PREMIUM VALUE.
DEFINED GROWTH.
INDEPENDENT.
2017 ANNUAL REPORT
2017 PERFORMANCE HIGHLIGHTS
Canadian Natural demonstrated strong operational and financial performance throughout 2017 and completed its transition to a long life low
decline asset base. The Company’s focus on disciplined and balanced capital allocation continues, generating sustainable free cash flow for
years to come.
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)
2017
2016
2015
$
$
$
$
$
$
$
$
$
$
$
$
$
17,669
2,397
2.04
2.03
1,403
1.19
1.19
7,347
6.25
6.21
17,129
22,458
31,653
$
$
$
$
$
$
$
$
$
$
$
$
$
360
282
23
20
685
1,601
39
22
1,662
962
11,098
$
13,167
(204) $
(0.19) $
(0.19) $
(669) $
(0.61) $
(0.61) $
4,293
3.90
3.89
3,794
16,805
26,267
$
$
$
$
$
$
351
123
24
26
524
1,622
38
31
1,691
806
(637)
(0.58)
(0.58)
263
0.24
0.24
5,785
5.29
5.28
3,853
16,794
27,381
400
123
22
19
564
1,663
36
27
1,726
852
(1) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation to this measure is discussed in the MD&A.
(2)
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.
Includes the current portion of long-term debt.
(3)
(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
2017 Performance Highlights
Letter to our Shareholders
Our World-Class Team
Year-End Reserves
IFC
02
06
12
20 Management’s Discussion and Analysis
56 Management’s Report
57 Management’s Assessment of Internal Control over
Financial Reporting
58 Report of Independent Registered Public Accounting Firm
60 Consolidated Financial Statements
Notes to the Consolidated Financial Statements
64
Supplementary Oil and Gas Information
96
106
Ten-Year Review
108 Corporate Information
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.
2017
2016
2015
521
2
—
523
18,795
72
2,194
21,061
9,958
180
125
10,263
9,520
32
67
9,619
11,866
188
1
1
190
17,579
78
2,194
19,851
7,281
253
133
7,667
8,911
85
80
9,076
9,179
134
—
6
140
18,961
93
2,439
21,493
7,197
284
142
7,623
8,338
96
74
8,508
9,041
866PERCENT
33YEARS
P+P PRODUCTION REPLACEMENT
P+P RESERVE LIFE INDEX
1
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT LETTER TO OUR SHAREHOLDERS
In 2017, Canadian Natural continued to execute on its proven and effective strategy by delivering strong operational and financial results,
disciplined capital allocation, financial strength and increasing returns to shareholders. 2017 was a milestone year for Canadian Natural as the
transition to a long life low decline asset base was completed with the successful completion and ramp up of the Phase 3 expansion at Horizon in
the fourth quarter. Our balanced approach to capital allocation included a transformational acquisition of the Athabasca Oil Sands Project (“AOSP”)
assets in the second quarter of 2017, adding to our long life low decline asset base and increasing the sustainability of our funds flow.
During 2017, Canadian Natural remained focused on driving top tier
effectiveness and efficiency by optimizing operating costs, leveraging
technology and capturing opportunities. 2017 annual funds flow from
operations was $7,347 million, a 71% increase from 2016, a significant
achievement given an annual average WTI crude oil price of less than
US$51.00/bbl. Operating costs were strong in the year and came within
or at the low end of Company guidance, a direct result of our continued
focus on optimizing operations. In the Oil Sands Mining and Upgrading
segment, cost savings were realized through safe, steady and reliable
operations. The Company achieved record low operating costs at Horizon
of $24.98/bbl of synthetic crude oil (“SCO”), representing a 13% reduction
from 2016 levels and AOSP operating costs came in below previously
issued guidance at $26.34/bbl, both including planned downtime.
Low Capital Exposure Assets
NATURAL GAS
Canadian Natural is the largest natural gas producer in Canada, supported
by a significant, diversified resource base combined with a largely owned
and operated infrastructure. Our extensive land positions in the Montney
and Deep Basin allow us to take advantage of some of the best liquids
rich plays in North America, maximizing value for our shareholders.
Throughout 2017, Canadian Natural remained focused on effective and
efficient operations through challenging low natural gas prices and third
party facility constraints. The Company has kept its top tier operating
costs low by employing drill to fill strategies and leveraging opportunities
in its liquids rich plays.
Canadian Natural is focused on delivering proactive, environmentally
responsible operations, where we continue to reduce our environmental
footprint. In 2017, we made significant gains in our environmental
performance by leveraging technology, being innovative and maintaining
effective and efficient operations. Our greenhouse gas emissions
intensity has decreased materially since 2012, and we have the ability to
capture and sequester over 1.5 million tonnes of CO2 annually at our Oil
Sands Mining and Upgrading operations. With the acquisition of the Quest
Carbon Capture Project along with the AOSP assets and once the North
West Redwater Refinery is fully operational in 2018, Canadian Natural
will be the 4th largest capturer and sequester of CO2 globally at 2.7 million
tonnes of CO2 annually. Additionally, the value of Canada’s Oil Sands is
very important to Canada, and the Company is committed to investing in
an environmental leadership manner in the oil sands by being a leader in
research and development. Our oil sands operations are targeted to have
the lowest environmental footprint and are well positioned to withstand
volatile commodity prices and any potential demand forecast scenario.
At Horizon, when we recognize our carbon capture initiatives, our
emissions intensity is only slightly higher, 5%, than the average for all
global crude oils, supporting our commitment to deliver environmentally
responsible operations.
Canadian Natural’s balanced and disciplined approach to how we do
business is driving increasing returns to shareholders and maximizing value.
2017 marked the seventeenth consecutive year of dividend increases,
a track record the Company is proud of. Our balanced and diverse asset
base ensures that our funds flow generation not only grows, but is also
sustainable. We have a robust financial position that allows us to be flexible
and target to execute on any value creating opportunities that arise in both
our low capital exposure assets and long life low decline assets. As a result,
Canadian Natural targets to deliver on our capital allocation strategy to
economically develop our resource base, capture opportunistic acquisitions,
maintain a strong balance sheet and increase returns to our shareholders.
In 2018, we target to drill 17 net natural gas wells and to strategically
manage our natural gas production within the constraints of a challenged
Western Canadian natural gas market, specifically AECO pricing. The
Company internally uses natural gas volumes equal to approximately 32%
of its natural gas production in its operations, and approximately 29% is
exported out of Western Canada and sold internationally, helping to limit
the Company’s exposure to AECO natural gas commodity pricing.
LIGHT CRUDE OIL AND NGLS – NORTH AMERICA
2017 was a successful year for light crude oil and NGLs as the Company
focused on optimizing assets and further improving on our effective and
efficient operations. As a result of a modest drilling program and minor
property acquisitions in 2017, we achieved 5% production growth over
2016 levels while keeping operating costs essentially flat from 2016
levels. Our light crude oil assets provide stable production and support
our increasing light crude oil product mix, strong funds flow generation
and value creation. In 2018, we will remain focused on enhancing oil
recoveries by leveraging technology and target to drill 67 net light crude
oil wells.
LIGHT CRUDE OIL AND NGLS – INTERNATIONAL
Canadian Natural’s international assets remain a strategic component
of our balanced portfolio. These assets offer exposure to international
pricing, support our light crude oil product mix and provide the Company
with a center for offshore expertise.
The Company’s assets in Offshore Africa generate amongst the highest
returns in our portfolio and are considered to be one of our key light
crude oil low capital exposure assets. Operating costs for Côte d’Ivoire
remained strong throughout 2017 and within corporate guidance. After
a highly successful 2016 infill drilling program at the Espoir and Baobab
fields and no drilling in 2017, production levels were down year over year
due to natural field declines and planned turnaround activity. In 2018, the
2
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Company targets to begin the Baobab Phase 4 drilling program consisting
of 1.7 net producers and 1.2 water injector wells, targeting approximately
5,700 bbl/d of additional net production in Q4/18.
crude oil assets now make up over 50% of the Company’s product mix,
with the remainder made up of 25% natural gas and 25% heavy crude oil,
reducing our overall exposure to heavy crude oil pricing.
In the North Sea, production remained comparable to 2016 levels as a
result of production enhancements and water flood optimization, a
significant achievement considering a modest drilling program in 2017
and the shut-in of the Ninian North platform in May 2017 as we began
proactive liability management and decommissioning of the platform.
After continued focus on cost reduction, operating costs for the North
Sea were $36.60/bbl, representing a decrease of 14% from 2016 levels.
In 2018, we target to drill 4.6 net wells, continuing to focus on increased
reliability, production enhancements and water flood optimization.
PRIMARY HEAVY CRUDE OIL
Canadian Natural remains the leading primary heavy crude oil producer
in Canada. Our large primary heavy crude oil undeveloped land base, vast
infrastructure and effective and efficient operations give us a significant
competitive advantage in this area, resulting in strong netbacks and
significant funds flow. As a result of the 2017 drilling program, we
averaged approximately 99,300 bbl/d of heavy crude oil production in
Q4/17, an increase of 3% over Q4/16 levels.
Long Life Low Decline Assets
PELICAN LAKE
Canadian Natural’s world class polymer flood at Pelican Lake is a
key component of our long life low decline assets. The technology
development used in the polymer flood is driving tremendous value and
increasing recovery factors by up to 28%. In 2017, the Company acquired
additional Pelican Lake assets, contiguous with Canadian Natural’s land,
adding approximately 19,000 bbl/d of production. In 2017, the continued
improvement of polymer flood reservoir performance along with the
opportunistic acquisition resulted in a 9% production increase over 2016
levels and annual record low operating costs of $6.42/bbl, the lowest in
our crude oil portfolio. Our continued focus on reducing costs, optimizing
production and leveraging polymer flood technology is generating
strong funds flow. In 2018, the Company targets to drill 22 net wells
at Pelican Lake and we will continue to focus on delivering significant
shareholder value by capturing synergies, optimizing production and
reactivating additional polymer flood conversions across portions of the
acquired operations.
In 2018, the Company targets to drill 377 net heavy crude oil wells and
continue to deliver repeatable and proven performance. These low capital
exposure opportunities and flexible heavy crude oil assets allow us to
adjust our capital and drilling programs as commodity prices fluctuate,
resulting in maximum value for our shareholders. We continue to focus
on improving recoveries and optimizing our operations.
CRUDE OIL MARKETING
As expected, 2017 was another year of market volatility. Canadian
Natural has a proven three pronged marketing strategy that maximizes
realized pricing for our overall portfolio. As in previous years, 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
as well as support and participate in projects that add conversion capacity
for heavy crude oil and bitumen. In support of our approach, Canadian
Natural is a 50% owner in the North West Redwater Partnership and is
participating in the Redwater refinery project, which will add 80,000 bbl/d
of diluted bitumen conversion capacity to the Alberta market in 2018.
The project is targeted to be complete in 2018, adding balance in the
Alberta crude oil market, helping to reduce the volatility of heavy
crude oil pricing and generating value for our shareholders.
During 2017, there was a significant change in the Company’s liquids
product mix to light crude oil, which is priced in close relation to the WTI
crude oil commodity price. Canadian Natural’s Oil Sands Mining and
Upgrading segment, conventional light crude oil and international light
THERMAL IN SITU OIL SANDS
Canadian Natural has a vast Thermal in situ oil sands (“Thermal”) portfolio,
consisting of some of the best thermal assets in Canada. These long
life low decline assets provide tremendous value and growth potential
and further add to the Company’s balanced portfolio. In 2017, overall
thermal production increased 8% over 2016 levels and strong operating
efficiencies were maintained, resulting in comparable operating costs of
$11.81/bbl in 2017.
The Company utilizes three distinct thermal processes tailored to specific
reservoirs, high pressure cyclic steam stimulation (“CSS”), low pressure
steamflood and steam assisted gravity drainage (“SAGD”). At Primrose,
our ongoing low pressure steamflood operations and steaming strategies
have been progressing successfully, resulting in excellent recoveries.
Production from our low pressure steamflood increased to an annual
average of 39,300 bbl/d from 2016 average levels of approximately
10,900 bbl/d. Overall production at Primrose increased by 11% over 2016
levels to 81,501 bbl/d, further demonstrating the strength of our steaming
technology. In 2018, the Company plans to drill 64 net horizontal CSS
wells as part of a growth drilling program continuing into 2019 with first
production targeted for late 2019, adding an average of 32,000 bbl/d of
net thermal production in 2020.
At Kirby South, the Company’s commercial SAGD project, annual
production averaged 36,107 bbl/d, a 4% decrease from 2016 levels as
the Company successfully completed turnaround activities during the
year. Operating costs remained in line with 2016 levels achieving strong
DISCIPLINED
BUSINESS APPROACH
CAPITAL &
OPERATIONAL FLEXIBILITY
3
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT thermal efficiencies and low annual steam to oil ratio (“SOR”) of 2.8 in
2017. In 2018, the Company is targeting to drill 4 infill producers and
2 SAGD well pairs. The reinitiated development of Kirby North, our second
SAGD project, with targeted facility capacity of 40,000 bbl/d is on time
and on budget. The initial development plans at Kirby North are to drill
49 net producer and 44 net injector wells with first production targeted
in early 2020. The addition of Kirby North will be another strategic
component of our long life low decline asset base.
WORLD CLASS OIL SANDS MINING AND UPGRADING
In our mining and upgrading operations, 2017 was a transformational
year for Canadian Natural as we completed the acquisition of a 70%
working interest in the AOSP in early 2017, further strengthening our
long life low decline asset base. These assets offer no decline production
with no reserve risk for decades. They are proximal to the Horizon
operations, allowing the Company to capture synergies and deliver on
our strategy to maximize value through continuous improvement while
leveraging technology.
At Horizon, with the completion of Phase 3, the final component of our
transition to a long life low decline asset is complete. Our team successfully
completed a 52 day turnaround, the largest man-hour event to date for
Canadian Natural, to tie in the Phase 3 expansion, which came in under
budget. Through the Company’s safe, steady and reliable operations and
strong focus on continuous improvement, record low annual average
operating costs were realized in 2017 at $21.46/bbl of SCO, representing
a 15% decrease from 2016 levels, after adjusting for planned downtime.
In 2017, Horizon achieved record annual production of approximately
170,100 bbl/d of SCO, after a full year of production from the
Phase 2B expansion and the successful ramp up of the Phase 3
expansion in late 2017. Strong performance continued after Phase 3
was completed, culminating in average production of approximately
247,000 bbl/d of SCO from December 1, 2017 to February 28, 2018.
In 2018, through safe and reliable operations the Company targets to gain
a better understanding of the plant capacity and will take a disciplined
approach to capital allocation for any debottlenecking opportunities.
In June 2017, Canadian Natural acquired a 70% operating interest in
the AOSP mines, and a 70% working interest in the Scotford Upgrader.
Through strong reliability and utilization, net AOSP production of
111,937 bbl/d of SCO was added to the Company’s portfolio, contributing
to the Company’s record annual production. The two AOSP mines are
adjacent to Horizon, allowing the Company to capture synergies, leverage
technologies and focus on increasing reliability with a goal of reduced
costs. Canadian Natural’s effective and efficient operations during the
7 months in 2017 resulted in operating costs of $26.34/bbl of Albian SCO,
below the Company’s previously issued guidance, a strong indicator of
synergies between the two projects.
As part of our commitment to environmentally responsible operations,
the Company is a part of several government, academia and industry
collaborations that play an important role in ensuring competitiveness
and a sustainable industry that meets Canada’s and the world’s energy
needs for the long term. As one of the leading investors in research
and development in Canada, the Company’s investment has been
focused on tailings and land management, reduced water usage and
GHG reduction. Our CO2 capture and sequestration facilities at Horizon
along with our 70% interest in the Quest carbon capture and storage
facilities at Scotford contribute to Canadian Natural’s 1.5 million tonnes
of annual CO2 capture and sequestration capacity. Through technology
and innovative practices, Canadian Natural has significantly reduced its
fresh water usage by recycling the vast majority of water used in our oil
sands operations, delivering on its committment to effective and efficient
water management. The combined impact of these projects and our
focus on continuous improvement will result in further reducing of our
environmental footprint and drive increased operational performance.
Plans for the Oil Sands Mining and Upgrading assets in 2018 include
continuing the evaluation and engineering for possible paraffinic froth
treatment and vacuum gas oil (“VGO”) expansions at Horizon. These
world class assets provide exceptional value for Canadian Natural and
our shareholders, generating significant funds flow from operations as
the Company continues to focus on maximizing value through increased
reliability, continuous improvement and the utilization of technology.
Finance
In 2017, we were proactive in managing our balance sheet and maintained
our capital discipline in a challenging commodity price environment. At
year-end 2017, we had strong liquidity with approximately $4.25 billion
available on our committed bank facilities. Balance sheet strength
continued to be a focus for the Company in 2017 with year-end debt to
book capitalization of 41%, within the Company's targeted operating
range of 25% to 45% and debt to adjusted EBITDA of 2.7x. Subsequent
to December 31, 2017, Canadian Natural repaid US$600 million of
1.75% notes, US$400 million of 5.90% notes and repaid and canceled
$275 million in non-revolving credit facilities with funds flow from
operations, further showcasing our commitment to strengthening our
balance sheet. In addition to credit facilities, Canadian Natural maintains
additional financial levers to effectively manage its liquidity, including the
Company’s third party equity investments of approximately $893 million
at December 31, 2017.
EFFECTIVE &
EFFICIENT OPERATIONS
HIGH QUALITY
DIVERSIFIED PORTFOLIO
4
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT N. MURRAY EDWARDS
Executive Chairman
STEVE W. LAUT
Executive Vice Chairman
TIM S. MCKAY
President
COREY B. BIEBER
CFO & SVP, Finance
In early 2018, as a result of the Board of Directors confidence in the
sustainability and the robustness of our asset base, the Company’s dividend
was increased by 22%, marking the eighteenth consecutive year of
increases, to an annualized value of $1.34 per common share.
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’s competitive advantages of maintaining
vast diversified inventories of drilling opportunities, owned and operated
infrastructure and a long life low decline asset base, position the
Company for significant sustainable free cash flow growth. Another
key advantage for Canadian Natural is our committed team of 9,973
employees, keeping our culture strong and enabling knowledge sharing
amongst our employees maximizes current and future opportunities.
The Company takes a very proactive and disciplined approach to
succession, ensuring we maintain our corporate culture and top tier
performance and as such, on March 1, 2018, Tim McKay was promoted to
President and Steve Laut assumed the role of Executive Vice Chairman.
These leadership changes allow for smooth transition and leadership
continuity and as a result, the Company is in a strong position to deliver
results through top tier effectiveness and efficiency while increasing
returns to shareholders.
In 2017, we continued to add value for our shareholders through the
completion of the Phase 3 expansion at Horizon and executing on key
accretive acquisitions. Our transition to a long life low decline asset base is
complete with an overall corporate decline rate targeted at approximately
9%. As a result of our long life low decline asset base, the Company’s
maintenance capital to keep production essentially flat is approximately
$3.0 billion, further contributing to the Company’s capital flexibility and
sustainable free cash flow generation. With increased free cash flow, the
Company will continue its focus on balanced capital allocation to our four
pillars, economic resource development, balance sheet strength, returns
to shareholders and execution on opportunistic acquisitions.
In 2018, Canadian Natural will be focused on reliability across our diverse
asset base and continue to integrate and optimize the assets acquired
in 2017. The Company will target cost control with a directed drilling
program, essential in a volatile commodity price environment and targets
to grow total production by 17% compared to 2017 levels. Our capital
development program is disciplined and is targeted to be within the $4.0
to $5.0 billion range going forward. Canadian Natural’s 2018 budget is
targeted at $4.3 billion and includes our mid-term thermal in situ CSS and
SAGD growth projects at Primrose and Kirby North, further increasing the
Company’s long life low decline asset base.
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. Our commitment to strengthen
our balance sheet metrics will provide the Company with ample liquidity
and significant capital flexibility to capture opportunities as they arise.
Canadian Natural is well positioned to continue to execute upon our
defined plans and deliver significant and sustainable free 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 and as such we will continue to remain the Premium
Value, Defined Growth Independent.
N. MURRAY EDWARDS
Executive Chairman
STEVE W. LAUT
Executive Vice Chairman
TIM S. MCKAY
President
COREY B. BIEBER
CFO & SVP, Finance
5
CANADIAN NATURAL 2017 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, J. Abbott, L. Abbott, M. Abbott, I. Abdi, M. Abdulrhman, A. Abeda, W. Abeda, D. Abel, R. Abel, T. Abercrombie, G. Abou Mechrek, R. Abrams, A.
Abramyan, J. Abramyk, J. Abreu, R. Abreu, N. Abro, C. Acharya, D. Acheson, R. Ackerman, C. Acorn, J. Acosta, N. Adair, T. Adair, S. Adam, B. Adams, D. Adams, K. Adams, D. Adamson, P. Adamson, C. Adan, D. Addinall,
A. Adebayo, Y. Adebayo, K. Adejare, S. Adel, M. Aden, A. Adesanya, B. Adkins, J. Agate, A. Agnihotri, K. Agombar, I. Agu, U. Agu, A. Agustin, E. Agyemang, C. Agyemang-Badu, M. Ahmad, O. Ahmad, S. Ahmad, A. Ahmadi,
M. Ahmadi, F. Ahmadloo, A. Ahmari, A. Ahmed, R. Ahmed, S. Ahmed, M. Ahn, T. Aickelin, R. Aidoo, R. Aikens, G. Ailsby, T. Ailsby, K. Airth, J. Airton, C. Aitchison, K. Aitchison, K. Aitken, T. Ajayi, J. Ajedegba, R. Akers, S.
Akhtar, D. Akins, A. Akinsanya, R. Akkineni, J. Akolkar, N. Akolkar, S. Akolkar, K. Akpan, M. Al-Dhabbi, M. Al-Kaisy, A. Al-Saleem, R. Al-Samarrai, S. Al-Siani, C. Alarcon, H. Albaran, J. Albert, J. Alcala, E. Alconcel, J. Aleman,
A. Alexander, B. Alexander, D. Alexander, J. Alexander, S. Alexander, A. Ali, G. Ali, K. Ali, S. Ali, R. Aliazas, H. Aljanabi, C. Allan, J. Allan, E. Allard, J. Allard, L. Allegretto, H. Allen, J. Allen, T. Allen, D. Allibone, S. Allport,
J. Allsop, B. Almen, Y. Alnumi, A. Alstad, J. Alvarez Luzon, J. Alvarez, J. Aman, M. Amar, A. Amay, B. Amer, K. Amer, J. Amero, D. Ames, D. Amevor, E. Amos, W. Amy, D. Anctil, J. Andel, D. Anders, D. Andersen, T. Andersen,
A. Anderson, B. Anderson, C. Anderson, D. Anderson, G. Anderson, J. Anderson, K. Anderson, L. Anderson, M. Anderson, N. Anderson, P. Anderson, R. Anderson, W. Anderson, P. Andrekson, D. Andreoli, C. Andres, J. Andres,
B. Andrews, D. Andrews, K. Andrews, L. Andrews, T. Andrews, R. Andriekus, E. Anfort, C. Angeles, P. Angell, K. Angerman, C. Angus, D. Anheliger, M. Anis, S. Annis, M. Ansah-Sam, Z. Ansarizadeh, A. Ansell, C. Ansong-
Danquah, D. Ansorger, R. Anstett, G. Anstey, J. Anstey, M. Anstey, V. Anstey, L. Antal, J. Antle, C. Antoine, G. Antoine, M. Antoine, K. Antonishyn, T. Antoniuk, H. Aparicio Ramos, D. Appelt, P. Appiah, B. April, R. April, J.
Aquila, R. Aranguren, F. Arano, L. Arbour, C. Arcand, J. Arceneaux, L. Archer, J. Argan, M. Arguin, H. Arias, L. Arias, J. Arizaleta, S. Arjomandi, J. Arkley, T. Armfelt, M. Armour, A. Armstrong, D. Armstrong, J. Armstrong, P.
Armstrong, R. Armstrong, J. Arnault, B. Arneson, B. Arnold, C. Arnold, J. Arnold, V. Aron, F. Arrieta, M. Arsenault, A. Arthur Brown, L. Arthur, B. Artz, S. Arunachalam, B. Asake, J. Ashe, Z. Ashmore, C. Ashton, W. Ashun-
Codjiw, R. Aslin, R. Asmundson, S. Aspden, H. Aspeslet, M. Asselstine, D. Assinger, A. Assoum, A. Astalos, R. Astalos, I. Astete, N. Athavan, A. Atienza, R. Atkins, J. Atkinson, K. Atkinson, L. Attreo, E. Au, G. Au, C. Aube,
R. Aubin, J. Auch, D. Aucoin, J. Aucoin, P. Aucoin, S. Aucoin, W. Aucoin, A. Auger, B. Auger, D. Auger, L. Auger, P. Auger, G. Augustine, C. Aular, C. Austin, R. Austin, F. Avery, S. Avery, M. Avila, C. Aviles, O. Awodein, E.
Awuni, W. Ayles, A. Ayoub, J. Ayub, F. Azam, A. Babiarz, O. Babiker, C. Babos, K. Babu, C. Bachelder, C. Bachelet, C. Bachman, W. Bachmeier, A. Baciulica, C. Backer, J. Bacon, K. Baddeley, W. Bader, N. Badgley, M. Baes,
O. Baffoh, S. Bagai, L. Bagg, G. Baggs, N. Bagheri, A. Bagnall, M. Bahiraei, B. Bahlieda, D. Baichev, D. Baier, J. Baier, N. Baier, M. Bailer, R. Bailer, A. Bailey, B. Bailey, J. Bailey, K. Bailey, S. Bailey, B. Bain, E. Bain, D. Baines,
B. Bairstow, D. Baisley, D. Bak, L. Bakaas, A. Baker, C. Baker, D. Baker, I. Baker, J. Baker, R. Baker, J. Balacang, A. Balajadia, M. Balan, B. Balaski, B. Baldonado, J. Baldonado, C. Baldwin, G. Baldwin, M. Baldwin, R. Baldwin,
I. Balicanta, J. Balkam, C. Ball, D. Ball, G. Ball, P. Ball, T. Ball, J. Ballard, G. Ballas, S. Ballas, A. Baloch, B. Balog, D. Balson, B. Baluyot, R. Bama, R. Bamotra, C. Ban-Nelson, R. Banack, J. Banak, M. Banas, D. Banash, J.
Banawa, P. Bandola, N. Banerjee, A. Banfield, R. Banfield, S. Banfield, O. Bango, J. Banks, L. Banks, R. Bannerholt, B. Bannis, C. Bantaya, M. Banwait, R. Barabe, G. Bardoel, L. Bardoel, K. Barham, M. Bari, M. Barilea, R.
Barker, S. Barker, A. Barley, C. Barnes, D. Barnes, M. Barnes, N. Barnes, B. Barnett, D. Barr, P. Barr, S. Barr, T. Barr, E. Barreto, C. Barrett, M. Barrett, R. Barrett, T. Barrett, T. Barretto, S. Barriault, C. Barrie, D. Barron, K. Barron,
R. Barron, L. Barros, D. Barry, V. Barry, A. Barstad, P. Barter, B. Bartlett, C. Bartlett, J. Bartlett, M. Bartlett, C. Bartman, D. Bartman, M. Bartman, J. Basabe, K. Basarab, N. Basi, R. Basile, V. Basilio, L. Basines, P. Bass, S.
Basso, C. Bast, A. Bastardo, C. Bastien, S. Basu, M. Batac, S. Batarseh, B. Bate, C. Bateman, T. Bateman, L. Bates, D. Bath, L. Bath, S. Batina, M. Batovanja, U. Batta, R. Batten, C. Battrum, B. Battyanie, J. Batuyong, D.
Bauer, R. Bauer, S. Baugh, T. Bauld, J. Bauman, C. Baumgardner, J. Baxter, D. Bayley, A. Bazowski, B. Beach, A. Beacon, W. Beals, C. Beaman, J. Beamish, D. Bean, G. Bean, R. Bear, C. Beaton, D. Beaton, N. Beaton, A.
Beattie, C. Beattie, R. Beattie, S. Beattie, A. Beatty, E. Beatty, S. Beauchamp, B. Beauclaire, C. Beaudoin, J. Beaudoin, R. Beaudoin, B. Beaulac, M. Beaulieu, L. Beaunoyer, F. Beaver, D. Bechtel, B. Beck, N. Beck, C. Becker,
H. Becker, R. Becker, R. Beckner, S. Beckow, D. Bedell, J. Bedell, A. Bedi, G. Bedi, M. Bednarchuk, S. Beebe, T. Beebe, M. Beeks, C. Beeler, B. Beesley, W. Behnke, J. Behrens, P. Behrens, A. Belah, P. Belair, S. Belak, G.
Belanger, R. Belanger, H. Belas, L. Belcourt, R. Belcourt, J. Belik, R. Belisle, A. Bell, D. Bell, J. Bell, L. Bell, S. Bell, T. Bell, J. Bellavance, J. Beller, M. Beller, E. Bellerose, A. Bellettini, J. Belliveau, A. Bellows, C. Bellows, S.
Belseck, K. Belyea, M. Belzile, M. Bembridge, A. Bempong, A. Bendahmane, K. Bendahmane, R. Benedictson, S. Beniwal, M. Benko, D. Benn, T. Benn, K. Benner, C. Bennett, D. Bennett, E. Bennett, J. Bennett, M. Bennett,
R. Bennett, S. Bennett, A. Benoit, G. Benoit, K. Benoit, P. Benoit, S. Bensmiller, C. Benson, M. Benson, R. Benson, A. Benson- Bartko, J. Bent, A. Bentley, R. Bentley, J. Benyon, J. Berdan, C. Bereznicki, D. Berg, B. Berge, L.
Berge, K. Bergen, O. Bergeron, J. Bergeson, M. Bergeson, B. Bergley, J. Bergman, J. Bergsma, D. Berisha, D. Berlinguette, H. Berlinguette, D. Bernal, J. Bernardin, D. Bernardo, J. Bernier, K. Berreth, L. Berry, W. Berscht, D.
Bershadsky, S. Bertelmann, G. Bertolin, A. Bertrand, B. Bertrand, J. Bertrand, M. Bertsch, B. Berube, W. Berube, R. Bessey, C. Best, J. Best, C. Betancur Pelaez, C. Bettany, T. Betteridge, W. Bewski, B. Beyer, J. Beytell, S.
Bezpalchuk, J. Bezruchak, N. Bhachu, U. Bhachu, J. Bhangoo, I. Bhasin, H. Bhatia, J. Bhatt, K. Bhatt, R. Bhatt, R. Bhattacharyya, V. Bhekare, J. Bianchini, L. Bianco, M. Bibars, A. Bibo, J. Bick, S. Biddle, T. Biddlecombe, C.
Bieber, D. Bieber, D. Bielech, E. Bieleski, D. Biendarra, D. Biener, V. Biesinger, C. Biggin, M. Biggs, A. Bilal, D. Biles, P. Bilkowski, B. Bill, L. Billard, T. Billard, L. Billiard, J. Bilous, T. Binczyk, W. Binda, M. Binder, B. Binns, C.
Bint, R. Bintz, 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, M. Bissonnette, D. Bittner, S. Bjarnason, T. Bjerland, J. Blachford,
A. Black, B. Black, C. Black, J. Black, K. Black, R. Black, P. Blackburn, T. Blackett, K. Blackhall, K. Blackmore, R. Blackmore, T. Blackwell, A. Blacquiere, D. Blain, A. Blair, D. Blair, L. Blair, J. Blais, A. Blake, D. Blake, E. Blake,
J. Blake, T. Blake, D. Blanchard, G. Blanchard, T. Blanchard, J. Blanche, R. Blanchett, D. Blanchette, G. Blanchette, K. Blanchette, A. Blanco, G. Blanco, U. Blanco, W. Blanco, S. Blaydes, K. Blencowe, M. Blinkhorn, J. Blomdal,
R. Blondin, J. Blume, G. Blumhagen, C. Blyan, T. Bo-Lassen, C. Boadas Salazar, J. Bobbett, A. Bobrowski, H. Bocalan, D. Bochek, R. Bock, G. Boddy, J. Bodell, R. Bodell, S. Bodell, A. Bodnar, B. Bodnar, K. Bodnar, J. Bodnarchuk,
V. Bodnarchuk, B. Bodner, G. Bodner, D. Bodoano, D. Boehmer, D. Boettcher, D. Boettger, M. Boggust, L. Boghici, T. Bohach, A. Bohemier, J. Bohlken, N. Bohning, J. Bohorquez, G. Bohrson, J. Boire, J. Boissoneault, C. Boisvert,
M. Boisvert, D. Bokota, M. Boland, S. Bolduc, C. Boleski, C. Bolger, G. Bolin, D. Bolster, B. Bolt, J. Bolt, G. Bolton, G. Bolzon, D. Boman, J. Bonami-McRae, N. Bond, S. Bond, T. Bond, E. Bondarenko, T. Bondaruk, C. Bonebrake,
A. Bonilla, C. Bonogofski, A. Bonwick, R. Booker, S. Booker, P. Booklall, J. Boomgaarden, B. Boone, C. Boos, J. Boos, K. Booth, B. Borbely, A. Borbon, K. Bordeleau, R. Borg, C. Borgel, O. Borghesan, C. Borgland, P. Bork, J.
Borkowski, J. Borland, M. Borlaza, D. Borle, M. Born, D. Borowski Grimaldi, K. Borromeo, E. Borsini Marin, J. Borstel, K. Borysiuk, B. Bosch, D. Bosch, J. Bosch, S. Bosch, J. Boschman, G. Bosma, L. Bosoi, P. Bossel, B.
Bosworth, H. Botha, K. Bothwell, J. Botterill, R. Botting, J. Bouchard Lacoste, D. Bouchard, L. Bouchard, T. Bouchard, C. Boucher, T. Boucher, S. Boudignon, K. Boudreau, J. Boudreault, K. Bougie, B. Boulton, J. Boulton, T.
Bouma, J. Bounds, C. Bourassa, L. Bourassa, R. Bourassa, S. Bourassa, J. Bourgeois, D. Bourke, C. Bourlon, D. Bourque, D. Bourquin, S. Bourrie, C. Boutier Becerra, M. Boutilier, C. Bowal, M. Bowal, C. Bowditch, D. Bowen,
J. Bowen, P. Bowering, R. Bowers, S. Bowers, D. Bowes, B. Bowie, J. Bowie, M. Bowles, C. Bowman, J. 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, J. Boyde, C. Boyer, R. Boyko, V. Boyko, D. Boyle, N. Boyle, D. Bradbury, K. Bradbury, B. Bradley, P. Bradley, P. Bradner, C. Bradt, M. Brady, C. Bragg, J. Bragg, L. Bragg, S. Braithwaite, J. Brake, N. Brake,
S. Brake, T. Brake, T. Branch, P. Brand, J. Branderhorst, J. Brannick, B. Brant, D. Brant, E. Brant, P. Brar, C. Brassard, M. Brataschuk, K. Bratt, K. Brattebo, R. Brattston, C. Brausen, K. Bravo, L. Bravo, J. Brawn, N. Bray, T. Bray,
A. Brazeau, W. Brebant, G. Brecht, M. Brecht, D. Bredy, D. Breen, J. Breen, M. Breen, S. Breitkreuz, B. Brekke, E. Brekke, D. Bremner, K. Brennan, L. Brennan, B. Brenton, C. Brenton, J. Brenton, R. Brenton, A. Breski, T.
Bresson, K. Brethour, T. Bretzer, R. Bretzlaff, O. Breukel, A. Brewer, S. Brewer, J. Breytenbach, W. Briand, S. Briard, B. Bricker, M. Brideau, C. Bridger, D. Bridger, J. Bridger, H. Brietzke, M. Brietzke, C. Briggs, G. Briggs, J.
Bright, L. Brinkworth, S. Brinson, C. Brisebois, G. Brisseau, P. Britton, J. Brock, M. Brock, K. Brocke, B. Broda, A. Broderick, D. Broderick, S. Broderson, D. Brodziak, E. Broidioi, K. Bromley, J. Bronkhorst, G. Bronson, R. Brood,
J. Brooke, D. Brooks, J. Brooks, R. Brooks, S. Broomfield, G. Brophy-Maclean, K. Brosowsky, T. Brosseau, K. Brost, C. Brousseau, E. Brousseau, C. Brow, A. Brown, B. Brown, C. Brown, D. Brown, E. Brown, G. Brown, J. Brown,
K. Brown, L. Brown, M. Brown, N. Brown, R. Brown, T. Brown, W. Brown, T. Browne, D. Brownrigg, J. Bruce, L. Bruchanski, A. Brucker, R. Brue, K. Bruggencate, F. Brugger, J. Brule, K. Brule, V. Brule, S. Brulotte, N. Brummitt,
R. Brundige, K. Bruner, A. Brunet, M. Brunette, D. Brush, M. Brushett, R. Bryan, B. Bryant, L. Bryant, P. Bryant, R. Bryant, T. Bryant, G. Brydges, T. Brydges, H. Bryenton, J. Bryla, M. Bryson, G. Buchan, A. Buchanan, P. Buchanan,
M. Bucholtz, J. Buck, K. Buckle, D. Buckley, G. Buckshaw, D. Budalich, T. Budd, N. Budden, B. Budgell, R. Budzen, R. Bueckert, W. Bugiak, J. Buholzer, S. Bukhari, S. Bulger, R. Bullen, T. Bullen, K. Bulley, J. Bullock, D.
Bumstead, G. Bungay, Q. Bunten-Walberg, B. Bunz, D. Burak, T. Burchenski, A. Burden, K. Burden, J. Burdett, C. Burge, D. Burgess, G. Burgess, B. Burk, G. Burkart, T. Burkart, S. Burke, G. Burkhart, J. Burnett, R. Burnham, L.
Burns, B. Burr, R. Burris, D. Burry, K. Burry, S. Burry, D. Bursey, A. Burt, B. Burt, T. Burt, D. Burton, G. Burton, J. Burton, K. Burton, M. Burton, N. Burton, R. Burton, T. Burton, W. Burton, R. Busato, K. Bush, D. Bushey, T. Bushie,
D. Bussey, N. Bussiere, J. Bustamante, M. Butchart, K. Butcher, C. Butler, D. Butler, I. Butler, J. Butler, M. Butler, R. Butler, T. Butler, K. Butt, Q. Butt, R. Butt, S. Butt, T. Butt, B. Butterworth, M. Buttigieg, J. Button, K. Butts,
R. Butts, P. Buxton, W. Bykewich, J. Byrne, M. Byrne, T. Byrnell, J. Byrtus, I. Byvald, L. Cabatuando, A. Cabral, M. Caceres-Centeno, J. Cachene-Clark, E. Cadieux, K. Cadieux, T. Cadieux, L. Cahill, G. Cahoon, L. Cai, B. Cain,
A. Caines, H. Cairns, E. Caissie, T. Cake, W. Calabio, B. Calder, L. Calder, J. Calderon, B. Caldwell, J. Caldwell, P. Caldwell, C. Caleffi, C. Callihoo, P. Callin, R. Calliou, N. Cambridge, S. Cameron, S. Camp, A. Campbell, B.
Campbell, C. Campbell, D. Campbell, E. Campbell, M. Campbell, P. Campbell, S. Campbell, A. Campeau, N. Campeau, W. Campeau, M. Canchica, G. Cane, R. Canelon Oyarzabal, J. Canning, M. Canning, R. Canning, J.
Cannon, B. Cant, E. Cantlon, J. Cantwell, N. Cantwell, K. Canuel, M. Cao, A. Caouette, K. Cap, M. Capitaneanu, A. Caplette, J. Capstick, M. Capstick, B. Carabin, M. Cardak, G. Carde, A. Cardenas, F. Cardinal, J. Cardinal,
L. Cardinal, R. Cardinal, S. Cardinal, W. Cardinal, A. Carefoot, M. Carew, W. Carey, D. Carleton, T. Carleton, J. Carlier, F. Carlos Sanchez, K. Carlos, J. Carlson, W. Carlson, D. Carnes, A. Carnochan, A. Caron, D. Caron, J.
Caron, R. Caron, S. Caron, Y. Caron, G. Carpo, D. Carr, J. Carr, L. Carranza, V. Carrasco Rueda, M. Carrier, T. Carrier, D. Carroll, I. Carroll, J. Carroll, M. Carroll, S. Carroll, C. Carruthers, C. Carsh, C. Carson, J. Carson, E. Cartaya,
S. Carter Hicks, A. Carter, D. Carter, E. Carter, I. Carter, J. Carter, K. Carter, N. Carter, R. Carter, C. Cartier, X. Cartron, J. Cartwright, S. Carty, G. Case, P. Cashin, E. Cassell, D. Cassidy, T. Cassidy, K. Cassity, J. Cassivi, L. Casson,
O. Castellanos Diaz, F. Castellanos, H. Castillo Leon, A. Castillo, K. Castle, J. Castro, N. Catley, S. Catley, J. Catto, L. Catto, J. Cauchie, D. Cavacciuti, A. Cavanagh, D. Cavers, J. Cawthorpe, J. Cayabo, C. Cayer, C. Celis, A.
Centeno, S. Cervantes, A. Chafe, A. Chaisson, H. Chaisson, R. Chaisson, S. Chakraborty, S. Chakravarty, A. Chalifoux, C. Chalifoux, J. Challoner, M. Chalmers, A. Chamanara, C. Chambers, K. Champagne, L. Champagne, A.
Chan, C. Chan, I. Chan, J. Chan, L. Chan, M. Chan, R. Chan, S. Chan, T. Chan, V. Chan, A. Chaney, K. Chang, J. Chanski, T. Chantler, C. Chaon, K. Chapman, M. Chapman, B. Chapple, W. Charanek, S. Charette, J. Charlebois,
Y. Charniauski, L. Charrois, C. Chartrand, R. Chartrand, P. Chase, A. Chatman, M. Chatman, A. Chatterjee, L. Chau, M. Chaudhry, R. Chauhan, R. Chaulk, J. Chaval, D. Chavez, M. Chawla, M. Chayko, T. Chayko, C. Chaytor, M.
Chaytor, P. Chaytor, E. Chebunina, S. Checkley, B. Chen, C. Chen, H. Chen, O. Chen, S. Chen, T. Chen, X. Chen, Z. Chen, C. Cheng, J. Cheng, N. Cheng, D. Chenier, N. Cheraghi, S. Cherian, Z. Cherniawsky, M. Chernichen, T.
Cherry, D. Chervenkov, O. Chervyakova, B. Chester, J. Chester, A. Chesterman, D. Chetcuti, A. Cheung, I. Cheung, K. Cheung, W. Cheung, L. Cheveldeaw, B. Cheyne, H. Chhokar, F. Chiasson, B. Chichak, K. Chichak, D. Chick,
G. Chick, T. Chick, B. Chicoine, D. Chidley, D. Childs, S. Childs, K. Chilibeck, A. Chin, S. Chin, Y. Chin, P. Chinzvende, R. Chipchura, T. Chipiuk, M. Chiplin, A. Chisholm, B. Chisholm, T. Chisholm, P. Chiu, R. Chmelyk, R. Chmilar,
6
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT J. Chohan, J. Cholka, R. Chong, P. Choo, B. Chopping, B. Chorney, M. Chorney, C. Chornohos, C. Chorostecki, S. Choudhury, R. Chowdhury, S. Chowdhury, G. Choy, A. Chretien, L. Christensen, R. Christensen, T. Christensen,
J. Christian, N. Christian, S. Christiansen, D. Christianson, R. Christie, S. Christie, A. Chu, C. Chua, G. Chubbs, D. Chudobiak, V. Chui, H. Chung, P. Chung, W. Chung, H. Church, C. Churchill, D. Churchill, G. Churchill, J. Churchill,
D. Chute, K. Chychul, O. Chyon, R. Cikes, V. Cimon, E. Cissell, W. Clapperton, T. Clare, A. Clark, J. Clark, K. Clark, R. Clark, T. Clark, B. Clarke, C. Clarke, D. Clarke, J. Clarke, K. Clarke, L. Clarke, M. Clarke, R. Clarke, S. Clarke,
W. Clarke, R. Clarkson, W. Clarkson, S. Clavette, G. Clegg, J. Clelland, T. Clelland, R. Clemit, R. Clemmer, J. Clevenger, C. Closs, Z. Closter, J. Clouter, J. Clowater, G. Clowe, M. Cnossen, R. Coates, T. Coates, E. Cobaj, D.
Coburn, M. Cochet, B. Cochrane, J. Cochrane, C. Cockerill, D. Cockerill, F. Codd, E. Code, C. Codner, C. Cody, J. Coers, B. Colaco, L. Colborne, D. Colbourne, M. Colbourne, A. Cole, B. Cole, M. Cole, P. Cole, A. Coles, K. Coles,
M. Coles, C. Colina, L. Collard, P. Colley, D. Collicott, D. Collicutt, M. Collie, G. Collings, B. Collins, J. Collins, M. Collins, N. Collins, O. Collins, R. Collins, S. Collins, A. Collison, G. Collison, A. Collyer, K. Colton, E. Comeau,
J. Commance, S. Compagnion, K. Compagnon, R. Compagnon, W. Compagnon, C. Compton, Q. Conacher, J. Condie, P. Connaghan, A. Connell, E. Connell, M. Connell, M. Connellan, M. Connors, D. Conrad, S. Constant, V.
Constantin, D. Conway, M. Conway, P. Conway, D. Cook, G. Cook, K. Cook, L. Cook, N. Cook, S. Cook, A. Cooke, G. Cooke, H. Cooke, J. Cooke, K. Cookson, L. Cookson, J. Coolen, R. Coolen, H. Coolidge, J. Coombs, K. Coombs,
L. Coombs, L. Coonan, J. Cooper, M. Cooper, C. Copeland, N. Copeland, M. Copithorne, D. Coppard, R. Coppard, D. Corbett, J. Corcoran, M. Corell, E. Coreman, D. Cormier, I. Cormier, S. Cormier, J. Cornect, D. Cornish, R.
Cornish, S. Correll, C. Corrigan, D. Corrigan, M. Corrigan, R. Corrigan, J. Corson, S. Corson, B. Cortez, C. Corzo De Canchica, G. Cossani, H. Costello, S. Costello, J. Costigan, J. Costley, A. Cote Simard, B. Cote, E. Cote, G.
Cote, J. Cote, E. Cotten, L. Cottreau, K. Coulombe, L. Coulson, M. Courage, J. Courchene, R. Courchesne, N. Courteoreille, B. Courtney, G. Courtney, T. Courtney, P. Courtoreille, S. Courtoreille, T. Courtoreille, D. Courts, P.
Cousin, D. Cousins, J. Cousins, M. Cousins, P. Covell, K. Cowan, D. Coward, K. Cowger, R. Cowley, A. Cox, B. Cox, G. Cox, J. Cox, K. Cox, R. Cox, Z. Coxwell, B. Coyston, E. Cozicor, R. Craft, J. Craftchick, C. Craig, D. Craig, G.
Craig, R. Craig, H. Craigie, B. Crain, K. Cramb, P. Cramb, S. Cramm, M. Crane, A. Crawford, L. Crawford, H. Crawley, J. Crawley, G. Crayford, E. Crellin, L. Cressman, R. Crichton, P. Crisby, C. Critch, F. Critch, J. Critch, N. Critch,
D. Crittall, W. Crockford, A. Croft, S. Croft, C. Crook, G. Crooks, D. Crosley, T. Crosley, B. Cross, C. Cross, G. Cross, R. Cross, T. Cross, S. Croteau, T. Crouser, A. Croutch, C. Crowe, S. Crowe, D. Crowle, R. Crowle, P. Crozier, K.
Cruickshank, R. Cruickshank, D. Crum, K. Crutchley, L. Cruttenden, C. Cruz, J. Cruz, A. Csabay, E. Cuello, H. Cui, M. Culligan, E. Cullimore, A. Cunanan, A. Cunningham, D. Cunningham, R. Cunningham, S. Cunningham, E.
Cupac-Cingel, J. Curran, S. Currie, R. Currier, B. Curry, T. Curry, K. Cursley, D. Curtis, K. Cusack, M. Cusson, R. Cusson, D. Cutler, J. Cutler, S. Cutler, J. Cuu, J. Cuzovic, C. Cyr, D. Cyr, G. Cyr, S. Cyr, J. Cyrenne, D. Cyron, K.
Cytko, P. Czajko, J. Czarnecki, L. Czernicki, M. Czerwinski, D. D'Amour, P. D'Souza, V. D'Souza, M. D'arcangelo, C. DaRosa, A. Dabrowski, R. Dadey, M. Dadi, G. Dafoe, J. Dafoe, W. Dagley, A. Dahmani, J. Dai, C. Daigle, J.
Daigle, B. Daignault, P. Dale, D. Dalgarno, L. Dalgetty-Rouse, G. Dallaire, J. Dallaire, B. Dalley, G. Dalley, S. Dalrymple, M. Dalton, G. Daly, G. Dalziel, S. Dams, E. Dana, C. Danaher, A. Danbrook, T. Danbrook, W. Danchak,
J. Daniels, T. Daniels, D. Danilkewich, G. Dann, I. Dantiwala, C. Danyluk, P. Danyluk, R. Danyluk, D. Daraban, S. Darai, H. Darbin, A. Dareichuk, V. Darel, E. Dargatz, C. Daria, M. Darling, W. Darling, S. Darrah, K. Darvill, M.
Dashti, F. Daub, J. Daugherty, D. Dave, M. Dave, C. Davey, L. David, P. David, W. David, J. Davidson, M. Davidson, S. Davidson, T. Davidson, C. Davies, D. Davies, J. Davies, L. Davies, M. Davies, N. Davies, S. Davies, C.
Davis, H. Davis, J. Davis, K. Davis, R. Davis, E. Davison, D. Dawe, J. Dawe, S. Dawe, M. Dawes, J. Dawson, R. Dawyduk, C. Day, D. Day, T. Day, J. Daye, V. Daze, S. De Graaf, R. De Jesus, R. De Leeuw, B. De Lorenzo, A.
De Sousa, W. DeBona, S. DeBruycker, J. DeCoste, S. DeFord, B. DeHaan, R. DeJong Dyck, E. DeLaRonde, C. DeLand, M. DeLorme, C. DeMone, R. DeMott, J. DeVries, B. Deacon, I. Deaconu, P. Deagle, M. Dean, A. Dearaway,
G. Dearden, C. Deaver, T. Debler, S. Debnath, D. Deboer, D. Dechaine, J. Dechaine, R. Dechaine, P. Dechant, R. Dechesne, B. Decker, D. Decker, J. Decker, K. Decker, M. Decker, R. Decker, J. Decoeur, D. Decoine, W. Dedam,
E. Dee, L. Deep, M. Deering, D. Defoort, L. Defoort, M. Degenstien, A. Deibert, E. Deisting, R. Deitz, M. DelMastro, D. DelaCruz, L. Delaire, I. Delaney, P. Delany, J. Delaurier, M. Delfin, F. Dell'Ovo, M. Dell, M. Delong, A.
Demaiter, C. Dempsey, S. Dempsey, M. Denault, D. Deneau, D. Denney, F. Denney, G. Denney, S. Dennis, S. Denny, J. Dent, H. Derakhshan, D. Derbyshire, J. Derix, B. Derochie, M. Derry, A. Desai, C. Desai, D. Desai, G.
Desai, P. Desai, R. Desai, M. Deschambeau, T. Deschamps, D. Deschenes, A. Desharnais, V. Deshpande, D. Desjardins, C. Desjardins-Knowlden, G. Desjardins-Knowlden, C. Desjarlais, C. Desmarais, J. Desnoyers, M.
Desormeau, L. Despins, D. Dessario, M. Detta, P. Deutcheu, K. Deutsch, A. Deutscher, S. Deval, L. Devey, B. Dew, T. Dew, C. Dewar, J. Dewar, T. Dewhurst, D. Dey, K. Deyaegher, M. Deyan, G. Dhaliwal, H. Dhaliwal, M.
Dhaliwal, P. Dhalwala, B. Dhanesha, P. Dhanjal, J. Dharamsi, M. Dhariwal, M. Dhere, D. DiBenedetto, B. Diamond, D. Diaz, L. Diaz, M. Diaz, L. Dick, K. Dickey, A. Dicks, E. Dicks, J. Dicks, N. Dicks, C. Dickson, F. Dickson, A.
Didenko, J. Diederich, M. Dief, P. Diggle, S. Diggle, M. Diiorio, I. Dikau, E. Dillabough, R. Dillman, K. Dilts, A. Dimapilis, X. Ding, Y. Ding, G. Dingwell, R. Dingwell, H. Dinn, R. Dinn, P. Dion, S. Dionne, R. Diputado, M. Dirk,
S. Dirk, T. Ditchburn, A. Dixit, C. Dixon, D. Dixon, R. Dixon, T. Dixon, D. Dixson, K. Do, W. Dobchuk, C. Dobek, L. Dober, S. Dobie, C. Dobson, L. Dobson, S. Dobson, R. Docksteader, L. Dodd, R. Dodd, P. Dodsworth, M. Doepel,
R. Doering, J. Doetzel, J. Doiron, K. Doiron, G. Dolan, E. Doleman, J. Doleman, S. Dolhanty, K. Doll, D. Dolynchuk, G. Doma, G. Domalain, R. Domazet, B. Dombrova, D. Domin, S. Dominguez, K. Donahue, K. Donald, E.
Donaldson, S. Donaldson, R. Donaleshen, C. Dong, M. Dong, J. Donohoe, J. Donovan, N. Donovan, J. Doonanco, T. Dootka, S. Dorer, A. Dorey, M. Dorocicz, J. Dorusak, A. Dosanjh, M. Doucet, D. Doucette, K. Doucette, P.
Douglas, T. Dove, L. Dovichak, R. Dow, S. Dow, A. Dowd, J. Dowd, E. Dowell, S. Dowell, M. Dowman, P. Downes, A. Downey, D. Downey, J. Downey, P. Downey, A. Downs, A. Doyer, R. Doyer, G. Doyle, L. Doyle, S. Drake,
P. Drapeau, G. Draper, K. Draper, T. Draper, W. Draper, D. Draycott, J. Dreaddy, S. Drebit, K. Dreger, C. Drescher, D. Dressler, C. Drevant, B. Drew, D. Drew, T. Dreyer, C. Driedger, A. Driemel, A. Drier, S. Driscoll, T. Driscoll, E.
Drolet, R. Drolet, R. Drosu, S. Drouin, A. Drover, B. Drover, C. Drover, R. Drover, R. Drummond, C. Drury, D. Drury, S. Drysdall, M. Du Preez, M. Du, C. Duane, R. Duarte, M. Dube, N. Dube, R. Dube, T. Dube, J. Dubeau, T. Dubie,
G. Dubois, J. Dubois, J. Dubuc, D. Duby, C. Dubyk, M. Ducey, R. Ducharme, S. Ducharme, P. Duchesnay, C. Duchesne, J. Duchscherer, J. Duczek, P. Duda, S. Dudley, L. Dueck, R. Dueck, G. Duff, C. Duffett, K. Duford, E. Dufour,
P. Dugay, C. Duggan, R. Duggan, W. Duggan, D. Duguid, A. Duhaime, J. Dul, E. Dulay, C. Dumais, J. Dumas, T. Dumba, O. Dumitrache, G. Dumont, Y. Dumont, L. Dumoulin, C. Dunbar, H. Duncan, J. Duncan, S. Duncan, B.
Dunn, D. Dunn, J. Dunn, P. Dunn, R. Dunn, S. Dunn, B. Dunne, J. Dunsmuir, D. Duplessie, K. Dupuis, J. Durdle, A. Durham, J. Duris, K. Durocher, H. Dutchak, J. Dutchak, O. Dutka, R. Duval, M. Dux, B. Dwyer, C. Dwyer, R.
Dwyer, D. Dybala, J. Dybala, A. Dyck, C. Dyck, C. Dyer, J. Dyer, T. Dyer, E. Dyjur, A. Dyke, L. Dyke, S. Dykstra, R. Dyson, B. Dzirasah, K. Dzwonek, J. Eagleson, B. Eales, G. Earl, R. Earl, J. Easthope, B. Eastman, J. Eastman,
A. Easton, J. Easton, M. Easton, K. Eberle, R. Ebuna, T. Eburne, G. Ecker, E. Edeonu, D. Edgington, P. Edirisinghe, A. Edmunds, J. Edmunds, D. Edwards, J. Edwards, P. Edwards, T. Eeuwes, S. Effiong, A. Effray, T. Egan, L.
Egeland, R. Eggen, C. Eggleton, M. Egniem, A. Egresits, C. Ehnes, C. Ehresman, I. Eichelbaum, B. Eitzen, D. Ekdahl, J. Ekelund, C. Ekpekurede, S. Ekstrom, A. El Chayeb, M. El-Harakeh, O. El-Sayed, R. Elaschuk, M. Elbanna,
M. Elgarni, D. Elia, T. Elias, M. Elias-Neira, R. Elko, K. Elladen, S. Ellerton, P. Ellingson, D. Elliott, H. Elliott, J. Elliott, R. Elliott, S. Elliott, W. Elliott, D. Ellis, K. Ellis, S. Ellis, C. Ellsworth, E. Ellsworth, K. Ellsworth, T. Elmassah,
A. Elmobarik, M. Elms, M. Eloursa Escanela, E. Elson, J. Elson, A. Eluik, T. Ely, C. Emberley, V. Embleton, H. Emery, D. Emond, J. Emro, J. Engel, J. Engen, R. Engler, T. Engler, J. English, R. Enns, M. Entz, R. Ephgrave, J. Epp,
J. Erasmus, S. Erb, D. Ereaut, B. Eresman, C. Erfle, A. Erickson, B. Erickson, D. Erickson, S. Erickson, N. Erixon, M. Erl, M. Ernst, P. Ersh, C. Erskine, D. Ertmoed, P. Escalona, S. Eschak, P. Escobar, L. Eshaq, N. Eskandar, G.
Eskandari, M. Espejo, R. Espenido, L. Espie-Winsor, A. Espindola, B. Estey, O. Estrada, D. Etherington, S. Etherington, G. Etti, A. Evans, D. Evans, J. Evans, R. Evans, T. Evans, K. Evdokimoff, J. Eveleigh, L. Eveleigh, S. Eveleigh,
A. Everson, C. Eves, J. Ewald, R. Ewing, V. Ezeronye, L. Faber, T. Fabrick, R. Faechner, D. Fagnan, E. Faichney, B. Fairbairn, B. Fairey, S. Fairfield, M. Faiz, S. Faizal, E. Falconer, S. Fallahi, Y. Fang, D. Fanning, H. Farah, S. Farn,
D. Farney, G. Farrell, T. Farrell, R. Farrer, T. Farrer, D. Farrow, S. Farrow, S. Faruqi, W. Faryna, B. Fast, R. Fast, S. Fast, A. Faucher, C. Faucher, R. Faustini, E. Fauth, C. Fayant, R. Fayant, M. Fear, R. Featherstone, S. Feaver, T.
Feaver, N. Fecteau, M. Federucci, D. Fedoruk, E. Fedossova, C. Fedun, M. Fedyk, T. Fedyna, J. Feener, D. Fehr, B. Feil, D. Feland, I. Feland, J. Feland, D. Feller, R. Feltham, E. Fender, M. Feng, B. Fenrich, K. Fenrich, L. Fentie,
A. Ferbey, A. Ferdjallah, K. Ferdous, S. Ferenc, K. Ference, L. Ference, B. Ferguson, C. Ferguson, H. Ferguson, M. Ferguson, R. Ferguson, S. Ferguson, M. Ferhatbegovic, B. Fernandes, L. Fernandez Exposito, A. Fernandez, E.
Fernandez, S. Fernandez-Trujillo, N. Ferrer, B. Ferris, M. Ferris, M. Ferron, M. Ferry, R. Fersch, L. Fetter, J. Fewer, V. Fiacco, D. Fichter, J. Fidler, B. Field, M. Fielden, K. Fielding, M. Fielding, W. Fielding, W. Fields, B. Fifield, C.
Filewych, C. Filgate, I. Filipescu, D. Fillier, T. Fillmore, N. Findlay, T. Findlay, A. Fink, B. Finlayson, J. Finley, D. Finnamore, C. Finnebraaten, K. Finnerty, R. Finney, B. Finnie, E. Finnigan, K. Finnigan, T. Finnigan, T. Fir, C. Fischer,
L. Fischer, W. Fischer, C. Fisher, D. Fisher, L. Fisher, A. Fisk, C. Fitzgerald, S. Fitzgerald, S. Fitzner, S. Fitzpatrick, G. Fitzsimmons, K. Flack, M. Flahr, C. Flamont, J. Flamont, D. Flannery, B. Fleck, M. Flegel, A. Fleming, D. Fleming,
R. Fleming, S. Fleming, T. Fleming, J. Fletcher, L. Fletcher, P. Flett, R. Flett, B. Flier, I. Florea, B. Flottvik, J. Floyd, B. Flynn, J. Flynn, R. Flynn, S. Flynn, R. Fobes, C. Fogal, K. Foisy, D. Fokema, E. Follis, R. Folmer, P. Foming, G.
Fondjo, Y. Fong, B. Fontaine, D. Fontaine, G. Fontaine, R. Fontaine, B. Foord, L. Foote, R. Foran, D. Forbes, M. Forbes, D. Forbister, A. Forcade, D. Ford, G. Ford, T. Ford, J. Foreman, B. Forest, C. Forfar, L. Forget, B. Forman, D.
Forman, C. Formanek, R. Formanek, T. Fornwald, A. Forrest, B. Forrester, G. Forrester, L. Forrester, B. Forrister, J. Forsberg, B. Forshner, K. Forshner, M. Forster, S. Forster, S. Forsyth, H. Forte, A. Fortier, C. Fortier, D. Fortin, B.
Foss, R. Foss, S. Foss, D. Fosseneuve, C. Foster, D. Foster, K. Foster, R. Foster, S. Foster, V. Foster, D. Fotty, C. Fotur, O. Fouego, A. Fougere, K. Foulds, R. Foulkes, G. Fountain, J. Fountain, B. Fouracres, L. Fournier, H. Fowell,
C. Fowler, G. Fowler, D. Fox, J. Fox, R. Fox, M. Foxton, K. Fraboni, S. Fraino, C. Frampton, J. France, R. France, M. Francescone, D. Franche, O. Franchi, D. Francis, M. Franco, C. Frank, D. Franke, A. Frankiw, P. Fransen, K.
Franson, W. Franson, S. Franssen, R. Frasch, B. Fraser, C. Fraser, G. Fraser, K. Fraser, M. Fraser, R. Fraser, K. Frazer, C. Freake, G. Freake, R. Freake, B. Frechette, K. Frechette, S. Freckelton, R. Fredericks, A. Freeman, G.
Freeman, M. Freeman, J. Freer, U. Freiberg, E. Frejoles, J. French, R. French, R. Frere, J. Frese, L. Freund, K. Freyman, K. Friedrich, D. Friedt, K. Friedt, W. Friend, D. Friesen, F. Friesen, H. Friesen, J. Friesen, N. Friesen, K. Frith,
A. Frizorguer, D. Frizzell, J. Froc, M. Froehler, C. Frosini, F. Frosini, C. Froude, S. Froude, A. Fry, T. Fryer, X. Fu, C. Fudge, J. Fudge, L. Fudge, R. Fudge, K. Fujimoto, D. Fukushima, W. Fulkerson, D. Fuller, J. Fuller, C. Fulowski,
D. Fung, J. Fung, N. Fung, S. Fung-Yau, C. Funk, J. Funk, K. Funk, R. Funk, M. Funke, J. Furey, M. Furey, A. Furgiuele, A. Furlong, G. Furlong, L. Furlong, W. Furman, T. Furuya, C. Fuster, R. Fyfe, A. Gabr, K. Gabrielson, M.
Gabruch, D. Gabruck, L. Gadowski, K. Gadzala, J. Gaeta, R. Gaetz, L. Gaffney, N. Gafuik, A. Gage, C. Gagne, D. Gagne, J. Gagnon, K. Gagnon, R. Gagnon, S. Gagnon, W. Gail, B. Galbraith, M. Galea, J. Galey, R. Gall, R.
Gallagher, F. Gallant, M. Gallant, R. Gallant, F. Gallardo, J. Galliott, M. Gallon, J. Galotta, B. Gamble, D. Gamblin, C. Gamboa, L. Gamboa, W. Gamp, F. Gan, A. Gandhi, P. Gandhi, V. Gandhi, J. Ganie, D. Ganske, B. Gantz, Y.
Gao, V. Gapaz, M. Garbin, A. Garcia, C. Garcia, D. Gardham, K. Gardiner, S. Gardiner, L. Gardner, S. Gardner, J. Gareau, R. Gareau, T. Gareau, R. Garg, V. Garg, K. Garland, A. Garneau, W. Garner, P. Garon, E. Garrison, L.
Garvey, C. Garzon, C. Gascon, O. Gascoyne, K. Gaslard, V. Gatchalian, L. Gates, J. Gatrell, S. Gauchan, F. Gaudet, W. Gaugler, L. Gauld, G. Gaulin, K. Gaulton, C. Gauthier, D. Gauthier, F. Gauthier, J. Gauthier, M. Gauthier, N.
Gauthier, P. Gauthier, S. Gauthier, K. Gautschi, C. Gawley, T. Gaydos, G. Gayton, C. Geddes, J. Geddes, D. Geleta, O. Gelowitz, M. Gemmell, J. Genereux, M. Genereux, G. Genge, B. Gensollen del Barco, P. Gentles, C. George,
M. George, R. Georgescu, J. Georget, S. Geremia, J. Gergely, B. Gerke, G. Gerla, E. Gerlakh, J. Gerlinger, M. Germain, R. Germain, C. German, K. Gerow, S. Gerow, E. Gervais, K. Gervais, M. Gervais, P. Gervais, K. Gessner,
T. Getchell, S. Getson, V. Getty, G. Getz, K. Getzinger, L. Ghasem Rashid, K. Ghesmat, M. Ghorbanie, J. Ghosh, E. Ghoubrial, S. Gibbon, A. Gibbs, E. Gibbs, C. Gibson, D. Gibson, J. Giebelhaus, S. Giefer, W. Giers, D. Giesbrecht,
J. Giesbrecht, T. Giesbrecht, K. Gifford, J. Gigg, D. Giggs, G. Gilbert, K. Gilbertson, C. Giles, S. Giles, V. Giles, P. Gilhespy, D. Gill, J. Gill, K. Gill, M. Gill, N. Gill, R. Gill, S. Gill, J. Gillam, D. Gillanders, J. Gillatt, S. Gillespie,
A. Gillingham, D. Gillingham, H. Gillingham, J. Gillingham, L. Gillingham, M. Gillingham, S. Gillingham, E. Gillis, M. Gillund, C. Gilman, K. Gilman, E. Gimenez, R. Gimoro, G. Gin, P. Gingras, K. Ginter, M. Ginter, T. Ginther, C.
Giraldo Sierra, L. Giraldo, D. Girard, G. Girard, S. Girbav, R. Girletz, J. Girouard, L. Giroux, B. Gisby, M. Gisondo Crawford, J. Gladue, P. Glasier, K. Glavine, M. Glavine, S. Glazier, R. Gleasure, R. Gleed, J. Glen, J. Glendenning,
G. Glenn, D. Gliddon, D. Gloade, D. Glover, R. Glover, S. Glubish, J. Gnam, R. Gnatovski, M. Go, J. Godin, K. Godin, D. Godwin, L. Godwin, M. Goebel, L. Goerzen, C. Gogol, J. Gogol, B. Gogowich, H. Goldberg, D. Golden, A.
Goll, D. Goll, R. Goman, E. Gomez, J. Gomez, C. Gomuwka, E. Gong, K. Gong, M. Gonzales, P. Gonzalez Sierra, I. Gonzalez, N. Gonzalez, Y. Gonzalez, C. Good, P. Good, J. Goodair, C. Goodall, A. Goodine, C. Goodman, J.
Goodman, P. Goodman, A. Goodwin, W. Goodwin, B. Goodyear, J. Goodyear, R. Gooler, J. Gorai, K. Gordeyko, I. Gordon, J. Gordon, K. Gordon, S. Gordon, J. Gorgichuk, D. Gorrie, J. Gorski, R. Goshi, S. Gosling, M. Gospodinov,
B. Gosse, M. Gosse, R. Gosse, S. Gosse, T. Gosse, T. Gosselin, Y. Gosselin, K. Goudie, C. Goudreau, C. Gough, A. Gould, B. Gould, T. Gould, H. Gouldie, G. Goulding, C. Goulet, P. Goulet, J. Gourlie, G. Gouthro, S. Gouthro, M.
Govindaswamy Krishnamoorthy, M. Goyal, L. Goymer, J. Graca, N. Grace, R. Graf Jr., D. Graham, J. Graham, M. Graham, P. Graham, Q. Graham, S. Graham, T. Graham, R. Grandy, B. Granger, J. Granger, C. Grant, J. Grant,
M. Grant, R. Grant, S. Grant, A. Graup, B. Gravel, R. Gravell, T. Graveson, A. Gray, B. Gray, C. Gray, D. Gray, P. Gray, R. Gray, S. Gray, C. Grayston, J. Greaves, G. Grebowski, A. Greeley, C. Green, D. Green, G. Green, J. Green,
K. Green, M. Green, P. Green, T. Green, W. Green, C. Greenawalt, D. Greenawalt, C. Greene, D. Greene, T. Greene, A. Greenfield, R. Greening, G. Greenwood, K. Greenwood, M. Greenwood, R. Greenwood, D. Greep, K. Greig,
A. Grenier, J. Grenon, J. Greter, A. Grewal, B. Grice, C. Grice, R. Grice, R. Griemann, S. Grier, L. Grierson, R. Grieve, J. Griffin, M. Griffin, P. Griffin, E. Griffiths, H. Griffiths, J. Griffiths, K. Griffiths, R. Griswold, R. Groenen, Z.
Groom, M. Grosseth, A. Grossi, J. Grouchy, P. Grove, D. Grundner, D. Grzela, S. Gu, C. Guay, C. Gudjonson, C. Gudmundson, P. Guedez, I. Guelber, J. Guerin, E. Guerra, M. Gueye, D. Guglielmin, A. Guillen, K. Guimond, R.
Guinup, A. Guitard, A. Gulamhusein, K. Gulamhusein, R. Gulati, S. Guled, R. Gulutzan, J. Gumbley, E. Gummeson, L. Gunnell, I. Gunning, R. Gunning, A. Gupta, S. Gupta, J. Gurba, M. Gurin, C. Gursky, J. Gushue, T. Gushue,
7
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT T. Gusnowski, R. Gussen, C. Gustafson, G. Gustafson, P. Gut, R. Gutknecht, G. Gygi, S. Gysler, D. Ha, T. Ha, E. Haag, B. Haahr, B. Haas, C. Haas, S. Haas, R. Haberlack, M. Haberoth, S. Habiby, R. Hache, C. Hachey, K. Hachey-
Lalonde, J. Hack, S. Hackett, E. Hadada, V. Haddad, L. Hadi, T. Hadji, N. Hadskis, K. Hagan, S. Hagan, S. Hagen, 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, D. Halifax, A. Hall, B. Hall, C. Hall, J. Hall, R. Hall, S. Hall, T. Hall, S. Halland, S. Hallas, C. Hallborg, R. Halldorson, B. Hallett, G. Hallett, J. Hallett, K. Halliday, O. Hallmark, R. Hallock, A.
Halvorson, B. Halvorson, C. Hambly, B. Hamborg, A. Hameed, J. Hamel, P. Hamel, T. Hamel, J. Hamelin, B. Hamer, S. Hamill, D. Hamilton, J. Hamilton, M. Hamilton, R. Hamilton, T. Hamilton, T. Hamlyn, K. Hamm, A. Hammami,
M. Hammel, R. Hammer, D. Hammerlindl, S. Hammersley, G. Hammond, J. Hammond, M. Hammond, C. Hamori, C. Hampton, B. Hamrell, E. Han, G. Hanas, B. Hancock, E. Hancock, B. Hancott, S. Hancott, F. Hanif, E. Hanlon,
S. Hanlon, E. Hann, K. Hann, R. Hann, R. Hannah, A. Hansen, D. Hansen, J. Hansen, K. Hansen, M. Hansen, P. Hansen, R. Hansen, V. Hansen, D. Hanson, L. Hanson, R. Hanson, T. Hanson, J. Hanthorn, Z. Haqqi, T. Hara, I.
Harb Chouchane, E. Harband, B. Harbin, L. Harder, C. Harding, P. Harding, G. Hardisty, J. Hardisty, B. Hardy, F. Hardy, H. Hardy, A. Hare, K. Hargrove, E. Harikumar, K. Harke, A. Harlal, J. Harland, D. Harley, E. Haroldson, G.
Harper, E. Harrietha, R. Harrietha, A. Harris, B. Harris, C. Harris, J. Harris, M. Harris, S. Harris, C. Harrison, D. Harrison, N. Harrison, R. Harsany, C. Hartery, C. Hartl, M. Hartt, A. Harty, J. Harty, B. Harvey, D. Harvey, G. Harvey,
J. Harvey, K. Harvey, P. Harvey, R. Harvey, S. Harvey, I. Hashi, H. Hashmi, K. Hasiuk, M. Hassan, O. Hassan, B. Hassen, C. Hassenrueck, J. Hatala, J. Hatch, J. Hatcher, P. Hatt, G. Hatto, W. Hatton, D. Haub, R. Hauger, T.
Hauger, B. Haugo, W. Hausch, J. Haviland, A. Hawco, S. Hawco, T. Hawco, D. Hawkins, C. Hawley, A. Hawthorne, S. Haxton, N. Hay, D. Hayashi, B. Hayden, C. Hayden, J. Hayden, J. Haydo, D. Hayes, M. Hayes, P. Hayes,
K. Hayko, D. Haynes, J. Haynes, L. Haynes, A. Hayward, M. Hayward, R. Hayward, T. Hayward, J. Hazin, S. He, T. He, Y. He, T. Head, M. Headrick, B. Heagy, C. Heagy, J. Heagy, A. Heale, L. Healy, K. Heard, B. Hearn, B.
Heasley, A. Heath, B. Heath, C. Heath, D. Heath, L. Heath, B. Heatley, J. Heavens, T. Hebel, B. Hebert, D. Hebert, G. Hebert, J. Hebert, M. Hebert, B. Hebner, S. Heck, T. Heck, D. Heemeryck, C. Heffner, D. Hefford, C. Hehr,
T. Heid, M. Heigl, J. Heilman, F. Hein, R. Hein, J. Heinen, M. Heinen, R. Heinrichs, B. Heise, S. Heiskanen, D. Heit, R. Heiz, R. Helland, B. Helliker, A. Hellyer, M. Helman, R. Helyar, C. Hemington, D. Hemmelgarn, W.
Hemminger, B. Hemstock, D. Henderson, R. Henderson, W. Henderson, E. Hendrickson, K. Hendrickson, S. Hendry, R. Henley, K. Hennessey, A. Hennig, E. Henriquez, C. Henry, R. Henry, T. Henry, D. Herauf, K. Herba, L. Hergott,
L. Herlina, B. Herman, J. Herman, W. Herman, A. Hernandez, G. Hernandez, M. Hernandez, P. Hernandez, L. Heron, G. Herrebout, N. Herrebout, C. Herring, R. Herrington, D. Hertzsprung, D. Heshka, R. Heska, B. Heugh, A.
Heuthorst, J. Hevey, J. Hewitt, M. Hewitt, T. Hewitt, C. Hewlett, J. Hewlett, K. Hewlin, C. Heywood, R. Hibbs, D. Hicke, P. Hickey, R. Hickey, B. Hicks, C. Hicks, K. Hicks, R. Hicks, L. Hiebert, R. Hiebert, M. Hiemstra, T.
Hiemstra, E. Hietanen, R. Higa, A. Higgins, J. Higgins, L. Higgins, R. Higgins, S. Higgins, P. Higgitt, C. Hildahl, C. Hildebrand, T. Hildebrand, D. Hill, H. Hill, J. Hill, K. Hill, R. Hill, T. Hill, B. Hillier, C. Hillier, D. Hillier, J. Hillier,
S. Hillier, T. Hillier, C. Hills, T. Hills, D. Hillyard, R. Hilton, B. Hindmarch, K. Hingley, W. Hinkle, T. Hinks, K. Hinton, N. Hinze, D. Hiscock, D. Hitra, G. Ho, J. Ho, M. Ho, T. Ho, R. Hoath, W. Hobart, J. Hobbs, D. Hoblak, R. Hoda,
C. Hodder, G. Hodder, J. Hodder, O. Hodder, D. Hodge, L. Hodge, R. Hodgins, P. Hodgkinson, D. Hodgson, A. Hoeg, A. Hoey, N. Hoey, L. Hoff, T. Hoff, R. Hoffman, M. Hofstrand, G. Hogan, S. Hogan, A. Hogg, J. Hogg, R. Hogg,
J. Hoilund, B. Hokanson, B. Holaki, K. Hole, D. Holik, K. Holland, M. Holland, C. Hollands, A. Hollebakken, I. Hollenbeck, P. Hollett, D. Holley, D. Hollingshead, G. Holloway, J. Holloway, L. Holloway, C. Holman, D. Holman,
F. Holman, R. Holman, N. Holmberg, J. Holmes, K. Holmes, T. Holmes, D. Holt, E. Holt-Groom, B. Holthe, C. Holthe, J. Holton, J. Holuk, D. Holwell, A. Holz, G. Homann, D. Honing, A. Hood, C. Hood, D. Hood, F. Hood, J. Hood,
G. Hook, J. Hooper, R. Hooper, M. Hoormann, A. Hope, P. Hopkins, S. Hopkins, Y. Hopkins, C. Hopps, T. Hopwood, A. Hordy, D. Horlick, R. Horn, T. Hornberger, M. Hornsby, K. Hornseth, B. Horobec, K. Horvath, M. Horvath, R.
Horvath, J. Horyn, K. Hosker, A. Hoskins, B. Hossain, M. Hossain, T. Hou, S. Houck, C. Houle, E. Houlihan, A. House, G. House, P. House, R. House, T. House, G. Houston, P. Houston, K. Hovdebo, D. Howard, L. Howard, T.
Howard, I. Howatt, C. Howden, R. Howden, J. Howell, L. Howell, T. Howell, S. Howlader, M. Howrish, J. Howse, T. Hoyles, D. Hoyt, R. Hoyt, B. Hoza, M. Hrabarchuk, D. Hrycak, T. Hrycay, V. Hrycuik, B. Hryniw, A. Hrynkevych,
J. Hu, M. Hu, T. Hu, Y. Hu, D. Huang, J. Huang, N. Huang, Q. Huang, M. Hubbers, G. Huber, W. Hubert, K. Huculak, W. Huddlestun, A. Hudkins, A. Hudson, D. Hudson, J. Hudson, P. Hudson, S. Huebner, K. Huey, V. Huey, A.
Hughes, B. Hughes, D. Hughes, J. Hughes, M. Hughes, J. Hughston-Bulmer, E. Huh, K. Hui, M. Hulan, D. Hull, F. Hulme, W. Hulme, M. Human, T. Humbke, R. Humphrey, A. Humphries, C. Humphries, S. Humphries, T.
Humphries, D. Hunchak, I. Hundeby, M. Hundessa, M. Hung, C. Hunt, D. Hunt, M. Hunt, D. Hunter, E. Hunter, K. Hunter, L. Hunter, P. Hunter, R. Hunter, S. Hunter, W. Hunter, M. Hupchuk, K. Hupp, J. Hurd, K. Hurd, G. Hurley,
S. Hurley, R. Hurtado Urdaneta, R. Hurtado, N. Husain, A. Hussain, S. Hussaini, G. Hussey, C. Hussynec, L. Huston, A. Hutchinson, C. Hutchinson, D. Hutchinson, R. Hutchinson, C. Hutchison, L. Hutchison, R. Hutscal, D.
Huxley, A. Huynh, C. Huynh, M. Huys, S. Hwang, S. Hyatt, A. Hymanyk, A. Hynes, C. Hynes, D. Hynes, E. Hynes, G. Hynes, J. Hynes, K. Hynes, L. Hynes, M. Hynes, N. Hynes, S. Hynes, T. Hynes, S. Hyrcha, J. Iampen, K.
Iampen, G. Iannattone, L. Iannattone, P. Iannattone, T. Ibatullin, R. Ibbotson, T. Idler, A. Idowu, G. Iervella, H. Iftemie, N. Ilchuk, T. Ilie, E. Imbery, W. Imeson, K. Imlach, M. Imran, G. Indome, C. Inglis, E. Ingram, G. Ingram, J.
Inlow, B. Inman, C. Innes, M. Inscho, D. Ip, A. Iqbal, M. Iqbal, R. Ireton, M. Irfan, J. Irons, K. Ironstand, R. Irvine, M. Irving, S. Irwin, J. Isaacs, C. Isaka, B. Isbister, C. Isea Natera, D. Isele, B. Ish, H. Ishaque, A. Islam, M. Islam,
U. Islam, F. Isley, G. Ismaguilova, O. Issa, A. Ivany, B. Ivany, D. Ivany, L. Iversen, J. Ivezic, M. Jablonski, C. Jabusch, C. Jackson, D. Jackson, K. Jackson, R. Jackson, S. Jackson, T. Jackson, S. Jacob, C. Jacobs, J. Jacobs, K.
Jacobs, M. Jacobs, K. Jacobson, M. Jacome, A. Jacques, A. Jacula, C. Jacula, M. Jacula, D. Jaeger, A. Jaffer, M. Jahangiri, R. Jahanshahi, E. Jahelka, C. Jahraus, V. Jain, M. Jaindl, K. Jaji, R. Jakher, R. Jakubowski, B.
Jakulj, G. Jaleel, L. Jama, M. Jama, S. Jamam, D. Jaman, D. James, R. James, S. James, W. James, R. Jamieson, T. Jamieson, D. Jamilano Jr., A. Janes, D. Janes, J. Janes, M. Janes, S. Jang, J. Jankowski, Z. Janosova,
D. Jans, S. Jansky, S. Janssen, T. Janusc, A. Janzen, L. Janzen, M. Janzen, L. Jardie, C. Jardine, J. Jardine, N. Jaricha, C. Jarratt, B. Jarvis, J. Jarvis, K. Jarvis, K. Jaschke, J. Jeannotte, R. Jeanson, J. Jechow, A. Jegou,
W. Jellison, C. Jenkins, G. Jenkins, J. Jenkins, T. Jenkins, R. Jenniex, D. Jennings, A. Jensen, B. Jensen, D. Jensen, K. Jensen, L. Jensen, Q. Jensen, T. Jensen, V. Jensen, D. Jenson, K. Jentas, K. Jerke, M. Jeroncic, R.
Jeronymo, G. Jervis-Read, B. Jesso, C. Jesso, M. Jesso, D. Jessome, T. Jessome, J. Jesson, S. Jevne, B. Jevne-Dick, B. Jewell, R. Jha, P. Jia, N. Jiang, Q. Jiang, S. Jiang, Y. Jiang, R. Jimeno, X. Jing, P. Jingar, K. Jivraj, D.
Joa, M. Joarder, P. Jobin, N. Jobson, K. Jochaud du Plessix, J. Jocksch, D. Jodoin, G. Joe, J. Joffre, G. Johal, K. Johansson, B. Johns, D. Johns, A. Johnson, B. Johnson, C. Johnson, D. Johnson, G. Johnson, J. Johnson, K.
Johnson, M. Johnson, N. Johnson, R. Johnson, S. Johnson, T. Johnson, D. Johnston, H. Johnston, M. Johnston, N. Johnston, R. Johnston, D. Johnston-Watson, B. Johnstone, C. Johnstone, E. Johnstone, R. Johnstone, S.
Johnstone, V. Jolliffe, J. Jonasson, A. Jones, B. Jones, C. Jones, D. Jones, E. Jones, G. Jones, K. Jones, L. Jones, M. Jones, N. Jones, P. Jones, R. Jones, S. Jones, V. Jones, N. Jongkind, N. Jonlija, P. Joo, O. Joos, J.
Jorawsky, D. Jordan, M. Jordan, D. Jordison, B. Jorgensen, C. Jorgensen, D. Jorgensen, L. Jorgensen, L. Jorgenson Donahue, D. Joseph, P. Joseph, V. Joseph, A. Joshi, T. Joshi, U. Joshi, S. Josselyn, M. Jovic, D. Jowsey,
M. Juanerio, R. Jubinville, A. Junaid, J. Jung, S. Jung, C. Jungen, R. Jungkind, M. Junio-Read, C. Jurgenliemk, K. Jurouloff, A. Kachra, C. Kada, L. Kada, T. Kadikoff, L. Kadutski, G. Kadylo, C. Kaglea, R. Kahanyshyn, A. Kaid,
G. Kailas, K. Kajorinne, H. Kakadiya, S. Kalbag, L. Kalinin, J. Kallis, A. Kalmet, N. Kalomiris, D. Kalynchuk, B. Kamath, A. Kamke, G. Kamon, A. Kamran, S. Kanarek, A. Kandasamy, S. Kandulva Chakrapany, J. Kane, L. Kane,
S. Kane, N. Kang, Z. Kanji, D. Kantz, S. Kapeluck, Y. Karayan Moosafi, P. Karimi, R. Karlowsky, J. Karlson, R. Karlson, S. Karmakar, M. Karpan, B. Karpiak, C. Karpiak, J. Karr, K. Kartushyn, D. Kary, N. Kashirina, C. Kaskiw, M.
Kaspers, M. Kassim, A. Katebi, M. Kathan, D. Katnick, H. Katrip, A. Katyayan, J. Kaufman, M. Kaur, S. Kaur, S. Kaushik, C. Kavalec, T. Kavalec, T. Kawadza, K. Kay, O. Kay, G. Kaya, A. Kaye, G. Kazimirowich, M. Kealey, S.
Kealey, R. Kean, J. Kearley, M. Kearley, K. Keating, M. Keck, B. Keddie, A. Keebler, L. Keech, M. Keefe, C. Keehn, H. Keele, T. Keenan, P. Keglowitsch, P. Kehler, C. Keil, P. Keiley, G. Keith, J. Kelenc, M. Keller, C. Kelley, C.
Kellogg, E. Kellough, J. Kelloway, M. Kelloway, R. Kelloway, C. Kellsey, J. Kelly, M. Kelly, T. Kemmer, C. Kemp, S. Kempner, R. Kendall, S. Kendall, C. Kendell, D. Kendell, R. Kendell, C. Kendrick, M. Kendrick, B. Kennedy, C.
Kennedy, G. Kennedy, K. Kennedy, L. Kennedy, M. Kennedy, R. Kennedy, S. Kennedy, W. Kennedy, J. Kenny, R. Kenny, D. Kent, R. Kent, S. Kent, D. Kenyon, V. Kenyon, K. Keough, S. Kermanshachi, S. Kernachan, P. Kernaghan,
C. Kerpan, A. Kerr, D. Kerr, R. Kerr, S. Kerr, S. Kers, D. Ketchum, D. Kett, B. Kevol, M. Khalil, A. Khan, F. Khan, M. Khan, S. Khan, N. Khatri, R. Khatri, J. Kho, S. Khong, S. Khoromskaya, V. Khot, H. Khurana, S. Kiasosua, M.
Kichler, I. Kidd, R. Kidd, D. Kidger, B. Kidmose, C. Kiehn, K. Kieley, K. Kielt, L. Kiez, C. Kilback, D. Kilbreath, M. Kilcollins, C. Killick, O. Kilo, I. Kilpatrick, H. Kim, R. Kim, D. Kimmie, M. Kinden, K. Kindree, B. King, C. King, D.
King, G. King, I. King, J. King, M. King, N. 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, T. Kirilo, R. Kirk, D. Kirkham, L.
Kirkpatrick, M. Kirkwood, B. Kiss, K. Kiss, B. Kissel, M. Kissoon, F. Kitivi, B. Kiyawasew, C. Kiyawasew, G. Kjelshus, T. Kjemhus, J. Klaffl, A. Klassen, D. Klassen, J. Klassen, R. Klassen, S. Klassen, C. Klatt, A. Klause, D.
Klause, R. Klautt, R. Klimek, J. Klotz, G. Kluthe, R. Knee, S. Knelsen, W. Knelson, R. Kneteman, J. Knibbs, M. Kniebel, J. Knight, J. Knight-Ehiwe, J. Knipe, L. Knoblauch, D. Knoblich, B. Knopf, D. Knott, W. Knouse, G.
Knowlton, J. Knox, T. Knox, D. Knutson, D. Kobes, B. Kobzey, B. Koch, M. Koch, R. Koenig, K. Koger, C. Kohls, J. Kohut, B. Koizumi, M. Kokorudz, C. Kolberg, L. Kolberg, M. Kolenchuk, M. Kolesnikov, B. Koma, M. Komant, A.
Komm, S. Kompally, M. Kondor, B. Kondratowicz, R. Konrad, M. Konschuh, E. Kontuk, B. Kootenay, P. Korba, S. Korchagin, M. Koren, P. Kornacki, B. Korolischuk, J. Kosanovich, A. Kosasih, I. Koshcheev, R. Kosheiff, A. Koshlay,
B. Kosowan, V. Kostic, D. Kostiuk, K. Kostrub, S. Kostyshen, A. Kostyshyn, K. Kotkas, D. Kotze, K. Kovac, M. Kovac, B. Kovacs, R. Kovalenko, R. Kovasin, M. Kowalchuk, J. Kowalewski, R. Kowalski, K. Kowbel, D. Kozak, M.
Kozak, T. Kozina, A. Kozler, D. Kozler, A. Kozlowski, A. Kozovski, L. Kozovski, B. Kozuback, T. Kozyra, D. Krajci, D. Kramps, R. Kranitz, C. Kratchmer, T. Kratz, G. Krause, T. Krause, R. Krauss, R. Kravitz, C. Krawchuk, D. Krawec,
H. Krawec, J. Krawetz, M. Krawetz, J. Kreft, T. Kreics, M. Kreiser, B. Krell, J. Krenbrink, B. Kress, B. Kresse, K. Krewulak, A. Krishnamoorthy, R. Krishnamurthy, D. Krismer, N. Krochmal, D. Kroeger, R. Kroeker, K. Krogh, P.
Krol, K. Krowchenko, U. Krstic, R. Krueger, G. Kruger, K. Kruger, N. Krupka, T. Krushel, K. Krynowsky, J. Kube, C. Kubik, J. Kubik, C. Kucinar, G. Kucy, E. Kudrynytskyi, M. Kulkarni, C. Kully, B. Kumar, P. Kumar, R. Kumar, S.
Kumar, H. Kundert, C. Kung, J. Kung, D. Kunitz, J. Kuntz, T. Kuntz, P. Kuppers, D. Kurek, M. Kureshi, M. Kurowski, K. Kurschenska, K. Kursteiner, D. Kurtz, R. Kurtz, F. Kurucz, D. Kusmiadji, G. Kusuma, B. Kutash, D. Kuzemchuk,
S. Kuzmak, F. Kuzmic, C. Kwan, J. Kwan, R. Kwiatkowski, S. Kwiatkowski, A. Kwon, K. Kwong, T. Ky, K. Kyffin, D. Kyle, B. Kyllo, J. Kynock, R. Kynock, R. L'Heureux, J. L'Hirondelle, J. LaBelle, J. LaBossiere, T. LaBrie, A.
LaChance, A. LaPrade, E. LaRose, J. LaSha Pool, M. LaTorre, D. Labby, A. Laboucan, J. Laboucan, R. Laboucan, N. Lachance, J. Lacharite, K. Lacombe, R. Lacombe, P. Lacoste-Bouchet, D. Lacroix, S. Lacroix, L. Lacuna, A.
Laderoute, K. Lafferty, A. Laflamme, S. Lafond, D. Lafontaine, R. Laforge, L. Lafrance, L. Lafreniere, G. Lagace, M. Lagimodiere, O. Lagoke, D. Laha, M. Laha, B. Lahoda, D. Lahoda, J. Lahoda, C. Lai, R. Lai, S. Lai, T. Lai, E.
Laidlaw, K. Laidler, L. Laidler, A. Laing, R. Laing, S. Laird, A. Laite, M. Lake, J. Lakes, P. Lalani, J. Laliberte, K. Lalonde, P. Lalonde, C. Lam, D. Lam, E. Lam, I. Lam, J. Lam, N. Lam, R. Lam, S. Lam, K. Lamb, Z. Lamba, D. Lambert,
J. Lambert, S. Lambert, D. Lameman, R. Lameman, J. Lamontagne, R. Lamontagne, A. Lamouche, W. Lamoureux, O. Lampron, W. Lamptey, W. Land, E. Lander, A. Landry, C. Landry, E. Landry, G. Landry, J. Landry, L. Landry,
M. Landry, S. Landry, Y. Landry, W. Landsburg, B. Lane, M. Lane, W. Lane, R. Lanfranchi, J. Langdon, K. Langdon, M. Langdon, J. Lange, L. Lange, N. Lange, O. Lange, R. Lange, G. Langevin, S. Langford, W. Langford, T. Langill,
C. Langpap, B. Lanh, R. Laniec, T. Lanktree, C. Lanthier, L. Lanza, S. Lanza, C. Lapp, P. Lapp, S. Lapp, C. Lappin, M. Larade, G. Laramee, J. Larkin, T. Larko, J. Larochelle, A. Larocque, J. Larocque, R. Larsen, J. Larson, P. Larson,
R. Larson, B. Larsson, W. Latchuk, A. Latif, Z. Latif, C. Latimer, R. Latimer, J. Lau, S. Lau, L. Laube, A. Lauder, B. Laughlin, P. Laughman, D. Laurenson, K. Laurin, N. Laustsen, S. Laut, R. Lauze, J. Lauzon, M. Lavallee, D.
Laventure, K. Laverty, V. Laviano, B. Lavigne, J. Lavigne, A. Lavoie, C. Lavoie, D. Law, I. Law, S. Lawlor, B. Lawrence, D. Lawrence, E. Lawrence, L. Lawrence, R. Lawrence, S. Lawrence, W. Lawrence, J. Laya, A. Layland, K.
Layland, P. Layland, S. Layton, G. Lazaruk, S. Lazeski, T. Lazowski, R. Le Manne, L. Le, M. Le, N. Le, S. Le, T. Le, V. Le, B. LeBlanc, C. LeBlanc, E. LeBlanc, J. LeBlanc, L. LeBlanc, R. LeBlanc, W. LeBlanc, P. LeBlond, M. LeGrow,
Z. LeMoine, D. LeSann, B. Leach, T. Leach, R. Leahy, K. Leamon, D. Leask, M. Lebas, I. Leblanc, T. Leblanc, C. Lebrun, S. Lebsack, G. Leclerc, G. Ledger, J. Ledoux, C. Ledrew, J. Ledrew, A. Lee, D. Lee, G. Lee, H. Lee, J. Lee,
K. Lee, L. Lee, M. Lee, P. Lee, R. Lee, T. Lee, B. Leeman, G. Lefebure, D. Lefebvre, S. Lefebvre, D. Lefrancois, D. Legault, K. Legault, L. Legault, J. Legere, M. Legge, R. Legge, K. Lehal, B. Lehbauer, M. Lehouillier, P. Leibel, T.
Leibel, C. Leicht, P. Leighton, S. Leithoff, R. Lemoine, T. Lemon, R. Lendrum, P. Leniuk, C. Lenz, J. Lenzner, T. Leon, K. Leonard, M. Leonard, G. Leong, H. Leong, K. Lepage, D. Lepine, S. Lepp, L. Leppaie, P. Lepper, Y. Lerner, C.
Leschinski, G. Leslie, R. Leslie, S. Lester, B. Lesyk, C. Lesyk, K. Letby, F. Letkeman, P. Letkeman, T. Letkeman, A. Letourneau, M. Letourneau, H. Lett, D. Leung, E. Leung, J. Leung, K. Leung, M. Leung, P. Leung, Y. Leung, J.
Levack, J. Levesque, M. Levesque, R. Levesque, S. Lewchuk, C. Lewis, D. Lewis, E. Lewis, J. Lewis, K. Lewis, P. Lewis, R. Lewis, T. Lewis, W. Lewis, E. Lewynsky, W. Leyland, H. Li, J. Li, Q. Li, S. Li, X. Li, Y. Li, B. Liang, N.
Liang, S. Liao, C. Liba, M. Liber, Z. Licastro, D. Lidstone, H. Lien, S. Lien, J. Lieske, C. Lieverse, J. Lieverse, D. Lightburn, A. Likhar, D. Lilburn, H. Lim, M. Lim, F. Lin, H. Lin, J. Lin, Q. Lin, K. Linaker, B. Lind, K. Linder, T. Lindley,
K. Lindsay, D. Lindskog, D. Linfoot, A. Linggon, N. Link, P. Linklater, N. Linnell, J. Linton, M. Liou-McKinstry, R. Lipman, R. Liske, P. Lister, C. Little, G. Little, J. Little, R. Little, S. Little, J. Littlechilds, J. Liu Prest, H. Liu, J. Liu,
L. Liu, T. Liu, W. Liu, X. Liu, Y. Liu, E. Liv, J. Lively, J. Livingston, S. Livingstone, C. Lizee, J. Llanos, L. Llewellyn, R. Lloy, M. Lloyd, P. Lloyd, Y. Lo, A. Lobbes, G. Lobdell, J. Lochansky, F. Locke, R. Locke, A. Lockhart, L. Lockhart,
R. Lockhart, J. Lockyer, C. Loder, S. Loder, J. Lodoen, K. Loewen, S. Loewen, C. Lofstrom, D. Lofstrom, C. Logan, M. Logan, S. Logan, R. Logozar, S. Lojczyc, R. Loke, J. Lomada, K. Lomond, D. Londo, C. Long, D. Long, S. Long,
Y. Long, S. Longman, D. Longpre, S. Longson, C. Longston, K. Loo, D. Lord, N. Lord, J. Loree, C. Lorenson, L. Lorentz, N. Lorentz, J. Lorette, K. Lorette, M. Lorincz, B. Lorinczy, K. Lorteau, E. Lot, J. Lotito, M. Lotito, A. Loughran,
W. Loutit, S. Loutitt, C. Love, M. Love, D. Loveless, J. Loveless, W. Loveless, E. Lovell, I. Lovera-Figueroa, M. Lovestrom, E. Lovmo, N. Low, D. Lowe, J. Lowe, J. Lowen, V. Lowes, K. Loyer, L. Loyola, C. Lozinski-Kumpula, A.
8
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Lu, J. Lu, S. Lu, W. Lu, G. Lucas, I. Lucas, J. Lucas, L. Luciow, T. Lucksinger, B. Lucy, E. Ludwig, C. Luk, K. Luk, A. Lukacs, K. Lukan, J. Luke, L. Lukey, D. Lukic, C. Lumley, K. Lumley, H. Lund, W. Lundell, K. Lundrigan, E. Lunn,
R. Lunn, J. Lunt, C. Lunzmann, K. Luo, X. Luo, M. Lupul, J. Luscombe, D. Lush, J. Lush, R. Lusk, A. Lussier, K. Lussier, D. Lutwick, J. Lutyck, K. Lutz, A. Ly, G. Lyall, K. Lyall, T. Lychuk, G. Lye, D. Lynch, L. Lynch, R. Lynett, M.
Lyon, N. Lyons, R. Lyric, H. Ma, N. Maawia, M. MacBeth, K. MacBride, L. MacCallum, K. MacComish, M. MacConnell, P. MacCrimmon, A. MacDonald, C. MacDonald, D. MacDonald, F. MacDonald, J. MacDonald, L.
MacDonald, M. MacDonald, P. MacDonald, R. MacDonald, T. MacDonald, G. MacDonell, J. MacDougall, M. MacDougall, S. MacDougall, A. MacEachern, C. MacEachern, J. MacEachern, M. MacEachern, T. MacEachern,
C. MacFarlane, K. MacGillis, R. MacGregor, S. MacHale, C. MacInnes, A. MacInnis, B. MacInnis, D. MacInnis, S. MacInnis, L. MacIntosh, A. MacKay, B. MacKay, C. MacKay, G. MacKay, K. MacKay, S. MacKay, G. MacKenzie,
K. MacKenzie, M. MacKenzie, S. MacKenzie, B. MacKey, A. MacKinnon, B. MacKinnon, J. MacKinnon, K. MacKinnon, P. MacKinnon, R. MacKinnon, T. MacKinnon, Z. MacKinnon, R. MacKnight, B. MacLaren, T. MacLaren,
C. MacLean, E. MacLean, K. MacLean, M. MacLean, R. MacLean, T. MacLean, V. MacLean, G. MacLellan, J. MacLellan, H. MacLennan, J. MacLennan, A. MacLeod, I. MacLeod, J. MacLeod, L. MacLeod, M. MacLeod, T.
MacLeod, W. MacLeod, H. MacMillan, N. MacMillan, B. MacNeil, K. MacNeil, B. MacNeill, W. MacPherson, T. MacVicar, L. Macdaid, T. Macdougall-Sinclair, Y. Macedo, M. Macfarlane, A. Macgillivray, K. Machado
Rodriguez, D. Machuk, R. Maciborski, J. Maciejewski, T. Macijuk, T. Macintyre, A. Mack, B. Mack, C. Mack, L. Mack, S. Mack, L. Mackay, R. Mackelvie, D. Mackenzie, T. Mackenzie, P. Mackey, R. Mackey, T. Mackey, A.
Mackowski, B. Maclean, A. Maclellan, D. Maclellan, T. Maclellan, A. Macneil, C. Macneil, D. Macneil, J. Macneil, S. Macquarrie, B. Macwilliams, C. Madadi, J. Madathiparambil, A. Madhukar, R. Madigan, C. Madill, H.
Madlung, D. Madoche, G. Madore, T. Madro, G. Madsen, M. Maennchen, L. Maga, J. Magbanua, D. Magee, B. Mageza, S. Magill, P. Magnan, D. Magnusson, M. Magnusson, J. Magpali, A. Magro, V. Magsila, D. Magson,
D. Mah, L. Mah, M. Mah, R. Mah, L. Mahamud, K. Mahboobi, B. Mahe, T. Mailandt, M. Mailhot, D. Maillet, E. Maillet, J. Maillet, M. Mailloux, P. Mailloux, R. Mailman, J. Mainville, B. Maisey, D. Maisey, O. Maita, S.
Majdnia, J. Majeau, A. Majidi, P. Major, J. Makahnouk, M. Makhoul, D. Maki, D. Makin, M. Makin, G. Makumbe, A. Malabad, D. Malabad, E. Malabad, J. Malbon, B. Malcolm, S. Malcolm, H. Maldonado, M. Malech, P.
Malhame, A. Malimban, T. Malkova, J. Mallard, K. Mallard, S. Mallay, G. Mallette, T. Malley, G. Malo, M. Malo, T. Maloney, D. Malowski, A. Maltseva, M. Malyk, O. Malyshev, S. Mamedov, F. Manangu, D. Manarang, E.
Mancelita, M. Manderscheid, D. Mandley, L. Mandrusiak, G. Mandula, D. Manengyao, K. Mangaliman, J. Mangrove, M. Manhera, D. Manitopyes, E. Mankowski, D. Mann, R. Mann, V. Manning, J. Mansfield, D.
Manshanden, R. Mantei, V. Mantey, A. Manthorne, E. Mantilla, G. Manuel, J. Manuel, L. Manzano Weffer, H. Maralli, N. Maralli, M. Maratovic, D. Marazzo, G. Marceau, A. Marcel, S. Marchand, M. Marchi, R. Marcichiw,
N. Marcil, A. Marcinkoski, T. Marcotte, L. Marcucci, N. Marcy, W. Margison, H. Maric, V. Maries, E. Marilao, R. Marin, S. Marin, P. Marinzi, S. Marion, D. Mark, S. Markle, S. Markosyan, K. Markstrom, P. Marolt, U. Maroney,
B. Marple, T. Marquis, K. Marriner, R. Marrington, C. Marriott, B. Marsh, C. Marsh, M. Marsh, P. Marsh, R. Marsh, C. Marshall, S. Marshall, S. Marshman, J. Marston, A. Martakoush, P. Martell, S. Martens, T. Martens, B.
Martin, C. Martin, D. Martin, J. Martin, M. Martin, R. Martin, S. Martin, T. Martin, D. Martinat, S. Martinella, D. Martinez Gomez, Z. Martinez, O. Martis, D. Martyn, R. Martyn, M. Martynuik, A. Martyshuk, M. Martyshuk,
B. Martz, J. Maruniak, K. Mashayekh, R. Maskoni, B. Mason, C. Mason, J. Mason, K. Mason, W. Mason, D. Massey, K. Massick, A. Massicotte, P. Massicotte, B. Masters, A. Matatko, A. Matchem, J. Matecki, H. Mateen,
D. Mathers, D. Matheson, E. Matheson, K. Matheson, L. Matheson, A. Mathew, L. Mathew, K. Mathews, D. Mathieson, C. Mathiot, E. Mathiot, B. Matsalla, N. Matsushita, T. Matsushita, D. Matte, B. Matthews, C.
Matthews, D. Matthews, E. Matthews, N. Matthews, J. Matthiessen, J. Mattiussi, R. Matychuk, J. Mault, P. Maurice, S. Maurice, N. Mavani, D. Mavridis, D. Mavuwa, A. Mawer, C. Maxsom, K. Maxwell, R. Maxwell, A.
May, K. May, R. May, C. Maye, F. Mayell, J. Mayer, S. Mayer, R. Mayers, T. Mayhew, A. Maynard, W. Maynard, K. Mayner, A. Mayo, B. Mayo, C. Mays, A. Mazur, D. Mazur, C. Mazuryk, D. McAlister, D. McAllister, M.
McAlpine, D. McArthur, K. McArthur, D. McBrearty, K. McBride, R. McBrien, D. McCabe, G. McCabe, T. McCabe, J. McCaffrey, S. McCaffrey, R. McCallum, S. McCann, J. McCarthy, J. McCarty, D. McCarvill, K. McClary, D.
McClelland, I. McClelland, B. McClure, B. McConachie, J. McConnell, T. McCord, B. McCormack, M. McCormack, C. McCormick, S. McCracken, B. McCrady, K. McCrae, C. McCrea, W. McCrone, B. McCullough, C.
McCullough, R. McCullough, A. McDaniel, C. McDonald, J. McDonald, K. McDonald, S. McDonald, T. McDonald, L. McDonnell, M. McDougall, S. McDougall, J. McDowell, K. McEachern, R. McEachnie, M. McElroy, P.
McElwain, J. McEwen, W. McEwen, C. McFarlane, M. McFarlane, B. McFaul, M. McGannon, K. McGean, D. McGee, L. McGee, G. McGinnis, P. McGinnis, C. McGovern, G. McGowan, M. McGowan, A. McGrath, C. McGrath,
L. McGrath, M. McGrath, T. McGrath, P. McGregor, T. McGregor, L. McHugh, D. McInally, D. McIntosh, C. McIntyre, P. McIntyre, R. McIntyre, C. McIver, T. McKague, B. McKay, C. McKay, J. McKay, K. McKay, L. McKay, N.
McKay, R. McKay, S. McKay, T. McKay, N. McKeachnie, T. McKee, K. McKendry, N. McKendry, M. McKenna, P. McKenna, T. McKenna, B. McKenzie, K. McKenzie, R. McKenzie, C. McKersie, R. McKiel, C. McKim, S.
McKinney, J. McKinnon, S. McKinnon, N. McKnight, R. McLachlen, M. McLane, C. McLaren, D. McLaren, M. McLaren, H. McLarty, M. McLaughlin, R. McLaughlin, K. McLean, M. McLean, N. McLean, R. McLean, C.
McLellan, K. 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, R.
McMaster, S. McMichael, K. McMillan, S. McMillan, C. McNabb, R. McNabb, R. McNair, D. McNamara, R. McNaughton, M. McNay, D. McNeil, K. McNeil, M. McNeil, R. McNeil, S. McNeill, T. McNelly, R. McNinch, P.
McNulty, R. McPhail, L. McPhee, R. McPhee, J. McPherson, K. McPherson, C. McQuaker, E. McQueen, J. McQueen, L. McQuiston, K. McRae, R. McRae, R. McRoberts, B. McTavish, T. McTavish, C. McWhan, C. McWhinnie,
C. Mcallister, T. Mcbride, C. Mccoy, J. Mccready, G. Mccubbing, C. Mcdermott, C. Mcgee, G. Mcgonigal, D. Mcgrath, K. Mcgrath, M. Mcintosh, D. Mckay, K. Mckinnon, T. Mclaughlan, P. Mclaughlin, B. Mclean, P. Mcloughlin,
J. Mcskimming, M. Meade, D. Meador, B. Meadus, P. Meadus, M. Meadwell, S. Meagher, M. Meakes, M. Medhurst, I. Medina, N. Medina, B. Medway, M. Mehaney, F. Mehdiyev, P. Mehrabi, N. Mehta, R. Mehta, V. Mehta,
C. Mei, D. Meier, C. Mejia, J. Mejia, B. Melanson, D. Melanson, R. Melanson, T. Melanson, T. Melindy, H. Mellafont, L. Mello, G. Mellom, D. Melnyk, K. Melnyk, M. Melnyk, R. Melnyk, A. Melo, B. Melton, J. Melville, A.
Menard, D. Menard, L. Mendenhall, P. Mendes, N. Meneses, B. Mennie, M. Mer, G. Merali, C. Mercer, J. Mercer, R. Mercer, J. Mercier, W. Mercredi, C. Merkel, G. Merkel, D. Merkley, A. Merle, K. Merrill, M. Merrill, M.
Merriman, C. Merritt, N. Merritt, R. Merritt, I. Meseldzija, K. Mesenchuk, U. Meservy, M. Mesquita, G. Metcalfe, S. Metcalfe, T. Methuen, C. Metz, K. Metzler, S. Meunier, A. Mews, C. Mews, D. Mews, R. Mews, S. Meyer,
C. Meyers, I. Meynin, L. Michalishen, C. Michalko, G. Michaud, T. Michel, K. Michener, C. Michie, L. Michon, N. Mickelson, J. Miclat, A. Middleton, D. Midgley, K. Mielty, J. Mihai, J. Mihailoff, T. Mijic, C. Mikalishen, J.
Mikalsky, A. Mikhailov, S. Mikloukhine, J. Miko, G. Milan Garcia, J. Milce, R. Miles, N. Miles-Berenger, R. Millar, G. Millard, A. Miller, D. Miller, G. Miller, H. Miller, J. Miller, K. Miller, P. Miller, R. Miller, T. Miller, W. Miller,
H. Millership, D. Milley, K. Milley, D. Mills, G. Mills, J. Mills, M. Mills, R. Mills, S. Mills, T. Mills, T. Milne-McLean, D. Milward, A. Minett, F. Mingle, A. Minhas, M. Minick, W. Minni, W. Minnie, W. Minns, D. Mino, J.
Minor, A. Mir, S. Mir, W. Mirabal, A. Mirza, B. Mirza, W. Mirza, L. Mislan, J. Mistecki, D. Mistry, C. Mitchell, G. Mitchell, M. Mitchell, N. Mitchell, T. Mitchell, W. Mitchell, G. Mitchelmore, A. Mitroi, Y. Miville, D. Mocodean,
V. Modak, B. Moelbert, T. Moen, J. Moffat, R. Mogensen, P. Mohajer, A. Mohamed, B. Mohammed, A. Mohideen, J. Mohl, B. Moini, M. Moisson, N. Molder, S. Molendyk, N. Molina, J. Moll, R. Mollison, J. Molnar, R.
Monahan, R. Money, C. Montague, F. Montefresco-Gentile, R. Monteith, V. Montenegro, N. Montes, J. Montgomery, M. Montinola, S. Moojelsky, K. Moon, P. Moon, C. Mooney, J. Mooney, B. Moore, D. Moore, E. Moore,
J. Moores, T. Moores, S. Moosavi, L. Mora, N. Morel, A. Morelli, K. Morency, J. Morency-Letto, L. Moreno, J. Moretto, M. Morey, C. Morgan, T. Morgan, M. Moriarty, A. Morin, J. Morin, P. Morin, R. Morin, D. Mork, J.
Morley, R. Morley, S. Moron Labarca, K. Morphy, B. Morris, D. Morris, K. Morris, M. Morris, S. Morris, T. Morris, J. Morriseau, A. Morrison, C. Morrison, J. Morrison, R. Morrison, S. Morrison, T. Morrison, W. Morrison, W.
Morrow, S. Morse, A. Mortlock, D. Morton, K. Morton, L. Morton, D. Mose, D. Moser, K. Moser, J. Moshenko, S. Moshi, T. Moskol, P. Mossey, C. Mostowich, S. Mothersele, L. Motowylo, S. Motta Cabrera, B. Mottle, J.
Moul, S. Moul, I. Mountain, S. Mousazadeh, O. Moussa, R. Moussavi Nik, M. Mousseau, C. Mouta, D. Mouton, D. Mrakava, M. Mubarak, W. Mudryk, T. Mudzviti, T. Mueller, T. Muessle, A. Mugford, R. Mugford, A. Mughal,
M. Mughal, W. Muir, D. Muise, L. Muise, M. Muise, G. Mullen, C. Mullin, R. Mullin, N. Mulvena, S. Mundt, F. Munn, K. Munn, A. Munro, I. Munro, J. Munro, L. Munro, R. Munro, R. Muralidharan, C. Murdoch, J. Murdoch,
S. Murison, G. Murley, L. Murley, A. Murphy, B. Murphy, C. Murphy, D. Murphy, J. Murphy, K. Murphy, M. Murphy, P. Murphy, R. Murphy, T. Murphy, B. Murray, C. Murray, G. Murray, L. Murray, S. Murray, E. Murrin, S. Murrin,
M. Musaid, A. Musil, S. Musil, I. Musiwarwo, W. Muss, T. Musselman, A. Muthuswamy, R. Mutschler, I. Muwhen, P. Muza, J. Mweshi, D. Myers, E. Myers, S. Myers, J. Myette, L. Myhre, D. Myshak, M. Myszczyszyn, N.
N'Doye, G. Nabi, B. Nadeau, S. Nadeau, M. Naderikia, S. Nagare, A. Nagra, J. Nagy, J. Nagy-Kolodychuk, J. Naidu, J. Nair, N. Nair, R. Nair, S. Nair, S. Najeeb, L. Najoan, B. Nalder, N. Namoca, E. Namur, I. Nandez Hernandez,
J. Napier, R. Napier, C. Naqvi, S. Naqvi, K. Narayanan, P. Narayanasarma, A. Narcise, S. Naser, B. Nash, D. Nash, J. Nash, S. Nash, D. Nater, M. Nathwani-Crowe, D. Naugler, P. Nava, L. Navarrette, P. Navarro, D. Navas,
R. Navas, V. Navratil, M. Nawab, D. Nayler, T. Nazari, C. Nazarko, D. Neal, M. Neate, A. Neddjar, R. Needham, D. Neergaard, J. Neff, S. Negi, Y. Neguse, D. Neigum, A. Neilson, S. Neilson, D. Nein, D. Neitz, K. Nelligan,
A. Nelson, B. Nelson, C. Nelson, D. Nelson, J. Nelson, K. Nelson, M. Nelson, V. Nelson, A. Nemirsky, M. Nergaard, C. Nerurkar, B. Nessman, K. Netter, K. Nettesheim, G. Netzel, C. Neufeld, O. Neufeld, D. Neumann, D.
Nevil, W. Nevills, D. Newbury, G. Newbury, J. Newell, R. Newitt, J. Newman, L. Newman, M. Newman, P. Newman, R. Newman, A. Newton, K. Newton, R. Newton, C. Ng, D. Ng, H. Ng, K. Ng, V. Nganzo, H. Ngo, T. Ngo,
N. Ngo-Schneider, M. Nguyen, T. Nguyen, H. Ni, R. Nibogie, F. Nichol, J. Nicholl, J. Nichols, A. Nicholson, J. Nicholson, S. Nicholson, A. Nickel, D. Nickel, D. Nickerson, K. Nickerson, J. Nicolajsen, J. Nicoll, J. Nie, T. Nielsen,
O. Nieto, P. Nihon, W. Nikiforuk, E. Nikitina, R. Nilsson, R. Nimco, M. Nippard, D. Nissen, J. Nistico, R. Nitsch, O. Niven, M. Nixdorf, K. Nixon, P. Niziolek, M. Nobles, B. Noel, C. Noel, D. Noel, A. Noftall, Z. Noftall, C. Noga,
J. Noga, G. Nogue, B. Nolan, P. Nolan, R. Nolan, S. Nolan, B. Nolin, G. Nolin, B. Nordell, W. Nordin, J. Norgaard, K. Noriega, A. Noriel, V. Norkin, B. Norman, D. Norman, J. Norman, M. Norman, P. Norman, R. Norman, T.
Norman, T. Normand, Y. Normand, C. Normandin, D. Normore, E. Normore, G. Normore, M. Normore, S. Normore, B. Norquay, N. Northcott, K. Norton, B. Noseworthy, A. Noskey, K. Notenbomer, F. Nothnagel, R. Novales,
R. Nunweiler, L. Nurkowski, D. Nwagbogwu, R. Nycholat, E. Nyenhuis, A. Nylen, C. Nyman, J. O'Beid, A. O'Brien, B. O'Brien, D. O'Brien, H. O'Brien, K. O'Brien, P. O'Brien, J. O'Connell, G. O'Connor, P. O'Donnell, L. O'Gallagher,
J. O'Grady, K. O'Hearn, C. O'Keefe, E. O'Keefe, S. O'Leary, B. O'Neil, D. O'Neil, T. O'Neill, C. O'Quinn, D. O'Quinn, R. O'Regan, M. O'Reilly, J. O'Rourke, J. O'Sullivan, J. O'Toole, W. Oak, A. Oake, N. Oake, R. Oakes, D. Oakley,
D. Oaks, D. Ober, J. Oberg, J. Oberholtzer, N. Obi, F. Obiri, P. Oblozinsky, J. Obrigewitsch, J. Obuck, P. Ocana, M. Ochran, L. Odeleye, T. Oele, J. Oestreicher, I. Offor, E. Ofuya, J. Oganwu, O. Ogbodo, A. Ogilvie, R. Ogilvie, T.
Oh, T. Oickle, R. Okada, L. Okemow, A. Okeynan, R. Oksanen, K. Okuszko, F. Oladebo, P. Olaniyan, S. Olar, A. Olaski, B. Olaski, C. Oldfield, M. Oldford, B. Olenik, D. Olesen, B. Olheiser, T. Olinek, D. Oliveira, D. Oliver, N. Oliver,
A. Oliverio, C. Olivier, S. Ollerhead, J. Ollikka, V. Olofernes, G. Oloumi, A. Olsen, K. Olsen, R. Olsen, S. Olsen, C. Olson, D. Olson, J. Olson, L. Olson, S. Olson, T. Olson, V. Olson, W. Olson, O. Oluwole, M. Omosun, P. Onciul,
D. Ong, K. Onuoha, P. Onyszko, D. Orlecki, L. Orpilla Jr, A. Orr, N. Orr, S. Orser, M. Ortega, P. Ortega, K. Orth, R. Osachoff, J. Osborne, K. Osmond, T. Osmond, H. Osorio Lobo, A. Ospino, K. Osuoji, D. Oswald, J. Otis, G. Ott,
M. Otteson, W. Otteson, D. Otto, J. Otto, T. Ouart, L. Ouch, D. Ouellette, J. Ouellette, S. Ouellette, E. Overbye, Z. Overbye, M. Overwater, E. Oviedo, P. Oza, A. Paananen, L. Paananen, J. Paarsmarkt, M. Pachan, F. Pacheco,
M. Pacheco, T. Packard, J. Paddington, D. Padilla, R. Padilla, M. Pady, S. Page, M. Pagnucco, Q. Pagnucco, G. Pahl, B. Pahtayken, S. Paiement, K. Paige, R. Paine, K. Painter, J. Pak, V. Pak, A. Palani, A. Palatheerdhapu, C.
Paleck, B. Pallan, B. Palmer, D. Palmer, L. Palmer, R. Palmer, M. Palmquist, O. Palomino, G. Palsen, J. Palsis, G. Paluck, P. Palumbo, I. Panas, J. Panas, B. Panchal, V. Pandey, D. Pandher, J. Pandya, S. Pandya, C. Panokarren,
L. Pantazi, F. Pantilag, S. Panuganty, Y. Panya, L. Paolucci, A. Papadoulis, R. Papalia, M. Papcun, W. Papineau, J. Papp, V. Papuga, P. Paquette, R. Paquette, L. Paquin, D. Paradis, E. Paradis, J. Paradis, M. Paradis, T. Paradis,
M. Paranjape, B. Parathundathil, G. Parchewsky, M. Pardy, E. Parece, L. Paredes, B. Parent, B. Parenteau, C. Parenteau, J. Parenteau, P. Parhar, R. Parillo, B. Parker, D. Parker, B. Parkin, D. Parlee, C. Paron, J. Parr, B. Parsons,
C. Parsons, D. Parsons, G. Parsons, L. Parsons, M. Parsons, S. Parsons, T. Parsons, W. Parsons, A. Partsch, C. Pascon, J. Paseska, K. Pashaei Fakhri, J. Pashko, M. Pasichnuk, W. Pasko, J. Pasos, N. Pasowisty, C. Pass, E.
Pastor, A. Patel, B. Patel, D. Patel, H. Patel, J. Patel, K. Patel, M. Patel, N. Patel, P. Patel, R. Patel, S. Patel, T. Patel, V. Patel, N. Pateliya, R. Patenaude, C. Pater, D. Paterson, J. Paterson, B. Patey, D. Patey, I. Patey, M. Patey,
T. Patey, K. Patmore, C. Paton, G. Paton, P. Patrick, W. Patrick, C. Patrie, E. Patten, B. Patterson, C. Patterson, K. Patterson, L. Patterson, W. Patterson, L. Pattison, A. Paul, C. Paul, G. Paul, J. Paul, K. Paul, T. Paul, M. Paulgaard,
E. Paulin, W. Pauls-Atas, B. Paulson, B. Paulssen, B. Pauwels, D. Pavelick, M. Pavlic, M. Pawluk, C. Pay, B. Payne, C. Payne, D. Payne, G. Payne, J. Payne, M. Payne, N. Payne, S. Payson, P. Pazienza, E. Peace, B. Peacock, E.
Peacock, L. Peacock, A. Pearson, D. Pearson, E. Pearson, T. Peats, T. Peciulis, D. Pecoskie, E. Peddle, D. Pedersen, J. Pedersen, K. Pedersen, P. Pedersen, S. Pedersen, B. Pederson, L. Pederson, J. Peeke, D. Peet, K. Peeters,
C. Peifer, F. Pelayo, K. Pelayo, M. Pelkey, G. Pellegrino, D. Pelletier, E. Pelletier, M. Pelletier, T. Pelletier, I. Pelly, M. Pelypiw, D. Pemberton, L. Pena, C. Pennell, T. Pennell, S. Pennemann, D. Penner, R. Penner, S. Penner, T.
Penner, D. Penney, E. Penney, H. Penney, J. Penney, M. Penney, P. Penney, S. Penny, J. Penton, J. Penzo, I. Pepper, K. Pepper, K. Peppler, D. Peramanu, S. Peramanu, R. Peraza, R. Perchaylo, M. Perdue, C. Peregrym, M.
Perehudoff, S. Perehudoff, J. Perepelecta, F. Perez, L. Perez, J. Perez-Licera, M. Perkins, R. Perkins, S. Perkins, T. Perkins, K. Perkovich, J. Pernitsch, J. Peroramas, H. Perozak, G. Perpar, D. Perreault, M. Perreault, N. Perron,
B. Perry, C. Perry, D. Perry, G. Perry, J. Perry, O. Perry, R. Perry, V. Perry, T. Persaud, B. Persson, D. Perumal, B. Pesowski, P. Peter, D. Peters, J. Peters, K. Peters, R. Peters, C. Petersen, E. Petersen, B. Peterson, E. Peterson, J.
9
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Peterson, M. Peterson, S. Peterson, T. Peterson, B. Petite, C. Petkau, D. Petkau, B. Petkus, N. Petrola, R. Petrone, D. Petryshen, K. Petterson, B. Pettipas, J. Pettit, S. Pettit, K. Peyman, J. Peyton, L. Pham, T. Pham, B. Philibert,
G. Philip, B. Phillips, D. Phillips, J. Phillips, T. Phillips, B. Philpott, T. Philpott, G. Phinney, L. Picard, W. Picard, E. Picard-Goulet, K. Picco, J. Picken, A. Pickersgill, B. Pickett, B. Piderman, D. Pierce, S. Piercey, J. Pieroway, S.
Pierzchala, A. Pietrusik, R. Pighin, J. Pihowich, J. Pike, L. Pike, S. Pike, P. Pilecki, B. Pilgrim, L. Pilgrim, S. Pilgrim, T. Pilgrim, M. Pili, D. Pilisko, J. Piliszanski, R. Pillai, L. Pillaveethil, K. Pillon, N. Pilote, J. Pilsner, G. Pimienta,
L. Pineda Perez, G. Pineda, M. Pineda, E. Pinituj-Flores, A. Pinksen, T. Pinksen, W. Pinksen, J. Pintaric, B. Pipa, J. Pipke, C. Pirnak, D. Pirvan, K. Pisio, M. Pitman, J. Pitoulis, M. Pitre, A. Pittman, C. Pittman, D. Pittman, E.
Pittman, I. Pittman, J. Pittman, M. Pittman, R. Pittman, S. Pittman, W. Pittman, S. Pituka, A. Plaiasu, M. Plamondon, R. Plamondon, J. Plata, D. Plepelic, I. Plesa, J. Plessis, J. Plitt, K. Plosz, N. Plouffe, T. Plouffe, K. Plummer,
I. Pocaterra, J. Pocock, S. Podhorodeski, A. Poetker, H. Poffenroth, D. Pohl, A. Poirier, D. Poirier, K. Poirier, D. Poitras, J. Polacik, D. Pole, E. Poliquin, C. Pollard, R. Pollard, T. Pollard, A. Pollock, J. Pollock, L. Pollock, M. Pollock,
R. Pollock, J. Polsfut, M. Polujan, S. Poluk, G. Pome Franco, M. Poncelet, D. Poncsak, B. Pond, D. Pond, G. Pond, B. Ponjevic, N. Ponkiya, H. Ponnurangan, T. Poole, K. Poon, S. Poor Ghorban, A. Popa, T. Pope, C. Popko, J.
Popowich, M. Popowich, C. Portelance, J. Portelli, A. Porter, C. Porter, I. Porter, L. Porter, M. Posnikoff, P. Postlewaite, R. Postnikoff, N. Pothier, C. Potorti, M. Potorti, L. Potosky, J. Potter, T. Potter, S. Pottle, K. Potts, R. Potts,
J. Poulin, R. Poulter, K. Pounall, C. Povse, D. Powell, R. Powell, T. Powell, A. Power, B. Power, C. Power, E. Power, H. Power, J. Power, K. Power, L. Power, P. Power, T. Power, D. Pozniak, M. Prajapati, D. Prasad, P. Prasad, G.
Pratch, G. Prather, R. Pratt, S. Pratt, L. Praud, W. Prawdzik, D. Prediger, M. Preece, D. Preshyon, J. Preshyon, D. Presley, A. Preston, J. Preston, S. Preston, R. Preteau, A. Pretty, A. Price, C. Price, M. Price, W. Price, J. Priest,
D. Pringle, T. Prins, M. Pritchard, S. Pritchett, K. Proceviat, G. Prochner, K. Proctor, R. Proctor, D. Procyshyn, M. Profiri, M. Pronk, J. Properzi, D. Prostebby, D. Prostler, I. Proudfoot, D. Proulx, S. Prouse, S. Prud'Homme, T.
Prudhomme, C. Prybylski, R. Pryde, A. Prysiaznyj, C. Przybylski, M. Psenicka, S. Pshyk, S. Puerto, Y. Puerto, B. Pugh, J. Puhl, M. Pulgar, A. Pulikkottil, C. Pumphrey, M. Pumphrey, A. Punko, K. Pupneja, S. Pupneja, B. Purcell,
S. Purchase, C. Purdy, T. Purves, D. Pushak, S. Pushak, D. Pye, M. Pye, R. Pyke, M. Pyne, W. Pyne, T. Pyo, J. Pyper, M. Qian, W. Qian, L. Qing, J. Qu, A. Quan, G. Quan, L. Quan, A. Quarin, R. Quartermain, K. Quaschnick, J.
Quiba, D. Quigley, R. Quigley, S. Quigley, J. Quinn, K. Quintilio, C. Quinton, G. Quinton, B. Quipp, R. Quiring, S. Qureshi, J. Raban Mardelli, L. Rabbitt, J. Rabby, B. Rabusic, M. Raby, P. Racette, D. Rach, D. Rachkewich, D.
Raciborski, W. Raczynski, L. Radesh, K. Radke, N. Radke, R. Radke, M. Radu, J. Rae, D. Raedts, K. Rafferty, I. Rafiyev, G. Raghavan Nair, J. Raher, A. Rahmani, M. Rahmani, M. Rahmanian, P. Rai, J. Rainnie, M. Raisinghani,
A. Raivio, K. Raj, J. Rajotte, J. Ralph, P. Ralph, S. Ralph, S. Raman, J. Ramazani, D. Ramburrun, E. Ramirez Capitaine, J. Ramirez, M. Ramirez, P. Ramirez, R. Ramirez, C. Ramos, J. Ramroop, J. Ramsay, M. Ramsay, R. Ramsay,
S. Ramsay, K. Ramsbottom, M. Rana, L. Rancourt, D. Randell, L. Randell, M. Randell, T. Randell, W. Randell, J. Randhile, J. Rankin, M. Rankin, D. Ranola, J. Ransom, M. Raoufi, R. Raposo, S. Rasch, T. Rasheed, C. Rasko,
S. Rasmussen, R. Raso, W. Ratcliffe, S. Rathamone, R. Rathburn, S. Ratkovic, H. Ratzlaff, A. Rau, M. Rausch, L. Ravoy, A. Ray, B. Ray, D. Ray, K. Ray, S. Ray, K. Rayment, D. Raymond, E. Rayner, J. Rayner, R. Rayner, M. Raza,
D. Read, G. Reader, W. Reashore, K. Reason, B. Reaume, R. Reaume, C. Reber, D. Reber, D. Rechenmacher, G. Redding, S. Reddy, B. Redlich, R. Redmond, A. Reed, D. Reed, J. Reed, S. Reed, A. Regan, P. Regan, H. Regimbald,
R. Reginato, C. Regnier, R. Regnier, P. Regular, K. Rehel, H. Rehman, M. Rehman, C. Reib, K. Reichle, B. Reid, C. Reid, D. Reid, E. Reid, G. Reid, J. Reid, K. Reid, M. Reid, R. Reid, S. Reid, T. Reid, H. Reilly, T. Reilly, D. Reimer,
I. Reimer, M. Reimer, M. Reinders, D. Reinhold, J. Reiniger, T. Reiniger, E. Reis, R. Reis, C. Reiter, G. Reiter, H. Reithaug, M. Reithaug, D. Rejman, B. Relland, B. Rellosa, P. Rellosa, T. Remington, W. Remmer, C. Rempel, L.
Rempel, P. Rempel, L. Ren, S. Ren, R. Renaud, T. Renkema, L. Rennie, M. Reno, J. Rentar, J. Repchuk, S. Resus, M. Rew, E. Reyes, O. Reyes, S. Reynhardt, J. Reynolds, P. Reynolds, S. Reynolds, T. Reynolds, M. Rezkallah, D.
Reznik, N. Rhemtulla, C. Rhode, A. Rhodes, G. Ricard, S. Ricci, D. Rice, G. Rice, J. Rice, R. Rice, C. Richard, J. Richard, K. Richard, M. Richard, B. Richards, C. Richards, D. Richards, G. Richards, H. Richards, K. Richards, T.
Richards, A. Richardson, K. Richardson, S. Richardson, T. Richardson, D. Richter, W. Ricker, C. Ricketson, M. Ricketts, M. Ricks, C. Rico-Ospina, R. Riddell, J. Riddle, J. Rideout, M. Rideout, R. Rideout, C. Riegling, C. Ries,
A. Riley, D. Riley, S. Riley, D. Rimmer, D. Rinas, G. Ringheim, K. Rioux, M. Rioux, R. Rioux, S. Rioux, S. Risling, S. Ristic, L. Ritchat, D. Ritchie, M. Ritchie, R. Ritchie, S. Rivard, M. Rivas, J. Rivera, O. Rizvi, M. Rizwan, A. Roach,
N. Robbins, R. Roberge, A. Robert, C. Roberts, D. Roberts, J. Roberts, M. Roberts, T. Roberts, G. Robertson, M. Robertson, T. Robertson, J. Robichaud, M. Robideau, H. Robillard, A. Robinson, B. Robinson, D. Robinson, G.
Robinson, J. Robinson, K. Robinson, M. Robinson, N. Robinson, W. Robleto, A. Roche, L. Roche, G. Rocheleau, J. Rochemont, D. Rochon, L. Rochon, R. Rock, J. Rockarts, N. Roculan, S. Rodberg, T. Rodgers, R. Rodh, J.
Rodriguez, O. Rodriguez, P. Roett, D. Rogal, K. Rogalsky, A. Rogers, C. Rogers, G. Rogers, J. Rogers, K. Rogers, M. Rogers, S. Rogers, Y. Rohner, L. Rojas, K. Roll, S. Rolling, K. Rolseth, L. Romanchuk, T. Romanchuk, C. Romano,
D. Romanyshyn, M. Rombough, W. Rombough, A. Romero, G. Romero, J. Romero, A. Ronald, G. Ronald, D. Rondeau, J. Roney, S. Roney, L. Rong, B. Ronspies, A. Rook, A. Roomy, J. Rooney, M. Rooney, S. Roop, C. Root, A.
Roozendaal, B. Rose, C. Rose, J. Rose, M. Rose, P. Rose, R. Rose, M. Rose-Atkins, C. Rosenthal, R. Rosenthal, D. Rosgen, S. Roskey, M. Rosloot, T. Rosner, A. Ross, B. Ross, D. Ross, E. Ross, I. Ross, J. Ross, R. Ross, S. Ross,
W. Ross, G. Rosser, S. Rosser, G. Rosso, J. Rostad, B. Rosychuk, R. Rosychuk, B. Roszell, K. Roth, M. Roth, R. Roth, T. Roth, B. Rott, T. Rotzien, J. Rotzoll, S. Rouf, J. Rouleau, G. Rousselle, A. Routhier, D. Routhier, R. Routhier,
R. Routley, K. Row, A. Rowbottom, J. Rowe, M. Rowe, R. Rowe, S. Rowein, C. Rowland, L. Rowland, A. Rowsell, C. Rowsell, K. Rowsell, R. Rowsell, F. Roxas, A. Roy, B. Roy, C. Roy, D. Roy, M. Roy, R. Roy, S. Roy, D. Royston,
Z. Ruda, V. Ruddy, D. Rudkevitch, K. Rudolf, B. Rudolph, C. Rudolph, K. Rudra, J. Rueb, K. Ruecker, L. Ruesga, M. Ruetz, A. Ruff, I. Rugg, M. Ruggles, M. Ruiz, S. Rumball, D. Rumbolt, T. Rumbolt, J. Rumjan, D. Rumohr, C.
Runnalls, J. Rusk, C. Russell, D. Russell, E. Russell, P. Russell, Q. Russell, T. Russell, D. Rutberg, J. Rutherford, K. Rutherford, M. Rutherford, S. Rutherford, D. Rutley, M. Rutter, H. Rutz, C. Ruzycki, F. Rwirangira, J. Ryalls, A.
Ryan, C. Ryan, D. Ryan, M. Ryan, T. Ryan, S. Ryback, R. Rybchinsky, C. Ryder, D. Ryder, J. Ryder, J. Ryll, A. Ryzebol, J. Saaedi, J. Saastad, R. Saastad, R. Sabas, M. Sabo, A. Sabourov, A. Saby, J. Sachs, J. Sacrey, N. Sacrey,
V. Sacrey, H. Sadiq, E. Saenz de Santa Maria, S. Sagrafena, A. Saha, K. Sahni, 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, E. Salazar, A. Saleh, 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, J. Salvador, R. Salyn, A. Samadi, A.
Samarathunge, N. Samer, S. Samida, M. Samimi, K. Samms, A. Samoisette, J. Sampang, S. Sampanthamoorthy, H. Sampson, J. Sampson, R. Sampson, T. Sampson, R. Samson, T. Samuelson, S. Samy, V. Sanchala, R.
Sanchez Hernandez, P. Sanders, T. Sanders, D. Sanderson, S. Sanderson, S. Sandhar, N. Sandhawalia, G. Sando, T. Sanelli, G. Sanford, N. Sanftleben, E. Sangroniz, N. Sankaran, T. Santos, J. Sanyal, R. Sarabin, J. Sarai, A.
Saran, S. Saran, Z. Saran, R. Sarauskas, M. Sarbah, D. Saretsky, D. Sargent, I. Sarjeant, S. Sarkar, D. Sarmiento, A. Sartori, M. Sartoris, M. Sas, S. Sashuk, B. Sather, T. Sather, W. Sather, T. Satink, M. Satra, E. Saucier, J.
Saucier, S. Sauder, E. Saulnier, G. Saunders, L. Saunders, M. Saunders, R. Saunders, S. Saurette, C. Sauve, J. Savage, C. Savard, F. Savaria, S. Savas, B. Savla, D. Savoie, K. Savoie, L. Savoie, M. Savoie, C. Savostianik, A.
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M. Schanzenbach, T. Schatkoske, R. Schatschneider, C. Schaub, P. Schaub, J. Schechtel, J. Schedlosky, K. Schedlosky, W. Scheelar, T. Scheers, C. Scheerschmidt, K. Scheiris, S. Schell, M. Schellenberg, S. Schellenberg, L.
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R. Schmidt, T. Schmidt, J. Schmitz, S. Schmitz, P. Schmuland, H. Schnaier, D. Schneider, G. Schneider, P. Schneider, S. Schneider, B. Schnell, C. Schnepf, A. Schnick, J. Schnieder, R. Schnieder, C. Schnurer, K. Schnurer, J.
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C. Schultz, D. Schultz, J. Schultz, S. Schultz, M. Schultze, T. Schulz, K. Schumacher, D. Schwank, R. Schwank, D. Schwarz, C. Schwenning, L. Schwetz, J. Schwindt, T. Scimia, J. Scollard, C. Scott, D. Scott, E. Scott, G. Scott,
J. Scott, K. Scott, L. Scott, M. Scott, R. Scott, S. Scott, R. Scoville, M. Scragg, A. Scriba, R. Scrimshaw, J. Sculland, C. Scullion, S. Seabrook, M. Seafoot, G. Seal, K. Seaman, C. Sears, G. Seaton, T. Seaward, M. Sebastian,
J. Sedens, D. Seel, C. Seely, B. Seewitz, M. Seguin, 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, J. Senior, J. Seniuk, B. Senkow, T. Senkow, T. Senner, F. Sepnio, N. Serani, D. Serate, C. Sereda, D. Sereda, R. Sereda, N. Sereggela, B. Serfas, R. Serfas, P. Sergeant, J. Serino, E. Serniak, P. Servello,
B. Severight, B. Sevinski, J. Seward, B. Sewell, P. Sexton, S. Seyed Tarrah, A. Seyyed Najafi, G. Sgambaro, M. Sgambaro, R. Sgambaro, C. Shackleton, M. Shad, B. Shah, H. Shah, M. Shah, N. Shah, R. Shah, S. Shah, V.
Shah, M. Shahebrahimi, S. Shahzad, K. Shakir, K. Shakotko, L. Shang, C. Shank, P. Shankowski, B. Shanmugam, J. Shannon, A. Sharifi, K. Sharma, R. Sharma, M. Sharman, N. Sharp, J. Sharpe, K. Sharpe, T. Sharpe, R.
Sharron, T. Shatosky, B. Shaw, D. Shaw, K. Shaw, M. Shaw, R. Shaw, O. Shaykina, J. Shea, K. Shea, L. Shea, R. Shea, C. Shears, P. Shears, D. Sheaves, L. Sheaves, W. Sheaves, A. Shehata, K. Sheikh, M. Sheikh, O. Sheikh,
B. Shenton, R. Shepel, C. Sheppard, D. Sheppard, G. Sheppard, J. Sheppard, R. Sheppard, T. Sheppard, C. Sherbanuk, A. Shergill, T. Sheridan, M. Sherman, S. Sherman, I. Sherr, M. Sheth, N. Sheth, C. Sheward, B. Shewchuk,
D. Shewchuk, J. Shewchuk, L. Shi, A. Shideler, C. Shields, A. Shiers, N. Shihinski, S. Shiledarbaxi, K. Shill, A. Shillam, J. Shiner, P. Shiner, W. Shipley, J. Shire, V. Shirhatti, B. Shmoury, B. Shmyr, C. Shmyrko, M. Shobeiri, N.
Shohel, R. Shonhiwa, S. Short, T. Short, D. Shortland, D. Shortreed, J. Shortt, M. Shott, G. Shrafnagle, M. Shukalov, T. Shukin, K. Shukla, D. Shular, J. Shumate, T. Shymko, S. Shymoniak, D. Shypitka, J. Shysh, I. Siddhanta,
A. Siddiqui, M. Siddiqui, M. Sideroff, R. Sidhu, C. Sieben, D. Sieben, J. Sieben, P. Siganporia, R. Sigsworth, W. Sikorski, L. Silas, T. Silbernagel, A. Sillito, I. Silva, L. Silva, J. Silver, G. Silvis, H. Simani, C. Simard, D. Simard,
K. Simard, D. Simbi, M. Simm, G. Simmelink, T. Simmonds, J. Simmons, A. Simms, B. Simms, C. Simms, F. Simms, R. Simms, A. Simon, P. Simon, T. Simon, R. Simper, G. Simpkins, G. Simpson, J. Simpson, R. Simpson, S.
Simpson, W. Simpson, E. Sinclair, S. Sinclair, D. Sine, A. Singh, K. Singh, S. Singh, M. Singher, S. Singla, J. Singleton, M. Sinkova-Hovdestad, A. Sinnett, L. Sinnicks, R. Sison, S. Sison, J. Sisson, J. Sjonnesen, D. Skanderup,
W. Skaret, K. Skarra, E. Skarsen, B. Skinner, M. Skinner, R. Skinner, T. Skinner, M. Skipper, J. Skjeie, G. Skoczek, J. Skog, M. Skolski, J. Skonnord, R. Skrepnek, S. Skulmoski, M. Skulski, M. Skyrpan, A. Slade, R. Slade, S.
Slade, M. Slavin, K. Slemko, D. Slemp, J. Sloan, M. Sloan, R. Sloan, R. Slobodian, J. Sloychuk, W. Slunt, S. Slywka, E. Smart, R. Smart, D. Smeltzer, J. Smid, S. Smiegielski, K. Smigelski, C. Smillie, A. Smith, B. Smith, C.
Smith, D. Smith, E. Smith, G. Smith, J. Smith, K. Smith, L. Smith, M. Smith, R. Smith, S. Smith, T. Smith, W. Smith, C. Smitham, E. Smolyaninova, A. Smyl, K. Smyl, R. Smyl, N. Sneddon, K. Snee, T. Snell, G. Snider, J. Snider,
I. Snook, J. Snow, K. Snow, R. Snow, W. Snow, D. Snowdon, J. Snowdon, D. Snyder, J. Soar, D. Sohlbach, D. Sokoloski, J. Solano, J. Soley, V. Sollid, M. Sollows, S. Soloshy, A. Soloway, B. Soltani, L. Somerville, R. Somji,
L. Sommer, R. Somorai, D. Soni, A. Sonpal, N. Soodyall, W. Sookram, M. Soolagallu, T. Sopatyk, G. Sopczak, H. Sorensen, P. Sorensen, R. Sorensen, L. Soriano, C. Sorochan, K. Sorochan, D. Soroko, L. Soucy, M. Soucy, R.
Soucy, J. Soulis, J. Southern, H. Sow, D. Spagrud, E. Spagrud, D. Spanics, B. Speedtsberg, G. Speer, L. Speer, D. Spencer, R. Spencer, S. Spencer, B. Spendiff, R. Sperling, J. Spetz, D. Spidell, K. Spiker, A. Spohn, C. Sporidis,
M. Spreacker, M. Sprinkle, K. Sproule, A. Spurrell, C. Spurrell, D. Spurrell, E. Spurrell, N. Spurrell, R. Spurrell, P. Spurvey, N. Squarek, J. Squire, M. Squires, P. Squires, T. Squires, R. Sran, S. St. Croix, J. St. Denis, K. St. Denis,
P. St. Denis, F. St. Goddard, R. St. Jean, R. St. Martin, J. St. Onge, E. St. Pierre, M. St. Pierre, R. St. Pierre, L. Staats, A. Stacey, C. Stacey, K. Stacey, I. Stacey-Salmon, P. Stackhouse, G. Stadnichuk, S. Stadnichuk, S. Stadnyk,
D. Stagg, J. Stagg, K. Stagg, T. Stagg, M. Stainthorpe, K. Stairs, J. Stajkowski, M. Stalker, R. Stamp, J. Standeven, A. Standing, S. Stanford, C. Stang, M. Stang, R. Stanger, A. Stanley, J. Stanley, A. Staples, D. Staples, J.
Staples, P. Stapleton, L. Stark, R. Staruiala, D. Staszewski, B. Staudinger, S. Stauth, A. Stavropoulos, K. Stawinski, E. Stearns, M. Stec, D. Steele, R. Steele, S. Steele, B. Steeves, L. Steeves, S. Stefan, T. Stefansson, M.
Stein, J. Steinkey, S. Steinkey, A. Stella, R. Stelten, D. Stemmann, W. Stenhouse, J. Stephens, M. Stephens, T. Stephens, G. Stetar, G. Stevens, J. Stevens, N. Stevens, R. Stevens, A. Stevens-Dicks, A. Stevenson, H.
Stevenson, J. Stevenson, N. Stevenson, R. Stevenson, T. Stevers, R. Steward, C. Stewart, D. Stewart, I. Stewart, J. Stewart, L. Stewart, M. Stewart, R. Stewart, W. Stewart, W. Stickel, R. Stieben, M. Stiefel, D. Stinn, S.
Stirling, M. Stirrett, M. Stobart, D. Stobbe, J. Stober, M. Stockes, C. Stocking, R. Stokes, C. Stolz, T. Stolz, D. Stone, R. Stoner, M. Stordahl, J. Storey, D. Stormo, L. Storsley, B. Stortz, D. Stout, R. Stoutenberg, D. Stoyles, K.
Stoyles, J. Strachan, S. Strachan, A. Stranaghan, R. Stranberg, W. Strand, J. Strandquist, C. Strang, D. Strang, R. Strang, N. Strantz, B. Stratichuk, M. Street, S. Street, C. Stretch, R. Stretch, W. Stretch, H. Strickland, R.
Strickland, T. Strickland, R. Striegler, J. Strilchuk, M. Stroh, J. Strom, J. Strong, R. Strong, M. Stronski, G. Stroud, R. Struski, D. Strynadka, D. Stuart, C. Stubbs, G. Stuber, V. Stuckey, L. Stuckless, N. Stuckless, R. Stuckless,
T. Stuckless, C. Study, J. Stuebing, G. Sturdy, F. Sturge, J. Sturge, P. Sturge, J. Sturgeon, P. Sturgeon, L. Su, P. Su, W. Su, G. Suarez Caicedo, M. Suarez, V. Subasic, J. Subramaniam, R. Subramaniam, S. Suche, R. Sukkel, J.
Sullivan, M. Sullivan, N. Sullivan, R. Sullivan, T. Sullivan, P. Sultanian, B. Summerfelt, C. Summers, E. Summers, T. Sun, U. Sundar, U. Sundaram, P. Sundaravadivelu, C. Surgenor, G. Surugiu, C. Sutherland, D. Sutherland, H.
Sutherland, K. Sutherland, L. Sutherland, S. Sutherland, B. Sutton, P. Sutton, S. Sverdahl, T. Svoboda, J. Swaby, A. Swain, D. Swain, S. Swain, J. Swampy, A. Swan, D. Swan, M. Swan, J. Swannack, C. Swanson, J. Swanson,
W. Swanson, R. Swarnkar, E. Sweeney, S. Sweetapple, C. Swenarchuk, N. Swennumson, D. Swiegocki, E. Switzer, A. Sychak, K. Sydorko, D. Syed, J. Sykes, J. Sykora, J. Sylvester, T. Sylvester, D. Sylvestre, G. Sylvestre, B.
Symington, M. Symons, D. Syrnyk, N. Szalay, E. Szeto, C. Szmata, A. Szoke, C. Szpecht, D. Sztukowski, D. Sztym, C. Szutiak, I. Szwiega, K. Szydlik, J. Ta, V. Ta, C. Tacadena, M. Tade, A. Taghipour, P. Taiani, M. Tainsh, D.
Tainton, D. Tait, O. Tait, J. Taite, A. Tajik, D. Tajiri, D. Takala, S. Takala, S. Talati, B. Talbot, C. Talbot, J. Talbot, M. Talerico, C. Tallack, D. Tallas, B. Talma, K. Tam, N. Taman, B. Tan, C. Tan, K. Tan, S. Tan, M. Tanasescu, B.
Tancowny, E. Tang, L. Tang, X. Tang, G. Tangonan, T. Tanigami, J. Tanner, K. Tanner, M. Tapley, G. Tapp, C. Tarache, A. Tarasenco, C. Tardif, G. Tarditi, K. Targett, B. Tarkowski, R. Taron, D. Tarrant, B. Tasek, J. Tatarin, N.
10
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Tavassoli, A. Taylor, B. Taylor, G. Taylor, H. Taylor, J. Taylor, K. Taylor, L. Taylor, M. Taylor, N. Taylor, P. Taylor, R. Taylor, S. Taylor, J. Tazzman, B. Teare, M. Teeple, A. Tegnander, S. Tejpar, M. Teleptean, R. Tellier, B. Temesgen,
G. Temple, J. Temple, C. Templeton, C. Templin, K. Tenney, J. Teppin, G. Teske, C. Tessier, W. Teszeri, W. Tetachuk, C. Tetreau, J. Tettensor, B. Tetz, J. Tetz, S. Tetz, I. Tewfik, E. Tezcan, F. Thaddaues, L. Thai, T. Tham, J.
Thauberger, S. Theoret, G. Theriault, G. Therriault, W. Thew, R. Thibodeau, J. Thiessen, T. Thiessen, W. Thijs, S. Thind, K. Thistleton, M. Thoen, J. Thomas Cotton, D. Thomas, E. Thomas, I. Thomas, L. Thomas, M. Thomas,
N. Thomas, P. Thomas, S. Thomas, A. Thompson, C. Thompson, D. Thompson, E. Thompson, H. Thompson, I. Thompson, J. Thompson, L. Thompson, R. Thompson, S. Thompson, T. Thompson, J. Thomsen, P. Thomsen, A.
Thomson, K. Thomson, P. Thomson, S. Thomson, T. Thomson, K. Thorburn, T. Thorburne, W. Thorburne, J. Thorleifson, B. Thorn, A. Thorne, D. Thorne, K. Thorne, L. Thorne, B. Thornhill, E. Thornton, N. Thorp, E. Thunaes, D.
Thurman, M. Thyer, T. Tian, M. Tiedje, R. Tiessen, P. Tieu, B. Tiffin, M. Tilford-Shaw, D. Tillapaugh, D. Tilley, K. Tilley, M. Tilley, K. Tillotson, T. Tillotson, B. Timmons, N. Tindall, M. Tineo, W. Tipler, D. Tipper, B. Titus, D. Tiwary,
R. Tiwary, C. Tkach, D. Tkachuk, E. To, B. Tobin, V. Tobin, K. Tobler, B. Todd, C. Todd, W. Todoschuk, N. Tolley, D. Tomar, B. Tomchuk, G. Tomchuk, R. Tomiak, D. Tomiuk, K. Tomlinson, B. Tompkins, A. Tomszak, N. Tomte, W.
Tong, R. Tonhauser, M. Tonon, S. Tookey, V. Topacio, S. Topolnitsky, K. Tordon, L. Torrance, P. Torrance, C. Torraville, F. Torraville, J. Torraville, N. Torres, D. Torriero, M. Tosio, K. Totten, D. Touchette, S. Touchette, L. Tough,
D. Toullelan, K. Tourand, T. Tourand, M. Townsend, D. Tozer, O. Tozser, C. Tran, D. Tran, R. Trant, C. Trapp, L. Trautman, M. Travers, N. Travers, J. Traverse, M. Traverse, P. Traverse, S. Travis, J. Tredger, G. Treen, J. Treen, J.
Trelinski, W. Trelinski, J. Treliving, E. Tremblay, L. Tremblay, M. Tremblay, C. Tremblett, M. Tremblett, W. Tremblett, S. Tremel, D. Trentham, J. Trieu, J. Trieu-Ly, J. Trifaux, S. Trifonov, W. Trigger, A. Trinh, D. Trinh, J. Trinier,
E. Trip-De-Roche, E. Triumbari, B. Troy, P. Troy, J. Trto, J. Trudeau, R. Trudeau, R. Trudel, A. Truefitt, B. Trumpf, A. Truong, S. Truong, H. Tsagalas, Y. Tse, G. Tsemenko, M. Tsineli, F. Tsisar, P. Tso, J. Tu, Y. Tu, A. Tuck, B. Tucker,
D. Tucker, J. Tucker, R. Tucker, S. Tucker, C. Tuffs, A. Tuico, D. Tuite, S. Tulan, B. Tulk, J. Tulk, L. Tulk, B. Tulloch, B. Tumbach, M. Tunke, T. Tupper, T. Turbide, D. Turcotte, J. Turcotte, D. Turgeon, T. Turgeon, B. Turner, C. Turner,
D. Turner, J. Turner, S. Turner, D. Turpin, T. Turpin, V. Turska, S. Turton, S. Turvey, R. Tuttle, S. Tuttle, I. Tutto, L. Tuttosi, T. Twist, M. Twomey, P. Twomey, D. Twyne, O. Tyan, A. Tyler, E. Tylosky, L. Tymchuk, W. Tymchuk, D.
Tymchyna, Z. Tymo, N. Tynan, S. Tyrell, J. Uddin, L. Uhrich, T. Uhrich, S. Ulloa, E. Ulrich, J. Umali, O. Umana, U. Umoh, K. Underwood, N. Underwood, R. Underwood, T. Ung, K. Unger, B. Unrath, L. Unrau, H. Unruh, P. Unruh,
U. Upadhyaya, C. Upham, M. Uponi, D. Urban, L. Urbina, J. Urdaneta, C. Urlacher, A. Ustariz, K. Uyanwune, B. Vacheresse, R. Vachon, S. Vadnai, K. Vaideswaran, G. Valencia, A. Valentine, D. Valin, T. Valin, A. Valiquette, L.
Vallee, M. Vallee, W. Vallee, G. Vallis, A. Valmadrid, A. Van De Reep, V. Van Der Merwe, H. Van Dyck, N. Van Dyke, J. Van Es, D. Van Genne, L. Van Genne, S. Van Jaarsveld, J. Van Nes, S. Van Rensburg, C. Van Schoor, R.
Van Steinburg, R. Van Wieren, C. Van de Reep, W. Van den Oever, M. Vanberg, D. Vanbocquestal, M. Vance, J. Vancoughnett, K. Vandaelle, J. Vandeligt, R. Vandemark, T. Vandemark, D. Vandenberg, G. Vander Veen, T.
Vandermeer, J. Vandervoort, C. Vare, L. Varela Avendano, S. Varey, M. Varga, D. Varty, N. Vaschetto, A. Vashisht, A. Vasquez, M. Vasquez-Placid, J. Vasseur, R. Vassov, R. Vaudan, N. Vaughan, S. Vekved, B. Velagapudi, B.
Velichka, S. Venkatesh, R. Venn, D. Venning, J. Vera, L. Verbaas, D. Verbeek, D. Verbicky, A. Verge, J. Verge, M. Verge, N. Veriotes, A. Verma, S. Veroba, J. Verot, B. Verreau, D. Versnick-Brown, K. Veysey, J. Vezina, E. Viale,
C. Viana, G. Vibert, J. Vicic, S. Vicic, N. Vick, B. Vickery, D. Vidic, N. Vienneau, G. Viljoen, R. Villanueva, J. Villemaire, M. Villemaire, C. Villemere, P. Villeneuve, R. Vincent, R. Vindevoghel, S. Vineham, B. Viney, R. Vinkle, B.
Vinoly, J. Virtanen, G. Virus, K. Virus, A. Visotto, R. Vivian, N. Vizcuna Alvarado, R. Vloet, M. Vogan, E. Vogelsang, V. Volk, B. Volkmann, R. Volkmann, J. Vollman, W. Volschenk, B. Von-Grat, L. Vondermuhll, A. Vosburgh, A.
Votta, A. Vredegoor, J. Vrolson, N. Vucic, J. Vuong, Q. Vuong, B. Vye, G. Wack, C. Wadden, K. Waddy, J. Wade, W. Wade, T. Waggoner, T. Wagil, C. Wagner, D. Wagner, G. Wagner, J. Wagner, K. Wagner, L. Wagner, N.
Wagner, M. Wahl, F. Wajih, D. Wakaruk, L. Wakaruk, L. Wakefield, A. Walchuk, D. Waldner, D. Waldo, K. Waldron, C. Walker, D. Walker, G. Walker, J. Walker, S. Walker, T. Walker, K. Walko, D. Wall, S. Wall, A. Wallace,
C. Wallace, E. Wallace, H. Wallace, K. Wallace, V. Wallace, G. Wallin, N. Wallin, M. Wallis, V. Wallwork, T. Walraven, A. Walsh, B. Walsh, C. Walsh, D. Walsh, E. Walsh, J. Walsh, P. Walsh, R. Walsh, S. Walsh, T. Walsh,
W. Walsh, L. Walter, A. Walters, C. Walters, D. Walters, J. Walters, K. Walters, K. Wambolt, N. Wan, D. Wanchuk, C. Wang, H. Wang, J. Wang, L. Wang, R. Wang, S. Wang, T. Wang, W. Wang, X. Wang, Y. Wang, B.
Wangler, D. Wannas, J. Waquan, L. Waquan, S. Waquan, G. Warburton, T. Warburton, D. Ward, E. Ward, K. Ward, M. Ward, D. Warford, W. Warholik, J. Waring, W. Warman, K. Warnica, F. Warraich, G. Warren, J. Warren,
K. Warren, R. Warren, S. Warren, M. Warsame, K. Warwaruk, A. Wasikowski, P. Wassell, C. Wasylciw, J. Wasylik, W. Wasylucha, L. Watchorn, S. Waterfield, C. Waters, J. Watkins, D. Watson, E. Watson, G. Watson, J.
Watson, K. Watson, M. Watson, B. Watton, S. Watton, B. Watts, J. Watts, A. Wazir, D. Weatherby, C. Weatherhead, L. Weaving, A. Webb, B. Webb, G. Webb, P. Webb, T. Webb, B. Webber, D. Webber, J. Webber, O.
Websdale, K. Webster, D. Weed, E. Weening, E. Weenink, B. Wegenast, B. Wei, Z. Wei, J. Weibrecht, J. Weigl, J. Weik, D. Weimer, C. Weiner, C. Weingarten, A. Weir, R. Weir, G. Weisbeck, T. Weisbrod, R. Weisbrot, M.
Weishaar, C. Weiss, T. Welland, J. Weller, B. Wellman, A. Wells, C. Wells, D. Wells, E. Wells, L. Wells, N. Wells, R. Wells, S. Wells, T. Wells, K. Wellwood, A. Welsh, J. Welsh, W. Welte, Z. Wen, G. Weng, P. Wenger, J.
Wenisch, M. Wenner, J. Wentworth, K. Wenzel, D. Werbowy, D. Werle, C. Werner, H. Werner, C. Werstiuk, N. Wert, B. Weslake, D. Weslake, D. West, R. West, M. Westad, D. Westbrook, R. Westbrook, K. Westland, R.
Westland, J. Westwood, B. Wetthuhn, D. Wheating, L. Wheating, J. Wheaton, S. Wheaton, B. Wheeler, C. Wheeler, J. Wheeler, K. Wheeler, N. Wheeler, S. Wheeler, C. Whelan, D. Whelan, K. Whelan, M. Whelan, R.
Whelan, S. Whelan, R. Whelan-Maloney, G. Whelen, J. Whidden, L. Whillans, A. White, B. White, D. White, F. White, G. White, H. White, J. White, K. White, M. White, P. White, R. White, S. White, T. White, J. Whitehead,
L. Whitehead, T. Whitehead, V. Whitehead, K. Whiteknife, N. Whiteknife, C. Whiteley, A. Whiteside, C. Whitford, H. Whitmore, M. Whittaker, A. Whitten, H. Whitten, A. Whitwell, R. Whyte, A. Wickins, C. Wickwire, A.
Wiebe, D. Wiebe, M. Wiebe, N. Wiebe, T. Wiebe, D. Wiege, T. Wielgus, D. Wiens, S. Wiens, B. Wiesener, C. Wietzel, Z. Wigglesworth, S. Wight, T. Wight, D. Wijesingha, D. Wilbee, M. Wilcox, R. Wild, D. Wilde, E.
Wildeman, M. Wilders, D. Wiles, R. Wiles, C. Wilk, T. Wilk, C. Wilkes, C. Wilkin, D. Wilkins, J. Wilkinson, K. Wilkinson, D. Willard, E. Willard, B. Willburn, A. Willcott, B. Willcott, J. Willems, S. Willette, C. Willey, R. Willey,
A. Williams, B. Williams, C. Williams, D. Williams, G. Williams, L. Williams, M. Williams, N. Williams, P. Williams, S. Williams, T. Williams, W. Williams, C. Williamson, D. Williamson, M. Williamson, J. Willick, M. Willis,
R. Willis, J. Williston, D. Willms, S. Wills, C. Willson, D. Willson, M. Wilschut, B. Wilson, C. Wilson, D. Wilson, G. Wilson, H. Wilson, J. Wilson, K. Wilson, L. Wilson, M. Wilson, R. Wilson, S. Wilson, W. Wilson, J. Wilton,
S. Wilton, A. Winfield, B. Wingate, A. Wingert, J. Winia, B. Winiarz, I. Winland, R. Winnicky, J. Winquist, T. Winquist, D. Winship, R. Winslow, J. Winsor, A. Winter, T. Winter, G. Winters, R. Winters, G. Wirachowsky, J.
Wirachowsky, M. Wiseman, W. Wiseman, N. Withers, M. Witmer, Z. Witt, B. Wittenborn, C. Wlad, A. Wlos, K. Woidak, D. Woitas, J. Woitas, T. Woitte, R. Wojtowicz, S. Wolf, D. Wolfe, J. Wolfe, D. Wollum, C. Woloshyn,
J. Wolstenholme, B. Wolstoncroft, J. Wolter, R. Wolters, A. Wong, J. Wong, L. Wong, N. Wong, T. Wong, C. Woo, J. Woo, K. Woo, L. Woo, G. Wood, J. Wood, L. Wood, P. Wood, R. Wood, R. Woodburne, J. Woodd, S.
Woodfine, F. Woodford, N. Woodford, S. Woodford, T. Woodford, M. Woodhead, D. Woods, J. Woods, S. Woods, T. Woods, M. Woodske, J. Wooldridge, B. Wooley, S. Woolfitt, T. Woolley, R. Woolner, R. Wootton, M.
Workman, M. Workun, M. Woroniuk, C. Worthman, P. Wortman, J. Wotten, B. Wright, J. Wright, L. Wright, S. Wright, G. Wrinn, B. Wu, C. Wu, D. Wu, J. Wu, M. Wu, S. Wu, Y. Wu, P. Wuorinen, B. Wurzer, K. Wutzke, B.
Wychopen, G. Wyman, G. Wyndham, R. Wyness, D. Wyshynski, L. Wysocki, S. Wytrychowski, Y. Xia, Y. Xie, C. Xu, H. Xu, J. Xu, Q. Xu, Y. Xu, Z. Xu, D. Yackel, K. Yakemchuk, K. Yakimowich, L. Yakiwchuk, B. Yang, D. Yang,
J. Yang, L. Yang, S. Yang, D. Yanke, M. Yanota, H. Yare, A. Yaremko, K. Yaremko, R. Yarmuch, J. Yaroslawsky, S. Yasin, M. Yaychuk, B. Ye, B. Yee, G. Yee, R. Yee, C. Yeoman, D. Yep, P. Yepes, J. Yeske, C. Ying, O. Ying, Y.
Ying, J. Yip, K. Yip, L. Yip, L. Yogasundaram, F. Yohannes, R. Yong, F. York, P. York, A. Yoshikawa, X. You, D. Youck, B. Young, C. Young, D. Young, E. Young, G. Young, J. Young, K. Young, L. Young, M. Young, P. Young, S. Young,
T. Young, N. Younis, K. Yousaf, P. Youssef, R. Yowney, E. Yu, G. Yu, J. Yu, C. Yuen, D. Yuill, J. Yuill, R. Yuristy, R. Zabek, A. Zacharias, M. Zacharuk, T. Zachoda, C. Zackowski, J. Zaderey, N. Zaderey, S. Zagozewski, E. Zahacy,
D. Zahara, A. Zahorszky, B. Zaitsoff, D. Zambrano Suarez, B. Zandstra, H. Zarazun, D. Zarowny, K. Zarowny, K. Zayac, D. Zazula, S. Zbrodoff, C. Zeeman, T. Zeiser, Z. Zeitoun, I. Zelazny, D. Zelman, B. Zembik, D. Zemlak, B.
Zeng, A. Zenide, W. Zeniuk, G. Zeran, J. Zerpa, K. Zerr, M. Zerr, S. Zgurski, Y. Zhai, B. Zhang, J. Zhang, M. Zhang, Q. Zhang, W. Zhang, X. Zhang, Y. Zhang, Z. Zhang, B. Zhao, L. Zhao, G. Zheng, S. Zheng, H. Zhou, Q. Zhou, X.
Zhou, Y. Zhou, L. Zhu, W. Zhu, E. Zhuromsky, S. Ziadeh, A. Zielke, F. Zilahy, D. Zilinski, E. Zilinski, E. Zimmer, M. Ziolecki, M. Zoladz, L. Zou, L. Zseder, G. Zubiak, A. Zubot, J. Zuk, S. Zukanovic, N. Zukiwski, D. Zurabyan, J.
Zwolak, K. d'Abadie, S. d'Entremont, M. de Chavez, H. de Graaf, R. de Jong, R. de Ruiter, V. de Ruiter, B. de Winter, B. de Witt, C. de la Salle, R. deBoer, B. van Dyke, P. van Eerde, L. van Heerden, C. van Niekerk, R. van
Zanden, M. van der Burgh, G. van't Wout, E. von Hertzberg, I. Adam, M. Adams, M. Aditiakusuma, R. Adzabe Ella, F. Agbadou, R. Allan, W. Allerton, D. Amalaman, T. Amara, N. Ango Mfene, L. Anongba, R. Aspden, J. Asso,
V. Assohou-Ouattara, F. Assoko-Mve, S. Assoumane, F. Bakita, D. Balogoum, L. Bamba, G. Bates, D. Batt, G. Beaton, K. Begg, N. Bell, S. Bettinson, A. Bhadauria, A. Bhaduri, A. Bird, D. Black, E. Bonnefon, C. Boussougou
Mayagui, L. Boyle, J. Bradshaw, S. Brown, S. Bryson, I. Bulloch, N. Campbell, W. Campbell, D. Chadwick, S. Chalmers, B. Chhualsingh, K. Cisse-Banny, A. Clouston, C. Collinson, D. Conybeare, C. Cook, R. Copland, N. Corbett,
P. Corticelli, J. Costello, L. Coulibaly, S. Coulibaly, D. Coull, I. Cowie, N. Crabb, A. Critten, F. Dadashov, A. Darwin, P. Davison, N. Deeney, D. Dennison, C. Denslow, B. Diabagate, K. Diallo, R. Dicken, G. Dickson, M. Dingley,
P. Dingley, M. Doak, C. Doo, I. Dosso, J. Douglas, B. Duncan, A. Edoukou, J. Edoukou, R. Esslemont, J. Eunson, J. Ewen, A. Farquhar, D. Farrell, B. Finch, J. Fish, B. Flockhart, J. Fowler, N. Franck, L. Fraser, A. Garden, S. Gatt,
R. Gayler, A. Gboko, L. Gemmell, I. Gibbon, J. Gilbert, E. Giuliani, M. Gomaa, L. Gordon, J. Gover, R. Govil, N. Govindarajan Prithivirajan, C. Graham, A. Grant, T. Greig, S. Gue, J. Hardy, J. Harker, S. Hay, S. Heawood, S.
Henderson, K. Heslop, T. Hindson, J. Hoare, L. Houghton, P. Howie, J. Humphrey, E. Hutton, S. Imrie, A. Inglis, R. Inglis, J. Jackson, J. Jamieson, M. Jamieson, S. Jamieson, T. Jervis, P. Johnson, A. Johnston, K. Joseph, T.
Juett, A. Kamate, S. Kelsey, G. Kemp, J. Kerr, G. Kidd, C. Knapper, E. Kodjo Gaba, K. Koffi, L. Koffi, S. Koffi, B. Kone, L. Kone, V. Kone, B. Kotchi, M. Kotty, M. Koua, P. Kouadio, A. Kouakou, D. Kouame, A. Kouassi, H. Kouassi,
J. Koulepe, G. Koumba Lendoye, A. Kourbaj, M. Koutou, V. Kumar, J. Kushe, T. Lamb, S. Lane, P. Latus, A. Laurie, C. Lawford, G. Lawson, E. Leroy, M. Lethaby, E. Lindsay, A. Lobban, J. Loukou, P. Mackintosh, C. MacLeod, A.
MacNiven, C. MacPherson, H. Macrae, M. MacRitchie, D. Maganga, D. Mallum, G. Mann, J. Manning, M. Markussen, D. Marshall, J. Mathieson, R. Mathieson, N. McBain, A. McBoyle, D. McCarry, D. McDonald, F. McGaw,
S. McGregor, J. McGuckin, S. McHardy, A. McIntosh, G. McIntosh, G. McKay, M. McKenzie, K. McLaughlin, W. Mclean, A. McLellan, J. McLellan, J. McMillan, J. McQuade, A. McSharry, J. McTamney, J. Mearns, K. Meh,
D. Merrington, R. Mewis, D. Millar, L. Miller, A. Milne, J. Milne, A. Minty, Y. Mitchell, I. Moffat, A. Mognin, T. Moh, J. Morgan, K. Morrell, I. Morris, P. Mouori Mbani, A. Naughton, H. Ndjoteme - Nendjot, A. NDong Eba,
G. Neves, A. Newman, P. N'Gbesso, H. Ngowe, C. N'Guessan, D. Niamke, A. N'Kesse, M. Nyamba Ekomi, Y. Oble-Karike, M. O'Connell, M. Ogden, M. Ogg, D. Ogilvie, B. Orrell, E. Palmer, A. Paterson, H. Paterson, T. Paterson,
J. Patience, C. Pattinson, J. Penman, D. Philp, G. Plews, I. Pouncey, M. Prosper, R. Puranik, R. Rae, M. Raistrick, H. Rassi, J. Rattray, M. Rattray, G. Renfrew, A. Rennie, J. Rennie, M. Reynolds, I. Riach, J. Richards, T. Rider,
A. Robertson, J. Robertson, S. Robertson, S. Robson, P. Ronnie, E. Rowe, S. Ruddy, N. Rusk, N. Salazar, L. Sanderson, J. Sandie, L. Sanoko, K. Scagliarini, H. Scott, J. Segynola, G. Shah, M. Shahrom, I. Shepherd, B. Silue,
N. Silue, D. Simpson, R. Sinclair, Y. Singh, C. Slessor, K. Slotwinski, F. Smith, L. Smollet, J. Sneddon, I. Soro, L. Soutar, E. Spearman, J. Springer, P. Stephen, M. Stockton, M. Stone, L. Stuart, P. Stuart, D. Sturrock, A. Styles,
C. Suttie, G. Tait, C. Taylor, P. Thimaiah, J. Thomson, W. Thomson, K. Thornton, S. Timothy, C. Tomlinson, C. Toshney, D. Tredou, N. Tulloch, R. Turnbull, A. Vaughan, E. Waddell, C. Wark, S. Watson, D. Watt, G. Watt, H.
Weaver, C. Wheaton, A. Wheeler, D. Whitehouse, S. Wightman, J. Wilding, P. Will, J. Williamson, T. Wire, P. Wiseman, I. Wishart, M. Woodfin, A. Woodger, H. Wossey Ogandaga Mbourou, R. Wright, C. Yang, K. Yao, B.
Yeboue, I. Yohanna, P. Zia
9,973STRONG
WORLD-CLASS TEAM
11
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT 2017 YEAR-END RESERVES
Determination of Reserves
For the year ended December 31, 2017, 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.
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
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Canadian Natural’s 2017 performance has resulted in another year of excellent finding and development costs:
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Finding, Development and Acquisition ("FD&A") costs, excluding the change in Future Development Capital ("FDC"), are $5.15/BOE for proved
reserves and $5.52/BOE for proved plus probable reserves.
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FD&A costs, including the change in FDC, are $12.29/BOE for proved reserves and $12.17/BOE for proved plus probable reserves.
Proved reserve additions and revisions replaced 2017 production by 927%. Proved plus probable reserve additions and revisions replaced
2017 production by 866%.
Proved reserves increased 49% to 8.871 billion BOE with reserve additions and revisions of 3.253 billion BOE. Proved plus probable reserves
increased 29% to 11.866 billion BOE with reserve additions and revisions of 3.038 billion BOE.
The proved BOE reserve life index is 24.6 years and the proved plus probable BOE reserve life index is 33.0 years.
Recycle ratios are 4.5 times and 4.2 times for proved and proved plus probable reserves respectively, excluding the change in FDC. Including the
change in FDC, recycle ratios are 1.9 times for both proved and proved plus probable reserves.
The net present value of future net revenues, before income tax, discounted at 10%, increased 30% to $89.8 billion for proved reserves
and increased 24% to $114.5 billion for proved plus probable reserves. The net present value for proved developed producing reserves increased
46% to $68.1 billion reflecting the completion of Horizon Phase 3 and the acquisition of AOSP.
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12
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT NORTH AMERICA EXPLORATION AND PRODUCTION
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Canadian Natural’s North America conventional and thermal assets delivered strong reserves results in 2017:
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FD&A costs, excluding the change in FDC, are $6.81/BOE for proved reserves and $5.57/BOE for proved plus probable reserves.
FD&A costs, including the change in FDC, are $11.31/BOE for proved reserves and $9.96/BOE for proved plus probable reserves.
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Proved reserve additions and revisions replaced 196% of 2017 production. Proved plus probable reserve additions and revisions replaced
240% of 2017 production.
Proved reserves increased 7% to 3.397 billion BOE. This is comprised of 2.275 billion bbl of crude oil, bitumen, and NGL reserves and 6.730 Tcf
of natural gas reserves.
Proved plus probable reserves increased 6% to 5.482 billion BOE. This is comprised of 3.895 billion bbl of crude oil, bitumen, and NGL reserves and
9.520 Tcf of natural gas reserves.
Proved reserve additions and revisions are 320 million bbl of crude oil, bitumen and NGL and 770 Bcf of natural gas. Proved plus probable reserve
additions and revisions are 349 million bbl of crude oil, bitumen and NGL and 1,194 Bcf of natural gas.
■■
The proved BOE reserve life index is 16.2 years and the proved plus probable BOE reserve life index is 26.2 years.
NORTH AMERICA OIL SANDS MINING AND UPGRADING
■■
Canadian Natural’s Horizon and AOSP oil sands mining and upgrading delivered strong reserves results in 2017:
■●
■●
FD&A costs, excluding the change in FDC, are $4.78/bbl for proved reserves and $5.24/bbl for proved plus probable reserves.
FD&A costs, including the change in FDC, are $12.58/bbl for proved reserves and $12.78/bbl for proved plus probable reserves.
■■
■■
Proved Synthetic Crude Oil ("SCO") reserves increased 106% to 5.264 billion bbl. Proved plus probable SCO reserves increased 68% to 6.063 billion bbl.
SCO proved developed producing reserves increased 107% to 5.264 billion bbl reflecting the completion of Phase 3 at Horizon and the acquisition
of AOSP.
■■
SCO reserves account for 59% of the Company’s proved BOE reserves and 51% of the proved plus probable BOE reserves.
INTERNATIONAL EXPLORATION AND PRODUCTION
■■ North Sea proved reserves decreased 12% to 124 million BOE and proved plus probable reserves decreased 31% to 185 million BOE.
■■ Offshore Africa proved reserves decreased 7% to 86 million BOE and proved plus probable reserves decreased 7% to 136 million BOE.
13
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Summary of Company Gross Reserves
As of December 31, 2017
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)
108
15
75
198
74
272
266
—
61
327
142
469
322
34
994
1,350
1,230
2,580
5,264
—
—
5,264
799
6,063
4,029
347
2,354
6,730
2,790
9,520
102
8
119
229
106
335
6,848
126
1,687
8,661
2,884
11,545
17
—
4
21
11
32
12
—
8
20
47
67
28
4
92
124
61
185
32
2
52
86
50
136
108
15
75
198
74
272
266
—
61
327
142
469
322
34
994
1,350
1,230
2,580
5,264
—
—
5,264
799
6,063
4,058
347
2,366
6,771
2,848
9,619
102
8
119
229
106
335
6,908
132
1,831
8,871
2,995
11,866
114
11
46
171
68
239
25
4
91
120
60
180
30
2
51
83
42
125
169
17
188
374
170
544
North America
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
North Sea
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
Offshore Africa
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
Total Company
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
14
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
Summary of Company Net Reserves
As of December 31, 2017
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
103
10
39
152
58
210
25
4
91
120
60
180
27
2
41
70
32
102
155
16
171
342
150
492
91
13
65
169
61
230
207
—
50
257
101
358
262
28
825
1,115
971
2,086
4,552
—
(9)
4,543
653
5,196
3,654
312
2,066
6,032
2,422
8,454
80
6
101
187
86
273
17
—
4
21
11
32
9
—
6
15
32
47
5,904
109
1,415
7,428
2,334
9,762
28
4
92
124
61
185
29
2
42
73
37
110
91
13
65
169
61
230
207
—
50
257
101
358
262
28
825
1,115
971
2,086
4,552
—
(9)
4,543
653
5,196
3,680
312
2,076
6,068
2,465
8,533
80
6
101
187
86
273
5,961
115
1,549
7,625
2,432
10,057
15
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
Reconciliation of Company Gross Reserves
As of December 31, 2017
Forecast Prices and Costs
PROVED
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, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
North Sea
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
Offshore Africa
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
Total Company
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
16
168
—
4
4
—
6
—
—
7
(18)
171
134
—
—
—
—
—
—
4
(9)
(9)
120
87
—
—
—
—
—
—
—
3
(7)
83
389
—
4
4
—
6
—
4
1
(34)
374
187
—
14
7
1
20
—
—
4
(35)
198
264
—
—
—
1
76
—
—
5
(19)
327
1,269
—
20
—
—
23
—
—
82
(44)
1,350
2,559
—
—
—
—
2,321
—
—
487
(103)
5,264
187
—
14
7
1
20
—
—
4
(35)
198
264
—
—
—
1
76
—
—
5
(19)
327
1,269
—
20
—
—
23
—
—
82
(44)
1,350
2,559
—
—
—
—
2,321
—
—
487
(103)
5,264
6,545
—
276
191
1
116
—
(25)
211
(585)
6,730
41
—
—
—
—
—
—
(5)
(1)
(14)
21
31
—
—
—
—
—
—
—
(3)
(8)
20
6,617
—
276
191
1
116
—
(30)
207
(607)
6,771
198
—
15
17
—
1
—
—
13
(15)
229
198
—
15
17
—
1
—
—
13
(15)
229
5,736
—
99
60
2
2,467
—
(4)
633
(332)
8,661
141
—
—
—
—
—
—
3
(9)
(11)
124
92
—
—
—
—
—
—
—
2
(8)
86
5,969
—
99
60
2
2,467
—
(1)
626
(351)
8,871
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
Reconciliation of Company Gross Reserves
As of December 31, 2017
Forecast Prices and Costs
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, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
North Sea
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
Offshore Africa
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
Total Company
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
65
—
4
2
—
2
—
1
(6)
—
68
119
—
—
1
—
—
—
(4)
(56)
—
60
46
—
—
—
—
—
—
—
(4)
—
42
230
—
4
3
—
2
—
(3)
(66)
—
170
72
—
8
3
—
6
—
—
(15)
—
74
120
—
—
—
1
23
—
—
(2)
—
142
1,248
—
19
—
—
27
—
—
(64)
—
1,230
1,045
—
—
—
—
175
—
—
(421)
—
799
72
—
8
3
—
6
—
—
(15)
—
74
120
—
—
—
1
23
—
—
(2)
—
142
1,248
—
19
—
—
27
—
—
(64)
—
1,230
1,045
—
—
—
—
175
—
—
(421)
—
799
2,366
—
278
104
—
29
(1)
(4)
18
—
2,790
44
—
—
—
—
—
—
5
(38)
—
11
49
—
—
—
—
—
—
—
(2)
—
47
2,459
—
278
104
—
29
(1)
1
(22)
—
2,848
86
—
10
9
—
—
—
—
1
—
106
86
—
10
9
—
—
—
—
1
—
106
3,030
—
88
31
1
237
—
1
(504)
—
2,884
126
—
—
1
—
—
—
(3)
(63)
—
61
54
—
—
—
—
—
—
—
(4)
—
50
3,210
—
88
32
1
237
—
(2)
(571)
—
2,995
17
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
Reconciliation of Company Gross Reserves
As of December 31, 2017
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, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
North Sea
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
Offshore Africa
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
Total Company
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
18
233
—
8
6
—
8
—
1
1
(18)
239
253
—
—
1
—
—
—
—
(65)
(9)
180
133
—
—
—
—
—
—
—
(1)
(7)
125
619
—
8
7
—
8
—
1
(65)
(34)
544
259
—
22
10
1
26
—
—
(11)
(35)
272
384
—
—
—
2
99
—
—
3
(19)
469
2,517
—
39
—
—
50
—
—
18
(44)
2,580
3,604
—
—
—
—
2,496
—
—
66
(103)
6,063
259
—
22
10
1
26
—
—
(11)
(35)
272
384
—
—
—
2
99
—
—
3
(19)
469
2,517
—
39
—
—
50
—
—
18
(44)
2,580
3,604
—
—
—
—
2,496
—
—
66
(103)
6,063
8,911
—
554
295
1
145
(1)
(29)
229
(585)
9,520
85
—
—
—
—
—
—
—
(39)
(14)
32
80
—
—
—
—
—
—
—
(5)
(8)
67
9,076
—
554
295
1
145
(1)
(29)
185
(607)
9,619
284
—
25
26
—
1
—
—
14
(15)
335
284
—
25
26
—
1
—
—
14
(15)
335
8,766
—
187
91
3
2,704
—
(3)
129
(332)
11,545
267
—
—
1
—
—
—
—
(72)
(11)
185
146
—
—
—
—
—
—
—
(2)
(8)
136
9,179
—
187
92
3
2,704
—
(3)
55
(351)
11,866
CANADIAN NATURAL 2017 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:
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$/MMBtu)
Henry Hub (US$/MMBtu)
2018
55.00
51.05
65.44
64.44
67.72
58.00
2.85
2.45
3.25
$
$
$
$
$
$
$
$
$
2019
65.00
59.61
74.51
73.51
75.61
67.00
3.11
2.71
3.50
$
$
$
$
$
$
$
$
$
2020
70.00
64.94
78.24
77.24
78.82
72.00
3.65
3.25
4.00
$
$
$
$
$
$
$
$
$
2021
73.00
68.43
82.45
81.45
82.35
75.00
3.80
3.40
4.08
$
$
$
$
$
$
$
$
$
2022
74.46
69.80
84.10
83.10
84.07
76.50
3.95
3.55
4.16
$
$
$
$
$
$
$
$
$
Annual
increase
thereafter
2.00%
2.00%
2.00%
2.00%
2.00%
2.00%
2.00%
2.00%
2.00%
Note: A foreign exchange rate of 0.7900 US$/C$ for 2018, 0.8200 US$/C$ for 2019, and 0.8500 US$/C$ after 2019 was used in the 2017 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) Reserve replacement or Production 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 2018 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 2017 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 2017
and net change in FDC from December 31, 2016 to December 31, 2017 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 ($23.40/BOE for 2017) 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.
19
CANADIAN NATURAL 2017 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 Oil Sands Mining and
Upgrading operations and future expansions, Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands
Project, the cost of 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 2018
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 future production may vary significantly from reserves 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; production levels; imprecision of reserves 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.
20
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT The Company’s operations have been, and in the future may be, affected by political developments and by national, federal, provincial and local laws
and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies,
price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any
of the Company’s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements.
The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such 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 (previously 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, 2017. It should also be read in conjunction with the Company's MD&A for the three
months and year ended December 31, 2017, which is incorporated herein by reference. 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 SCO. 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 and feedstock 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 2017 financial results compared to 2016 and 2015, unless otherwise indicated.
In addition, this MD&A details the Company's targeted capital program for 2018. Additional information relating to the Company, including its quarterly
MD&A for the year and three months ended December 31, 2017, its Annual Information Form for the year ended December 31, 2017, and its audited
consolidated financial statements for the year ended December 31, 2017 is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov.
This MD&A is dated February 28, 2018.
21
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Definitions and Abbreviations
AECO
Alberta natural gas reference location
AIF
AOSP
API
ARO
bbl
bbl/d
Bcf
Bcf/d
BOE
Annual Information Form
Athabasca Oil Sands Project
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
BOE/d
barrels of oil equivalent per day
Bitumen
Brent
C$
CAGR
CAPEX
CO2
CO2e
Crude oil
CSS
EOR
E&P
FPSO
GHG
GJ
GJ/d
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
thousand cubic feet
thousand cubic feet equivalent
thousand cubic feet per day
MMbbl
million barrels
MMBOE
million barrels of oil equivalent
MMBtu
million British thermal units
MMcf
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 WCS Heavy Differential from WTI
Differential
WTI
West Texas Intermediate reference location at
Cushing, Oklahoma
22
CANADIAN NATURAL 2017 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 economic development of its existing crude oil and natural gas properties and through the discovery and/or acquisition of new reserves.
The Company strives to meet these objectives by having a defined growth and value enhancement plan for each of its products and segments. The
Company takes a balanced approach to growth and investments and focuses on creating long-term shareholder value. The Company allocates its
capital by maintaining:
■■
Balance among its products, namely 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, long life low decline 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 12–17º 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, and 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 periodically utilizes its risk management hedging program to reduce the
risk of volatility in commodity prices and foreign exchange rates and to support 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 and equity financing to selectively acquire properties generating future cash flows in its core areas.
23
CANADIAN NATURAL 2017 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
2017
17,669
2,397
2.04
2.03
1,403
1.19
1.19
7,347
6.25
6.21
1.10
73,867
35,953
17,129
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2016
11,098
$
(204) $
(0.19) $
(0.19) $
(669) $
(0.61) $
(0.61) $
4,293
3.90
3.89
0.94
58,648
27,289
3,794
$
$
$
$
$
$
$
2015
13,167
(637)
(0.58)
(0.58)
263
0.24
0.24
5,785
5.29
5.28
0.92
59,275
27,299
3,853
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(2)
(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” presented in this MD&A, 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.
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 Company's
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 February 28, 2018, the Board of Directors approved an increase in the quarterly dividend to $0.335 per common share, beginning with the dividend payable on April 1, 2018.
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. On March 4, 2015 the Board of
Directors declared a quarterly dividend of $0.23 per common share, beginning with the dividend payable on April 1, 2015.
24
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
Adjusted Net Earnings (Loss) from Operations
($ millions)
Net earnings (loss) as reported
Share-based compensation, net of tax (1)
Unrealized risk management loss, net of tax (2)
Unrealized foreign exchange (gain) loss, net of tax (3)
(Gain) loss from investments, net of tax (4) (5)
Gain on acquisition, disposition and revaluation of properties, net of tax (6)
Derecognition of exploration and evaluation assets, net of tax (7)
Effect of statutory tax rate and other legislative changes on deferred
income tax liabilities (8)
Adjusted net earnings (loss) from operations
2017
2016
$
2,397
$
(204) $
134
33
(821)
(11)
(339)
—
10
355
21
(93)
(299)
(241)
13
(221)
$
1,403
$
(669) $
2015
(637)
(46)
275
858
55
(663)
70
351
263
(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 charged to (recovered from) Oil Sands Mining and Upgrading.
(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) 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.
(5) 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).
(6) During 2017, the Company recorded a pre-tax revaluation gain of $114 million ($83 million after-tax) related to a previously held joint interest in a pipeline system. Additionally, the Company
recorded a pre and after-tax gain of $230 million on the acquisition of a direct and indirect 70% interest in AOSP and other assets from Shell Canada Limited and certain subsidiaries (“Shell”)
and an affiliate of Marathon Oil Corporation (“Marathon"), and a pre-tax gain of $35 million ($26 million after-tax) on the disposition of certain exploration and evaluation assets in the North
America segment. 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.
(7) During 2016, in connection with the Company's notice of withdrawal from Block CI-12 in Côte d'Ivoire, Offshore Africa, the Company derecognized $18 million ($13 million after-tax) of
exploration and evaluation assets through depletion, depreciation and amortization expense. 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 ($70 million after-tax) of exploration and evaluation assets through depletion, depreciation and amortization expense.
(8) All substantively enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company's balance
sheets in determining deferred income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in net earnings (loss) during the period the
legislation is substantively enacted. During 2017, the British Columbia government enacted legislation that increased the provincial corporate income tax rate from 11% to 12%
effective January 1, 2018. As a result of this income tax rate increase, the Company's deferred corporate income tax liability was increased by $10 million. 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. 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, 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
Unrealized foreign exchange (gain) loss
(Gain) loss from investments
Deferred income tax expense (recovery)
Gain on acquisition, disposition and revaluation of properties
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.
2017
2016
$
2,397
$
(204) $
5,186
4,858
134
164
37
(821)
(11)
640
(379)
—
355
142
25
(93)
(299)
(241)
(250)
—
2015
(637)
5,483
(46)
173
374
858
55
231
(739)
33
$
7,347
$
4,293
$
5,785
25
CANADIAN NATURAL 2017 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
2017
2016
$
7,262
$
3,452
$
(299)
274
110
542
267
32
2015
5,632
(239)
370
22
$
7,347
$
4,293
$
5,785
Summary of Consolidated Net Earnings (Loss) and Funds Flow from Operations
For 2017, the Company reported net earnings of $2,397 million compared with a net loss of $204 million for 2016 (2015 – $637 million net loss).
Net earnings for 2017 included net after-tax income of $994 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 acquisition, disposition and revaluation of properties, derecognition of exploration and evaluation assets and the impact of statutory
tax rate and other legislative changes on deferred income tax liabilities (2016 – $465 million after-tax income; 2015 – $900 million after-tax expenses).
Excluding these items, the adjusted net earnings from operations for 2017 was $1,403 million compared with an adjusted net loss of $669 million for 2016
(2015 – $263 million adjusted net earnings).
The increase in adjusted net earnings (loss) for 2017 from 2016 was primarily due to:
■■
■■
■■
higher SCO sales volumes in the Oil Sands Mining and Upgrading segment, due to volumes associated with both the acquisition of AOSP and new
Phase 2B and Phase 3 sales volumes at Horizon;
higher crude oil and NGLs and natural gas netbacks in the Exploration and Production segments; and
higher realized SCO prices in the Oil Sands Mining and Upgrading segment;
partially offset by:
■■
■■
■■
higher depletion, depreciation and amortization;
higher interest and financing expense; and
the strengthening of the Canadian dollar relative to the US dollar.
The impacts of share-based compensation, risk management activities and fluctuations in foreign exchange rates are expected to continue to contribute
to significant volatility in consolidated net earnings (loss) and are discussed in detail in the relevant sections of this MD&A.
Funds flow from operations for 2017 increased to $7,347 million ($6.25 per common share) from $4,293 million for 2016 ($3.90 per common share)
(2015 – $5,785 million; $5.29 per common share). The increase in funds flow from operations for 2017 from 2016 was primarily due to the factors noted
above relating to the increase in adjusted net earnings (loss), partially offset by the impact of cash taxes.
In the Company’s Exploration and Production activities, the 2017 average sales price per bbl of crude oil and NGLs increased 32% to average
$48.57 per bbl from $36.93 per bbl in 2016 (2015 – $41.13 per bbl), and the 2017 average natural gas price increased 19% to average $2.76 per Mcf from
$2.32 per Mcf in 2016 (2015 – $3.16 per Mcf). In the Oil Sands Mining and Upgrading segment, the Company’s 2017 average SCO sales price increased
9% to average $63.98 per bbl from $58.59 per bbl in 2016 (2015 – $61.39 per bbl).
Total production of crude oil and NGLs before royalties for 2017 increased 31% to average 685,236 bbl/d from 523,873 bbl/d in 2016
(2015 – 564,188 bbl/d). The increase in crude oil and NGLs production from 2016 was primarily due to acquisitions completed in 2017 and new
Phase 2B and Phase 3 production at Horizon.
Total natural gas production before royalties for 2017 decreased 2% to average 1,662 MMcf/d from 1,691 MMcf/d in 2016 (2015 – 1,726 MMcf/d).
The decrease in natural gas production from 2016 primarily reflected lower production in North America due to the continued impact of reliability
issues at a third party processing facility and shut-in production volumes related to low natural gas prices.
Total crude oil and NGLs and natural gas production volumes before royalties for 2017 increased 19% to average 962,264 BOE/d from 805,782 BOE/d
in 2016 (2015 – 851,901 BOE/d).
26
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company’s quarterly results for the eight most recently completed quarters:
($ millions, except per common share amounts)
2017
Product sales
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
($ millions, except per common share amounts)
2016
Product sales
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
Total
17,669
2,397
2.04
2.03
$
$
$
$
Dec 31
5,323
396
0.32
0.32
Total
11,098
$
(204) $
Dec 31
3,672
566
(0.19) $
(0.19) $
0.51
0.51
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Sep 30
4,547
684
0.56
0.56
$
$
$
$
Jun 30
3,927
1,072
0.93
0.93
$
$
$
$
Mar 31
3,872
245
0.22
0.22
Sep 30
Jun 30
Mar 31
2,477
$
(326) $
2,686
$
(339) $
(0.29) $
(0.29) $
(0.31) $
(0.31) $
2,263
(105)
(0.10)
(0.10)
Volatility in the quarterly net earnings (loss) over the eight most recently completed quarters was primarily due to:
■■ Crude oil pricing – 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 shale
oil production in North America, the impact of the WCS Heavy Differential in North America and the impact of the differential between WTI and
Brent benchmark pricing in the North Sea and Offshore Africa.
■■ Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, third party pipeline maintenance
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, fluctuations in the Company’s drilling program in
North America, the impact and timing of acquisitions, including the acquisition of AOSP and other assets, new production from Horizon Phase 2B
and Phase 3, the impact of turnarounds at Horizon and pitstops at AOSP, shut-in production due to low commodity prices, 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, an outage at a third party processing facility, shut-in production due to third party pipeline restrictions and related pricing impacts,
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, including the acquisition of AOSP and other assets, turnarounds at Horizon and pitstops at AOSP, 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, fluctuations in depletion, depreciation, and amortization expense in the North Sea due to the cessation of production at the
Ninian North platform in 2017, 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.
27
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
■■
Income tax expense – Fluctuations in income tax expense include statutory tax rate and other legislative changes substantively enacted in the
various periods.
■■ Gain on acquisition, disposition and revaluation of properties and gain/loss on investments – Fluctuations due to the recognition of
gains on the acquisition of AOSP and other assets, the disposition and revaluation of properties in the various periods, fair value changes in the
investments in PrairieSky and Inter Pipeline shares, and the equity (gain) loss in North West Redwater.
Business Environment
(Yearly average)
WTI benchmark price (US$/bbl)
Dated Brent benchmark price (US$/bbl)
WCS blend differential from WTI (US$/bbl)
SCO price (US$/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$)
2017
50.93
54.38
11.97
52.20
51.65
3.11
2.30
0.7701
0.7988
$
$
$
$
$
$
$
$
$
2016
43.37
43.96
13.91
43.94
42.51
2.45
1.98
0.7548
0.7448
$
$
$
$
$
$
$
$
$
2015
48.76
52.40
13.51
48.59
47.34
2.67
2.62
0.7820
0.7225
$
$
$
$
$
$
$
$
$
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 2017, product revenue continued to be impacted by the volatility in the 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 2017, with a high of approximately US$0.82 in September 2017 and a low of
approximately US$0.73 in May 2017.
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$50.93 per bbl for 2017, an
increase of 17% from US$43.37 per bbl for 2016 (2015 – US$48.76 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$54.38 per bbl for 2017, an increase of 24% from US$43.96 per bbl for
2016 (2015 – US$52.40 per bbl).
WTI and Brent pricing for 2017 increased from 2016 primarily due to declines in global crude oil inventories as a result of OPEC’s adherence to
previously announced production cuts, together with larger than anticipated increases in global demand for crude oil.
The WCS Heavy Differential averaged US$11.97 for 2017, a decrease of 14% from US$13.91 for 2016 (2015 – US$13.51). The WCS Heavy
Differential reflects US Gulf Coast pricing, adjusted for transportation costs. Fluctuations in the WCS Heavy Differential reflected seasonal supply and
demand factors and changes in transportation logistics. Subsequent to December 31, 2017 the WCS Heavy Differential widened due to third party
pipeline outages.
The SCO price averaged US$52.20 per bbl for 2017, an increase of 19% from US$43.94 per bbl for 2016 (2015 – US$48.59 per bbl). The increase in
SCO pricing for 2017 from 2016 was primarily due to changes in WTI benchmark pricing.
NYMEX natural gas prices averaged US$3.11 per MMBtu for 2017, an increase of 27% from US$2.45 per MMBtu for 2016 (2015 – US$2.67 per
MMBtu). AECO natural gas prices averaged $2.30 per GJ for 2017, an increase of 16% from $1.98 per GJ for 2016 (2015 – $2.62 per GJ).
The increase in natural gas prices for 2017 compared with 2016 reflected the rebalancing of natural gas storage inventory to historically normal levels.
28
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Analysis of Changes in Product Sales
Changes due to
Changes due to
2015
Volumes
Prices
Other
2016
Volumes
Prices
Other
2017
$
(937) $
(690) $
(40)
(977)
(454)
(1,144)
$
108
—
108
5,933
1,276
7,209
$
135
$
1,755
$
(168) $
250
2,005
—
(168)
($ millions)
North America
Crude oil and NGLs
$
Natural gas
North Sea
Crude oil and NGLs
Natural gas
Offshore Africa
Crude oil and NGLs
Natural gas
Subtotal
Crude oil and NGLs
Natural gas
Oil Sands Mining
and Upgrading
Midstream
Intersegment
eliminations and
other (1)
7,452
1,770
9,222
512
126
638
389
93
482
8,353
1,989
10,342
2,764
136
(75)
7,655
1,506
9,161
666
118
784
579
53
632
8,900
1,677
10,577
7,072
102
(5)
—
(5)
14
—
14
(159)
—
(159)
27
(12)
(20)
115
63
3
66
(70)
(22)
(92)
128
(39)
89
3,827
—
130
23
153
103
4
107
1,988
277
2,265
561
—
—
54
9
63
224
17
241
(659)
(14)
(673)
17
—
—
(78)
(43)
(121)
(79)
(39)
(118)
(847)
(536)
(1,383)
(126)
—
—
478
92
570
532
71
603
6,943
1,439
8,382
2,657
114
(10)
—
(10)
(2)
—
(2)
96
—
96
2
(22)
20
96
Total
$
13,167
$
(656) $
(1,509) $
(1) Eliminates internal transportation and electricity charges.
(55)
—
(27)
(82)
$
11,098
$
3,916
$
2,826
$
(171) $
17,669
Product sales increased 59% to $17,669 million for 2017 from $11,098 million for 2016 (2015 – $13,167 million). The increase was primarily due to higher
SCO sales volumes in the Oil Sands Mining and Upgrading segment and higher realized prices in all business segments.
For 2017, 8% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America (2016 – 11%; 2015 – 9%).
North Sea accounted for 4% of crude oil and NGLs and natural gas product sales for 2017 (2016 – 5%; 2015 – 5%), and Offshore Africa accounted for
4% of crude oil and NGLs and natural gas product sales for 2017 (2016 – 6%; 2015 – 4%).
29
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
Daily Production, Before Royalties
Crude oil and NGLs (bbl/d)
North America – Exploration and Production
Oil Sands Mining and Upgrading – Horizon (1)
Oil Sands Mining and Upgrading – AOSP
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
2017
2016
2015
359,449
170,089
111,937
23,426
20,335
685,236
1,601
39
22
1,662
962,264
14%
6%
10%
12%
29%
29%
90%
10%
350,958
123,265
—
23,554
26,096
523,873
1,622
38
31
1,691
805,782
17%
6%
13%
14%
15%
35%
85%
15%
399,982
122,911
—
22,216
19,079
564,188
1,663
36
27
1,726
851,901
16%
6%
15%
15%
14%
34%
82%
18%
(1) 2017 SCO production before royalties excludes 651 bbl/d of SCO consumed internally as diesel (2016 – 1,966 bbl/d, 2015 – 2,122 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
Oil Sands Mining and Upgrading – Horizon
Oil Sands Mining and Upgrading – AOSP
North Sea
Offshore Africa
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Total barrels of oil equivalent (BOE/d)
30
2017
2016
2015
312,297
167,248
107,189
23,382
19,124
629,240
1,528
39
20
1,587
893,702
311,059
122,258
—
23,497
24,995
481,809
1,559
38
30
1,627
752,974
350,451
121,208
—
22,164
18,209
512,032
1,606
36
25
1,667
789,799
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
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 2017 production averaged 962,264 BOE/d, a 19% increase from 805,782 BOE/d in 2016 (2015 – 851,901 BOE/d).
Total production of crude oil and NGLs for 2017 increased 31% to 685,236 bbl/d from 523,873 bbl/d for 2016 (2015 – 564,188 bbl/d). The increase in
crude oil and NGLs production from 2016 was primarily due to acquisitions completed in 2017 and new Phase 2B and Phase 3 production at Horizon.
Crude oil and NGLs production for 2017 was within the Company’s previously issued guidance of 663,000 to 717,000 bbl/d.
Natural gas production accounted for 29% of the Company's total production in 2017 on a BOE basis. Natural gas production for 2017 decreased 2%
to 1,662 MMcf/d from 1,691 MMcf/d for 2016 (2015 – 1,726 MMcf/d). Natural gas production continued to be impacted by shut-in production volumes
due to low natural gas prices and the impact of reliability issues at a third party facility. As a result of continued integrity issues, capacity at this
facility has now been reduced to a one train operation. Natural gas production for 2017 was within the Company’s previously issued guidance of 1,655
to 1,705 MMcf/d.
NORTH AMERICA – EXPLORATION AND PRODUCTION
North America crude oil and NGLs production for 2017 increased 2% to average 359,449 bbl/d from 350,958 bbl/d for 2016 (2015 – 399,982 bbl/d).
The increase in production from 2016 was primarily due to acquisitions completed in 2017.
Natural gas production for 2017 of 1,601 MMcf/d was comparable with 1,622 MMcf/d for 2016 (2015 – 1,663 MMcf/d). Natural gas production
continued to be impacted by shut-in production volumes due to low natural gas prices and the impact of reliability issues at a third party facility. As a
result of continued integrity issues, capacity at this facility has now been reduced to a one train operation.
HORIZON
Horizon SCO production for 2017 increased 38% to 170,089 bbl/d from 123,265 bbl/d for 2016 (2015 – 122,911 bbl/d). The increase in 2017 production
primarily reflected new Phase 2B and Phase 3 production.
ATHABASCA OIL SANDS PROJECT
AOSP annualized SCO production for 2017 averaged 111,937 bbl/d, reflecting the Company's direct and indirect 70% interest in the project acquired
in May 2017.
NORTH SEA
North Sea crude oil production for 2017 of 23,426 bbl/d was comparable with 23,554 bbl/d for 2016 (2015 – 22,216 bbl/d).
OFFSHORE AFRICA
Offshore Africa crude oil production for 2017 decreased 22% to 20,335 bbl/d from 26,096 bbl/d for 2016 (2015 – 19,079 bbl/d). Production volumes
decreased from 2016 primarily due to natural field declines.
CORPORATE PRODUCTION GUIDANCE FOR 2018
The Company targets production levels in 2018 to average between 815,000 bbl/d and 885,000 bbl/d of crude oil and NGLs and between 1,650 MMcf/d
and 1,710 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
2017
—
121,936
121,936
2016
987,316
1,126,999
2,114,315
2015
835,806
1,271,170
2,106,976
31
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Operating Highlights – Exploration and Production
Crude oil and NGLs ($/bbl) (1)
Sales price (2)
Transportation
Realized sales price, net of transportation
Royalties
Production expense
Netback
Natural gas ($/Mcf) (1)
Sales price (2)
Transportation
Realized sales price, net of transportation
Royalties
Production expense
Netback
Barrels of oil equivalent ($/BOE) (1)
Sales price (2)
Transportation
Realized sales price, net of transportation
Royalties
Production expense
Netback
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
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)
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
2017
2016
$
48.57
$
36.93
$
2.80
45.77
5.24
14.89
25.64
2.76
0.39
2.37
0.11
1.27
0.99
$
$
$
2.61
34.32
3.40
14.10
16.82
2.32
0.33
1.99
0.09
1.18
0.72
$
$
$
35.54
$
27.58
$
2.66
32.88
3.40
11.95
17.53
2017
45.85
69.43
67.15
48.57
2.58
8.24
6.57
2.76
35.54
$
$
$
$
$
$
$
$
$
$
2.44
25.14
2.21
11.18
11.75
2016
34.31
55.91
54.96
36.93
2.15
6.62
6.13
2.32
27.58
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2015
41.13
2.60
38.53
4.30
15.74
18.49
3.16
0.38
2.78
0.10
1.34
1.34
32.60
2.56
30.04
2.85
12.70
14.49
2015
38.96
65.13
63.13
41.13
2.91
9.66
9.53
3.16
32.60
Realized crude oil and NGLs prices increased 32% to average $48.57 per bbl for 2017 from $36.93 per bbl for 2016 (2015 – $41.13 per bbl), primarily
due to higher WTI and Brent benchmark pricing.
The Company’s realized natural gas price increased 19% to average $2.76 per Mcf for 2017 from $2.32 per Mcf for 2016 (2015 – $3.16 per Mcf).
The increase in 2017 reflected the rebalancing of natural gas storage inventory to historically normal levels.
NORTH AMERICA
North America realized crude oil prices increased 34% to average $45.85 per bbl for 2017 from $34.31 per bbl for 2016 (2015 – $38.96 per bbl),
primarily due to higher WTI benchmark pricing.
North America realized natural gas prices increased 20% to average $2.58 per Mcf for 2017 from $2.15 per Mcf for 2016 (2015 – $2.91 per Mcf).
The increase reflected the rebalancing of natural gas storage inventory to historically normal levels.
32
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT The Company continues to focus on its crude oil marketing strategy including a blending strategy that expands markets within current pipeline
infrastructure, supporting pipeline projects that will provide capacity to transport crude oil to new markets, and working with refiners to add incremental
heavy crude oil and bitumen (thermal oil) conversion capacity. During 2017, the Company contributed approximately 195,800 bbl/d of heavy crude oil
blends to the WCS stream.
The Company has entered into a 20 year transportation agreement to ship 75,000 bbl/d of crude oil on the proposed Kinder Morgan Trans Mountain
Pipeline Expansion from Edmonton, Alberta to Vancouver, British Columbia. The project has received regulatory approval and is awaiting final permits.
Pipeline construction is scheduled to begin in the latter half of 2018 with an expected in-service date late in 2020.
The Company has also entered into a 20 year transportation agreement to ship 175,000 bbl/d of crude oil on the proposed Trans Canada Keystone XL
Pipeline from Hardisty, Alberta to the US Gulf Coast. The project received a Presidential Permit in March 2017 and the regulatory process of finalizing
route alterations and shipper commitments is ongoing. The pipeline has an expected in-service date in 2021.
In November 2017, the Energy East Pipeline Limited Partnership terminated the Energy East Pipeline project and the Company’s agreement to transport
80,000 bbl/d was cancelled.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
(Yearly average)
Wellhead Price (1) (2)
Light and medium crude oil and NGLs ($/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.
NORTH SEA
2017
47.78
48.30
46.88
42.49
2.58
$
$
$
$
$
2016
37.72
36.03
34.73
30.47
2.15
$
$
$
$
$
2015
41.88
41.09
40.71
34.37
2.91
$
$
$
$
$
North Sea realized crude oil prices increased 24% to average $69.43 per bbl for 2017 from $55.91 per bbl for 2016 (2015 – $65.13 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 increase in realized crude oil prices in 2017 reflected higher
prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.
OFFSHORE AFRICA
Offshore Africa realized crude oil prices increased 22% to average $67.15 per bbl for 2017 from $54.96 per bbl for 2016 (2015 – $63.13 per bbl).
Realized crude oil prices per bbl in any particular year are dependent on the terms of the various sales contracts, the frequency and timing of liftings of
each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The increase in realized crude oil prices in 2017 reflected
higher prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.
Royalties – Exploration and Production
Crude oil and NGLs ($/bbl) (1)
North America
North Sea
Offshore Africa
Company average
Natural gas ($/Mcf) (1)
North America
Offshore Africa
Company average
Company average ($/BOE) (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2017
2016
2015
5.69
0.13
4.13
5.24
0.11
0.76
0.11
3.40
$
$
$
$
$
$
$
$
3.69
0.13
2.31
3.40
0.08
0.28
0.09
2.21
$
$
$
$
$
$
$
$
4.57
0.14
2.87
4.30
0.09
0.46
0.10
2.85
$
$
$
$
$
$
$
$
33
CANADIAN NATURAL 2017 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 2017 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 13% of product sales for 2017 compared with 12% of product sales for 2016 (2015 – 13%).
The increase in royalties for 2017 from 2016 was primarily due to higher realized crude oil prices during 2017. North America crude oil and NGLs
royalties per bbl are anticipated to average 10% to 12% of product sales for 2018.
Natural gas royalties averaged approximately 5% of product sales for 2017 compared with 4% of product sales for 2016 (2015 – 4%). The increase in
royalties for 2017 from 2016 was primarily due to higher realized natural gas prices. North America natural gas royalties are anticipated to average
4% to 6% of product sales for 2018.
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 7% for 2017 compared with 4% of product sales for 2016 (2015 – 5%).
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 2018.
Production Expense – Exploration and Production
Crude oil and NGLs ($/bbl) (1)
North America
North Sea
Offshore Africa
Company average
Natural gas ($/Mcf) (1)
North America
North Sea
Offshore Africa
Company average
Company average ($/BOE) (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
NORTH AMERICA
2017
12.71
36.60
24.07
14.89
1.19
3.37
2.90
1.27
11.95
$
$
$
$
$
$
$
$
$
2016
11.89
42.47
18.48
14.10
1.12
3.09
1.79
1.18
11.18
$
$
$
$
$
$
$
$
$
2015
12.51
63.67
33.32
15.74
1.27
4.41
1.76
1.34
12.70
$
$
$
$
$
$
$
$
$
North America crude oil and NGLs production expense for 2017 increased 7% to $12.71 per bbl from $11.89 per bbl for 2016 (2015 – $12.51 per bbl).
The Company continues to focus on cost control and achieving efficiencies on acquired assets and across the entire asset base. The increase in crude
oil and NGLs production expense for 2017 from 2016 reflected higher maintenance, trucking and other service costs. Crude oil and NGLs production
expense for 2017 was within annual guidance of $11.50 to $13.50 per bbl. North America crude oil and NGLs production expense is anticipated to
average $11.50 to $13.50 per bbl for 2018.
North America natural gas production expense for 2017 increased 6% to $1.19 per Mcf from $1.12 per Mcf for 2016 (2015 – $1.27 per Mcf).
The Company continues to focus on cost control and achieving efficiencies on acquired assets and across the entire asset base. The increase in natural
gas production expense for 2017 from 2016 reflected higher maintenance and other service costs. Natural gas production expense for 2017 was within
annual guidance of $1.00 to $1.20 per Mcf. North America natural gas production expense is anticipated to average $1.00 to $1.20 per Mcf for 2018.
NORTH SEA
North Sea crude oil production expense for 2017 decreased 14% to $36.60 per bbl from $42.47 per bbl for 2016 (2015 – $63.67 per bbl). The decrease
for 2017 from 2016 reflected the Company's continuous focus on cost control, efficiencies and production optimization. Production expense also
reflected fluctuations in the Canadian dollar and the UK pound sterling. Crude oil and NGLs production expense for 2017 was slightly above annual
guidance of $33.00 to $36.00 per bbl, reflecting the impact of lower volumes on a relatively fixed cost base due to temporary unplanned shut-ins.
North Sea crude oil production expense guidance is anticipated to average $36.00 to $39.00 per bbl for 2018.
34
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT OFFSHORE AFRICA
Offshore Africa crude oil production expense for 2017 increased 30% to $24.07 per bbl from $18.48 per bbl for 2016 (2015 – $33.32 per bbl). Total
Offshore Africa crude oil production expense for 2017 primarily reflected 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.
On a standalone basis, Offshore Africa production expense for 2017 related to the Baobab and Espoir fields in Côte d'Ivoire was $12.41 per bbl and
was within annual guidance of $10.50 to $12.50 per bbl. Offshore Africa production expense related to Côte d'Ivoire is anticipated to average
$11.00 to $13.00 per bbl for 2018.
Depletion, Depreciation and Amortization – Exploration and Production
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Expense
$/BOE (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2017
2016
3,243
$
3,465
$
509
205
458
262
3,957
15.82
$
$
4,185
16.79
$
$
2015
4,248
388
273
4,909
18.50
$
$
$
Depletion, depreciation and amortization in 2017 decreased 6% to $15.82 per BOE from $16.79 per BOE for 2016 (2015 – $18.50 per BOE). The decrease
in depletion, depreciation and amortization expense per BOE for 2017 from 2016 was primarily due to a lower depletable base in North America,
partially offset by additional depletion, depreciation and amortization in the North Sea related to the abandonment of the Ninian North platform.
Asset Retirement Obligation Accretion – Exploration and Production
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Expense
$/BOE (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2017
80
27
9
116
0.46
$
$
$
2016
66
35
12
113
0.45
$
$
$
2015
93
39
10
142
0.54
$
$
$
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 2017 of $0.46 per BOE was comparable with $0.45 per BOE for 2016 (2015 – $0.54 per BOE).
Operating Highlights – Oil Sands Mining and Upgrading
On May 31, 2017 the Company completed the acquisition of a direct and indirect 70% interest in AOSP, including a 70% interest in the mining and
extraction operations north of Fort McMurray, Alberta and 70% of the Scotford Upgrader and Quest Carbon Capture and Storage ("CCS") project.
The acquisition strengthened the Company's portfolio of long life no decline synthetic crude oil assets. Effective May 31, 2017, the Oil Sands Mining
and Upgrading segment of this MD&A reflects the mining, extraction and upgrading operations at both Horizon and AOSP.
The Company continues to focus on reliable and efficient operations. The Oil Sands Mining and Upgrading segment achieved production during 2017
averaging 282,026 bbl/d following the addition of new production volumes from the acquisition of and successful integration of the Company's interest
in AOSP as well as new Phase 2B and Phase 3 production at Horizon.
HORIZON OPERATIONS UPDATE
Horizon SCO production averaged 170,089 bbl/d during 2017, reflecting new Phase 2B and Phase 3 production. Through the Company's continuous
focus on cost control and efficiencies, high utilization rates and reliability, together with additional production from new Phase 2B and Phase 3,
adjusted cash production costs averaged $21.46 per bbl.
The Horizon Phase 3 expansion was completed on schedule and within budget. Phase 3 activities included the expansion tie-in and commissioning of
the production plant. SCO production for the month of December averaged approximately 247,200 bbl/d, reflecting new Phase 3 production.
35
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT AOSP OPERATIONS UPDATE
Annualized AOSP SCO production averaged 111,937 bbl/d during 2017, reflecting high reliability of operations. Through the Company's continuous focus
on cost control and efficiencies, high utilization rates and reliability of AOSP operations, cash production costs averaged $26.34 per bbl.
Product Prices, Royalties and Transportation – Oil Sands Mining and Upgrading
($/bbl) (1)
SCO sales price (2) (3)
Bitumen value for royalty purposes (4)
Bitumen royalties (5)
Transportation
2017
63.98
41.05
1.64
1.54
$
$
$
$
2016
58.59
27.57
0.54
1.77
$
$
$
$
2015
61.39
32.14
1.08
1.81
$
$
$
$
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) The realized sales price for 2017 reflects the weighted average price of Horizon SCO and AOSP SCO while the realized sales price for 2016 and 2015 reflects the Horizon SCO price only.
The Horizon realized sales price reflects a premium light sweet SCO compared to the blend at AOSP.
(3) Net of blending and feedstock costs.
(4) Calculated as the annual average of the bitumen valuation methodology price.
(5) Calculated based on bitumen royalties expensed during the year; divided by the corresponding SCO sales volumes.
The realized SCO sales price for the Oil Sands Mining and Upgrading segment averaged $63.98 per bbl for 2017, an increase of 9% compared with
$58.59 per bbl for 2016 (2015 – $61.39 per bbl). The increase in SCO pricing for 2017 compared to 2016 primarily reflected higher WTI benchmark
pricing, together with the impact of new AOSP SCO sales volumes.
The SCO sales price for 2017 reflected an average realized price at Horizon of $67.74 per bbl and an average realized price at AOSP of $58.30 per bbl
for 2017.
Cash Production Costs – Oil Sands Mining and Upgrading
The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 21 to the Company’s audited consolidated
financial statements.
($ 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.
$
$
$
$
$
$
2017
2016
2,600
$
1,292
$
(216)
2,384
2,239
145
$
$
(151)
1,141
1,057
84
$
$
2,384
$
1,141
$
2017
2016
21.98
$
23.36
$
1.42
1.84
23.40
$
25.20
$
2015
1,332
(45)
1,287
1,212
75
1,287
2015
26.95
1.66
28.61
279,084
123,652
123,231
Adjusted cash production costs for 2017 decreased 7% to $23.40 per bbl from $25.20 per bbl for 2016 (2015 – $28.61 per bbl). The decrease in
adjusted cash production costs per barrel for 2017 from 2016 primarily reflected the Company's continuous focus on cost control and efficiencies
and high utilization rates and reliability, together with additional capacity from new Phase 2B and Phase 3 production at Horizon, partially offset by
the impact of the acquisition of AOSP. For 2018, Oil Sands Mining and Upgrading cash production costs, including turnaround costs, are anticipated to
average $22.50 to $26.50 per bbl.
Horizon adjusted cash production costs for 2017 decreased 15% to $21.46 per bbl from $25.20 per bbl for 2016 (2015 – $28.61 per bbl). Cash production
costs of $24.98 per bbl for 2017, including turnaround costs, were within the Company's previously issued guidance of $24.00 to $27.00 per bbl.
AOSP annualized cash production costs for 2017 averaged $26.34 per bbl, reflecting high reliability of operations. Cash production costs for 2017 were
below the Company's previously issued guidance of $27.00 to $31.00 per bbl.
36
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Depletion, Depreciation and Amortization – Oil Sands Mining and Upgrading
($ millions, except per bbl amounts)
Depletion, depreciation and amortization
Less: depreciation incurred during turnaround period
Adjusted depletion, depreciation and amortization
$/bbl (1)
(1) Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods.
2017
2016
1,220
$
662
$
(213)
1,007
9.89
$
$
(99)
563
12.43
$
$
2015
562
(5)
557
12.37
$
$
$
Adjusted depletion, depreciation and amortization expense per barrel for 2017 decreased 20% to $9.89 per bbl from $12.43 per bbl for 2016
(2015 – $12.37 per bbl), primarily due to the impact of AOSP, which has a lower depletion rate.
Asset Retirement Obligation Accretion – Oil Sands Mining and Upgrading
($ millions, except per bbl amounts)
Expense
$/bbl (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2017
48
0.47
$
$
2016
29
0.64
$
$
2015
31
0.69
$
$
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of
time. The increase in asset retirement obligation accretion expense in 2017 reflected the acquisition of AOSP.
Asset retirement obligation accretion expense per barrel for 2017 decreased 27% to $0.47 per bbl from $0.64 per bbl for 2016, reflecting added sales
volumes from AOSP (2015 – $0.69 per bbl).
Midstream
($ millions)
Revenue
Production expense
Midstream cash flow
Depreciation
Equity (gain) loss from Redwater Partnership
Gain on disposition and revaluation of properties
Segment earnings before taxes
2017
2016
2015
$
102
$
114
$
16
86
9
(31)
(114)
25
89
11
(7)
(218)
$
222
$
303
$
136
32
104
12
44
—
48
During 2017, the Company recorded a pre-tax revaluation gain of $114 million ($83 million after-tax) related to a previously held joint interest in a
pipeline system. 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 and after-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 consist of two crude oil pipeline systems, a
50% working interest in an 84-megawatt cogeneration plant at Primrose and the Company's 50% interest in the Redwater Partnership. Approximately
50% of the Company's heavy crude oil production is transported to international mainline liquid pipelines via the 100% owned and operated ECHO
and Pelican Lake pipelines. 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.
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.
37
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT The facility capital cost (“FCC”) budget for the Project is currently estimated to be $9,500 million with project completion targeted for third quarter
2018. Productivity challenges during construction have continued to result in upward budgetary pressures that may result in a further increase in
FCC of up to 2%. During 2013, the Company and APMC agreed, each with a 50% interest, to provide subordinated debt, bearing interest at prime
plus 6%, as required for Project costs to reflect an agreed debt to equity ratio of 80/20. To December 31, 2017, each party has provided $411 million
of subordinated debt, together with accrued interest thereon of $99 million, for a Company total of $510 million. Any additional subordinated debt
financing is not expected to be significant.
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.
During 2017, Redwater Partnership issued $750 million of 2.80% series J senior secured bonds due June 2027 and $750 million of 3.65% series K
senior secured bonds due June 2035.
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, 2017, Redwater Partnership had additional borrowings of $1,870 million under its secured $3,500 million syndicated credit facility,
maturing June 2018. Subsequent to December 31, 2017, Redwater Partnership extended $2,000 million of the $3,500 million revolving syndicated
credit facility to June 2021. The remaining $1,500 million was extended on a fully drawn non-revolving basis maturing February 2020.
Administration Expense
($ millions, except per BOE amounts)
Expense
$/BOE (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2017
319
0.91
$
$
2016
345
1.17
$
$
2015
390
1.26
$
$
Administration expense per BOE for 2017 decreased 22% to $0.91 per BOE from $1.17 per BOE for 2016 (2015 – $1.26 per BOE). Administration expense
per BOE decreased for 2017 from 2016 primarily due to higher overhead recoveries and higher sales volumes.
Share-Based Compensation
($ millions)
Expense (recovery)
2017
2016
$
134
$
355
$
2015
(46)
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 $134 million share-based compensation expense for the year ended December 31, 2017, 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. Included within share-based
compensation expense for 2017 was $5 million (2016 – $nil; 2015 – $nil) related to performance share units granted to certain executive employees.
For 2017, the Company charged $14 million of share-based compensation costs to the Oil Sands Mining and Upgrading segment (2016 – $67 million
costs charged, 2015 – $10 million costs recovered).
Interest and Other Financing Expense
($ millions, except per BOE amounts and interest rates)
Expense, gross
Less: capitalized interest
Expense, net
$/BOE (1)
Average effective interest rate
(1) Amounts expressed on a per unit basis are based on sales volumes.
$
$
$
2017
713
$
82
631
1.79
3.8%
$
$
2016
616
233
383
1.30
3.9%
$
$
$
2015
566
244
322
1.04
3.9%
Gross interest and other financing expense for 2017 increased from 2016 primarily due to the impact of higher average debt levels as a result of
acquisitions completed in 2017. Capitalized interest of $82 million for 2017 was related to the Horizon Phase 3 expansion and the Kirby North project.
38
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Net interest and other financing expense for 2017 increased 38% to $1.79 per BOE from $1.30 per BOE for 2016 (2015 – $1.04 per BOE). The increase
for 2017 from 2016 was primarily due to higher average debt levels as a result of acquisitions completed in 2017 and lower capitalized interest related
to the completion of Horizon Phase 2B and Phase 3.
The Company’s average effective interest rate of 3.8% for 2017 was consistent with 2016.
Risk Management Activities
The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These
derivative financial instruments are not intended for trading or speculative purposes.
($ millions)
Crude oil and NGLs financial instruments
Natural gas financial instruments
Foreign currency contracts
Realized (gain) loss
Crude oil and NGLs financial instruments
Natural gas financial instruments
Foreign currency contracts
Unrealized loss
Net loss (gain)
2017
2016
(32) $
— $
(7)
37
(2) $
—
8
8
$
— $
— $
(6)
43
37
35
$
$
6
19
25
33
$
$
2015
(599)
—
(244)
(843)
394
—
(20)
374
(469)
$
$
$
$
$
During 2017, net realized risk management gains were related to the settlement of crude oil price collars and natural gas AECO swaps, offset by the
settlement of foreign currency contracts. The Company recorded a net unrealized loss of $37 million ($33 million after-tax) on its risk management
activities for 2017 (2016 – $25 million unrealized loss, $21 million after-tax; 2015 – $374 million unrealized loss, $275 million after-tax).
Complete details related to outstanding derivative financial instruments at December 31, 2017 are disclosed in note 18 to the Company's consolidated
financial statements.
Foreign Exchange
($ millions)
Net realized loss (gain)
Net unrealized (gain) loss
Net (gain) loss (1)
2017
34
$
(821)
(787) $
2016
38
$
(93)
(55) $
2015
(97)
858
761
$
$
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange loss for 2017 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 2017 was primarily related to the impact of a stronger
Canadian dollar with respect to outstanding US dollar debt. The net unrealized (gain) loss for each of the periods presented included the impact of cross
currency swaps (2017 – unrealized loss of $280 million, 2016 – unrealized loss of $295 million, 2015 – unrealized gain of $649 million). The US/Canadian
dollar exchange rate at December 31, 2017 was US$0.7988 (December 31, 2016 – US$0.7448, December 31, 2015 – US$0.7225).
39
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Income Taxes
($ millions, except income tax rates)
North America (1)
North Sea
Offshore Africa
PRT – North Sea
Other taxes
Current income tax recovery
Deferred corporate income tax expense (recovery)
Deferred PRT expense (recovery) – North Sea
Deferred income tax expense (recovery)
Income tax rate and other legislative changes (2)
2017
2016
$
(145) $
(377) $
57
45
(132)
11
(164)
586
54
640
476
(10)
(74)
22
(198)
9
(618)
(106)
(135)
(241)
(859)
221
Effective income tax rate on adjusted net earnings (loss) from operations (3)
27%
45%
$
466
$
(638) $
2015
86
(117)
17
(258)
11
(261)
216
15
231
(30)
(351)
(381)
61%
Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments.
(1)
(2) During 2017, the British Columbia government enacted legislation that increased the provincial corporate income tax rate from 11% to 12% effective January 1, 2018. As a result of
this income tax rate increase, the Company's deferred corporate income tax liability was increased by $10 million. 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.
The UK government also enacted tax rate reductions relating to 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 2017 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 corporate income tax and PRT recoveries in the North Sea in 2017 and the comparable years included the impact of
abandonment expenditures.
During 2017, the British Columbia government enacted legislation that increased the provincial corporate income tax rate from 11% to 12% effective
January 1, 2018. As a result of this income tax rate increase, the Company's deferred corporate income tax liability was increased by $10 million.
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. In addition, 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 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 corporate 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 also 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 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 reported results of operations, financial position or liquidity.
For 2018, the Company expects to recognize current income tax expense ranging from $300 million to $400 million in Canada and recoveries of $nil to
$40 million in the North Sea and Offshore Africa.
During 2017, the Company filed Scientific Research and Experimental Development claims of approximately $345 million (2016 – $549 million;
2015 – $527 million) relating to qualifying research and development expenditures for Canadian income tax purposes.
40
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Net Capital Expenditures (1)
($ millions)
Exploration and Evaluation
Net expenditures (proceeds) (2) (3) (4)
Property, Plant and Equipment
Net property acquisitions (dispositions) (2) (3) (4) (5)
Well drilling, completion and equipping
Production and related facilities
Capitalized interest and other (6)
Net expenditures
Total Exploration and Production
Horizon Oil Sands Mining and Upgrading
Horizon Phases 2/3 construction costs
Sustaining capital
Turnaround costs
Capitalized interest and other (6)
Total Horizon Oil Sands Mining and Upgrading
Athabasca Oil Sands Project
Acquisitions of Exploration and Evaluation assets (2) (4)
Net property acquisitions (2) (4)
Sustaining capital
Turnaround costs
Total Athabasca Oil Sands Project
Total Oil Sands Mining and Upgrading
Midstream (7)
Abandonments (8)
Head office
Total net capital expenditures
By segment
North America (2) (3) (4) (5)
North Sea
Offshore Africa
Oil Sands Mining and Upgrading (4)
Midstream (7)
Abandonments (8)
Head office
Total
2017
2016
2015
$
149
$
(6) $
(805)
1,219
1,001
860
91
3,171
3,320
821
419
149
76
1,465
219
11,604
142
6
11,971
13,436
80
274
19
159
712
369
91
1,331
1,325
1,920
379
135
284
2,718
—
—
—
—
—
2,718
(533)
267
17
(451)
965
908
102
1,524
719
2,187
301
18
224
2,730
—
—
—
—
—
2,730
8
370
26
$
$
17,129
$
3,794
$
3,853
3,056
$
1,048
$
(119)
160
104
13,436
80
274
19
126
151
2,718
(533)
267
17
230
608
2,730
8
370
26
$
17,129
$
3,794
$
3,853
(1) Net capital expenditures exclude adjustments related to fair value and revaluation adjustments, and include non-cash transfers of property, plant and equipment to inventory due to
change in use.
Includes Business Combinations.
Includes proceeds from the Company’s disposition of properties.
(2)
(3)
(4) Total purchase consideration for the acquisition of interests in AOSP of $12,157 million includes $26 million of exploration and evaluation assets and $308 million of property, plant and
equipment within the North America segment, and $219 million of exploration and evaluation assets and $11,604 million of property, plant and equipment within the Oil Sands Mining
and Upgrading segment in 2017.
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)
(6) Capitalized interest and other includes expenditures related to land acquisition and retention, seismic, and other adjustments.
(7)
(8) Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table.
Includes non-cash share consideration of $190 million received from Inter Pipeline on the disposition of Midstream assets in 2016.
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.
41
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Net capital expenditures for 2017 were $17,129 million compared with $3,794 million for 2016 (2015 – $3,853 million). Net capital expenditures for 2017
included $12,157 million related to the acquisition of AOSP and other assets and $921 million related to the acquisition of assets in the Greater Pelican
Lake region and other miscellaneous assets.
On November 7, 2017 the Company announced its 2018 Capital Budget. The budget reflects the Company's transition to a long life low decline asset
base with a focus on reliability across the asset base and the continued integration and optimization of assets acquired in 2017. The 2018 budget is
targeted at $4,335 million.
DRILLING ACTIVITY
(number of wells)
Net successful natural gas wells
Net successful crude oil wells (1)
Dry wells
Stratigraphic test / service wells
Total
Success rate (excluding stratigraphic test / service wells)
(1)
Includes bitumen wells.
NORTH AMERICA
2017
21
495
7
289
812
99%
2016
9
174
7
268
458
96%
2015
19
115
6
166
306
96%
North America, excluding Oil Sands Mining and Upgrading, accounted for approximately 19% of the total net capital expenditures for 2017 compared
with approximately 20% for 2016 (2015 – 1%).
During 2017, the Company targeted 22 net natural gas wells, including 7 wells in Northeast British Columbia, 14 wells in Northwest Alberta and
1 well in Northern Plains. The Company also targeted 499 net crude oil wells. The majority of these wells were concentrated in the Company's
Northern Plains region where 415 primary heavy crude oil wells, 17 Pelican Lake heavy crude oil wells, 27 bitumen (thermal oil) wells and 2 light crude
oil wells were drilled. Another 38 wells targeting light crude oil were drilled outside the Northern Plains region.
Overall thermal oil production for 2017 averaged approximately 120,100 bbl/d compared with approximately 111,000 bbl/d for 2016
(2015 – 129,800 bbl/d). Production volumes in 2017 reflected strong thermal oil production following the successful turnarounds at Primrose and Kirby
South plants in 2017 and added production volumes as a result of the acquisition of other assets on May 31, 2017.
Operating performance at the Pelican Lake tertiary recovery project continued to be strong, leading to average production of approximately
51,700 bbl/d in 2017 compared with 47,600 bbl/d in 2016 (2015 – 50,800 bbl/d).
HORIZON OIL SANDS MINING AND UPGRADING
During the fourth quarter of 2017, Horizon Phase 3 expansion work was completed on schedule and within budget. Phase 3 activities included the
expansion tie-in and commissioning of the production plant.
The Phase 2/3 expansion program is essentially complete with residual scope remaining related to Mature Fine Tailings ("MFT") and mine basal water.
NORTH SEA
During 2017, the Company completed two injection wells (1.8 on a net basis) and two production wells (1.8 on a net basis) at Ninian. The Company also
completed all of the heavy lifts at the Murchison platform, ceased production at the Ninian North field and commenced well plugging and abandonment
activities. Abandonment activities are currently on schedule and within budget.
OFFSHORE AFRICA
During 2017, the Company successfully completed the 18 day turnaround at Baobab ahead of schedule.
42
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Liquidity and Capital Resources
($ millions, except ratios)
Working capital (1)
Long-term debt (2) (3)
Less: cash and cash equivalents
Long-term debt, net
Share capital
Retained earnings
Accumulated other comprehensive (loss) 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)
$
$
$
$
2017
2016
513
$
1,056
$
2015
1,193
22,458
$
16,805
$
16,794
137
17
69
22,321
$
16,788
$
16,725
9,109
$
4,671
$
22,612
(68)
21,526
70
4,541
22,765
75
$
31,653
$
26,267
$
27,381
41%
29%
8%
6%
39%
26%
(1%)
0%
38%
34%
(2%)
(1%)
(1) Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
Includes the current portion of long-term debt (2017 – $1,877 million, 2016 – $1,812 million, 2015 – $1,729 million).
(2)
(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 net current and long-term debt; divided by the book value of common shareholders’ equity plus net current and long-term debt.
(5) Calculated as net current and long-term debt; divided by the market value of common shareholders’ equity plus net 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, 2017, 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. 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;
■■ Utilizing funds flow from operations to facilitate debt reduction. Subsequent to December 31, 2017, the Company:
■●
■●
■●
extended the fully drawn $750 million non-revolving credit facility originally due February 2019 to February 2021 and fully repaid and
cancelled the $125 million non-revolving credit facility;
repaid and cancelled $150 million of the $3,000 million non-revolving term loan facility; and
repaid US$600 million of 1.75% notes and US$400 million of 5.90% notes.
■■
Reviewing the Company's borrowing capacity:
■● During 2017, the Company extended $2,095 million of the $2,425 million revolving syndicated credit facility originally due June 2019 to
June 2021. The remaining $330 million outstanding under this facility continues under the previous terms and matures in June 2019. The other
$2,425 million revolving credit facility matures in June 2020. The revolving credit facilities are 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.
43
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT ■● During 2017, the $1,500 million non-revolving term credit facility was increased to $2,200 million and the maturity date was extended to
October 2019 from April 2018. Borrowings under the $2,200 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, 2017, the
$2,200 million facility was fully drawn.
■●
■●
Borrowings under the $750 million non-revolving term credit facilities may be made by way of pricing referenced to Canadian dollar bankers’
acceptances or Canadian prime loans.
In addition to the credit facilities described above, during 2017 the Company entered into a $3,000 million non-revolving term loan facility
to finance the acquisition of AOSP and other assets. This facility matures in May 2020 and is subject to annual amortization of 5% of the
original balance. Borrowings under the term loan facility may be made by way of pricing referenced to Canadian dollar or US dollar bankers’
acceptances, or LIBOR, US base rate or Canadian prime loans. The facility also supports a US$375 million letter of credit relating to the
deferred purchase consideration payable to Marathon in March 2018. As at December 31, 2017, the $3,000 million facility was fully drawn.
■●
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 this program.
■● During 2017, the Company issued $900 million of 2.05% medium-term notes due June 2020, $600 million of 3.42% medium-term notes
due December 2026 and $300 million of 4.85% medium-term notes due May 2047. Proceeds from the securities were used to finance the
acquisition of AOSP and other assets. In July 2017, the Company filed a new 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 August 2019. 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 2016, the Company issued $1,000 million of 3.31% medium-term notes due February 2022.
■● During 2017, the Company repaid US$1,100 million of 5.70% notes, and issued US$1,000 million of 2.95% notes due January 2023,
US$1,250 million of 3.85% notes due June 2027 and US$750 million of 4.95% notes due June 2047. Proceeds from the debt securities were
used to finance the acquisition of AOSP and other assets. In July 2017, the Company filed a new 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 August 2019. 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 2016, the Company repaid US$250 million of 6.00% notes and US$500 million of three-month LIBOR plus 0.375% notes.
■■
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, and as applicable, taking other mitigating actions to minimize the impact in the event
of a default.
At December 31, 2017, the Company had in place bank credit facilities of $11,050 million, of which approximately $4,112 million was available, resulting
in liquidity of $4,249 million, including cash and cash equivalents. This excludes certain other dedicated credit facilities supporting letters of credit.
At December 31, 2017, the Company had total US dollar denominated debt with a carrying amount of $13,753 million (US$10,989 million),
before transaction costs and original issue discounts. This included $4,239 million (US$3,389 million) hedged by way of cross currency swaps
(US$1,050 million) and foreign currency forwards (US$2,339 million). The fixed repayment amount of these hedging instruments is $4,150 million,
resulting in a notional reduction of the carrying amount of the Company’s US dollar denominated debt by approximately $89 million to $13,664 million
as at December 31, 2017.
Net long-term debt was $22,321 million at December 31, 2017, resulting in a debt to book capitalization ratio of 41% (December 31, 2016 – 39%, December
31, 2015 – 38%); 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, 2017 are discussed in note
10 to the Company’s consolidated financial statements.
The Company periodically utilizes commodity derivative financial instruments under its commodity hedge policy to reduce the risk of volatility in
commodity prices and to support 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 February 28, 2018 the Company had no commodity derivative financial
instruments outstanding.
44
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
SHARE CAPITAL
As at December 31, 2017, there were 1,222,769,000 common shares outstanding (December 31, 2016 – 1,110,952,000 common shares) and
56,036,000 stock options outstanding. As at February 27, 2018, the Company had 1,225,805,000 common shares outstanding and 54,701,000 stock
options outstanding.
On February 28, 2018, the Board of Directors approved an increase in the quarterly dividend to $0.335 per common share, beginning with the dividend
payable on April 1, 2018. 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
$546 million. Subsequent to the distribution, the Company’s ownership interest in PrairieSky was less than 10% of the issued and outstanding common
shares of PrairieSky.
On May 16, 2017, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock
Exchange, alternative Canadian trading platforms, and the New York Stock Exchange, up to 27,931,135 common shares, over a 12 month period
commencing May 23, 2017 and ending May 22, 2018. During 2017, 2016 and 2015 the Company did not purchase any common shares for cancellation.
Commitments and Off Balance Sheet Arrangements
In the normal course of business, the Company has entered into various commitments that will have an impact on the Company’s future operations.
In connection with the acquisition of AOSP and other assets, the Company also assumed certain pipeline and other commitments. The following table
summarizes the Company’s commitments as at December 31, 2017:
($ millions)
Product transportation and pipeline
Offshore equipment operating leases
Long-term debt (1)
Interest and other financing expense (2)
Office leases
Other (3)
2018
680
181
2,027
842
43
87
$
$
$
$
$
$
2019
584
92
4,228
755
42
41
$
$
$
$
$
$
2020
526
70
4,231
638
42
40
$
$
$
$
$
$
$
$
$
$
$
$
2021
482
68
760
561
39
39
$
$
$
$
$
$
2022
422
8
1,000
513
30
43
$
$
$
$
$
$
Thereafter
3,868
—
10,351
5,384
118
333
(1)
(2)
(3)
Long-term debt represents principal repayments only and does not reflect original issue discounts and premiums or transaction costs.
Interest and other financing payments were estimated based upon applicable interest and foreign exchange rates as at December 31, 2017.
In addition to the amounts disclosed above, beginning on the earlier of the commercial operations date of the Redwater 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.
In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and
construction of its various development projects. 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.
45
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Reserves
For the years ended December 31, 2017, 2016 and 2015, 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, 2017,
prepared in accordance with NI 51-101 reserves disclosures:
Proved Reserves
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
Proved Plus
Probable Reserves
December 31, 2016
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2017
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)
389
—
4
4
—
6
—
4
1
(34)
374
187
—
14
7
1
20
—
—
4
(35)
198
264
1,269
2,559
6,617
198
5,969
—
—
—
1
76
—
—
5
—
20
—
—
23
—
—
82
(19)
327
(44)
1,350
—
—
—
—
2,321
—
—
487
(103)
5,264
—
276
191
1
116
—
(30)
207
(607)
6,771
—
15
17
—
1
—
—
13
(15)
229
—
99
60
2
2,467
—
(1)
626
(351)
8,871
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)
619
—
8
7
—
8
—
1
(65)
(34)
544
259
384
2,517
3,604
9,076
284
9,179
—
22
10
1
26
—
—
(11)
(35)
272
—
—
—
2
99
—
—
3
—
39
—
—
50
—
—
18
(19)
469
(44)
2,580
—
—
—
—
2,496
—
—
66
(103)
6,063
—
554
295
1
145
(1)
(29)
185
—
25
26
—
1
—
—
14
—
187
92
3
2,704
—
(3)
55
(607)
9,619
(15)
335
(351)
11,866
At December 31, 2017, the company gross proved crude oil, bitumen (thermal oil), SCO and NGLs reserves totaled 7,742 MMbbl, and company gross
proved plus probable crude oil, bitumen (thermal oil), SCO and NGLs reserves totaled 10,263 MMbbl. Proved reserves additions and revisions replaced
1,250% of 2017 production. Additions to proved reserves resulting from exploration and development activities, acquisitions and future offset additions
amounted to 2,530 MMbbl, and additions to proved plus probable reserves amounted to 2,820 MMbbl. Net positive revisions amounted to 596 MMbbl
for proved reserves and 26 MMbbl for proved plus probable reserves, primarily due to technical revisions.
At December 31, 2017, the company gross proved natural gas reserves totaled 6,771 Bcf, and company gross proved plus probable natural gas
reserves totaled 9,619 Bcf. Proved reserves additions and revisions replaced 125% of 2017 production. Additions to proved reserves resulting from
exploration and development activities, acquisitions and future offset additions amounted to 584 Bcf, and additions to proved plus probable reserves
amounted to 994 Bcf. Net positive revisions amounted to 177 Bcf for proved reserves and 156 Bcf for proved plus probable reserves, primarily due to
technical revisions.
46
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
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, extracting 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 reserves revisions due to economic and technical factors. Reserves revisions can have a positive or negative impact on asset
valuations, ARO and depletion rates;
Reservoir quality and uncertainty of reserves 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;
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;
The risk of significant interruption or failure of the Company's information technology systems and related data and control systems or a significant
breach that could adversely affect the Company's operations; 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 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, and
as applicable, taking other mitigating actions to minimize the impact in the event of a default. Derivative financial instruments are periodically
47
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT utilized to help ensure targets are met and to manage commodity price, foreign currency and interest rate exposures. The Company is exposed to
possible losses in the event of non-performance by counterparties to derivative financial instruments; however, the Company manages this credit
risk by entering into agreements with counterparties that are substantially all investment grade financial institutions. The arrangements and policies
concerning the Company’s financial instruments are under constant review and may change depending upon the prevailing market conditions.
The Company has implemented cyber security protocols and procedures to reduce the risk of failure or a significant breach of the Company’s
information technology systems and related data and control systems.
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, 2017.
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. The Company believes that it meets all existing environmental standards and regulations and has included appropriate amounts
in its capital expenditure budget to continue to meet current environmental protection requirements. Increasingly stringent laws and
regulations may have an adverse effect on the Company’s future net earnings.
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 to preserve high value diversity. The Company’s environmental risk management
strategies employ an Environmental Management Plan (the “Plan”). Details of the Plan, along with performance results, are presented to,
and reviewed by, the Board of Directors quarterly.
The Company’s Plan and operating guidelines focus on minimizing the impact of operations while meeting regulatory requirements, regional
management frameworks for air, water and biodiversity, industry operating standards and guidelines, and internal corporate standards.
Training and due diligence for operators and contractors is key to the effectiveness of the Company’s environmental management programs and the
prevention of incidents to protect the environment. 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 through biodiversity protection
and restoration 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, and the Quest carbon
capture and storage facility as part of AOSP;
■■ A program in place related to progressive reclamation and tailings management in Oil Sands Mining and Upgrading including low fines mining;
■■
Participation and support for the Joint Oil Sands Monitoring Program; and
■■ Wildlife monitoring and mitigation plans to help maintain biodiversity, as well as mitigation and restoration programs targeted specifically at
boreal caribou.
48
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and have
been discounted using a weighted average discount rate of 4.7% (2016 – 5.2%; 2015 – 5.9%). For 2017, the Company’s capital expenditures
included $274 million for abandonment expenditures (2016 – $267 million; 2015 – $370 million). The Company’s estimated discounted ARO at
December 31, 2017 was as follows:
($ millions)
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream
2017
2016
$
1,840
$
1,444
755
245
1,486
1
837
244
717
1
$
4,327
$
3,243
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. The Company’s integrated GHG emissions
reduction strategy includes: 1) integrating emission reduction in project planning and operations; 2) leveraging technology to create value and enhance
performance; 3) investing in research and development and supporting collaboration; 4) focusing on continuous improvement to drive long-term
emissions reduction; 5) leading in carbon capture and sequestration/storage; 6) engaging proactively in policy and regulatory development (including
trading capacity and offsetting emissions); and, 7) considering and developing new business opportunities and trends.
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 40-45% 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 engines operated by the Company. The federal government is also developing a Clean Fuel
Standard which may affect production and consumption of fuels in Canada. Effective January 1, 2017, the Alberta government implemented increases
in both the carbon price and stringency of the existing large-emitter regulatory system. The Alberta government has introduced additional changes
to this system beginning in 2018, 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 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. The carbon
price in Alberta is currently $30/tonne for emissions above the regulated limits. Seven of the Company’s operated facilities (the Horizon and Athabasca
oil sands facilities, the Primrose/Wolf Lake in situ heavy crude oil facilities, the Kirby South in situ heavy crude oil facility, the Peace River in situ heavy
crude oil facility, the Hays sour natural gas plant, and the Wapiti gas plant) are subject to compliance under the regulation. The non-operated Scotford
Upgrader is also subject to compliance under the regulations. The non-operated North West Redwater bitumen upgrader and refinery will not be subject
to a reduction target until 2019. In British Columbia, carbon tax is currently being assessed at $30/tonne of CO2e on fuel consumed and gas flared
in the province, with the rate increasing to $35/tonne on April 1, 2018. The British Columbia Government will be increasing the carbon tax at a rate
of $5 per tonne of CO2e annually to $50 per tonne of CO2e on April 1, 2021. The Saskatchewan government has released a Climate Change Strategy
that will regulate facilities emitting more than 25 kilotonnes of CO2e annually and will likely require the North Tangleflags in situ heavy oil facility and
the Senlac in situ heavy oil facility to meet reduction targets for GHG emissions once the governing legislation comes into force. The Saskatchewan
strategy also includes measures that will regulate GHG emissions (including methane) at facilities below the 25 kilotonne/year threshold. 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.
49
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Air pollutant standards and guidelines are being developed federally and provincially and the Company is participating in these discussions.
Ambient air quality and sector based reductions in air emissions are being reviewed. Through Company and industry participation with stakeholders,
guidelines are being developed that adopt a structured process to emission reductions that is commensurate with technological development and
operational requirements.
Critical Accounting Policies and Estimates
The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the application of IFRS that have a
significant impact on the financial results of the Company. Actual results may 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, 2017.
A)
DEPLETION, DEPRECIATION AND AMORTIZATION AND IMPAIRMENT
Exploration and evaluation (“E&E”) costs relating to activities to explore and evaluate crude oil and natural gas properties are initially capitalized
and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and
evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E assets are carried forward until technical
feasibility and commercial viability of extracting a mineral resource is determined. Technical feasibility and commercial viability of extracting a mineral
resource is considered to be determined when an assessment of proved reserves is made. The judgements associated with the estimation of proved
reserves are described below in “Crude Oil and Natural Gas Reserves”.
An alternative acceptable accounting method for E&E costs under IFRS 6 “Exploration for and Evaluation of Mineral Resources” is to charge exploratory
dry holes and geological and geophysical exploration costs incurred after having obtained the legal rights to explore an area against net earnings in the
period incurred rather than capitalizing to E&E assets.
E&E assets are tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable
amount, by comparing the relevant costs to the fair value of related Cash Generating Units (“CGUs”), aggregated at a 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 10% 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
Reserves estimates are based on engineering data, estimated future prices and production costs, expected future rates of production,
and the timing and amount of future development expenditures, all of which are subject to many uncertainties, interpretations and judgements.
The Company expects that, over time, its reserves estimates will be revised upward or downward based on updated information. Reserves 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 reserves estimates would result in a higher or lower depletion,
depreciation and amortization charge to net earnings. Downward revisions to reserves 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
50
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT 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 4.7%. 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 amount of assets and liabilities in the consolidated financial
statements and their respective tax bases, using income tax rates substantively enacted as at the date of the balance sheet. Accounting for income
taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements
with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. There
are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes 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 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 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 crude oil and natural gas properties. To determine the fair value of these properties, the
Company estimates crude oil and natural gas reserves. Reserves 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.
51
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Accounting Standards Issued But Not Yet Applied
In October 2017, the IASB issued amendments to IAS 28 “Investments in Associates and Joint Ventures” to clarify that the impairment provisions
in IFRS 9 apply to financial instruments in an associate or joint venture that are not accounted for using the equity method, including long-term
interests that form part of the net investment in the associate or joint venture. The amendments are effective January 1, 2019 with earlier adoption
permitted. The amendments are required to be adopted retrospectively. The Company is assessing the impact of the amendments on its consolidated
financial statements.
In June 2017, the IASB issued IFRIC 23 "Uncertainty over Income Tax Treatments". The interpretation provides guidance on how to reflect the effects
of uncertainty in accounting for income taxes where IAS 12 is unclear. The interpretation is effective January 1, 2019. The Company is assessing the
impact of this interpretation on its consolidated financial statements.
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.
IFRS 15 "REVENUE FROM CONTRACTS WITH CUSTOMERS"
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.
Effective January 1, 2018, the Company retrospectively adopted IFRS 15. Adoption of the new standard did not have a significant impact on the
Company’s recognition and measurement of revenue; however, it will require certain additional disclosures.
Upon adoption of IFRS 15, the Company applied the practical expedient such that contracts that were completed in the comparative periods have not
been restated.
IFRS 9 "FINANCIAL INSTRUMENTS"
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 and are required to be adopted retrospectively.
Effective January 1, 2018, the Company adopted the amendment to IFRS 9 and elected to apply the limited exemption in IFRS 9 relating
to transition for impairment. Adoption of the amendment did not have a significant impact on the Company’s previous accounting
for impairment of financial assets.
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, 2017, 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, 2017, 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
2017 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.
52
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Outlook
The Company continues to implement its strategy of maintaining a large portfolio of varied projects, which the Company believes will enable it, over
an extended period of time, to provide consistent growth in production and create shareholder value. Annual budgets are developed, scrutinized
throughout the year and revised if necessary in the context of targeted financial ratios, project returns, product pricing expectations, and balance in
project risk and time horizons. The Company maintains a high ownership level and operatorship level in all of its properties and can therefore control
the nature, timing and extent of capital expenditures in each of its project areas.
Capital expenditures in 2018 are currently targeted to be as follows:
($ 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
Environment, technology and project development
Sustaining capital
Turnarounds, reclamation and other
Total Oil Sands Mining and Upgrading
Total
$
2018
440
1,115
410
960
30
$
2,955
500
660
220
1,380
4,335
$
$
Sensitivity Analysis
The following table is indicative of the annualized sensitivities of funds flow from operations and net earnings (loss) due to changes in certain key
variables. The analysis is based on business conditions and sales volumes during the fourth quarter of 2017, 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)
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)
$
$
$
$
248
33
127
1
$ 133 – 137
$
47
$
$
$
$
$
$
0.21
0.03
$
$
0.11
$
— $
227
33
$
$
98
$
— $
0.12
0.04
$
$
17
47
$
$
0.19
0.03
0.08
—
0.01
0.04
(1)
For details of financial instruments in place, refer to note 18 to the Company’s consolidated financial statements as at December 31, 2017.
53
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
Daily Production By Segment, Before Royalties
Crude oil and NGLs (bbl/d)
North America – Exploration and Production
North America – Oil Sands Mining
and Upgrading
North Sea
Offshore Africa
Total
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Total
Barrels of oil equivalent (BOE/d)
North America – Exploration and Production
North America – Oil Sands Mining
and Upgrading
North Sea
Offshore Africa
Total
Q1
Q2
Q3
Q4
2017
2016
2015
359,964
332,802
361,216
383,537
359,449
350,958
399,982
192,491
257,541
354,365
321,496
282,026
123,265
122,911
23,042
22,616
26,304
20,480
24,832
18,776
19,548
19,519
23,426
20,335
23,554
26,096
22,216
19,079
598,113
637,127
759,189
744,100
685,236
523,873
564,188
1,613
1,603
1,593
1,596
1,601
1,622
1,663
37
23
37
16
46
25
37
23
39
22
38
31
36
27
1,673
1,656
1,664
1,656
1,662
1,691
1,726
628,671
599,901
626,642
649,473
626,230
621,239
677,270
192,491
257,541
354,365
321,496
282,026
123,265
122,911
29,238
26,507
32,517
23,212
32,487
23,005
25,723
23,402
29,989
24,019
29,913
31,365
28,191
23,529
876,907
913,171
1,036,499
1,020,094
962,264
805,782
851,901
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
2017
2016
2015
$
47.05
$
47.12
$
46.33
$
53.42
$
48.57
$
36.93
$
41.13
2.54
44.51
4.89
14.37
25.25
3.25
0.43
2.82
0.19
1.28
1.35
$
$
$
3.06
44.06
4.83
15.51
23.72
2.97
0.34
2.63
0.12
1.25
1.26
$
$
$
2.81
43.52
5.33
14.71
23.48
2.29
0.33
1.96
0.07
1.22
0.67
$
$
$
2.82
50.60
5.84
15.03
29.73
2.55
0.46
2.09
0.08
1.33
0.68
$
$
$
2.80
45.77
5.24
14.89
25.64
2.76
0.39
2.37
0.11
1.27
0.99
$
$
$
2.61
34.32
3.40
14.10
16.82
2.32
0.33
1.99
0.09
1.18
0.72
$
$
$
2.60
38.53
4.30
15.74
18.49
3.16
0.38
2.78
0.10
1.34
1.34
35.98
$
33.94
$
33.27
$
38.78
$
35.54
$
27.58
$
32.60
2.57
33.41
3.38
11.67
18.36
$
2.67
31.27
3.09
12.11
16.07
$
2.51
30.76
3.36
11.73
15.67
$
2.86
35.92
3.75
12.28
19.89
$
2.66
32.88
3.40
11.95
17.53
$
2.44
25.14
2.21
11.18
11.75
$
2.56
30.04
2.85
12.70
14.49
$
$
$
$
$
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
54
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Per Unit Results – Oil Sands Mining and Upgrading
Crude oil and NGLs ($/bbl)
SCO sales price (1)
Bitumen royalties (2)
Transportation
Adjusted cash production costs (3)
Netback
Q1
Q2
Q3
Q4
2017
2016
2015
$
67.85
$
63.39
$
56.55
$
70.85
$
63.98
$
58.59
$
61.39
1.14
1.17
22.08
43.46
$
1.38
1.32
23.44
37.25
$
1.39
1.61
22.69
30.86
$
2.45
1.88
24.99
41.53
$
1.64
1.54
23.40
37.40
$
0.54
1.77
25.20
31.08
$
1.08
1.81
28.61
29.89
$
(1) The realized sales price for 2017 reflects the weighted average price of Horizon SCO and AOSP SCO while the realized sales price for 2016 and 2015 reflects the Horizon SCO price only.
The Horizon realized sales price reflects a premium light sweet SCO compared to the blend at AOSP.
(2) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes.
(3) Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods.
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
2017
2016
176,219
142,680
144,852
124,671
588,422
653,727
$
$
$
$
$
$
44.84
37.34
43.54
$
$
$
45.94
36.44
37.42
$
$
$
42.88
35.90
41.79
$
$
$
47.00
40.62
44.92
$
$
$
$
47.00
35.90
44.92
54,927
$
$
$
$
46.74
21.27
42.79
47,538
1,222,769
1,110,952
205,031
153,928
130,936
118,113
608,008
892,220
33.39
28.39
32.79
$
$
$
34.31
27.53
28.84
$
$
$
34.48
27.88
33.49
$
$
$
36.78
32.11
35.72
$
$
$
$
36.78
27.53
35.72
43,677
$
$
$
$
35.28
14.60
31.88
35,417
1,222,769
1,110,952
55
CANADIAN NATURAL 2017 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, 2017; and
the effectiveness of the Company’s internal control over financial reporting as at December 31, 2017.
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
MURRAY G. HARRIS, CA
Chief Financial Officer and
Senior Vice-President, Finance
Vice-President, Financial Controller
and Horizon Accounting
Calgary, Alberta, Canada
February 28, 2018
56
CANADIAN NATURAL 2017 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, 2017. 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, 2017, as stated in their accompanying Report of Independent Registered Public Accounting Firm.
STEVE W. LAUT
President
Calgary, Alberta, Canada
February 28, 2018
COREY B. BIEBER, CA
Chief Financial Officer and
Senior Vice-President, Finance
57
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Canadian Natural Resources Limited
OPINIONS ON THE FINANCIAL STATEMENTS AND INTERNAL CONTROL OVER FINANCIAL REPORTING
We have audited the accompanying consolidated balance sheets of Canadian Natural Resources Limited (the "Company") as of December 31, 2017
and December 31, 2016, and the related 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, 2017, including the related notes (collectively referred to as the "consolidated financial
statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO").
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as
of December 31, 2017 and December 31, 2016 and its financial performance and its cash flows for each of the three years in the period ended December
31, 2017 in conformity with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Also
in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on
criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
BASIS FOR OPINIONS
The Company's management is responsible for these consolidated financial statements, 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. Our responsibility is to express opinions on the Company's consolidated financial statements
and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company
Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. These standards require that we plan and perform the audits to obtain
reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and
whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risk of material misstatement of the consolidated
financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining,
on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the
accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial
statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits
provided a reasonable basis for our opinions.
58
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT DEFINITION AND LIMITATIONS 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 consolidated 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 consolidated financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorization 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 consolidated financial statements.
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.
Chartered Professional Accountants
Calgary, Canada
February 28, 2018
We have served as the Company's auditor since 1973.
59
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Note
2017
2016
$
137
$
2,397
322
894
175
893
79
4,897
2,632
65,170
1,168
$
73,867
$
$
775
$
2,597
1,877
1,012
6,261
20,581
4,397
10,975
42,214
9,109
22,612
(68)
31,653
$
73,867
$
4
8
9
5
6
9
10
11
10
11
12
13
14
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
CONSOLIDATED BALANCE SHEETS
As at December 31
(millions of Canadian dollars)
ASSETS
Current assets
Cash and cash equivalents
Accounts receivable
Current income taxes receivable
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 (loss)
Commitments and contingencies (note 19).
Approved by the Board of Directors on February 28, 2018
CATHERINE M. BEST
N. MURRAY EDWARDS
Chair of the Audit
Committee and Director
Executive Chairman of the Board of
Directors and Director
60
CANADIAN NATURAL 2017 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, blending and feedstock
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 acquisition, disposition and revaluation of properties
(Gain) loss from investments
Earnings (loss) before taxes
Current income tax recovery
Deferred income tax expense (recovery)
Net earnings (loss)
Net earnings (loss) per common share
Basic
Diluted
Note
2017
2016
$
17,669
$
11,098
$
(1,018)
16,651
(575)
10,523
5,596
2,917
5,186
319
134
164
631
35
(787)
(379)
(38)
13,778
2,873
(164)
640
4,099
2,003
4,858
345
355
142
383
33
(55)
(250)
(327)
11,586
(1,063)
(618)
(241)
5, 6
11
11
17
18
5, 6, 7
8, 9
12
12
$
2,397
$
(204) $
16 $
16 $
2.04
2.03
$
$
(0.19) $
(0.19) $
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
(637)
(0.58)
(0.58)
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 income (loss), net of taxes of $9 million (2016 – $3 million, 2015 – $2 million)
Reclassification to net earnings (loss), net of taxes of $5 million (2016 – $2 million,
2015 – $2 million)
Foreign currency translation adjustment
Translation of net investment
Other comprehensive income (loss), net of taxes
Comprehensive income (loss)
2017
2016
$
2,397
$
(204) $
2015
(637)
53
(33)
20
(158)
(138)
(18)
(13)
(31)
26
(5)
(23)
(13)
(36)
60
24
$
2,259
$
(209) $
(613)
61
CANADIAN NATURAL 2017 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 for the acquisition of AOSP and other assets (1)
Issued upon exercise of stock options
Previously recognized liability on stock options exercised for common shares
Return of capital on PrairieSky Royalty Ltd. share distribution
Balance – end of year
Retained earnings
Balance – beginning of year
Net earnings (loss)
Dividends on common shares
Balance – end of year
Accumulated other comprehensive income (loss)
Balance – beginning of year
Other comprehensive income (loss), net of taxes
Balance – end of year
Shareholders’ equity
Note
13
7, 13
$
8
13
14
2017
4,671
3,818
466
154
—
9,109
21,526
2,397
(1,311)
22,612
70
(138)
(68)
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
$
31,653
$
26,267
$
27,381
(1) During 2017, in connection with the acquisition of direct and indirect interests in the Athabasca Oil Sands Project ("AOSP") and other assets, the Company issued non-cash share
consideration of $3,818 million. See note 7.
62
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31
(millions of Canadian dollars)
Operating activities
Net earnings (loss)
Non-cash items
Depletion, depreciation and amortization
Share-based compensation
Asset retirement obligation accretion
Unrealized risk management loss
Unrealized foreign exchange (gain) loss
(Gain) loss from investments
Deferred income tax expense (recovery)
Gain on acquisition, disposition and revaluation of properties
Current income tax on disposition of properties
Other
Abandonment expenditures
Net change in non-cash working capital
Financing activities
Issue of bank credit facilities and commercial paper, net
Issue of medium-term notes, net
Issue (repayment) of US dollar debt securities, net
Issue of common shares on exercise of stock options
Dividends on common shares
Net change in non-cash working capital
Investing activities
Net (expenditures) proceeds on exploration and evaluation assets (1)
Net expenditures on property, plant and equipment (1) (2)
Acquisition of AOSP and other assets, net of cash acquired (3)
Current income tax on disposition of properties
Investment in other long-term assets
Net change in non-cash working capital
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents – beginning of year
Cash and cash equivalents – end of year
Interest paid, net
Income taxes (received) paid
Note
2017
2016
2015
$
2,397
$
(204) $
(637)
5,186
4,858
134
164
37
(821)
(11)
640
(379)
—
(110)
(274)
299
7,262
2,222
1,791
2,733
466
(1,252)
—
5,960
(124)
(4,574)
(8,630)
—
(87)
313
8, 9
5, 6, 7
20
10, 20
10, 20
10, 20
20
20
20
7
20
355
142
25
(93)
(299)
(241)
(250)
—
(32)
(267)
(542)
5,483
(46)
173
374
858
55
231
(739)
33
(22)
(370)
239
3,452
5,632
342
998
(834)
559
(758)
—
307
6
(3,803)
—
—
(99)
85
970
107
—
91
(1,251)
(40)
(123)
236
(4,704)
—
(33)
(112)
(852)
(13,102)
(3,811)
(5,465)
120
17
137
725
$
$
(52)
69
17
617
$
$
(792) $
(444) $
44
25
69
541
42
$
$
$
(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.
(3) The acquisition of AOSP in 2017 includes net working capital of $291 million and excludes non-cash share consideration of $3,818 million. See note 7.
63
CANADIAN NATURAL 2017 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 "Oil Sands Mining and Upgrading" segment produces synthetic crude oil through bitumen mining and upgrading operations at Horizon Oil Sands
("Horizon") and through the Company's direct and indirect interest in the Athabasca Oil Sands Project ("AOSP").
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 determined that it 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 determined that it 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 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.
64
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT (E)
EXPLORATION AND EVALUATION ASSETS
Exploration and evaluation (“E&E”) assets consist of the Company’s crude oil and natural gas exploration projects that are pending the determination
of proved reserves.
E&E costs are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic
acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E costs do
not include general prospecting or evaluation costs incurred prior to having obtained the legal rights to explore an area. These costs are recognized
in net earnings.
Once the technical feasibility and commercial viability of E&E assets are determined and a development decision is made by management, the E&E
assets are tested for impairment upon reclassification to property, plant and equipment. The technical feasibility and commercial viability of extracting
a mineral resource is considered to be determined when an assessment of proved reserves is made. An E&E asset is derecognized upon disposal or
when no future economic benefits are expected to arise from its use. Any gain or loss arising on derecognition of the asset is recognized in net earnings
within depletion, depreciation and amortization.
E&E assets are also tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable
amount, by comparing the relevant costs to the fair value of the related Cash Generating Units (“CGUs”), aggregated at a 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 proved reserves. Costs of the upgraders and related infrastructure
located on the Horizon and AOSP sites are depreciated on the unit-of-production method based on the estimated productive capacity of the respective
upgraders and related infrastructure. Other equipment is depreciated on a straight-line basis over its estimated useful life ranging from 2 to 18 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.
65
CANADIAN NATURAL 2017 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 CGUs 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, depreciation and amortization, 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, depreciation and amortization 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 and AOSP 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.
66
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT (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 sheets. Subsequent to the initial measurement, the obligation is adjusted to reflect the passage of time, changes in credit adjusted
interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is
recognized as asset retirement obligation accretion expense whereas changes due to discount rates or estimated future cash flows are capitalized
to or derecognized from property, plant and equipment. Actual costs incurred upon settlement of the asset retirement obligation are charged against
the provision.
(L)
FOREIGN CURRENCY TRANSLATION
Functional and presentation currency
Items included in the financial statements of the Company’s subsidiary companies and partnerships are measured using the currency of the primary
economic environment in which the subsidiary operates (the “functional currency”). The consolidated financial statements are presented in Canadian
dollars, which is the Company’s functional currency.
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 sheets, 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, blending and feedstock, 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 income 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.
67
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Deferred income tax assets for deductible temporary differences and tax loss carryforwards are recognized to the extent that it is probable that future
taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. The carrying amount of deferred
income tax assets is reviewed at each reporting date, and is reduced if it is no longer probable that sufficient future taxable profits will be available
against which the temporary differences or tax loss carryforwards can be utilized.
Current income tax is calculated based on net earnings for the period, adjusted for items that are non-taxable or taxed in different periods, using
income tax rates that are substantively enacted at each reporting date.
Income taxes are recognized in net earnings or other comprehensive income, consistent with the items to which they relate.
(P) SHARE-BASED COMPENSATION
The Company’s Stock Option Plan (the “Option Plan”) provides current employees with the right to elect to receive common shares or a cash payment
in exchange for stock options surrendered. The liability for awards granted to employees is initially measured based on the grant date fair value of the
awards and the number of awards expected to vest. The awards are re-measured each reporting period for subsequent changes in the fair value of
the liability. Fair value is determined using the Black-Scholes valuation model under a graded vesting method. Expected volatility is estimated based
on historic results. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are
exercised for common shares under the Option Plan, consideration paid by the employee and any previously recognized liability associated with the
stock options are recorded as share capital.
The Company grants Performance Share Units ("PSUs") to certain executive employees. The PSUs are subject to certain performance conditions and
vest three years from original grant date.
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 comprised of 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
68
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions,
the Company primarily relied on external, readily-observable market inputs including quoted commodity prices and volatility, interest rate yield curves,
and foreign exchange rates. The carrying amount of a risk management liability is adjusted for the Company’s own credit risk.
The Company documents all derivative financial instruments that are formally designated as hedging transactions at the inception of the hedging
relationship, in accordance with the Company’s risk management policies. The effectiveness of the hedging relationship is evaluated, both at inception
of the hedge and on an ongoing basis.
The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil and natural gas in order to
protect its cash flow for its capital expenditure programs. The effective portion of changes in the fair value of derivative commodity price contracts
formally designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to risk management activities in
net earnings in the same period or periods in which the commodity is sold or purchased. The ineffective portion of changes in the fair value of these
designated contracts is recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural
gas commodity price contracts are recognized in risk management activities in net earnings.
The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on certain of its long-term debt. The
interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments
are based. Changes in the fair value of interest rate swap contracts designated as fair value hedges and corresponding changes in the fair value of the
hedged long-term debt are recognized in interest expense in net earnings. Changes in the fair value of non-designated interest rate swap contracts are
recognized in risk management activities in net earnings.
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.
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 periods 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.
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.
69
CANADIAN NATURAL 2017 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. Accounting Standards Issued But Not Yet Applied
In October 2017, the IASB issued amendments to IAS 28 “Investments in Associates and Joint Ventures” to clarify that the impairment provisions
in IFRS 9 apply to financial instruments in an associate or joint venture that are not accounted for using the equity method, including long-term
interests that form part of the net investment in the associate or joint venture. The amendments are effective January 1, 2019 with earlier adoption
permitted. The amendments are required to be adopted retrospectively. The Company is assessing the impact of the amendments on its consolidated
financial statements.
In June 2017, the IASB issued IFRIC 23 "Uncertainty over Income Tax Treatments". The interpretation provides guidance on how to reflect the effects
of uncertainty in accounting for income taxes where IAS 12 is unclear. The interpretation is effective January 1, 2019. The Company is assessing the
impact of this interpretation on its consolidated financial statements.
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.
IFRS 15 "REVENUE FROM CONTRACTS WITH CUSTOMERS"
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.
Effective January 1, 2018, the Company retrospectively adopted IFRS 15. Adoption of the new standard did not have a significant impact on the
Company’s recognition and measurement of revenue; however, it will require certain additional disclosures.
Upon adoption of IFRS 15, the Company applied the practical expedient such that contracts that were completed in the comparative periods have not
been restated.
IFRS 9 "FINANCIAL INSTRUMENTS"
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 and are required to be adopted retrospectively.
Effective January 1, 2018, the Company adopted the amendment to IFRS 9 and elected to apply the limited exemption in IFRS 9 relating
to transition for impairment. Adoption of the amendment did not have a significant impact on the Company’s previous accounting for impairment of
financial assets.
70
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT 3. Critical Accounting Estimates and Judgements
The Company has made estimates, assumptions and judgements regarding certain assets, liabilities, revenues and expenses in the preparation of
the consolidated financial statements, primarily related to unsettled transactions and events as of the date of the consolidated financial statements.
Accordingly, actual results may differ from estimated amounts. The estimates, assumptions and judgements that have a significant risk of causing a
material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below.
(A) CRUDE OIL AND NATURAL GAS RESERVES
Purchase price allocations, depletion, depreciation and amortization, asset retirement obligations, and amounts used in impairment calculations
are based on estimates of crude oil and natural gas reserves. Reserves estimates are based on engineering data, estimated future prices and
production costs, expected future rates of production, and the timing and amount of future development expenditures, all of which are subject to
many uncertainties, interpretations and judgements. The Company expects that, over time, its reserves estimates will be revised upward or downward
based on updated information.
(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 reserves life. These differences may have a
material impact on the estimated provision.
(C)
INCOME TAXES
The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the Company to interpret frequently
changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating
the timing of temporary difference reversals, and estimating the realizability of tax assets. There are many transactions and calculations for which
the ultimate tax determination is uncertain. The Company recognizes 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 its 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.
71
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT (H)
IMPAIRMENT OF ASSETS
The recoverable amount of a CGU or an individual asset has been determined as the higher of the CGUs’ 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 10% 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.
4.
Inventory
Product inventory
Materials and supplies
2017
285
609
894
$
$
2016
263
426
689
$
$
The Company recorded a write-down of its product inventory of $33 million from cost to net realizable value as at December 31, 2017
(2016 – $73 million).
5. Exploration and Evaluation Assets
Cost
At December 31, 2015
Additions
Transfers to property, plant and equipment
Disposals/derecognitions
Foreign exchange adjustments
At December 31, 2016
Additions
Acquisition of AOSP and other assets (note 7)
Transfers to property, plant and equipment
Disposals/derecognitions
At December 31, 2017
Exploration and Production
North
America
North
Sea
Offshore
Africa
Oil Sands
Mining and
Upgrading
Total
$
2,500
$
— $
20
(211)
(3)
—
2,306
144
31
(198)
(1)
—
—
—
—
—
—
—
—
—
$
2,282
$
— $
86
9
—
(18)
(1)
76
15
—
—
—
91
$
— $
2,586
—
—
—
—
—
—
259
—
—
29
(211)
(21)
(1)
2,382
159
290
(198)
(1)
$
259
$
2,632
On May 31, 2017, the Company completed the acquisition of AOSP and other assets in the Oil Sands Mining and Upgrading and North America
Exploration and Production segments, including exploration and evaluation assets of $290 million. Refer to note 7 regarding the acquisition of AOSP
and other assets.
During 2017, the Company disposed of a number of North America exploration and evaluation assets with a net book value $1 million for consideration
of $36 million, resulting in a pre-tax gain on sale of properties of $35 million.
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.
72
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
6. Property, Plant and Equipment
Oil Sands
Mining and
Upgrading Midstream
Head
Office
Total
Exploration and Production
North
America
North
Sea
Offshore
Africa
Cost
At December 31, 2015
Additions
Transfers from E&E assets
Disposals/derecognitions
Foreign exchange adjustments and other
At December 31, 2016
Additions (1)
Acquisition of AOSP and other assets (note 7)
Transfers from E&E assets
Disposals/derecognitions
Foreign exchange adjustments and other
$
60,540
$
7,414
$
5,173
$
24,343
$
577
$
378
$
98,425
1,462
211
(566)
—
61,647
3,003
349
198
(381)
—
186
—
—
(220)
7,380
255
—
—
—
116
—
—
(157)
5,132
101
—
—
—
(509)
(352)
2,822
—
(127)
—
27,038
1,660
13,832
—
(446)
—
6
—
(349)
—
234
194
—
—
—
—
17
—
—
—
4,609
211
(1,042)
(377)
395
101,826
19
—
—
—
—
5,232
14,181
198
(827)
(861)
At December 31, 2017
$
64,816
$
7,126
$
4,881
$
42,084
$
428
$
414
$ 119,749
Accumulated depletion and depreciation
At December 31, 2015
Expense
Disposals/derecognitions
Foreign exchange adjustments and other
At December 31, 2016
Expense
Disposals/derecognitions
Foreign exchange adjustments and other
At December 31, 2017
Net book value
– at December 31, 2017
– at December 31, 2016
$
35,347
$
5,264
$
3,659
$
2,294
$
132
$
254
$
46,950
3,440
(486)
10
38,311
3,220
(381)
1
457
—
(137)
5,584
509
—
(440)
243
—
(105)
3,797
205
—
(283)
662
(127)
(1)
2,828
1,220
(446)
26
11
(28)
—
115
9
—
—
27
—
—
281
23
—
—
4,840
(641)
(233)
50,916
5,186
(827)
(696)
$
41,151
$
5,653
$
3,719
$
3,628
$
124
$
304
$
54,579
$
$
23,665
23,336
$
$
1,473
1,796
$
$
1,162
1,335
$
$
38,456
24,210
$
$
304
119
$
$
110
114
$
$
65,170
50,910
(1) Additions in Midstream include the revaluation of a previously held joint interest in certain pipeline system assets.
Project costs not subject to depletion and depreciation
Kirby Thermal Oil Sands – North
2017
$
944
$
2016
846
On May 31, 2017, the Company completed the acquisition of AOSP and other assets in the Oil Sands Mining and Upgrading and North America
Exploration and Production segments, including property, plant and equipment of $14,181 million. Refer to note 7 regarding the acquisition of AOSP
and other assets.
During 2017, the Company acquired a number of other producing crude oil and natural gas properties in the North America Exploration and Production
segment, including exploration and evaluation assets of $27 million (2016 - $nil; 2015 - $37 million), along with the remaining interest in certain
pipeline system assets in the Midstream segment, for net cash consideration of $1,013 million (2016 – $159 million; 2015 – $406 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 $63 million (2016 – $30 million; 2015 – $133 million). No net deferred income tax liabilities were recognized on these
acquisitions (2016 - $nil; 2015 - $nil).Further, in connection with the acquisition of pipeline system assets in the Midstream segment, the Company
recognized a pre-tax revaluation gain of $114 million ($83 million after-tax) related to a previously held joint interest in the pipeline.
During 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 and after-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.
73
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
As at December 31, 2017, 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 2017, pre-tax interest of $82 million
(2016 – $233 million; 2015 – $244 million) was capitalized to property, plant and equipment using a weighted average capitalization rate of 3.8%
(2016 – 3.9%; 2015 – 3.9%).
7. Acquisition of Interests in the Athabasca Oil Sands Project and Other Assets
On May 31, 2017, the Company completed the acquisition of a direct and indirect 70% interest in AOSP from Shell Canada Limited and certain
subsidiaries (“Shell”) and an affiliate of Marathon Oil Corporation (“Marathon"), including a 70% interest in the mining and extraction operations north
of Fort McMurray, Alberta, 70% of the Scotford Upgrader and Quest Carbon Capture and Storage ("CCS") project, and a 100% working interest in the
Peace River thermal in situ operations and Cliffdale heavy oil field, as well as other oil sands leases. The Company also assumed certain pipeline and
other commitments (see note 19). The Company consolidates its direct and indirect interest in the assets, liabilities, revenue and expenses of AOSP
and other assets in proportion to the Company’s interests.
Total purchase consideration of $12,541 million, subject to closing adjustments, was comprised of cash payments of $8,217 million, approximately
97.6 million common shares of the Company issued to Shell with a fair value of approximately $3,818 million, and deferred purchase consideration of
$506 million (US$375 million) payable to Marathon in March 2018. The fair value of the Company's common shares was determined using the market
price of the shares as at the acquisition date.
In connection with the acquisition of AOSP and other assets, the Company arranged acquisition financing of $1.8 billion of medium-term notes in
Canada, US$3 billion of long-term notes in the United States and a $3 billion non-revolving term loan facility (see note 10).
The acquisition has been accounted for as a business combination using the acquisition method of accounting. The allocation of the purchase price was
based on management's best estimates of the fair value of the assets and liabilities acquired as at the acquisition date. Key assumptions used in the
determination of estimated fair value were future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations,
future development and operating costs, discount rates, income taxes and foreign exchange rates. The fair value of accounts receivable, inventory,
accounts payable and accrued liabilities approximated their carrying values due to the liquid nature of the assets and liabilities.
The following provides a summary of the net assets acquired and (liabilities) assumed relating to the acquisition:
Cash
Other working capital
Property, plant and equipment
Exploration and evaluation assets
Asset retirement obligations
Other long-term liabilities
Deferred income taxes
Net assets acquired
Total purchase consideration
Gain on acquisition before transaction costs
$
$
$
93
291
14,181
290
(721)
(73)
(1,287)
12,774
12,541
233
The Company recognized a gain of $230 million, net of transaction costs of $3 million, representing the excess of the fair value of the net
assets acquired compared to total purchase consideration. The above amounts are estimates, and may be subject to change based on the receipt of
new information.
As a result of the acquisitions, revenue increased by $2,872 million to $16,651 million and net operating income (comprised of revenue less
production, and transportation, blending, and feedstock expense) increased by $1,166 million to $8,138 million for the year ended December 31, 2017.
If the acquisitions had occurred on January 1, 2017, the Company estimates that pro forma revenue would have increased by $2,181 million to
$18,832 million and pro forma net operating income would have increased by $735 million to $8,873 million for the year ended December 31, 2017.
Readers are cautioned that pro forma revenue and pro forma net operating income are not necessarily indicative of the results of operations that
would have resulted had the acquisition actually occurred on January 1, 2017, or of future results. Actual results would have been different and
those differences may have been material in comparison to the pro forma information provided. Pro forma results are based on available historical
information for the assets as provided to the Company and do not include any synergies that have arisen subsequent to the acquisition date.
74
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Investments
8.
As at December 31, 2017 and 2016, the Company had the following investments:
Investment in PrairieSky Royalty Ltd.
Investment in Inter Pipeline Ltd.
INVESTMENT IN PRAIRIESKY ROYALTY LTD.
2017
726
167
893
$
$
2016
723
190
913
$
$
During 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 Royalty Ltd. ("PrairieSky")
at $22.16 per common share determined as of the closing date. 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 investment of 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, 2017, 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
INVESTMENT IN INTER PIPELINE LTD.
2017
2016
2015
$
$
(3) $
(292) $
(17)
(27)
(20) $
(319) $
11
(5)
6
During 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 Ltd. ("Inter Pipeline") at $29.57 per common share
determined as of the closing date. 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 of 6.4 million common shares of Inter Pipeline 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, 2017, the Company's investment in Inter Pipeline was classified as a
current asset.
The loss (gain) from the investment in Inter Pipeline was comprised as follows:
Fair value loss from Inter Pipeline
Dividend income from Inter Pipeline
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.
2017
2016
$
$
23
$
(10)
13
$
— $
(1)
(1) $
$
$
2017
292
510
204
241
1,247
79
$
1,168
$
2015
—
—
—
2016
261
385
489
168
1,303
283
1,020
75
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT 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.
The facility capital cost ("FCC") budget for the Project is currently estimated to be $9,500 million with project completion targeted for third quarter
2018. Productivity challenges during construction have continued to result in upward budgetary pressures that may result in a further increase in
FCC of up to 2%. During 2013, the Company and APMC agreed, each with a 50% interest, to provide subordinated debt, bearing interest at prime
plus 6%, as required for Project costs to reflect an agreed debt to equity ratio of 80/20. To December 31, 2017, each party has provided $411 million
of subordinated debt, together with accrued interest thereon of $99 million, for a Company total of $510 million. Any additional subordinated debt
financing is not expected to be significant.
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.
During 2017, Redwater Partnership issued $750 million of 2.80% series J senior secured bonds due June 2027 and $750 million of 3.65% series K
senior secured bonds due June 2035.
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, 2017, Redwater Partnership had additional borrowings of $1,870 million under its secured $3,500 million syndicated credit facility,
maturing June 2018. Subsequent to December 31, 2017, Redwater Partnership extended $2,000 million of the $3,500 revolving syndicated credit
facility to June 2021. The remaining $1,500 million was extended on a fully drawn non-revolving basis maturing February 2020.
The assets, liabilities, partners’ equity and equity income related to Redwater Partnership and the Company’s 50% interest at December 31, 2017 and
2016 were comprised as follows:
2017
2016
Redwater
Partnership
100% interest
Company
50% interest
Redwater
Partnership
100% interest
Company
50% interest
$
$
$
$
$
$
330
10,540
2,476
7,810
584
$
$
$
$
$
165
5,270
1,238
3,905
292
$
$
$
$
$
96
8,258
572
7,260
522
$
$
$
$
$
48
4,129
286
3,630
261
(62) $
(31) $
(14) $
(7)
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Partners’ equity
Equity income
76
CANADIAN NATURAL 2017 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
2.05% debentures due June 1, 2020
2.89% debentures due August 14, 2020
3.31% debentures due February 11, 2022
3.55% debentures due June 3, 2024
3.42% debentures due December 1, 2026
4.85% debentures due May 30, 2047
US dollar denominated debt, unsecured
Bank credit facilities (December 31, 2017 – US$1,839 million; December 31, 2016 – US$905 million)
Commercial paper (December 31, 2017 – US$500 million; December 31, 2016 – US$250 million)
US dollar debt securities
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)
2.95% due January 15, 2023 (US$1,000 million)
3.80% due April 15, 2024 (US$500 million)
3.90% due February 1, 2025 (US$600 million)
3.85% due June 1, 2027 (US$1,250 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)
4.95% due June 1, 2047 (US$750 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 other long-term debt (1) (2)
2017
2016
$
3,544
$
2,758
500
500
900
1,000
1,000
500
600
300
8,844
2,300
625
—
751
501
625
1,252
625
751
1,566
501
438
438
563
1,377
501
939
13,753
22,597
18
121
22,458
625
1,252
$
20,581
$
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
(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, 2017, the Company had in place bank credit facilities of $11,050 million, as described below, of which $4,112 million was available.
This excludes certain other dedicated credit facilities supporting letters of credit.
■■
■■
■■
■■
a $100 million demand credit facility;
a $750 million non-revolving term credit facility maturing February 2019;
a $125 million non-revolving term credit facility maturing February 2019;
a $2,200 million non-revolving term credit facility maturing October 2019;
77
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
■■
■■
■■
■■
a $3,000 million non-revolving term credit facility maturing May 2020;
a $2,425 million revolving syndicated credit facility maturing June 2020;
a $2,425 million revolving syndicated credit facility with $330 million maturing in June 2019 and $2,095 million maturing June 2021; and
a £15 million demand credit facility related to the Company’s North Sea operations.
During 2017, the Company extended $2,095 million of the $2,425 million revolving syndicated credit facility originally due June 2019 to June 2021. The
remaining $330 million outstanding under this facility continues under the previous terms and matures in June 2019. The other $2,425 million revolving
credit facility matures in June 2020. The revolving credit facilities are 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 2017, the $1,500 million non-revolving term credit facility was increased to $2,200 million and the maturity date was extended to October 2019
from April 2018. Borrowings under the $2,200 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, 2017, the $2,200 million facility was fully drawn.
Borrowings under the $750 million and $125 million non-revolving term credit facilities may be made by way of pricing referenced to Canadian dollar
bankers’ acceptances or Canadian prime loans. As at December 31, 2017, the $750 million and $125 million facilities were each fully drawn. Subsequent
to December 31, 2017, the Company extended the $750 million non-revolving term credit facility originally due February 2019 to February 2021 and fully
repaid and cancelled the $125 million non-revolving term credit facility.
In addition to the credit facilities described above, during 2017 the Company entered into a $3,000 million non-revolving term loan facility to finance the
acquisition of AOSP and other assets. This facility matures in May 2020 and is subject to annual amortization of 5% of the original balance. Borrowings
under the term loan facility may be made by way of pricing referenced to Canadian dollar or US dollar bankers’ acceptances, or LIBOR, US base rate or
Canadian prime loans. The facility also supports a US$375 million letter of credit relating to the deferred purchase consideration payable to Marathon
in March 2018. As at December 31, 2017, the $3,000 million facility was fully drawn. Subsequent to December 31, 2017, the Company repaid and
cancelled $150 million of the facility; $2,850 million remains outstanding.
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, 2017 was
2.2% (December 31, 2016 – 1.9%), and on total long-term debt outstanding for the year ended December 31, 2017 was 3.8% (December 31, 2016 – 3.9%).
At December 31, 2017, letters of credit and guarantees aggregating $866 million were outstanding, including letters of credit of $651 million related
to AOSP (including the deferred purchase consideration payable to Marathon in March 2018), a $39 million financial guarantee related to Horizon and
$63 million of letters of credit related to North Sea operations.
MEDIUM-TERM NOTES
During 2017, the Company issued $900 million of 2.05% medium-term notes due June 2020, $600 million of 3.42% medium-term notes due December
2026 and $300 million of 4.85% medium-term notes due May 2047. Proceeds from the securities were used to finance the acquisition of AOSP and
other assets. In July 2017, the Company filed a new 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 August 2019. 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 2016, the Company issued $1,000 million of 3.31% medium-term notes due February 2022.
US DOLLAR DEBT SECURITIES
During 2017, the Company repaid US$1,100 million of 5.70% notes, and issued US$1,000 million of 2.95% notes due January 2023, US$1,250 million of
3.85% notes due June 2027 and US$750 million of 4.95% notes due June 2047. Proceeds from the debt securities were used to finance the acquisition
of AOSP and other assets. In July 2017, the Company filed a new 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 August 2019. 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. Subsequent to December 31, 2017, the Company
repaid US$600 million of 1.75% notes and US$400 million of 5.90% notes.
During 2016, the Company repaid US$500 million of three-month LIBOR plus 0.375% notes and US$250 million of 6.00% notes.
78
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT SCHEDULED DEBT REPAYMENTS
Scheduled debt repayments are as follows:
Year
2018
2019
2020
2021
2022
Thereafter
11. Other Long-Term Liabilities
Asset retirement obligations
Share-based compensation
Risk management (note 18)
Other (1)
Less: current portion
Repayment
$
$
$
$
$
$
2017
$
4,327
$
414
103
565
5,409
1,012
4,397
$
$
2,027
4,228
4,231
760
1,000
10,351
2016
3,243
426
—
17
3,686
463
3,223
(1)
Included in Other at December 31, 2017 is $469 million (US$375 million) of deferred purchase consideration payable to Marathon in March 2018.
ASSET RETIREMENT OBLIGATIONS
The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and have been
discounted using a weighted average discount rate of 4.7% (2016 – 5.2%; 2015 – 5.9%). 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
2017
2016
$
3,243
$
2,950
$
12
784
(274)
164
(40)
509
(71)
4,327
92
3
30
(267)
142
(68)
493
(40)
3,243
95
$
4,235
$
3,148
$
2015
4,221
7
129
(370)
173
(313)
(1,150)
253
2,950
101
2,849
2017
2016
$
1,840
$
1,444
755
245
1,486
1
837
244
717
1
$
4,327
$
3,243
79
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT SHARE-BASED COMPENSATION
As the Company’s Option Plan provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock
options surrendered, a liability for potential cash settlements is recognized. The current portion represents the maximum amount of the liability
payable within the next twelve month period if all vested stock options are surrendered for cash settlement.
Balance – beginning of year
Share-based compensation expense (recovery)
Cash payment for stock options surrendered
Transferred to common shares
Charged to (recovered from) Oil Sands Mining and Upgrading, net
Balance – end of year
Less: current portion
$
$
2017
426
134
(6)
(154)
14
414
348
$
2016
128
355
(7)
(117)
67
426
368
$
66
$
58
$
2015
203
(46)
(1)
(18)
(10)
128
105
23
Included within share-based compensation expense for the year ended December 31, 2017 was $5 million (2016 – $nil; 2015 – $nil) related to PSUs
granted to certain executive employees.
The fair value of stock options outstanding 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.
$
$
$
$
2017
11.82
44.92
27.1%
2.5%
1.8%
5.0%
$
$
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%
4.5 years
4.6 years
4.5 years
The intrinsic value of vested stock options at December 31, 2017 was $195 million (2016 – $191 million; 2015 – $10 million).
12. Income Taxes
The provision for income tax was as follows:
Expense (recovery)
Current corporate income tax – North America
Current corporate income tax – North Sea
Current corporate income tax – Offshore Africa
Current PRT (1) – North Sea
Other taxes
Current income tax
Deferred corporate income tax
Deferred PRT (1) – North Sea
Deferred income tax
Income tax
(1) Petroleum Revenue Tax.
80
2017
2016
$
(145) $
(377) $
57
45
(132)
11
(164)
586
54
640
476
$
(74)
22
(198)
9
(618)
(106)
(135)
(241)
$
(859) $
2015
86
(117)
17
(258)
11
(261)
216
15
231
(30)
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT The provision for income tax is different from the amount computed by applying the combined statutory Canadian federal and provincial income tax
rates to earnings (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 expense (recovery)
2017
27.0%
2016
27.0%
$
776
$
(287) $
(67)
28
(43)
(86)
33
10
(63)
(3)
(86)
(23)
(324)
131
(54)
(80)
94
(107)
—
(120)
(80)
(32)
$
476
$
(859) $
2015
26.0%
(173)
(232)
119
(157)
36
(12)
362
—
32
36
(41)
(30)
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
$
12,484
$
10,259
2017
2016
Unrealized risk management activities
PRT deduction for corporate income tax
Investments
Investment in North West Redwater Partnership
Deferred income tax assets
Asset retirement obligations
Loss carryforwards
Unrealized foreign exchange loss on long-term debt
Deferred PRT
Other
20
7
96
252
12,859
(1,264)
(523)
(29)
(18)
(50)
(1,884)
Net deferred income tax liability
$
10,975
$
62
29
98
222
10,670
(983)
(390)
(149)
(73)
(2)
(1,597)
9,073
81
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
2015
(7)
(176)
(222)
(5)
522
(53)
60
106
15
(5)
(4)
231
2015
8,970
231
(4)
147
—
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
$
Timing of partnership items
Unrealized foreign exchange loss (gain) on long-term debt
Unrealized risk management activities
Asset retirement obligations
Loss carryforwards
Investments
Investment in North West Redwater Partnership
Deferred PRT
PRT deduction for corporate income tax
Other
2017
541
—
120
(46)
(88)
48
(2)
30
54
(21)
4
2016
$
37
$
(261)
63
(44)
(20)
(221)
38
81
(135)
61
160
The following table summarizes the movements of the net deferred income tax liability during the year:
$
640
$
(241) $
Balance – beginning of year
Deferred income tax expense (recovery)
Deferred income tax expense (recovery) included in other comprehensive income
Foreign exchange adjustments
Business combinations (note 7)
Balance – end of year
2017
9,073
$
$
640
4
(29)
1,287
$
2016
9,344
(241)
(5)
(25)
—
$
10,975
$
9,073
$
9,344
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 2017, the British Columbia government enacted legislation that increased the provincial corporate income tax rate from 11% to 12% effective
January 1, 2018. As a result of this income tax rate increase, the Company's deferred corporate income tax liability was increased by $10 million.
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. In addition, 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 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 corporate 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 also 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 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 reported 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.
82
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT 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
Issued for the acquisition of AOSP and other assets (note 7)
Issued upon exercise of stock options
Previously recognized liability on stock options exercised for
common shares
Return of capital on PrairieSky Royalty Ltd. share distribution (note 8)
Balance – end of year
PREFERRED SHARES
2017
2016
Number of
shares
(thousands)
1,110,952
$
97,561
14,256
—
—
Number of
shares
(thousands)
Amount
Amount
4,671
3,818
466
154
—
1,094,668
$
4,541
—
16,284
—
—
—
559
117
(546)
1,222,769
$
9,109
1,110,952
$
4,671
Preferred shares are issuable in a series. If issued, the number of shares in each series, and the designation, rights, privileges, restrictions and
conditions attached to the shares will be determined by the Board of Directors of the Company.
DIVIDEND POLICY
The Company has paid regular quarterly dividends in each year since 2001. The dividend policy undergoes periodic review by the Board of Directors
and is subject to change.
On February 28, 2018, the Board of Directors declared a quarterly dividend of $0.335 per common share, an increase from the previous quarterly
dividend of $0.275 per common share. The dividend is payable on April 1, 2018. 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.
NORMAL COURSE ISSUER BID
On May 16, 2017, the Company's application was approved 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 27,931,135 common shares, over a 12 month period
commencing May 23, 2017 and ending May 22, 2018. During 2017, 2016 and 2015, the Company did not purchase any common shares for cancellation.
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.
83
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
The following table summarizes information relating to stock options outstanding at December 31, 2017 and 2016:
Outstanding – beginning of year
Granted
Surrendered for cash settlement
Exercised for common shares
Forfeited
Outstanding – end of year
Exercisable – end of year
2017
2016
Stock
options
(thousands)
Weighted
average
exercise price
Stock
options
(thousands)
Weighted
average
exercise price
58,299
16,052
$
$
(626) $
(14,256) $
(3,433) $
56,036
18,282
$
$
34.22
42.07
33.18
32.66
37.53
36.67
34.25
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
The range of exercise prices of stock options outstanding and exercisable at December 31, 2017 was as follows:
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 – $46.74
Stock options outstanding
Stock options exercisable
Stock
options
outstanding
(thousands)
Weighted
average
remaining
term (years)
Weighted
average
exercise
price
Stock
options
exercisable
(thousands)
Weighted
average
exercise
price
3,657
8,390
10,047
13,523
19,417
1,002
56,036
3.03
2.34
1.61
3.29
4.15
3.63
3.13
$
$
$
$
$
$
$
22.90
28.72
33.31
37.21
43.60
45.61
36.67
1,116
3,967
5,557
4,190
3,118
334
18,282
$
$
$
$
$
$
$
22.90
28.57
33.49
35.88
43.55
45.09
34.25
14. Accumulated Other Comprehensive Income (Loss)
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
2017
47
$
(115)
(68) $
2016
27
43
70
$
$
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 net current and long-term debt
divided by the sum of the carrying value of shareholders’ equity plus net 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, 2017, the ratio was within the target range at 41%.
84
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
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, net (1)
Total shareholders’ equity
Debt to book capitalization
(1)
Includes the current portion of long-term debt, net of cash and cash equivalents.
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
$
$
2017
22,321
31,653
41%
$
$
2016
16,788
26,267
39%
2017
2016
2015
1,175,094
1,100,471
1,093,862
7,729
—
—
1,182,823
1,100,471
1,093,862
$
$
$
2,397
2.04
2.03
$
$
$
(204) $
(0.19) $
(0.19) $
(637)
(0.58)
(0.58)
In 2017, the Company excluded 17,547,000 potentially anti-dilutive stock options from the calculation of diluted earnings per common share.
17. Interest and Other Financing Expense
Interest and other financing expense:
Long-term debt
Other (1)
Less: amounts capitalized on qualifying assets
Total interest and other financing expense
Total interest income
Net interest and other financing expense
(1)
Includes the fair value impact of interest rate swaps on US dollar debt securities.
2017
2016
2015
$
$
810
—
810
82
728
(97)
$
664
—
664
233
431
(48)
$
631
$
383
$
618
1
619
244
375
(53)
322
85
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
18. Financial Instruments
The carrying amounts of the Company’s financial instruments by category were as follows:
Asset (liability)
Accounts receivable
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
Long-term debt (2)
Asset (liability)
Accounts receivable
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Long-term debt (2)
2017
Financial
assets
at amortized
cost
Fair value
through
profit or loss
Derivatives
used for
hedging
Financial
liabilities at
amortized
cost
$
2,397
$
— $
— $
— $
—
510
—
—
—
—
$
2,907
$
—
—
(775)
(2,597)
(469)
(22,458)
$
(26,299) $
893
—
—
—
(38)
—
855
$
—
204
—
—
(65)
—
139
2016
Financial
assets
at amortized
cost
Fair value
through
profit or loss
Derivatives
used for
hedging
Financial
liabilities at
amortized
cost
$
1,434
$
— $
— $
— $
—
385
—
—
—
913
4
—
—
—
—
485
—
—
—
—
—
(595)
(2,222)
(16,805)
$
1,819
$
917
$
485
$
(19,622) $
Total
2,397
893
714
(775)
(2,597)
(572)
(22,458)
(22,398)
Total
1,434
913
874
(595)
(2,222)
(16,805)
(16,401)
(1)
(2)
Includes $469 million (US$375 million) of deferred purchase consideration payable to Marathon in March 2018.
Includes the current portion of long-term debt.
86
CANADIAN NATURAL 2017 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 investments, recurring other long-term assets (liabilities) and fixed rate long-term debt are outlined below:
Asset (liability) (1) (2)
Investments (3)
Other long-term assets (4)
Other long-term liabilities
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
2017
Fair Value
Level 1
Level 2
Level 3
893
714
$
$
(103) $
893
$
— $
— $
(15,989) $
(17,259) $
— $
204
$
(103) $
— $
—
510
—
—
2016
Carrying
Amount
913
874
$
$
Level 1
913
$
— $
(12,498) $
(13,217) $
Fair Value
Level 2
— $
489
$
— $
Level 3
—
385
—
$
$
$
$
$
$
$
(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, and deferred purchase consideration payable to Marathon in March 2018).
(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 (liabilities) assets
Other long-term assets
2017
2016
$
(38) $
—
(71)
210
101
$
(103) $
204
101
$
$
$
$
10
(6)
16
469
489
222
267
489
During 2017, the Company recognized a gain of $5 million (2016 – gain of $7 million, 2015 – gain of $5 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.
87
CANADIAN NATURAL 2017 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
Net loss (gain) from risk management activities for the years ended December 31 were as follows:
Net realized risk management (gain) loss
Net unrealized risk management loss
FINANCIAL RISK FACTORS
a) Market risk
2017
$
489
$
(37)
(375)
24
101
(103)
$
204
$
2017
2016
(2) $
37
35
$
8
25
33
$
$
$
$
2016
854
(25)
(304)
(36)
489
222
267
2015
(843)
374
(469)
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, 2017, the Company had no derivative financial
instruments outstanding.
INTEREST RATE RISK MANAGEMENT
The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its floating rate long-term debt.
The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on long-term debt. Interest rate
swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based.
At December 31, 2017, the Company had no interest rate swap contracts outstanding.
88
CANADIAN NATURAL 2017 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
and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted in other currencies and in the
carrying value of its foreign subsidiaries. The Company periodically enters into cross currency swap contracts and foreign currency forward contracts
to manage known currency exposure on US dollar denominated long-term debt and working capital. The cross currency swap contracts require the
periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based.
At December 31, 2017 the Company had the following cross currency swap contracts outstanding:
Remaining term
Amount
(US$/C$)
Exchange rate
Interest rate
(US$)
Interest rate
(C$)
Cross currency
Swaps
Jan 2018 – Nov 2021
Jan 2018 – Mar 2038
US$500
US$550
1.022
1.170
3.45%
6.25%
3.96%
5.76%
All cross currency swap derivative financial instruments were designated as hedges at December 31, 2017 and were classified as cash flow hedges.
In addition to the cross currency swap contracts noted above, at December 31, 2017 the Company had US$3,705 million of foreign currency forward
contracts outstanding, with terms of up to 90 days, including US$2,339 million designated as cash flow hedges.
FINANCIAL INSTRUMENT SENSITIVITIES
The following table summarizes the annualized sensitivities of the Company’s 2017 net earnings and other comprehensive income (loss) to changes in
the fair value of financial instruments outstanding as at December 31, 2017, resulting from changes in the specified variable, with all other variables
held constant. These sensitivities are prepared on a different basis than those sensitivities disclosed in the Company’s other continuous disclosure
documents, are limited to the impact of changes in a specified variable applied to financial instruments only and do not represent the impact of a
change in the variable on the operating results of the Company taken as a whole. Further, these sensitivities are theoretical, as changes in one
variable may contribute to changes in another variable, which may magnify or counteract the sensitivities. In addition, changes in fair value generally
cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear.
Interest rate risk
Increase interest rate 1%
Decrease interest rate 1%
Foreign currency exchange rate risk
Increase exchange rate by US$0.01
Decrease exchange rate by US$0.01
b) Credit Risk
Increase (decrease)
to net earnings
(Increase)
decrease to other
comprehensive loss
$
$
$
$
(42)
42
(105)
101
$
$
$
$
(16)
19
—
—
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, 2017, 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, 2017, the Company had net risk management assets of $187 million with specific counterparties related to derivative financial
instruments (December 31, 2016 – $489 million).
The carrying amount of financial assets approximates the maximum credit exposure.
89
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities.
Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources of capital, consisting
primarily of cash flow from operating activities, available credit facilities, commercial paper and access to debt capital markets, to meet obligations as
they become due. The Company believes it has adequate bank credit facilities to provide liquidity to manage fluctuations in the timing of the receipt
and/or disbursement of operating cash flows.
The maturity dates for financial liabilities were as follows:
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
Long-term debt (2) (3)
Less than
1 year
1 to less than
2 years
2 to less than
5 years
Thereafter
$
$
$
$
775
2,597
572
2,027
$
$
$
$
— $
— $
— $
— $
— $
— $
—
—
—
4,228
$
5,991
$
10,351
(1)
(2)
(3)
Includes $469 million (US$375 million) of deferred purchase consideration payable to Marathon in March 2018.
Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
In addition to the financial liabilities disclosed above, estimated interest and other financing payments related to long-term debt are as follows: less than one year, $842 million;
one to less than two years, $755 million; two to less than five years, $1,712 million; and thereafter, $5,384 million. Interest payments were estimated based upon applicable interest
and foreign exchange rates as at December 31, 2017.
19. Commitments and Contingencies
The Company has committed to certain payments as follows:
Product transportation and pipeline
Offshore equipment operating leases
Office leases
Other (1)
2018
680
181
43
87
$
$
$
$
2019
584
92
42
41
$
$
$
$
2020
526
70
42
40
$
$
$
$
2021
482
68
39
39
$
$
$
$
2022
422
8
30
43
$
$
$
$
Thereafter
3,868
—
118
333
$
$
$
$
(1)
In addition to the amounts disclosed above, beginning on the earlier of the commercial operations date of the Redwater 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. See Note 9.
In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and
construction of its various development projects. 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.
90
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT 20. Supplemental Disclosure of Cash Flow Information
Changes in non-cash working capital
Accounts receivable
Current income tax assets
Inventory
Prepaids and other
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
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 (2)
Net expenditures (proceeds) on exploration and evaluation assets
Expenditures on property, plant and equipment
Net proceeds on sale of property, plant and equipment (2) (3)
Net expenditures on property, plant and equipment
2017
2016
2015
$
(977) $
(142) $
527
81
(28)
175
365
469
612
299
—
313
612
$
$
$
(165)
(79)
14
31
(116)
—
(457) $
(542) $
—
85
(457) $
2017
2016
159
$
(35)
124
$
29
$
(35)
(6) $
4,574
$
4,152
$
—
(349)
4,574
$
3,803
$
$
$
$
$
$
$
$
615
(447)
142
11
7
(981)
—
(653)
239
(40)
(852)
(653)
2015
180
(416)
(236)
5,118
(414)
4,704
Included in other long-term liabilities at December 31, 2017 is $469 million (US$375 million) of deferred purchase consideration payable to Marathon in March 2018.
(1)
(2) 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.
(3) 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.
The following table summarizes movements in the Company's liabilities arising from financing activities for the year ended December 31, 2017:
At December 31, 2016
Changes from financing cash flows:
Issue of long-term debt, net (1)
Settlement of hedge instruments, net
Changes in foreign exchange and fair value (2)
At December 31, 2017
Cash flow
hedges on US
dollar debt
securities
Liabilities
from financing
activities
Long-term
debt
$
16,805
$
(485) $
16,320
6,622
—
(969)
—
124
222
6,622
124
(747)
$
22,458
$
(139) $
22,319
(1)
(2)
Includes original issue discounts and premiums, and directly attributable transaction costs.
Includes foreign exchange (gain) loss, changes in the fair value of cash flow hedges on US dollar debt and the amortization of original issue discounts and premiums and directly
attributable transaction costs.
91
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
Less: royalties
Segmented revenue
Segmented expenses
Production
Transportation, blending and
feedstock
Depletion, depreciation and
amortization
Asset retirement obligation
accretion
Realized risk management
activities
Gain on acquisition, disposition
and revaluation of properties
(Gain) loss from investments
Total segmented expenses
7,932
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.
(millions of Canadian dollars)
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream
2017
2016
2015
2017
2016
2015
2017
2016
2015
2017
2016
2015
2017
2016
2015
2017
2015
2017
2015
Exploration and Production
Segmented product sales
$
9,161
$
7,209
$
9,222
$
784
$
570
$
638
$
632
$
603
$
(809)
8,352
(524)
6,685
(732)
8,490
(1)
783
(1)
569
(1)
637
(41)
591
(26)
577
482
(22)
460
$
7,072
$
2,657
$
2,764
$
102
$
114
$
136
$
(82) $
(55) $
(75) $ 17,669
$ 11,098
$ 13,167
Inter–segment elimination and
other
2016
Total
2016
—
(75)
(1,018)
16,651
(575)
(804)
10,523
12,363
(85)
(68)
(75)
2,917
2,003
2,379
5,186
4,858
5,483
(167)
6,905
(24)
2,633
(49)
2,715
679
1,220
48
—
(230)
—
4,317
80
662
29
—
—
—
82
562
31
—
—
—
—
102
16
—
9
—
—
—
114
25
—
11
—
—
(114)
(31)
(120)
(218)
(7)
(189)
—
136
32
—
12
—
—
—
44
88
—
(82)
(8)
—
—
—
—
—
—
(55)
(7)
—
—
—
—
—
—
—
—
—
—
2,063
2,007
(93)
(75)
(83)
13,444
10,533
11,229
164
(2)
(379)
(38)
319
134
631
37
(787)
334
2,873
(164)
142
8
(250)
(327)
345
355
383
25
(55)
1,053
(1,063)
(618)
173
(843)
(739)
50
390
(46)
322
374
761
1,801
(667)
(261)
640
(241)
231
$
2,397
$
(204) $
(637)
2,362
2,186
2,603
2,291
1,941
2,309
3,243
3,465
4,248
80
(2)
(35)
(7)
66
8
(32)
(320)
7,314
93
(843)
(739)
6
7,677
400
31
509
27
—
—
—
967
403
48
458
35
—
—
—
944
544
61
388
39
—
—
—
1,032
226
200
223
2,600
1,292
1,332
(8)
5,596
4,099
4,726
1
205
9
—
—
—
441
2
262
12
—
—
—
476
2
273
10
—
—
—
508
$
420
$
(629) $
813
$
(184) $
(375) $
(395) $
150
$
101
$
(48)
$
2,588
$
570
$
708
$
222
$
303
$
48
$
11
$
20
$
8
3,207
(10)
1,134
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
Deferred income tax expense
(recovery)
Net earnings (loss)
92
CANADIAN NATURAL 2017 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.
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.
Segmented revenue and segmented results include transactions between business segments. Sales between segments are made at prices that
approximate market prices, taking into account the volumes involved. 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.
(millions of Canadian dollars)
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream
Inter–segment elimination and
other
2017
2016
2015
2017
2016
2015
2017
2016
2015
2017
2016
2015
2017
2016
2015
2017
2016
2015
2017
Total
2016
2015
Segmented product sales
$
9,161
$
7,209
$
9,222
$
784
$
570
$
638
$
632
$
603
$
$
7,072
$
2,657
$
2,764
$
102
$
114
$
136
$
(82) $
(55) $
(75) $ 17,669
$ 11,098
$ 13,167
Exploration and Production
(809)
8,352
(524)
6,685
(732)
8,490
(1)
783
(1)
569
(1)
637
(41)
591
(26)
577
(167)
6,905
(24)
2,633
(49)
2,715
2,362
2,186
2,603
226
200
223
2,600
1,292
1,332
679
1,220
48
—
(230)
—
4,317
80
662
29
—
—
—
82
562
31
—
—
—
2,063
2,007
—
102
16
—
9
—
—
—
114
25
—
11
—
—
(114)
(31)
(120)
(218)
(7)
(189)
—
136
32
—
12
—
—
—
44
88
—
(82)
(8)
—
(55)
(7)
—
(75)
(1,018)
16,651
(575)
(804)
10,523
12,363
(8)
5,596
4,099
4,726
(85)
(68)
(75)
2,917
2,003
2,379
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5,186
4,858
5,483
164
(2)
(379)
(38)
142
8
(250)
(327)
173
(843)
(739)
50
(93)
(75)
(83)
13,444
10,533
11,229
$
420
$
(629) $
813
$
(184) $
(375) $
(395) $
150
$
101
$
(48)
$
2,588
$
570
$
708
$
222
$
303
$
48
$
11
$
20
$
8
3,207
(10)
1,134
319
134
631
37
(787)
334
2,873
(164)
345
355
383
25
(55)
1,053
(1,063)
(618)
390
(46)
322
374
761
1,801
(667)
(261)
640
(241)
231
$
2,397
$
(204) $
(637)
93
2,291
1,941
2,309
3,243
3,465
4,248
80
(2)
(35)
(7)
66
8
(32)
(320)
7,314
93
(843)
(739)
6
7,677
400
31
509
27
—
—
—
967
403
48
458
35
—
—
—
944
544
61
388
39
—
—
—
1,032
1
9
205
—
—
—
441
2
262
12
—
—
—
476
482
(22)
460
2
273
10
—
—
—
508
Total segmented expenses
7,932
Less: royalties
Segmented revenue
Segmented expenses
Production
Transportation, blending and
feedstock
Depletion, depreciation and
amortization
Asset retirement obligation
accretion
activities
Realized risk management
Gain on acquisition, disposition
and revaluation of properties
(Gain) loss from investments
Segmented earnings (loss)
before the following
Non-segmented expenses
Administration
Share-based compensation
Interest and other financing
expense
activities
Unrealized risk management
Foreign exchange (gain) loss
Total non-segmented expenses
Earnings (loss) before taxes
Current income tax recovery
Deferred income tax expense
(recovery)
Net earnings (loss)
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
CAPITAL EXPENDITURES (1)
Exploration and evaluation assets
Exploration and Production
North America (4)
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Property, plant and equipment
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading (5)
Midstream (6) (7)
Head office
2017
2016
Net (2)
expenditures
Non-cash
and fair value
changes (2) (3)
Capitalized
costs
Net
expenditures
(proceeds)
Non-cash
and fair value
changes (3)
Capitalized
costs
$
160
$
(184) $
(24) $
—
15
142
317
$
—
—
117
$
(67) $
—
15
259
250
$
17
—
9
—
26
$
(211) $
(194)
—
(18)
—
—
(9)
—
$
(229) $
(203)
$
2,815
$
354
$
3,169
$
1,143
$
(36) $
1,107
160
89
3,064
9,592
80
19
95
12
461
5,454
114
—
255
101
3,525
15,046
194
19
126
142
1,411
2,718
(315)
17
60
(26)
(2)
(23)
(28)
—
186
116
1,409
2,695
(343)
17
$
12,755
$
6,029
$
18,784
$
3,831
$
(53) $
3,778
(1) This table provides a reconciliation of capitalized costs including derecognitions and does not include the impact of foreign exchange adjustments.
(2) Net expenditures on exploration and evaluation assets and property, plant and equipment for the year ended December 31, 2017 exclude non-cash share consideration of
$3,818 million issued on the acquisition of AOSP and other assets. This non-cash consideration is included in non-cash and other fair value changes.
(3) Asset retirement obligations, transfers of exploration and evaluation assets, transfers of property, plant and equipment to inventory due to change in use, and other fair
value adjustments.
(4) The above noted figures for 2017 do not include the impact of a pre-tax cash gain of $35 million (2016 – $32 million pre-tax cash gain) on the disposition of exploration and
evaluation assets.
(5) Net expenditures for Oil Sands Mining and Upgrading include capitalized interest and share-based compensation.
(6) 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 to Inter Pipeline.
(7) The above noted figures for 2017 include the impact of a pre-tax non-cash revaluation gain of $114 million ($83 million after-tax) related to a previously held joint interest in a
pipeline system.
SEGMENTED ASSETS
Exploration and Production
North America
North Sea
Offshore Africa
Other
Oil Sands Mining and Upgrading
Midstream
Head office
94
2017
2016
$
28,705
$
28,892
1,854
1,331
29
40,559
1,279
110
2,269
1,580
29
24,852
912
114
$
73,867
$
58,648
CANADIAN NATURAL 2017 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
2017
2016
3
$
2
$
2015
2
2017
2016
2015
3
10
5
17
35
$
$
3
9
5
15
32
$
$
3
7
2
6
18
$
$
$
(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.
95
CANADIAN NATURAL 2017 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, 2017, 2016, 2015, and 2014 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, 2017, 2016, 2015, and 2014 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 2017 reserves for SEC requirements.
Crude Oil and NGLs
Natural Gas
WTI Cushing
Oklahoma
(US$/bbl)
51.30
WCS
(C$/bbl)
50.78
Canadian
Light Sweet
(C$/bbl)
Cromer
LSB
(C$/bbl)
North Sea
Brent
(US$/bbl)
Edmonton
C5+
(C$/bbl)
Henry Hub
Louisiana
(US$/MMBtu)
AECO
(C$/MMBtu)
BC Westcoast
Station 2
(C$/MMBtu)
63.56
61.81
54.98
67.78
3.07
2.34
1.81
A foreign exchange rate of US$1.00/C$1.2987 was used in the 2017 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 and review 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, 2017, 2016, 2015, and 2014, 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, 2017, 2016, 2015, and 2014, 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.
96
CANADIAN NATURAL 2017 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,
2017, 2016, 2015, and 2014:
Crude Oil and NGLs (MMbbl)
Net Proved Reserves
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
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, 2017
Net proved developed reserves
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
North America
Synthetic
Crude Oil Bitumen (1)
Crude
Oil &
NGLs
North
America
Total
North
Sea
Offshore
Africa
1,780
208
—
—
—
(44)
339
—
1,148
25
17
9
—
(84)
153
(5)
2,283
1,263
—
—
—
—
(45)
108
196
46
5
3
—
(71)
23
32
2,542
1,301
—
—
2,232
—
(100)
—
282
28
7
37
—
(70)
18
44
4,956
1,365
1,631
2,194
2,527
4,967
401
411
384
410
481
10
9
11
(7)
(44)
5
6
471
15
14
15
—
(43)
(19)
51
504
17
19
67
—
(44)
17
14
594
358
341
353
399
3,409
243
26
20
(7)
(172)
497
1
4,017
61
19
18
—
(159)
112
279
4,347
45
26
2,336
—
(214)
35
340
6,915
2,390
2,946
3,264
5,776
211
—
—
—
—
(8)
(51)
(33)
119
—
1
—
—
(9)
(10)
(8)
93
—
1
—
—
(9)
18
4
107
39
3
12
28
77
—
—
—
—
(6)
2
—
73
—
2
—
—
(8)
1
6
74
—
—
—
—
(6)
1
—
69
21
41
31
21
Total
3,697
243
26
20
(7)
(186)
448
(32)
4,209
61
22
18
—
(176)
103
277
4,514
45
27
2,336
—
(229)
54
344
7,091
2,450
2,990
3,307
5,825
(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.
97
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
2017 total proved Crude Oil and NGLs reserves increased by 2,577 MMbbl primarily due to the following:
■■
■■
■■
■■
■■
■■
Extensions and discoveries: Increase of 45 MMbbl primarily due to future thermal (Bitumen) well pad additions at Primrose and extension drilling/
future offset additions at various primary heavy crude oil (Bitumen), Crude Oil and natural gas (NGLs) properties.
Improved recovery: Increase of 27 MMbbl primarily due to infill drilling/future offset additions at various primary heavy crude oil (Bitumen), Crude
Oil and natural gas (NGLs) properties.
Purchases of reserves in place: Increase of 2,336 MMbbl primarily due to acquisitions of the Athabasca Oil Sands Project (SCO), Peace River
thermal and Cliffdale primary heavy crude oil properties (Bitumen) and at Pelican Lake (Crude Oil).
Production: Decrease of 229 MMbbl.
Economic revisions due to prices: Increase of 54 MMbbl primarily due to improved reserves life economics at several North America Bitumen and
Crude Oil core areas.
Revisions of prior estimates: Increase of 344 MMbbl primarily due to Horizon oil sands mining and upgrading ("Horizon") (SCO) revising the
stratigraphic well density used to define proved reserves quantities and increasing the Horizon (SCO) total-volume-to-bitumen-in-place-ratio,
partially offset by Horizon (SCO) adopting a low fines mine plan. Additionally, there were overall positive revisions at several North America
Bitumen and Crude Oil core areas including improved recoveries at Primrose (Bitumen).
2016 total proved Crude Oil and NGLs reserves increased by 305 MMbbl primarily due to the following:
■■
■■
■■
■■
■■
■■
Extensions and discoveries: Increase of 61 MMbbl primarily due to future thermal (Bitumen) well pad additions at Primrose and extension drilling/
future offset additions at various primary heavy crude oil (Bitumen) and Crude Oil properties.
Improved recovery: Increase of 22 MMbbl primarily due to infill drilling/future offset additions at various primary heavy crude oil (Bitumen) and
Crude Oil properties.
Purchases of reserves in place: Increase of 18 MMbbl due to various property acquisitions in several North America core areas.
Production: Decrease of 176 MMbbl.
Economic revisions due to prices: Increase of 103 MMbbl primarily due to reduced royalties at Horizon (SCO), thermal (Bitumen) and Pelican Lake
(Crude Oil) projects, partially offset by the loss of uneconomic reserves at several North America Bitumen and Crude Oil core areas.
Revisions of prior estimates: Increase of 277 MMbbl primarily due to Horizon (SCO) revising the stratigraphic well density used to define proved
reserves quantities. Additionally, there were overall positive revisions at several North America Bitumen and Crude Oil core areas.
2015 total proved Crude Oil and NGLs reserves increased by 512 MMbbl primarily due to the following:
■■
■■
■■
■■
■■
Extensions and discoveries: Increase of 243 MMbbl primarily due to increasing the Horizon (SCO) total-volume-to-bitumen-in-place ratio and well
pad additions at Wolf Lake (Bitumen).
Improved recovery: Increase of 26 MMbbl primarily due to improved recovery from the Primrose (Bitumen) steam flood conversion and infill drilling/
future offset additions at various primary heavy crude oil (Bitumen) properties.
Purchases of reserves in place: Increase of 20 MMbbl due to various property acquisitions in several North America core areas.
Production: Decrease of 186 MMbbl.
Economic revisions due to prices: Increase of 448 MMbbl primarily due to reduced royalties at Horizon (SCO), thermal (Bitumen) and Pelican Lake
(Crude Oil) projects, partially offset by the loss of uneconomic reserves at North Sea.
■■
Revisions of prior estimates: Decrease of 32 MMbbl primarily due to the deferral of undeveloped reserves at North Sea.
98
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Natural Gas (Bcf)
Net Proved Reserves
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
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, 2017
Net proved developed reserves
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
North
America
North
Sea
Offshore
Africa
5,017
237
242
344
(35)
(587)
(935)
240
4,523
176
166
85
(5)
(571)
(572)
792
4,594
261
179
106
—
(558)
403
214
5,199
3,585
2,883
2,805
3,081
84
—
—
—
—
(13)
(8)
(25)
38
—
—
—
—
(14)
(10)
11
25
—
—
—
—
(14)
5
9
25
64
26
18
22
34
—
—
—
—
(9)
3
(7)
21
—
3
—
—
(11)
1
11
25
—
—
—
—
(7)
(1)
(1)
16
22
15
18
9
Total
5,135
237
242
344
(35)
(609)
(940)
208
4,582
176
169
85
(5)
(596)
(581)
814
4,644
261
179
106
—
(579)
407
222
5,240
3,671
2,924
2,841
3,112
99
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
2017 total proved Natural Gas reserves increased by 596 Bcf primarily due to the following:
■■
■■
■■
■■
■■
■■
Extensions and discoveries: Increase of 261 Bcf primarily due to extension drilling/future offset additions in the Montney and Spirit River formations
of northwest Alberta and northeast British Columbia.
Improved recovery: Increase of 179 Bcf primarily due to infill drilling/future offset additions in the Montney and Spirit River formations of northwest
Alberta and northeast British Columbia.
Purchases of reserves in place: Increase of 106 Bcf primarily due to property acquisitions in several North America core areas.
Production: Decrease of 579 Bcf.
Economic revisions due to prices: Increase of 407 Bcf due to improved reserves life economics at several North America Natural Gas core areas.
Revisions of prior estimates: Increase of 222 Bcf primarily due to overall positive revisions at several North America core areas triggered by
production optimizations and reduced operating costs.
2016 total proved Natural Gas reserves increased by 62 Bcf primarily due to the following:
■■
■■
■■
■■
■■
■■
Extensions and discoveries: Increase of 176 Bcf primarily due to extension drilling/future offset additions in the Montney and Spirit River formations
of northwest Alberta and northeast British Columbia.
Improved recovery: Increase of 169 Bcf primarily due to infill drilling/future offset additions in the Montney and Spirit River formations of northwest
Alberta and northeast British Columbia.
Purchases of reserves in place: Increase of 85 Bcf primarily due to various property acquisitions in several North America core areas.
Production: Decrease of 596 Bcf.
Economic revisions due to prices: Decrease of 581 Bcf due to the loss of uneconomic reserves at several North America areas.
Revisions of prior estimates: Increase of 814 Bcf primarily due to overall positive revisions at several North America core areas triggered by
production optimizations and reduced operating costs.
2015 total proved Natural Gas reserves decreased by 553 Bcf primarily due to the following:
Extensions and discoveries: Increase of 237 Bcf primarily due to extension drilling/future offset additions in the Montney and Spirit River formations
of northwest Alberta and northeast British Columbia.
Improved recovery: Increase of 242 Bcf primarily due to infill drilling/future offset additions in the Montney and Spirit River formations of northwest
Alberta and northeast British Columbia.
Purchases of reserves in place: Increase of 344 Bcf primarily due to various property acquisitions in several North America core areas.
Production: Decrease of 609 Bcf.
Economic revisions due to prices: Decrease of 940 Bcf due to the loss of uneconomic reserves at several North America areas.
Revisions of prior estimates: Increase of 208 Bcf primarily due to overall positive revisions at several North America core areas triggered by
production optimizations and reduced operating costs.
■■
■■
■■
■■
■■
■■
100
CANADIAN NATURAL 2017 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
Net capitalized costs
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
Net capitalized costs
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
Net capitalized costs
2017
North
America
North
Sea
Offshore
Africa
Total
$ 106,900
$
7,126
$
4,881
$ 118,907
2,541
109,441
(44,779)
—
7,126
(5,653)
91
4,972
(3,719)
2,632
121,539
(54,151)
$
64,662
$
1,473
$
1,253
$
67,388
2016
North
America
North
Sea
Offshore
Africa
Total
$
88,685
$
7,380
$
5,132
$ 101,197
2,306
90,991
(41,139)
—
7,380
(5,584)
76
5,208
(3,797)
2,382
103,579
(50,520)
$
49,852
$
1,796
$
1,411
$
53,059
2015
North
America
North
Sea
Offshore
Africa
Total
$
84,883
$
7,414
$
5,173
$
97,470
2,500
87,383
(37,641)
—
7,414
(5,264)
86
5,259
(3,659)
2,586
100,056
(46,564)
$
49,742
$
2,150
$
1,600
$
53,492
101
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
2017
North
America
North
Sea
Offshore
Africa
Total
$
15,091
$
— $
— $
15,091
321
112
3,753
$
19,277
$
—
—
255
255
$
2016
—
15
101
116
321
127
4,109
$
19,648
North
America
North
Sea
Offshore
Africa
Total
50
—
26
4,427
4,503
$
$
$
50
—
17
4,125
4,192
$
$
— $
— $
—
9
116
125
—
—
186
186
$
2015
North
America
North
Sea
Offshore
Africa
$
(556) $
— $
— $
(446)
87
2,845
1,930
$
$
—
—
13
13
$
—
35
524
559
$
Total
(556)
(446)
122
3,382
2,502
Costs Incurred in Crude Oil and Natural Gas Activities
(millions of Canadian dollars)
Property acquisitions
Proved
Unproved
Exploration
Development
Costs incurred
(millions of Canadian dollars)
Property acquisitions
Proved
Unproved
Exploration
Development
Costs incurred
(millions of Canadian dollars)
Property acquisitions
Proved
Unproved
Exploration
Development
Costs incurred
102
CANADIAN NATURAL 2017 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, 2017, 2016, and 2015 are
summarized in the following tables:
(millions of Canadian dollars)
2017
North
America
North
Sea
Offshore
Africa
Total
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs
$
13,083
$
784
$
578
$
14,445
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
(millions of Canadian dollars)
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
(millions of Canadian dollars)
(4,962)
(790)
(4,463)
(128)
—
(740)
(400)
(31)
(509)
(27)
78
42
(226)
(1)
(205)
(9)
—
(28)
(5,588)
(822)
(5,177)
(164)
78
(726)
$
2,000
$
(63) $
109
$
2,046
2016
North
America
North
Sea
Offshore
Africa
(3,478)
(623)
(4,127)
(95)
—
143
(403)
(48)
(458)
(35)
333
18
(200)
(2)
(262)
(12)
—
(22)
Total
8,933
(4,081)
(673)
(4,847)
(142)
333
139
$
(389) $
(28) $
79
$
(338)
2015
North
America
North
Sea
Offshore
Africa
Total
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs
$
7,791
$
565
$
577
$
Crude oil and natural gas revenue, net of royalties, blending and feedstock costs
$
10,362
$
623
$
460
$
11,445
Production
Transportation
Depletion, depreciation and amortization (1)
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
(3,935)
(674)
(4,810)
(124)
—
(214)
(544)
(61)
(388)
(39)
243
83
(223)
(2)
(273)
(10)
—
20
$
605
$
(83) $
(28) $
(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.
103
CANADIAN NATURAL 2017 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
Standardized measure of future net cash flows
(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
Standardized measure of future net cash flows
2017
North
America
North
Sea
Offshore
Africa
Total
$ 413,180
$
8,740
$
4,786
$ 426,706
(198,304)
(61,169)
(35,645)
118,062
(73,171)
(4,168)
(2,853)
(595)
1,124
(59)
(1,876)
(1,258)
(248)
1,404
(455)
(204,348)
(65,280)
(36,488)
120,590
(73,685)
$
44,891
$
1,065
$
949
$
46,905
2016
North
America
North
Sea
Offshore
Africa
Total
$ 206,729
$
5,999
$
4,129
$ 216,857
(92,070)
(42,167)
(15,396)
57,096
(33,590)
(3,284)
(3,249)
280
(254)
271
(1,659)
(1,234)
(125)
1,111
(319)
(97,013)
(46,650)
(15,241)
57,953
(33,638)
$
23,506
$
17
$
792
$
24,315
104
CANADIAN NATURAL 2017 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
Standardized measure of future net cash flows
2015
North
America
Total North Sea
Offshore
Africa
Total
$ 225,032
$
10,258
$
4,936
$ 240,226
(100,924)
(47,323)
(16,173)
60,612
(34,050)
(5,973)
(5,228)
791
(152)
213
(2,026)
(1,297)
(430)
1,183
(270)
(108,923)
(53,848)
(15,812)
61,643
(34,107)
$
26,562
$
61
$
913
$
27,536
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)
2017
2016
Sales of crude oil and natural gas produced, net of production costs
$
(8,013) $
(4,159) $
Net changes in sales prices and production costs
Extensions, discoveries and improved recovery
Changes in estimated future development costs
Purchases of proved reserves in place
Sales of proved reserves in place
Revisions of previous reserve estimates
Accretion of discount
Changes in production timing and other
Net change in income taxes
Net change
Balance – beginning of year
Balance – end of year
7,466
481
(5,548)
25,782
—
4,245
3,075
(662)
(4,236)
22,590
24,315
(7,305)
700
1,750
352
(2)
3,668
3,527
(2,137)
385
(3,221)
27,536
$
46,905
$
24,315
$
2015
(5,107)
(43,489)
3,201
5,204
624
(165)
5,298
6,645
(3,452)
5,957
(25,284)
52,820
27,536
105
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
TEN YEAR REVIEW
2011
2012
2013
2014
2015
2016
2017
7,451
2,997
5,514
6,414
6,308
7,274
3,853
3,794
11,744
6,090
6,333
6,547
6,013
7,477
9,587
1,580
1,673
2,643
1,892
2,270
2008 (8)
2009 (8)
2010 (7)
17,129
1.46
1.46
1.54
1.53
1.72
1.72
2.08
2.08
2.41
2.40
5.62
5.62
5.82
5.78
5.98
5.94
5.48
5.47
6.87
6.86
8.78
8.74
3,929
3.60
3.58
2,397
2.04
2.03
7,347
6.25
6.21
4,985
4.61
4.61
6,969
6.45
6.45
1,193
2,586
51,475
59,275
16,794
27,381
1,056
2,382
50,910
58,648
16,805
26,267
513
2,632
65,170
73,867
22,458
31,653
(204)
(0.19)
(0.19)
4,293
3.90
3.89
(637)
(0.58)
(0.58)
5,785
5.29
5.28
(1,200)
2,402
38,429
42,954
8,485
20,368
(1,264)
2,611
44,028
48,980
8,736
24,283
(1,574)
2,609
46,487
51,754
9,661
25,772
(673)
3,557
52,480
60,200
14,002
28,891
(894)
2,475
41,631
47,278
8,571
22,898
(514)
-
39,115
41,024
9,658
19,426
(28)
-
38,966
42,650
12,596
18,374
Years ended December 31
FINANCIAL INFORMATION (1) (Cdn $ millions, except per share amounts)
Net earnings (loss)
Per share – basic ($/share)
Per share – diluted ($/share)
Funds flow from operations (2)
Per share – basic ($/share)
Per share – diluted ($/share)
Capital expenditures, net of
dispositions (including business
combinations)
Balance sheet information
(Cdn $ millions)
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) 1,222,769 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
Weighted average shares
outstanding – basic (thousands)
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
shareholders’ equity, after tax (4)
Daily production before royalties
per ten thousand common shares
36.78 $ 35.28 $ 34.46 $ 46.65 $ 33.92 $ 41.38 $ 52.04 $ 44.77 $ 38.26 $ 54.66
27.53 $ 14.60 $ 18.94 $ 26.53 $ 26.98 $ 25.01 $ 25.69 $ 30.00 $ 13.85 $ 13.22
35.72 $ 31.88 $ 21.83 $ 30.88 $ 33.84 $ 28.87 $ 37.37 $ 44.42 $ 35.98 $ 19.99
47.00 $ 46.74 $ 42.46 $ 49.57 $ 36.04 $ 41.12 $ 50.50 $ 45.00 $ 39.50 $ 55.65
35.90 $ 21.27 $ 25.01 $ 31.00 $ 28.44 $ 25.58 $ 27.25 $ 31.97 $ 17.93 $ 17.10
44.92 $ 42.79 $ 30.22 $ 35.92 $ 35.94 $ 28.64 $ 38.15 $ 44.35 $ 38.00 $ 24.38
1,182,823 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
0.20
$
1,175,094 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
661,832 1,040,320 1,359,476
759,327 1,514,614 1,934,456
0.90 $ 0.575 $
608,008
588,422
717,580
729,700
800,044
951,311
812,521
645,403
844,647
937,481
728,033
683,003
1.10 $
653,727
892,220
0.94 $
0.36 $
0.30 $
0.21 $
0.92 $
0.42 $
$
$
$
$
$
$
(1%)
(2%)
38%
33%
27%
26%
27%
29%
33%
41%
14%
12%
41%
39%
33%
8%
9%
8%
8%
8%
(BOE/d) (1)
7.9
7.3
7.8
7.2
6.2
6.0
5.5
5.8
5.3
5.2
Total proved plus probable reserves
per common share (BOE) (1) (5)
Net asset value ($/share) (1) (6)
$
9.7
3.1
81.41 $ 74.77 $ 73.39 $ 78.99 $ 72.41 $ 62.38 $ 70.37 $ 64.58 $ 64.92 $ 39.89
6.3
5.8
8.3
8.3
8.1
7.3
7.2
6.9
(1) Restated to reflect two-for-one share splits 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, 2018, the Board of Directors approved a quarterly dividend of $0.335 per common share, beginning with the dividend payable on April 1, 2018.
(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, 2017) 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 (2017 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.
106
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT
TEN YEAR REVIEW
2017
6,423
120
70
6,613
-
Years ended December 31
OPERATING INFORMATION
Crude oil and NGLs (MMbbl) (9)
Company net proved reserves (after royalties)
North America
North Sea
Offshore Africa
3,909
134
74
4,117
Horizon SCO (9)
-
Company net proved plus probable reserves (after royalties)
6,015
North America
252
North Sea
108
Offshore Africa
6,375
-
Horizon SCO (9)
Natural gas (Bcf) (9)
Company net proved reserves (after royalties)
North America
North Sea
Offshore Africa
5,845
41
23
5,909
Company net proved plus probable reserves (after royalties)
7,888
North America
85
North Sea
55
Offshore Africa
8,028
8,353
180
102
8,635
-
6,032
21
15
6,068
8,454
32
47
8,533
2016
2015
2014
2013
2012
2011
2010 (7)
2009 (8)
2008 (8)
3,645
158
74
3,877
-
3,380
204
78
3,662
-
5,806
284
113
6,203
-
5,383
39
21
5,443
7,361
96
50
7,507
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
Total net proved reserves
(after royalties) (MMBOE)
Total net proved plus probable
reserves (after royalties) (MMBOE)
Daily production (before royalties)
Crude oil and NGLs (Mbbl/d)
North America –
Exploration and Production
North America –
Oil Sands Mining and Upgrading
North Sea
Offshore Africa
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Total production (before royalties) (MBOE/d)
Product pricing
Average crude oil and NGLs price
($/bbl) (10)
Average natural gas price ($/Mcf) (10)
Average SCO price ($/bbl) (10) (11)
7,625
5,102
4,784
4,524
4,230
4,191
3,977
3,748
3,557
1,960
10,057
7,713
7,454
7,198
6,471
6,426
6,147
5,666
5,440
2,996
359
282
23
20
685
351
123
24
26
524
400
123
22
19
564
391
111
17
12
531
344
100
18
16
478
326
86
20
19
451
1,601
39
22
1,662
962
1,622
38
31
1,691
806
1,663
36
27
1,726
852
1,527
7
21
1,555
790
1,130
4
24
1,158
671
1,198
2
20
1,220
655
296
271
234
244
40
30
23
389
1,231
7
19
1,257
599
91
33
30
425
1,217
10
16
1,243
632
50
38
33
355
1,287
10
18
1,315
575
-
45
27
316
1,472
10
13
1,495
565
48.57
2.76
63.98
36.93
2.32
58.59
41.13
3.16
61.39
77.04
4.83
100.27
73.81
3.30
99.18
72.44
2.70
90.74
79.16
3.99
101.48
65.81
4.08
77.89
57.68
4.53
70.83
82.41
8.39
-
(9)
For the years 2010 to 2017, 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, SCO reserves are now included in the Company's
crude oil and natural gas reserves totals.
(10) For the years 2011 to 2017, product prices reflect realized product prices before transportation costs. Prior to 2011, product prices were reported net of transportation costs.
(11) For 2017 average SCO product price includes AOSP realized product prices net of blending and feedstock costs.
107
CANADIAN NATURAL 2017 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)
Executive Vice-Chairman,
Canadian Natural Resources Limited
Calgary, Alberta
Tim S. McKay
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
Senior Officers
N. Murray Edwards
Executive Chairman
Steve W. Laut
Executive Vice-Chairman
Tim S. McKay
President
Darren M. Fichter
Chief Operating Officer, Exploration and Production
Scott G. Stauth
Chief Operating Officer, Oil Sands
Corey B. Bieber
Chief Financial Officer and Senior Vice-President, Finance
Troy J.P. Andersen
Senior Vice-President, Canadian Conventional Field Operations
Trevor J. Cassidy
Senior Vice-President, Thermal
Réal M. Cusson
Senior Vice-President, Marketing
Allan E. Frankiw
Senior Vice-President, Production
Jay E. Froc
Senior Vice-President, Oil Sands Mining and Upgrading
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
Robin S. Zabek
Senior Vice-President, Exploitation
Paul M. Mendes
Vice-President, Legal, General Counsel and Corporate Secretary
*Annette M. Verschuren, O.C. (2) (3)
Chairman and Chief Executive Officer, NRStor Inc.
Toronto, Ontario
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.
108
CANADIAN NATURAL 2017 ANNUAL REPORTPREMIUM VALUE ▪ DEFINED GROWTH ▪ INDEPENDENT Corporate Offices
HEAD OFFICE
Canadian Natural Resources Limited
2100, 855 – 2 Street S.W.
Calgary, AB T2P 4J8
Telephone: (403) 517-6700
Facsimile: (403) 517-7350
Website: www.cnrl.com
INVESTOR RELATIONS
Telephone: (403) 514-7777
Email: ir@cnrl.com
INTERNATIONAL OFFICE
CNR International (U.K.) Limited
St. Magnus House, Guild Street
Aberdeen AB11 6NJ Scotland
REGISTRAR AND TRANSFER AGENT
Computershare Trust Company of Canada
Calgary, Alberta
Toronto, Ontario
Computershare Investor Services LLC
New York, New York
AUDITORS
PricewaterhouseCoopers LLP
Calgary, Alberta
INDEPENDENT QUALIFIED RESERVES EVALUATORS
GLJ Petroleum Consultants Ltd.
Calgary, Alberta
Sproule Associates Limited
Calgary, Alberta
Sproule International Limited
Calgary, Alberta
STOCK LISTING – CNQ
Toronto Stock Exchange
The New York Stock Exchange
COMPANY DEFINITION
Throughout the annual report, Canadian Natural Resources Limited is
referred to as “us”, “we”, “our”, “Canadian Natural”, or the “Company”.
CURRENCY
All amounts are reported in Canadian currency unless otherwise stated.
ABBREVIATIONS
Abbreviations can be found on page 22.
METRIC CONVERSION CHART
To convert
barrels
thousand cubic feet
feet
miles
acres
tonnes
COMMON SHARE DIVIDEND
To
cubic metres
cubic metres
metres
kilometres
hectares
tons
Multiply by
0.159
28.174
0.305
1.609
0.405
1.102
its common shares
its first dividend on
The Company paid
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, 2017.
2017
2016 2015
Cash dividends declared
per common share
$
1.10 (1) $
0.94 (1) $ 0.92 (1) (2)
(1) Annualized dividend value.
(2) 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 3, 2018 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 2017 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.
109
CANADIAN NATURAL 2017 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
IR@CNRL.COM
WWW.CNRL.COM