71.40 $
72.83 $
2.00%
53.12 $
61.85 $
64.94 $
66.93 $
68.27 $
2.00%
65.58 $
74.51 $
78.24 $
80.64 $
82.25 $
2.00%
64.58 $
73.51 $
77.24 $
79.64 $
81.25 $
2.00%
67.95 $
75.61 $
78.82 $
80.47 $
82.15 $
2.00%
55.00 $
65.00 $
70.00 $
71.40 $
72.83 $
2.00%
3.44 $
3.04 $
3.50 $
3.27 $
2.87 $
3.50 $
3.22 $
2.82 $
3.50 $
3.91 $
3.51 $
4.00 $
4.00 $
2.00%
3.60 $
2.00%
4.08 $
2.00%
A foreign exchange rate of 0.7800 US$/C$ for 2017, 0.8200 US$/C$ for 2018, and 0.8500 US$/C$ after 2018 was used in the 2016 evaluation.
(5) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may
be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices,
the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
(6) Metrics included herein are commonly used in the oil and natural gas industry and are determined by Canadian Natural as set out in the notes below. These
metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies and may be misleading when
making comparisons. Management uses these metrics to evaluate Canadian Natural’s performance over time. However, such measures are not reliable
indicators of Canadian Natural’s future performance and future performance may vary.
(7) Reserve additions and revisions are comprised of all categories of Company Gross reserve changes, exclusive of production.
(8) Production replacement or 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.
(9) Reserve Life Index is based on the amount for the relevant reserve category divided by the 2017 proved developed producing production forecast prepared
by the Independent Qualified Reserve Evaluators.
(10) Finding, Development and Acquisition ("FD&A") costs are calculated by dividing the sum of total exploration, development and acquisition capital costs
incurred in 2016 by the sum of total additions and revisions for the relevant reserve category.
(11) 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 2016 and net change in FDC from December 31, 2015 to December 31, 2016 by the sum of total additions and revisions for the
relevant reserve category. FDC excludes all abandonment and reclamation costs.
(12) Recycle Ratio is the operating netback (in $/BOE for the year) divided by the FD&A (in $/BOE). Operating netback is production revenues, excluding realized
gains and losses on commodity hedging, less royalties, transportation and production expenses, calculated on a per BOE basis.
17
Canadian Natural 2016 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 2017 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 and assets, including the announced acquisition of a significant interest in the Athabasca
Oil Sands Project and certain other producing and non-producing oil and gas properties; 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
18
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one
or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results
may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a
particular forward-looking statement is not determinable with certainty as such 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.
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 (loss) from operations, funds flow from operations (formerly referred to as 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 (loss) and cash flows from operating activities, as determined in accordance with IFRS, as an indication
of the Company’s performance. The non-GAAP measures adjusted net earnings (loss) from operations and funds flow from
operations are reconciled to net earnings (loss), as determined in accordance with IFRS, in the “Net Earnings (Loss) and Funds
Flow from Operations” section of this MD&A. The non-GAAP measure funds flow from operations is also reconciled to cash
flows from operating activities in this section. 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 audited
consolidated financial statements and related notes for the year ended December 31, 2016.
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 2016 financial results compared to 2015 and 2014,
unless otherwise indicated. In addition, this MD&A details the Company's targeted capital program for 2017. Additional
information relating to the Company, including its quarterly MD&A for the year and three months ended December 31, 2016, its
Annual Information Form for the year ended December 31, 2016, and its audited consolidated financial statements for the year
ended December 31, 2016 is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. This MD&A is dated
March 15, 2017.
19
Canadian Natural 2016 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
a naturally occurring solid or semi-solid
hydrocarbon, consisting mainly of heavier
hydrocarbons that are too heavy or thick to
flow at reservoir conditions, and recoverable
at economic rates using thermal in situ
recovery methods
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
International Accounting Standards Board
IFRS
LIBOR
Mbbl
Mbbl/d
MBOE
International Financial Reporting Standards
London Interbank Offered Rate
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
thousand 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
20
Canadian Natural 2016 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. Additionally, the Company’s risk management hedging
program reduces the risk of volatility in commodity prices and foreign exchange rates and supports the Company’s cash flow
for its capital expenditure programs.
Strategic accretive acquisitions are a key component of the Company’s strategy. The Company has used a combination
of internally generated cash flows and debt financing to selectively acquire properties generating future cash flows in its
core areas.
21
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Net Earnings (Loss) and Funds Flow from Operations
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Product sales
Net earnings (loss)
Per common share – basic
– diluted
Adjusted net earnings (loss) from operations (1)
Per common share – basic
– diluted
Funds flow from operations (2)
Per common share – basic
– diluted
Dividends declared per common share (3)
Total assets
Total long-term liabilities
Net capital expenditures
2016
2015
2014
11,098 $
13,167 $
21,301
(204) $
(637) $
3,929
(0.19) $
(0.58) $
(0.19) $
(0.58) $
3.60
3.58
(669) $
(0.61) $
(0.61) $
263 $
3,811
0.24 $
0.24 $
3.49
3.47
4,293 $
5,785 $
9,587
3.90 $
3.89 $
0.94 $
5.29 $
5.28 $
0.92 $
8.78
8.74
0.90
58,648 $
59,275 $
60,200
27,289 $
27,299 $
26,167
3,794 $
3,853 $
11,744
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(1) Adjusted net earnings (loss) from operations is a non-GAAP measure that represents net earnings (loss) as presented in the Company's consolidated
Statements of Earnings (Loss), adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings
(loss) from operations. The reconciliation “Adjusted Net Earnings (Loss) 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 (loss) from operations may not be comparable to similar measures
presented by other companies.
(2) Funds flow from operations is a non-GAAP measure that represents net earnings (loss) as presented in the Company's consolidated Statements of Earnings
(Loss), adjusted for certain non-cash items and current income tax on disposition of properties. The Company evaluates its performance based on funds flow
from operations. The Company considers funds 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 “Funds Flow from Operations, as Reconciled to Net Earnings
(Loss)” presented in this MD&A, includes certain non-cash items that are disclosed in the financial results as presented in the Company's consolidated
Statements of Cash Flows. Funds flow from operations may not be comparable to similar measures presented by other companies.
Funds flow from operations can also be derived by adjusting the GAAP measure Cash Flows from Operating Activities presented in the Company's
consolidated Statements of Cash Flows for the net change in non-cash working capital, and abandonment and other expenditures. Accordingly, the Company
has provided a second reconciliation, ”Funds Flow from Operations, as Reconciled to Cash Flows from Operating Activities” in this MD&A.
(3) On March 1, 2017, the Board of Directors approved an increase in the quarterly dividend to $0.275 per common share, beginning with the dividend payable
on April 1, 2017. On November 2, 2016, the Board of Directors approved an increase in the quarterly dividend to $0.25 per common share, beginning with
the dividend payable on January 1, 2017. 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 $0.225 per common share, beginning with the dividend payable on
April 1, 2014.
22
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Adjusted Net Earnings (Loss) from Operations
($ millions)
Net earnings (loss)
Share-based compensation, net of tax (1)
Unrealized risk management loss (gain), net of tax (2)
Unrealized foreign exchange (gain) loss, net of tax (3)
Realized foreign exchange loss on repayment of US dollar debt securities, net of tax (4)
(Gain) loss from investments, net of tax (5) (6)
Gain on disposition of properties and corporate acquisitions and dispositions,
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
2016
2015
$
(204) $
(637) $
355
21
(93)
–
(299)
(241)
13
(46)
275
858
–
55
(663)
70
tax liabilities (9)
(221)
351
2014
3,929
66
(339)
256
36
–
(137)
–
–
Adjusted net earnings (loss) from operations
$
(669) $
263 $
3,811
(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 (loss). 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.
(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 (gain) loss from investments is the Company's pro rata share of the Redwater Partnership's accounting (gain) loss.
(6) The Company’s investments in PrairieSky Royalty Ltd. (“PrairieSky”) and Inter Pipeline Ltd. (“Inter Pipeline“) have been accounted for at fair value through
profit and loss and are remeasured each period with changes in fair value recognized in net earnings (loss).
(7) During 2016, the Company recorded a pre and after-tax gain of $218 million on the disposition of Midstream property, plant and equipment. Additionally,
the Company recorded a pre-tax gain of $32 million ($23 million after-tax) on the disposition of certain exploration and evaluation assets. 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.
(8) In connection with the Company's notice of withdrawal from Block CI-12 in Côte d'Ivoire, Offshore Africa in 2016, the Company derecognized $18 million
($13 million after-tax) of exploration and evaluation assets through depletion, depreciation and amortization expense. 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. In 2016, the UK government enacted legislation to reduce the supplementary
charge on oil and gas profits from 20% to 10% effective January 1, 2016, resulting in a decrease in the Company's deferred corporate income tax liability
of $107 million. In addition, the UK government also enacted tax rate reductions relating to Petroleum Revenue Tax (“PRT”), resulting in a decrease in the
Company’s net deferred income tax liability of $114 million. 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 corporate income tax liability
was increased by $579 million. In addition, 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 net deferred income tax liability
of $228 million.
Funds Flow from Operations, as Reconciled to Net Earnings (Loss) (1)
($ 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 (gain) loss
Realized foreign exchange loss on repayment of US dollar debt securities
(Gain) loss from investments
Deferred income tax (recovery) expense
Gain on disposition of properties and corporate acquisitions and dispositions
Current income tax on disposition of properties
Funds flow from operations
(1) Funds flow from operations was previously referred to as cash flow from operations.
2016
2015
$
(204) $
(637) $
4,858
355
142
25
(93)
–
(299)
(241)
(250)
–
5,483
(46)
173
374
858
–
55
231
(739)
33
2014
3,929
4,880
66
193
(451)
256
36
8
807
(137)
–
$
4,293 $
5,785 $
9,587
23
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Funds Flow from Operations, as Reconciled to Cash Flows from Operating Activities
($ millions)
Cash flows from operating activities
Net change in non-cash working capital
Abandonment expenditures
Other
Funds flow from operations
2016
2015
$
3,452 $
5,632 $
542
267
32
(239)
370
22
2014
8,459
744
346
38
$
4,293 $
5,785 $
9,587
Summary Of Consolidated Net Earnings (Loss) and Funds Flow
from Operations
For 2016, the Company reported a net loss of $204 million compared with a net loss of $637 million for 2015 (2014 –
$3,929 million net earnings). The net loss for 2016 included net after-tax income of $465 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, (gain) loss from investments, gain on disposition of
properties and corporate acquisitions and dispositions, derecognition of exploration and evaluation assets and the impact
of statutory tax rate and other legislative changes on deferred income tax liabilities (2015 – $900 million after-tax expenses;
2014 – $118 million after-tax income). Excluding these items, the adjusted net loss from operations for 2016 was $669 million
compared with adjusted net earnings of $263 million for 2015 (2014 – $3,811 million).
The decrease in adjusted net earnings (loss) for 2016 from 2015 was primarily due to:
■■
■■
■■
■■
lower crude oil and NGLs sales volumes in the North America segment;
lower crude oil and NGLs netbacks in the North America segment;
lower natural gas netbacks in the Exploration and Production segments; and
lower realized risk management gains;
partially offset by:
■■ higher crude oil sales volumes in the Offshore Africa segment; and
■■
the weakening of the Canadian 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.
Funds flow from operations for 2016 decreased to $4,293 million ($3.90 per common share) from $5,785 million for 2015
($5.29 per common share) (2014 – $9,587 million; $8.78 per common share). The decrease in funds flow from operations for
2016 from 2015 was primarily due to the factors noted above relating to the decrease in adjusted net earnings (loss), together
with the impact of lower depletion, depreciation and amortization and cash taxes.
In the Company’s Exploration and Production activities, the 2016 average sales price per bbl of crude oil and NGLs decreased
10% to average $36.93 per bbl from $41.13 per bbl in 2015 (2014 – $77.04 per bbl), and the 2016 average natural gas price
decreased 27% to average $2.32 per Mcf from $3.16 per Mcf in 2015 (2014 – $4.83 per Mcf). In the Oil Sands Mining and
Upgrading segment, the Company’s 2016 SCO sales price averaged $58.59 per bbl, compared with $61.39 per bbl in 2015
(2014 – $100.27 per bbl).
Total production of crude oil and NGLs before royalties decreased 7% to average 523,873 bbl/d from 564,188 bbl/d in 2015
(2014 – 531,194 bbl/d). The decrease in crude oil and NGLs production from 2015 was primarily due to lower drilling activity
and natural field declines in North America, partially offset by increased production in the International segments.
Total natural gas production before royalties decreased 2% to average 1,691 MMcf/d from 1,726 MMcf/d in 2015 (2014 –
1,555 MMcf/d). The decrease in natural gas production from 2015 primarily reflected lower production in North America due
to the continued impact of the shut in of a third party processing facility, with constraints continuing past original target dates
set by the third party, as well as due to third party pipeline transportation restrictions.
Total crude oil and NGLs and natural gas production volumes before royalties decreased 5% to average 805,782 BOE/d from
851,901 BOE/d in 2015 (2014 – 790,410 BOE/d).
24
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company’s quarterly results for the eight most recently completed quarters:
($ millions, except per common share amounts)
2016
Product sales
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
($ millions, except per common share amounts)
2015
Product sales
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
Total
Dec 31
Sep 30
Jun 30
Mar 31
11,098 $
3,672 $
2,477 $
2,686 $
2,263
(204) $
566 $
(326) $
(339) $
(105)
(0.19) $
(0.19) $
0.51 $
0.51 $
(0.29) $
(0.31) $
(0.29) $
(0.31) $
(0.10)
(0.10)
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) $
(0.10) $
(0.37) $
(0.37) $
(0.23)
(0.23)
$
$
$
$
$
$
$
$
Volatility in the quarterly net earnings (loss) over the eight most recently completed quarters was primarily due to:
■■ Crude oil pricing – The impact of shale oil production in North America, fluctuating global supply/demand including crude
oil production levels from the Organization of the Petroleum Exporting Countries (“OPEC”) and its impact on world supply,
the impact of geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential from
the West Texas Intermediate reference location at Cushing, Oklahoma (“WTI“) in North America and the impact of the
differential between WTI and Dated Brent (“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 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, the reduction
in the Company’s drilling program in North America, the impact and timing of acquisitions, the impact of turnarounds at
Horizon, and the impact of the drilling program in Côte d’Ivoire in Offshore Africa. Sales volumes also reflected fluctuations
due to timing of liftings and maintenance activities in the International segments.
■■ Natural gas sales volumes – Fluctuations in production due to the Company’s allocation of capital to higher return crude
oil projects, natural decline rates, shut-in production due to third party pipeline restrictions and related pricing impacts,
an outage at a third party processing facility, shut-in production due to low commodity prices, 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, turnarounds at Horizon and maintenance activities in the International segments.
■■ Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes including the impact and timing
of acquisitions and dispositions, 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 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 predominantly on US dollar denominated
benchmarks. Fluctuations in realized and unrealized foreign exchange gains and losses were also recorded with respect
to US dollar denominated debt, partially offset by the impact of cross currency swap hedges.
■■
Income tax expense – Fluctuations in income tax expense include statutory tax rate and other legislative changes
substantively enacted in the various periods.
■■ Gains on disposition of properties and investments – Fluctuations due to the recognition of gains on disposition of
properties in the various periods and fair value changes in the investment in PrairieSky and Inter Pipeline.
25
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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$)
2016
2015
43.37 $
48.76 $
43.96 $
52.40 $
13.91 $
13.51 $
32%
28%
43.94 $
48.59 $
42.51 $
47.34 $
2.45 $
1.98 $
2.67 $
2.62 $
2014
92.92
98.85
19.41
21%
91.35
92.84
4.37
4.19
0.7548 $
0.7820 $
0.9054
0.7448 $
0.7225 $
0.8620
$
$
$
$
$
$
$
$
$
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. During 2016, realized
prices continued to be supported by the weaker Canadian dollar, as the Canadian dollar sales price the Company received
for its crude oil and natural gas sales is based on US dollar denominated benchmarks. The average value of the Canadian
dollar in relation to the US dollar fluctuated throughout 2016, with a high of approximately US$0.80 in April 2016 and a low of
approximately US$0.69 in January 2016.
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged
US$43.37 per bbl for 2016, a decrease of 11% from US$48.76 per bbl for 2015 (2014 – $92.92 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$43.96 per bbl for
2016, a decrease of 16% from US$52.40 per bbl for 2015 (2014 – $98.85 per bbl).
WTI and Brent pricing for 2016 continued to reflect volatility in supply and demand factors and geopolitical events. The OPEC
decision in November 2016 to implement a production cut effective January 1, 2017 followed by additional production cuts by
certain non-OPEC countries, contributed to an increase in 2016 fourth quarter pricing.
The WCS Heavy Differential averaged 32% for 2016, compared with 28% for 2015 (2014 – 21%). Fluctuations in the WCS
Heavy Differential reflected seasonal demand, changes in transportation logistics, and refinery utilization and shutdowns.
The SCO price averaged US$43.94 per bbl for 2016, a decrease of 10% from US$48.59 per bbl for 2015 (2014 – $91.35 per bbl).
The fluctuations in SCO pricing for 2016 from the comparable period were primarily due to changes in WTI benchmark pricing.
NYMEX natural gas prices averaged US$2.45 per MMBtu for 2016, a decrease of 8% from US$2.67 per MMBtu for 2015
(2014 – $4.37 per MMBtu). AECO natural gas prices averaged $1.98 per GJ for 2016, a decrease of 24% from $2.62 per GJ
for 2015 (2014 – $4.19 per GJ).
The decrease in natural gas prices for 2016 compared with 2015 was primarily due to warmer than normal winter temperatures
in the first quarter of 2016. US natural gas inventories were at near record high levels at the end of the 2015/2016 winter
season, which resulted in weaker prices during storage injection.
26
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Analysis of Changes in Product Sales
($ millions)
North America
Changes due to
Changes due to
2014 Volumes
Prices
Other
2015 Volumes
Prices
Other
2016
Crude oil and NGLs
$ 13,332 $
402 $ (6,378) $
96 $ 7,452 $
(937) $
(690) $
108 $ 5,933
1,770
9,222
(40)
(977)
(454)
(1,144)
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
2,631
15,963
682
19
701
410
93
503
14,424
2,743
17,167
4,095
120
(81)
234
636
137
73
210
185
24
209
724
331
1,055
(1,095)
(7,473)
(317)
34
(283)
(214)
(24)
(238)
(6,909)
(1,085)
(7,994)
435
(1,749)
–
–
–
–
–
96
10
–
10
8
–
8
114
–
114
(17)
16
512
126
638
389
93
482
8,353
1,989
10,342
2,764
136
6
(75)
–
108
(10)
–
(10)
(2)
–
(2)
96
–
96
2
(22)
1,276
7,209
478
92
570
532
71
603
6,943
1,439
8,382
2,657
114
20
(55)
54
9
63
224
17
241
(659)
(14)
(673)
17
–
–
(78)
(43)
(121)
(79)
(39)
(118)
(847)
(536)
(1,383)
(126)
–
–
$ 21,301 $ 1,490 $ (9,743) $
119 $ 13,167 $
(656) $ (1,509) $
96 $ 11,098
(1) Eliminates internal transportation and electricity charges.
Product sales decreased 16% to $11,098 million for 2016 from $13,167 million for 2015 (2014 – $21,301 million).
The decrease was primarily due to lower crude oil and NGLs sales volumes in North America and lower realized prices in all
business segments.
For 2016, 11% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America
(2015 – 9%; 2014 – 6%). North Sea accounted for 5% of crude oil and NGLs and natural gas product sales for 2016 (2015 – 5%;
2014 – 3%), and Offshore Africa accounted for 6% of crude oil and NGLs and natural gas product sales for 2016 (2015 – 4%;
2014 – 3%).
27
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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
2016
2015
2014
350,958
123,265
23,554
26,096
399,982
122,911
22,216
19,079
390,814
110,571
17,380
12,429
523,873
564,188
531,194
1,622
1,663
1,527
38
31
36
27
7
21
1,691
1,726
1,555
805,782
851,901
790,410
17%
6%
13%
14%
15%
35%
85%
15%
16%
6%
15%
15%
14%
34%
82%
18%
15%
6%
18%
14%
14%
33%
85%
15%
(1) 2016 SCO production before royalties excludes 1,966 bbl/d of SCO consumed internally as diesel (2015 – 2,122 bbl/d, 2014 – 545 bbl/d).
(2) Net of blending costs and excluding risk management activities.
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)
2016
2015
2014
311,059
122,258
23,497
24,995
350,451
121,208
22,164
18,209
318,291
104,095
17,313
11,500
481,809
512,032
451,199
1,559
1,606
1,407
38
30
36
25
7
18
1,627
1,667
1,432
752,974
789,799
689,893
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 2016 production averaged 805,782 BOE/d, a 5% decrease from 851,901 BOE/d in 2015 (2014 – 790,410 BOE/d).
Total production of crude oil and NGLs for 2016 decreased 7% to 523,873 bbl/d from 564,188 bbl/d for 2015
(2014 – 531,194 bbl/d). The decrease in crude oil and NGLs production from 2015 was primarily due to lower drilling
activity and natural field declines in North America, partially offset by increased production in the International segments.
Crude oil and NGLs production for 2016 was within the Company’s previously issued guidance of 514,000 to 563,000 bbl/d.
28
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Natural gas production continued to represent the Company's largest product offering, accounting for 35% of the
Company's total production in 2016 on a BOE basis. Natural gas production for 2016 decreased 2% to 1,691 MMcf/d from
1,726 MMcf/d for 2015 (2014 – 1,555 MMcf/d). Natural gas production for 2016 decreased from 2015 by approximately
70 MMcf/d as a result of flood damage to a third party gathering system and facility in June 2016, together with the delay in the
repair and reinstatement of full processing capacity. North America natural gas production volumes were also impacted by
31 MMcf/d due to third party transportation restrictions. The Company's sales volumes at the third party facility have
increased subsequent to year end. Annual 2016 natural gas production was below the Company's previously issued guidance
of 1,705 to 1,735 MMcf/d of natural gas.
NORTH AMERICA – EXPLORATION AND PRODUCTION
North America crude oil and NGLs production for 2016 decreased 12% to average 350,958 bbl/d from 399,982 bbl/d for
2015 (2014 – 390,814 bbl/d). The decrease in production from 2015 primarily reflected lower drilling activity, natural field
declines and the cyclic nature of thermal oil production at Primrose.
Natural gas production for 2016 decreased 2% to average 1,622 MMcf/d from 1,663 MMcf/d for 2015 (2014 –
1,527 MMcf/d). Natural gas production for 2016 decreased from 2015 by approximately 70 MMcf/d as a result
of flood damage to a third party gathering system and facility in June 2016, together with the delay in the
repair and reinstatement of full processing capacity. North America natural gas production volumes were also impacted by
31 MMcf/d due to third party transportation restrictions. The Company's sales volumes at the third party facility have
increased subsequent to year end
NORTH AMERICA – OIL SANDS MINING AND UPGRADING
SCO production for 2016 of 123,265 bbl/d was comparable with 2015 production of 122,911 bbl/d (2014 – 110,571 bbl/d).
Production in 2016 reflected new Phase 2B SCO volumes following the completion of the planned major turnaround in the
third quarter of 2016.
NORTH SEA
North Sea crude oil production for 2016 increased 6% to 23,554 bbl/d from 22,216 bbl/d for 2015 (2014 – 17,380 bbl/d). The
increase in production from 2015 was due to successful production optimization, more than offsetting natural field declines.
OFFSHORE AFRICA
Offshore Africa crude oil production for 2016 increased 37% to 26,096 bbl/d from 19,079 bbl/d for 2015 (2014 – 12,429 bbl/d).
Production volumes increased from 2015 reflecting the impact of additional wells coming on stream at the Espoir and Baobab
fields during 2015 and 2016, partially offset by natural field declines and planned and unplanned downtime.
CORPORATE PRODUCTION GUIDANCE FOR 2017
The Company targets production levels in 2017 to average between 550,000 bbl/d and 590,000 bbl/d of crude oil and NGLs
and between 1,700 MMcf/d and 1,760 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
2016
2015
987,316
835,806
1,126,999
1,271,170
2,114,315
2,106,976
2014
368,808
461,997
830,805
29
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Operating Highlights – Exploration and Production
2016
2015
2014
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.
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)
$
$
$
$
$
36.93 $
41.13 $
2.61
34.32
3.40
14.10
2.60
38.53
4.30
15.74
16.82 $
18.49 $
2.32 $
3.16 $
0.33
1.99
0.09
1.18
0.38
2.78
0.10
1.34
0.72 $
1.34 $
77.04
2.41
74.63
12.99
18.25
43.39
4.83
0.27
4.56
0.38
1.48
2.70
27.58 $
32.60 $
58.48
2.44
25.14
2.21
11.18
2.56
30.04
2.85
12.70
$
11.75 $
14.49 $
2.18
56.30
8.90
14.67
32.73
2016
2015
2014
$
$
$
$
$
$
$
$
$
34.31 $
38.96 $
75.09
55.91 $
65.13 $
106.63
54.96 $
63.13 $
36.93 $
41.13 $
2.15 $
6.62 $
6.13 $
2.32 $
2.91 $
9.66 $
9.53 $
3.16 $
97.81
77.04
4.72
7.07
11.98
4.83
27.58 $
32.60 $
58.48
(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 10% to average $36.93 per bbl for 2016 from $41.13 per bbl for 2015
(2014 – $77.04 per bbl), primarily due to lower WTI and Brent benchmark pricing.
The Company’s realized natural gas price decreased 27% to average $2.32 per Mcf for 2016 from $3.16 per Mcf for 2015
(2014 – $4.83 per Mcf). The decrease in 2016 was primarily due to warmer than normal winter temperatures in North America
in the first quarter of 2016. US natural gas inventories were at near record high levels at the end of the 2015/2016 winter
season, which resulted in weaker prices during storage injection.
NORTH AMERICA
North America realized crude oil prices decreased 12% to average $34.31 per bbl for 2016 from $38.96 per bbl for 2015
(2014 – $75.09 per bbl), primarily due to lower WTI benchmark pricing.
30
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. North America realized natural gas prices decreased 26% to average $2.15 per Mcf for 2016 from $2.91 per Mcf for 2015
(2014 – $4.72 per Mcf). The decrease was primarily due to warmer than normal winter temperatures in the first quarter of
2016. US natural gas inventories were at near record high levels at the end of the 2015/2016 winter season, which resulted in
weaker prices during storage injection.
The Company continues to focus on its crude oil marketing strategy including a blending strategy that expands markets within
current pipeline infrastructure, supporting pipeline projects that will provide capacity to transport crude oil to new markets,
and working with refiners to add incremental heavy crude oil and bitumen (thermal oil) conversion capacity. During 2016, the
Company contributed approximately 207,000 bbl/d of heavy crude oil blends to the WCS stream.
The Company has entered into a 20 year transportation agreement to ship 80,000 bbl/d of crude oil on the
proposed Energy East pipeline originating at Hardisty, Alberta with a delivery point in Saint John, New Brunswick.
This pipeline is subject to regulatory approval. The Company has also entered into a 20 year transportation agreement to
ship 75,000 bbl/d of crude oil on the proposed Kinder Morgan Trans Mountain Expansion from Edmonton, Alberta to
Vancouver, British Columbia. This pipeline has obtained federal regulatory approval and is awaiting final permits.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
(Yearly average)
Wellhead Price (1) (2)
Light and medium crude oil and NGLs ($/bbl)
Pelican Lake heavy crude oil ($/bbl)
Primary heavy crude oil ($/bbl)
Bitumen (thermal oil) ($/bbl)
Natural gas ($/Mcf)
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
2016
2015
2014
$
$
$
$
$
37.72 $
41.88 $
36.03 $
34.73 $
30.47 $
41.09 $
40.71 $
34.37 $
2.15 $
2.91 $
76.94
77.58
76.29
70.78
4.72
NORTH SEA
North Sea realized crude oil prices decreased 14% to average $55.91 per bbl for 2016 from $65.13 per bbl for 2015 (2014 –
$106.63 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 2016 primarily reflected prevailing Brent benchmark pricing at the time of liftings.
OFFSHORE AFRICA
Offshore Africa realized crude oil prices decreased 13% to average $54.96 per bbl for 2016 from $63.13 per bbl for 2015 (2014 –
$97.81 per bbl). Realized crude oil prices per bbl in any particular year are dependent on the terms of the various sales contracts,
the frequency and timing of liftings of each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting.
The decrease in realized crude oil prices in 2016 primarily reflected prevailing Brent benchmark pricing at the time of liftings.
Royalties – Exploration and Production
Crude oil and NGLs ($/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.
2016
2015
2014
$
$
$
$
$
$
$
$
3.69 $
0.13 $
2.31 $
3.40 $
0.08 $
0.28 $
0.09 $
2.21 $
4.57 $
13.74
0.14 $
2.87 $
0.33
6.83
4.30 $
12.99
0.09 $
0.46 $
0.10 $
2.85 $
0.36
1.74
0.38
8.90
31
Canadian Natural 2016 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“).
North America crude oil and natural gas royalties for 2016 and the comparable periods reflected movements in benchmark
commodity prices. North America crude oil royalties also reflected fluctuations in the WCS Heavy Differential.
Crude oil and NGLs royalties averaged approximately 12% of product sales for 2016 compared with 13% of product sales for
2015 (2014 – 19%). The decrease in royalties for 2016 from 2015 was primarily due to lower realized crude oil prices during
2016. North America crude oil and NGLs royalties per bbl are anticipated to average 13% to 14% of product sales for 2017.
Natural gas royalties averaged approximately 4% of product sales for 2016 compared with 4% of product sales for 2015
(2014 – 8%). North America natural gas royalties are anticipated to average 6% to 8% of product sales for 2017.
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 4% for 2016, compared with 5% of product sales for
2015 (2014 – 8%). Royalties as a percentage of product sales reflected the timing of liftings and the status of payout in the
various fields. Offshore Africa royalty rates are anticipated to average 7% to 9% of product sales for 2017.
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)
2016
2015
2014
$
$
$
$
$
$
$
$
$
11.89 $
12.51 $
42.47 $
63.67 $
18.48 $
33.32 $
14.10 $
15.74 $
1.12 $
3.09 $
1.79 $
1.18 $
1.27 $
4.41 $
1.76 $
1.34 $
14.98
74.04
43.97
18.25
1.42
9.10
3.22
1.48
11.18 $
12.70 $
14.67
(1) Amounts expressed on a per unit basis are based on sales volumes.
NORTH AMERICA
North America crude oil and NGLs production expense for 2016 decreased 5% to $11.89 per bbl from $12.51 per bbl for 2015
(2014 – $14.98 per bbl). The Company continues to successfully manage its production costs and achieve efficiencies across
the asset base, through focused cost and production optimization, together with lower industry service costs. As a result,
crude oil and NGL production expenses for 2016 were near the midpoint of annual guidance of $11.25 to $12.25 per bbl. North
America crude oil and NGLs production expense is anticipated to average $11.50 to $13.50 per bbl for 2017.
North America natural gas production expense for 2016 decreased 12% to $1.12 per Mcf from $1.27 per Mcf for 2015 (2014
– $1.42 per Mcf). Consistent with crude oil and NGLs production costs, the Company continues to successfully reduce its
natural gas production costs and achieve efficiencies across the asset base, through focused cost and production optimization,
together with lower industry service costs. As a result, natural gas production expenses for 2016 were below the midpoint of
annual guidance of $1.05 to $1.25 per Mcf. North America natural gas production expense guidance is anticipated to average
$1.00 to $1.20 per Mcf for 2017.
NORTH SEA
North Sea crude oil production expense for 2016 decreased 33% to $42.47 per bbl from $63.67 per bbl for 2015 (2014 –
$74.04 per bbl). The Company continues to successfully reduce its production costs and achieve efficiencies through focused
cost and production optimization, together with lower industry service costs. As a result, crude oil and NGLs production
expenses for 2016 were below the midpoint of annual guidance of $40.50 to $46.50 per bbl. The decrease in production
expense in 2016 compared with the prior year also reflected fluctuations in the Canadian dollar and the weakening of the UK
pound sterling. North Sea crude oil production expense guidance is anticipated to average $33.00 to $36.00 per bbl for 2017.
32
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. OFFSHORE AFRICA
Offshore Africa oil production expense for 2016 decreased 45% to $18.48 per bbl from $33.32 per bbl for 2015 (2014 –
$43.97 per bbl). The decrease in production expense for 2016 from 2015 was primarily due to the timing of liftings from various
fields, including the Olowi field, which have different cost structures, fluctuating production volumes on a relatively fixed cost
base and fluctuations in the Canadian dollar. Offshore Africa production expense is anticipated to average $10.50 to $12.50
per bbl for 2017.
Depletion, Depreciation and Amortization – Exploration and Production
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Expense
$/BOE (1)
2016
2015
$
3,465 $
4,248 $
458
262
388
273
$
$
4,185 $
4,909 $
16.79 $
18.50 $
2014
3,901
269
105
4,275
17.27
(1) Amounts expressed on a per unit basis are based on sales volumes.
The decrease in depletion, depreciation and amortization expense for 2016 from 2015 was primarily due to lower sales
volumes and depletion rates in North America.
Depletion, depreciation and amortization on a per barrel basis in 2016 decreased 9% to $16.79 per BOE from $18.50 per BOE
for 2015 (2014 – $17.27 per BOE). The decrease in depletion, depreciation and amortization expense per BOE for 2016 from
2015 was primarily due to a lower depletable cost base and higher reserves in North America.
Asset Retirement Obligation Accretion – Exploration and Production
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Expense
$/BOE (1)
2016
2015
2014
$
$
$
66 $
93 $
35
12
39
10
113 $
0.45 $
142 $
0.54 $
98
38
10
146
0.59
(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 expense for 2016 decreased 17% to $0.45 per BOE from $0.54 per BOE for 2015
(2014 – $0.59 per BOE).
Operating Highlights – Oil Sands Mining and Upgrading
Operations Update
At Horizon, the Company continues to focus on reliable and efficient operations. Horizon achieved record SCO production
during the fourth quarter of 2016, averaging 178,063 bbl/d following the completion of the major turnaround and the
successful tie-in of Phase 2B during the third quarter.
The Horizon Phase 3 expansion, which is targeted to add 80,000 bbl/d of SCO production, is on schedule and targeted for
commissioning and startup in the fourth quarter of 2017.
33
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Product Prices, Royalties and Transportation – Oil Sands Mining
and Upgrading
($/bbl) (1)
SCO sales price
Bitumen value for royalty purposes (2)
Bitumen royalties (3)
Transportation
2016
2015
2014
58.59 $
61.39 $
100.27
27.57 $
32.14 $
67.63
0.54 $
1.77 $
1.08 $
1.81 $
5.77
1.85
$
$
$
$
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Calculated as the annual average of the bitumen valuation methodology price.
(3) Calculated based on bitumen royalties expensed during the year; divided by the corresponding SCO sales volumes.
Realized SCO sales prices averaged $58.59 per bbl for 2016, a decrease of 5% compared with $61.39 per bbl for 2015
(2014 – $100.27 per bbl). The decrease in SCO pricing for 2016 compared to 2015 was primarily due to lower WTI benchmark
pricing and the impact of industry wide planned and unplanned upgrader outages.
Cash Production Costs – Oil Sands Mining and Upgrading
The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 21 to the
Company’s audited consolidated financial statements.
($ 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.
$
$
$
$
$
$
2016
2015
1,292 $
1,332 $
(151)
(45)
1,141 $
1,287 $
1,057 $
1,212 $
84
75
2014
1,609
(98)
1,511
1,395
116
1,141 $
1,287 $
1,511
2016
2015
23.36 $
26.95 $
1.84
1.66
25.20 $
28.61 $
2014
34.33
2.85
37.18
123,652
123,231
111,351
Adjusted cash production costs for 2016 decreased 12% to $25.20 per bbl from $28.61 per bbl for 2015 (2014 – $37.18 per bbl)
primarily reflecting the Company’s continuous focus on cost control and efficiencies, high utilization rates and reliability,
additional Phase 2B capacity and lower industry service costs. Cash production costs for 2016, including turnaround costs,
were within the Company's previously issued guidance. For 2017, cash production costs are anticipated to average $24.00 to
$27.00 per bbl, including turnaround costs.
Depletion, Depreciation and Amortization – Oil Sands Mining
and Upgrading
($ millions, except per bbl amounts)
Depletion, depreciation and amortization
Less: depreciation incurred during turnaround periods
Adjusted depletion, depreciation and amortization
$/bbl (1)
2016
2015
662 $
562 $
(99)
(5)
563 $
557 $
2014
596
(28)
568
12.43 $
12.37 $
13.97
$
$
$
(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 2016 of $12.43 per bbl was comparable
with $12.37 per bbl for 2015 (2014 – $13.97 per bbl).
34
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Asset Retirement Obligation Accretion – Oil Sands Mining and Upgrading
($ millions, except per bbl amounts)
Expense
$/bbl (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2016
2015
$
$
29 $
31 $
0.64 $
0.69 $
2014
47
1.16
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 expense for 2016 decreased 7% to $0.64 per bbl from $0.69 per bbl for 2015
(2014 – $1.16 per bbl).
Midstream
($ millions)
Revenue
Production expense
Midstream cash flow
Depreciation
Equity (gain) loss from Redwater Partnership
Gain on disposition
Segment earnings before taxes
2016
2015
$
114 $
136 $
25
89
11
(7)
(218)
32
104
12
44
–
$
303 $
48 $
2014
120
34
86
9
8
–
69
During 2016, the Company disposed of its interest in the Cold Lake Pipeline, including $321 million of property,
plant and equipment, for total net consideration of $539 million, resulting in a pre-tax gain of $218 million. Total net
consideration was comprised of $349 million in cash, together with $190 million of non-cash share consideration of
approximately 6.4 million common shares of Inter Pipeline with a value of $29.57 per common share, determined as of the
closing date.
With the Company's disposal of its interest in the Cold Lake Pipeline, the Company's Midstream assets now include two
crude oil pipeline systems and a 50% working interest in an 84-megawatt cogeneration plant at Primrose. Approximately 40%
of the Company's heavy crude oil production is transported to international mainline liquid pipelines via the 100% owned
and operated ECHO pipeline, and 62% owned and operated Pelican 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, committed each to provide funding up to $350 million by each party by January
2016 in the form of subordinated debt bearing interest at prime plus 6%. During 2016, the Company and APMC each provided
$99 million of subordinated debt. To date, each party has provided $324 million of subordinated debt, together with accrued
interest thereon of $61 million for a Company total of $385 million. Should final Project costs exceed the sanction cost
estimate of $8,500 million, the Company and APMC have agreed, each with a 50% interest, to provide additional subordinated
debt as required to reflect an agreed debt to equity ratio and, 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 2016, Redwater Partnership issued $550 million of 4.25% series F senior secured bonds due June 2029, $500 million
of 4.75% series G senior secured bonds due June 2037, $500 million of 4.15% series H senior secured bonds due June 2033,
and $500 million of 4.35% series I senior secured bonds due January 2039.
As at December 31, 2016, Redwater Partnership had additional borrowings of $1,581 million under its secured $3,500 million
syndicated credit facility.
Under its processing agreement, beginning on the earlier of the commercial operations date of the refinery and June 1, 2018,
the Company is unconditionally obligated to pay its 25% pro rata share of the debt portion of the monthly cost of service toll,
including interest, fees and principal repayments, of the syndicated credit facility and bonds, over the tolling period of 30 years.
35
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Redwater Partnership has entered into various agreements related to the engineering, procurement and construction of the
Project. These contracts can be cancelled by Redwater Partnership upon notice without penalty, subject to the costs incurred
up to and in respect of the cancellation.
Administration Expense
($ millions, except per BOE amounts)
Expense
$/BOE (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2016
2015
$
$
345 $
1.17 $
390 $
1.26 $
2014
367
1.28
Administration expense on a per BOE basis for 2016 decreased 7% to $1.17 per BOE from $1.26 per BOE for 2015
(2014 – $1.28 per BOE). Administration expense per BOE decreased for 2016 from 2015 primarily due to lower staffing related
costs and general corporate costs, partially offset by the impact of lower sales volumes on a relatively fixed cost base.
Share-Based Compensation
($ millions)
Expense (Recovery)
2016
2015
$
355 $
(46) $
2014
66
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 Company recorded a $355 million share-based compensation expense for the year ended December 31, 2016, 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. For 2016, the Company capitalized $67 million of share-based compensation
costs to property, plant and equipment in the Oil Sands Mining and Upgrading segment (2015 – $10 million costs recovered,
2014 – $14 million costs capitalized).
Interest and Other Financing Expense
($ millions, except per BOE amounts and interest rates)
Expense, gross
Less: capitalized interest
Expense, net
$/BOE (1)
Average effective interest rate
$
$
$
2016
2015
616 $
566 $
233
383 $
1.30 $
244
322 $
1.04 $
3.9%
3.9%
2014
527
204
323
1.12
3.9%
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest and other financing expense for 2016 increased from the comparable period in 2015 primarily due to the impact of
higher average debt levels. Capitalized interest of $233 million for 2016 was primarily related to the Horizon Phase 2/3 expansion.
Net interest and other financing expense for 2016 increased 25% to $1.30 per BOE from $1.04 per BOE for 2015 (2014 – $1.12 per
BOE). The increase for 2016 from 2015 was primarily due to higher average debt levels and lower sales volumes.
The Company’s average effective interest rate for 2016 was consistent with 2015.
36
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Risk Management Activities
The Company periodically utilizes various derivative financial instruments to manage its commodity price, interest rate and
foreign currency exposures. These derivative financial instruments are not intended for trading or speculative purposes.
($ millions)
Crude oil and NGLs financial instruments
Natural gas financial instruments
Foreign currency contracts
Realized loss (gain)
Crude oil and NGLs financial instruments
Natural gas financial instruments
Foreign currency contracts
Unrealized loss (gain)
Net loss (gain)
2016
2015
$
– $
(599) $
–
8
–
(244)
2014
(284)
34
(99)
$
$
$
$
8 $
(843) $
(349)
– $
394 $
(427)
6
19
–
(20)
25 $
33 $
374 $
(469) $
(3)
(21)
(451)
(800)
During 2016, net realized risk management losses were related to the settlement of foreign currency contracts. The Company
recorded a net unrealized loss of $25 million ($21 million after-tax) on its risk management activities for 2016 (2015 –
$374 million unrealized loss, $275 million after-tax; 2014 – $451 million unrealized gain, $339 million after-tax).
Complete details related to outstanding derivative financial instruments at December 31, 2016 are disclosed in note 18 to the
Company's consolidated financial statements.
Foreign Exchange
($ millions)
Net realized loss (gain)
Net unrealized (gain) loss
Net (gain) loss (1)
2016
2015
38 $
(97) $
(93)
858
(55) $
761 $
2014
47
256
303
$
$
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange loss for 2016 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 gain for 2016 was primarily
related to the impact of a stronger Canadian dollar with respect to outstanding US dollar debt. The net unrealized loss (gain)
for each of the periods presented included the impact of cross currency swaps (2016 – unrealized loss of $295 million, 2015 –
unrealized gain of $649 million, 2014 – unrealized gain of $259 million). The US/Canadian dollar exchange rate at December 31,
2016 was US$0.7448 (December 31, 2015 – US$0.7225, December 31, 2014 – US$0.8620).
37
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Income Taxes
($ millions, except income tax rates)
North America (1)
North Sea
Offshore Africa
PRT – North Sea
Other taxes
Current income tax (recovery) expense
Deferred corporate income tax (recovery) expense
Deferred PRT (recovery) expense – North Sea
Deferred income tax (recovery) expense
Income tax rate and other legislative changes (2)
2016
2015
$
(377) $
86 $
(74)
22
(198)
9
(618)
(106)
(135)
(241)
(859)
221
(117)
17
(258)
11
(261)
216
15
231
(30)
(351)
Effective income tax rate on adjusted net earnings (loss) from operations (3)
45%
61%
$
(638) $
(381) $
2014
702
(68)
43
(273)
23
427
681
126
807
1,234
–
1,234
25%
(1) Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments.
(2) In 2016, the UK government enacted legislation to reduce the supplementary charge on oil and gas profits from 20% to 10% effective January 1, 2016,
resulting in a decrease in the Company's deferred corporate income tax liability of $107 million. The UK government also enacted tax rate reductions relating
to Petroleum Revenue Tax (“PRT”), resulting in a decrease in the Company’s net deferred income tax liability of $114 million. During 2015, the Alberta
government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015, increasing the Company's
deferred corporate income tax liability by $579 million. In addition, 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 net deferred income
tax liability of $228 million.
(3) Excludes the impact of current and deferred PRT expense and other current income tax expense.
The effective income tax rate for 2016 and the comparable years included the impact of non-taxable items in North America
and the North Sea and the impact of differences in jurisdictional income (loss) and tax rates in the countries in which the
Company operates, in relation to net earnings (loss). In addition the effective income tax rate for 2016 also reflected the
successful resolution of certain prior year tax matters.
The current corporation income tax and PRT recoveries in the North Sea in 2016 and the comparable years included the impact
of abandonment expenditures related to the Murchison platform.
In 2016, the UK government enacted legislation to reduce the supplementary charge on oil and gas profits from 20% to 10%
effective January 1, 2016, resulting in a decrease in the Company's deferred corporate income tax liability of $107 million.
The UK government also enacted legislation to reduce the PRT rate from 35% to 0% effective January 1, 2016. Allowable
abandonment expenditures eligible for carryback to 2015 and prior taxation years for PRT purposes are still recoverable at a PRT
rate of 50%. As a result of these income tax rate changes, the Company’s deferred PRT liability was reduced by $228 million and
the deferred corporate income tax liability was increased by $114 million.
In 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 corporate income tax liability was
increased by $579 million.
In 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 were 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 Investment Allowance is deductible for supplementary charge
purposes, subject to certain restrictions. As a result of the new income tax changes, the Company's deferred corporate
income tax liability was reduced by $217 million and the deferred PRT liability was reduced by $11 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.
For 2017, the Company expects to recognize current income tax expense of $100 million to $150 million in Canada and
$15 million to $35 million in the North Sea and Offshore Africa.
For 2016, the Company filed Scientific Research and Experimental Development claims of approximately $549 million (2015 –
$527 million; 2014 – $450 million) relating to qualifying research and development expenditures for Canadian income tax purposes.
38
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Net Capital Expenditures (1)
($ millions)
Exploration and Evaluation
Net (proceeds) expenditures (2) (3) (4)
Property, Plant and Equipment
Net property acquisitions (dispositions) (2) (3) (4)
Well drilling, completion and equipping
Production and related facilities
Capitalized interest and other (5)
Net expenditures
Total Exploration and Production
Oil Sands Mining and Upgrading
Horizon Phases 2/3 construction costs
Sustaining capital
Turnaround costs
Capitalized interest and other (5)
Total Oil Sands Mining and Upgrading
Midstream (6)
Abandonments (7)
Head office
Total net capital expenditures
By segment
North America (2) (3) (4)
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream (6)
Abandonments (7)
Head office
Total
2016
2015
2014
$
(6) $
(805) $
1,190
159
712
369
91
1,331
1,325
(451)
965
908
102
1,524
719
2,893
2,162
1,830
106
6,991
8,181
1,920
2,187
2,502
379
135
284
2,718
(533)
267
17
301
18
224
2,730
8
370
26
352
29
227
3,110
62
346
45
$
$
3,794 $
3,853 $
11,744
1,048 $
(119) $
7,500
126
151
2,718
(533)
267
17
230
608
2,730
8
370
26
400
281
3,110
62
346
45
$
3,794 $
3,853 $
11,744
(1) Net capital expenditures exclude adjustments related to differences between carrying amounts and tax values and other fair value adjustments, and include
non-cash transfers of property, plant and equipment to inventory due to change in use.
(2) Includes Business Combinations.
(3) Includes proceeds from the Company’s disposition of properties.
(4) Includes 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) Includes non-cash share consideration of $190 million received from Inter Pipeline on the disposition of Midstream assets in 2016.
(7) Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table.
The Company’s strategy is focused on building a diversified asset base that is balanced among various products. In order to
facilitate efficient operations, the Company concentrates its activities in core areas. The Company focuses on maintaining its
land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration
risk. By owning associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby
increasing control over production costs.
Net capital expenditures for 2016 were $3,794 million compared with $3,853 million for 2015 (2014 – $11,744 million).
Net capital expenditures for 2016 included the disposition of the Company's ownership interest in the Cold Lake Pipeline
in the Midstream segment. Total net consideration on the disposition was comprised of $349 million in cash, together with
$190 million of non-cash share consideration of approximately 6.4 million common shares of Inter Pipeline with a value of
$29.57 per common share, determined as of the closing date.
On December 15, 2016 the Company announced its 2017 Capital Budget. Excluding the impact of the announced purchase of
the Athabasca Oil Sands Project, as well as additional working interests in certain other producing and non-producing oil and
gas properties, the 2017 budget reflects a continued focus on proactive capital allocation and lowering overall operating and
capital cost structures, and is targeted at $3,890 million.
39
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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.
2016
9
174
7
268
458
96%
2015
19
115
6
166
306
96%
2014
75
1,023
19
437
1,554
98%
NORTH AMERICA
North America, excluding Oil Sands Mining and Upgrading, accounted for approximately 20% of the total net capital
expenditures for 2016 compared with approximately 1% for 2015 (2014 – 66%).
During 2016, the Company targeted 9 net natural gas wells, including 4 wells in Northeast British Columbia and 5 wells
in Northwest Alberta. The Company also targeted 179 net crude oil wells. The majority of these wells were concentrated
in the Company's Northern Plains region where 160 primary heavy crude oil wells, 2 Pelican Lake heavy crude oil
wells and 9 bitumen (thermal oil) wells were drilled. Another 8 wells targeting light crude oil were drilled outside the Northern
Plains region.
Overall thermal oil production for 2016 averaged approximately 111,000 bbl/d compared with approximately 129,800 bbl/d
for 2015 (2014 – 107,800 bbl/d). Production volumes in 2016 reflected the cyclic nature of thermal oil production at Primrose,
together with the impact of the reinstatement of the Primrose East pipeline following the completion of repairs in May 2016.
Operating performance at the Pelican Lake tertiary recovery project continued to be strong, leading to average production of
approximately 47,600 bbl/d in 2016 compared with 50,800 bbl/d in 2015 (2014 – 50,100 bbld/).
OIL SANDS MINING AND UPGRADING
Phase 2/3 expansion activity in the fourth quarter of 2016 focused on the field construction and commissioning of the hydrogen
unit, hydrotreater unit, vacuum distillation and diluent recovery unit, sour water concentrator, tank farms, tailings re-handling
plant, froth treatment, froth tank, tailings transfer pumphouses and pipelines, extraction plant, ore preparation plants, and
superpot. Phase 3 work also continued with engineering, procurement and construction related to tailings retrofit and the
combined hydrotreater and sulphur recovery units.
During the turnaround in the third quarter, the Company successfully completed the tie-in of major Phase 2B components as
planned. The construction, commissioning and operational teams at Horizon worked together to execute a safe and effective
start-up of the Phase 2B expansion. The Horizon Phase 3 expansion, which is targeted to add 80,000 bbl/d of SCO production,
is on schedule and targeted for commissioning and startup in the fourth quarter of 2017.
NORTH SEA
During 2016, the Company drilled 1 gross well (0.9 net well) at Ninian.
The Company successfully completed the removal of the platform top side structures at Murchison on schedule and below
sanctioned costs, with further decommissioning efforts planned for 2017.
Due to the Company's continued focus on proactive capital allocation and lowering overall operating and capital cost structures,
the Company plans to commence abandonment of the Ninian North platform in 2017. Abandonment activities at Ninian North
have been reflected in 2017 guidance.
OFFSHORE AFRICA
In 2016, the Company drilled 2 gross wells (1.2 net wells) and subsequently demobilized the drilling rigs at Baobab and Espoir.
EVENT SUBSEQUENT TO DECEMBER 31, 2016
On March 9, 2017, the Company announced that it had entered into agreements to acquire 70% of the Athabasca Oil Sands
Project, as well as additional working interests in certain other producing and non-producing oil and gas properties, for
preliminary total consideration of approximately $12.7 billion, comprised of cash of approximately $8.7 billion and 97,560,975
common shares of the Company, with an estimated value of approximately $4 billion as at the announcement date. The
transaction is expected to close in mid-2017, subject to receipt of all required consents and regulatory and other approvals.
40
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Liquidity and Capital Resources
($ millions, except ratios)
Working capital (deficit) (1)
Long-term debt (2) (3)
Share capital
Retained earnings
Accumulated other comprehensive income
Shareholders’ equity
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)
$
$
$
2016
2015
1,056 $
1,193 $
2014
(673)
16,805 $
16,794 $
14,002
4,671 $
4,541 $
4,432
21,526
22,765
24,408
70
75
51
$
26,267 $
27,381 $
28,891
39%
26%
(1%)
0%
38%
34%
(2%)
(1%)
33%
26%
14%
10%
(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 (2016 – $1,812 million, 2015 – $1,729 million, 2014 – $980 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, 2016, the Company’s capital resources consisted primarily of funds flow from operations, available bank
credit facilities and access to debt capital markets. Funds 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 funds flow from operations supported by the implementation of its ongoing hedge policy, the
flexibility of its capital expenditure programs and 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 funds 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 current commodity price environment, 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 2016, the Company issued $1,000 million of 3.31% medium-term notes due February 2022. After issuing these
securities, the Company has $2,000 million remaining on its 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.
■●
In 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.
■● 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.
■● During 2016, the Company prepaid $250 million of the previously outstanding $1,000 million non-revolving term credit
facility and extended the maturity date to February 2019 from January 2017. Borrowings under this facility may be made by
way of pricing referenced to Canadian dollar bankers’ acceptances or Canadian prime loans. As at December 31, 2016, the
$750 million facility was fully drawn. During 2016, the Company also entered into a new $125 million non-revolving term
credit facility maturing February 2019, which was fully drawn at December 31, 2016. Borrowings under this facility may be
made by way of pricing referenced to Canadian dollar bankers’ acceptances or Canadian prime loans.
41
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. ■■ Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant
packages; 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 2016, the Company repaid US$250 million of 6.00% notes and US$500 million of three-month LIBOR plus 0.375% notes.
At December 31, 2016, the Company had in place bank credit facilities of $7,350 million, of which approximately $3,043 million,
net of commercial paper issuances of $336 million, was available for general corporate purposes.
At December 31, 2016, the Company had total US dollar denominated debt with a carrying amount of $10,612 million
(US$7,905 million), excluding transaction costs. This included $4,437 million (US$3,305 million) hedged by way of cross
currency swaps (US$2,150 million) and foreign currency forwards (US$1,155 million). The fixed repayment amount of these
hedging instruments was $3,975 million, resulting in a notional reduction of the carrying amount of the Company’s US dollar
denominated debt of approximately $462 million to $10,150 million as at December 31, 2016.
Long-term debt was $16,805 million at December 31, 2016, resulting in a debt to book capitalization ratio of 39% (December 31,
2015 – 38%, December 31, 2014 – 33%); 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 funds 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, 2016 are discussed
in note 10 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 December 31, 2016, 50,000 GJ/d of currently forecasted
natural gas volumes were hedged using AECO swaps for January 2017 to October 2017. Subsequent to year end, 50,000 bbl/d
of currently forecasted crude oil volumes were hedged using WTI collars for February 2017 to December 2017 and 17,500 bbl/d
of currently forecasted crude oil volumes were hedged using WTI collars for March 2017 to December 2017. Further details
related to the Company's commodity derivative financial instruments at December 31, 2016 are discussed in note 18 of the
Company's consolidated financial statements.
SHARE CAPITAL
As at December 31, 2016, there were 1,110,952,000 common shares outstanding (December 31, 2015 – 1,094,668,000
common shares) and 58,299,000 stock options outstanding. As at March 14, 2017, the Company had 1,113,884,000 common
shares outstanding and 54,331,000 stock options outstanding.
On March 1, 2017, the Board of Directors approved an increase in the quarterly dividend to $0.275 per common share,
beginning with the dividend payable on April 1, 2017. On November 2, 2016, the Board of Directors approved an increase in
the quarterly dividend to $0.25 per common share (previous quarterly dividend rate of $0.23 per common share), beginning
with the dividend payable on January 1, 2017. The dividend policy undergoes periodic review by the Board of Directors and is
subject to change.
During 2016, the Company completed the net distribution of approximately 21.8 million PrairieSky common shares to the
shareholders of record of the Company as at June 3, 2016, completing the previously announced Plan of Arrangement. The
distribution was recognized as a return of capital of $546 million. Subsequent to the distribution, the Company’s ownership
interest in PrairieSky was less than 10% of the issued and outstanding common shares of PrairieSky.
On March 1, 2017, the Board of Directors approved the Company's application for a Normal Course Issuer Bid to
purchase through the facilities of the Toronto Stock Exchange, alternative Canadian trading platforms, and the New York Stock
Exchange, up to 27,814,309 common shares, over a 12 month period commencing upon receipt of applicable regulatory and
other approvals.
The Company’s Normal Course Issuer Bid announced in 2015 expired in April 2016 and was not renewed. During 2016, the
Company did not purchase any common shares for cancellation.
42
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Commitments and Off Balance Sheet Arrangements
In the normal course of business, the Company has entered into various commitments that will have an impact on the
Company’s future operations. The following table summarizes the Company’s commitments as at December 31, 2016:
($ 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
2017
2018
2019
2020
2021 Thereafter
441 $
404 $
306 $
300 $
258 $ 2,337
166 $
105 $
59 $
34 $
33 $
9
$
$
$ 1,813 $ 2,841 $ 2,705 $ 1,768 $
671 $ 7,072
$
$
$
626 $
539 $
475 $
434 $
395 $ 4,126
44 $
53 $
43 $
2 $
43 $
2 $
43 $
2 $
40 $
2 $
154
35
(1) Long-term debt represents principal repayments only and does not reflect original issue discounts and premiums or transaction costs.
(2) Included in the 2017 long-term debt repayment commitments, the Company had US$1,100 million of 5.70% debt securities due May 2017, hedged by way
of a cross currency swap with a principal repayment amount fixed at $1,287 million.
(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, 2016.
In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering,
procurement and construction 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, 2016, 2015 and 2014, 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, 2016, prepared in accordance with NI 51-101 reserves disclosures:
Light
and
Medium
Crude Oil
Primary
Heavy
Crude Oil
Proved Reserves
(MMbbl)
(MMbbl)
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
December 31, 2015
386
213
268
Bitumen
(Thermal
Oil)
Synthetic
Crude Oil
(MMbbl)
1,225
(MMbbl)
2,408
Natural
Gas
(Bcf)
Natural
Gas
Liquids
Barrels
of Oil
Equivalent
(MMbbl)
(MMBOE)
6,106
195
5,713
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
1
7
9
–
15
–
(5)
12
(36)
389
–
9
5
–
–
–
(3)
1
(38)
187
–
–
–
6
–
–
–
7
(17)
264
–
53
–
–
3
–
–
29
(41)
–
–
–
–
–
–
–
196
(45)
3
196
225
–
103
(4)
(102)
709
(619)
1,269
2,559
6,617
–
9
4
–
5
–
(1)
1
(15)
198
2
111
55
6
40
(1)
(26)
364
(295)
5,969
43
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Light
and
Medium
Crude Oil
Primary
Heavy
Crude Oil
(MMbbl)
(MMbbl)
Proved Plus
Probable Reserves
December 31, 2015
618
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2016
1
15
13
–
19
–
(6)
(5)
(36)
619
294
–
13
7
–
–
–
(3)
(14)
(38)
259
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
388
Bitumen
(Thermal
Oil)
Synthetic
Crude Oil
(MMbbl)
2,407
(MMbbl)
3,633
Natural
Gas
(Bcf)
8,508
–
–
–
7
–
–
–
6
(17)
384
–
82
1
–
4
–
–
64
(41)
–
–
–
–
–
–
–
16
(45)
5
302
289
–
125
(7)
(134)
607
(619)
2,517
3,604
9,076
Natural
Gas
Liquids
Barrels
of Oil
Equivalent
(MMbbl)
(MMBOE)
283
1
17
6
–
6
–
(3)
(11)
(15)
284
9,041
3
177
75
7
50
(1)
(34)
156
(295)
9,179
At December 31, 2016, the company gross proved crude oil, bitumen (thermal oil), SCO and NGLs reserves totaled 4,866 MMbbl,
and company gross proved plus probable crude oil, bitumen (thermal oil), SCO and NGLs reserves totaled 7,667 MMbbl. Proved
reserve additions and revisions replaced 189% of 2016 production. Additions to proved reserves resulting from exploration and
development activities, acquisitions and future offset additions amounted to 126 MMbbl, and additions to proved plus probable
reserves amounted to 192 MMbbl. Net positive revisions amounted to 237 MMbbl for proved reserves and 44 MMbbl for proved
plus probable reserves, primarily due to technical revisions.
At December 31, 2016, the company gross proved natural gas reserves totaled 6,617 Bcf, and company gross proved
plus probable natural gas reserves totaled 9,076 Bcf. Proved reserve additions and revisions replaced 183% of 2016
production. Additions to proved reserves resulting from exploration and development activities, acquisitions and future offset
additions amounted to 523 Bcf, and additions to proved plus probable reserves amounted to 714 Bcf. Net positive revisions
amounted to 607 Bcf for proved reserves and 473 Bcf for proved plus probable reserves, primarily due to technical revisions.
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 and upgrading the Company’s bitumen products;
■■ Timing and success of integrating the business and operations of acquired companies and assets, including the announced
acquisition of a significant interest in the Athabasca Oil Sands Project, and certain other producing and non-producing oil
and gas properties;
44
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
■■ Credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts, including
derivative financial instruments and physical sales contracts as part of a hedging program;
■■
Interest rate risk associated with the Company’s ability to secure financing on commercially acceptable terms;
■■ Foreign exchange risk due to fluctuating exchange rates on the Company’s US dollar denominated debt and as 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;
■■ 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 substantively 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, 2016.
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 funds 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 2016 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 5.2% (2015 – 5.9%; 2014 – 4.6%). For 2016, the
Company’s capital expenditures included $267 million for abandonment expenditures (2015 – $370 million; 2014 – $346 million).
The Company’s estimated discounted ARO at December 31, 2016 was as follows:
($ millions)
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream
2016
2015
$
1,444 $
1,114
837
244
717
1
975
266
594
1
$
3,243 $
2,950
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 ratified the Paris climate change agreement, with a commitment to reduce GHG
emissions by 30% from 2005 levels by 2030. Canada has also committed to reduce methane emissions from the upstream oil
and gas sector by 40% to 45% by 2025, as compared to 2012 levels. The federal government is also developing a comprehensive
management system for air pollutants, and has released regulations pertaining to certain boilers, heaters and compressor
46
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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 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 price on combustion emissions from the upstream oil and gas sector beginning in 2023. In British Columbia, the
provincial government has also announced a methane reduction target, comparable to the federal target.
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. Various jurisdictions have enacted or are evaluating low carbon fuel standards,
which may affect access to market for crude oil with higher emissions intensity.
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 funds 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.
Changes In Accounting Policies
Effective January 1, 2016, the Company adopted the 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. The Company adopted this amendment prospectively. Adoption of this
amended standard did not result in an impact to the Company’s consolidated financial statements.
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. A comprehensive discussion of the Company’s significant
accounting estimates is contained in this MD&A and the audited consolidated financial statements for the year ended
December 31, 2016.
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.
47
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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 related 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.
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.
B) CRUDE OIL AND NATURAL GAS RESERVES
Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and the
timing of future capital expenditures, all of which are subject to many uncertainties, interpretations, and judgements. The
Company expects that, over time, its reserve estimates will be revised upward or downward based on updated information
such as the results of future drilling, testing and production levels, and may be affected by changes in commodity prices.
Reserve estimates can have a significant impact on net earnings, as they are a key component in the calculation of depletion,
depreciation and amortization and for determining potential asset impairment. For example, a revision to the proved reserve
estimates would result in a higher or lower depletion, depreciation and amortization charge to net earnings. Downward
revisions to reserve estimates may also result in an impairment of E&E and property, plant and equipment carrying amounts.
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 may 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 5.2%. 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.
D) INCOME TAXES
The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and
liabilities are recognized based on the estimated 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
48
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes a liability for a tax
filing position based on its assessment of the probability that additional taxes may ultimately be due.
E) RISK MANAGEMENT ACTIVITIES
The Company uses derivative financial instruments to manage its commodity price, foreign currency and interest rate
exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative
purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value.
The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows, 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
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.
F) 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.
The Company has made various assumptions in determining the fair values of 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.
G) SHARE-BASED COMPENSATION
The Company has made various assumptions in estimating the fair values of stock options granted including expected
volatility, expected exercise behavior and future forfeiture rates. At each period end, stock options outstanding are
remeasured for changes in the fair value of the liability.
Accounting Standards Issued But Not Yet Applied
In January 2016, 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.
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.
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.
49
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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, 2016, and concluded that disclosure
controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual
filings and other reports filed with securities regulatory authorities in Canada and the United States is recorded, processed,
summarized and reported within the time periods specified and such information is accumulated and communicated to the
Company’s management to allow timely decisions regarding required disclosures.
The Company’s management also performed an assessment of internal control over financial reporting as at December 31,
2016, 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 2016 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.
Excluding the impact of the announced purchase of the Athabasca Oil Sands Project, as well as additional working interests
in certain other producing and non-producing oil and gas properties, capital expenditures in 2017 are currently targeted to be
as follows:
$
2017
460
910
420
365
25
$
2,180
1,055
15
415
225
$
$
1,710
3,890
($ millions)
Exploration and Production
North America natural gas and NGLs
North America crude oil
International crude oil
Thermal In Situ Oil Sands
Net acquisitions, Midstream and other
Total Exploration and Production
Oil Sands Mining and Upgrading
Project Capital
Technology and Phase 4
Sustaining capital
Turnarounds, reclamation and other
Total Oil Sands Mining and Upgrading
Total
50
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Sensitivity Analysis
The following table is indicative of the annualized sensitivities of funds 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
2016, 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 (1)
Excluding financial derivatives
Including financial derivatives
Volume changes
Crude oil – 10,000 bbl/d
Natural gas – 10 MMcf/d
Foreign currency rate change
$0.01 change in US$ (1)
Including financial derivatives
Interest rate change – 1%
Funds flow
from
operations
($ millions)
Funds flow
from
operations
(per common
share, basic)
Net earnings
(loss)
($ millions)
Net earnings
(loss)
(per common
share, basic)
$
$
$
$
$
$
$
196 $
0.18 $
196 $
32 $
31 $
102 $
4 $
0.03 $
0.03 $
0.09 $
– $
102 – 105 $
31 $
0.09 $
0.03 $
32 $
31 $
66 $
– $
21 $
31 $
0.18
0.03
0.03
0.06
–
0.02
0.03
(1) For details of financial instruments in place, refer to note 18 to the Company’s consolidated financial statements as at December 31, 2016.
Daily Production by Segment, Before Royalties
Crude oil and NGLs (bbl/d)
North America – Exploration and Production 369,987
328,681
343,779
361,348
350,958
399,982
390,814
Q1
Q2
Q3
Q4
2016
2015
2014
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)
127,909
119,511
67,586
178,063
123,265
122,911
110,571
23,317
25,714
23,360
30,858
23,450
26,171
24,085
21,689
23,554
26,096
22,216
19,079
17,380
12,429
546,927
502,410
460,986
585,185
523,873
564,188
531,194
1,722
1,620
1,567
1,578
1,622
1,663
1,527
29
35
30
39
50
28
44
24
38
31
36
27
7
21
1,786
1,689
1,645
1,646
1,691
1,726
1,555
North America – Exploration and Production
656,929
598,773
605,009
624,386
621,239
677,270
645,227
North America – Oil Sands Mining
and Upgrading
North Sea
Offshore Africa
Total
127,909
119,511
67,586
178,063
123,265
122,911
110,571
28,072
31,621
28,370
37,334
31,793
30,824
31,380
25,748
29,913
31,365
28,191
23,529
18,629
15,983
844,531
783,988
735,212
859,577
805,782
851,901
790,410
51
Canadian Natural 2016 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
2016
2015
2014
$ 23.31 $ 39.98 $ 39.66 $ 45.00 $ 36.93 $ 41.13 $ 77.04
2.46
20.85
1.90
13.94
2.81
37.17
3.59
14.31
2.51
37.15
3.48
13.85
2.70
42.30
4.62
14.28
2.61
34.32
3.40
14.10
2.60
38.53
4.30
15.74
2.41
74.63
12.99
18.25
$
5.01 $ 19.27 $ 19.82 $ 23.40 $ 16.82 $ 18.49 $ 43.39
$
2.23 $
1.50 $
2.44 $
3.14 $
2.32 $
3.16 $
0.28
1.95
0.07
1.23
0.35
1.15
0.02
1.22
0.40
2.04
0.09
1.08
0.34
2.80
0.17
1.15
0.33
1.99
0.09
1.18
0.38
2.78
0.10
1.34
$
0.65 $
(0.09) $
0.87 $
1.48 $
0.72 $
1.34 $
4.83
0.27
4.56
0.38
1.48
2.70
$ 19.37 $ 27.28 $ 29.39 $ 34.54 $ 27.58 $ 32.60 $ 58.48
2.20
17.17
1.30
11.19
2.61
24.67
2.13
11.38
2.51
26.88
2.27
10.83
2.46
32.08
3.16
11.34
2.44
25.14
2.21
11.18
2.56
30.04
2.85
12.70
2.18
56.30
8.90
14.67
$
4.68 $ 11.16 $ 13.78 $ 17.58 $ 11.75 $ 14.49 $ 32.73
(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)
SCO sales price
Bitumen royalties (2)
Transportation
Adjusted cash production costs (1)
Netback
Q1
Q2
Q3
Q4
2016
2015
2014
$ 46.63 $ 61.78 $ 58.61 $ 64.51 $ 58.59 $ 61.39 $ 100.27
0.13
2.07
0.39
1.34
26.55
26.82
0.62
3.40
27.05
0.88
1.22
0.54
1.77
1.08
1.81
22.53
25.20
28.61
5.77
1.85
37.18
$ 17.88 $ 33.23 $ 27.54 $ 39.88 $ 31.08 $ 29.89 $ 55.47
(1) Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods.
(2) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes.
52
Canadian Natural 2016 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
2016
2015
262,029
161,011
113,085
117,602
653,727
728,034
$ 36.99 $ 40.59 $ 42.43 $ 46.74 $
46.74 $
$ 21.27 $ 33.11 $ 37.98 $ 39.64 $
21.27 $
$ 35.13 $ 39.86 $ 41.94 $ 42.79 $
42.79 $
42.46
25.01
30.22
$
47,538 $
33,081
1,110,952
1,094,668
383,518
210,872
140,914
156,916
892,220
951,311
$ 28.45 $ 32.02 $ 32.94 $ 35.28 $
35.28 $
$ 14.60 $ 25.08 $ 28.69 $ 29.46 $
14.60 $
$ 27.00 $ 30.83 $ 32.04 $ 31.88 $
31.88 $
34.46
18.94
21.83
$
35,417 $
23,897
1,110,952
1,094,668
53
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Management’s Report
The accompanying consolidated financial statements of Canadian Natural Resources Limited (the “Company“) 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 as issued by the International Accounting Standards Board as
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, 2016; and
the effectiveness of the Company’s internal control over financial reporting as at December 31, 2016.
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
COREY B. BIEBER, CA
Chief Financial Officer and Senior
Vice-President, Finance
MURRAY G. HARRIS, CA
Vice-President,
Financial Controller and
Horizon Accounting
Calgary, Alberta, Canada
March 15, 2017
54
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Management’s Assessment of Internal Control
over Financial Reporting
Management of Canadian Natural Resources Limited (the “Company“) 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, 2016. 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, 2016, as stated in their Independent Auditor’s Report.
STEVE W. LAUT
President
COREY B. BIEBER, CA
Chief Financial Officer and Senior
Vice-President, Finance
Calgary, Alberta, Canada
March 15, 2017
55
Canadian Natural 2016 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 2016, 2015, and 2014 consolidated financial
statements and its internal control over financial reporting as at December 31, 2016. 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, 2016 and December 31, 2015 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, 2016, 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, 2016 and December 31, 2015 and its financial performance and its cash flows
for each of the three years in the period ended December 31, 2016 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,
2016, based on criteria established in Internal Control - Integrated Framework (2013), issued by the Committee of Sponsoring
Organizations of the Treadway Commission (“COSO“).
56
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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.
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, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued
by COSO.
Chartered Professional Accountants
Calgary, Alberta, Canada
March 15, 2017
57
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Note
2016
2015
$
17 $
1,434
851
689
149
913
283
4,336
2,382
50,910
1,020
$
58,648 $
$
595 $
2,222
1,812
463
5,092
14,993
3,223
9,073
32,381
4,671
21,526
70
26,267
$
58,648 $
5
8
9
6
7
9
10
11
10
11
12
13
14
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
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
Investments
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 19).
Approved by the Board of Directors on March 15, 2017
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 2016 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 (gain) loss
Gain on disposition of properties and corporate
acquisitions and dispositions
(Gain) loss from investments
Earnings (loss) before taxes
Current income tax (recovery) expense
Deferred income tax (recovery) expense
Net earnings (loss)
Net earnings (loss) per common share
Basic
Diluted
Note
2016
$
11,098 $
(575)
10,523
4,099
2,003
4,858
345
355
142
383
33
(55)
(250)
(327)
11,586
(1,063)
(618)
(241)
6, 7
11
11
17
18
6, 7
8, 9
12
12
2015
13,167 $
(804)
12,363
4,726
2,379
5,483
390
(46)
173
322
(469)
761
(739)
50
13,030
(667)
(261)
231
$
(204) $
(637) $
16 $
16 $
(0.19) $
(0.19) $
(0.58) $
(0.58) $
2014
21,301
(2,438)
18,863
5,265
3,232
4,880
367
66
193
323
(800)
303
(137)
8
13,700
5,163
427
807
3,929
3.60
3.58
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 (loss)
Net change in derivative financial instruments designated
as cash flow hedges
Unrealized (loss) income, net of taxes of $3 million
(2015 – $2 million, 2014 – $nil)
Reclassification to net earnings (loss), net of taxes of $2 million
(2015 – $2 million, 2014 – $1 million)
Foreign currency translation adjustment
Translation of net investment
Other comprehensive income (loss), net of taxes
$
2016
(204) $
2015
(637) $
2014
3,929
(18)
(13)
(31)
26
(5)
(23)
(13)
(36)
60
24
5
8
13
(4)
9
Comprehensive income (loss)
$
(209) $
(613) $
3,938
59
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Consolidated Statements of Changes in Equity
For the years ended December 31
(millions of Canadian dollars)
Share capital
Balance – beginning of year
Issued upon exercise of stock options
Previously recognized liability on stock options exercised
for common shares
Purchase of common shares under Normal Course
Issuer Bid
Return of capital on PrairieSky Royalty Ltd.
share distribution
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 (loss) income, net of taxes
Balance – end of year
Shareholders’ equity
Note
13
2016
2015
$
4,541 $
4,432 $
559
117
–
(546)
4,671
22,765
(204)
–
(1,035)
21,526
75
(5)
70
91
18
–
–
4,541
24,408
(637)
–
(1,006)
22,765
51
24
75
8
13
13
14
2014
3,854
488
129
(39)
–
4,432
21,876
3,929
(414)
(983)
24,408
42
9
51
$
26,267 $
27,381 $
28,891
60
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Consolidated Statements of Cash Flows
Note
2016
2015
2014
$
(204) $
(637) $
3,929
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 (gain) loss
Realized foreign exchange loss on repayment of
US dollar debt securities
(Gain) loss from investments
Deferred income tax (recovery) expense
Gain on disposition of properties and corporate
acquisitions and dispositions
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
(Repayment) issue of US dollar debt securities, net
Issue of common shares on exercise of stock options
Purchase of common shares under Normal Course
Issuer Bid
Dividends on common shares
Net change in non-cash working capital
Investing activities
Net proceeds (expenditures) on exploration
and evaluation assets (1)
Net expenditures on property, plant and equipment (1) (2)
Current income tax on disposition of properties
Investment in other long-term assets
Net change in non-cash working capital
(Decrease) increase in cash and cash equivalents
Cash and cash equivalents – beginning of year
Cash and cash equivalents – end of year
Interest paid, net
Income taxes (received) paid
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
4,858
5,483
355
142
25
(93)
–
(299)
(241)
(250)
–
(32)
(267)
(542)
(46)
173
374
858
–
55
231
(739)
33
(22)
(370)
239
3,452
5,632
970
107
–
91
–
(1,251)
(40)
(123)
236
(4,704)
(33)
(112)
(852)
342
998
(834)
559
–
(758)
–
307
6
(3,803)
–
(99)
85
(3,811)
(52)
69
$
$
$
17 $
617 $
(444) $
8, 9
20
10
10
20
20
20
20
(5,465)
(11,177)
44
25
69 $
541 $
42 $
9
16
25
521
792
(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.
(2) Net expenditures on property, plant and equipment in 2016 exclude non-cash share consideration of $190 million received from Inter Pipeline Ltd. (“Inter
Pipeline“) on the disposition of the Company’s interest in the Cold Lake Pipeline.
61
Canadian Natural 2016 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.
(D) INVENTORY
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
62
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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.
(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 the related 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 the
estimated 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.
63
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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.
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.
(G) BUSINESS COMBINATIONS
Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed in a business
combination are recognized at their fair value at the date of the acquisition. 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.
(I) CAPITALIZED BORROWING COSTS
Borrowing costs attributable to the acquisition, construction or production of qualifying assets are capitalized to the cost of
those assets until such time as the assets are substantially available for their intended use. Qualifying assets are comprised of
those significant assets that require a period greater than one year to be available for their intended use. All other borrowing
costs are recognized in net earnings.
(J) LEASES
Finance leases, which transfer substantially all of the risks and rewards incidental to ownership of the leased item to the
Company, are capitalized at the commencement of the lease term at the fair value of the leased property or, if lower, at the
present value of the minimum lease payments. Capitalized leased assets are depreciated over the shorter of the estimated
useful life of the asset or the lease term. Operating lease payments are recognized in net earnings over the lease term.
(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
64
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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.
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.
(O) INCOME TAX
The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and
liabilities are recognized based on the estimated tax effects of temporary differences in the carrying amount of assets and
liabilities in the consolidated financial statements and their respective tax bases.
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.
65
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 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.
(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 and 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.
66
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. The Company documents all derivative financial instruments that are formally designated as hedging transactions at the
inception of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the
hedging relationship is evaluated, both at inception of the hedge and on an ongoing basis.
The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil
and natural gas in order to protect its cash flow for its capital expenditure programs. The effective portion of changes in the
fair value of derivative commodity price contracts formally designated as cash flow hedges is initially recognized in other
comprehensive income and is reclassified to risk management activities in net earnings in the same period or periods in
which the commodity is sold or purchased. The ineffective portion of changes in the fair value of these designated contracts is
recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural
gas commodity price contracts are recognized in risk management activities in net earnings.
The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on certain
of its long-term debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of
the notional principal amounts on which the payments are based. Changes in the fair value of interest rate swap contracts
designated as fair value hedges and corresponding changes in the fair value of the hedged long-term debt are recognized in
interest expense in net earnings. Changes in the fair value of non-designated interest rate swap contracts are recognized in
risk management activities in net earnings.
Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt.
The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional
principal amounts on which the payments are based. Changes in the fair value of the foreign exchange component of cross
currency swap contracts designated as cash flow hedges related to the notional principal amounts are recognized in foreign
exchange gains and losses in net earnings. The effective portion of changes in the fair value of the interest rate component of
cross currency swap contracts designated as cash flow hedges is initially recognized in other comprehensive income and is
reclassified to interest expense when 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.
67
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. (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. Changes in Accounting Policies
Effective January 1, 2016, the Company adopted the 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. The Company adopted this amendment prospectively. Adoption of this
amended standard did not result in an impact to the Company’s consolidated financial statements.
3. Accounting Standards Issued But Not Yet Applied
In January 2016, 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.
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 this standard on its 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.
4. 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.
68
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. (C) INCOME TAXES
The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the
Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain
judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating
the realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is
uncertain. The Company recognizes a liability for a tax filing position based on its assessment of the probability that additional
taxes may ultimately 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 stock options granted under the Option Plan,
including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding
are remeasured for changes in the fair value of the liability.
(G) IDENTIFICATION OF CGUs
CGUs are defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely
independent of the cash inflows of other assets or groups of assets. The classification of assets into CGUs requires significant
judgement and interpretations with respect to the integration between assets, the existence of active markets, shared
infrastructures, and the way in which management monitors the Company’s operations.
(H) IMPAIRMENT OF ASSETS
The recoverable amount of a CGU or an individual asset has been determined as the higher of the CGU’s or the asset’s
fair value less costs 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.
(I) CONTINGENCIES
Contingencies are subject to measurement uncertainty as the related financial impact will only be confirmed by the outcome
of a future event. The assessment of contingencies requires the application of judgements and estimates including the
determination of whether a present obligation exists and the reliable estimation of the timing and amount of cash flows
required to settle the contingency.
5. Inventory
Product inventory
Materials and supplies
$
$
2016
263 $
426
689 $
2015
186
339
525
As a result of fluctuations in crude oil prices, the Company recorded a write-down of its product inventory of $73 million from
cost to net realizable value as at December 31, 2016 (2015 – $174 million).
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Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 6. Exploration and Evaluation Assets
Cost
At December 31, 2014
Additions
Transfers to property, plant and equipment
Disposals/derecognitions (1)
Foreign exchange adjustments
At December 31, 2015
Additions
Transfers to property, plant and equipment
Disposals/derecognitions
Foreign exchange adjustments
At December 31, 2016
Exploration and Production
North
America
North
Sea
Offshore
Africa
Oil Sands
Mining and
Upgrading
Total
$
3,426 $
– $
131 $
– $
3,557
132
(567)
(491)
–
2,500
20
(211)
(3)
–
–
–
–
–
–
–
–
–
–
35
–
(96)
16
86
9
–
(18)
(1)
–
–
–
–
–
–
–
–
–
167
(567)
(587)
16
2,586
29
(211)
(21)
(1)
$
2,306 $
– $
76 $
– $
2,382
(1) Refer to note 7 regarding the disposition of exploration and evaluation assets in the North America segment in 2015.
During 2016, the Company disposed of a number of North America exploration and evaluation assets totaling $3 million for
consideration of $35 million, resulting in a pre-tax gain on sale of properties of $32 million. In addition, in connection with the
Company’s notice of withdrawal from Block CI-12 in Côte d’Ivoire, Offshore Africa, the Company derecognized $18 million of
exploration and evaluation assets.
During 2015, in connection with the Company’s notice of withdrawal from Block CI-514 in Côte d’Ivoire, Offshore Africa, the
Company derecognized $96 million of exploration and evaluation assets.
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Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
7. 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, 2014
$ 60,606 $ 6,182 $ 3,858 $
21,948 $
570 $
352 $ 93,516
Additions
Transfers from E&E assets
Disposals/derecognitions
Foreign exchange adjustments and other
At December 31, 2015
Additions
Transfers from E&E assets
Disposals/derecognitions
Foreign exchange adjustments and other
691
567
(1,324)
–
60,540
1,462
211
(566)
–
13
–
–
1,219
7,414
186
–
–
524
2,523
–
–
791
5,173
116
–
–
–
(128)
–
24,343
2,822
–
7
–
–
–
577
6
–
(220)
(157)
–
–
(127)
(349)
26
–
–
–
378
17
–
–
–
3,784
567
(1,452)
2,010
98,425
4,609
211
(1,042)
(377)
At December 31, 2016
$ 61,647 $ 7,380 $ 5,132 $
27,038 $
234 $
395 $ 101,826
Accumulated depletion
and depreciation
At December 31, 2014
Expense
Disposals/derecognitions
Foreign exchange adjustments and other
At December 31, 2015
Expense
Disposals/derecognitions
Foreign exchange adjustments and other
$ 31,886 $ 4,049 $ 2,890 $
1,864 $
120 $
227 $ 41,036
4,226
(758)
(7)
35,347
3,440
(486)
10
383
–
832
5,264
457
–
177
–
592
3,659
243
–
(137)
(105)
562
(128)
(4)
2,294
662
(127)
(1)
12
–
–
132
11
(28)
–
27
–
–
254
27
–
–
5,387
(886)
1,413
46,950
4,840
(641)
(233)
At December 31, 2016
$ 38,311 $ 5,584 $ 3,797 $
2,828 $
115 $
281 $ 50,916
Net book value
– at December 31, 2016
– at December 31, 2015
$ 23,336 $ 1,796 $ 1,335 $
24,210 $
$ 25,193 $ 2,150 $ 1,514 $
22,049 $
119 $
445 $
114 $ 50,910
124 $ 51,475
Project costs not subject to depletion and depreciation
Horizon
Kirby Thermal Oil Sands – North
2016
2015
– $
6,017
846 $
816
$
$
During 2016, 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 $nil (2015 – $37 million; 2014 – $nil), for net cash
consideration of $159 million (2015 – $406 million; 2014 – $3,753 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 $30 million (2015 – $133 million; 2014 – $404 million), other long-term liabilities of $nil (2015 – $nil; 2014 – $49 million)
and recognized net deferred income tax assets of $nil (2015 – $nil; 2014 – $91 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 (2015 – $nil; 2014 – $28 million). No pre-tax gains were recognized on these acquisitions in 2016
(2015 – $nil; 2014 – $137 million).
On December 16, 2016, in the Midstream segment, the Company disposed of its interest in the Cold Lake Pipeline, comprising
$321 million of property, plant and equipment for total net consideration of $539 million, resulting in a pre-tax gain of
$218 million. Total net consideration was comprised of $349 million in cash, together with $190 million of non-cash share
consideration of approximately 6.4 million common shares of Inter Pipeline Ltd. (“Inter Pipeline”) with a value of $29.57 per
common share, determined as of the closing date.
During 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
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Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
in a pre-tax gain on sale of properties of $690 million. Total consideration 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.
In addition, during 2015 the Company disposed of a number of other 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, 2016, 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 2016, pre-tax interest of $233 million (2015 – $244 million, 2014 – $204 million) was capitalized to property, plant and
equipment using a weighted average capitalization rate of 3.9% (2015 – 3.9%, 2014 – 3.9%).
Investments
8.
As at December 31, 2016, the Company had the following investments:
Investment in PrairieSky Royalty Ltd.
Investment in Inter Pipeline Ltd.
$
$
2016
723 $
190
913 $
2015
974
–
974
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 7). PrairieSky is in the business of
acquiring and managing oil and gas royalty income assets through indirect third-party oil and gas development.
During 2016, the Company completed the net distribution of approximately 21.8 million PrairieSky common shares to the
shareholders of record of the Company as at June 3, 2016, completing the previously announced Plan of Arrangement. The
distribution was recognized as a return of capital of $546 million. Subsequent to the distribution, the Company’s ownership
interest in PrairieSky was less than 10% of the issued and outstanding common shares of PrairieSky.
The Company’s remaining investment of approximately 22.6 million common shares does not constitute significant influence,
and is accounted for at fair value through profit or loss, remeasured at each reporting date. As at December 31, 2016, the
Company’s investment in PrairieSky was classified as a current asset.
The (gain) loss from the investment in PrairieSky was comprised as follows:
Fair value (gain) loss from PrairieSky
Dividend income from PrairieSky
$
$
2016
(292) $
(27)
(319) $
2015
2014
11 $
(5)
6 $
–
–
–
INVESTMENT IN INTER PIPELINE LTD.
On December 16, 2016, as partial consideration for the disposal of the Company’s interest in the Cold Lake Pipeline, the
Company received non-cash share consideration of $190 million, comprised of approximately 6.4 million common shares of
Inter Pipeline at $29.57 per common share determined as of the closing date (refer to Note 7). Inter Pipeline is in the business
of petroleum transportation, natural gas liquids processing, and bulk liquid storage in Western Canada and Europe.
The Company’s investment does not constitute significant influence, and is accounted for at fair value through profit or loss,
remeasured at each reporting date. As at December 31, 2016, the Company’s investment in Inter Pipeline was classified as
a current asset.
The gain from the investment in Inter Pipeline was comprised as follows:
Fair value gain from Inter Pipeline
Dividend income from Inter Pipeline
72
2016
2015
2014
$
$
– $
(1)
(1) $
– $
–
– $
–
–
–
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
9.
Other Long-Term Assets
Investment in North West Redwater Partnership
North West Redwater Partnership subordinated debt (1)
Risk Management (note 18)
Other
Less: current portion
(1) Includes accrued interest.
$
2016
261 $
385
489
168
1,303
283
$
1,020 $
2015
254
254
854
168
1,530
375
1,155
INVESTMENT IN NORTH WEST REDWATER PARTNERSHIP
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, committed each to provide funding up to $350 million by each party by January 2016
in the form of subordinated debt bearing interest at prime plus 6%. During 2016, the Company and APMC each provided $99 million
of subordinated debt. To date, each party has provided $324 million of subordinated debt, together with accrued interest thereon
of $61 million for a Company total of $385 million. Should final Project costs exceed the sanction cost estimate of $8,500 million,
the Company and APMC have agreed, each with a 50% interest, to provide additional subordinated debt as required to reflect
an agreed debt to equity ratio and, 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 2016, Redwater Partnership issued $550 million of 4.25% series F senior secured bonds due June 2029, $500 million
of 4.75% series G senior secured bonds due June 2037, $500 million of 4.15% series H senior secured bonds due June 2033,
and $500 million of 4.35% series I senior secured bonds due January 2039.
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, 2016, Redwater Partnership had additional borrowings of $1,581 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 (income) loss related to Redwater Partnership and the Company’s
50% interest at December 31, 2016 and 2015 were comprised as follows:
2016
2015
Redwater
Partnership
Company
Redwater
Partnership
Company
50% interest
100% interest
50% interest
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Partners’ equity
Equity (income) loss
100% interest
$
96 $
$
$
$
$
$
8,258 $
572 $
7,260 $
522 $
(14) $
48 $
4,129 $
286 $
3,630 $
261 $
(7) $
138 $
5,834 $
678 $
4,786 $
508 $
88 $
69
2,917
339
2,393
254
44
73
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
10. Long-Term Debt
Canadian dollar denominated debt, unsecured
Bank credit facilities
Medium-term notes
3.05% debentures due June 19, 2019
2.60% debentures due December 3, 2019
2.89% debentures due August 14, 2020
3.31% debentures due February 11, 2022
3.55% debentures due June 3, 2024
US dollar denominated debt, unsecured
Bank credit facilities (December 31, 2016 – US$905 million;
December 31, 2015 – US$657 million)
Commercial paper (December 31, 2016 – US$250 million;
December 31, 2015 – US$500 million)
US dollar debt securities
Three-month LIBOR plus 0.375% due March 30, 2016
(2016 – US$nil; 2015 – US$500 million)
6.00% due August 15, 2016 (2016 – US$nil; 2015 – 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)
2016
2015
$
2,758 $
2,385
500
500
1,000
1,000
500
6,258
1,213
336
—
—
1,477
806
537
671
671
806
537
470
470
604
1,477
537
10,612
16,870
(10)
(55)
16,805
336
1,476
$
14,993 $
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
15,065
(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, 2016, the Company had in place bank credit facilities of $7,350 million available for general corporate
purposes, comprised of:
a $100 million demand credit facility;
a $1,500 million non-revolving term credit facility maturing April 2018;
a $750 million non-revolving term credit facility maturing February 2019;
a $125 million non-revolving term credit facility maturing February 2019;
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 2016 Annual ReportPremium Value. Defined Growth. Independent.
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 2016, the Company prepaid $250 million of the previously outstanding $1,000 million non-revolving term credit facility and
extended the maturity date to February 2019 from January 2017. Borrowings under this facility may be made by way of pricing
referenced to Canadian dollar bankers’ acceptances or Canadian prime loans. As at December 31, 2016, the $750 million facility
was fully drawn. During 2016, the Company also entered into a new $125 million non-revolving term credit facility maturing
February 2019, which was fully drawn at December 31, 2016. Borrowings under this facility may be made by way of pricing
referenced to Canadian dollar bankers’ acceptances or Canadian prime loans.
Borrowings under the $1,500 million non-revolving credit 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. As at December 31, 2016, the $1,500 million
facility was fully drawn.
The Company's credit facilities are 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.
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,
2016 was 1.9% (December 31, 2015 – 1.7%), and on total long-term debt outstanding for the year ended December 31, 2016
was 3.9% (December 31, 2015 – 3.9%).
At December 31, 2016, letters of credit and guarantees aggregating $219 million, including a $39 million financial guarantee
related to Horizon and $82 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 2016, the Company issued $1,000 million of 3.31% medium-term notes due February 2022. After issuing these
securities, the Company has $2,000 million remaining on its 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 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.
US DOLLAR DEBT SECURITIES
During 2016, the Company repaid US$500 million of three-month LIBOR plus 0.375% notes and US$250 million of 6.00% 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
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.
SCHEDULED DEBT REPAYMENTS
Scheduled debt repayments are as follows:
Year
2017
2018
2019
2020
2021
Thereafter
Repayment
1,813
2,841
2,705
1,768
671
7,072
$
$
$
$
$
$
75
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 11. Other Long-Term Liabilities
Asset retirement obligations
Share-based compensation
Other
Less: current portion
2016
$
3,243 $
426
17
3,686
463
$
3,223 $
2015
2,950
128
18
3,096
206
2,890
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 5.2% (2015 – 5.9%; 2014 – 4.6%). 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
2016
2015
$
2,950 $
4,221 $
3
30
(267)
142
(68)
493
(40)
3,243
95
7
129
(370)
173
(313)
(1,150)
253
2,950
101
$
3,148 $
2,849 $
2014
4,162
41
404
(346)
193
(907)
558
116
4,221
121
4,100
2016
2015
$
1,444 $
1,114
837
244
717
1
975
266
594
1
$
3,243 $
2,950
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 expense (recovery)
Cash payment for stock options surrendered
Transferred to common shares
Capitalized to (recovered from) Oil Sands Mining and Upgrading
Balance – end of year
Less: current portion
$
2016
128 $
2015
203 $
355
(7)
(117)
67
426
368
(46)
(1)
(18)
(10)
128
105
$
58 $
23 $
2014
260
66
(8)
(129)
14
203
158
45
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Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. The share-based compensation liability of $426 million at December 31, 2016 (2015 – $128 million; 2014 – $203 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.
$
$
2016
11.41 $
42.79 $
30.7%
2.3%
0.9%
5.0%
2015
3.06 $
30.22 $
28.6%
3.0%
0.6%
4.8%
2014
5.51
35.92
25.1%
2.5%
1.2%
4.7%
4.6 years
4.5 years
4.5 years
The intrinsic value of vested stock options at December 31, 2016 was $191 million (2015 – $10 million; 2014 – $40 million).
12. Income Taxes
The provision for income tax was as follows:
Current corporate income tax (recovery) expense – North America
$
2016
(377) $
2015
86 $
Current corporate income tax recovery – North Sea
Current corporate income tax expense – Offshore Africa
Current PRT (1) recovery – North Sea
Other taxes
Current income tax (recovery) expense
Deferred corporate income tax (recovery) expense
Deferred PRT (1) (recovery) expense – North Sea
Deferred income tax (recovery) expense
(74)
22
(198)
9
(618)
(106)
(135)
(241)
(117)
17
(258)
11
(261)
216
15
231
2014
702
(68)
43
(273)
23
427
681
126
807
Income tax (recovery) expense
$
(859) $
(30) $
1,234
(1) Petroleum Revenue Tax.
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 (loss) 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
Change in unrecognized capital loss carryforward asset
Other
Income tax (recovery) expense
2016
27.0%
2015
26.0%
$
(287) $
(173) $
(324)
131
(54)
(80)
94
(107)
–
(120)
(80)
(32)
(232)
119
(157)
36
(12)
362
–
32
36
(41)
2014
25.1%
1,296
(124)
85
(61)
36
14
–
(34)
5
36
(19)
$
(859) $
(30) $
1,234
77
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
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
$
10,259 $
10,257
2016
2015
Timing of partnership items
Unrealized risk management activities
Deferred PRT
PRT deduction for corporate income tax
Investments
Investment in North West Redwater
Deferred income tax assets
Asset retirement obligations
Loss carryforwards
Unrealized foreign exchange loss on long-term debt
Deferred PRT
PRT deduction for corporate income tax
Other
–
62
–
29
98
222
10,670
(983)
(390)
(149)
(73)
–
(2)
(1,597)
Net deferred income tax liability
$
9,073 $
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
$
2016
37 $
2015
(7) $
Timing of partnership items
Unrealized foreign exchange loss on long-term debt
Unrealized risk management activities
Asset retirement obligations
Loss carryforwards
Investments
Investment in North West Redwater
Deferred PRT
PRT deduction for corporate income tax
Other
(261)
63
(44)
(20)
(221)
38
81
(135)
61
160
(176)
(222)
(5)
522
(53)
60
106
15
(5)
(4)
$
(241) $
231 $
The following table summarizes the movements of the net deferred income tax liability during the year:
Balance – beginning of year
Deferred income tax (recovery) expense
Deferred income tax (recovery) expense included in other
comprehensive income
Foreign exchange adjustments
Business combinations
Balance – end of year
2016
2015
$
9,344 $
8,970 $
(241)
(5)
(25)
–
231
(4)
147
–
$
9,073 $
9,344 $
8,970
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 2016, the UK government enacted legislation to reduce the supplementary charge on oil and gas profits from 20% to
10% effective January 1, 2016, resulting in a decrease in the Company’s deferred corporate income tax liability of $107 million.
During 2016, the UK government enacted legislation to reduce the PRT rate from 35% to 0% effective January 1, 2016.
Allowable abandonment expenditures eligible for carryback to 2015 and prior taxation years for PRT purposes are still
78
261
111
65
–
60
141
10,895
(976)
(170)
(212)
–
(33)
(160)
(1,551)
9,344
2014
647
(195)
(77)
142
119
109
–
35
126
(77)
(22)
807
2014
8,183
807
1
70
(91)
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
recoverable at a PRT rate of 50%. As a result of these income tax changes, the Company’s deferred PRT liability was reduced
by $228 million and the deferred corporate income tax liability was increased by $114 million.
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 were 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.
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.
13. Share Capital
AUTHORIZED
Preferred shares issuable in a series.
Unlimited number of common shares without par value.
ISSUED
Common shares
Balance – beginning of year
2016
2015
Number
of shares
(thousands)
Number
of shares
(thousands)
Amount
Amount
1,094,668 $
4,541
1,091,837 $
4,432
Issued upon exercise of stock options
16,284
559
2,831
Previously recognized liability on stock options exercised for
common shares
Return of capital on PrairieSky Royalty Ltd. share distribution (note 8)
–
–
117
(546)
–
–
91
18
–
Balance – end of year
1,110,952 $
4,671
1,094,668 $
4,541
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.
79
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
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 1, 2017, the Board of Directors declared a quarterly dividend of $0.275 per common share, beginning with
the dividend payable on April 1, 2017. On November 2, 2016, the Board of Directors declared a quarterly dividend of
$0.25 per common share, beginning with the dividend payable on January 1, 2017. 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.
NORMAL COURSE ISSUER BID
On March 1, 2017, the Board of Directors approved the Company's application for 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, up to 27,814,309 common shares, over a 12 month period commencing upon receipt of applicable regulatory and
other approvals.
During 2016 and 2015, the Company did not purchase any common shares for cancellation. In 2014, the Company purchased
for cancellation 10,095,000 common shares at a weighted average price of $44.85 per common share, for a total cost of
$453 million. Retained earnings were reduced by $414 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, 2016 and 2015:
Outstanding – beginning of year
Granted
Surrendered for cash settlement
Exercised for common shares
Forfeited
Outstanding – end of year
Exercisable – end of year
2016
2015
Stock options
(thousands)
Weighted
average
exercise price
Stock options
(thousands)
Weighted
average
exercise price
74,615 $
11,002 $
(817) $
(16,284) $
(10,217) $
58,299 $
20,747 $
34.88
34.97
34.47
34.31
39.66
34.22
33.75
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
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Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
The range of exercise prices of stock options outstanding and exercisable at December 31, 2016 was as follows:
Stock options outstanding
Stock options exercisable
Range of exercise prices
$22.90 – $24.99
$25.00 – $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
(thousands)
Weighted
average
exercise price
4,188
14,101
14,599
13,342
10,656
1,413
58,299
exercise price
22.90
4.03 $
2.69 $
2.46 $
2.29 $
4.29 $
2.10 $
2.92 $
28.58
33.20
36.17
43.66
45.07
34.22
666 $
5,574 $
5,744 $
6,680 $
1,257 $
826 $
20,747 $
14. Accumulated Other Comprehensive Income
The components of accumulated other comprehensive income (loss), net of taxes, were as follows:
Derivative financial instruments designated as cash flow hedges
Foreign currency translation adjustment
$
$
2016
27 $
43
70 $
22.90
28.41
33.45
36.36
43.25
45.06
33.75
2015
58
17
75
15. Capital Disclosures
The Company does not have any externally imposed regulatory capital requirements for managing capital. The Company has
defined its capital to mean its long-term debt and consolidated shareholders’ equity, as determined at each reporting date.
The Company’s objectives when managing its capital structure are to maintain financial flexibility and balance to enable the
Company to access capital markets to sustain its on-going operations and to support its growth strategies. The Company
primarily monitors capital on the basis of an internally derived financial measure referred to as its “debt to book capitalization
ratio“, which is the arithmetic ratio of current and long-term debt divided by the sum of the carrying value of shareholders’
equity plus current and long-term debt. The Company’s internal targeted range for its debt to book capitalization ratio is 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, 2016, the ratio was within the target range at 39%.
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.
$
$
2016
16,805 $
26,267 $
39%
2015
16,794
27,381
38%
81
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
16. 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
2016
2015
2014
1,100,471
1,093,862
1,091,754
–
–
5,068
1,100,471
1,093,862
1,096,822
$
$
$
(204) $
(0.19) $
(0.19) $
(637) $
(0.58) $
(0.58) $
3,929
3.60
3.58
In 2016, the Company excluded 27,235,000 potentially anti-dilutive stock options from the calculation of diluted earnings per
common share.
17. Interest and Other Financing Expense
2016
2015
2014
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
$
664 $
618 $
–
664
233
431
(48)
1
619
244
375
(53)
Net interest and other financing expense
$
383 $
322 $
(1) Includes the fair value impact of interest rate swaps on US dollar debt securities.
18. Financial Instruments
The carrying amounts of the Company’s financial instruments by category were as follows:
Asset (liability)
amortized cost
or loss
Financial
assets at
Fair value
through profit
Accounts receivable
$
1,434 $
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Long-term debt (1)
–
385
–
–
–
– $
913
4
–
–
–
2016
Derivatives
used for
hedging
Financial
liabilities at
amortized cost
– $
– $
–
485
–
–
–
–
–
(595)
(2,222)
(16,805)
$
1,819 $
917 $
485 $
(19,622) $
Financial
assets at
Fair value
through profit
or loss
2015
Derivatives
used for
hedging
Financial
liabilities at
amortized cost
Asset (liability)
Accounts receivable
Investments
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) $
(1) Includes the current portion of long-term debt.
82
542
(7)
535
204
331
(8)
323
Total
1,434
913
874
(595)
(2,222)
(16,805)
(16,401)
Total
1,277
974
1,108
(571)
(2,089)
(16,794)
(16,095)
Canadian Natural 2016 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. The fair values of the Company’s recurring other long-term assets and fixed rate long-term debt are outlined below:
Asset (liability) (1) (2)
Investments (3)
Other long-term assets (4)
Fixed rate long-term debt (5) (6)
Asset (liability) (1) (2)
Investments (3)
Other long-term assets (4)
Fixed rate long-term debt (5) (6)
Carrying
amount
2016
Fair value
Level 1
Level 2
Level 3
913 $
874 $
913 $
– $
(12,498) $
(13,217) $
– $
489 $
– $
–
385
–
Carrying
amount
2015
Fair value
Level 1
Level 2
Level 3
974 $
1,108 $
974 $
– $
(12,808) $
(12,431) $
– $
854 $
– $
–
254
–
$
$
$
$
$
$
(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 investments are based on quoted market prices.
(4) The fair value of 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
Foreign currency forward contracts
Natural gas AECO swaps
Cash flow hedges
Foreign currency forward contracts
Cross currency swaps
Included within:
Current portion of other long-term assets
Other long-term assets
2016
2015
10 $
(6)
16
469
489 $
222 $
267
489 $
36
–
30
788
854
305
549
854
$
$
$
$
During 2016, the Company recognized a gain of $7 million (2015 – gain of $5 million, 2014 – loss of $3 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 as
applicable, including crude oil and natural gas forward benchmark commodity prices and volatility, Canadian and United States
forward interest rate yield curves, and Canadian and United States foreign exchange rates, discounted to present value as
appropriate. The resulting fair value estimates may not necessarily be indicative of the amounts that could be realized or
settled in a current market transaction and these differences may be material.
83
Canadian Natural 2016 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 were recognized
in the financial statements as follows:
Asset (liability)
Balance – beginning of year
Net change in fair value of outstanding derivative financial instruments recognized in:
Risk management activities
Foreign exchange
Other comprehensive income (loss)
Balance – end of year
Less: current portion
$
2016
854 $
(25)
(304)
(36)
489
222
$
267 $
Net losses (gains) from risk management activities for the years ended December 31 were as follows:
Net realized risk management loss (gain)
Net unrealized risk management loss (gain)
$
$
2016
8 $
25
33 $
2015
(843) $
374
(469) $
2015
599
(374)
669
(40)
854
305
549
2014
(349)
(451)
(800)
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,
2016, the Company had the following derivative financial instruments outstanding to manage its commodity price risk:
Sales contracts (1)
Natural Gas
AECO swaps
Remaining term
Volume
Weighted Average Price
Index
Jan 2017 – Oct 2017
50,000 GJ/d
$2.80
AECO
(1) Subsequent to December 31, 2016, the Company entered into 50,000 bbl/d of US$50.00 – US$60.10 WTI collars for the period February to December 2017,
and 17,500 bbl/d of US$50.00 – US$60.03 WTI collars for the period March to December 2017.
The Company’s outstanding commodity derivative financial instruments are expected to be settled monthly based on the
applicable index pricing for the respective contract month.
INTEREST RATE RISK MANAGEMENT
The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company periodically enters into interest rate swap contracts to manage its fixed to floating
interest rate mix on long-term debt. Interest rate swap contracts require the periodic exchange of payments without the
exchange of the notional principal amounts on which the payments are based. At December 31, 2016, the Company had no
interest rate swap contracts outstanding.
84
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated
long-term debt, commercial paper and working capital. The Company is also exposed to foreign currency exchange rate risk
on transactions conducted in other currencies and in the carrying value of its foreign subsidiaries. The Company periodically
enters into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on
US dollar denominated long-term debt, commercial paper and working capital. The cross currency swap contracts require the
periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based.
At December 31, 2016, the Company had the following cross currency swap contracts outstanding:
Cross currency
Swaps
Remaining term
Amount
Exchange
rate (US$/C$)
Interest
rate (US$)
Interest
rate (C$)
Jan 2017 – May 2017
US$1,100
Jan 2017 – Nov 2021
Jan 2017 – Mar 2038
US$500
US$550
1.170
1.022
1.170
5.70%
3.45%
6.25%
5.10%
3.96%
5.76%
All cross currency swap derivative financial instruments were designated as hedges at December 31, 2016 and were classified
as cash flow hedges.
In addition to the cross currency swap contracts noted above, at December 31, 2016, the Company had US$1,928 million
of foreign currency forward contracts outstanding, with terms of approximately 30 days or less, including US$1,155 million
designated as cash flow hedges.
FINANCIAL INSTRUMENT SENSITIVITIES
The following table summarizes the annualized sensitivities of the Company’s 2016 net loss and other comprehensive loss to
changes in the fair value of financial instruments outstanding as at December 31, 2016, resulting from changes in the specified
variable, with all other variables held constant. These sensitivities are prepared on a different basis than those sensitivities
disclosed in the Company’s other continuous disclosure documents, are limited to the impact of changes in a specified
variable applied to financial instruments only and do not represent the impact of a change in the variable on the operating
results of the Company taken as a whole. Further, these sensitivities are theoretical, as changes in one variable may contribute
to changes in another variable, which may magnify or counteract the sensitivities. In addition, changes in fair value generally
cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear.
(Increase) decrease
(Increase) decrease
to other
to net loss
comprehensive loss
Commodity price risk
Increase AECO $0.10/Mcf
Decrease AECO $0.10/Mcf
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
$
$
$
$
$
$
(1) $
1 $
(19) $
19 $
(73) $
71 $
–
–
(27)
31
–
–
85
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
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, 2016, 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, 2016, the Company had net risk management assets
of $489 million with specific counterparties related to derivative financial instruments (December 31, 2015 – $854 million).
The carrying amount of financial assets approximates the maximum credit exposure.
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities.
Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources
of capital, consisting primarily of cash flow from operating activities, available credit facilities, 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
$
$
$
595 $
2,222 $
1,813 $
– $
– $
– $
– $
–
–
2,841 $
5,144 $
7,072
(1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
19. 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
$
$
$
$
2017
2018
2019
2020
2021
Thereafter
441 $
404 $
306 $
300 $
258 $
2,337
166 $
105 $
44 $
53 $
43 $
2 $
59 $
43 $
2 $
34 $
43 $
2 $
33 $
40 $
2 $
9
154
35
In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering,
procurement and construction of Horizon. These contracts can be cancelled by the Company upon notice without penalty,
subject to the costs incurred up to and in respect of the cancellation.
The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition,
the Company is subject to certain contractor construction claims. The Company believes that any liabilities that might arise
pertaining to any such matters would not have a material effect on its consolidated financial position.
86
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
20. Supplemental Disclosure of Cash Flow Information
2016
2015
2014
Changes in non-cash working capital
Accounts receivable
Current income tax assets
Inventory
Prepaids and other
Accounts payable
Accrued liabilities
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) (2)
Net expenditures on property, plant and equipment
$
$
$
$
$
$
$
$
(142) $
615 $
(165)
(79)
14
31
(116)
(457) $
(447)
142
11
7
(981)
(653) $
(542) $
239 $
–
85
(40)
(852)
(457) $
(653) $
2016
29 $
(35)
(6) $
2015
180 $
(416)
(236) $
(456)
(586)
(31)
(30)
(70)
741
(432)
(744)
(22)
334
(432)
2014
1,190
–
1,190
4,152 $
5,118 $
10,252
(349)
(414)
(44)
3,803 $
4,704 $
10,208
(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.
(2) Net expenditures on property, plant and equipment in 2016 exclude non-cash share consideration of $190 million received from Inter Pipeline on the
disposition of the Company’s interest in the Cold Lake Pipeline.
87
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. 21. 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.
Segmented product sales
$ 7,209 $ 9,222 $ 15,963 $ 570 $ 638 $
701 $ 603 $ 482 $ 503
$ 2,657 $ 2,764 $ 4,095 $
114 $
136 $
120 $
(55) $
(75) $
(81) $ 11,098 $ 13,167 $ 21,301
2016
2015
2014
2016
2015
2014
2016
2015
2014
2016
2015
2014
2016
2015
2014
2016
2015
2014
2016
2014
North America
North Sea
Offshore Africa
Oil Sands Mining
and Upgrading
Midstream
and other
Inter–segment elimination
Exploration and Production
Less: royalties
Segmented revenue
Segmented expenses
Production
Transportation and blending
Depletion, depreciation
and amortization
Asset retirement
obligation accretion
Realized risk
management activities
Gain on disposition of properties
and corporate acquisitions
and dispositions
(Gain) loss from investments
(524)
(732)
(2,159)
6,685
8,490
13,804
2,186
1,941
2,603
2,309
2,924
3,228
(1)
569
403
48
(1)
637
544
61
(2)
699
496
5
(26)
577
200
2
(22)
460
223
2
(43)
460
212
1
(24)
(49)
(234)
2,633
2,715
3,861
–
114
–
136
1,292
1,332
1,609
80
82
75
3,465
4,248
3,901
458
388
269
262
273
105
662
562
596
66
93
98
35
39
38
12
10
10
29
31
47
8
(843)
(349)
(32)
(320)
(739)
(137)
6
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Total segmented expenses
7,314
7,677
9,665
944
1,032
808
476
508
328
2,063
2,007
2,327
51
(75)
(83)
(87)
10,533
11,229
13,092
–
120
34
–
9
–
–
–
8
–
(55)
(7)
(68)
–
–
–
–
–
–
(75)
(8)
(75)
–
–
–
–
–
25
–
11
–
–
(218)
(7)
(189)
32
–
12
–
–
–
44
88
$
(629) $
813 $ 4,139 $
(375) $
(395) $
(109) $
101 $
(48) $
132
$ 570 $ 708 $ 1,534 $ 303 $
48 $
69 $
20 $
8 $
6
(10)
1,134
5,771
Segmented earnings (loss)
before the following
Non-segmented expenses
Administration
Share-based compensation
Interest and other
financing expense
Unrealized risk
management activities
Foreign exchange (gain) loss
Total non-segmented
expenses
Earnings (loss) before taxes
Current income tax
(recovery) expense
Deferred income tax
(recovery) expense
Net earnings (loss)
88
Total
2015
–
(575)
(804)
(2,438)
(81)
10,523
12,363
18,863
(10)
(77)
4,099
2,003
4,726
2,379
5,265
3,232
–
–
–
–
–
4,858
5,483
4,880
142
173
193
8
(843)
(349)
(250)
(327)
(739)
50
(137)
8
345
355
390
(46)
367
66
383
322
323
25
(55)
374
761
(451)
303
1,053
1,801
608
(1,063)
(667)
5,163
(618)
(261)
427
(241)
231
807
$
(204) $
(637) $ 3,929
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
21. 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
The Company’s Oil Sands Mining and Upgrading activities are reported in a separate segment from exploration and
liquids and natural gas.
production activities.
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.
North America
North Sea
Offshore Africa
Oil Sands Mining
and Upgrading
Midstream
Inter–segment elimination
and other
2016
2015
2014
2016
2015
2014
2016
2015
2014
2016
2015
2014
2016
2015
2014
2016
2015
2014
2016
Total
2015
2014
Segmented product sales
$ 7,209 $ 9,222 $ 15,963 $ 570 $ 638 $
701 $ 603 $ 482 $ 503
$ 2,657 $ 2,764 $ 4,095 $
114 $
136 $
120 $
(55) $
(75) $
(81) $ 11,098 $ 13,167 $ 21,301
Exploration and Production
(524)
(732)
(2,159)
6,685
8,490
13,804
2,186
1,941
2,603
2,309
2,924
3,228
(1)
569
403
48
(1)
637
544
61
(2)
699
496
5
(26)
577
200
2
(22)
460
223
2
(43)
460
212
1
(24)
(49)
(234)
2,633
2,715
3,861
–
114
–
136
3,465
4,248
3,901
458
388
269
262
273
105
662
562
596
66
93
98
35
39
38
12
10
10
29
31
47
management activities
8
(843)
(349)
Gain on disposition of properties
and corporate acquisitions
and dispositions
(Gain) loss from investments
(32)
(320)
(739)
(137)
6
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Total segmented expenses
7,314
7,677
9,665
944
1,032
808
476
508
328
2,063
2,007
2,327
1,292
1,332
1,609
80
82
75
25
–
11
–
–
(218)
(7)
(189)
32
–
12
–
–
–
44
88
–
120
34
–
9
–
–
–
8
–
(55)
(7)
(68)
–
–
–
–
–
–
(75)
(8)
(75)
–
–
–
–
–
–
(575)
(804)
(2,438)
(81)
10,523
12,363
18,863
(10)
(77)
4,099
2,003
4,726
2,379
5,265
3,232
–
–
–
–
–
4,858
5,483
4,880
142
173
193
8
(843)
(349)
(250)
(327)
(739)
50
(137)
8
51
(75)
(83)
(87)
10,533
11,229
13,092
before the following
$
(629) $
813 $ 4,139 $
(375) $
(395) $
(109) $
101 $
(48) $
132
$ 570 $ 708 $ 1,534 $ 303 $
48 $
69 $
20 $
8 $
6
(10)
1,134
5,771
345
355
390
(46)
367
66
383
322
323
25
(55)
374
761
(451)
303
1,053
1,801
608
(1,063)
(667)
5,163
(618)
(261)
427
(241)
231
807
$
(204) $
(637) $ 3,929
89
Less: royalties
Segmented revenue
Segmented expenses
Production
Transportation and blending
Depletion, depreciation
and amortization
Asset retirement
obligation accretion
Realized risk
Segmented earnings (loss)
Non-segmented expenses
Administration
Share-based compensation
Interest and other
financing expense
Unrealized risk
management activities
Foreign exchange (gain) loss
Total non-segmented
expenses
Earnings (loss) before taxes
Current income tax
(recovery) expense
Deferred income tax
(recovery) expense
Net earnings (loss)
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Capital Expenditures (1)
Net
expenditures
(proceeds)
2016
Non-cash
and fair value
changes (2)
Net
2015
Non-cash
Capitalized
costs
expenditures
(proceeds) (3)
and fair value
changes (2)
Capitalized
costs
Exploration and
evaluation assets
Exploration and
Production
North America (4) (5) $
North Sea
Offshore Africa
17
$
(211)
$
(194)
$
(260)
$
(666)
$
–
9
–
(18)
–
(9)
–
35
–
(96)
$
26
$
(229)
$
(203)
$
(225)
$
(762)
$
Property, plant
and equipment
Exploration and
Production
North America (5)
North Sea
Offshore Africa
Oil Sands Mining
and Upgrading (6)
Midstream (7)
Head office
$
1,143
$
(36)
$
1,107
$
1,171
$
(1,237)
$
126
142
1,411
2,718
(315)
17
60
(26)
(2)
(23)
(28)
–
186
116
1,409
2,695
(343)
17
230
573
1,974
2,730
8
26
(217)
(49)
(1,503)
(335)
(1)
–
(926)
–
(61)
(987)
(66)
13
524
471
2,395
7
26
$
3,831
$
(53)
$
3,778
$
4,738
$
(1,839)
$
2,899
(1) This table provides a reconciliation of capitalized costs including derecognitions and does not include the impact of foreign exchange adjustments.
(2) Asset retirement obligations, deferred income tax adjustments related to differences between carrying amounts and tax values, transfers of exploration and
evaluation assets, transfers of property, plant and equipment to inventory due to change in use, and other fair value adjustments.
(3) 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.
(4) The above noted figures for 2016 do not include the impact of a pre-tax cash gain of $32 million on the disposition of exploration and evaluation assets.
(5) The above noted figures for 2015 do not include the impact of other pre-tax gains on the sale of other properties totaling $49 million recognized in 2015.
(6) Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest and share-based compensation.
(7) The above noted figures for 2016 do not include a pre-tax cash and non-cash gain of $218 million on the disposition of certain Midstream assets
2016
2015
$
28,892 $
30,937
2,269
1,580
29
24,852
912
114
$
58,648 $
2,734
1,755
73
22,598
1,054
124
59,275
to Inter Pipeline.
Segmented Assets
Exploration and Production
North America
North Sea
Offshore Africa
Other
Oil Sands Mining and Upgrading
Midstream
Head office
90
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
22. 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
$
$
$
$
$
$
2016
2 $
2015
2 $
2014
3
2016
2015
2014
3 $
9 $
5 $
15 $
32 $
3 $
7 $
2 $
6 $
18 $
3
8
4
17
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.
23. Event Subsequent to December 31, 2016
On March 9, 2017, the Company announced that it had entered into agreements to acquire 70% of the Athabasca Oil
Sands Project, as well as additional working interests in certain other producing and non-producing oil and gas properties,
for preliminary total consideration of approximately $12.7 billion, comprised of cash of approximately $8.7 billion
and 97,560,975 common shares of the Company, with an estimated value of approximately $4 billion as at the
announcement date. The transaction is expected to close in mid-2017, subject to receipt of all required consents and regulatory
and other approvals.
91
Canadian Natural 2016 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, 2016, 2015, 2014, and 2013 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, 2016,
2015, 2014, and 2013 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 2016 reserves for
SEC requirements.
Crude Oil and NGLs
Natural Gas
WTI Cushing
Oklahoma
(US$/bbl)
WCS
(C$/bbl)
Canadian
Light Sweet
(C$/bbl)
Cromer
LSB
(US$/bbl)
North Sea
Brent
(US$/bbl)
Edmonton
C5+
(C$/bbl)
Henry Hub
Louisiana
(US$/MMBtu)
AECO
(C$/MMBtu)
BC
Westcoast
Station 2
(C$/MMBtu)
42.75
38.13
52.08
50.64
44.49
55.36
2.55
2.17
1.66
A foreign exchange rate of US$1.00/C$1.3228 was used in the 2016 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, 2016, 2015, 2014, and 2013, 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, 2016, 2015, 2014, and 2013, 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 2016 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, 2016, 2015, 2014, and 2013:
Crude Oil and NGLs (MMbbl)
Oil Bitumen(1)
Synthetic
Crude
Crude
Oil &
NGLs
North
America
Total
North
Sea
Offshore
Africa
North America
Net Proved Reserves
Reserves, December 31, 2013
1,925
1,068
380
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
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
–
–
–
–
(38)
(89)
(18)
1,780
208
–
–
–
(44)
339
–
2,283
–
–
–
–
112
10
–
–
(76)
11
23
1,148
25
17
9
–
(84)
153
(5)
1,263
46
5
3
–
11
29
54
–
(40)
–
47
481
10
9
11
(7)
(44)
5
6
15
14
15
–
Production
(45)
(71)
(43)
Economic revisions due to prices
108
23
(19)
Revisions of prior estimates
Reserves, December 31, 2016
196 32
1,301
2,542
51
504
Net proved developed reserves
December 31, 2013
December 31, 2014
December 31, 2015
December 31, 2016
1,621
1,631
2,194
2,527
431
401
411
384
298
358
341
353
3,373
123
39
54
–
(154)
(78)
52
3,409
243
26
20
(7)
(172)
497
1
61
19
18
–
(159)
112
279
4,347
2,350
2,390
2,946
3,264
232
–
–
–
–
(6)
(9)
(6)
211
–
–
–
–
(8)
(51)
(33)
119
–
1
–
–
(9)
(10)
(8)
93
59
39
3
12
471
4,017
Total
3,685
123
39
54
–
(164)
(86)
46
3,697
243
26
20
(7)
(186)
448
(32)
4,209
61
22
18
–
80
–
–
–
–
(4)
1
–
77
–
–
–
–
(6)
2
–
73
–
2
–
–
(8)
(176)
1
6
74
30
21
41
31
103
277
4,514
2,439
2,450
2,990
3,307
(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 2016 Annual ReportPremium Value. Defined Growth. Independent. North
America
North
Sea
Offshore
Africa
3,234
119
443
1,229
–
(514)
576
(70)
5,017
237
242
344
(35)
(587)
(935)
240
4,523
176
166
85
(5)
(571)
(572)
792
4,594
2,342
3,585
2,883
2,805
92
–
–
–
–
(2)
(6)
–
84
–
–
–
–
(13)
(8)
(25)
38
–
–
–
–
(14)
(10)
11
25
72
64
26
18
37
–
–
–
–
(6)
1
2
34
–
–
–
–
(9)
3
(7)
21
–
3
–
–
(11)
1
11
25
27
22
15
18
Total
3,363
119
443
1,229
–
(522)
571
(68)
5,135
237
242
344
(35)
(609)
(940)
208
4,582
176
169
85
(5)
(596)
(581)
814
4,644
2,441
3,671
2,924
2,841
Natural Gas (Bcf)
Net Proved Reserves
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
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, 2016
Net proved developed reserves
December 31, 2013
December 31, 2014
December 31, 2015
December 31, 2016
94
Canadian Natural 2016 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
2016
North
America
North
Sea
Offshore
Africa
$
88,685 $
7,380 $
5,132 $
2,306
90,991
(41,139)
–
7,380
(5,584)
76
5,208
(3,797)
Net capitalized costs
$
49,852 $
1,796 $
1,411 $
(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 $
Total
101,197
2,382
103,579
(50,520)
53,059
Total
97,470
2,586
100,056
(46,564)
53,492
Total
92,594
3,557
96,151
(40,689)
55,462
95
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Costs Incurred in Crude Oil and Natural Gas Activities
2016
North
America
North
Sea
Offshore
Africa
$
50 $
– $
– $
–
17
4,125
$
4,192 $
–
9
116
125 $
–
–
186
186 $
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 $
–
–
485
486 $
–
87
193
280 $
Total
50
–
26
4,427
4,503
Total
(556)
(446)
122
3,382
2,502
Total
3,324
873
317
6,941
11,455
(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 2016 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,
2016, 2015, and 2014 are summarized in the following tables:
(millions of Canadian dollars)
Crude oil and natural gas revenue,
net of royalties and blending costs
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
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 (1)
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
2016
North
America
North
Sea
Offshore
Africa
$
7,791 $
565 $
577 $
(3,478)
(623)
(4,127)
(95)
–
143
(403)
(48)
(458)
(35)
333
18
(200)
(2)
(262)
(12)
–
(22)
$
(389) $
(28) $
79 $
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
8,933
(4,081)
(673)
(4,847)
(142)
333
139
(338)
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
Cote 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
2014
North
America
North
Sea
Offshore
Africa
$
15,385 $
696 $
460 $
(4,533)
(593)
(4,497)
(145)
–
(496)
(5)
(269)
(38)
147
(212)
(1)
(105)
(10)
–
$
(1,411)
4,206 $
(22)
13 $
(29)
103 $
Total
16,541
(5,241)
(599)
(4,871)
(193)
147
(1,462)
4,322
97
Canadian Natural 2016 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
2016
North
America
North
Sea
Offshore
Africa
Total
$
206,729 $
5,999 $
4,129 $
216,857
(92,070)
(3,284)
(1,659)
(97,013)
(42,167)
(15,396)
57,096
(33,590)
(3,249)
280
(254)
271
(1,234)
(125)
1,111
(319)
Standardized measure of future net cash flows
$
23,506 $
17 $
792 $
(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
$
225,032 $
10,258 $
4,936 $
(100,924)
(5,973)
(2,026)
(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 $
98
(46,650)
(15,241)
57,953
(33,638)
24,315
Total
240,226
(108,923)
(53,848)
(15,812)
61,643
(34,107)
27,536
Canadian Natural 2016 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
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 $
Total
355,739
(134,934)
(67,029)
(30,572)
123,204
(70,384)
52,820
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
2016
2015
2014
$
(4,159) $
(5,107) $
(10,321)
(7,305)
700
1,750
352
(2)
3,668
3,527
(2,137)
385
(3,221)
27,536
(43,489)
3,201
5,204
624
(165)
5,298
6,645
(3,452)
5,957
(25,284)
52,820
$
24,315 $
27,536 $
8,575
4,428
(2,821)
4,425
–
(1,306)
5,154
5,895
(1,051)
12,978
39,842
52,820
99
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
Ten-Year Review
2015
2016
Years ended December 31
FINANCIAL INFORMATION (1) (Cdn $ millions, except per share amounts)
Net earnings (loss)
Per share - basic
Per share - diluted
Funds flow from operations (2)
Per share - basic
Per share - diluted
Capital expenditures, net of dispositions
(including business combinations)
(637)
(0.58) $
(0.58) $
5,785
5.29 $
5.28 $
(204)
(0.19) $
(0.19) $
4,293
3.90 $
3.89 $
3,794
3,853
$
$
$
$
2014
2013
2012
2011
2010 (7)
2009 (8)
2008 (8)
2007 (8)
3,929
3.60 $
3.58 $
2,270
1,892
2,643
1,673
1,580
4,985
2.08 $
2.08 $
1.72 $
1.72 $
2.41 $
2.40 $
1.54 $
1.53 $
1.46 $
1.46 $
4.61 $
4.61 $
9,587
7,477
6,013
6,547
6,333
6,090
6,969
8.78 $
8.74 $
6.87 $
6.86 $
5.48 $
5.47 $
5.98 $
5.94 $
5.82 $
5.78 $
5.62 $
5.62 $
6.45 $
6.45 $
2,608
2.42
2.42
6,198
5.75
5.75
11,744
7,274
6,308
6,414
5,514
2,997
7,451
6,425
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
1,056
2,382
50,910
58,648
16,805
26,267
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
1,110,952 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
- basic (thousands)
1,100,471 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
Weighted average shares outstanding
- diluted (thousands)
Dividends declared ($/share) (3)
Trading statistics (1)
TSX – C$
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 (4)
Return on average common
1,100,471 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
0.17
$
0.575 $
0.94 $
0.36 $
0.30 $
0.20 $
0.90 $
0.92 $
0.21 $
0.42 $
653,727
728,033
717,580
683,003
729,700
800,044
661,832 1,040,320 1,359,476
858,068
$
$
$
46.74 $
21.27 $
42.79 $
42.46 $
25.01 $
30.22 $
49.57 $
31.00 $
35.92 $
36.04 $
28.44 $
35.94 $
41.12 $
25.58 $
28.64 $
50.50 $
27.25 $
38.15 $
45.00 $
31.97 $
44.35 $
39.50 $
17.93 $
38.00 $
55.65 $
17.10 $
24.38 $
40.01
26.23
36.29
892,220
951,311
812,521
645,403
844,647
937,481
759,327 1,514,614 1,934,456
972,532
$ 35.28 $
14.60 $
$
31.88 $
$
34.46 $
18.94 $
21.83 $
46.65 $
26.53 $
30.88 $
33.92 $
26.98 $
33.84 $
41.38 $
25.01 $
28.87 $
52.04 $
25.69 $
37.37 $
44.77 $
30.00 $
44.42 $
38.26 $
13.85 $
35.98 $
54.66 $
13.22 $
19.99 $
43.59
22.28
36.57
39%
38%
33%
27%
26%
27%
29%
33%
41%
45%
shareholders’ equity, after tax (4)
(1%)
(2%)
14%
Daily production before royalties per ten
thousand common shares (BOE/d) (1)
Total proved plus probable reserves per
7.3
7.8
7.2
9%
6.2
8%
6.0
12%
8%
8%
33%
22%
5.5
5.8
5.3
5.2
5.7
common share (BOE) (1)(5)
Net asset value ($/share) (1)(6)
8.3
74.77 $
8.3
73.39 $
8.1
78.99 $
7.3
72.41 $
7.2
62.38 $
6.9
70.37 $
6.3
64.58 $
5.8
64.92 $
3.1
39.89 $
3.2
34.47
$
(1) Restated to reflect two-for-one share split in May 2010.
(2) Funds flow from operations is a non-GAAP measure that represents net earnings (loss) as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for certain
non-cash items and current income tax on disposition of properties. Funds flow from operations can also be derived by adjusting the GAAP measure Cash Flows from Operating
Activities presented in the Company's consolidated Statements of Cash Flows for the net change in non-cash working capital, and abandonment and other expenditures.
(3) On March 1, 2017, the Board of Directors approved a quarterly dividend of $0.275 per common share, beginning with the dividend payable on April 1, 2017.
(4) Refer to the "Liquidity and Capital Resources" section of the MD&A for the definitions of these items.
(5) 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.
(6) 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, 2016) 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 (2016 to 2015, $300/acre for core unproved property from 2014 to 2010, $250/acre for core undeveloped land from 2009 to 2007), 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.
(7) 2010 comparative figures have been restated in accordance with IFRS issued at December 31, 2011.
(8) Comparative figures for years prior to 2010 are in accordance with Canadian GAAP as previously reported and may not be prepared on a basis consistent with IFRS as adopted.
100
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent.
2016
2015
2014
2013
2012
2011
2010 (7)
2009 (8)
2008 (8)
2007 (8)
Years ended December 31
OPERATING INFORMATION
Crude oil and NGLs (MMbbl) (9)
Company net proved reserves (after royalties)
North America
North Sea
Offshore Africa
Horizon SCO (9)
Company net proved plus probable reserves (after royalties)
North America
North Sea
Offshore Africa
Horizon SCO (9)
Natural gas (Bcf) (9)
Company net proved reserves (after royalties)
North America
North Sea
Offshore Africa
Company net proved plus probable reserves (after royalties)
North America
North Sea
Offshore Africa
7,888
85
55
8,028
3,909
134
74
4,117
-
6,015
252
108
6,375
-
5,845
41
23
5,909
3,645
158
74
3,877
-
5,806
284
113
6,203
-
5,383
39
21
5,443
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
Total net proved reserves
(after royalties) (MMBOE)
Total net proved plus probable reserves
5,102
4,784
4,524
4,230
4,191
3,977
3,748
3,557
1,960
1,969
(after royalties) (MMBOE)
7,713
7,454
7,198
6,471
6,426
6,147
5,666
5,440
2,996
2,937
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)
351
123
24
26
524
1,622
38
31
1,691
806
36.93
2.32
58.59
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
77.04
4.83
100.27
344
100
18
16
478
1,130
4
24
1,158
671
73.81
3.30
99.18
326
86
20
19
451
1,198
2
20
1,220
655
72.44
2.70
90.74
296
271
234
244
247
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
82.41
8.39
-
55.45
6.85
-
(9) For the years 2010 to 2016, 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 2016, product prices reflect realized product prices before transportation costs. Prior to 2011, product prices were reported net of transportation costs.
101
Canadian Natural 2016 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)
Corporate Director
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
Darren M. Fichter
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
Allan E. Frankiw
Senior Vice-President, Production
Ron K. Laing
Senior Vice-President, Corporate Development and Land
Bill R. Peterson
Senior Vice-President, Development Operations
Ken W. Stagg
Senior Vice-President, Exploration
Scott G. Stauth
Senior Vice-President, North American Operations
Robin S. Zabek
Senior Vice-President, Exploitation
Paul M. Mendes
Vice-President, Legal, General Counsel and
Corporate Secretary
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 2016 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 20.
METRIC CONVERSION CHART
To convert
To
barrels
thousand cubic feet
feet
miles
acres
tonnes
cubic metres
cubic metres
metres
kilometres
hectares
tons
Multiply by
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, 2016.
2016
2015
2014
Cash dividends declared
per common share
$ 0.94 (1) $ 0.92 (1) $
0.90
(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 General Meeting of the Shareholders
will be held on Thursday, May 4, 2017 at 1:00 p.m. Mountain
Daylight Time in the Macleod C&D Exhibition Halls of the Telus
Convention 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 2016 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 Canadian Bank Note Commercial Solutions.
Design and produced by nonfiction studios inc.
103
Canadian Natural 2016 Annual ReportPremium Value. Defined Growth. Independent. Canadian Natural Resources Limited
2100, 855 – 2 Street S.W.
Calgary, AB T2P 4J8
T (403) 517-6700
F (403) 517-7350
www.cnrl.com
E ir@cnrl.com