Premium Value.
Defined Growth.
Independent.
Canadian Natural.
2018 Performance Highlights
Canadian Natural’s diverse and balanced asset base, continued focus on effective and efficient
operations along with capital flexibility delivered a strong year for the Company, creating significant
value for its shareholders.
FINANCIAL ($ millions, except per common share amounts)
Product sales (1)
Net earnings (loss)
Per common share – basic
– diluted
Adjusted net earnings (loss) from operations (2)
Per common share – basic
– diluted
Cash flows from operating activities
Adjusted funds flow (3)
Per common share – basic
– diluted
Cash flows used in investing activities
Net capital expenditures (4)
Long-term debt (5)
Shareholders’ equity
OPERATING
Daily production, before royalties
Crude oil and NGLs (Mbbl/d)
North America – excluding Oil Sands Mining and Upgrading
North America – Oil Sands Mining and Upgrading
North Sea
Offshore Africa
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Barrels of oil equivalent (MBOE/d) (6)
2018
2017
2016
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
22,282 $
18,360 $
12,002
2,591 $
2,397 $
2.13 $
2.12 $
2.04 $
2.03 $
3,263 $
1,403 $
2.68 $
2.67 $
1.19 $
1.19 $
10,121 $
7,262 $
9,088 $
7,347 $
7.46 $
7.43 $
6.25 $
6.21 $
4,814 $
4,731 $
13,102 $
17,129 $
(204)
(0.19)
(0.19)
(669)
(0.61)
(0.61)
3,452
4,293
3.90
3.89
3,811
3,794
20,623 $
22,458 $
16,805
31,974 $
31,653 $
26,267
351
426
24
20
821
360
282
23
20
685
351
123
24
26
524
1,490
1,601
1,622
32
26
1,548
1,079
39
22
1,662
962
38
31
1,691
806
(1) 2017 and 2016 comparative figures have been restated in accordance with adoption of IFRS 15 on January 1, 2018. See note 2 of the Company’s consolidated
financial statements.
(2) Adjusted net earnings (loss) from operations is a non-GAAP measure that the Company utilizes to evaluate its performance, as it demonstrates the Company's
ability to generate after-tax operating earnings from its core business areas. The derivation of this measure is discussed in the Management’s Discussion and
Analysis (“MD&A”).
(3) Adjusted funds flow (previously referred to as funds flow from operations) is a non-GAAP measure that the Company considers key as it demonstrates the
Company’s ability to generate the cash flow necessary to fund future growth through capital reinvestment and to repay debt. The derivation of this measure
is discussed in the MD&A.
(4) Net capital expenditures is a non-GAAP measure that the Company considers key as it provides an understanding of the Company’s capital spending activities
in comparison to the Company’s annual capital budget. The derivation to this measure is discussed in the MD&A.
(5) Includes the current portion of long-term debt.
(6) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may
be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices,
the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
TABLE OF CONTENTS
2018 Performance Highlights
Letter to our Shareholders
IFC
02
T1-T6 Our World-Class Team
04
12
54
55
Year-End Reserves
Management’s Discussion and Analysis
Management’s Report
Management’s Assessment of Internal Control over Financial Reporting
56
58
62
98
106
108
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Notes to the Consolidated Financial Statements
Supplementary Oil and Gas Information
Ten-Year Review
Corporate Information
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
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.
2018
2017
2016
504
4
2
510
521
2
–
523
19,736
18,795
61
993
20,790
11,453
186
121
72
2,194
21,061
9,958
180
125
11,760
10,263
188
1
1
190
17,579
78
2,194
19,851
7,281
253
133
7,667
9,633
9,520
8,911
38
63
9,734
13,382
32
67
9,619
11,866
85
80
9,076
9,179
14%
ANNUAL BOE PRODUCTION
PER SHARE GROWTH
52%
OF BOE PRODUCTION IS SCO,
LIGHT CRUDE OIL & NGLS
1
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Letter to our Shareholders
In 2018, Canadian Natural demonstrated the strength of our diverse, balanced and vast asset base, and
our ability to create value for our shareholders throughout the commodity price cycle. Canadian Natural's
continued focus on effective and efficient operations, ability to exercise capital flexibility within our
four pillars of capital allocation and our combination of long life low decline and low capital exposure
assets resulted in annual adjusted funds flow of over $9.0 billion. 2018 was a strong year operationally
as the Company was able to react quickly and strategically to changing market conditions, resulting
in record annual production of approximately 1,079,000 BOE/d, delivering 12% production growth and
14% production per share growth over 2017 levels. Returns to shareholders were significant in 2018
totaling $2.8 billion, which included an increase in the Company’s dividend for the 18th consecutive year
by 22% from 2017 levels and over $1.2 billion in share purchases. Throughout 2018, Canadian Natural
demonstrated its commitment to balance sheet strength through a reduction in absolute long-term debt
by approximately $1.8 billion, resulting in an upgrade to our already investment grade credit ratings.
The Company’s industry leading Oil Sands Mining and
the Company’s Primrose pad additions are also on budget and
Upgrading area continued to deliver strong results in
ahead of schedule, with the first twelve months of production
2018, driving high reliability of operations and capturing
targeted to be 26,000 bbl/d. The Company continues to
synergies which significantly lowered the cost structure.
advance technology to enhance performance and improve
As a result, the Company’s combined Oil Sands Mining
steam-to-oil ratios with the installation of vacuum insulated
and Upgrading assets achieved record low annual cash
tubing (“VIT”) on step-out wells at Kirby South. The wells
production costs of $21.75/bbl (US$16.78/bbl) of synthetic
with VIT installed have improved operations as expected,
crude oil (“SCO”). The year 2018 represented the first full
lowering steam use by approximately 30%, which if applied to
year of production following the successful completion of
additional wells will add value for shareholders.
the Horizon Phase 3 expansion in late 2017, which increased
productive capacity to 250,000 bbl/d of SCO at the Horizon
site. At
the Company’s 70% owned and operated
Athabasca Oil
Sands
Project
(“AOSP”),
teams
achieved an
impressive milestone of a cumulative
lifetime production
to date of 1 billion barrels on
July 18, 2018, supported by net annual production of
approximately 199,000 bbl/d of SCO in 2018. Additionally,
due to the opportunistic acquisition of the Joslyn lease
directly south of Horizon, Canadian Natural targets to optimize
its mine plan going forward at Horizon, targeting future
savings of approximately $500 million.
In the Company’s conventional North American Exploration
and Production assets, average crude oil and NGL production
in 2018 was just over 243,000 bbl/d and natural gas
production was approximately 1,550 MMcf/d. Crude oil
and NGL production represented an
improvement of
approximately 4,000 bbl/d over 2017 levels, impressive results
given strategic voluntary production curtailments throughout
the year. With a focus on execution excellence, drilling teams
worked together to complete the 2018 Wembley drilling
program, achieving enhanced drilling performance with
drilling days reduced by 30% and cost reductions of 17%.
New multilateral technology has been successfully deployed
The Company’s thermal in situ teams worked together
in the Company’s Smith primary heavy crude oil play with
effectively
to enhance our growth projects
in 2018.
production continuing to exceed sanctioned rates. As a result,
At Kirby North, construction and drilling activities
the Company is looking to leverage this technology further
continued in 2018 and as a result of top tier execution
within the Company’s vast heavy crude oil land base. Within
and strong productivity from our teams, the project is on
the Company’s natural gas assets, at Septimus, a natural
budget and the timeline has been accelerated by two quarters,
gas reinjection pilot is being advanced in 2019. If successful,
with first steam targeted in late Q2/19. Additionally, work on
natural gas reinjection technology has the potential to add
$2.8 billion
RETURNED TO SHAREHOLDERS
$1.8 billion
LONG-TERM DEBT REDUCTION
2
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. N. MURRAY EDWARDS
Executive Chairman
STEVE W. LAUT
Executive Vice-Chairman
TIM S. MCKAY
President
COREY B. BIEBER
Chief Financial Officer &
Senior Vice-President, Finance
significant value by leveraging the Company’s strategically
commodity prices remain stable and as visibility to market
owned and operated facilities and unlocking liquids rich
access improves, the Company has identified opportunities
development without producing incremental natural gas into
to invest incremental capital in the latter half of 2019 of up
a constrained takeaway environment.
to approximately $680 million, which would add future value
International production was strong in 2018, averaging
approximately 43,600 bbl/d. International teams hit a key
beyond 2019 within the Company’s Oil Sands Mining and
Upgrading, thermal in situ and conventional areas.
production milestone at Baobab (Offshore Africa) in November
Canadian Natural is a unique E&P company that is delivering
2018 with 100 million barrels of light crude oil produced
free cash flow, strong and growing returns to shareholders
from the field since first production in 2005. The Company
and
increasing returns on capital combined with the
drilled 1.7 net producer wells in Baobab in the second half
vast inventory of assets and discipline to allocate capital
of 2018 and performance from the wells has exceeded
to maximize shareholder value and drive per share value
production expectations. As a result Canadian Natural targets
growth. Canadian Natural has a strong track record of
to drill one additional producer well at Baobab in 2019. The
optimizing capital allocation to our four pillars; balance
Company also targets to drill an appraisal well at Kossipo
sheet strength, returns to shareholders, economic resource
which, if successful, could lead to development drilling and a
development and opportunistic acquisitions, to maximize
pipeline tied-back to the Baobab Floating Production Storage
shareholder value and 2019 will be no different. Canadian
and Offloading vessel, adding future value with significant
Natural has the strength and ability to continue to deliver
potential production capability. Additionally, in the North Sea
top tier effective and efficient operations, a robust balance
3.9 net producer wells were drilled on time and on budget
sheet, low maintenance capital and low breakeven prices.
during 2018, with strong light crude oil production results.
Canadian Natural's biggest strength, our people, will continue
Effective and efficient operations and capital discipline
will continue to be a focus for the Company in 2019. Our
2019 base capital budget is disciplined and is targeted to
be approximately $3.7 billion driving corporate production
to make a significant difference in our performance, driven by
continuous improvement and our top tier safety performance,
while minimizing the Company’s environmental footprint
through leveraging technology and innovation.
volumes of approximately 1,075,000 BOE/d at the midpoint
Canadian Natural looks forward to building on the many
of the Company’s annual corporate guidance. Additionally, if
successes achieved in 2018.
N. MURRAY EDWARDS
Executive Chairman
STEVE W. LAUT
Executive Vice-Chairman
TIM S. MCKAY
President
COREY B. BIEBER
Chief Financial Officer
& Senior Vice-President,
Finance
3
Canadian Natural 2018 Annual Report Premium 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, M. Abbott, I. Abdi, A.
Abdolmaleki, M. Abdulrhman, A. Abeda, W. Abeda, D. Abel, R. Abel, T. Abercrombie, G. Abou Mechrek, R.
Abrams, A. Abramyan, J. Abramyk, J. Abreu, N. Abro, C. Acharya, D. Acheson, R. Ackerman, J. Acosta, J.
Acteson-Grill, N. Adair, T. Adair, S. Adam, I. Adam, B. Adams, D. Adams, K. Adams, M. Adams, D. Adamson, P.
Adamson, R. Adamson, C. Adan, D. Addinall, A. Adebayo, Y. Adebayo, K. Adejare, S. Adel, M. Aden, A. Adesanya,
O. Adigun, M. Aditiakusuma, B. Adkins, R. Adzabe Ella, J. Agate, F. Agbadou, A. Agnihotri, K. Agombar, I. Agu, U.
Agu, A. Agustin, E. Agyemang, C. Agyemang-Badu, J. Ahmad, M. Ahmad, N. Ahmad, O. Ahmad, R. Ahmad, S.
Ahmad, A. Ahmadi, M. Ahmadi, F. Ahmadloo, A. Ahmari, A. Ahmed, R. Ahmed, S. Ahmed, M. Ahoonmanesh, T.
Aickelin, R. Aidoo, R. Aikens, G. Ailsby, K. Airth, J. Airton, C. Aitchison, K. Aitchison, S. Aitken, T. Ajayi, J.
Ajedegba, L. Ajijolaiya, S. Akhtar, R. Akinde, I. Akinnola, D. Akins, A. Akinsanya, J. Akolkar, N. Akolkar, S. Akolkar,
I. Alallam, C. Alarcon, J. Albert, J. Alcala, E. Alconcel, M. Al-Dhabbi, J. Aleman, A. Alexander, B. Alexander, D.
Alexander, J. Alexander, P. Alexander, S. Alexander, B. Alfred, A. Ali, G. Ali, S. Ali, R. Aliazas, H. Aljanabi, C. Allan,
J. Allan, E. Allan, E. Allard, J. Allard, L. Allegretto, H. Allen, J. Allen, T. Allen, W. Allerton, D. Allibone, S. Allport,
J. Allsop, B. Almen, M. Almestar Bustamante, S. Almstrong, Y. Alnumi, Y. Al-Saeedi, A. Al-Saleem, R. Al-
Samarrai, S. Al-Siani, A. Alstad, C. Altrogge, J. Alvarez, J. Alvarez Luzon, B. Alyman, D. Amalaman, J. Aman, M.
Amar, T. Amara, A. Amay, A. Amer, B. Amer, K. Amer, J. Amero, D. Ames, 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, D.
Andreoli, C. Andres, J. Andres, B. Andrews, D. Andrews, K. Andrews, T. Andrews, C. Angeles, P. Angell, L. Angen,
K. Angerman, N. Ango Mfene, M. Anis, S. Annis, L. Anongba, M. Ansah-Sam, A. Ansell, C. Ansong-Danquah, D.
Ansorger, R. Anstett, G. Anstey, V. Anstey, L. Antal, E. Antle, J. Antle, M. Antoine, K. Antonishyn, A. Antunes, H.
Aparicio Ramos, P. Appiah, J. Aquila, R. Aranguren, F. Arano, L. Arbour, C. Arcand, 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, L. Arthur, A. Arthur Brown, B. Artz, S. Arunachalam, B. Asake, J. Ashe, Z. Ashmore, A. Aslam, R.
Aslin, R. Asmundson, S. Aspden, R. Aspden, H. Aspeslet, M. Asselstine, D. Assinger, J. Asso, V. Assohou-
Ouattara, F. Assoko-Mve, A. Assoum, S. Assoumane, A. Astalos, R. Astalos, I. Astete, M. Atchudda Reddy, N.
Athavan, A. Atienza, R. Atkins, J. Atkinson, K. Atkinson, L. Attreo, E. Au, G. Au, C. Aube, R. Aubin, J. Auch, D.
Aucoin, P. Aucoin, A. Auger, B. Auger, D. Auger, L. Auger, P. Auger, G. Augustine, C. Aular, C. Austin, L. Austin, R.
Austin, F. Avery, S. Avery, M. Avila, C. Aviles, O. Awodein, A. Ayasse, W. Ayles, A. Ayoub, J. Ayub, F. Azam, A.
Babiarz, O. Babiker, L. Babstock, K. Babu, C. Bachelder, C. Bachelet, C. Bachman, W. Bachmeier, 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, L. Bai, D. Baichev, D. Baier, J. Baier, N. Baier, M. Bailer, R. Bailer, B. Bailey, J. Bailey, K.
Bailey, S. Bailey, T. Bailey, M. Baillie, B. Bain, E. Bain, C. Baird, B. Bairstow, D. Baisley, D. Bak, L. Bakaas, A. Baker,
C. Baker, D. Baker, J. Baker, R. Baker, F. Bakita, D. Bakkar, J. Balacang, A. Balajadia, M. Balan, B. Balaski, B.
Baldonado, J. Baldonado, C. Baldwin, G. Baldwin, M. Baldwin, R. Baldwin, M. Baleja, I. Balicanta, J. Balkam, C.
Ball, D. Ball, G. Ball, P. Ball, T. Ball, J. Ballard, G. Ballas, S. Ballas, B. Balog, D. Balogoum, D. Balson, B. Baluyot,
R. Bama, L. Bamba, B. Bamber, R. Bamotra, R. Banack, J. Banak, M. Banas, D. Banash, J. Banawa, N. Banerjee,
R. Banfield, S. Banfield, O. Bango, J. Banks, L. Banks, C. Ban-Nelson, R. Bannerholt, B. Bannis, C. Bantaya, R.
Barabe, D. Barber, G. Barber, J. Barbour, L. Bardoel, K. Barham, M. Bari, M. Barilea, R. Barker, S. Barker, A. Barley,
C. Barnes, D. Barnes, M. Barnes, N. Barnes, V. Barnes, B. Barnett, D. Barr, S. Barr, E. Barreto, C. Barrett, T. Barrett,
R. Barrett, T. Barretto, S. Barriault, C. Barrie, D. Barron, K. Barron, R. Barron, L. Barros, D. Barry, A. Barstad, G.
Bartel, P. Barter, B. Bartlett, C. Bartlett, J. Bartlett, M. Bartlett, C. Bartman, D. Bartman, M. Bartman, J. Basabe,
K. Basarab, N. Basi, J. Basilan, R. Basile, L. Basines, P. Bass, S. Basso, C. Bast, A. Bastardo, C. Bastien, S. Basu,
M. Batac, S. Batarseh, B. Bate, C. Bateman, M. Bateman, P. Bateman, T. Bateman, G. Bates, D. Bath, L. Bath, S.
Batina, M. Batovanja, D. Batt, U. Batta, R. Batten, C. Battrum, B. Battyanie, J. Batuyong, D. Bauer, R. Bauer, T.
Bauld, C. Baumgardner, J. Baxter, D. Bayley, F. Bayuk, A. Bazowski, B. Beach, A. Beacon, W. Beals, C. Beaman, J.
Beamish, D. Bean, G. Bean, R. Bear, C. Beaton, D. Beaton, N. Beaton, G. Beaton, A. Beattie, C. Beattie, S. Beattie,
E. Beatty, S. Beauchamp, C. Beaudoin, J. Beaudoin, R. Beaudoin, B. Beaulac, J. Beaulieu, M. Beaulieu, L.
Beaunoyer, F. Beaver, K. Beazer, D. Bechtel, N. Beck, C. Becker, H. Becker, R. Becker, R. Beckner, S. Beckow, L.
Bedard, D. Bedell, A. Bedi, G. Bedi, M. Bednarchuk, S. Beebe, T. Beebe, M. Beeks, C. Beeler, K. Befus, K. Begg, W.
Behnke, J. 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, N. Bell, R. Bell, J. Bellavance, J. Beller, M. Beller, E.
Bellerose, A. Bellettini, J. Belliveau, A. Bellows, C. Bellows, S. Belseck, M. Belzile, D. Belzil-Pittman, M.
Bembridge, A. Bempong, A. Bendahmane, K. Bendahmane, C. Bender, R. Benedictson, S. Beniwal, M. Benko, D.
Benn, T. Benn, K. Benner, C. Bennett, D. Bennett, E. Bennett, J. Bennett, N. Bennett, R. Bennett, S. Bennett, A.
Benoit, G. Benoit, P. Benoit, C. Benson, M. Benson, R. Benson, A. Benson- Bartko, J. Bent, A. Bentley, R. Bentley,
T1
J. Benyon, J. Berdan, J. Beresford, C. Bereznicki, D. Berg, L. Berge, K. Bergen, O. Bergeron, J. Bergeson, M.
Bergeson, B. Bergley, J. Bergsma, D. Berlinguette, H. Berlinguette, J. Bernardin, D. Bernardo, T. Berner, J. Bernier,
K. Berreth, R. Berry, W. Berscht, D. Bershadsky, S. Bertelmann, G. Bertolin, A. Bertrand, B. Bertrand, J. Bertrand,
B. Berube, C. Best, J. Best, C. Betancur Pelaez, C. Bettany, T. Betteridge, S. Bettinson, W. Bewski, B. Beyer, J.
Beytell, S. Bezpalchuk, J. Bezruchak, M. Bezugley, A. Bhadauria, A. Bhaduri, 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, B. Bill, L. Billard, T. Billard, J. Bilous, J. Bilsky, W. Binda, M. Binder, B. Binns, C. Bint,
R. Bintz, A. Bird, T. Bisbing, 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, J. Blachford, A. Black,
B. Black, C. Black, J. Black, K. Black, R. Black, D. 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, B. Blakney, D. Blanchard, G. Blanchard, T. Blanchard, R. Blanchett, K. Blanchette, A. Blanco, G.
Blanco, U. Blanco, W. Blanco, S. Blaydes, K. Blencowe, J. Blesa, M. Blinkhorn, R. Blonar, R. Blondin, P. Bluemke,
J. Blume, C. Blyan, C. Boadas Salazar, J. Bobbett, H. Bocalan, D. Bochek, R. Bock, G. Boddy, J. Bodell, R. Bodell,
S. Bodell, A. Bodnar, K. Bodnar, J. Bodnarchuk, V. Bodnarchuk, B. Bodner, G. Bodner, D. Bodoano, D. Boehmer, D.
Boettcher, D. Boettger, M. Boggust, T. Bohach, A. Bohemier, J. Bohlken, N. Bohning, J. Bohorquez, G. Bohrson, J.
Boire, J. Boissoneault, C. Boisvert, M. Boisvert, D. Bokota, R. Boksteyn, S. Bolduc, C. Boleski, C. Bolger, G. Bolin,
D. Bolster, B. Bolt, J. Bolt, G. Bolzon, J. Bonami-McRae, K. Bond, N. Bond, S. Bond, T. Bond, E. Bondarenko, T.
Bondaruk, C. Bonebrake, A. Bonilla, E. Bonnefon, C. Bonogofski, A. Bonwick, T. Bonwick, R. Booker, S. Booker, P.
Booklall, J. Boomgaarden, A. Boone, B. Boone, C. Boos, K. Booth, B. Borbely, A. Borbon, K. Bordeleau, R. Borg, C.
Borgel, O. Borghesan, C. Borgland, J. Borkowski, 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, D. Bouchard, L. Bouchard, T. Bouchard, J. Bouchard
Lacoste, C. Boucher, T. Boucher, K. Boudreau, J. Boudreault, K. Bougie, B. Boulton, J. Boulton, T. Bouma, J.
Bounds, C. Bourassa, L. Bourassa, R. Bourassa, S. Bourassa, T. Bourassa, J. Bourgeois, C. Bourlon, D. Bourque, D.
Bourquin, S. Bourrie, C. Boussougou Mayagui, C. Boutier, C. Boutilier, M. Boutilier, C. Bowal, M. Bowal, C.
Bowditch, D. Bowen, J. Bowen, 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, J. Boxer, D. Boyarski, T. Boyce, R. Boyd,
J. Boyde, L. Boyde, C. Boyer, A. Boyes, R. Boyko, V. Boyko, D. Boyle, N. Boyle, L. Boyle, D. Bradbury, K. Bradbury,
A. Bradley, B. Bradley, P. Bradley, P. Bradner, J. Bradshaw, C. Bradt, M. Brady, C. Bragg, J. Bragg, L. Bragg, S.
Braithwaite, J. Brake, N. Brake, S. Brake, T. Brake, T. Branch, J. Branderhorst, J. Brannick, B. Brant, D. Brant, E.
Brant, P. Brar, C. Brassard, M. Brataschuk, K. Bratt, K. Brattebo, R. Brattston, C. Brausen, M. Brautigam, K. Bravo,
L. Bravo, J. Brawn, T. Bray, A. Brazeau, J. Breau, W. Brebant, G. Brecht, M. Brecht, D. Bredy, D. Breen, M. Breen,
S. Breitkreuz, B. Brekke, E. Brekke, D. Bremner, L. Brennan, M. Brennan, B. Brenton, C. Brenton, J. Brenton, R.
Brenton, 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, M. Brietzke, C. Briggs, G. Briggs, M. Briggs, J.
Bright, L. Brinkworth, S. Brinson, C. Brisebois, L. Brisebois, G. Brisseau, P. Britton, S. Britton, J. Brock, M. Brock,
K. Brocke, A. Broderick, D. Broderick, S. Broderson, D. Brodziak, E. Broidioi, K. Bromley, J. Bronkhorst, G. Bronson,
D. Brooks, J. Brooks, R. Brooks, S. Broomfield, G. Brophy-Maclean, K. Brosowsky, T. Brosseau, K. Brost, C.
Brousseau, C. Brow, N. Brow, A. Brown, B. Brown, C. Brown, D. Brown, E. Brown, G. Brown, J. Brown, K. Brown,
L. Brown, M. Brown, N. Brown, P. Brown, R. Brown, T. Brown, W. Brown, S. Brown, D. Brownrigg, J. Bruce, R.
Bruce, L. Bruchanski, A. Brucker, R. Brue, K. Bruggencate, F. Brugger, V. Brule, S. Brulotte, N. Brummitt, R.
Brundige, K. Bruner, A. Brunet, M. Brunet, M. Brunette, M. Brushett, R. Bryan, B. Bryant, L. Bryant, P. Bryant, R.
Bryant, T. Bryant, G. Brydges, T. Brydges, E. Bryenton, H. Bryenton, B. Bryks, J. Bryla, M. Bryson, S. Bryson, G.
Buchan, J. Buck, D. Buckley, G. Buckshaw, T. Budd, N. Budden, B. Budgell, R. Budzen, R. Bueckert, M. Buffett, W.
Bugiak, J. Buholzer, S. Bukhari, S. Bulger, R. Bullen, T. Bullen, K. Bulley, I. Bulloch, J. Bullock, D. Bumstead, G.
Bungay, L. Bungay, Q. Bunten-Walberg, B. Bunz, D. Burak, T. Burchenski, A. Burden, J. Burdett, C. Burge, D.
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, M. Bursey, A. Burt, B. Burt, T. Burt, G. Burton, J. Burton, K. Burton, M. Burton,
N. Burton, R. Burton, T. Burton, W. Burton, R. Busato, K. Bush, D. Bushey, T. Bushie, G. Bushore, N. Bussiere, J.
Bustamante, M. Butchart, K. Butcher, C. Butler, D. Butler, H. Butler, I. Butler, J. Butler, M. Butler, R. Butler, T. Butler,
B. Butt, K. Butt, Q. Butt, R. Butt, S. Butt, T. Butt, M. Buttigieg, K. Butts, R. Butts, P. Buxton, W. Bykewich, J. Byrne,
M. Byrne, T. Byrnell, J. Byrtus, I. Byvald, O. Byvald, L. Cabatuando, A. Cabral, J. Cachene-Clark, K. Cadieux, T.
Cadieux, G. Cahoon, B. Cain, A. Caines, H. Cairns, E. Caissie, W. Calabio, B. Calder, L. Calder, J. Calderon, J.
Caldwell, P. Caldwell, C. Caleffi, D. Callander, C. Callihoo, P. Callin, R. Calliou, M. Camargo, N. Cambridge, S.
Cameron, A. Campbell, B. Campbell, C. Campbell, D. Campbell, E. Campbell, K. Campbell, P. Campbell, S.
Campbell, N. Campbell, W. Campbell, A. Campeau, N. Campeau, W. Campeau, A. Campos, M. Canchica, G. Cane,
R. Canelon Oyarzabal, J. Canning, M. Canning, R. Canning, J. Cannon, E. Cantlon, J. Cantwell, M. Cao, A.
Caouette, D. Caouette, K. Cap, M. Capitaneanu, A. Caplette, L. Cappelle, J. Capstick, M. Capstick, B. Carabin, G.
Carde, A. Cardenas, F. Cardinal, J. Cardinal, L. Cardinal, R. Cardinal, W. Cardinal, M. Carew, W. Carey, D. Carleton,
T. Carleton, K. Carlos, F. Carlos Sanchez, J. Carlson, W. Carlson, D. Carnes, A. Carnochan, A. Caron, D. Caron, J.
Caron, R. Caron, S. 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, E. Cartaya, D. Carter, E. Carter, I.
Carter, J. Carter, K. Carter, N. Carter, R. Carter, S. Carter Hicks, C. Cartier, X. Cartron, J. Cartwright, S. Carty, D.
Casavant, G. Case, P. Cashin, E. Cassell, D. Cassidy, T. Cassidy, J. Cassivi, L. Casson, F. Castellanos, A. Castillo, K.
Castle, C. Castro, J. Castro, N. Catley, L. Catto, J. Cauchie, D. Cavacciuti, A. Cavanagh, D. Cavers, C. Cayer, C.
Celis, M. Celis, A. Centeno, S. Cervantes, B. Chaba, D. Chadwick, 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, D. 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, H. Chaouach, 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, M. Chaudhry, R. Chaulk, D. Chauvet, J. Chaval, S. Chavda, D. Chavez, M.
Chawla, M. Chayko, T. Chayko, C. Chaytor, M. Chaytor, P. Chaytor, M. Chechile, S. Checkley, W. Cheladyn, B. Chen,
C. Chen, H. Chen, S. Chen, T. Chen, X. Chen, Z. Chen, C. Cheng, J. Cheng, N. Cheng, D. Chenier, N. Cheraghi, Z.
Cherniawsky, M. Chernichen, T. Cherry, D. Chervenkov, O. Chervyakova, B. Chester, J. Chester, A. Chesterman, D.
Chetcuti, A. Cheung, K. Cheung, W. Cheung, L. Cheveldeaw, B. Cheyne, H. Chhokar, B. Chhualsingh, F. Chiasson,
B. Chichak, K. Chichak, D. Chick, T. Chick, B. Chicoine, D. Chidley, K. Chikowski, D. Childs, S. Childs, K. Chilibeck,
A. Chin, S. Chin, Y. Chin, R. Chipchura, T. Chipiuk, M. Chiplin, A. Chisholm, B. Chisholm, T. Chisholm, P. Chiu, R.
Chmilar, D. Choi, J. Cholka, R. Chong, P. Choo, B. Chorney, M. Chorney, C. Chornohos, C. Chorostecki, S. Choudhury,
R. Chowdhury, S. Chowdhury, G. Choy, J. Choy, A. Chretien, L. Christensen, R. Christensen, T. Christensen, J.
Christian, N. Christian, R. Christian, S. Christiansen, D. Christianson, M. Christianson, D. Christie, R. Christie, S.
Christie, T. Christie, A. Chu, C. Chua, R. Chubaty, G. Chubbs, D. Chudobiak, V. Chui, H. Chung, P. Chung, H. Church,
C. Churchill, D. Churchill, G. Churchill, J. Churchill, J. Churko, D. Chute, K. Chychul, O. Chyon, V. Cimon, K. Cisse-
Banny, W. Clapperton, T. Clare, A. Clark, C. Clark, J. Clark, K. Clark, R. Clark, T. Clark, B. Clarke, J. Clarke, K. Clarke,
L. Clarke, M. Clarke, R. Clarke, S. Clarke, W. Clarke, C. Clarkson, D. Clarkson, W. Clarkson, S. Clavette, G. Clegg,
J. Clelland, T. Clelland, R. Clemit, R. Clemmer, J. Clevenger, C. Closs, Z. Closter, A. Clouston, J. Clouter, J.
Clowater, G. Clowe, M. Cnossen, J. Coates, R. Coates, T. Coates, E. Cobaj, D. Coburn, D. Coccimiglio, M. Cochet,
B. Cochrane, J. Cochrane, D. Cockerill, F. Codd, E. Code, A. Codner, C. Codner, K. Codner, C. Cody, R. Coen, J. Coers,
L. Colborne, M. Colbourne, A. Cole, B. Cole, M. Cole, P. Cole, A. Coles, K. Coles, M. Coles, C. Colina, L. Collard, P.
Colley, D. Collicutt, M. Collie, G. Collings, B. Collins, J. Collins, M. Collins, N. Collins, O. Collins, R. Collins, S.
Collins, C. Collinson, A. Collison, G. Collison, A. Collyer, E. Comeau, J. Commance, K. Compagnon, W. Compagnon,
C. Compton, Q. Conacher, W. Conacher, A. Connell, E. Connell, M. Connell, M. Connellan, G. Connors, D. Conrad,
B. Conroy, S. Constant, D. Conway, M. Conway, P. Conway, D. Conybeare, D. Cook, K. Cook, L. Cook, N. Cook, S.
Cook, C. Cook, G. Cook, A. Cooke, G. Cooke, H. Cooke, K. Cookson, L. Cookson, J. Coolen, R. Coolen, J. Coombs,
K. Coombs, L. Coonan, L. Cooper, M. Cooper, C. Copeland, N. Copeland, R. Copland, R. Coppard, D. Corbett, "N.
Corbett, ", J. Corcoran, M. Corell, E. Coreman, C. Corkish, I. Cormier, S. Cormier, V. Cornejo, D. Cornish, R. Cornish,
S. Correll, C. Corrigan, D. Corrigan, R. Corrigan, C. Corry, S. Corson, P. Corticelli, C. Corzo De Canchica, G. Cossani,
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 9,709
strong
DIVERSITY. TALENT.
EXPERTISE.
To develop people to work together to create
value for the Company’s shareholders by
doing it right with fun and integrity.
H. Costello, S. Costello, J. Costello, J. Costigan, B. Cote, C. Cote, E. Cote, G. Cote, J. Cote, A. Cote Simard, E.
Cotten, L. Cottreau, L. Coulibaly, S. Coulibaly, D. Coull, K. Coulombe, J. Courchene, R. Courchesne, B. Courtney, T.
Courtney, P. Courtoreille, S. Courtoreille, T. Courtoreille, D. Courts, P. Cousin, J. Cousins, M. Cousins, P. Covell, E.
Cowan, K. Cowan, K. Cowger, I. Cowie, B. Cox, G. Cox, J. Cox, K. Cox, R. Cox, E. Cozicor, N. Crabb, R. Craft, J.
Craftchick, C. Craig, D. Craig, G. Craig, R. Craig, H. Craigie, K. Cramb, P. Cramb, S. Cramb, S. Cramm, M. Crane, A.
Crawford, H. Crawley, J. Crawley, G. Crayford, N. Cressey, L. Cressman, R. Crichton, P. Crisby, C. Critch, J. Critch,
N. Critch, D. Crittall, A. Critten, W. Crockford, A. Croft, S. Croft, C. Crook, G. Crooks, D. Crosley, T. Crosley, B. Cross,
C. Cross, R. Cross, T. Cross, S. Croteau, K. Crouser, T. Crouser, C. Crowe, S. Crowe, D. Crowle, R. Crowle, E.
Crowley, P. Crozier, D. Crum, K. Crutchley, C. Cruz, J. Cruz, A. Csabay, S. Cseke, P. Cudak, E. Cuello, H. Cui, J. Cullen,
M. Culligan, E. Cullimore, A. Cunanan, A. Cunningham, D. Cunningham, R. Cunningham, S. Cunningham, E. Cupac-
Cingel, J. Curran, S. Curran, S. Currie, R. Currier, B. 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, M. Czerwinski, K. d'Abadie, A. Dabrowski, M. Dacillo-Basallajes, F. Dadashov, R. Dadey, M.
Dadi, G. Dafoe, J. Dafoe, W. Dagley, A. Dahmani, J. Dai, J. Daigle, B. Daignault, P. Dale, D. Dalgarno, L. Dalgetty-
Rouse, G. Dallaire, J. Dallaire, B. Dalley, G. Dalley, M. Dalton, G. Daly, G. Dalziel, D. D'Amour, 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, M. D'arcangelo, A. Dareichuk, L. Dareichuk, V. Darel, E.
Dargatz, C. Daria, M. Darling, C. DaRosa, S. Darrah, K. Darvill, F. Daub, J. Daugherty, D. Dave, M. Dave, C. Davey,
G. David, L. David, P. 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, P. Davison,
B. Davis-Sorochuk, D. Dawe, J. Dawe, K. Dawe, S. Dawe, J. Dawson, R. Dawyduk, C. Day, D. Day, T. Day, J. Daye,
V. Daze, M. de Chavez, M. De Ga, H. de Graaf, S. De Graaf, S. De Jaham, R. De Jesus, R. de Jong, R. De Leeuw,
B. De Lorenzo, R. de Ruiter, V. de Ruiter, A. De Sousa, J. de Werk, B. de Winter, C. de Wit, B. de Witt, B. Deacon,
I. Deaconu, P. Deagle, M. Dean, R. Dean, A. Dearaway, G. Dearden, C. Deaver, J. deBalinhard, T. Debler, S.
Debnath, D. Deboer, R. deBoer, W. DeBona, S. DeBruycker, 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, J. DeCoste,
W. Dedam, E. Dee, N. Deeney, L. Deep, M. Deering, D. Defoort, L. Defoort, S. DeFord, M. Degenstien, S. Degroot,
B. DeHaan, A. Deibert, E. Deisting, R. Deitz, R. DeJong Dyck, L. Delaire, I. Delaney, P. Delany, E. DeLaRonde, J.
Delaurier, M. Delfin, M. Delorme, C. DeMone, R. DeMott, C. Dempsey, S. Dempsey, M. Denault, D. Deneau, D.
Denney, G. Denney, S. Dennis, D. Dennison, S. Denny, C. Denslow, J. Dent, S. d'Entremont, H. Derakhshan, D.
Derbyshire, J. Derix, B. Derochie, M. Derry, A. Desai, C. Desai, D. Desai, G. Desai, P. Desai, R. Desai, S. Desai, M.
Deschambeau, T. Deschamps, D. Deschenes, A. Desharnais, V. Deshpande, D. Desjardins, C. Desjardins-
Knowlden, G. Desjardins-Knowlden, C. Desjarlais, D. Desjarlais, C. Desmarais, J. Desnoyers, M. Desormeau, L.
Despins, D. Dessario, M. Detta, P. Deutcheu, K. Deutsch, A. Deutscher, S. Deval, B. Devereux, L. Devey, N. Devlin,
J. DeVries, T. Dew, C. Dewar, J. Dewar, T. Dewhurst, D. Dey, K. Deyaegher, K. Deyan, M. Deyan, G. Dhaliwal, H.
Dhaliwal, M. Dhaliwal, P. Dhalwala, B. Dhanesha, P. Dhanjal, J. Dharamsi, M. Dhariwal, M. Dhere, B. Diabagate,
K. Diallo, B. Diamond, D. Diaz, L. Diaz, M. Diaz, K. Diaz Garcia, L. Dick, R. Dicken, K. Dickey, A. Dicks, E. Dicks, J.
Dicks, C. Dickson, F. Dickson, G. Dickson, S. Didyk, J. Diederich, P. Diggle, S. Diggle, M. Diiorio, I. Dikau, E.
Dillabough, R. Dillman, K. Dilts, A. Dimapilis, X. Ding, Y. Ding, M. Dingley, G. Dingwell, H. Dinn, R. Dinn, K. Dinney,
P. Dion, S. Dionne, R. Diputado, M. Dirk, S. Dirk, T. Ditchburn, E. Ditzler, A. Dixit, C. Dixon, D. Dixon, R. Dixon, T.
Dixon, D. Dixson, K. Do, M. Doak, W. Dobchuk, C. Dobek, G. Dobek, L. Dober, C. Dobson, L. Dobson, S. Dobson, R.
Docksteader, L. Dodd, R. Dodd, P. Dodsworth, M. Doepel, R. Doering, J. Doetzel, A. Doherty-Snelgrove, J. Doiron,
K. Doiron, G. Dolan, S. Dolhanty, K. Doll, D. Dolynchuk, D. Doma, G. Doma, G. Domalain, R. Domazet, B. Dombrova,
M. Dombrova, D. Domin, S. Dominguez, K. Donahue, K. Donald, E. Donaldson, S. Donaldson, R. Donaleshen, M.
Dong, J. Donohoe, J. Donovan, N. Donovan, C. Doo, J. Doonanco, S. Dorer, A. Dorey, M. Dorocicz, J. Dorusak, A.
Dosanjh, I. Dosso, M. Doty, M. Doucet, D. Doucette, K. Doucette, P. Douglas, J. Douglas, T. Dove, R. Dow, S. Dow,
A. Dowd, J. Dowd, E. Dowell, J. Dowhay, M. Dowman, P. Downes, A. Downey, D. Downey, J. Downey, P. Downey,
A. Downs, R. Doyer, G. Doyle, L. Doyle, R. Drainville, S. Drake, P. Drapeau, G. Draper, K. Draper, T. Draper, W.
Draper, J. Dreaddy, S. Drebit, K. Dreger, C. Drescher, D. Dresser, D. Dressler, C. Drevant, B. Drew, D. Drew, A.
Driemel, A. Drier, S. Driscoll, T. Driscoll, E. Drolet, R. Drolet, R. Drosu, S. Drouin, M. Drouin Coomber, A. Drover, B.
Drover, C. Drover, R. Drover, R. Drummond, C. Drury, D. Drury, S. Drysdall, P. D'Souza, V. D'Souza, C. Du, M. Du, M.
Du Preez, C. Duane, R. Duarte, N. Dube, R. Dube, T. Dube, A. Dubetz, T. Dubie, G. Dubois, J. Dubois, L. DuBois, J.
Dubuc, D. Duby, M. Ducey, R. Ducharme, S. Ducharme, P. Duchesnay, J. Duchscherer, J. Duczek, P. Duda, S.
Dudley, L. Dueck, R. Dueck, G. Duff, C. Duffett, K. Duford, E. Dufour, P. Dugay, C. Duggan, W. Duggan, D. Duguid,
A. Duhaime, 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. Duncan, B. Dunn, D. Dunn, J. Dunn, P. Dunn, R. Dunn, S. Dunn, J.
Dunnigan, C. Dunsmore, J. Dunsmuir, D. DuPerrier, D. Duplessie, D. Dupuis, K. Dupuis, J. Durdle, A. Durham, J.
Duris, K. Durocher, J. Dutchak, J. Duthie, O. Dutka, N. Duval, R. Duval, B. Dwyer, C. Dwyer, R. Dwyer, D. Dybala,
J. Dybala, A. Dyck, B. Dyck, C. Dyck, J. Dyer, E. Dyjur, A. Dyke, L. Dyke, R. Dyson, B. Dzirasah, K. Dzwonek, B. Eagle,
J. Eagleson, B. Eales, G. Earl, R. Earl, J. Easthope, B. Eastman, J. Eastman, J. Easton, M. Easton, K. Eberle, R.
Ebuna, G. Ecker, E. Edeonu, D. Edgington, A. Edmunds, J. Edmunds, A. Edoukou, J. Edoukou, D. Edwards, J.
Edwards, M. Edwards, P. Edwards, T. Edwards, T. Eeuwes, S. Effiong, A. Effray, T. Egan, L. Egeland, R. Eggen, C.
Eggleton, A. Egresits, C. Ehnes, C. Ehresman, I. Eichelbaum, B. Eitzen, D. Ekdahl, J. Ekelund, C. Ekpekurede, S.
Ekstrom, R. Elaschuk, I. Elgarni, M. Elgarni, M. El-Harakeh, D. Elia, T. Elias, M. Elias-Neira, K. Elladen, P. Ellingson,
B. Elliott, D. Elliott, H. Elliott, J. Elliott, R. Elliott, S. Elliott, D. Ellis, K. Ellis, S. Ellis, C. Ellsworth, E. Ellsworth, K.
Ellsworth, A. Elmobarik, M. Elms, M. Eloursa Escanela, O. El-Sayed, E. Elson, J. Elson, T. Ely, C. Emberley, V.
Embleton, H. Emery, D. Emond, J. Engel, K. Engelking, J. Engen, R. Engler, T. Engler, J. English, M. Enns, R. Enns,
J. Entz, M. Entz, R. Ephgrave, J. Epp, T. Epp, J. Erasmus, S. Erb, D. Ereaut, B. Eresman, C. Erfle, B. Erickson, S.
Erickson, N. Erixon, M. Erl, M. Ernst, K. Eroglu, P. Ersh, C. Erskine, D. Ertmoed, P. Escalona, P. Escobar, L. Eshaq, N.
Eskandar, G. Eskandari, M. Espejo, R. Espenido, L. Espie-Winsor, A. Espindola, R. Esslemont, B. Estey, O. Estrada,
J. Etcheverry, D. Etherington, S. Etherington, G. Etti, A. Evans, D. Evans, R. Evans, T. Evans, R. Evasco, K.
Evdokimoff, J. Eveleigh, L. Eveleigh, S. Eveleigh, A. Everson, C. Eves, K. Ewach, J. Ewald, J. Ewen, R. Ewing, Z.
Ezeh, V. Ezeronye, L. Faber, T. Fabrick, R. Faechner, E. Faichney, B. Fairbairn, B. Fairey, S. Fairfield, M. Faiz, S. Faizal,
S. Fallahi, Y. Fang, D. Fanning, H. Farah, A. Faria, S. Farn, D. Farney, M. Farokhshad, A. Farquhar, G. Farrell, T.
Farrell, D. Farrell, R. Farrer, T. Farrer, D. Farrow, S. Farrow, S. Faruqi, W. Faryna, B. Fast, R. Fast, S. Fast, A. Faucher,
C. Faucher, S. Faucher, J. Faulkner, 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, E. Feely, J. Feener,
D. Fehr, B. Feil, D. Feland, I. Feland, J. Feland, D. Feller, R. Feltham, E. Fender, M. Feng, 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, A. Fernandez, E. Fernandez, J. Fernandez, L.
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J. Fewer, V. Fiacco, D. Fichter, C. Ficko, B. Field, M. Fielden, J. Fielding, K. Fielding, M. Fielding, W. Fielding, B.
Fifield, C. Filewych, C. Filgate, I. Filipescu, M. Filipponi, D. Fillier, T. Fillmore, B. Finch, 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, J. Fish, C. Fisher, D. Fisher, L. Fisher, B. Fitzgerald, C. Fitzgerald,
S. Fitzner, S. Fitzpatrick, K. Flack, M. Flahr, C. Flamont, J. Flamont, D. Flannery, B. Fleck, M. Flegel, A. Fleming, D.
Fleming, S. Fleming, T. Fleming, N. Flemming, J. Fletcher, L. Fletcher, P. Flett, R. Flett, M. Flette, B. Flockhart, 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, H. Fong, Y. Fong, D. Fontaine, G. Fontaine, R. Fontaine, B. Foord, L. Foote, R. Foran,
D. Forbes, M. Forbes, D. Forbister, A. Forcade, G. Ford, R. Ford, T. Ford, W. Ford, J. Foreman, B. Forest, L. Forget,
D. Forgie, B. Forman, D. Forman, L. 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, B. Foster, 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, H. Fowell, G. Fowler, J. Fowler, D. Fox, J. Fox, M. Foxton, S. Foxton, K. Fraboni, S. Fraino, F. Frame,
C. Frampton, C. France, J. France, R. France, D. Franche, O. Franchi, D. Francis, N. Franck, C. Frank, A. Frankiw, P.
Fransen, K. Franson, W. Franson, S. Franssen, R. Frasch, B. Fraser, C. Fraser, G. Fraser, K. Fraser, M. Fraser, R.
Fraser, L. Fraser, K. Frazer, C. Freake, G. Freake, R. Freake, B. Frechette, K. Frechette, S. Freckelton, A. Freeman, G.
Freeman, M. Freeman, J. Freer, U. Freiberg, E. Frejoles, J. French, J. Frese, L. Freund, K. Freyman, K. Friedrich, D.
Friedt, W. Friend, D. Friesen, F. Friesen, H. Friesen, J. Friesen, K. Friesen, M. Friesen, N. Friesen, R. Friesen, K. Frith,
A. Frizorguer, D. Frizzell, J. Froc, M. Froehler, C. Froude, S. Froude, A. Fry, T. Fryer, X. Fu, N. Fucile, C. Fudge, L.
Fudge, R. Fudge, K. Fujimoto, D. Fukushima, W. Fulkerson, J. Fuller, C. Fulowski, D. Fung, J. Fung, S. Fung-Yau, C.
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A. Gage, C. Gagne, D. Gagne, J. Gagnon, K. Gagnon, S. Gagnon, W. Gail, B. Galbraith, P. Gale, M. Galea, J. Galey,
R. Gallagher, F. Gallant, M. Gallant, R. Gallant, F. Gallardo, J. Galliott, M. Gallon, J. Galotta, B. Gamble, D.
Gamblin, C. Gamboa, L. Gamboa, F. Gan, A. Gandhi, P. Gandhi, V. Gandhi, J. Ganie, D. Ganske, B. Gantz, Y. Gao, V.
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Gardner, J. Gareau, R. Gareau, T. Gareau, R. Garg, V. Garg, K. Garland, A. Garneau, W. Garner, P. Garon, L. Garvey,
C. Garzon, C. Gascon, O. Gascoyne, K. Gaslard, L. Gates, J. Gatrell, S. Gatt, S. Gauchan, F. Gaudet, G. Gaudet, W.
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S. Gerow, E. Gervais, K. Gervais, M. Gervais, K. Gessner, T. Getchell, S. Getson, G. Getz, K. Getzinger, V.
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M. Giles, S. Giles, V. Giles, P. Gilhespy, D. Gill, J. Gill, K. Gill, L. Gill, M. Gill, N. Gill, R. Gill, S. Gill, J. Gillam, D.
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S. Glazier, R. Gleasure, R. Gleed, J. Glen, J. Glendenning, G. Glenn, D. Gliddon, D. Gloade, D. Glover, R. Glover, S.
T2
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. B. Jakulj, M. Jalali, G. Jaleel, L. Jama, M. Jama, S. Jamam, D. Jaman, A. Jambrosic, D. James, K. James, R.
James, S. James, W. James, R. Jamieson, T. Jamieson, J. Jamieson, M. Jamieson, S. Jamieson, D. Jamilano Jr.,
A. Janes, D. Janes, J. Janes, Z. Janosova-Den Boer, D. Jans, S. Jansky, S. Janssen, T. Janusc, A. Janzen, L.
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Jaschke, J. Jechow, W. Jellison, G. Jenkins, J. Jenkins, T. Jenkins, J. Jenner, R. Jenniex, S. Jenniex, D. Jennings,
A. Jensen, B. Jensen, D. Jensen, K. Jensen, L. Jensen, Q. Jensen, T. Jensen, V. Jensen, D. Jenson, K. Jentas, M.
Jeroncic, R. Jeronymo, T. Jervis, B. Jesso, C. Jesso, M. Jesso, T. Jessome, J. Jesson, S. Jevne, B. Jewell, P. Jia,
N. Jiang, Q. Jiang, S. Jiang, Y. Jiang, Z. Jiang, R. Jimeno, X. Jing, P. Jingar, K. Jivraj, R. 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, L. Johnston, M. Johnston,
N. Johnston, R. Johnston, A. Johnston, B. Johnstone, C. Johnstone, E. Johnstone, R. Johnstone, S. Johnstone, D.
Johnston-Watson, V. Jolliffe, J. Jonasson, A. Jones, B. Jones, C. Jones, D. Jones, E. Jones, G. Jones, K. Jones,
L. Jones, M. Jones, N. Jones, R. Jones, S. Jones, V. Jones, N. Jongkind, P. Joo, O. Joos, J. Jorawsky, D. Jordan,
M. Jordan, D. Jordison, B. Jorgensen, C. Jorgensen, D. Jorgensen, M. Jorgensen, L. Jorgenson Donahue, A. Jose,
D. Joseph, P. Joseph, V. Joseph, K. Joseph, A. Joshi, T. Joshi, U. Joshi, S. Josselyn, M. Jovic, D. Jowsey, M.
Juanerio, R. Jubinville, T. Juett, A. Junaid, J. Jung, S. Jung, C. Jungen, R. Jungkind, G. Junio, M. Junio-Read, C.
Jurgenliemk, K. Jurouloff, A. Kachra, C. Kada, L. Kada, T. Kadi, T. Kadikoff, L. Kadutski, G. Kadylo, C. Kaglea, R.
Kahanyshyn, A. Kaid, G. Kailas, H. Kakadiya, S. Kalbag, V. Kalbag, L. Kalinin, D. Kalinowski, J. Kallis, A. Kalmet,
D. Kalynchuk, A. Kamate, B. Kamath, A. Kamke, G. Kamon, A. Kamran, S. Kanarek, A. Kandasamy, S. Kandulva
Chakrapany, J. Kane, L. Kane, S. Kane, K. Kang, N. Kang, Z. Kanji, S. Kapeluck, Y. Karayan Moosafi, P. Karimi, R.
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C. Kaskiw, M. Kaspers, M. Kassim, A. Katebi, M. Kathan, D. Katnick, H. Katrip, A. Katyayan, J. Kaufman, S.
Kaushik, C. Kavalec, T. Kavalec, T. Kawadza, R. Kawano, K. Kay, O. Kay, G. Kaya, A. Kaye, J. Kaye, G. Kazimirowich,
M. Kealey, S. Kealey, R. Kean, E. Keane, J. Kearley, M. Kearley, R. Kearns, K. Keating, M. Keck, B. Keddie, R.
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, K. Keller, C. Kelley, C. Kellogg, E. Kellough, J. Kelloway, M. Kelloway, R. Kelloway, C. Kellsey,
C. Kelly, J. Kelly, M. Kelly, S. Kelsey, T. Kemmer, G. Kemp, S. Kempner, J. Kempton, R. Kendall, S. Kendall, C.
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D. Kidger, B. Kidmose, B. Kiedyk, C. Kiehn, K. Kieley, K. Kielt, L. Kiez, C. Kilback, D. Kilbreath, M. Kilcollins, C.
Killick, O. Kilo, B. Kim, H. Kim, R. Kim, D. Kimmie, M. Kinden, B. King, C. King, D. King, G. King, I. King, J. King, M.
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T. Kirchner, R. Kirk, D. Kirkham, L. Kirkpatrick, B. Kiss, K. Kiss, B. Kissel, M. Kissoon, F. Kitivi, B. Kiyawasew, C.
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D. Klause, R. Klautt, A. Klein, B. Klenk, R. Klimek, M. Klimkiewicz, E. Klitiris, J. Klotz, G. Kluthe, R. Klys, C. Knapper,
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K. Kramps, R. Kranitz, T. Kratz, W. Kraus, G. Krause, T. Krause, R. Krauss, R. Kravitz, C. Krawchuk, D. Krawec, J.
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R. Krishnamurthy, D. Krismer, B. Kristianson, N. Krochmal, R. Kroeker, K. Krogh, P. Krol, U. Krstic, R. Krueger, G.
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M. Kulkarni, C. Kully, B. Kumar, P. Kumar, R. Kumar, S. Kumar, V. Kumar, H. Kundert, C. Kung, D. Kunitz, J. Kuntz, P.
Kuppers, D. Kurek, M. Kureshi, M. Kurowski, K. Kurschenska, K. Kursteiner, D. Kurtz, R. Kurtz, F. Kurucz, J. Kushe,
D. Kusmiadji, G. Kusuma, B. Kutash, R. Kutz- Semeniuk, S. Kuzmak, F. Kuzmic, C. Kwan, J. Kwan, R. Kwiatkowski,
S. Kwiatkowski, A. Kwon, K. Kwong, T. Ky, K. Kyffin, D. Kyle, J. Kynock, R. Kynock, T. La Grange, D. Labby, J.
LaBossiere, A. Laboucan, J. Laboucan, R. Laboucan, T. Lacey, A. LaChance, N. Lachance, S. 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. Lafreniere, G. Lagace, M. Lagimodiere, O. Lagoke, A. Laguduva,
D. Laha, M. Laha, B. Lahoda, D. Lahoda, J. Lahoda, C. Lai, R. Lai, S. Lai, T. Lai, K. Laidler, A. Laing, R. Laing, S. Laird,
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Land, E. Lander, A. Landry, C. Landry, E. Landry, G. Landry, J. Landry, L. Landry, M. Landry, S. Landry, Y. Landry, X.
Landry-Pellerin, W. Landsburg, B. Lane, M. Lane, W. Lane, S. Lane, R. Lanfranchi, J. Langdon, K. Langdon, J.
Lange, L. Lange, N. Lange, O. Lange, S. Lange, S. Langford, W. Langford, T. Langill, C. Langpap, B. Lanh, R. Laniec,
C. Lanthier, L. Lanza, S. Lanza, C. Lapp, P. Lapp, S. Lapp, C. Lappin, M. Larade, G. Laramee, J. Larkin, J. Larochelle,
Glubish, M. Go, R. Go, J. Godin, K. Godin, D. Godwin, M. Goebel, C. Goeson, C. Gogol, J. Gogol, B. Gogowich, H.
Goldberg, D. Golden, A. Goll, D. Goll, P. Goll, M. Gomaa, R. Goman, E. Gomez, J. Gomez, C. Gomuwka, E. Gong, K.
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Gosse, M. Gosse, R. Gosse, T. Gosse, T. Gosselin, Y. Gosselin, K. Goudie, C. Goudreau, C. Gough, A. Gould, B.
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Govindarajan Prithivirajan, M. Govindaswamy Krishnamoorthy, M. Goyal, L. Goymer, J. Graca, N. Grace, R. Graf
Jr., L. Graff, D. Graham, J. Graham, M. Graham, P. Graham, S. Graham, T. Graham, C. Graham, I. Grandy, R. Grandy,
B. Granger, J. Granger, A. Grant, C. Grant, J. Grant, M. Grant, R. Grant, S. Grant, T. Grant, A. Graup, B. Gravel, R.
Gravell, T. Graveson, A. Gray, B. Gray, C. Gray, D. Gray, J. Gray, N. 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, T. Green, W. Green, C.
Greenawalt, D. Greenawalt, C. Greene, D. Greene, T. Greene, A. Greenfield, G. Greenwood, K. Greenwood, M.
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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, J.
Hardy, A. Hare, E. Harikumar, K. Harke, J. Harker, A. Harlal, D. Harley, L. Harley, E. Haroldson, G. Harper, R.
Harrietha, R. Harriman, A. Harris, B. Harris, C. Harris, J. Harris, M. Harris, S. Harris, C. Harrison, D. Harrison, N.
Harrison, R. Harsany, D. Hart, C. Hartery, C. Hartl, A. Harty, J. Harty, B. Harvey, D. Harvey, J. Harvey, K. Harvey, P.
Harvey, R. Harvey, S. Harvey, I. Hashi, H. Hashmi, K. Hasiuk, M. Hassan, O. Hassan, B. Hassen, 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, C. Hawkings, D. Hawkins, S. Hawryliw, A. Hawthorne, S. Haxton, N. Hay, S. Hay, D.
Hayashi, B. Hayden, C. Hayden, J. Hayden, J. Haydo, C. Hayduk, D. Hayes, M. Hayes, P. Hayes, K. Hayko, D.
Haynes, J. Haynes, L. Haynes, A. Hayward, M. Hayward, R. Hayward, T. Hayward, J. Hazin, J. He, S. He, T. He, Y.
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Heath, C. Heath, D. Heath, L. Heath, B. Heatley, D. Heavens, J. Heavens, S. Heawood, 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, T. Heidebrecht, M. Heigl, C. Hein, F. Hein, R. Hein, J. Heinen, R. Heinrichs, B. Heise, D. Heit, R. Heiz, R.
Helland, B. Helliker, A. Hellyer, R. Helyar, C. Hemington, D. Hemmelgarn, W. Hemminger, B. Hemstock, D.
Henderson, R. Henderson, W. Henderson, S. Henderson, E. Hendrickson, K. Hendrickson, S. Hendry, R. Henley, K.
Hennessey, A. Hennig, E. Henriquez, C. Henry, R. Henry, T. Henry, H. Henschel, D. Herauf, K. Herba, C. Herbst, W.
Hergott, B. Herman, J. Herman, W. Herman, A. Hernandez, G. Hernandez, M. Hernandez, P. Hernandez, L. Heron,
G. Herrebout, C. Herring, R. Herrington, D. Hertzsprung, D. Heshka, R. Heska, K. Heslop, A. Hess, B. Heugh, A.
Heuthorst, J. Hevey, B. Hewitt, J. Hewitt, M. Hewitt, T. Hewitt, C. Hewlett, J. Hewlett, K. Hewlin, A. Heydari Gorji,
C. Heywood, R. Hibbs, D. Hicke, P. Hickey, R. Hickey, B. Hicks, C. Hicks, R. Hicks, S. Hicks, O. Hidalgo, L. Hiebert,
R. Hiebert, M. Hiemstra, T. Hiemstra, E. Hietanen, R. Higa, J. Higdon, A. Higgins, J. Higgins, L. Higgins, M.
Higgins, R. Higgins, P. Higgitt, J. Higuerey De Sanchez, C. Hildahl, C. Hildebrand, T. Hildebrand, C. Hill, D. Hill, H.
Hill, J. Hill, K. Hill, R. Hill, T. Hill, B. Hillier, C. Hillier, D. Hillier, J. Hillier, M. Hillier, S. Hillier, T. Hillier, C. Hills, T.
Hills, D. Hillyard, R. Hilton, B. Hindmarch, T. Hindson, K. Hingley, W. Hinkle, T. Hinks, K. Hinton, N. Hinze, D.
Hiscock, J. Hitchens, D. Hitra, G. Ho, J. Ho, M. Ho, T. Ho, J. Hoare, R. Hoath, W. Hobart, A. Hobbi, J. Hobbs, R.
Hoda, C. Hodder, G. Hodder, J. Hodder, D. Hodge, G. Hodgins, R. Hodgins, D. Hodgson, A. Hoeg, A. Hoey, N. Hoey,
L. Hoff, N. Hoff, T. Hoff, M. Hoffart, R. Hoffman, M. Hofstrand, G. Hogan, S. Hogan, A. Hogg, J. Hogg, R. Hogg, J.
Hoilund, B. Holaki, D. Holik, A. Holland, K. Holland, M. Holland, C. Hollands, A. Hollebakken, I. Hollenbeck, P.
Hollett, D. Holley, D. Hollingshead, G. Holloway, J. Holloway, L. Holloway, J. Hollowell, C. Holman, D. Holman, R.
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J. Hooper, R. Hooper, A. Hope, P. Hopkins, S. Hopkins, Y. Hopkins, N. Hopner, C. Hopps, T. Hopwood, A. Hordy, D.
Horlick, R. Horn, T. Hornberger, K. Hornseth, B. Horobec, K. Horvath, M. Horvath, R. Horvath, J. Horyn, K. Hosker,
B. Hossain, M. Hossain, T. Hou, S. Houck, C. Houle, E. Houlihan, A. House, G. House, P. House, R. House, T. House,
L. Houseman, G. Houston, P. Houston, K. Hovdebo, D. Howard, T. Howard, C. Howden, R. Howden, L. Howell, P.
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Hunter, S. Hunter, W. Hunter, M. Hupchuk, K. Hupp, K. Hurd, G. Hurley, S. Hurley, R. Hurtado, R. Hurtado Urdaneta,
M. Hurtaj, 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, E. Hutton, D. Huxley, A. Huynh, C. Huynh, M.
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D. Jaeger, A. Jaffer, M. Jahangiri, R. Jahanshahi, E. Jahelka, V. Jain, M. Jaindl, K. Jaji, R. Jakher, R. Jakubowski,
T3
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. A. Larocque, J. Larocque, E. LaRose, R. Larsen, J. Larson, P. Larson, R. Larson, B. Larsson, A. Laser, J. LaSha Pool,
C. Lassey, W. Latchuk, A. Latif, Z. Latif, C. Latimer, R. Latimer, M. LaTorre, P. Latus, J. Lau, S. Lau, B. Laughlin, P.
Laughman, P. Laurie, A. Laurie, K. Laurin, N. Laustsen, S. Laut, R. Lauze, J. Lauzon, D. Laventure, K. Laverty, V.
Laviano, B. Lavigne, J. Lavigne, C. Lavoie, D. Law, I. Law, C. Lawford, S. Lawlor, B. Lawrence, D. Lawrence, E.
Lawrence, L. Lawrence, R. Lawrence, S. Lawrence, W. Lawrence, Y. Lawrence, R. Lawrie, G. Lawson, J. Laya, A.
Layland, K. Layland, P. Layland, S. Layton, K. Layug, G. Lazaruk, S. Lazeski, T. Lazowski, L. Le, M. Le, N. Le, S. Le,
T. Le, V. Le, R. Le Manne, B. Leach, T. Leach, R. Leahy, C. Leamon, K. Leamon, L. Leamon, D. Leask, M. Lebas, C.
LeBlanc, E. LeBlanc, J. LeBlanc, R. LeBlanc, T. Leblanc, W. LeBlanc, P. LeBlond, C. Lebrun, S. LeBrun, S. Lebsack,
S. Leclair, G. Leclerc, G. Ledger, J. Ledoux, C. 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, M. LeForte, D. Lefrancois, D. Legault, K.
Legault, L. Legault, J. Legere, M. Legge, R. Legge, M. LeGrow, K. Lehal, B. Lehbauer, M. Lehouillier, S. Lei, P.
Leibel, T. Leibel, C. Leicht, S. Leithoff, R. Lemoine, Z. LeMoine, T. Lemon, R. Lendrum, P. Leniuk, P. Lennon, C. Lenz,
J. Lenzner, T. Leon, G. Leong, H. Leong, K. Lepage, S. Lepp, L. Leppaie, P. Lepper, Y. Lerner, E. Leroy, C. Leschinski,
G. Leslie, R. Leslie, S. Lester, B. Lesyk, K. Letby, M. Lethaby, 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, G. Lewis, J. Lewis, K. Lewis, P.
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Li, Q. Li, S. Li, W. Li, Y. Li, B. Liang, N. Liang, S. Liao, C. Liba, M. Liber, Z. Licastro, H. Lien, 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, S. Lindballe, K.
Linder, T. Lindley, E. Lindsay, D. Lindskog, D. Linfoot, A. Linggon, P. Linklater, N. Linnell, J. Linton, M. Liou-
McKinstry, R. Lipman, R. Liske, C. Little, G. Little, J. Little, S. Little, J. Littlechilds, H. Liu, J. Liu, L. Liu, T. Liu, W.
Liu, X. Liu, Y. Liu, J. Liu Prest, E. Liv, J. Lively, J. Livingston, S. Livingstone, C. Lizee, J. Llanos, R. Lloy, M. Lloyd, P.
Lloyd, Y. Lo, A. Lobban, A. Lobbes, G. Lobdell, J. Lochansky, F. Locke, R. Locke, A. Lockhart, L. Lockhart, N.
Lockhart, R. Lockhart, C. Loder, S. Loder, J. Lodoen, K. Loewen, S. Loewen, C. Lofstrom, C. Logan, M. Logan, S.
Logan, D. Loggie, R. Logozar, J. Lok, R. Loke, J. Lomada, K. Lomond, D. Londo, C. Long, D. Long, S. Long, Y. Long,
S. Longman, D. Longpre, S. Longson, C. Longston, I. Lonsbury, K. Loo, K. Lopez, M. Lopushinsky, D. Lord, N. Lord,
J. Loree, C. Lorenson, L. Lorentz, N. Lorentz, J. Lorette, K. Lorette, M. Lorincz, B. Lorinczy, K. Lorteau, M. Loshny,
J. Lotito, T. Lougheed, A. Loughran, J. Loukou, S. Lourido, W. Loutit, 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, K. Loyer, L.
Loyola, E. Lozano, C. Lozinski-Kumpula, A. Lu, J. Lu, M. Lu, W. Lu, G. Lucas, I. Lucas, J. Lucas, L. Luciow, T.
Lucksinger, B. Lucy, E. Ludwig, L. Luiken, C. Luk, K. Luk, K. Lukan, L. Lukey, C. Lumley, K. Lumley, W. Lundell, J.
Lundquist, K. Lundrigan, V. Lundrigan, E. Lunn, R. Lunn, J. Lunt, C. Lunzmann, K. Luo, X. Luo, M. Lupul, J.
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G. Lyall, K. Lyall, T. Lychuk, G. Lye, D. Lynch, K. Lynch, L. Lynch, R. Lynett, M. Lyon, W. Lyon, N. Lyons, R. Lyric, H.
Ma, N. Maawia, M. MacBeth, K. MacBride, K. MacComish, M. MacConnell, L. Macdaid, 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, T. Macdougall-
Sinclair, A. MacEachern, C. MacEachern, J. MacEachern, M. MacEachern, T. MacEachern, Y. Macedo, C.
MacFarlane, M. Macfarlane, K. MacGillis, K. Machado Rodriguez, S. MacHale, D. Machuk, R. Maciborski, J.
Maciejewski, T. Macijuk, C. MacInnes, A. MacInnis, B. MacInnis, S. MacInnis, L. MacIntosh, R. MacIntyre, T.
Macintyre, A. Mack, B. Mack, L. Mack, S. Mack, B. MacKay, C. Mackay, G. MacKay, K. MacKay, L. Mackay, S.
MacKay, R. Mackelvie, D. Mackenzie, G. MacKenzie, K. MacKenzie, M. MacKenzie, S. MacKenzie, T. Mackenzie,
B. MacKey, P. Mackey, S. Mackey, T. Mackey, A. MacKinnon, B. MacKinnon, J. MacKinnon, K. MacKinnon, P.
MacKinnon, R. MacKinnon, T. MacKinnon, P. Mackintosh, B. MacLaren, T. MacLaren, B. Maclean, C. MacLean, E.
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MacLellan, T. Maclellan, J. MacLennan, A. MacLeod, I. MacLeod, J. MacLeod, L. MacLeod, M. MacLeod, T.
MacLeod, W. MacLeod, C. MacLeod, H. MacMillan, N. MacMillan, A. Macneil, B. MacNeil, C. Macneil, J.
Macneil, K. MacNeil, B. MacNeill, A. MacNiven, W. MacPherson, C. MacPherson, S. Macquarrie, H. Macrae, M.
MacRitchie, T. MacVicar, B. Macwilliams, C. Madadi, J. Madathiparambil, A. Madhukar, R. Madigan, C. Madill,
H. Madlung, D. Madoche, G. Madsen, M. Maennchen, L. Maga, D. Maganga, J. Magbanua, D. Magee, S. Magill,
P. Magnan, D. Magnussen, D. Magnusson, M. Magnusson, J. Magpali, A. Magro, V. Magsila, D. Magson, R.
Maguet, D. Mah, M. Mah, R. Mah, K. Mahboobi, B. Mahe, T. Mailandt, M. Mailhot, E. Maillet, J. Maillet, M.
Mailloux, P. Mailloux, R. Mailman, J. Mainville, B. Maisey, D. Maisey, O. Maita, R. Maitripala, 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, S. Malcolm, H. Maldonado, M. Malech, P. Malhame, H. Malik, A. Malimban,
T. Malkova, J. Mallard, K. Mallard, S. Mallay, G. Mallette, T. Malley, D. Mallum, G. Malo, T. Maloney, D.
Malowski, A. Maltseva, G. Malvar, 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, S. Mann, G. Mann, J. Manning, J. Mansfield, D.
Manshanden, V. Mantey, A. Manthorne, E. Mantilla, G. Manuel, J. Manuel, L. Manzano Weffer, H. Maralli, M.
Maratovic, D. Marazzo, G. Marceau, A. Marcel, N. Marchand, F. Marchesan, M. Marchi, R. Marcichiw, N. Marcil,
A. Marcinkoski, T. Marcotte, L. Marcucci, N. Marcy, W. Margison, H. Maric, V. Maries, E. Marilao, S. Marin, P.
Marinzi, S. Marion, D. Mark, S. Markle, S. Markosyan, K. Markstrom, M. Markussen, P. Marolt, U. Maroney, B.
Marple, A. Marquardt, T. Marquis, D. Marr, K. Marriner, R. Marrington, C. Marriott, B. Marsh, C. Marsh, M. Marsh,
N. Marsh, P. Marsh, C. Marshall, S. Marshall, D. Marshall, S. Marshman, J. Marston, A. Martakoush, P. Martell,
L. Martens, S. Martens, A. Marter, B. Martin, C. Martin, D. Martin, J. Martin, M. Martin, R. Martin, S. Martin, T.
Martin, D. Martinat, S. Martinella, Z. Martinez, D. Martinez Gomez, O. Martis, D. Martyn, R. Martyn, M.
Martynuik, A. Martyshuk, M. Martyshuk, B. Martz, J. Maruniak, K. Mashayekh, R. Maskoni, B. Mason, K. Mason,
D. Massey, M. Massiah, K. Massick, A. Massicotte, P. Massicotte, B. Masters, M. Mata, 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, R. Mathieson, C. Mathiot, J. Matkowski, B. Matsalla, N.
Matsushita, T. Matsushita, A. Matthews, B. Matthews, C. Matthews, D. Matthews, E. Matthews, N. Matthews,
J. Matthiessen, R. Matychuk, P. Maurice, S. Maurice, N. Mavani, D. Mavridis, D. Mavuwa, A. Mawer, C. Maxsom,
J. Maxwell, R. Maxwell, A. May, K. May, R. May, C. Maye, J. Mayer, S. Mayer, R. Mayers, A. Maynard, W.
Maynard, K. Mayner, A. Mayo, B. Mayo, C. Mays, A. Mazur, C. Mazuryk, H. Mc Gee, D. McAlister, C. Mcallister,
D. McAllister, M. McAlpine, D. McArthur, K. McArthur, N. McBain, A. McBoyle, K. McBride, T. Mcbride, R.
McBrien, D. McCabe, G. McCabe, T. McCabe, J. McCaffrey, S. McCaffrey, R. McCallum, S. McCann, D. McCarry,
J. McCarthy, J. McCarty, D. McCarvill, K. McClary, D. McClelland, I. McClelland, B. McClure, B. McConachie, J.
McConnell, B. McCormack, C. Mccoy, S. McCracken, B. McCrady, K. McCrae, C. McCrea, J. Mccready, G.
Mccubbing, B. McCullough, C. McCullough, R. McCullough, A. McDaniel, C. McDonald, J. McDonald, K.
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K. McEachern, R. McEachnie, M. McElroy, P. McElwain, J. McEwen, W. McEwen, J. Mcfarland, C. McFarlane, M.
McFarlane, A. McFaul, B. McFaul, M. McGannon, F. McGaw, L. McGean, C. Mcgee, D. McGee, L. McGee, G.
McGinnis, P. McGinnis, G. Mcgonigal, C. McGovern, G. McGowan, M. McGowan, A. McGrath, C. McGrath, D.
Mcgrath, K. Mcgrath, L. McGrath, M. McGrath, T. McGrath, P. McGregor, T. McGregor, S. McGregor, J. McGuckin,
S. McHardy, L. McHugh, D. McIntosh, M. Mcintosh, A. McIntosh, G. 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, G. McKay, N. McKeachnie, S. McKee, T. McKee, W. McKellar, K. McKendry, N. McKendry, M.
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McKinney, J. Mckinnon, K. Mckinnon, S. McKinnon, R. McLachlen, M. McLane, C. McLaren, D. McLaren, M.
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McLellan, C. McLenaghan, M. McLenehan, C. McLeod, D. McLeod, I. McLeod, S. McLeod, T. McLeod, P.
Mcloughlin, E. McMahon, G. McMahon, L. McMahon, K. McMann, N. McManus, J. McMaster, R. McMaster, S.
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M. Meckelborg, M. Medhurst, I. Medina, N. Medina, A. Medley, D. Medlicott Lymburner, B. Medway, J. Meeks,
K. Meh, M. Mehaney, F. Mehdiyev, P. Mehrabi, N. Mehta, V. Mehta, C. Mei, D. Meier, C. Mejia, J. Mejia, B.
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Minhas Chapman, M. Minick, W. Minni, W. Minnie, W. Minns, J. Minor, A. Minty, A. Mir, S. Mir, T. Mir, W.
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T4
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D. Ober, J. Oberg, J. Oberholtzer, N. Obi, F. Obiri, Y. Oble-Karike, P. Oblozinsky, A. O'Brien, B. O'Brien, D. O'Brien,
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Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Wagner, J. Wagner, K. Wagner, N. Wagner, M. Wahl, N. Waite, F. Wajih, D. Wakaruk, L. Wakaruk, L. Wakefield,
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L. Zhu, W. Zhu, E. Zhuromsky, P. Zia, S. Ziadeh, A. Zielke, F. Zilahy, D. Zilinski, E. Zilinski, D. Zimmer, E. Zimmer, L.
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Smiegielski, C. Smillie, A. Smith, B. Smith, C. Smith, D. Smith, E. Smith, G. Smith, J. Smith, K. Smith, L. Smith, M.
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A. Sychak, K. Sydorko, C. Syed, D. Syed, J. Sykes, T. Sylvester, D. Sylvestre, G. Sylvestre, B. Symington, A.
Symons, M. Symons, T. Sypher-Michel, D. Syrnyk, N. Szalay, E. Szeto, C. Szmata, A. Szoke, C. Szpecht, D.
Sztukowski, D. Sztym, C. Szutiak, K. Szydlik, J. Ta, V. Ta, C. Tacadena, M. Tade, D. Taggart, A. Taghipour, P. Taiani,
M. Tainsh, D. Tainton, D. Tait, O. Tait, G. Tait, J. Taite, A. Tajik, D. Tajiri, D. Takala, S. Takala, G. Talati, S. Talati, C.
Talbot, J. Talbot, M. Talerico, C. Tallack, D. Tallas, B. Talma, K. Tam, N. Taman, B. Tamas, B. Tan, C. Tan, K. Tan, S.
Tan, M. Tanasescu, B. Tancowny, E. Tang, L. Tang, X. Tang, G. Tangonan, T. Tanigami, J. Tanner, H. Tansley, M.
Tapley, G. Tapp, C. Tarache, A. Tarasenco, C. Tardif, G. Tarditi, K. Targett, B. Tarkowski, M. Taron, D. Tarrant, B.
Tasek, J. Tatarin, N. Tavassoli, A. Taylor, B. Taylor, G. Taylor, J. Taylor, K. Taylor, L. Taylor, M. Taylor, N. Taylor, P.
Taylor, R. Taylor, S. Taylor, W. Taylor, C. Taylor, H. Taylor, B. Teare, C. Tearoe, M. Teeple, A. Tegnander, S. Tejpar, A.
Telan, M. Teleptean, R. Tellier, B. Temesgen, J. Temple, C. Templeton, 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, B. Thevarajah, W. Thew, R. Thibodeau, C. Thiessen,
J. Thiessen, L. Thiessen, T. Thiessen, W. Thijs, P. Thimaiah, S. Thind, M. Thoen, D. Thomas, E. Thomas, L. Thomas,
M. Thomas, N. Thomas, P. Thomas, S. Thomas, J. Thomas Cotton, 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, M. Thomson, P. Thomson, S. Thomson, T. Thomson, J. Thomson, W. Thomson,
K. Thorburn, T. Thorburne, W. Thorburne, J. Thorleifson, B. Thorn, A. Thorne, D. Thorne, L. Thorne, B. Thornhill, E.
Thornton, K. Thornton, N. Thorp, K. Thors, E. Thunaes, D. Thurman, M. Thyer, T. Tian, M. Tiedje, S. Tieh, P. Tieu, B.
Tiffin, T. Tigere, D. Tillapaugh, D. Tilley, K. Tilley, M. Tilley, K. Tillotson, T. Tillotson, B. Timmons, S. Timothy, N.
Tindall, M. Tineo, D. Tipper, B. Titus, D. Tiwary, R. Tiwary, C. Tkach, D. Tkachuk, E. To, B. Tobin, K. Tobin, V. Tobin,
K. Tobler, B. Todd, C. Todd, S. Todd, W. Todoschuk, T. Tolen, D. Tomar, B. Tomchuk, G. Tomchuk, D. Tomiuk, C.
Tomlinson, A. Tomszak, N. Tomte, W. Tong, M. Tonon, S. Tookey, V. Topacio, S. Topolnitsky, K. Tordon, L. Torrance,
P. Torrance, C. Torraville, F. Torraville, J. Torraville, N. Torres, D. Torriero, D. Toth, K. Totten, D. Touchette, S.
Touchette, D. Toullelan, K. Tourand, T. Tourand, M. Townsend, D. Tozer, O. Tozser, C. Tran, D. Tran, R. Trant, C.
Trapp, L. Trautman, M. Travers, J. Traverse, M. Traverse, P. Traverse, J. Tredger, D. Tredou, G. Treen, J. Treen, J.
Trelinski, W. Trelinski, J. Treliving, L. Tremblay, M. Tremblay, C. Tremblett, M. Tremblett, W. Tremblett, S. Tremel,
J. Trenholm, 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, C. Troake, B. Troy, P. Troy, J. Trto, J. Trudeau, R. Trudeau, B. Trumpf, A. Truong, S.
Truong, H. Tsagalas, S. Tschetters, C. Tse, Y. Tse, P. Tso, Y. Tu, A. Tuck, B. Tucker, D. Tucker, J. Tucker, R. Tucker, A.
Tuico, D. Tuite, S. Tulan, B. Tulk, J. Tulk, L. Tulk, B. Tulloch, N. 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, A. Turtulga, S. Tutkaluk, W. Tutt, R. Tuttle, S. Tuttle, I. Tutto, L. Tuttosi, T. Twist, P.
Twomey, D. Twyne, O. Tyan, A. Tyler, M. Tyler, W. Tymchuk, D. Tymchyna, R. Tymchyna, Z. Tymo, N. Tynan, S. Tyrell,
G. Tyrer, C. Tyssen, J. Uddin, D. Uduwara Merennage, T. Uhrich, S. Ulloa, C. Ulrich, E. Ulrich, J. Umali, O. Umana,
U. Umoh, L. Underhill, K. Underwood, N. Underwood, R. Underwood, T. Ung, D. Unger, K. Unger, B. Unrath, L.
Unrau, H. Unruh, P. Unruh, S. Upadhyay, 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, G. Valiquette, J. Valle, L. Vallee, M. Vallee, W. Vallee, G. Vallis, A. Valmadrid, K.
Van Buskirk, A. Van De Reep, C. Van de Reep, W. Van den Oever, M. van der Burgh, N. Van Der Merwe, V. Van Der
Merwe, A. Van Donkervoort, H. Van Dyck, M. Van Dyk, B. van Dyke, N. Van Dyke, P. van Eerde, D. Van Genne, L.
Van Genne, L. van Heerden, S. Van Jaarsveld, J. Van Nes, C. van Niekerk, S. Van Rensburg, D. Van Rootselaar, C.
Van Schoor, R. Van Steinburg, R. van Zanden, M. Vanberg, D. Vanbocquestal, M. Vance, J. Vancoughnett, K.
Vandaelle, J. Vandeligt, R. Vandemark, T. Vandemark, D. Vandenberg, G. Vander Veen, J. Vanderkley, T.
Vandermeer, J. Vandervoort, G. van't Wout, C. Vare, S. Varey, M. Varga, D. Varty, N. Vaschetto, A. Vashisht, A.
Vasquez, M. Vasquez-Placid, J. Vasseur, R. Vassov, A. Vaters, R. Vaudan, N. Vaughan, A. Vaughan, J. Veale, O.
Vedmedenko, S. Vekved, B. Velagapudi, B. Velichka, S. Venkatesh, R. Venn, D. Venning, J. Vera, L. Verbaas, D.
Verbeek, D. Verbicky, M. Verburg, A. Verge, J. Verge, M. Verge, N. Veriotes, S. Veroba, J. Verot, B. Verreau, D.
Versnick-Brown, K. Veysey, J. Vezina, E. Viale Tudela, C. Viana, G. Vibert, J. Vicic, S. Vicic, N. Vick, K. Vierboom,
A. Vihristencu, G. Viljoen, R. Villanueva, J. Villemaire, M. Villemaire, C. Villemere, P. Villeneuve, R. Vincent, 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, S. Voight, V. Volk, B. Volkmann, R. Volkmann, J. Vollman, W. Volschenk, E. von Hertzberg, L.
Vondermuhll, B. Von-Grat, A. Vosburgh, G. Vose, A. Votta, A. Vredegoor, J. Vrolson, N. Vucic, J. Vuong, Q. Vuong,
B. Vye, G. Wack, E. Waddell, C. Wadden, K. Waddy, J. Wade, W. Wade, T. Wagil, C. Wagner, D. Wagner, G.
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 2018 Year-End Reserves
DETERMINATION OF RESERVES
For the year ended December 31, 2018, 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
■■ Canadian Natural’s 2018 performance has resulted in another year of excellent finding and development costs:
■● Finding, Development and Acquisition ("FD&A") costs, excluding changes in Future Development Capital ("FDC"),
are $3.11/BOE for proved reserves and $2.31/BOE for proved plus probable reserves.
■● FD&A costs, including changes in FDC, are $9.39/BOE for proved reserves and $10.79/BOE for proved plus
probable reserves.
■■ Proved reserves additions and revisions replaced 2018 production by 359%. Proved plus probable reserves additions and
revisions replaced 2018 production by 485%.
■■ Proved reserves increased 12% to 9.893 billion BOE with reserves additions and revisions of 1.416 billion BOE. Proved
plus probable reserves increased 13% to 13.382 billion BOE with reserves additions and revisions of 1.910 billion BOE.
■■ The proved BOE reserves life index is 27.7 years and the proved plus probable BOE reserves life index is 37.4 years.
■■ Proved developed producing reserves additions and revisions are 1.109 billion BOE, replacing 2018 production by 281%.
The total proved developed producing BOE reserves life index is 21.3 years.
■■ Recycle ratios are 8.7 times and 11.8 times for proved and proved plus probable reserves respectively, excluding
changes in FDC, recycle ratios are 2.9 times and 2.5 times for proved and proved plus probable reserves respectively,
including changes in FDC.
■■ The net present value of future net revenues, before income tax, discounted at 10%, increased 19% to $106.6 billion for
proved reserves and increased 14% to $131.0 billion for proved plus probable reserves. The net present value for proved
developed producing reserves increased 24% to $84.2 billion reflecting the impact of the Horizon South Pit addition and
decreased production expenses at AOSP.
4
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. North America Exploration and Production
■■ Canadian Natural’s North America conventional and thermal assets delivered strong reserves results in 2018:
■● FD&A costs, excluding changes in FDC, are $6.51/BOE for proved reserves and $3.50/BOE for proved plus
probable reserves.
■● FD&A costs, including changes in FDC, are $7.23/BOE for proved reserves and $10.54/BOE for proved plus
probable reserves.
■■ Proved reserves additions and revisions replaced 187% of 2018 production. Proved plus probable reserves additions and
revisions replaced 349% of 2018 production.
■■ Proved reserves increased 6% to 3.588 billion BOE. This is comprised of 2.488 billion bbl of crude oil, bitumen, and NGL
reserves and 6.597 Tcf of natural gas reserves.
■■ Proved plus probable reserves increased 10% to 6.027 billion BOE. This is comprised of 4.421 billion bbl of crude oil,
bitumen, and NGL reserves and 9.633 Tcf of natural gas reserves.
■■ Proved reserves additions and revisions are 341 million bbl of crude oil, bitumen and NGL and 411 Bcf of natural gas.
Proved plus probable reserves additions and revisions are 654 million bbl of crude oil, bitumen and NGL and 657 Bcf of
natural gas.
■■ The proved BOE reserves life index is 18.9 years and the proved plus probable BOE reserves life index is 31.7 years.
North America Oil Sands Mining and Upgrading
■■ Canadian Natural’s Oil Sands Mining and Upgrading segment delivered strong reserves results in 2018:
■● FD&A costs, excluding changes in FDC, are $1.47/bbl for proved reserves and $1.29/bbl for proved plus
probable reserves.
■● FD&A costs, including changes in FDC, are $10.49/bbl for proved reserves and $11.33/bbl for proved plus
probable reserves.
■■ Proved SCO reserves increased 16% to 6.091 billion bbl. Proved plus probable SCO reserves increased 16% to
7.032 billion bbl.
■■ SCO reserves account for 62% of the Company’s proved BOE reserves and 53% of the proved plus probable
BOE reserves.
International Exploration and Production
■■ North Sea proved reserves are unchanged at 124 million BOE and proved plus probable reserves increased 4% to
193 million BOE.
■■ Offshore Africa proved reserves increased 5% to 90 million BOE and proved plus probable reserves decreased 4% to
131 million BOE.
5
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Summary of Company Gross Reserves
As of December 31, 2018
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
114
14
66
194
74
268
34
4
81
119
67
186
41
–
45
86
35
Total Proved plus Probable
121
97
16
69
182
70
252
248
–
57
305
140
445
311
123
1,106
1,540
1,519
3,059
6,091
3,477
–
–
6,091
941
7,032
326
2,794
6,597
3,036
9,633
101
10
156
267
130
397
7,541
218
1,920
9,679
3,379
13,058
23
–
4
27
11
38
17
–
11
28
35
63
38
4
82
124
69
193
44
–
46
90
41
131
Total Company
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
189
18
192
399
176
575
97
16
69
182
70
252
248
–
57
305
140
445
311
123
1,106
1,540
1,519
3,059
6,091
3,517
–
–
6,091
941
7,032
326
2,809
6,652
3,082
9,734
101
10
156
267
130
397
7,623
222
2,048
9,893
3,489
13,382
6
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
Summary of Company Net Reserves
As of December 31, 2018
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
101
12
56
169
61
230
34
4
81
119
67
186
36
–
36
72
26
98
171
16
173
360
154
514
81
14
59
154
57
211
189
–
48
237
100
337
252
104
911
1,267
1,210
2,477
5,125
3,183
–
(8)
5,117
761
5,878
303
2,519
6,005
2,676
8,681
80
8
131
219
104
323
6,358
189
1,616
8,163
2,740
10,903
23
–
4
27
11
38
12
–
9
21
23
44
38
4
82
124
69
193
38
–
38
76
30
106
81
14
59
154
57
211
189
–
48
237
100
337
252
104
911
1,267
1,210
2,477
5,125
3,218
–
(8)
5,117
761
5,878
303
2,532
6,053
2,710
8,763
80
8
131
219
104
323
6,434
193
1,736
8,363
2,839
11,202
7
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
Reconciliation of Company Gross Reserves
As of December 31, 2018
Forecast Prices and Costs
PROVED
North America
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
North Sea
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
Offshore Africa
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
Total Company
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
8
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)
171
–
12
17
–
3
–
–
10
(19)
194
120
–
–
1
–
8
–
5
(6)
(9)
119
83
–
–
–
–
–
–
–
10
(7)
86
374
–
12
18
–
11
–
5
14
(35)
399
198
–
14
6
–
2
(5)
1
(2)
(32)
182
327
–
–
–
1
–
–
1
(1)
(23)
305
1,350
–
171
4
2
–
–
–
52
(39)
1,540
5,264
–
808
–
–
–
–
–
175
(156)
6,091
6,730
–
122
470
3
82
(3)
(305)
42
(544)
6,597
229
–
9
38
–
4
–
(4)
6
(15)
267
8,661
–
1,034
143
4
22
(5)
(53)
247
(374)
9,679
21
–
–
–
–
–
–
–
18
(12)
27
20
–
–
–
–
–
–
–
17
(9)
28
124
–
–
1
–
8
–
5
(3)
(11)
124
86
–
–
–
–
–
–
–
13
(9)
90
198
–
14
6
–
2
(5)
1
(2)
(32)
182
327
–
–
–
1
–
–
1
(1)
(23)
305
1,350
–
171
4
2
–
–
–
52
(39)
1,540
5,264
–
808
–
–
–
–
–
175
(156)
6,091
6,771
–
122
470
3
82
(3)
(305)
77
(565)
6,652
229
–
9
38
–
4
–
(4)
6
(15)
267
8,871
–
1,034
144
4
30
(5)
(48)
257
(394)
9,893
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
Reconciliation of Company Gross Reserves
As of December 31, 2018
Forecast Prices and Costs
PROBABLE
North America
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
North Sea
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
Offshore Africa
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
Total Company
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
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)
68
–
4
6
1
1
–
(1)
(5)
–
74
60
–
–
–
–
5
–
(5)
7
–
67
42
–
–
–
–
–
–
–
(7)
–
35
170
–
4
6
1
6
–
(6)
(5)
–
176
74
–
7
2
–
1
(1)
–
(13)
–
70
142
–
–
–
2
–
–
–
(4)
–
140
1,230
–
59
1
2
403
–
–
(176)
–
1,519
799
–
71
–
–
–
–
–
71
–
941
2,790
–
93
391
1
22
(2)
(104)
(155)
–
3,036
106
–
5
22
–
1
–
(1)
(3)
–
130
2,884
–
162
97
4
410
(2)
(19)
(157)
–
3,379
11
–
–
–
–
–
–
–
–
–
11
47
–
–
–
–
–
–
–
(12)
–
35
74
–
7
2
–
1
(1)
–
(13)
–
70
142
–
–
–
2
–
–
–
(4)
–
140
1,230
–
59
1
2
403
–
–
(176)
–
1,519
799
–
71
–
–
–
–
–
71
–
941
2,848
–
93
391
1
22
(2)
(104)
(167)
–
3,082
106
–
5
22
–
1
–
(1)
(3)
–
130
61
–
–
–
–
5
–
(5)
8
–
69
50
–
–
–
–
–
–
–
(9)
–
41
2,995
–
162
97
4
415
(2)
(24)
(158)
–
3,489
9
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
Reconciliation of Company Gross Reserves
As of December 31, 2018
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, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
North Sea
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
Offshore Africa
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
Total Company
December 31, 2017
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
10
239
–
16
23
1
4
–
(1)
5
(19)
268
180
–
–
1
–
13
–
–
1
(9)
186
125
–
–
–
–
–
–
–
3
(7)
121
544
–
16
24
1
17
–
(1)
9
(35)
575
272
–
21
8
–
3
(6)
1
(15)
(32)
252
469
–
–
–
3
–
–
1
(5)
(23)
445
2,580
–
230
5
4
403
–
–
(124)
(39)
3,059
6,063
–
879
–
–
–
–
–
246
(156)
7,032
9,520
–
215
861
4
104
(5)
(409)
(113)
(544)
9,633
335
–
14
60
–
5
–
(5)
3
(15)
397
11,545
–
1,196
240
8
432
(7)
(72)
90
(374)
13,058
32
–
–
–
–
–
–
–
18
(12)
38
67
–
–
–
–
–
–
–
5
(9)
63
185
–
–
1
–
13
–
–
5
(11)
193
136
–
–
–
–
–
–
–
4
(9)
131
272
–
21
8
–
3
(6)
1
(15)
(32)
252
469
–
–
–
3
–
–
1
(5)
(23)
445
2,580
–
230
5
4
403
–
–
(124)
(39)
3,059
6,063
–
879
–
–
–
–
–
246
(156)
7,032
9,619
–
215
861
4
104
(5)
(409)
(90)
(565)
9,734
335
–
14
60
–
5
–
(5)
3
(15)
397
11,866
–
1,196
241
8
445
(7)
(72)
99
(394)
13,382
Canadian Natural 2018 Annual Report Premium 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 reserves 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)
2019
2020
2021
2022
2023
63.00
59.47
75.27
75.27
75.32
70.00
1.95
1.35
3.00
67.00
62.31
77.89
76.89
80.00
72.00
2.44
1.94
3.25
70.00
67.45
82.25
81.25
83.75
73.00
3.00
2.60
3.50
71.40
69.53
84.79
83.79
85.50
74.46
3.21
2.81
3.57
72.83
71.66
87.39
86.39
87.29
75.95
3.30
2.90
3.64
Note. All prices increase at a rate of 2%/year after 2023. A foreign exchange rate of 0.7700 US$/C$ for 2019 and 0.8000 US$/C$ after 2019 was used in the
2018 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) Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production.
(8) Reserves replacement or Production replacement ratio is the Company Gross reserves additions and revisions, for the relevant reserves category, divided by
the Company Gross production in the same period.
(9) Reserves Life Index is based on the amount for the relevant reserves category divided by the 2019 proved developed producing production forecast prepared
by the Independent Qualified Reserves 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 2018 by the sum of total additions and revisions for the relevant reserves category. All values used in the calculation are not rounded.
(11) FD&A costs including changes in Future Development Capital ("FDC") are calculated by dividing the sum of total exploration, development and acquisition
capital costs incurred in 2018 and net changes in FDC from December 31, 2017 to December 31, 2018 by the sum of total additions and revisions for the
relevant reserves category. FDC excludes all abandonment and reclamation costs. All values used in the calculation are not rounded.
(12) Recycle Ratio is the operating netback ($27.13/BOE for 2018) 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.
(13) Abandonment and reclamation costs included in the calculation of the Future Net Revenue (FNR) for 2018 consist of both forecast estimates of
abandonment and reclamation costs attributable to future development activity, as well as certain costs already included in the Company’s Asset Retirement
Obligation (ARO) for development existing as at December 31, 2018. The portion of the Company’s estimated ARO included in the reserves FNR is escalated
at 2.0% per year after 2019. Specifically, for North America (excluding SCO assets), FNR includes the ARO costs associated with abandonment and
reclamation of wells (wells, well sites, well site equipment and pipelines) with assigned reserves. For SCO assets, FNR includes the ARO costs associated
with the abandonment and reclamation of the mine site and all mining facilities and for Horizon assets, it also includes abandonment and reclamation of the
upgrading facilities. For North Sea and Offshore Africa, FNR includes the ARO costs associated with the abandonment and reclamation of offshore wells and
facilities with assigned reserves.
11
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
13
14
16
17
22
23
24
26
30
31
32
35
37
40
40
41
42
45
49
49
50
Management's Discussion and Analysis
Table of Contents
Definitions and Abbreviations
Advisory
Objectives and Strategy
Financial and Operational Highlights
Business Environment
Analysis of Changes in Product Sales
Daily Production
Exploration and Production
Oil Sands Mining and Upgrading
Midstream
Corporate and Other
Net Capital Expenditures
Liquidity and Capital Resources
Commitments and Contingencies
Reserves
Risks and Uncertainties
Environment
Accounting Policies and Standards
Control Environment
Outlook
Other
12
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Definitions and Abbreviations
AECO
AIF
AOSP
API
ARO
bbl
bbl/d
Bcf
Bcf/d
BOE
BOE/d
Bitumen
Brent
C$
CAGR
CAPEX
CO2
CO2e
Crude oil
CSS
EOR
E&P
FPSO
GHG
GJ
GJ/d
Alberta natural gas reference location
Annual Information Form
Athabasca Oil Sands Project
specific gravity measured in degrees on the
American Petroleum Institute scale
asset retirement obligations
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
barrel
barrels per day
billion cubic feet
billion cubic feet per day
barrels of oil equivalent
barrels of oil equivalent per day
a naturally occurring solid or semi-solid
hydrocarbon consisting mainly of heavier
hydrocarbons that are too heavy or thick to
flow at reservoir conditions, and recoverable at
economic rates using thermal in situ recovery
methods
Dated Brent
Canadian dollars
compound annual growth rate
capital expenditures
carbon dioxide
carbon dioxide equivalents
includes light and medium crude oil, primary
heavy crude oil, Pelican Lake heavy crude oil,
bitumen (thermal oil), and synthetic crude oil
Cyclic Steam Stimulation
Enhanced Oil Recovery
Exploration and Production
Floating Production, Storage and
Offloading Vessel
greenhouse gas
gigajoules
gigajoules per day
Mcf
Mcfe
Mcf/d
MMbbl
MMBOE
MMBtu
MMcf
thousand cubic feet
thousand cubic feet equivalent
thousand cubic feet per day
million barrels
million barrels of oil equivalent
million British thermal units
million cubic feet
MMcf/d
million cubic feet per day
NGLs
natural gas liquids
NYMEX
New York Mercantile Exchange
NYSE
PRT
SAGD
SCO
SEC
Tcf
TSX
UK
US
New York Stock Exchange
Petroleum Revenue Tax
Steam-Assisted Gravity Drainage
synthetic crude oil
United States Securities and Exchange
Commission
trillion cubic feet
Toronto Stock Exchange
United Kingdom
United States
US GAAP
generally accepted accounting principles in the
United States
US$
WCS
United States dollars
Western Canadian Select
WCS Heavy
Differential
WTI
WCS Heavy Differential from WTI
West Texas Intermediate reference location at
Cushing, Oklahoma
Horizon
Horizon Oil Sands
IASB
International Accounting Standards Board
13
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Advisory
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, production expenses,
capital expenditures, income tax expenses and other guidance provided throughout this Management’s Discussion and
Analysis (“MD&A”) of the financial condition and results of operations of the Company, constitute forward-looking statements.
Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the
Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake water
and polymer flood project, the Kirby Thermal Oil Sands Project, the cost and timing of construction and future operations
of the North West Redwater bitumen upgrader and refinery, construction by third parties of new or expansion of existing
pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic
crude oil (“SCO”) that the Company may be reliant upon to transport its products to market, development and deployment
of technology and technological innovations, the assumption of operations at processing facilities, and the "Outlook" section
of this MD&A, particularly in reference to the 2019 guidance provided with respect to budgeted capital expenditures, also
constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year
forecasts, and are 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
NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or
timing of actual future production may vary significantly from 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 expenditures
and production expenses); asset retirement obligations; the adequacy of the Company’s provision for taxes; and other
circumstances affecting revenues and expenses.
The Company’s operations have been, and in the future may be, affected by political developments and by 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.
14
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 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 MD&A could also have 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 applicable 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 the Company'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; adjusted funds flow (previously referred to as funds flow from operations); net
capital expenditures; adjusted cash production costs; adjusted depreciation, depletion, and amortization; 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), cash flows from operating
activities, and cash flows used in investing activities as determined in accordance with IFRS, as an indication of the Company’s
performance. The non-GAAP measure adjusted net earnings (loss) from operations is reconciled to net earnings (loss), as
determined in accordance with IFRS, in the “Financial and Operational Highlights" section of this MD&A. Additionally, the non-
GAAP measure adjusted funds flow is reconciled to cash flows from operating activities, as determined in accordance with
IFRS, in the "Financial and Operational Highlights" section of this MD&A. The non-GAAP measure net capital expenditures is
reconciled to cash flows used in investing activities, as determined in accordance with IFRS, in the "Net Capital Expenditures"
section of this MD&A. The derivation of adjusted cash production costs and adjusted depreciation, depletion and amortization
are included in the “Operating Highlights – Oil Sands Mining and Upgrading” section of this MD&A. The Company also
presents certain non-GAAP financial ratios and their derivation in the “Liquidity and Capital Resources” section of this MD&A.
SPECIAL NOTE REGARDING CURRENCY, FINANCIAL INFORMATION, PRODUCTION AND RESERVES
This MD&A should be read in conjunction with the audited consolidated financial statements and related notes for the
year ended December 31, 2018. It should also be read in conjunction with the Company's MD&A for the three months and
year ended December 31, 2018, 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").
Production volumes, per unit statistics and reserves data are presented throughout this MD&A on a “before royalties” or
“company gross” basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management
activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE").
A 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 on an “after royalties” or “company net” basis is also presented for information purposes only.
The following discussion and analysis refers primarily to the Company’s 2018 financial results compared to 2017 and 2016,
unless otherwise indicated. In addition, this MD&A details the Company's targeted capital program for 2019. Additional
information relating to the Company, including its quarterly MD&A for the three months and year ended December 31, 2018,
its Annual Information Form for the year ended December 31, 2018, and its audited consolidated financial statements for the
year ended December 31, 2018 is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. Detailed guidance
on production levels, capital expenditures and production expenses can be found on the Company's website at www.cnrl.com.
This MD&A is dated March 6, 2019.
15
Canadian Natural 2018 Annual Report Premium 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 expense 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.
16
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Financial and Operational Highlights
($ millions, except per common share amounts)
Product sales
Crude oil and NGLs
Natural gas
Net earnings (loss)
Per common share – basic
– diluted
Adjusted net earnings (loss) from operations (1)
Per common share – basic
– diluted
Cash flows from operating activities
Adjusted funds flow (2)
Per common share – basic
– diluted
Dividends declared per common share (3)
Total assets
Total long-term liabilities
Cash flows used in investing activities
Net capital expenditures (4)
Average sales price
Crude oil and NGLs - Exploration and Production ($/bbl)
Natural gas - Exploration and Production ($/Mcf)
Oil Sands Mining and Upgrading ($/bbl)
Daily production, before royalties (BOE/d)
Crude oil and NGLs (bbl/d)
Natural gas (MMcf/d)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2018
22,282 $
20,668 $
1,614 $
2,591 $
2.13 $
2.12 $
3,263 $
2.68 $
2.67 $
10,121 $
9,088 $
7.46 $
7.43 $
1.34 $
71,559 $
34,823 $
4,814 $
4,731 $
46.92 $
2.61 $
68.61 $
2017
18,360 $
16,522 $
1,838 $
2,397 $
2.04 $
2.03 $
1,403 $
1.19 $
1.19 $
7,262 $
7,347 $
6.25 $
6.21 $
1.10 $
73,867 $
35,953 $
13,102 $
17,129 $
48.57 $
2.76 $
63.98 $
1,078,813
820,778
1,548
962,264
685,236
1,662
2016
12,002
10,396
1,606
(204)
(0.19)
(0.19)
(669)
(0.61)
(0.61)
3,452
4,293
3.90
3.89
0.94
58,648
27,289
3,811
3,794
36.93
2.32
58.59
805,782
523,873
1,691
(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 the after-tax effects of certain items of a non-operational nature. The Company considers adjusted net earnings (loss)
from operations a key measure in evaluating the Company's performance, as it demonstrates the Company’s ability to generate after-tax operating earnings
from its core business areas. The reconciliation “Adjusted Net Earnings (Loss) from Operations, as Reconciled to Net Earnings (Loss)” is presented in
this MD&A. Adjusted net earnings (loss) from operations may not be comparable to similar measures presented by other companies.
(2) Adjusted funds flow (previously referred to as funds flow from operations) is a non-GAAP measure that represents cash flows from operating activities as
presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment and certain
movements in other long-term assets. The Company considers adjusted funds flow 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 “Adjusted Funds Flow, as Reconciled to Cash
Flows from Operating Activities” is presented in this MD&A. Adjusted funds flow may not be comparable to similar measures presented by other companies.
(3) On March 6, 2019, the Board of Directors approved an increase in the quarterly dividend to $0.375 per common share, beginning with the dividend payable on
April 1, 2019. 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
$0.23 per common share, beginning with the dividend payable on April 1, 2016.
(4) Net capital expenditures is a non-GAAP measure that represents cash flows used in investing activities as presented in the Company's consolidated
Statements of Cash Flows, adjusted for the net change in non-cash working capital, investment in other long-term assets, share consideration in business
acquisitions (dispositions) and abandonment expenditures. The Company considers net capital expenditures a key measure as it provides an understanding of
the Company’s capital spending activities in comparison to the Company's annual capital budget. The reconciliation “Net Capital Expenditures, as Reconciled
to Cash Flows used in Investing Activities” is presented in the "Net Capital Expenditures" section of this MD&A. Net capital expenditures may not be
comparable to similar measures presented by other companies.
17
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
ADJUSTED NET EARNINGS (LOSS) FROM OPERATIONS, AS RECONCILED TO NET EARNINGS (LOSS)
($ millions)
Net earnings (loss), as reported
Share-based compensation, net of tax (1)
Unrealized risk management (gain) loss, net of tax (2)
Unrealized foreign exchange loss (gain), net of tax (3)
Realized foreign exchange loss on repayment of US dollar debt securities,
net of tax (4)
Loss (gain) from investments, net of tax (5) (6)
Gain on acquisition, disposition and revaluation of properties, net of tax (7)
Derecognition of exploration and evaluation assets, net of tax (8)
Effect of statutory tax rate and other legislative changes on deferred income
tax liabilities (9)
2018
2017
$
2,591 $
2,397 $
(146)
(36)
706
146
374
(372)
–
–
134
33
(821)
–
(11)
(339)
–
10
Adjusted net earnings (loss) from operations
$
3,263 $
1,403 $
2016
(204)
355
21
(93)
–
(299)
(241)
13
(221)
(669)
(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) the
Oil Sands Mining and Upgrading segment.
(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 those amounts reflected in the financial statements due to
changes in prices of the underlying items hedged, primarily crude oil, natural gas and foreign exchange.
(3) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates,
partially offset by the impact of cross currency swaps, and are recognized in net earnings (loss).
(4) During 2018, the Company repaid US$600 million of 1.75% notes and US$400 million of 5.90% notes.
(5) The Company's investment in the 50% owned North West Redwater Partnership ("Redwater Partnership") is accounted for using the equity method of
accounting. Included in the non-cash loss (gain) from investments is the Company's pro rata share of the Redwater Partnership's accounting loss (gain).
(6) The Company’s investments in PrairieSky Royalty Ltd. (“PrairieSky”) and Inter Pipeline Ltd. ("Inter Pipeline") have been accounted for at fair value through
profit and loss and are measured each period with changes in fair value recognized in net earnings (loss).
(7) During 2018, the Company recorded a pre-tax gain of $16 million ($12 million after-tax) on the disposition of a 30% interest in the exploration right in South
Africa. Additionally, the Gabonese Republic approved cessation of production from the Company’s Olowi field and associated asset retirement obligations,
as well as the terms of termination of the Olowi Production Sharing Contract and the surrender of the permit area back to the Gabonese Republic, resulting
in a pre-tax gain on disposition of property of $20 million ($14 million after-tax). The Company also recorded a pre-tax gain of $277 million ($263 million after-
tax) related to acquisitions in the North America Exploration and Production segment. Additionally, the Company recorded a pre-tax gain of $120 million
($72 million after-tax) on the acquisition of the remaining interest at Ninian in the North Sea and a pre-tax gain of $19 million ($11 million after-tax) relating
to the revaluation of the Company's previously held interest at Ninian. 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.
(8) 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.
(9) All substantively enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the
Company's balance sheets in determining deferred income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in
net earnings (loss) during the period the legislation is substantively enacted. During 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 $114 million.
ADJUSTED FUNDS FLOW, AS RECONCILED TO CASH FLOWS FROM OPERATING ACTIVITIES (1)
($ millions)
Cash flows from operating activities
Net change in non-cash working capital
Abandonment expenditures (2)
Other (3)
Adjusted funds flow
2018
2017
$
10,121 $
7,262 $
(1,346)
290
23
(299)
274
110
2016
3,452
542
267
32
$
9,088 $
7,347 $
4,293
(1) Adjusted funds flow was previously referred to as funds flow from operations.
(2) The Company includes abandonment expenditures in “Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities” in the “Net Capital
Expenditures” section of this MD&A.
(3) Includes certain movements in other long-term assets.
18
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
CONSOLIDATED NET EARNINGS (LOSS) AND ADJUSTED NET EARNINGS (LOSS)
For 2018, the Company reported net earnings of $2,591 million compared with net earnings of $2,397 million for 2017
(2016 – $204 million net loss). Net earnings for 2018 included net after-tax expenses of $672 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 on repayments of long-term debt, the loss (gain) 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 (2017 – $994 million after-tax income; 2016 – $465 million after-tax
income). Excluding these items, adjusted net earnings from operations for 2018 were $3,263 million compared with adjusted
net earnings of $1,403 million for 2017 (2016 – $669 million adjusted net loss).
The increase in net earnings and adjusted net earnings from operations for 2018 from 2017 was primarily due to:
■■ higher SCO sales volumes in the Oil Sands Mining and Upgrading segment;
■■ higher realized SCO prices in the Oil Sands Mining and Upgrading segment;
■■ higher realized risk management gains; and
■■ higher crude oil and NGLs netbacks in the International segments;
partially offset by:
■■
lower crude oil and NGLs netbacks in the North America Exploration and Production segment;
■■ higher depletion, depreciation and amortization in the Oil Sands Mining and Upgrading segment;
■■
■■
lower natural gas netbacks in the North America Exploration and Production segment; and
lower crude oil and NGLs sales volumes in the Exploration and Production segments.
Net earnings and adjusted net earnings from operations for 2018 as compared to net earnings and adjusted net earnings from
operations for 2017 included the impact of a significant decline in crude oil pricing in November and December 2018 as a result
of an oversupplied domestic market environment and a lack of takeaway capacity, resulting in increased storage levels and
higher apportionment on the Enbridge Mainline system. The WCS heavy differential averaged US$39.36 per bbl for the fourth
quarter of 2018 (third quarter of 2018 – US$22.17 per bbl). The SCO price averaged US$37.48 per bbl for the fourth quarter of
2018 (third quarter of 2018 – US$68.44 per bbl).
Following the Government of Alberta's announcement on December 2, 2018 of a mandatory curtailment of crude oil
production, the WCS heavy differential index narrowed to US$12.38 per bbl for the first quarter of 2019 and the differential
between SCO and WTI benchmark pricing narrowed to US$2.70 per bbl for the first quarter of 2019. Crude oil and natural gas
pricing are discussed in detail in the "Business Environment" section of this MD&A.
The impacts of share-based compensation, risk management activities and fluctuations in foreign exchange rates also
contributed to the movements in net earnings (loss) for 2018 from 2017. These items are discussed in detail in the relevant
sections of this MD&A.
19
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. CASH FLOWS FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW
Cash flows from operating activities for 2018 increased to $10,121 million from $7,262 million for 2017 (2016 – $3,452 million).
The increase in cash flows from operating activities for 2018 from 2017 was primarily due to the factors noted above relating
to the fluctuations in adjusted net earnings (loss) (except for the effect of depletion, depreciation and amortization), as well as
due to the impact of changes in non-cash working capital.
Adjusted funds flow for 2018 increased to $9,088 million ($7.46 per common share) from $7,347 million for 2017 ($6.25 per
common share) (2016 – $4,293 million; $3.90 per common share). The increase in adjusted funds flow for 2018 from 2017
was primarily due to the factors noted above relating to the fluctuations in cash flows from operating activities excluding the
impact of the net change in non-cash working capital, abandonment and certain movements in other long-term assets.
PRODUCT PRICING
In the Company’s Exploration and Production activities, the 2018 average sales price per bbl of crude oil and NGLs decreased
3% to average $46.92 per bbl from $48.57 per bbl in 2017 (2016 – $36.93 per bbl), and the 2018 average natural gas price
decreased 5% to average $2.61 per Mcf from $2.76 per Mcf in 2017 (2016 – $2.32 per Mcf). In the Oil Sands Mining
and Upgrading segment, the Company’s 2018 average SCO sales price increased 7% to average $68.61 per bbl from
$63.98 per bbl in 2017 (2016 – $58.59 per bbl). Crude oil and NGLs and natural gas pricing are discussed in detail in the
“Business Environment” section of this MD&A.
PRODUCTION VOLUMES
Total production of crude oil and NGLs before royalties for 2018 increased 20% to average 820,778 bbl/d from 685,236 bbl/d
in 2017 (2016 – 523,873 bbl/d). The increase in crude oil and NGLs production from 2017 was primarily due to the impact of
Phase 3 production at Horizon and acquisitions completed in 2017, partially offset by the impact of proactive measures taken
by the Company to voluntarily curtail crude oil production and reduce drilling in heavy oil.
Total natural gas production before royalties for 2018 decreased 7% to average 1,548 MMcf/d from 1,662 MMcf/d in 2017
(2016 – 1,691 MMcf/d). The decrease in natural gas production from 2017 primarily reflected the impact of shut-in volumes
due to low natural gas prices, a failure on a natural gas transmission line in British Columbia (T-South) and a turnaround at the
third-party Pine River processing facility beginning on September 15, 2018. Operations at the facility were partially reinstated
on December 6, 2018. Subject to regulatory approval, the Company targets to take over operations at the facility in the first
half of 2019.
Total crude oil and NGLs and natural gas production volumes before royalties for 2018 increased 12% to average
1,078,813 BOE/d from 962,264 BOE/d in 2017 (2016 – 805,782 BOE/d). Crude oil and NGLs and natural gas production
volumes are discussed in detail in the “Daily Production” section of this MD&A.
20
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company’s quarterly financial results for the eight most recently completed quarters:
($ millions, except per common share amounts)
2018
Product sales
Crude oil and NGLs
Natural gas
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
($ millions, except per common share amounts)
2017
Product sales
Crude oil and NGLs
Natural gas
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
Total
Dec 31
Sep 30
Jun 30
Mar 31
22,282 $
3,831 $
6,327 $
6,389 $
20,668 $
3,327 $
5,967 $
6,071 $
1,614 $
2,591 $
504 $
360 $
(776) $
1,802 $
318 $
982 $
5,735
5,303
432
583
2.13 $
2.12 $
(0.64) $
(0.64) $
1.48 $
1.47 $
0.80 $
0.80 $
0.48
0.47
Total
Dec 31
Sep 30
Jun 30
Mar 31
18,360 $
5,516 $
4,725 $
4,127 $
16,522 $
5,098 $
4,320 $
3,645 $
1,838 $
2,397 $
418 $
396 $
405 $
482 $
684 $
1,072 $
3,992
3,459
533
245
2.04 $
2.03 $
0.32 $
0.32 $
0.56 $
0.56 $
0.93 $
0.93 $
0.22
0.22
$
$
$
$
$
$
$
$
$
$
$
$
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 Western Canadian Select ("WCS")
Heavy Differential from the West Texas Intermediate reference location at Cushing, Oklahoma ("WTI") in North America
including the impact of a shortage of takeaway capacity out of the Western Canadian Sedimentary Basin (the "Basin") and
the impact of the differential between WTI and Dated Brent ("Brent") benchmark pricing in the North Sea and Offshore Africa.
■■ Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, third-
party pipeline maintenance and outages 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, production from Horizon Phase 3 as well as the impact of turnarounds and pitstops in the Oil Sands
Mining and Upgrading segment, voluntarily curtailed production due to low commodity prices in North America, and the
impact of the drilling program in the International segments. 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, fluctuating capacity 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 volumes, the impact of seasonal costs that are dependent on weather, the impact of increased
carbon tax and energy costs, cost optimizations across all segments, the impact and timing of acquisitions, including the
acquisition of AOSP and other assets, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading
segment, 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 the second
quarter of 2017, and the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment.
21
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. ■■ 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 impact the realized price the
Company received for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated
benchmarks. Fluctuations in realized and unrealized foreign exchange gains and losses were also recorded with respect to
US dollar denominated debt, partially offset by the impact of cross currency swap hedges.
■■
Income tax expense – Fluctuations in income tax expense due to statutory tax rate and other legislative changes
substantively enacted in the various periods.
■■ Gains on acquisition, disposition and revaluation of properties and gains/losses on investments – Fluctuations due
to the recognition of gains on the acquisition of AOSP and other assets, the acquisition, disposition and revaluation of
properties in the various periods, fair value changes in the investments in PrairieSky and Inter Pipeline shares, and the
equity loss (gain) on the Company's interest in the Redwater Partnership.
Business Environment
(Yearly average)
WTI benchmark price (US$/bbl)
Dated Brent benchmark price (US$/bbl)
WCS heavy 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$)
2018
2017
64.78 $
71.12 $
50.93 $
54.38 $
26.29 $
11.97 $
58.62 $
52.20 $
60.98 $
51.65 $
3.08 $
1.45 $
3.11 $
2.30 $
2016
43.37
43.96
13.91
43.94
42.51
2.45
1.98
0.7717 $
0.7701 $
0.7548
0.7328 $
0.7988 $
0.7448
$
$
$
$
$
$
$
$
$
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 2018, 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 2018, with a high of approximately US$0.81 in February 2018
and a low of approximately US$0.73 in December 2018.
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged
US$64.78 per bbl for 2018, an increase of 27% from US$50.93 per bbl for 2017 (2016 – US$43.37 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$71.12 per bbl for
2018, an increase of 31% from US$54.38 per bbl for 2017 (2016 – US$43.96 per bbl).
WTI and Brent pricing for 2018 increased from 2017 primarily due to declines in global crude oil inventories, together with
larger than anticipated increases in global demand for crude oil.
The WCS heavy differential averaged US$26.29 per bbl for 2018, an increase of 120% from US$11.97 per bbl for 2017
(2016 – US$13.91 per bbl). The significant widening of the WCS heavy differential reflected a shortage of takeaway capacity
out of the Basin, resulting in increased storage levels and higher apportionment on the Enbridge Mainline system. Following
the Government of Alberta's announcement on December 2, 2018 of a mandatory curtailment of crude oil production, the
WCS heavy differential index narrowed to US$12.38 per bbl for the first quarter of 2019 compared to US$39.36 per bbl during
the fourth quarter of 2018.
22
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. The SCO price averaged US$58.62 per bbl for 2018, an increase of 12% from US$52.20 per bbl for 2017
(2016 – US$43.94 per bbl). The increase in SCO pricing for 2018 from 2017 primarily reflected increases in WTI benchmark
pricing through the third quarter of 2018, partially offset by decreased pricing in the fourth quarter of 2018 due to a shortage
of takeaway capacity out of the Basin, resulting in increased storage levels and higher apportionment on the Enbridge
Mainline system. Following the Government of Alberta's announcement on December 2, 2018 of a mandatory curtailment of
crude oil production, the differential between SCO and WTI benchmark pricing narrowed to US$2.70 per bbl for the first
quarter of 2019 compared to US$21.35 per bbl during the fourth quarter of 2018.
Condensate pricing averaged US$60.98 per bbl for 2018, an increase of 18% from US$51.65 per bbl for 2017
(2016 – US$42.51 per bbl). The increase in condensate pricing for 2018 from 2017 primarily reflected increases in the underlying
benchmark pricing.
NYMEX natural gas prices averaged US$3.08 per MMBtu for 2018, comparable with US$3.11 per MMBtu for 2017
(2016 – US$2.45 per MMBtu). AECO natural gas prices averaged $1.45 per GJ for 2018, a decrease of 37% from
$2.30 per GJ for 2017 (2016 – $1.98 per GJ).
The decrease in AECO natural gas prices for 2018 compared with 2017 reflected third party pipeline constraints limiting flow
of natural gas to export markets as well as increased natural gas production in the Basin.
Analysis of Changes in Product Sales
($ millions)
North America
Changes due to
Changes due to
2016 Volumes
Prices
Other
2017 Volumes
Prices
Other
2018
Crude oil and NGLs
$ 5,933 $
135 $ 1,755 $
(168) $ 7,655 $
(188) $
(224) $
11 $ 7,254
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)
1,276
7,209
(20)
115
250
2,005
–
(168)
1,506
9,161
(105)
(293)
(136)
(360)
478
92
570
532
71
603
6,943
1,439
8,382
2,657
114
849
63
3
66
(70)
(22)
(92)
128
(39)
89
130
23
153
103
4
107
(5)
–
(5)
14
–
14
666
118
784
579
53
632
1,988
277
2,265
(159)
–
8,900
1,677
(159)
10,577
(69)
(23)
(92)
(102)
10
(92)
(359)
(118)
(477)
155
45
200
164
7
171
95
(84)
11
3,827
561
–
–
–
–
27
(12)
7,072
102
(240)
609
3,696
722
–
–
–
–
(9)
2
1
–
1
(13)
–
(13)
(1)
(9)
1,256
8,510
753
140
893
628
70
698
8,635
1,466
(10)
10,101
31
–
11,521
102
(51)
558
Total
$ 12,002 $ 3,916 $ 2,826 $
(384) $ 18,360 $ 3,219 $
733 $
(30) $ 22,282
(1) Eliminates internal transportation and electricity charges and includes production, processing and other purchasing and selling activities that are not included
in the above segments.
Product sales increased 21% to $22,282 million for 2018 from $18,360 million for 2017 (2016 – $12,002 million). The
increase was primarily due to higher SCO sales volumes and higher realized SCO sales prices in the Oil Sands Mining and
Upgrading segment.
For 2018, 7% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America
(2017 – 8%; 2016 – 10%). North Sea accounted for 4% of crude oil and NGLs and natural gas product sales for 2018
(2017 – 4%; 2016 – 5%), and Offshore Africa accounted for 3% of crude oil and NGLs and natural gas product sales for 2018
(2017 – 4%; 2016 – 5%).
23
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Daily Production, Before Royalties
Crude oil and NGLs (bbl/d)
North America – Exploration and Production
North America – Oil Sands Mining and Upgrading (1)
North Sea
Offshore Africa
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Total barrels of oil equivalent (BOE/d)
Product mix
Light and medium crude oil and NGLs
Pelican Lake heavy crude oil
Primary heavy crude oil
Bitumen (thermal oil)
Synthetic crude oil (1)
Natural gas
Percentage of gross revenue (1) (2)
(excluding Midstream revenue)
Crude oil and NGLs
Natural gas
2018
2017
2016
350,961
426,190
23,965
19,662
359,449
282,026
23,426
20,335
350,958
123,265
23,554
26,096
820,778
685,236
523,873
1,490
1,601
1,622
32
26
39
22
38
31
1,548
1,662
1,691
1,078,813
962,264
805,782
13%
6%
8%
10%
39%
24%
93%
7%
14%
6%
10%
12%
29%
29%
90%
10%
17%
6%
13%
14%
15%
35%
85%
15%
(1) 2018 SCO production before royalties excludes 3,093 bbl/d of SCO consumed internally as diesel (2017 – 651 bbl/d, 2016 – 1,966 bbl/d).
(2) Net of blending costs and excluding risk management activities.
Daily Production, Net of Royalties
Crude oil and NGLs (bbl/d)
North America – Exploration and Production
North America – Oil Sands Mining and Upgrading
North Sea
Offshore Africa
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Total barrels of oil equivalent (BOE/d)
2018
2017
2016
303,956
405,731
23,902
18,450
312,297
274,437
23,382
19,124
311,059
122,258
23,497
24,995
752,039
629,240
481,809
1,432
1,528
1,559
32
23
39
20
38
30
1,487
1,587
1,627
999,857
893,702
752,974
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 2018 production averaged 1,078,813 BOE/d, a 12% increase from 962,264 BOE/d in 2017 (2016 – 805,782 BOE/d).
Total production of crude oil and NGLs for 2018 increased 20% to 820,778 bbl/d from 685,236 bbl/d for 2017
(2016 – 523,873 bbl/d). The increase in crude oil and NGLs production from 2017 was primarily due to the impact of Phase 3
production at Horizon and acquisitions completed in 2017, partially offset by the impact of proactive measures taken by the
Company to voluntarily curtail crude oil production and reduce heavy oil drilling. Crude oil and NGLs production for 2018 was
above the midpoint of the Company’s previously issued guidance of 812,000 to 822,000 bbl/d.
24
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
Natural gas production accounted for 24% of the Company's total production in 2018 on a BOE basis. Natural gas production
for 2018 decreased 7% to 1,548 MMcf/d from 1,662 MMcf/d for 2017 (2016 – 1,691 MMcf/d). The decrease in natural gas
production from 2017 primarily reflected the impact of shut-in volumes due to low natural gas prices, natural field declines and
reduced drilling activity, together with the impact of downtime and restricted capacity at the third-party Pine River processing
facility. Subject to regulatory approval, the Company targets to take over operations at the facility in the first half of 2019.
Natural gas production for 2018 was within the Company’s previously issued guidance of 1,545 to 1,555 MMcf/d.
North America – Exploration and Production
North America crude oil and NGLs production for 2018 decreased 2% to average 350,961 bbl/d from 359,449 bbl/d for 2017
(2016 – 350,958 bbl/d). The decrease in production from 2017 primarily reflected the impact of proactive measures taken by
the Company to voluntarily curtail crude oil production, together with reduced heavy oil drilling and natural field declines.
Operating performance at Pelican Lake continued to be strong following the acquisition completed in 2017, leading to average
production of 63,082 bbl/d in 2018 compared with 51,743 bbl/d in 2017 (2016 – 47,637 bbl/d). The polymer flood on the acquired
Pelican assets was restored to 62% of the field.
Overall thermal oil production for 2018 averaged 107,839 bbl/d compared with 120,140 bbl/d for 2017 (2016 – 111,046 bbl/d).
Production volumes in 2018 primarily reflected the impact of proactive measures taken by the Company to voluntarily curtail
crude oil production.
Natural gas production for 2018 decreased 7% to average 1,490 MMcf/d from 1,601 MMcf/d for 2017 (2016 – 1,622 MMcf/d).
The decrease in natural gas production from 2017 primarily reflected the impact of shut-in volumes due to low natural gas
prices, natural field declines and reduced drilling activity, together with the impact of downtime and restricted capacity at the
third-party Pine River processing facility.
North America – Oil Sands Mining and Upgrading
SCO production for 2018 increased 51% to 426,190 bbl/d from 282,026 bbl/d for 2017 (2016 – 123,265 bbl/d). The increase
in SCO production from 2017 primarily reflected high Phase 3 production reliability at Horizon and the acquisition of AOSP.
North Sea
North Sea crude oil production for 2018 increased 2% to 23,965 bbl/d from 23,426 bbl/d for 2017 (2016 – 23,554 bbl/d).
The increase in production from 2017 primarily reflected the successful drilling program completed in 2018, partially offset by
natural field declines.
Offshore Africa
Offshore Africa crude oil production for 2018 decreased 3% to 19,662 bbl/d from 20,335 bbl/d for 2017
(2016 – 26,096 bbl/d). Production volumes decreased from 2017 primarily due to natural field declines offsetting volumes from
new wells drilled at Baobab in the latter half of 2018.
Corporate Production Guidance for 2019
The Company targets production levels in 2019 to average between 782,000 bbl/d and 861,000 bbl/d of crude oil and NGLs
and between 1,485 MMcf/d and 1,545 MMcf/d of natural gas. Corporate crude oil and NGLs production guidance for 2019
reflects production curtailments as currently mandated by the Government of Alberta for the first quarter of 2019.
INTERNATIONAL CRUDE OIL INVENTORY VOLUMES
The Company recognizes revenue on its crude oil production when control of the product passes 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
2018
71,832
404,475
476,307
2017
–
2016
987,316
121,936
1,126,999
121,936
2,114,315
25
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Exploration and Production
OPERATING HIGHLIGHTS
Crude oil and NGLs ($/bbl) (1)
Sales price (2)
Transportation
Realized sales price, net of transportation
Royalties
Production expense
Netback
Natural gas ($/Mcf) (1)
Sales price (2)
Transportation
Realized sales price, net of transportation
Royalties
Production expense
Netback (3)
Barrels of oil equivalent ($/BOE) (1)
Sales price (2)
Transportation
Realized sales price, net of transportation
Royalties
Production expense
Netback
2018
2017
2016
$
46.92 $
48.57 $
36.93
$
$
$
$
3.08
43.84
5.08
15.69
2.80
45.77
5.24
14.89
23.07 $
25.64 $
2.61 $
2.76 $
0.47
2.14
0.08
1.36
0.39
2.37
0.11
1.27
0.70 $
0.99 $
34.62 $
35.54 $
2.96
31.66
3.27
12.71
2.66
32.88
3.40
11.95
$
15.68 $
17.53 $
2.61
34.32
3.40
14.10
16.82
2.32
0.33
1.99
0.09
1.18
0.72
27.58
2.44
25.14
2.21
11.18
11.75
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
(3) Natural gas netbacks exclude netbacks derived from the sale of NGLs. Combining natural gas and NGLs, the netback for 2018 was $1.18/Mcfe
(2017 – $1.31/Mcfe, 2016 – $0.89/Mcfe).
PRODUCT PRICES
Crude oil and NGLs ($/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)
2018
2017
2016
$
$
$
$
$
$
$
$
$
41.82 $
45.85 $
87.41 $
69.43 $
90.95 $
67.15 $
46.92 $
48.57 $
2.33 $
12.08 $
7.34 $
2.61 $
2.58 $
8.24 $
6.57 $
2.76 $
34.31
55.91
54.96
36.93
2.15
6.62
6.13
2.32
34.62 $
35.54 $
27.58
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
Realized crude oil and NGLs prices decreased 3% to average $46.92 per bbl for 2018 from $48.57 per bbl for 2017
(2016 – $36.93 per bbl), primarily due to the significant widening of the WCS heavy differential in the fourth quarter of 2018,
partially offset by higher WTI and Brent benchmark pricing.
The Company’s realized natural gas price decreased 5% to average $2.61 per Mcf for 2018 from $2.76 per Mcf for 2017
(2016 – $2.32 per Mcf). The decrease in 2018 primarily reflected third party pipeline constraints limiting the flow of natural gas
to the export market, together with increased natural gas production in the Basin.
26
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. North America – Product Prices
North America realized crude oil prices decreased 9% to average $41.82 per bbl for 2018 from $45.85 per bbl for 2017
(2016 – $34.31 per bbl), primarily due to the widening of the WCS heavy differential, which reflected a shortage of takeaway
capacity out of the Basin, resulting in increased storage levels and higher apportionment on the Enbridge Mainline system.
North America realized natural gas prices decreased 10% to average $2.33 per Mcf for 2018 from $2.58 per Mcf for 2017
(2016 – $2.15 per Mcf). The decrease primarily reflected third party pipeline constraints limiting the flow of natural gas to the
export market, together with increased natural gas production in the Basin.
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 2018, the
Company contributed approximately 175,100 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 Trans
Mountain Pipeline Expansion from Edmonton, Alberta to Vancouver, British Columbia. The National Energy Board has provided
their recommendation that construction of the pipeline should proceed and the related Federal Government consultations
with Indigenous communities are ongoing. Subject to Cabinet’s final approval, the project could be issued a revised
Certificate of Public Convenience and Necessity this summer with construction re-starting as early as August 2019.
The Company has also entered into a 20 year transportation agreement to ship 175,000 bbl/d of crude oil on the proposed
TransCanada Keystone XL Pipeline from Hardisty, Alberta to the US Gulf Coast. TransCanada is awaiting the completion of
a new supplemental environmental review addressing issues raised through litigation in a Montana Federal Court Case.
A decision is also expected in April 2019 on the Nebraska Public Service Commission's route approval. Pre-construction
activities have started and TransCanada is working to maintain an expected in-service date in 2021.
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.
2018
2017
2016
$
$
$
$
$
52.87 $
47.78 $
43.30 $
48.30 $
38.98 $
46.88 $
33.66 $
42.49 $
2.33 $
2.58 $
37.72
36.03
34.73
30.47
2.15
North Sea – Product Prices
North Sea realized crude oil prices increased 26% to average $87.41 per bbl for 2018 from $69.43 per bbl for 2017
(2016 – $55.91 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 2018 reflected prevailing Brent benchmark pricing at the time of liftings,
together with the impact of movements in the Canadian dollar.
Offshore Africa – Product Prices
Offshore Africa realized crude oil prices increased 35% to average $90.95 per bbl for 2018 from $67.15 per bbl for 2017
(2016 – $54.96 per bbl). Realized crude oil prices per bbl in any particular year are dependent on the terms of the various sales
contracts, the frequency and timing of liftings of each field, and prevailing crude oil prices and foreign exchange rates at the
time of lifting. The increase in realized crude oil prices in 2018 reflected prevailing Brent benchmark pricing at the time of liftings,
together with the impact of movements in the Canadian dollar.
27
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. ROYALTIES
Crude oil and NGLs ($/bbl) (1)
North America
North Sea
Offshore Africa
Company average
Natural gas ($/Mcf) (1)
North America
Offshore Africa
Company average
Company average ($/BOE) (1)
2018
2017
2016
$
$
$
$
$
$
$
$
5.36 $
0.22 $
6.00 $
5.08 $
0.07 $
1.00 $
0.08 $
3.27 $
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
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America – Royalties
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 royalty rates for 2018 and the comparable periods reflected movements in benchmark
commodity prices. North America crude oil royalty rates also reflected fluctuations in the WCS Heavy Differential.
Crude oil and NGLs royalty rates averaged approximately 14% of product sales for 2018 compared with 13% of product sales
for 2017 (2016 – 12%). The increase in royalty rates for 2018 from 2017 was primarily due to higher realized crude oil prices for
the majority of 2018, offsetting the impact of lower realized crude oil prices in the fourth quarter of 2018.
Natural gas royalty rates averaged approximately 4% of product sales for 2018 compared with 5% of product sales for 2017
(2016 – 4%). The decrease in royalty rates for 2018 from 2017 was primarily due to lower realized natural gas prices.
Offshore Africa – Royalties
Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing,
capital expenditures and production expenses, the status of payouts, and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 7% for 2018 compared with 7% of product sales for 2017
(2016 – 4%). Royalty rates as a percentage of product sales reflected the timing of liftings and the status of payout in the various fields.
PRODUCTION EXPENSE
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)
2018
2017
2016
$
$
$
$
$
$
$
$
$
13.48 $
12.71 $
39.89 $
36.60 $
26.34 $
24.07 $
15.69 $
14.89 $
1.25 $
5.29 $
2.76 $
1.36 $
1.19 $
3.37 $
2.90 $
1.27 $
11.89
42.47
18.48
14.10
1.12
3.09
1.79
1.18
12.71 $
11.95 $
11.18
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America – Production Expense
North America crude oil and NGLs production expense for 2018 increased 6% to $13.48 per bbl from $12.71 per bbl for 2017
(2016 – $11.89 per bbl). The increase in crude oil and NGLs production expense for 2018 from 2017 reflected increased carbon
tax and energy costs in 2018 together with increased costs associated with the Company's proactive measures to voluntarily
curtail crude oil production, partially offset by the Company's continuous focus on cost control and achieving efficiencies
across the entire asset base.
28
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. North America natural gas production expense for 2018 increased 5% to $1.25 per Mcf from $1.19 per Mcf for 2017
(2016 – $1.12 per Mcf). The increase in natural gas production expense for 2018 from 2017 primarily reflected the impact of
lower volumes on a relatively fixed cost base due to low natural gas prices and a turnaround at the third-party Pine River
processing facility. Production expense in 2018 also reflected additional costs associated with the shut-in of production due
to low natural gas pricing during 2018, partially offset by the Company's continuous focus on cost control and achieving
efficiencies across the entire asset base.
North Sea – Production Expense
North Sea crude oil production expense for 2018 increased 9% to $39.89 per bbl from $36.60 per bbl for 2017
(2016 – $42.47 per bbl). The increase in crude oil production expense for 2018 from 2017 primarily reflected higher carbon tax
costs and the strengthening of the UK pound sterling compared to the Canadian dollar.
Offshore Africa – Production Expense
Offshore Africa crude oil production expense related to the Baobab and Espoir fields in Côte d'Ivoire for 2018 was
$13.30 per bbl, compared to $12.41 per bbl for 2017. Total Offshore Africa crude oil production expense, including the
Olowi field in Gabon, was $26.34 per bbl for 2018, an increase of 9% from $24.07 per bbl for 2017 (2016 – $18.48 per bbl).
Total Offshore Africa crude oil production expense for 2018 primarily reflected the timing of liftings from various fields, including
the Olowi field in Gabon, that have different cost structures, fluctuating production volumes on a relatively fixed cost base, and
planned maintenance activities. Production expense was also impacted by movements in the Canadian dollar.
During 2018, the Gabonese Republic approved cessation of production from the Company’s Olowi field, as well as the
terms of termination of the Olowi Production Sharing Contract and the surrender of the permit area back to the Gabonese
Republic, including associated asset retirement obligations of $69 million. The transaction resulted in a pre-tax gain on
disposition of property of $20 million ($14 million after-tax). In January 2019, the Company completed FPSO demobilization
and sail away activities.
DEPLETION, DEPRECIATION AND AMORTIZATION
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Expense
$/BOE (1)
2018
2017
$
3,132 $
3,243 $
257
201
509
205
$
$
3,590 $
3,957 $
15.12 $
15.82 $
2016
3,465
458
262
4,185
16.79
(1) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, depreciation and amortization in 2018 decreased 4% to $15.12 per BOE from $15.82 per BOE for 2017
(2016 – $16.79 per BOE). The decrease in depletion, depreciation and amortization expense per BOE for 2018 from 2017 was
primarily due to the impact of additional depletion, depreciation and amortization expense in 2017 related to the abandonment
of the Ninian North platform in the North Sea.
ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Expense
$/BOE (1)
2018
2017
2016
$
$
$
87 $
80 $
29
9
27
9
125 $
0.53 $
116 $
0.46 $
66
35
12
113
0.45
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement
obligation due to the passage of time.
Asset retirement obligation accretion expense per BOE for 2018 increased 15% to $0.53 per BOE from $0.46 per BOE for
2017 (2016 – $0.45 per BOE).
29
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Oil Sands Mining and Upgrading
OPERATING HIGHLIGHTS
The Company continues to focus on safe, reliable and efficient operations and leveraging its expertise in capturing
synergies following the acquisition completed in 2017. Production averaged 426,190 bbl/d during 2018, reflecting strong,
reliable operations at Horizon, together with incremental reliability at AOSP. Through the Company's continuous focus on
cost control and efficiencies, high utilization rates and reliability of operations, adjusted cash production costs averaged
$21.05 per bbl for 2018.
PRODUCT PRICES, ROYALTIES AND TRANSPORTATION
($/bbl) (1)
SCO realized sales price (2)
Bitumen value for royalty purposes (3)
Bitumen royalties (4)
Transportation
2018
2017
68.61 $
63.98 $
40.02 $
41.05 $
3.09 $
1.61 $
1.64 $
1.54 $
2016
58.59
27.57
0.54
1.77
$
$
$
$
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending and feedstock costs.
(3) Calculated as the annual average of the bitumen valuation methodology price.
(4) 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 $68.61 per bbl for 2018, an increase
of 7% compared with $63.98 per bbl for 2017 (2016 – $58.59 per bbl). The increase in SCO pricing for 2018 compared to 2017
primarily reflected WTI benchmark pricing.
CASH PRODUCTION COSTS
The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 22 to the
Company’s audited consolidated financial statements.
($ millions)
Cash production costs
Less: costs incurred during turnaround periods
Adjusted cash production costs
Adjusted cash production costs, excluding natural gas costs
Natural gas costs
Adjusted cash production costs
($/bbl) (1)
Adjusted cash production costs, excluding natural gas costs
Natural gas costs
Adjusted cash production costs
Sales (bbl/d)
(1) Amounts expressed on a per unit basis are based on sales volumes.
$
$
$
$
$
$
2018
2017
3,367 $
2,600 $
(109)
(216)
2016
1,292
(151)
3,258 $
2,384 $
1,141
3,156 $
2,239 $
1,057
102
145
84
3,258 $
2,384 $
1,141
2018
2017
20.39 $
21.98 $
0.66
1.42
2016
23.36
1.84
21.05 $
23.40 $
25.20
424,112
279,084
123,652
Adjusted cash production costs for 2018 decreased 10% to $21.05 per bbl from $23.40 per bbl for 2017 (2016 – $25.20 per bbl).
The decrease in adjusted cash production costs per barrel for 2018 from 2017 primarily reflected the Company's high utilization rates
and reliability and the capture of cost synergies between the operations, as well as additional capacity from Phase 3 production at
Horizon and the acquisition of AOSP.
30
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. DEPLETION, DEPRECIATION AND AMORTIZATION
($ millions, except per bbl amounts)
Depletion, depreciation and amortization
Less: depreciation incurred during turnaround periods
Adjusted depletion, depreciation and amortization
$/bbl (1)
(1) Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods.
2018
2017
1,557 $
1,220 $
(56)
(213)
1,501 $
1,007 $
2016
662
(99)
563
9.70 $
9.89 $
12.43
$
$
$
Adjusted depletion, depreciation and amortization expense per barrel for 2018 decreased 2% to $9.70 per bbl from
$9.89 per bbl for 2017 (2016 – $12.43 per bbl), primarily due to the impact of AOSP, which has a lower depletion rate.
ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per bbl amounts)
Expense
$/bbl (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2018
2017
$
$
61 $
48 $
0.40 $
0.47 $
2016
29
0.64
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 per barrel for 2018 decreased 15% to $0.40 per bbl from $0.47 per bbl for 2017
(2016 – $0.64 per bbl), reflecting higher sales volumes.
Midstream
($ millions)
Revenue
Less:
Production expense
Depreciation
Equity loss (gain) from Redwater Partnership
Gain on disposition and revaluation of properties
Segment earnings before taxes
2018
2017
$
102 $
102 $
21
14
5
–
16
9
(31)
(114)
$
62 $
222 $
2016
114
25
11
(7)
(218)
303
The Company's Midstream assets 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 46% 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 asset ownership allows the Company to control transportation
costs, earn third party revenue, and manage the marketing of heavy crudes.
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.
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 $9,700 million. The Project is currently in
the commissioning phase, with completion targeted for the second quarter of 2019. 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 maintain the agreed debt to equity ratio of 80/20. To December 31, 2018, each party has provided $439 million of
subordinated debt, together with accrued interest thereon of $152 million, for a Company total of $591 million. Any additional
subordinated debt financing is not expected to be significant.
31
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt portion
of the monthly cost of service toll, currently consisting of interest and fees, with principal repayments beginning in 2020.
The Company is unconditionally obligated to pay this portion of the cost of service toll over the 30 year tolling period. As at
December 31, 2018, the Company had recognized $62 million in prepaid service tolls.
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, 2018, Redwater Partnership had borrowings of $2,333 million under its secured $3,500 million syndicated
credit facility. During 2018, Redwater Partnership extended $2,000 million of the $3,500 million revolving syndicated credit
facility to June 2021. The remaining $1,500 million was extended on a fully drawn non-revolving basis maturing February 2020.
Corporate and Other
ADMINISTRATION EXPENSE
($ millions, except per BOE amounts)
Expense
$/BOE (1)
2018
2017
$
$
325 $
0.83 $
319 $
0.91 $
2016
345
1.17
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense per BOE for 2018 decreased 9% to $0.83 per BOE from $0.91 per BOE for 2017 (2016 –
$1.17 per BOE). Administration expense per BOE decreased for 2018 from 2017 primarily due to higher sales volumes.
SHARE-BASED COMPENSATION
($ millions)
(Recovery) expense
2018
2017
$
(146) $
134 $
2016
355
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 an $146 million share-based compensation recovery for the year ended December 31, 2018, 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 the share-based compensation recovery for 2018 was an expense of $8 million
related to performance share units granted to certain executive employees (2017 – $5 million; 2016 – $nil). For 2018, the Company
recovered $19 million of share-based compensation costs from the Oil Sands Mining and Upgrading segment (2017 – $14 million
costs charged, 2016 – $67 million costs charged).
INTEREST AND OTHER FINANCING EXPENSE
($ 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.
$
$
$
2018
2017
808 $
713 $
69
739 $
1.88 $
82
631 $
1.79 $
3.9%
3.8%
2016
616
233
383
1.30
3.9%
32
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Gross interest and other financing expense for 2018 increased from 2017 primarily due to the impact of higher average debt
levels as a result of acquisitions completed in 2017 and higher interest rates in 2018. Capitalized interest of $69 million for 2018
was primarily related to Kirby North and residual project activities at Horizon.
Net interest and other financing expense for 2018 increased 5% to $1.88 per BOE from $1.79 per BOE for 2017 (2016 –
$1.30 per BOE). The increase for 2018 from 2017 was primarily due to higher average debt levels as a result of acquisitions
completed in 2017 and lower capitalized interest related to the completion of Horizon Phase 3.
The Company’s average effective interest rate of 3.9% for 2018 was consistent with 2017 and 2016.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency
exposures. These derivative financial instruments are not intended for trading or speculative purposes.
($ millions)
2018
2017
2016
Crude oil and NGLs financial instruments
$
(27) $
(32) $
Natural gas financial instruments
Foreign currency contracts
Realized (gain) loss
Crude oil and NGLs financial instruments
Natural gas financial instruments
Foreign currency contracts
Unrealized (gain) loss
Net (gain) loss
5
(77)
(7)
37
(99) $
(2) $
16 $
– $
(4)
(47)
(35) $
(134) $
(6)
43
37 $
35 $
$
$
$
$
–
–
8
8
–
6
19
25
33
During 2018, net realized risk management gains were related to the settlement of foreign currency contracts and crude oil
and NGLs financial instruments. The Company recorded a net unrealized gain of $35 million ($36 million after-tax) on its risk
management activities for 2018 (2017 – $37 million unrealized loss, $33 million after-tax; 2016 – $25 million unrealized loss,
$21 million after-tax).
Complete details related to outstanding derivative financial instruments at December 31, 2018 are disclosed in note 19 to the
Company's audited consolidated financial statements.
FOREIGN EXCHANGE
($ millions)
Net realized loss
Net unrealized loss (gain)
Net loss (gain) (1)
2018
2017
2016
$
$
121 $
34 $
706
(821)
827 $
(787) $
38
(93)
(55)
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange loss for 2018 was primarily due to foreign exchange rate fluctuations on settlement of working
capital items denominated in US dollars or UK pounds sterling and the repayment of US$600 million of 1.75% notes and
US$400 million of 5.90% notes. The net unrealized foreign exchange loss for 2018 was primarily related to the impact of the
weakening Canadian dollar with respect to outstanding US dollar debt, partially offset by the reversal of the net unrealized
foreign exchange loss on the repayment of US$600 million of 1.75% notes and US$400 million of 5.90% notes. The net
unrealized loss (gain) for each of the periods presented included the impact of cross currency swaps (2018 – unrealized gain of
$118 million, 2017 – unrealized loss of $280 million, 2016 – unrealized loss of $295 million). The US/Canadian dollar exchange rate at
December 31, 2018 was US$0.7328 (December 31, 2017 – US$0.7988, December 31, 2016 – US$0.7448).
33
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. INCOME TAXES
($ millions, except income tax rates)
North America (1)
North Sea
Offshore Africa
PRT – North Sea
Other taxes
Current income tax expense (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
2018
2017
$
312 $
(145) $
28
54
(29)
9
374
540
17
557
931
–
57
45
(132)
11
(164)
586
54
640
476
(10)
Effective income tax rate on adjusted net earnings (loss) from operations (2)
21%
27%
$
931 $
466 $
(1) Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments.
(2) Excludes the impact of current and deferred PRT expense and other current income tax expense.
2016
(377)
(74)
22
(198)
9
(618)
(106)
(135)
(241)
(859)
221
(638)
45%
The effective income tax rate for 2018 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 2018 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.
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 2019, current income tax expense is targeted to range from $300 million to $400 million in Canada and $55 million to
$85 million in the North Sea and Offshore Africa.
During 2018,
the Company filed Scientific Research and Experimental Development claims of approximately
$265 million (2017 – $345 million; 2016 – $549 million) relating to qualifying research and development expenditures for Canadian
income tax purposes.
34
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Net Capital Expenditures (1)
($ millions)
Exploration and Evaluation
Net expenditures (proceeds) (2) (3) (4)
Property, Plant and Equipment
Net property acquisitions (2) (3) (4)
Well drilling, completion and equipping
Production and related facilities
Capitalized interest and other (5)
Net expenditures
Total Exploration and Production
Oil Sands Mining and Upgrading
Project costs (6)
Sustaining capital
Turnaround costs
Acquisitions of Exploration and Evaluation assets (2) (4) (7)
Net property acquisitions (2) (4)
Capitalized interest and other (5)
Total Oil Sands Mining and Upgrading
Midstream (8)
Abandonments (9)
Head office
Total net capital expenditures
By segment
North America (2) (3) (4)
North Sea (3)
Offshore Africa (3)
Oil Sands Mining and Upgrading (4) (7)
Midstream (8)
Abandonments (9)
Head office
Total
2018
2017
2016
$
48 $
149 $
(6)
98
1,446
1,262
106
2,912
2,960
438
665
112
218
–
14
1,219
1,001
860
91
3,171
3,320
821
561
155
219
11,604
76
1,447
13,436
13
290
21
80
274
19
159
712
369
91
1,331
1,325
1,920
379
135
–
–
284
2,718
(533)
267
17
$
$
4,731 $
17,129 $
3,794
2,671 $
3,056 $
1,048
131
158
160
104
1,447
13,436
13
290
21
80
274
19
126
151
2,718
(533)
267
17
$
4,731 $
17,129 $
3,794
(1) Net capital expenditures exclude fair value and revaluation adjustments, and include non-cash transfers of property, plant and equipment to inventory due to
change in use.
(2) Includes business combinations.
(3) Includes proceeds from the acquisition and disposition of properties.
(4) During 2017, total purchase consideration for the acquisition of 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.
(5) Capitalized interest and other includes expenditures related to land acquisition and retention, seismic, and other adjustments.
(6) Includes Horizon Phase 2/3 construction costs.
(7) In the fourth quarter of 2018, following integration of the Joslyn oil sands project into the Horizon mine plan and determination of proved crude oil reserves,
the exploration and evaluation assets were transferred to property, plant, and equipment.
(8) Includes non-cash share consideration of $190 million received from Inter Pipeline on the disposition of Midstream assets in 2016.
(9) Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table.
35
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. NET CAPITAL EXPENDITURES, AS RECONCILED TO CASH FLOWS USED IN INVESTING ACTIVITIES
($ millions)
Cash flows used in investing activities
Net change in non-cash working capital (1) (2)
Investment in other long-term assets
Share consideration in business acquisitions (dispositions)
Abandonment expenditures (3)
Net capital expenditures
2018
2017
$
4,814 $
13,102 $
(345)
(28)
–
290
22
(87)
3,818
274
2016
3,811
5
(99)
(190)
267
$
4,731 $
17,129 $
3,794
(1) Includes net working capital of $291 million related to the acquisition of AOSP in 2017.
(2) Includes property, plant and equipment of $80 million transferred to inventory in 2016.
(3) The Company excludes abandonment expenditures from “Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities” in the "Financial and
Operational Highlights" section of this MD&A.
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 expenses.
Net capital expenditures for 2018 were $4,731 million compared with $17,129 million for 2017 (2016 – $3,794 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. Net capital expenditures
for 2018 included:
■■ $105 million (US$79 million) of proceeds for the disposal of a 30% interest in the exploration right in South Africa,
comprised of exploration and evaluation assets of $89 million, including a recovery of $14 million of past incurred costs in
the Offshore Africa segment;
■■ $218 million of consideration for the acquisition of the Joslyn oil sands project in the Oil Sands Mining and Upgrading
segment (comprising $100 million cash on closing with the remaining balance paid equally over the next five years);
■■ $22 million of cash consideration for the acquisition of Laricina Energy Ltd. in the North America Exploration and Production
segment (net of $24 million of cash acquired); and
■■ $73 million of cash proceeds for the acquisition of the remaining interest at the Ninian field in the North Sea.
2019 CAPITAL BUDGET
On December 5, 2018, the Company announced its 2019 Capital Budget. The 2019 budget targets a base capital program of
$3,700 million, including $3,100 million to maintain current production levels and approximately $600 million directed toward
long-term growth projects. The Company maintains capital flexibility in its 2019 budget. Should market access conditions
improve, the Company has the capability to adjust 2019 capital spending. Capital expenditures in 2019 are discussed in further
detail in the “Outlook” section of this MD&A.
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.
2018
18
483
9
615
1,125
98%
2017
21
495
7
289
812
99%
2016
9
174
7
268
458
96%
36
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
North America
During 2018, the Company targeted 18 net natural gas wells, 6 in Northeast British Columbia and 12 in Northwest Alberta. The
Company also targeted 486 net crude oil wells. The majority of these net wells were concentrated in the Company's Northern
Plains region where 240 primary heavy crude oil wells, 125 bitumen (thermal oil) wells, 22 Pelican Lake heavy crude oil wells
and 7 light crude oil wells were drilled. Another 92 wells targeting light crude oil were drilled outside the Northern Plains region.
The Company's strategic and proactive decisions and its ability to utilize capital flexibility based on its large, balanced and
diverse asset base has been reflected in the North America drilling program. During 2018, the Company reallocated capital
spending from primary heavy crude oil to light crude oil, with an increase of 32 net wells in light crude oil and a corresponding
decrease of 137 net wells in primary heavy crude oil.
North Sea
During 2018, the Company completed four gross production wells and one gross injection well (4.9 on a net basis), successfully
completing the 2018 drilling program in the North Sea.
Offshore Africa
During 2018, the Company completed three gross production wells (1.7 on a net basis) at Baobab. The Company is targeting
one gross production well and two gross injection wells at Baobab in 2019.
The Company has retained a 20% working interest in Block 11B/12B, off the southern coast of South Africa. In late December,
the operator of the exploration right commenced the drilling of an exploratory well. Subsequent to December 31, 2018, the
operator announced that drilling results indicate the presence of natural gas condensate. The Company expects the cost of
the current exploration well to be fully carried pursuant to two separate farm-out agreements that were completed in 2018.
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 income (loss)
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)
2018
2017
$
(601) $
513 $
2016
1,056
$
20,623 $
22,458 $
16,805
101
137
17
$
20,522 $
22,321 $
16,788
$
9,323 $
9,109 $
4,671
22,529
122
22,612
21,526
(68)
70
$
31,974 $
31,653 $
26,267
39%
34%
8%
6%
41%
29%
8%
6%
39%
26%
(1%)
0%
(1) Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
(2) Includes the current portion of long-term debt (2018 – $1,141 million, 2017 – $1,877 million, 2016 – $1,812 million).
(3) Long-term debt is stated at its carrying value, net of fair value adjustments, original issue discounts and premiums and transaction costs.
(4) Calculated as 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.
As at December 31, 2018, the Company’s capital resources consisted primarily of cash flows from operating activities, available
bank credit facilities and access to debt capital markets. Cash flows from operating activities and the Company’s ability to
renew existing bank credit facilities and raise new debt is dependent on factors discussed in the “Risks and Uncertainties”
section of this MD&A. In addition, the Company’s ability to renew existing bank credit facilities and raise new debt reflects
current credit ratings as determined by independent rating agencies, and the conditions of the market. The Company continues
to believe that its internally generated cash flows from operating activities 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.
37
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. On an ongoing basis the Company continues to focus on its balance sheet strength and available liquidity by:
■■ Monitoring cash flows from operating activities, 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 cash flows from operating activities to facilitate net repayment of bank credit facilities and US dollar debt securities
of $3,312 million for 2018, excluding the impact of foreign exchange on debt balances, including:
■●
■●
■●
repayment and cancellation of the $125 million non-revolving credit facility;
repayment and cancellation of $1,200 million of the $3,000 million non-revolving credit facility; and
repayment of US$600 million of 1.75% notes and US$400 million of 5.90% notes.
■■ Additionally, the Company utilized available liquidity to settle the deferred payment to Marathon for $481 million, resulting
in total net repayments of debt of $2,831 million.
■■ Reviewing the Company's borrowing capacity:
■● During 2018, the Company extended the $2,425 million revolving syndicated credit facility originally due June 2020 to
June 2022. During 2017, the Company extended $2,095 million of the other $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. Each of the $2,425 million revolving facilities is extendible annually at the mutual
agreement of the Company and the lenders. If the facilities are not extended, the full amount of the outstanding principal
is repayable on the maturity date. Borrowings under these facilities may be made by way of pricing referenced to Canadian
dollar bankers' acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian prime rate.
■● During 2018, the Company extended the $2,200 million non-revolving credit facility originally due October 2019 to October
2020. Borrowings under the $2,200 million non-revolving credit facility may be made by way of pricing referenced to
Canadian dollar bankers’ acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian prime rate. As
at December 31, 2018, the $2,200 million facility was fully drawn.
■● During 2018, the Company extended the $750 million non-revolving credit facility originally due in February 2019 to
February 2021. Borrowings under the $750 million non-revolving term credit facility may be made by way of pricing
referenced to Canadian dollar bankers’ acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian
prime rate. As at December 31, 2018, the $750 million facility was fully drawn.
■● Borrowings under the $1,800 million non-revolving credit facility may be made by way of pricing referenced to Canadian
dollar bankers’ acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian prime rate. This facility
matures in May 2020 and is subject to annual amortization of 5% of the original balance. As at December 31, 2018, the
$1,800 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 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.
■■ Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant
packages. The Company is subject to a financial covenant that requires debt to book capitalization as defined in its credit
facility agreements to not exceed 65%. As at December 31, 2018, the Company was in compliance with this covenant; 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.
As at December 31, 2018, the Company had in place revolving bank credit facilities of $4,976 million of which $4,723 million
was available. Additionally, the Company had in place fully drawn term credit facilities of $4,750 million. This excludes certain
other dedicated credit facilities supporting letters of credit.
38
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. As at December 31, 2018, the Company had total US dollar denominated debt with a carrying amount of $14,611 million
(US$10,708 million), before transaction costs and original issue discounts. This included $5,604 million (US$4,108 million)
hedged by way of cross currency swaps (US$1,050 million) and foreign currency forwards (US$3,058 million). The fixed
repayment amount of these hedging instruments is $5,256 million, resulting in a notional reduction of the carrying amount
of the Company’s US dollar denominated debt by approximately $348 million to $14,263 million as at December 31, 2018.
Net long-term debt was $20,522 million at December 31, 2018, resulting in a debt to book capitalization ratio of 39%
(December 31, 2017 – 41%, December 31, 2016 - 39%); this ratio is within the 25% to 45% internal range utilized by
management. This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity
prices occurs. The Company may be below the low end of the targeted range when cash flows from operating activities is
greater than current investment activities. The Company remains committed to maintaining a strong balance sheet, adequate
available liquidity and a flexible capital structure. Further details related to the Company’s long-term debt at December 31,
2018 are discussed in note 11 to the Company’s audited 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.
As at December 31, 2018, 28,000 bbl/d of currently forecasted crude oil volumes were hedged using WCS differential swaps
for January to March 2019 and 8,000 bbl/d were hedged for January to September 2019. Additionally, 10,000 MMbtu/d of
currently forecasted natural gas volumes were hedged using AECO basis swaps for January to March 2019, 30,000 GJ/d were
hedged using AECO fixed price swaps for January to March 2019 and 10,000 GJ/d were hedged for April to October 2019.
Subsequent to December 31, 2018, the Company has hedged an additional 105,000 GJ/d of currently forecasted natural gas
volumes using AECO fixed price swaps for April to October 2019. Further details related to the Company’s commodity derivative
financial instruments outstanding at December 31, 2018 are discussed in note 19 of the Company’s audited consolidated
financial statements.
SHARE CAPITAL
As at December 31, 2018, there were 1,201,886,000 common shares outstanding (December 31, 2017 – 1,222,769,000
common shares) and 46,685,000 stock options outstanding. As at March 5, 2019, the Company had 1,199,849,000 common
shares outstanding and 50,413,000 stock options outstanding.
On March 6, 2019, the Board of Directors approved an increase in the quarterly dividend to $0.375 per common share,
beginning with the dividend payable on April 1, 2019. 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.
On May 16, 2018, 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 61,454,856
common shares, over a 12-month period commencing May 23, 2018 and ending May 22, 2019. The Company's Normal
Course Issuer Bid announced in March 2017 expired on May 22, 2018.
During 2018, the Company purchased for cancellation 30,857,727 common shares at a weighted average price of
$41.56 per common share for a total cost of $1,282 million. Retained earnings were reduced by $1,044 million, representing
the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2018,
the Company purchased 4,340,000 common shares at a weighted average price of $35.86 per common share for a total cost
of $156 million.
39
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Commitments and Contingencies
In the normal course of business, the Company has entered into various commitments that will have an impact on the
Company’s future operations. The following table summarizes the Company’s commitments as at December 31, 2018:
($ millions)
Product transportation and pipeline
North West Redwater Partnership debt service toll (1)
Offshore equipment operating leases
Long-term debt (2)
Interest and other financing expense (3)
Office leases
Other
2019
2020
2021
2022
2023 Thereafter
$
$
$
692 $
664 $
620 $
516 $
381 $ 3,991
86 $
94 $
126 $
157 $
158 $
157 $ 2,858
73 $
75 $
8 $
– $
–
$ 1,141 $ 5,996 $ 1,444 $ 1,003 $ 1,365 $ 9,793
$
$
$
836 $
755 $
610 $
558 $
500 $ 5,327
42 $
85 $
42 $
35 $
39 $
32 $
31 $
32 $
32 $
31 $
89
424
(1) Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt portion of the monthly cost of service
toll, currently consisting of interest and fees, with principal repayments beginning in 2020. Included in the service toll is $1,301 million of interest payable
over the 30 year tolling period.
(2) Long-term debt represents principal repayments only and does not reflect original issue discounts and premiums or transaction costs.
(3) Interest and other financing payments were estimated based upon applicable interest and foreign exchange rates as at December 31, 2018.
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.
Reserves
For the years ended December 31, 2018, 2017 and 2016, 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, 2018, prepared in accordance with NI 51-101 reserves disclosures:
Light
and
Medium
Crude Oil
Primary
Heavy
Crude Oil
Proved Reserves
(MMbbl)
(MMbbl)
December 31, 2017
374
–
12
18
–
11
–
5
14
(35)
399
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
40
198
–
14
6
–
2
(5)
1
(2)
(32)
182
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
327
–
–
–
1
–
–
1
Bitumen
(Thermal
Oil)
Synthetic
Crude Oil
(MMbbl)
1,350
–
171
(MMbbl)
5,264
–
808
4
2
–
–
–
–
–
–
–
–
(1)
(23)
305
52
(39)
1,540
175
(156)
6,091
Natural
Gas
(Bcf)
6,771
–
122
470
3
82
(3)
(305)
77
(565)
6,652
Natural
Gas
Liquids
Barrels
of Oil
Equivalent
(MMbbl)
(MMBOE)
229
–
9
38
–
4
–
(4)
6
(15)
267
8,871
–
1,034
144
4
30
(5)
(48)
257
(394)
9,893
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
Light
and
Medium
Crude Oil
Primary
Heavy
Crude Oil
(MMbbl)
(MMbbl)
Proved Plus
Probable Reserves
December 31, 2017
544
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2018
–
16
24
1
17
–
(1)
9
(35)
575
272
–
21
8
–
3
(6)
1
(15)
(32)
252
Pelican
Lake
Heavy
Crude Oil
(MMbbl)
469
–
–
–
3
–
–
1
(5)
(23)
445
Bitumen
(Thermal
Oil)
Synthetic
Crude Oil
Natural
Gas
(Bcf)
9,619
–
215
861
4
104
(5)
(409)
(90)
(565)
(MMbbl)
6,063
–
879
–
–
–
–
–
246
(156)
7,032
9,734
Natural
Gas
Liquids
Barrels
of Oil
Equivalent
(MMbbl)
(MMBOE)
335
–
14
60
–
5
–
(5)
3
11,866
–
1,196
241
8
445
(7)
(72)
99
(15)
397
(394)
13,382
(MMbbl)
2,580
–
230
5
4
403
–
–
(124)
(39)
3,059
At December 31, 2018, the company gross proved crude oil, bitumen (thermal oil), SCO and NGLs reserves totaled
8,784 MMbbl, and company gross proved plus probable crude oil, bitumen (thermal oil), SCO and NGLs reserves totaled
11,760 MMbbl. Proved reserves additions and revisions replaced 447% of 2018 production. Additions to proved reserves
resulting from exploration and development activities, acquisitions and future offset additions amounted to 1,095 MMbbl, and
additions to proved plus probable reserves amounted to 1,687 MMbbl. Net positive revisions amounted to 247 MMbbl for
proved reserves and 110 MMbbl for proved plus probable reserves, primarily due to technical revisions.
At December 31, 2018, the company gross proved natural gas reserves totaled 6,652 Bcf, and company gross proved plus
probable natural gas reserves totaled 9,734 Bcf. Proved reserves additions and revisions replaced 79% of 2018 production.
Additions to proved reserves resulting from exploration and development activities, acquisitions and future offset additions
amounted to 674 Bcf, and additions to proved plus probable reserves amounted to 1,179 Bcf. Net negative revisions amounted
to 228 Bcf for proved reserves and 499 Bcf for proved plus probable reserves, primarily due to economic factors.
The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence
procedures with each of the Company’s Independent Qualified Reserves Evaluators to review the qualifications of and
procedures used by each evaluator in determining the estimate of the Company’s quantities and related net present value of
future net revenue of the remaining reserves.
Additional reserves disclosure is annually disclosed in the AIF and the “Supplementary Oil and Gas Information” section of the
Company’s Annual Report.
Risks and Uncertainties
The Company is exposed to various operational risks inherent in the exploration, development, production and marketing
of crude oil and NGLs and natural gas and the mining, 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;
41
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
■■ Foreign exchange risk due to the effect of fluctuating exchange rates on the Company’s US dollar denominated debt and
revenue from sales 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, including but not limited to restrictions on production;
■■ 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 seek to 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 seeks to manage 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 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 seeks to manage 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 designed 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, 2018.
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. Environmental, social, economic and health
considerations are evaluated in new project designs and in operations to improve environmental performance. Processes
are employed to avoid, mitigate, minimize or compensate for environmental effects. Working with local communities, the
Company considers the values to the people using the land in proximity to operations and adapts projects in recognition of
those values.
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.
42
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 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, water management and land management to minimize disturbance impacts. The
Company’s environmental risk management strategies employ an Environmental Management Plan (the “Plan”). As part of
risk management, the Company develops, assesses and implements technologies and innovative practices that will improve
environmental performance, often through collaborative efforts with industry partners, governments and research institutions.
Details of the Plan, along with performance results, are presented to, and reviewed by, the Board of Directors quarterly.
The Plan and the Company's 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 proactive programs that include:
■■ Environmental planning to assess impacts and implement avoidance and mitigation programs in order to preserve high
value biodiversity;
■■ Continued evaluation of new technologies to reduce environmental impacts, including support for Canada’s Oil Sands
Innovation Alliance (“COSIA”), Petroleum Technology Alliance Canada (“PTAC”) and other research institutions;
■■ CO2 reduction programs including carbon capture, CO2 injection for EOR, CO2 sequestration in tailings and the Quest
carbon capture and storage facility;
■■ A methane emission reduction program, including solution gas conservation to reduce methane venting, and an
equipment retrofit program to reduce methane emissions from pneumatic equipment;
■■ Optimization of efficiencies at the Company’s facilities;
■■ Water programs to improve efficiency of use and recycle rates as well as to reduce fresh water use;
■■ An effective reclamation and decommissioning program across the Company’s operations, returning sites to their former
state. In North America, well abandonment and progressive reclamation of large contiguous areas of land advances
biodiversity and establishes functional wildlife habitats;
■■ Tailings management in Oil Sands Mining to minimize fine tailings and promote reclamation;
■■ Monitoring programs to assess changes to biodiversity, wildlife and fisheries in order to manage construction and operation
effects and to assess reclamation success;
■■ Participation and support for the Oil Sands Monitoring Program of regional important resources;
■■ Groundwater monitoring for all thermal in situ and mine operations;
■■ An active spill prevention and management program; and
■■ An internal environmental compliance audit and inspection program of operating facilities.
The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately
60 years and have been discounted using a weighted average discount rate of 5.0% (2017 – 4.7%; 2016 – 5.2%). For 2018, the
Company’s capital expenditures included $290 million for abandonment expenditures (2017 – $274 million; 2016 – $267 million).
The Company’s estimated discounted ARO at December 31, 2018 was as follows:
($ millions)
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream
2018
2017
$
1,665 $
1,840
707
134
1,379
1
755
245
1,486
1
$
3,886 $
4,327
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.
43
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. GREENHOUSE GAS AND OTHER AIR EMISSIONS
As a result of the Company’s large, diversified and balanced portfolio and its defined pathway to drive long-term emissions
reductions through technology and innovation, the Company is well-positioned to be resilient in a lower carbon economy.
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, 2018, the Alberta government implemented the Carbon
Competitiveness Incentive Regulation (CCIR) to replace the Specified Gas Emitters Regulation, for the regulation of GHG
emissions from large facilities. The Alberta government has also finalized regulations to reduce methane emissions from the
upstream oil and gas sector (consistent with the federal reduction target), with the first regulatory requirements coming into
effect January 1, 2020. A previously announced carbon price on combustion emissions from the upstream oil and gas sector
is scheduled to begin in 2023. In British Columbia, the provincial government has announced a methane reduction target,
comparable to the federal target, and has released final regulations to achieve this target. The Saskatchewan government has
also released a regulation to reduce methane emissions from oil production facilities, effective 2020.
In Alberta, GHG reduction regulations came into effect July 1, 2007, affecting facilities emitting more than 100 kilotonnes of
CO2e annually, and those facilities that elect to “opt-in” to the regulation. The carbon price in Alberta is currently $30/tonne
for emissions above the regulated limits. Eight of the Company’s operated facilities (the facilities at Horizon and AOSP, 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, the Wapiti gas plant, and the Brintnell power generation facility) 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 became subject to a reduction target on
January 1, 2019. In British Columbia, carbon tax is currently being assessed at $35/tonne of CO2e on fuel consumed
and gas flared in the province, with the rate increasing to $40/tonne on April 1, 2019. 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 British Columbia government is implementing a program (the CleanBC Plan) to partially mitigate the impact of the carbon
tax increases on emission intensive trade exposed (EITE) sectors. The Saskatchewan government has released a regulation
that applies to facilities emitting more than 25 kilotonnes of CO2e annually and will require the North Tangleflags in situ heavy
oil facility and the Senlac in situ heavy oil facility to meet reduction targets for GHG emissions effective 2019. The government
of Canada has determined that a federal “backstop” carbon pricing system will apply beginning in 2019 in specific provinces
and territories within Canada, including the provinces of Saskatchewan and Manitoba in which the Company operates. The
federal backstop system will consist of an output-based pricing system for facilities that emit more than 25 kilotonnes CO2e
annually, and a fuel charge that applies to facilities with emissions below this level.
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 offshore
facilities and on trading mechanisms to ensure compliance with requirements now in effect.
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.
44
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Accounting Policies and Standards
CHANGES IN ACCOUNTING POLICIES
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.
The Company adopted IFRS 15 on January 1, 2018 using the retrospective with cumulative effect method. There were no
changes to reported net earnings (loss) or retained earnings as a result of adopting IFRS 15. Under the standard, the Company
is required to provide additional disclosure of disaggregated revenue by major product type. In connection with adoption
of the standard, the Company has reclassified certain comparative amounts in a manner consistent with the presentation
adopted for the year ended December 31, 2018. For details refer to note 2 of the Company’s audited consolidated financial
statements as at December 31, 2018.
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. Applying this expedient had no impact to the revenue recognized under the
previous revenue accounting standard as all performance obligations had been met and the consideration had been determined.
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 Company retrospectively adopted the amendments to IFRS 9 on January 1, 2018 and elected to apply the limited
exemption in IFRS 9 relating to transition for impairment. Accordingly, provisions for impairment have not been restated in the
comparative periods. Adoption of the amendment did not have a significant impact on the Company’s previous accounting for
impairment of financial assets.
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
In October 2018, the IASB issued amendments to IFRS 3 “Definition of a Business” that narrowed and clarified the definition
of a business. The amendments also permit a simplified assessment of whether an acquired set of activities and assets is
a group of assets rather than a business. The amendments are effective January 1, 2020 with earlier adoption permitted.
The amendments apply to business combinations after the date of adoption. The Company is assessing the impact of
these amendments on its consolidated financial statements.
In October 2018, the IASB issued amendments to IAS 1 “Presentation of Financial Statements” and IAS 8 “Accounting
Policies, Changes in Accounting Estimates and Errors”. The amendments make minor changes to the definition of the term
"material" and align the definition across all IFRS Standards. Materiality is used in making judgments related to the preparation
of financial statements. The amendments are effective January 1, 2020 with earlier adoption permitted. The Company is
assessing the impact of these amendments on its consolidated financial statements.
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 assets 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 has determined that these amendments have no significant impact 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 has determined that this interpretation has no significant impact on its consolidated
financial statements.
45
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. IFRS 16 "Leases"
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 and requires balance sheet recognition for all leases. Certain short-term (less than 12 months)
and low-value leases (as defined in the standard) are exempt from the requirements, and may continue to be treated as an
expense. Leases to explore for or use crude oil, natural gas, minerals and similar non-regenerative resources are exempt from
the standard.
The Company will adopt IFRS 16 on January 1, 2019 using the retrospective with cumulative effect method with no impact
to opening retained earnings at the date of adoption. In accordance with the transitional provisions in the standard, balances
reported in the comparative periods will not be restated.
On initial adoption, the Company intends to use the following practical expedients under the standard. Certain expedients are
on a lease-by-lease basis and others are applicable by class of underlying assets:
■■
■■
the use of a single discount rate to a portfolio of leases with reasonably similar characteristics;
leases with a remaining lease term of less than twelve months as at January 1, 2019 will be treated as short- term leases;
and
■■ exclusion of indirect costs for the measurement of lease assets at the date of initial application.
The Company does not intend to apply any practical expedients pertaining to grandfathering of leases assessed under the
previous standard.
On adoption of IFRS 16, the Company will recognize lease assets and liabilities at the present value of the remaining lease
payments, discounted using the Company’s applicable borrowing rate on January 1, 2019. The Company expects to report
additional lease assets and corresponding liabilities of between $1.5 billion and $1.6 billion. The Company continues to finalize
its accounting for leases in accordance with IFRS 16, and the above estimates are subject to change based on finalization of
the Company's review of its lease arrangements.
In the statement of earnings, depletion, depreciation and amortization expense and interest expense will increase, with
corresponding decreases in production, transportation and administration expenses. The Company does not expect to report
a material impact on net earnings. Under the new standard, the Company will report cash outflows for repayment of the
principal portion of the lease liability as cash flows from financing activities. The interest portion of the lease payments will
continue to be classified as cash flows from operating activities.
Where the Company, acting as the operator, signs a lease on behalf of a joint operation and assumes the legal liability for
that lease, the Company will recognize 100% of the related lease asset and lease liability. As the Company recovers its
joint operation partners' share of the costs of the lease contract, these recoveries will be recognized in the consolidated
statements of earnings.
The Company continues to finalize its evaluation of its contracts that are potentially leases under IFRS 16, as well as
implementing changes to policies, internal controls, information systems, and business accounting processes.
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, 2018.
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.
46
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. E&E assets are tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets
may exceed their recoverable amount, by comparing the relevant costs to the fair value of related Cash Generating Units
(“CGUs”), aggregated at 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 of the site. Since these estimates
are specific to the sites involved, there are many individual assumptions underlying the Company’s total ARO amount. These
individual assumptions may be subject to change.
The estimated present values of ARO related to long-term assets are recognized as a liability in the period in which they
are incurred. The provision for the ARO is estimated by discounting the expected future cash flows to settle the ARO at
the Company’s weighted average credit-adjusted risk-free interest rate, which is currently 5.0%. 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.
47
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 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.
48
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Control Environment
The Company’s management, including the President and the Chief Financial Officer and Senior Vice-President, Finance,
evaluated the effectiveness of disclosure controls and procedures as at December 31, 2018, 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, including the President and the Chief Financial Officer and Senior Vice-President, Finance,
also evaluated the effectiveness of internal control over financial reporting as at December 31, 2018, 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 2018 that have materially affected, or are reasonably likely to materially affect, internal control over
financial reporting.
While the Company’s management believes that the Company’s disclosure controls and procedures and internal
control over financial reporting provide a reasonable level of assurance they are effective, they recognize that all control systems have
inherent limitations. Because of its inherent limitations, the Company’s control systems may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Outlook
The Company continues to implement its strategy of maintaining a large portfolio of varied projects, which the Company
believes will enable it, over an extended period of time, to provide consistent growth in production and create shareholder
value. Annual budgets are developed, scrutinized throughout the year and revised if necessary in the context of targeted
financial ratios, project returns, product pricing expectations, and balance in project risk and time horizons. The Company
maintains a high ownership level and operatorship level in all of its properties and can therefore control the nature, timing and
extent of capital expenditures in each of its project areas.
Capital expenditures in 2019 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
Strategic, project development, environment and technology
Sustaining capital
Turnarounds, reclamation and other
Total Oil Sands Mining and Upgrading
Total Capital Expenditures
$
2019
365
775
460
545
30
$
2,175
505
780
240
$
$
1,525
3,700
49
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
Other
SENSITIVITY ANALYSIS
The following table is indicative of the annualized sensitivities of cash flows from operating activities 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 2018, 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
Excluding financial derivatives
Including financial derivatives
Natural gas – AECO C$0.10/Mcf (1)
Excluding financial derivatives
Including financial derivatives
Volume changes
Crude oil – 10,000 bbl/d
Natural gas – 10 MMcf/d
Foreign currency rate change
$0.01 change in US$ (1)
Including financial derivatives
Interest rate change – 1%
Cash flows
from
Operating
Activities
($ millions)
Cash flows
from
Operating
Activities
(per common
share, basic)
Net
earnings
(loss)
($ millions)
Net
earnings
(loss)
(per common
share, basic)
$
$
$
$
$
$
$
$
279 $
274 $
26 $
25 $
126 $
4 $
0.23 $
0.22 $
0.02 $
0.02 $
0.10 $
– $
157 – 163 $
37 $
0.13 $
0.03 $
279 $
274 $
26 $
25 $
99 $
– $
38 $
37 $
0.23
0.22
0.02
0.02
0.08
–
0.03
0.03
(1) For details of financial instruments in place, refer to note 19 to the Company’s audited consolidated financial statements as at December 31, 2018.
50
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
Q1
Q2
Q3
Q4
2018
2017
2016
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
357,460
343,538
359,856
343,054
350,961
359,449
350,958
456,076
407,704
394,382
447,048
426,190
282,026
123,265
21,584
19,438
24,456
18,201
28,702
18,802
21,071
22,185
23,965
19,662
23,426
20,335
23,554
26,096
854,558
793,899
801,742
833,358
820,778
685,236
523,873
1,547
1,485
1,489
1,441
1,490
1,601
1,622
37
30
30
24
38
26
22
25
32
26
39
22
38
31
1,614
1,539
1,553
1,488
1,548
1,662
1,691
615,228
590,963
608,063
583,242
599,310
626,230
621,239
456,076
407,704
394,382
447,048
426,190
282,026
123,265
27,740
24,502
29,485
22,224
35,076
23,108
24,727
26,351
29,264
24,049
29,989
24,019
29,913
31,365
1,123,546
1,050,376
1,060,629
1,081,368
1,078,813
962,264
805,782
51
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. PER UNIT RESULTS – EXPLORATION AND PRODUCTION
Crude oil and NGLs ($/bbl) (1)
Sales price (2)
Transportation
Realized sales price, net of transportation
Royalties
Production expense
Netback
Natural gas ($/Mcf) (1)
Sales price (2)
Transportation
Realized sales price, net of transportation
Royalties
Production expense
Netback (3)
Barrels of oil equivalent ($/BOE) (1)
Sales price (2)
Transportation
Realized sales price, net of transportation
Royalties
Production expense
Netback
Q1
Q2
Q3
Q4
2018
2017
2016
$ 43.06 $ 61.14 $ 57.89 $ 25.95 $ 46.92 $ 48.57 $ 36.93
3.10
39.96
4.87
15.70
3.30
57.84
7.56
15.64
3.00
54.89
7.08
14.47
2.94
23.01
0.92
16.93
3.08
43.84
5.08
15.69
2.80
45.77
5.24
14.89
2.61
34.32
3.40
14.10
$ 19.39 $ 34.64 $ 33.34 $
5.16 $ 23.07 $ 25.64 $ 16.82
$
2.74 $
1.95 $
2.32 $
3.46 $
2.61 $
2.76 $
0.51
2.23
0.10
1.41
0.51
1.44
0.08
1.39
0.42
1.90
0.05
1.33
0.42
3.04
0.10
1.32
0.47
2.14
0.08
1.36
0.39
2.37
0.11
1.27
$
0.72 $
(0.03) $
0.52 $
1.62 $
0.70 $
0.99 $
2.32
0.33
1.99
0.09
1.18
0.72
$ 32.02 $ 41.63 $ 40.77 $ 24.04 $ 34.62 $ 35.54 $ 27.58
3.05
28.97
3.10
12.68
3.20
38.43
4.75
12.75
2.83
37.94
4.44
11.91
2.77
21.27
0.80
13.51
2.96
31.66
3.27
12.71
2.66
32.88
3.40
11.95
2.44
25.14
2.21
11.18
$ 13.19 $ 20.93 $ 21.59 $
6.96 $ 15.68 $ 17.53 $ 11.75
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
(3) Natural gas netbacks exclude netbacks derived from the sale of NGLs. Combining natural gas and NGLs, the netback for the three months ended
December 31, 2018 was $1.84/Mcfe (September 30, 2018 – $1.05/Mcfe, June 30, 2018 – $0.60/Mcfe, March 31, 2018 – $1.19/Mcfe; year ended
December 31, 2018 – $1.18/Mcfe, December 31, 2017 – $1.31/Mcfe, December 31, 2016 – $0.89/Mcfe).
52
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. PER UNIT RESULTS – OIL SANDS MINING AND UPGRADING
Crude oil and NGLs ($/bbl)
SCO sales price
Bitumen royalties (1)
Transportation
Q1
Q2
Q3
Q4
2018
2017
2016
$ 71.61 $ 80.17 $ 81.69 $ 42.73 $ 68.61 $ 63.98 $ 58.59
1.98
1.54
4.25
1.63
4.31
1.73
2.03
1.56
3.09
1.61
21.05
1.64
1.54
0.54
1.77
23.40
25.20
Adjusted cash production costs (2)
21.37
22.94
19.95
19.97
Netback
$ 46.72 $ 51.35 $ 55.70 $ 19.17 $ 42.86 $ 37.40 $ 31.08
(1) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes.
(2) 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
2018
2017
174,140
198,092
165,227
268,795
806,254
588,422
$ 46.77 $ 48.73 $ 49.08 $ 43.31 $
49.08 $
$ 36.88 $ 39.15 $ 40.71 $ 30.11 $
30.11 $
$ 40.50 $ 47.45 $ 42.20 $ 32.94 $
32.94 $
47.00
35.90
44.92
$
39,590 $
54,927
1,201,886
1,222,769
153,374
234,303
154,675
254,619
796,971
608,008
$ 37.63 $ 38.19 $ 37.41 $ 33.86 $
38.19 $
$ 29.21 $ 30.26 $ 31.29 $ 21.85 $
21.85 $
$ 31.47 $ 36.07 $ 32.66 $ 24.13 $
24.13 $
36.78
27.53
35.72
$
29,002 $
43,677
1,201,886
1,222,769
53
Canadian Natural 2018 Annual Report Premium 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, 2018; and
the effectiveness of the Company’s internal control over financial reporting as at December 31, 2018.
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.
TIM S. MCKAY
President
COREY B. BIEBER, CA
Chief Financial Officer and Senior
Vice-President, Finance
RONALD D. KIM, CA
Vice-President,
Finance – Corporate
Calgary, Alberta, Canada
March 6, 2019
54
Canadian Natural 2018 Annual Report Premium 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, 2018. 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, 2018, as stated in their accompanying Report of
Independent Registered Public Accounting Firm.
TIM S. MCKAY
President
COREY B. BIEBER, CA
Chief Financial Officer and Senior
Vice-President, Finance
Calgary, Alberta, Canada
March 6, 2019
55
Canadian Natural 2018 Annual Report Premium 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 and its
subsidiaries (together, the “Company”) as of December 31, 2018 and 2017, 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, 2018, 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, 2018, 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, 2018 and 2017, and its financial performance and its cash flows for each
of the three years in the period ended December 31, 2018 in conformity with International Financial Reporting Standards
as issued by the International Accounting Standards Board (“IFRS”). Also in our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2018, 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 Controls 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. Those 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 risks 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 provide a reasonable basis for our opinions.
56
Canadian Natural 2018 Annual Report Premium 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 financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
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
March 6, 2019
We have served as the Company's auditor since 1973.
57
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Note
2018
2017
$
101 $
1,148
–
955
176
524
116
3,020
2,637
64,559
1,343
$
71,559 $
$
779 $
2,356
151
1,141
335
4,762
19,482
3,890
11,451
39,585
9,323
22,529
122
31,974
$
71,559 $
5
9
10
6
7
10
11
12
11
12
13
14
15
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
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 income taxes payable
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 20).
Approved by the Board of Directors on March 6, 2019
CATHERINE M. BEST
Chair of the Audit
Committee and Director
N. MURRAY EDWARDS
Executive Chairman of the Board of
Directors and Director
58
Canadian Natural 2018 Annual Report Premium 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 loss (gain)
Gain on acquisition, disposition and revaluation
of properties
Loss (gain) from investments
Earnings (loss) before taxes
Current income tax expense (recovery)
Deferred income tax expense (recovery)
Net earnings (loss)
Net earnings (loss) per common share
Basic
Diluted
Note
22 $
2018
22,282 $
(1,255)
21,027
2017 (1)
18,360 $
(1,018)
17,342
6,464
4,189
5,161
325
(146)
186
739
(134)
827
(452)
346
17,505
3,522
374
557
5,675
3,529
5,186
319
134
164
631
35
(787)
(379)
(38)
14,469
2,873
(164)
640
6, 7
12
12
18
19
6, 7, 8
9, 10
13
13
$
2,591 $
2,397 $
17 $
17 $
2.13 $
2.12 $
2.04 $
2.03 $
2016 (1)
12,002
(575)
11,427
4,184
2,822
4,858
345
355
142
383
33
(55)
(250)
(327)
12,490
(1,063)
(618)
(241)
(204)
(0.19)
(0.19)
(1) In connection with adoption of IFRS 15 on January 1, 2018, the Company has reclassified certain comparative amounts in a manner consistent with the
presentation adopted for the year ended December 31, 2018 (see note 2).
Consolidated Statements of Comprehensive
Income (Loss)
$
2018
2,591 $
2017
2,397 $
2016
(204)
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 $nil
(2017 – $9 million, 2016 – $3 million)
Reclassification to net earnings (loss), net of taxes of $6 million
(2017 – $5 million, 2016 – $2 million)
Foreign currency translation adjustment
Translation of net investment
Other comprehensive income (loss), net of taxes
Comprehensive income (loss)
$
2,781 $
2,259 $
5
(39)
(34)
224
190
53
(33)
20
(158)
(138)
(18)
(13)
(31)
26
(5)
(209)
59
Canadian Natural 2018 Annual Report Premium 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
Purchase of common shares under Normal Course
Issuer Bid
Return of capital on PrairieSky Royalty Ltd.
share distribution
Balance – end of year
Retained earnings
Balance – beginning of year
Net earnings (loss)
Purchase of common shares under Normal Course
Issuer Bid
Dividends on common shares
Balance – end of year
Accumulated other comprehensive income (loss)
Balance – beginning of year
Other comprehensive income (loss), net of taxes
Balance – end of year
Shareholders’ equity
Note
14
8
14
14
15
2018
2017
$
9,109 $
4,671 $
–
332
120
(238)
–
9,323
22,612
2,591
(1,044)
(1,630)
22,529
(68)
190
122
3,818
466
154
–
–
9,109
21,526
2,397
–
(1,311)
22,612
70
(138)
(68)
2016
4,541
–
559
117
–
(546)
4,671
22,765
(204)
–
(1,035)
21,526
75
(5)
70
$
31,974 $
31,653 $
26,267
(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 8.
60
Canadian Natural 2018 Annual Report Premium 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 (gain) loss
Unrealized foreign exchange loss (gain)
Realized foreign exchange loss on repayment of
US dollar debt securities
Gain on acquisition, disposition and revaluation
of properties
Loss (gain) from investments
Deferred income tax expense (recovery)
Other
Abandonment expenditures
Net change in non-cash working capital
Cash flows from operating activities
Financing activities
(Repayment) issue of bank credit facilities and
commercial paper, net
Issue of medium-term notes, net
(Repayment) issue of US dollar debt securities, net
Issue of common shares on exercise of stock options
Purchase of common shares under Normal Course
Issuer Bid
Dividends on common shares
Cash flows (used in) from financing activities
Investing activities
Net (expenditures) proceeds on exploration
and evaluation assets
Net expenditures on property, plant and equipment (1)
Acquisition of AOSP and other assets,
net of cash acquired (2)
Investment in other long-term assets
Net change in non-cash working capital
Cash flows used in investing activities
(Decrease) increase in cash and cash equivalents
Cash and cash equivalents – beginning of year
Cash and cash equivalents – end of year
Interest paid, net
Income taxes received
Note
2018
2017
2016
$
2,591 $
2,397 $
(204)
5,161
(146)
186
(35)
706
146
(452)
374
557
(23)
(290)
1,346
10,121
(1,595)
–
(1,236)
332
(1,282)
(1,562)
(5,343)
(266)
(4,175)
–
(28)
(345)
(4,814)
(36)
137
5,186
134
164
37
(821)
–
(379)
(11)
640
(110)
(274)
299
7,262
2,222
1,791
2,733
466
–
(1,252)
5,960
(124)
(4,574)
(8,630)
(87)
313
(13,102)
120
17
$
$
$
101 $
911 $
(225) $
137 $
725 $
(792) $
21
11, 21
11, 21
11, 21
21
21
8
21
4,858
355
142
25
(93)
–
(250)
(299)
(241)
(32)
(267)
(542)
3,452
342
998
(834)
559
–
(758)
307
6
(3,803)
–
(99)
85
(3,811)
(52)
69
17
617
(444)
(1) 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.
(2) 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 8.
61
Canadian Natural 2018 Annual Report Premium 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 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.
Changes in the Company's accounting policies are discussed in note 2.
(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 include 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.
62
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. INVENTORY
(D)
Inventory is primarily comprised of product inventory and materials and supplies and is carried at the lower of cost and net
realizable value. Product inventory is comprised of crude oil held for sale, including pipeline linefill and crude oil stored in
floating production, storage and offloading vessels. Cost of product inventory 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. Cost for materials and supplies
consists of purchase costs and is based on a first-in, first-out or an average cost basis. Net realizable value for materials and
supplies is determined by reference to current market prices.
(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.
63
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Midstream and Head Office
The Company capitalizes all costs that expand the capacity or extend the useful life of the midstream and head office assets.
Midstream assets are depreciated on a straight-line basis over their estimated useful lives ranging from 5 to 30 years. Head
office assets are depreciated on a declining balance basis.
Useful lives
The depletion rates and expected useful lives of property, plant and equipment are reviewed on an annual basis, with changes
in depletion rates and useful lives accounted for prospectively.
Derecognition
A property, plant and equipment asset is derecognized upon disposal or when no future economic benefits are expected to
arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference
between the net disposal proceeds and the carrying amount of the asset) is recognized in net earnings within depletion,
depreciation and amortization.
Major maintenance expenditures
Inspection costs associated with major maintenance turnarounds are capitalized and depreciated over the period to the next
major maintenance turnaround. All other maintenance costs are expensed as incurred.
Impairment
The Company assesses property, plant and equipment for impairment whenever events or changes in circumstances indicate
that the carrying amount of an asset or group of assets may not be recoverable. Indications of impairment include the existence
of low benchmark commodity prices for an extended period of time, significant downward revisions of estimated reserves
volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable
legislative or regulatory frameworks. If an indication of impairment exists, the Company performs an impairment test related
to the assets. Individual assets are grouped for impairment assessment purposes into CGUs, which are the lowest level at
which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets. A CGU's
recoverable amount is the higher of its fair value less costs of disposal and its value in use. Where the carrying amount of a
CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount through
depletion, depreciation and amortization expense.
In subsequent periods, an assessment is made at each reporting date to determine whether there is any indication that
previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the recoverable
amount is re-estimated and the net carrying amount of the asset is increased to its revised recoverable amount. The revised
recoverable amount cannot exceed the carrying amount that would have been determined, net of depletion, 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.
64
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. (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. The
Company adopted IFRS 16 on January 1, 2019 (see note 3).
(K) ASSET RETIREMENT OBLIGATIONS
The Company provides for asset retirement obligations on all of its property, plant and equipment and certain exploration and
evaluation assets 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 NGLs and natural gas products is recognized when performance obligations in the sales
contract are satisfied and it is probable that the Company will collect the consideration to which it is entitled. Performance
obligations are generally satisfied at the point in time when the product is delivered to a location specified in a contract and
control passes to the customer. The Company assesses customer creditworthiness, both before entering into contracts and
throughout the revenue recognition process.
Contracts for sale of the Company’s products generally have terms of less than a year, with certain contracts extending
beyond one year. Contracts in North America generally specify delivery of crude oil and NGLs and natural gas throughout the
term of the contract. Contracts in the North Sea and Offshore Africa generally specify delivery of crude oil at a point in time.
Sales of the Company’s crude oil and NGLs and natural gas products to customers are made pursuant to contracts based
on prevailing commodity pricing at or near the time of delivery and volumes of product delivered. Revenues are typically
collected in the month following delivery and accordingly, the Company has elected to apply the practical expedient to not
adjust consideration for the effects of a financing component. Purchases and sales of crude oil and NGLs and natural gas with
the same counterparty, made to facilitate sales to customers or potential customers, that are entered into in contemplation of
one another, are combined and recorded as non-monetary exchanges and measured at the net settlement amount.
Revenue in the consolidated statement of earnings represents the Company’s share of product sales net of royalty payments
to governments and other mineral interest owners. The Company discloses the disaggregation of revenues from sales of
crude oil and NGLs and natural gas in the segmented information in note 22. 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.
65
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. The Company continues to report revenue for the years ended December 31, 2017 and 2016 in accordance with the Company's
previous accounting policy for revenue and cost of goods sold as follows:
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.
(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.
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.
66
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 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 solely
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, on a forward looking basis, the Company assesses the expected credit losses associated with its
financial assets carried at amortized cost. Expected credit losses are measured as the difference between the cash flows that
are due to the Company and the cash flows that the Company expects to receive, discounted at the effective interest rate
determined at initial recognition. For trade accounts receivable, the Company applies the simplified approach permitted by
IFRS 9, which requires expected lifetime credit losses to be recognized from initial recognition of the receivables. To measure
expected credit losses, accounts receivable are grouped based on the number of days the receivables have been outstanding
and internal credit assessments of the customers. Credit risk for longer-term receivables is assessed based on an external
credit rating of the counterparty. For longer-term receivables with credit risk that has not increased significantly since the date
of recognition, the Company measures the expected credit loss as the 12-month expected credit loss.
Changes in the provision for expected credit loss are recognized in net earnings.
The Company continues to report impairment of financial assets for the years ended December 31, 2017 and 2016 in
accordance with the Company's previous accounting policy for impairment of financial assets as follows:
At each reporting date, the Company assesses whether there is objective evidence that a financial asset is impaired. If
such evidence exists, an impairment loss is recognized. Impairment losses on financial assets carried at amortized cost are
calculated as the difference between the amortized cost of the financial asset and the present value of the estimated future
cash flows, discounted using the instrument’s original effective interest rate. Impairment losses on financial assets carried
at amortized cost are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related
objectively to an event occurring after the impairment was recognized.
(R) RISK MANAGEMENT ACTIVITIES
The Company periodically uses derivative financial instruments to manage its commodity price, foreign currency and interest
rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative
purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value.
The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions,
the Company primarily relied on external, readily-observable market inputs including quoted commodity prices and volatility,
interest rate yield curves, and foreign exchange rates. The carrying amount of a risk management liability is adjusted for the
Company’s own credit risk.
The Company documents all derivative financial instruments that are formally designated as hedging transactions at the
inception of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the
hedging relationship is evaluated, both at inception of the hedge and on an ongoing basis.
The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil
and natural gas in order to protect its cash flow for its capital expenditure programs. The effective portion of changes in the
fair value of derivative commodity price contracts formally designated as cash flow hedges is initially recognized in other
comprehensive income and is reclassified to risk management activities in net earnings in the same period or periods in
which the commodity is sold or purchased. The ineffective portion of changes in the fair value of these designated contracts is
recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural
gas commodity price contracts are recognized in risk management activities in net earnings.
67
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 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.
(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.
68
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 2. Changes in Accounting Policies
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.
The Company adopted IFRS 15 on January 1, 2018 using the retrospective with cumulative effect method. There were no
changes to reported net earnings or retained earnings as a result of adopting IFRS 15. Under the standard, the Company is
required to provide additional disclosure of disaggregated revenue by major product type. In connection with adoption of the
standard, the Company has reclassified certain comparative amounts in a manner consistent with the presentation adopted
for the year ended December 31, 2018 (see note 22).
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. Applying this expedient had no impact to the revenue recognized under the
previous revenue accounting standard as all performance obligations had been met and the consideration had been determined.
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 Company retrospectively adopted the amendments to IFRS 9 on January 1, 2018 and elected to apply the limited
exemption in IFRS 9 relating to transition for impairment. Accordingly, provisions for impairment have not been restated in the
comparative periods. Adoption of the amendment did not have a significant impact on the Company’s previous accounting for
impairment of financial assets.
3. Accounting Standards Issued But Not Yet Applied
In October 2018, the IASB issued amendments to IFRS 3 "Definition of a Business" that narrowed and clarified the definition
of a business. The amendments also permit a simplified assessment of whether an acquired set of activities and assets is
a group of assets rather than a business. The amendments are effective January 1, 2020 with earlier adoption permitted.
The amendments apply to business combinations after the date of adoption. The Company is assessing the impact of these
amendments on its consolidated financial statements.
In October 2018, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" and IAS 8 "Accounting Policies,
Changes in Accounting Estimates and Errors". The amendments make minor changes to the definition of the term "material"
and align the definition across all IFRS Standards. Materiality is used in making judgments related to the preparation of financial
statements. The amendments are effective January 1, 2020 with earlier adoption permitted. The Company is assessing the
impact of these amendments on its consolidated financial statements.
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 assets 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 has determined that these amendments have no significant impact 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 has determined that this interpretation has no significant impact on its consolidated
financial statements.
IFRS 16 "LEASES"
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 and requires balance sheet recognition for all leases. Certain short-term (less than 12 months)
and low-value leases (as defined in the standard) are exempt from the requirements, and may continue to be treated as an
expense. Leases to explore for or use crude oil, natural gas, minerals and similar non-regenerative resources are exempt from
the standard.
69
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. The Company will adopt IFRS 16 on January 1, 2019 using the retrospective with cumulative effect method with no impact
to opening retained earnings at the date of adoption. In accordance with the transitional provisions in the standard, balances
reported in the comparative periods will not be restated.
On initial adoption, the Company intends to use the following practical expedients under the standard. Certain expedients are
on a lease-by-lease basis and others are applicable by class of underlying assets:
■■
■■
the use of a single discount rate to a portfolio of leases with reasonably similar characteristics;
leases with a remaining lease term of less than twelve months as at January 1, 2019 will be treated as short-term leases;
and
■■ exclusion of indirect costs for the measurement of lease assets at the date of initial application.
The Company does not intend to apply any practical expedients pertaining to grandfathering of leases assessed under the
previous standard.
On adoption of IFRS 16, the Company will recognize lease assets and liabilities at the present value of the remaining lease
payments, discounted using the Company’s applicable borrowing rate on January 1, 2019. The Company expects to report
additional lease assets and corresponding liabilities of between $1.5 billion and $1.6 billion. The Company continues to finalize
its accounting for leases in accordance with IFRS 16, and the above estimates are subject to change based on finalization of
the Company's review of its lease arrangements.
In the statement of earnings, depletion, depreciation and amortization expense and interest expense will increase, with
corresponding decreases in production, transportation and administration expenses. The Company does not expect to report
a material impact on net earnings. Under the new standard, the Company will report cash outflows for repayment of the
principal portion of the lease liability as cash flows from financing activities. The interest portion of the lease payments will
continue to be classified as cash flows from operating activities.
Where the Company, acting as the operator, signs a lease on behalf of a joint operation and assumes the legal liability for
that lease, the Company will recognize 100% of the related lease asset and lease liability. As the Company recovers its
joint operation partners' share of the costs of the lease contract, these recoveries will be recognized in the consolidated
statements of earnings.
4. Critical Accounting Estimates and Judgements
The Company has made estimates, assumptions and judgements regarding certain assets, liabilities, revenues and expenses
in the preparation of the consolidated financial statements, primarily related to unsettled transactions and events as of the
date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts. The estimates,
assumptions and judgements that have a significant risk of causing a material adjustment to the carrying amounts of assets
and liabilities within the next financial year are addressed below.
(A) CRUDE OIL AND NATURAL GAS RESERVES
Purchase price allocations, depletion, depreciation and amortization, 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.
70
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. INCOME TAXES
(C)
The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the Company
to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements
with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the
realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain.
The Company recognizes 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 estimated 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.
IMPAIRMENT OF ASSETS
(H)
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.
5. Inventory
Product inventory
Materials and supplies
$
$
2018
297 $
658
955 $
2017
285
609
894
The Company recorded a write-down of its product inventory of $13 million from cost to net realizable value as at
December 31, 2018 (2017 – $33 million).
71
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 6. Exploration and Evaluation Assets
Cost
At December 31, 2016
Additions
Acquisition of AOSP and other assets (note 8)
Transfers to property, plant and equipment
Disposals/derecognitions
At December 31, 2017
Additions
Transfers to property, plant and equipment
Disposals/derecognitions and other
Exploration and Production
North
America
North
Sea
Offshore
Africa
Oil Sands
Mining and
Upgrading
Total
$
2,306 $
– $
76 $
– $
2,382
144
31
(198)
(1)
2,282
245
(175)
(4)
–
–
–
–
–
–
–
–
15
–
–
–
91
35
–
(89)
–
259
–
–
259
222
(222)
(7)
159
290
(198)
(1)
2,632
502
(397)
(100)
At December 31, 2018
$
2,348 $
– $
37 $
252 $
2,637
During the year ended December 31, 2018, the Company acquired a number of exploration and evaluation properties in the
Oil Sands Mining and Upgrading and North America Exploration and Production segments.
In the Oil Sands Mining and Upgrading segment, the Company acquired the Joslyn oil sands project including exploration
and evaluation assets of $222 million and associated asset retirement obligations of $4 million. Total consideration of
$218 million was comprised of $100 million cash on closing with the remaining balance paid equally over each of the next five
years. In the fourth quarter of 2018, following integration of the acquired assets into the Horizon mine plan and determination
of proved crude oil reserves, the exploration and evaluation assets were transferred to property, plant and equipment.
The above amounts are estimates, and may be subject to change based on the receipt of new information.
In the North America Exploration and Production segment, the Company acquired Laricina Energy Ltd., including exploration
and evaluation assets of $118 million and property, plant and equipment of $44 million. In addition, the Company also acquired
cash of $24 million and deferred income tax assets of $168 million and assumed net working capital liabilities of $18 million,
asset retirement obligations of $17 million and notes payable of $48 million. Total purchase consideration was $46 million,
resulting in a pre-tax gain of $225 million on the acquisition, representing the excess of the fair value of the net assets acquired
compared to total purchase consideration. The Company settled the notes payable immediately following the completion
of the acquisition. The transaction was accounted for using the acquisition method of accounting. The above amounts are
estimates, and may be subject to change based on the receipt of new information.
The Company also completed two additional farm-out agreements in the Offshore Africa segment to dispose of a combined
30% interest in its exploration right in South Africa, comprised of exploration and evaluation assets of $89 million, including
a recovery of $14 million of past incurred costs, for net proceeds of $105 million (US$79 million), resulting in a pre-tax gain
of $16 million ($12 million after-tax). The Company retains a 20% working interest in the exploration right following the
completion of these farm-out agreements.
Under the terms of the various agreements, in the event of a commercial crude oil discovery on the exploration right and
conversion to a production right, additional cash payments of between US$623 million and US$645 million will be made to
the Company. In the event of a commercial natural gas discovery on the exploration right and conversion to a production right,
additional cash payments of between US$126 million and US$132 million will be made to the Company.
During 2017, the Company also disposed of a number of North America exploration and evaluation assets with a net book
value of $1 million for consideration of $36 million, resulting in a pre-tax gain on sale of properties of $35 million.
72
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
7. Property, Plant and Equipment
Oil Sands
Mining and
Upgrading Midstream
Head
Office
Total
Exploration and Production
North
America
North
Sea
Offshore
Africa
Cost
At December 31, 2016
$ 61,647 $ 7,380 $ 5,132 $
27,038 $
234 $
395 $ 101,826
Additions (1)
3,003
255
101
1,660
194
19
5,232
Acquisition of AOSP and other assets
(note 8)
Transfers from E&E assets
Disposals/derecognitions
Foreign exchange adjustments and other
At December 31, 2017
Additions (2)
Transfers from E&E assets
Disposals/derecognitions
Foreign exchange adjustments and other
349
198
(381)
–
64,816
2,428
175
(412)
–
–
–
–
(509)
7,126
237
–
(703)
661
–
–
–
(352)
4,881
212
–
(70)
448
13,832
–
(446)
–
42,084
1,050
222
(209)
–
–
–
–
–
428
13
–
–
–
–
–
–
–
414
21
–
–
–
14,181
198
(827)
(861)
119,749
3,961
397
(1,394)
1,109
At December 31, 2018
$ 67,007 $ 7,321 $ 5,471 $
43,147 $
441 $
435 $ 123,822
Accumulated depletion
and depreciation
At December 31, 2016
Expense
Disposals/derecognitions
Foreign exchange adjustments and other
At December 31, 2017
Expense
Disposals/derecognitions
Foreign exchange adjustments and other
$ 38,311 $ 5,584 $ 3,797 $
2,828 $
115 $
281 $ 50,916
3,220
(381)
1
41,151
3,111
(393)
12
509
–
(440)
5,653
257
(703)
528
205
–
(283)
3,719
201
(70)
353
1,220
(446)
26
3,628
1,557
(209)
5
9
–
–
124
14
–
–
23
–
–
304
21
–
–
5,186
(827)
(696)
54,579
5,161
(1,375)
898
At December 31, 2018
$ 43,881 $ 5,735 $ 4,203 $
4,981 $
138 $
325 $ 59,263
Net book value
– at December 31, 2018
– at December 31, 2017
$ 23,126 $ 1,586 $ 1,268 $
38,166 $
$ 23,665 $ 1,473 $ 1,162 $
38,456 $
303 $
304 $
110 $ 64,559
110 $ 65,170
(1) Additions in Midstream include a pre-tax revaluation gain of $114 million of a previously held joint interest in certain pipeline system assets.
(2) Additions in North Sea include a pre-tax revaluation gain of $19 million relating to acquisitions of its previously held interest.
Project costs not subject to depletion and depreciation
Kirby Thermal Oil Sands – North
2018
$
1,424 $
2017
944
During the year ended December 31, 2018, the Company acquired a number of producing crude oil and natural gas properties
in the North America and North Sea Exploration and Production segments. These transactions were accounted for using the
acquisition method of accounting. Gains reported on the acquisitions represent the excess of the fair value of the net assets
acquired compared to total purchase consideration.
In North America Exploration and Production, excluding the impact of acquisitions disclosed in note 6, the Company acquired
property, plant and equipment for net cash consideration paid of $170 million and assumed associated asset retirement
obligations of $13 million. No net deferred income tax liabilities were recognized. The Company recognized a pre-tax gain of
$47 million on the transactions.
In connection with the acquisition of the remaining interest in certain operations in the North Sea Exploration and Production
segment, the Company acquired $108 million of property, plant and equipment, for net proceeds received of $73 million. The
Company also acquired net working capital of $7 million, assumed associated asset retirement obligations of $41 million and
recognized net deferred income tax liabilities of $27 million. The Company recognized a pre-tax gain of $120 million on the
acquisition and a pre-tax revaluation gain of $19 million relating to its previously held interest.
73
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
During the fourth quarter of 2018, the Gabonese Republic agreed to cessation of production from the Company’s Olowi field,
as well as the terms of termination of the Olowi Production Sharing Contract and the return of the permit area back to the
Gabonese Republic, including the associated asset retirement obligations of $69 million. The transaction resulted in a pre-tax
gain on disposition of property of $20 million ($14 million after-tax).
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), for net cash
consideration of $1,013 million ( 2016 – $159 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). No net deferred income tax liabilities were recognized on these acquisitions (2016 – $nil).
In connection with the acquisition of pipeline system assets in the Midstream segment in 2017, 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.
As at December 31, 2018, 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 2018, pre-tax interest of $69 million (2017 – $82 million; 2016 – $233 million) was capitalized to property, plant and
equipment using a weighted average capitalization rate of 3.9% (2017 – 3.8%; 2016 – 3.9%).
8. 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 20). 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 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) paid 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 11).
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.
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
For the year ended December 31, 2017, 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.
74
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 9. Investments
As at December 31, 2018 and 2017, the Company had the following investments:
Investment in PrairieSky Royalty Ltd.
Investment in Inter Pipeline Ltd.
$
$
2018
400 $
124
524 $
2017
726
167
893
INVESTMENT IN PRAIRIESKY ROYALTY LTD.
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, 2018, the Company’s investment in
PrairieSky Ltd. ("PrairieSky") was classified as a current asset. PrairieSky is in the business of acquiring and managing oil and
gas royalty income assets through indirect third-party oil and gas development.
The loss (gain) from the investment in PrairieSky was comprised as follows:
Fair value loss (gain) from PrairieSky
Dividend income from PrairieSky
$
$
2018
326 $
(17)
309 $
2017
(3) $
(17)
(20) $
2016
(292)
(27)
(319)
INVESTMENT IN INTER PIPELINE LTD.
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
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, 2018, 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
2018
2017
2016
$
$
43 $
(11)
32 $
23 $
(10)
13 $
–
(1)
(1)
75
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 10. Other Long-Term Assets
Investment in North West Redwater Partnership
North West Redwater Partnership subordinated debt (1)
Risk management (note 19)
Other
Less: current portion
(1) Includes accrued interest.
$
2018
287 $
591
373
208
1,459
116
$
1,343 $
2017
292
510
204
241
1,247
79
1,168
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 $9,700 million. The Project is currently in
the commissioning phase. 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, 2018, each party has provided $439 million of subordinated debt, together with accrued interest thereon of
$152 million, for a Company total of $591 million. Any additional subordinated debt financing is not expected to be significant.
Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt
portion of the monthly cost of service toll, currently consisting of interest and fees, with principal repayments beginning in
2020 (see note 20). The Company is unconditionally obligated to pay this portion of the cost of service toll over the 30-year
tolling period. As at December 31, 2018, the Company had recognized $62 million in prepaid service tolls.
As at December 31, 2018, Redwater Partnership had borrowings of $2,333 million under its secured $3,500 million syndicated
credit facility, maturing June 2018. During the first quarter of 2018, 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.
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.
The assets, liabilities, partners’ equity and equity loss (income) related to Redwater Partnership and the Company’s
50% interest at December 31, 2018 and 2017 were comprised as follows:
2018
2017
Redwater
Partnership
Company
Redwater
Partnership
Company
50% interest
100% interest
50% interest
100% interest
$
210 $
$
$
$
$
$
11,250 $
352 $
10,534 $
574 $
10 $
105 $
5,625 $
176 $
5,267 $
287 $
5 $
330 $
10,540 $
2,476 $
7,810 $
584 $
(62) $
165
5,270
1,238
3,905
292
(31)
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Partners’ equity
Equity loss (income)
76
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
11. 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, 2018 – US$2,954 million;
December 31, 2017 – US$1,839 million)
Commercial paper (December 31, 2018 – US$104 million;
December 31, 2017 – US$500 million)
US dollar debt securities
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 long-term debt (1) (2)
2018
2017
$
831 $
3,544
500
500
900
1,000
1,000
500
600
300
6,131
4,031
141
–
–
682
1,364
682
819
1,706
546
478
478
614
1,501
546
1,023
14,611
20,742
17
102
20,623
141
1,000
$
19,482 $
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
(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.
77
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
BANK CREDIT FACILITIES AND COMMERCIAL PAPER
As at December 31, 2018, the Company had in place revolving bank credit facilities of $4,976 million of which $4,723 million
was available for use. Additionally, the Company had in place fully drawn term credit facilities of $4,750 million. Details of
these facilities are described below. This excludes certain other dedicated credit facilities supporting letters of credit.
■■
■■
■■
■■
■■
■■
■■
a $100 million demand credit facility;
a $1,800 million non-revolving term credit facility maturing May 2020;
a $2,200 million non-revolving term credit facility maturing October 2020;
a $750 million non-revolving term credit facility maturing February 2021;
a $2,425 million revolving syndicated credit facility with $330 million maturing in June 2019 and $2,095 million maturing
June 2021;
a $2,425 million revolving syndicated credit facility maturing June 2022; and
a £15 million demand credit facility related to the Company’s North Sea operations.
During 2018, the Company extended the $2,425 million revolving syndicated credit facility originally due June 2020 to
June 2022. Each of the $2,425 million revolving facilities is extendible annually at the mutual agreement of the Company
and the lenders. If the facilities are not extended, the full amount of the outstanding principal is repayable on the maturity
date. Borrowings under these facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances,
US dollar bankers’ acceptances, LIBOR, US base rate or Canadian prime rate.
During 2018, the Company repaid and cancelled $1,200 million of the $3,000 million non-revolving term credit facility (third
quarter of 2018 – $1,050 million; first quarter of 2018 – $150 million) scheduled to mature in May 2020. The required annual
amortization of 5% of the original balance is now satisfied. Borrowings under the term loan facility may be made by way of
pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian
prime rate. As at December 31, 2018, the $1,800 million facility was fully drawn.
During 2018, the Company extended the $2,200 million non-revolving credit facility originally due October 2019 to October
2020. Borrowings under the $2,200 million non-revolving credit facility may be made by way of pricing referenced
to Canadian dollar bankers' acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian prime rate.
As at December 31, 2018, the $2,200 million facility was fully drawn.
During 2018, the Company repaid and cancelled the $125 million non-revolving term credit facility scheduled to mature in
February 2019. The Company also extended the $750 million non-revolving term credit facility originally due February 2019 to
February 2021. Borrowings under the $750 million non-revolving credit facility may be made by way of pricing referenced to
Canadian dollar bankers’ acceptances, US dollar bankers' acceptances, LIBOR, US base rate or Canadian prime rate. As at
December 31, 2018, the $750 million facility was fully drawn.
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,
2018 was 2.6% (December 31, 2017 – 2.2%), and on total long-term debt outstanding for the year ended December 31, 2018
was 3.9% (December 31, 2017 – 3.8%).
As at December 31, 2018, letters of credit and guarantees aggregating to $450 million were outstanding.
78
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 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.
US DOLLAR DEBT SECURITIES
During 2018, the Company repaid US$600 million of 1.75% notes and US$400 million of 5.90% notes.
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.
SCHEDULED DEBT REPAYMENTS
Scheduled debt repayments are as follows:
Year
2019
2020
2021
2022
2023
Thereafter
Repayment
1,141
5,996
1,444
1,003
1,365
9,793
$
$
$
$
$
$
79
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 12. Other Long-Term Liabilities
Asset retirement obligations
Share-based compensation
Risk management (note 19)
Deferred purchase consideration (1) (2)
Other
Less: current portion
2018
$
3,886 $
124
17
118
80
4,225
335
$
3,890 $
2017
4,327
414
103
469
96
5,409
1,012
4,397
(1) Includes $118 million of deferred purchase consideration at December 31, 2018, payable in annual installments of $25 million over the next five years.
(2) Includes $469 million (US$375 million) of deferred purchase consideration at December 31, 2017, paid 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 5.0% (2017 – 4.7%; 2016 – 5.2%) and
inflation rates of up to 2% (December 31, 2017 – up to 2%). 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
2018
2017
$
4,327 $
3,243 $
19
6
(290)
186
(111)
(334)
83
3,886
186
12
784
(274)
164
(40)
509
(71)
4,327
92
$
3,700 $
4,235 $
2018
$
1,665 $
707
134
1,379
1
$
3,886 $
2016
2,950
3
30
(267)
142
(68)
493
(40)
3,243
95
3,148
2017
1,840
755
245
1,486
1
4,327
80
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. SHARE-BASED COMPENSATION
As the Company’s Option Plan provides current employees with the right to elect to receive common shares or a cash
payment in exchange for stock options surrendered, a liability for potential cash settlements is recognized. The current portion
represents the maximum amount of the liability payable within the next twelve month period if all vested stock options are
surrendered for cash settlement.
Balance – beginning of year
Share-based compensation (recovery) expense
Cash payment for stock options surrendered
Transferred to common shares
(Recovered from) charged to Oil Sands Mining and Upgrading, net
Balance – end of year
Less: current portion
$
2018
414 $
2017
426 $
(146)
(5)
(120)
(19)
124
92
134
(6)
(154)
14
414
348
$
32 $
66 $
2016
128
355
(7)
(117)
67
426
368
58
Included within share-based compensation liability as at December 31, 2018 was $13 million (2017 – $5 million; 2016 – $nil)
related to performance share units 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.
$
$
2018
3.33 $
32.94 $
27.4%
4.1%
1.9%
4.2%
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%
4.4 years
4.5 years
4.6 years
The intrinsic value of vested stock options at December 31, 2018 was $27 million (2017 – $195 million; 2016 – $191 million).
13. 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.
2018
312 $
2017
(145) $
28
54
(29)
9
374
540
17
557
57
45
(132)
11
(164)
586
54
640
$
931 $
476 $
2016
(377)
(74)
22
(198)
9
(618)
(106)
(135)
(241)
(859)
81
Canadian Natural 2018 Annual Report Premium 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)
2018
27.0%
2017
27.0%
$
951 $
776 $
(3)
3
6
142
(41)
–
(119)
(136)
142
(14)
(67)
28
(43)
(86)
33
10
(63)
(3)
(86)
(23)
$
931 $
476 $
2016
27.0%
(287)
(324)
131
(54)
(80)
94
(107)
–
(120)
(80)
(32)
(859)
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
$
12,885 $
12,484
2018
2017
Unrealized risk management activities
PRT deduction for corporate income tax
Investments
Investment in North West Redwater Partnership
Other
Deferred income tax assets
Asset retirement obligations
Loss carryforwards
Unrealized foreign exchange loss on long-term debt
Deferred PRT
Other
Net deferred income tax liability
$
11,451 $
Movements in deferred tax assets and liabilities recognized in net earnings (loss) during the year were as follows:
Property, plant and equipment and exploration and evaluation assets
$
Timing of partnership items
Unrealized foreign exchange (gain) loss on long-term debt
Unrealized risk management activities
Asset retirement obligations
Loss carryforwards
Investments
Investment in North West Redwater Partnership
Deferred PRT
PRT deduction for corporate income tax
2018
281 $
2017
541 $
–
(75)
18
175
(61)
(50)
162
17
(7)
97
–
120
(46)
(88)
48
(2)
30
54
(21)
4
$
557 $
640 $
Other
82
33
1
46
414
174
20
7
96
252
–
13,553
12,859
(1,142)
(855)
(104)
(1)
–
(2,102)
(1,264)
(523)
(29)
(18)
(50)
(1,884)
10,975
2016
37
(261)
63
(44)
(20)
(221)
38
81
(135)
61
160
(241)
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
The following table summarizes the movements of the net deferred income tax liability during the year:
Balance – beginning of year
Deferred income tax expense (recovery)
Deferred income tax (recovery) expense included in other
comprehensive income
Foreign exchange adjustments
Business combinations (note 6, 7, 8)
Balance – end of year
2018
2017
$
10,975 $
9,073 $
557
(6)
41
(116)
640
4
(29)
1,287
2016
9,344
(241)
(5)
(25)
–
$
11,451 $
10,975 $
9,073
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.
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 $750 million, which can only be claimed against income from certain oil
and gas properties.
Deferred income tax liabilities have not been recognized on the unremitted net earnings of wholly controlled subsidiaries.
The Company is able to control the timing and amount of distributions and no taxes are payable on distributions from these
subsidiaries provided that the distributions remain within certain limits.
83
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
14. 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 8)
Issued upon exercise of stock options
Previously recognized liability on stock options exercised
for common shares
Purchase of common shares under Normal Course Issuer Bid
2018
2017
Number
of shares
Number
of shares
(thousands)
Amount
(thousands)
Amount
1,222,769 $
9,109
1,110,952 $
–
9,975
–
(30,858)
–
332
120
(238)
97,561
14,256
–
–
4,671
3,818
466
154
–
Balance – end of year
1,201,886 $
9,323
1,222,769 $
9,109
PREFERRED SHARES
Preferred shares are issuable in a series. If issued, the number of shares in each series, and the designation, rights, privileges,
restrictions and conditions attached to the shares will be determined by the Board of Directors of the Company.
DIVIDEND POLICY
The Company has paid regular quarterly dividends in each year since 2001. The dividend policy undergoes periodic review by
the Board of Directors and is subject to change.
On March 6, 2019, the Board of Directors declared a quarterly dividend of $0.375 per common share, an increase from the
previous quarterly dividend of $0.335 per common share. The dividend is payable on April 1, 2019. 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.
NORMAL COURSE ISSUER BID
On May 16, 2018, 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 61,454,856
common shares, over a 12-month period commencing May 23, 2018 and ending May 22, 2019. The Company's Normal
Course Issuer Bid announced in March 2017 expired on May 22, 2018.
For the year ended December 31, 2018, the Company purchased 30,857,727 common shares at a weighted average
price of $41.56 per common share for a total cost of $1,282 million. Retained earnings were reduced by $1,044 million,
representing the excess of the purchase price of common shares over their average carrying value. During 2017 and 2016,
the Company did not purchase any common shares for cancellation. Subsequent to December 31, 2018, the Company
purchased 4,340,000 common shares at a weighted average price of $35.86 per common share for a total cost of $156 million.
84
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
STOCK OPTIONS
The Company’s Option Plan provides for the granting of stock options to employees. Stock options granted under the Option
Plan have terms ranging from five to six years to expiry and vest over a five-year period. The exercise price of each stock option
granted is determined at the closing market price of the common shares on the Toronto Stock Exchange on the day prior to the
grant. Each stock option granted provides the holder the choice to purchase one common share of the Company at the stated
exercise price or receive a cash payment equal to the difference between the stated exercise price and the market price of
the Company’s common shares on the date of surrender of the stock option.
The Option Plan is a "rolling 9%" plan, whereby the aggregate number of common shares that may be reserved for issuance
under the plan shall not exceed 9% of the common shares outstanding from time to time.
The following table summarizes information relating to stock options outstanding at December 31, 2018 and 2017:
Outstanding – beginning of year
Granted
Surrendered for cash settlement
Exercised for common shares
Forfeited
Outstanding – end of year
Exercisable – end of year
2018
2017
Stock options
(thousands)
Weighted
average
exercise price
Stock options
(thousands)
Weighted
average
exercise price
56,036 $
4,256 $
(392) $
(9,975) $
(3,240) $
46,685 $
19,436 $
36.67
43.75
33.46
33.28
38.76
37.92
36.03
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
The range of exercise prices of stock options outstanding and exercisable at December 31, 2018 was as follows:
Stock options outstanding
Stock options exercisable
Range of exercise prices
$22.90 – $24.99
$25.00 – $29.99
$30.00 – $34.99
$35.00 – $39.99
$40.00 – $44.99
$45.00 – $46.74
Stock options
outstanding
(thousands)
Weighted
average
remaining
term (years)
Weighted
average
Stock options
exercisable
(thousands)
Weighted
average
exercise price
3,120
5,112
6,013
11,304
17,107
4,029
46,685
exercise price
22.90
2.04 $
2.02 $
0.83 $
2.72 $
3.23 $
4.06 $
2.66 $
28.86
33.27
37.46
43.59
45.20
37.92
1,515 $
2,453 $
4,831 $
4,131 $
5,664 $
842 $
19,436 $
15. 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
$
$
2018
13 $
109
122 $
22.90
28.87
33.43
35.91
43.60
45.08
36.03
2017
47
(115)
(68)
85
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
16. Capital Disclosures
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, 2018, the ratio was within the target range at 39%.
Readers are cautioned that the debt to book capitalization ratio is not defined by IFRS and this financial measure may not
be comparable to similar measures presented by other companies. Further, there are no assurances that the Company will
continue to use this measure to monitor capital or will not alter the method of calculation of this measure in the future.
Long-term debt, net (1)
Total shareholders’ equity
Debt to book capitalization
$
$
2018
20,522 $
31,974 $
39%
2017
22,321
31,653
41%
(1) Includes the current portion of long-term debt, net of cash and cash equivalents.
The Company is subject to a financial covenant that requires debt to book capitalization as defined in its credit facility
agreements to not exceed 65%. At December 31, 2018, the Company was in compliance with this covenant.
17. 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
2018
2017
2016
1,218,798
1,175,094
1,100,471
4,960
7,729
–
1,223,758
1,182,823
1,100,471
$
$
$
2,591 $
2.13 $
2.12 $
2,397 $
2.04 $
2.03 $
(204)
(0.19)
(0.19)
In 2018, the Company excluded 23,458,000 potentially anti-dilutive stock options from the calculation of diluted earnings per
common share (year ended December 31, 2017 – 17,547,000).
86
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
18. Interest and Other Financing Expense
Interest and other financing expense:
Long-term debt
Less: amounts capitalized on qualifying assets
Total interest and other financing expense
Total interest income
Net interest and other financing expense
2018
2017
2016
$
$
867 $
810 $
69
798
(59)
82
728
(97)
739 $
631 $
664
233
431
(48)
383
19. Financial Instruments
The carrying amounts of the Company’s financial instruments by category were as follows:
Asset (liability)
amortized cost
or loss
Financial
assets at
Fair value
through profit
2018
Derivatives
used for
hedging
Financial
liabilities at
amortized cost
Accounts receivable
$
1,148 $
– $
– $
– $
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
Long-term debt (2)
–
591
–
–
–
–
524
12
–
–
(17)
–
–
361
–
–
–
–
–
–
(779)
(2,356)
(118)
(20,623)
$
1,739 $
519 $
361 $
(23,876) $
Asset (liability)
amortized cost
or loss
Financial
assets at
Fair value
through profit
Accounts receivable
$
2,397 $
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Other long-term liabilities (3)
Long-term debt (2)
–
510
–
–
–
–
– $
893
–
–
–
(38)
–
2017
Derivatives
used for
hedging
Financial
liabilities at
amortized cost
– $
– $
–
204
–
–
(65)
–
–
–
(775)
(2,597)
(469)
(22,458)
$
2,907 $
855 $
139 $
(26,299) $
(1) Includes $118 million of deferred purchase consideration payable over the next five years.
(2) Includes the current portion of long-term debt.
(3) Includes $469 million (US$375 million) of deferred purchase consideration which was paid to Marathon in March 2018.
Total
1,148
524
964
(779)
(2,356)
(135)
(20,623)
(21,257)
Total
2,397
893
714
(775)
(2,597)
(572)
(22,458)
(22,398)
87
Canadian Natural 2018 Annual Report Premium 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
Other long-term liabilities
Fixed rate long-term debt (6) (7)
Asset (liability) (1) (2)
Investments (3)
Other long-term assets
Other long-term liabilities
Fixed rate long-term debt (6) (7)
Carrying
amount
2018
Fair value
Level 1
Level 2
Level 3 (4) (5)
524 $
964 $
(135) $
524 $
– $
– $
(15,620) $
(15,952) $
– $
373 $
(17) $
– $
–
591
(118)
–
Carrying
amount
893 $
714 $
(103) $
(15,989) $
2017
Fair value
Level 1
Level 2
Level 3 (5)
893 $
– $
– $
(17,259) $
– $
204 $
(103) $
– $
–
510
–
–
$
$
$
$
$
$
$
$
(1) Excludes financial assets and liabilities where the carrying amount approximates fair value due to the short-term nature of the asset or liability (cash and cash
equivalents, accounts receivable, accounts payable and accrued liabilities, and purchase consideration paid to Marathon in March 2018).
(2) There were no transfers between Level 1, 2 and 3 financial instruments.
(3) The fair values of the investments are based on quoted market prices.
(4) The fair value of the deferred purchase consideration is based on the present value of future cash payments.
(5) The fair value of Redwater Partnership subordinated debt is based on the present value of future cash receipts.
(6) The fair value of fixed rate long-term debt has been determined based on quoted market prices.
(7) Includes the current portion of fixed rate long-term debt.
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 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
Crude oil WCS (1) differential swaps
Natural gas AECO basis swaps
Natural gas AECO fixed price swaps
Cash flow hedges
Foreign currency forward contracts
Cross currency swaps
Included within:
Current portion of other long-term assets
Current portion of other long-term liabilities
Other long-term assets
(1) Western Canadian Select.
88
2018
2017
$
8 $
(38)
(17)
1
3
70
291
356 $
92 $
(17)
281
356 $
–
–
–
(71)
210
101
–
(103)
204
101
$
$
$
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
During 2018, the Company recognized a gain of $2 million (2017 – gain of $5 million, 2016 – gain of $7 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.
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 (loss) income
Balance – end of year
Less: current portion
$
2018
101 $
35
260
(40)
356
75
$
281 $
Net (gain) loss from risk management activities for the years ended December 31 were as follows:
Net realized risk management (gain) loss
Net unrealized risk management (gain) loss
$
$
2018
(99) $
(35)
(134) $
2017
(2) $
37
35 $
2017
489
(37)
(375)
24
101
(103)
204
2016
8
25
33
FINANCIAL RISK FACTORS
a) Market risk
Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in
market prices. The Company’s market risk is comprised of commodity price risk, interest rate risk, and foreign currency
exchange risk.
COMMODITY PRICE RISK MANAGEMENT
The Company periodically uses commodity derivative financial instruments to manage its exposure to commodity price risk
associated with the sale of its future crude oil and natural gas production and with natural gas purchases.
At December 31, 2018, the Company had the following derivative financial instruments outstanding to manage its commodity
price risk:
Crude Oil
WCS differential swaps
WCS differential swaps
Natural Gas
Remaining term
Volume
Weighted Average Price
Index
Jan 2019 – Mar 2019
Jan 2019 – Sep 2019
28,000 bbl/d
8,000 bbl/d
US$17.65
US$23.57
WCS
WCS
AECO basis swaps
Jan 2019 – Mar 2019
10,000 MMbtu/d
AECO fixed price swaps
Jan 2019 – Mar 2019
AECO fixed price swaps (1)
Apr 2019 – Oct 2019
30,000 GJ/d
10,000 GJ/d
US$1.39
$2.30
$1.30
AECO
AECO
AECO
(1) As at March 6, 2019, the Company has hedged an additional 105,000 GJ/d of currently forecasted natural gas volumes using AECO fixed price swaps, at a
weighted average price of $1.32/GJ, for April to October 2019.
89
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. The Company's outstanding commodity derivative financial instruments are expected to be settled monthly based on the
applicable index pricing for the respective contract month.
INTEREST RATE RISK MANAGEMENT
The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company periodically enters into interest rate swap contracts to manage its fixed to floating
interest rate mix on long-term debt. Interest rate swap contracts require the periodic exchange of payments without the
exchange of the notional principal amounts on which the payments are based. At December 31, 2018, the Company had no
interest rate swap contracts outstanding.
FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long-
term debt and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted
in other currencies and in the carrying value of its foreign subsidiaries. The Company periodically enters into cross currency
swap contracts and foreign currency forward contracts to manage known currency exposure on US dollar denominated
long-term debt and working capital. The cross currency swap contracts require the periodic exchange of payments with the
exchange at maturity of notional principal amounts on which the payments are based.
At December 31, 2018 the Company had the following cross currency swap contracts outstanding:
Cross currency
Swaps
Remaining term
Amount
Exchange
rate (US$/C$)
Interest
rate (US$)
Interest
rate (C$)
Jan 2019 – Nov 2021
Jan 2019 – 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, 2018 and were classified
as cash flow hedges.
In addition to the cross currency swap contracts noted above, at December 31, 2018 the Company had US$3,506 million of
foreign currency forward contracts outstanding, with terms of up to 90 days, including US$3,058 million designated as cash
flow hedges.
FINANCIAL INSTRUMENT SENSITIVITIES
The following table summarizes the annualized sensitivities of the Company’s 2018 net earnings and other comprehensive
income (loss) to changes in the fair value of financial instruments outstanding as at December 31, 2018, 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.
90
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
2018
2017
Increase
(decrease)
to other
(Increase)
decrease
to other
Increase
(decrease)
comprehensive
comprehensive
Increase
(decrease)
Commodity price risk (1)
Increase WCS differential US$1.00/bbl
Decrease WCS differential US$1.00/bbl
Increase AECO $0.10/Mcf (2)
Decrease AECO $0.10/Mcf (2)
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
to net earnings
income
to net earnings
loss
$
$
$
$
$
$
$
$
(5) $
5 $
(1) $
1 $
(33) $
33 $
(114) $
113 $
– $
– $
– $
– $
(21) $
25 $
– $
– $
– $
– $
– $
– $
(42) $
42 $
(105) $
101 $
–
–
–
–
(16)
19
–
–
(1) Based on the Company's contracted AECO basis swap volumes at December 31, 2018, a movement of US$0.10/Mcf would not have a significant impact on
net earnings or other comprehensive income.
(2) Movements in AECO are based on the Company's contracted AECO fixed price swap volumes at December 31, 2018.
b) Credit risk
Credit risk is the risk that a party to a financial instrument will cause a financial loss to the Company by failing to discharge
an obligation.
COUNTERPARTY CREDIT RISK MANAGEMENT
The Company’s accounts receivable are mainly with customers in the crude oil and natural gas industry and are subject to
normal industry credit risks. The Company manages these risks by reviewing its exposure to individual companies on a regular
basis and where appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the
event of default. At December 31, 2018, substantially all of the Company’s accounts receivable were due within normal trade
terms and the average expected credit loss was approximately 1% of the Company's accounts receivable balance.
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, 2018, the Company had net risk management assets
of $361 million with specific counterparties related to derivative financial instruments (December 31, 2017 – $187 million).
The carrying amount of financial assets approximates the maximum credit exposure.
91
Canadian Natural 2018 Annual Report Premium 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 of the Company’s financial liabilities were as follows:
Accounts payable
Accrued liabilities
Other long-term liabilities
Long-term debt (1) (2)
Less than
1 to less than
2 to less than
1 year
2 years
5 years
Thereafter
$
$
$
$
779 $
2,356 $
42 $
1,141 $
– $
– $
24 $
– $
– $
69 $
–
–
–
5,996 $
3,812 $
9,793
(1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
(2) 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, $836 million; one to less than two years, $755 million; two to less than five years, $1,668 million; and thereafter, $5,327 million. Interest payments were
estimated based upon applicable interest and foreign exchange rates as at December 31, 2018.
20. Commitments and Contingencies
The Company has committed to certain payments as follows:
Product transportation and pipeline
North West Redwater Partnership
service toll (1)
Offshore equipment operating leases
Office leases
Other
$
$
$
$
$
2019
2020
2021
2022
2023
Thereafter
692 $
664 $
620 $
516 $
381 $
3,991
86 $
94 $
42 $
85 $
126 $
157 $
158 $
157 $
2,858
73 $
42 $
35 $
75 $
39 $
32 $
8 $
31 $
32 $
– $
32 $
31 $
–
89
424
(1) Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt portion of the monthly cost of service
toll, which currently consists of interest and fees, with principal repayments beginning in 2020. Included in the service toll is $1,301 million of interest payable
over the 30 year tolling period. See note 10.
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.
92
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
21. Supplemental Disclosure of Cash Flow Information
2018
2017
2016
Changes in non-cash working capital
Accounts receivable
Current income tax assets (liabilities)
Inventory
Prepaids and other
Accounts payable
Accrued liabilities
Other long-term liabilities (1) (2)
Net changes in non-cash working capital
Relating to:
Operating activities
Investing activities
Expenditures on exploration and evaluation assets
Net proceeds on sale of exploration and evaluation assets
Net expenditures (proceeds) on exploration and evaluation assets
Expenditures on property, plant and equipment
Net proceeds on sale of property, plant and equipment (3)
Net expenditures on property, plant and equipment
$
1,233 $
(977) $
471
(74)
(3)
(7)
(268)
(351)
527
81
(28)
175
365
469
1,001 $
612 $
1,346 $
(345)
1,001 $
2018
282 $
(16)
266 $
299 $
313
612 $
2017
159 $
(35)
124 $
4,175 $
4,574 $
–
–
4,175 $
4,574 $
$
$
$
$
$
$
$
(142)
(165)
(79)
14
31
(116)
–
(457)
(542)
85
(457)
2016
29
(35)
(6)
4,152
(349)
3,803
(1) Included in other long-term liabilities at December 31, 2018 is $118 million of deferred purchase consideration payable over the next five years.
(2) Included in other long-term liabilities at December 31, 2017 is $469 million (US$375 million) of deferred purchase consideration paid to Marathon.
(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 years' ended
December 31, 2018 and 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
Changes from financing cash flows:
Repayment of long-term debt, net (1)
Changes in foreign exchange and fair value (2)
At December 31, 2018
Long-term
debt
Cash flow
hedges on
US dollar debt
securities
$
16,805 $
(485) $
Liabilities
from financing
activities
16,320
6,622
–
(969)
–
124
222
22,458 $
(139) $
(2,831)
996
20,623 $
–
(222)
(361) $
6,622
124
(747)
22,319
(2,831)
774
20,262
$
$
(1) Includes original issue discounts and premiums, and directly attributable transaction costs.
(2) 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.
93
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
3,132
3,243
3,465
257
509
458
201
205
262
1,557
1,220
662
14
5,161
5,186
4,858
22. 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.
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.
(millions of Canadian dollars)
2018
2017
2016
2018
2017
2016
2018
2017
2016
2018
2017
2016
2018
2017
2016
2018
2017
2016
2018
2016
North America
North Sea
Offshore Africa
Oil Sands Mining
and Upgrading
Midstream
and other
Inter-segment elimination
Total
2017
Segmented product sales
Crude oil and NGLs
$ 7,254 $ 7,655 $ 5,933 $ 753 $ 666 $ 478 $ 628 $ 579 $ 532
$ 11,521 $ 7,072 $ 2,657 $ 102 $
102 $
114 $
410 $ 448 $ 682 $ 20,668 $ 16,522 $ 10,396
Natural gas
Total segmented product sales
Less: royalties
Segmented revenue
Segmented expenses
Production
Transportation, blending and
1,256
8,510
(723)
7,787
1,506
9,161
1,276
7,209
(809)
(524)
8,352
6,685
140
893
(2)
891
118
784
(1)
783
92
570
(1)
569
70
698
(51)
647
53
632
(41)
591
71
603
(26)
577
–
11,521
(479)
–
7,072
(167)
–
2,657
(24)
11,042
6,905
2,633
102
–
–
102
102
–
–
102
148
558
–
558
161
609
–
609
167
849
1,614
1,838
1,606
22,282
18,360
12,002
–
(1,255)
(1,018)
(575)
849
21,027
17,342
11,427
2,405
2,362
2,186
405
400
403
208
226
200
3,367
2,600
1,292
21
16
58
71
78
6,464
5,675
4,184
feedstock
2,587
2,291
1,941
22
31
48
2
1
2
1,087
679
80
491
527
751
4,189
3,529
2,822
87
80
(10)
(45)
66
6
29
–
(277)
(35)
(32)
(139)
27
35
–
–
–
–
–
–
967
944
9
–
(36)
–
384
9
–
–
–
12
–
–
–
441
476
6,072
4,317
2,063
549
598
829
15,543
14,099
11,755
Total segmented expenses
7,924
7,896
7,632
–
–
–
–
574
$
(137) $ 456 $
(947) $ 317 $
(184) $
(375) $ 263 $
150 $
101
$ 4,970 $ 2,588 $ 570 $
62 $ 222 $ 303 $
9 $
11 $
20 $ 5,484 $ 3,243 $
(328)
Segmented earnings (loss)
before the following
Non-segmented expenses
Administration
Share-based compensation
Interest and other financing
expense
Risk management activities
(other)
Foreign exchange loss (gain)
Loss (gain) from investments
Total non-segmented expenses
Earnings (loss) before taxes
Current income tax expense
(recovery)
Deferred income tax expense
(recovery)
Net earnings (loss)
94
114
–
–
114
25
–
11
–
–
–
9
–
–
–
–
–
–
5
40
(31)
(120)
(7)
(189)
61
48
29
–
–
–
(230)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
186
164
142
(10)
(45)
6
5
(31)
(7)
(114)
(218)
(452)
(379)
(250)
325
(146)
319
134
345
355
739
631
383
(124)
827
341
1,962
3,522
80
(787)
(7)
370
27
(55)
(320)
735
2,873
(1,063)
374
(164)
(618)
557
640
(241)
$ 2,591 $ 2,397 $
(204)
Depletion, depreciation and
amortization
Asset retirement obligation
accretion
Realized risk management
(commodity derivatives)
Gain on acquisition, disposition
and revaluation of properties
Equity loss (gain) from
investments
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
Inter-segment elimination and Other includes internal transportation and electricity charges. Production, processing and other
purchasing and selling activities that are not included in the above segments are also reported in the segmented information
as Inter-segment eliminations and Other. In connection with the adoption of IFRS 15 on January 1, 2018 (see note 2), the
Company has reclassified certain comparative figures for product sales, production expense and transportation, blending and
feedstock expense for the years ended December 31, 2017 and 2016 in a manner consistent with the presentation adopted
for the year ended December 31, 2018.
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)
2018
2017
2016
2018
2017
2016
2018
2017
2016
2018
2017
2016
2018
2017
2016
2018
2017
2016
2018
North America
North Sea
Offshore Africa
Oil Sands Mining
and Upgrading
Midstream
Inter-segment elimination
and other
Total
2017
2016
Crude oil and NGLs
$ 7,254 $ 7,655 $ 5,933 $ 753 $ 666 $ 478 $ 628 $ 579 $ 532
$ 11,521 $ 7,072 $ 2,657 $ 102 $
102 $
114 $
410 $ 448 $ 682 $ 20,668 $ 16,522 $ 10,396
1,256
8,510
(723)
7,787
1,506
9,161
1,276
7,209
(809)
(524)
8,352
6,685
140
893
(2)
891
118
784
(1)
783
92
570
(1)
569
70
698
(51)
647
53
632
(41)
591
71
603
(26)
577
–
11,521
(479)
–
7,072
(167)
–
2,657
(24)
11,042
6,905
2,633
2,405
2,362
2,186
405
400
403
208
226
200
3,367
2,600
1,292
feedstock
2,587
2,291
1,941
22
31
48
1,087
679
80
3,132
3,243
3,465
257
509
458
201
205
262
1,557
1,220
662
Total segmented expenses
7,924
7,896
7,632
967
944
441
476
6,072
4,317
2,063
61
–
–
–
48
–
(230)
–
29
–
–
–
and revaluation of properties
(277)
(35)
(32)
(139)
Equity loss (gain) from
investments
–
–
–
87
80
27
35
(10)
(45)
66
6
29
–
–
574
–
–
–
–
–
–
2
9
–
(36)
–
384
1
9
–
–
–
12
2
–
–
–
–
102
–
102
21
–
14
–
–
–
5
40
–
102
–
102
16
–
9
–
–
–
114
–
114
25
–
11
–
–
(114)
(218)
(31)
(120)
(7)
(189)
148
558
–
558
161
609
–
609
167
849
1,614
1,838
1,606
22,282
18,360
12,002
–
(1,255)
(1,018)
(575)
849
21,027
17,342
11,427
58
71
78
6,464
5,675
4,184
491
527
751
4,189
3,529
2,822
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
5,161
5,186
4,858
186
164
142
(10)
(45)
6
(452)
(379)
(250)
5
(31)
(7)
549
598
829
15,543
14,099
11,755
before the following
$
(137) $ 456 $
(947) $ 317 $
(184) $
(375) $ 263 $
150 $
101
$ 4,970 $ 2,588 $ 570 $
62 $ 222 $ 303 $
9 $
11 $
20 $ 5,484 $ 3,243 $
(328)
325
(146)
319
134
345
355
739
631
383
(124)
827
341
1,962
3,522
80
(787)
(7)
370
27
(55)
(320)
735
2,873
(1,063)
374
(164)
(618)
557
640
(241)
$ 2,591 $ 2,397 $
(204)
95
Segmented product sales
Natural gas
Total segmented product sales
Less: royalties
Segmented revenue
Segmented expenses
Production
Transportation, blending and
Depletion, depreciation and
amortization
Asset retirement obligation
accretion
Realized risk management
(commodity derivatives)
Gain on acquisition, disposition
Segmented earnings (loss)
Non-segmented expenses
Administration
Share-based compensation
Interest and other financing
expense
Risk management activities
(other)
Foreign exchange loss (gain)
Loss (gain) from investments
Total non-segmented expenses
Earnings (loss) before taxes
Current income tax expense
Deferred income tax expense
(recovery)
(recovery)
Net earnings (loss)
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
CAPITAL EXPENDITURES (1)
2018
Non-cash
and fair value
changes
Net
expenditures
2017
Non-cash
Capitalized
costs
Net
expenditures (2)
and fair value
changes (2)
Capitalized
costs
Exploration and
evaluation assets
Exploration and
Production
North America (3)
North Sea
Offshore Africa (4)
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)
Head office
$
118 $
(52)
$
66 $
160 $
(184)
$
–
(54)
218
–
–
(225)
$
282 $
(277)
$
–
(54)
–
15
–
–
(7)
5 $
142
317 $
117
(67)
$
(24)
–
15
259
250
$
2,553 $
(362)
$
2,191 $
2,815 $
354
$
3,169
131
228
2,912
1,229
13
21
(597)
(86)
(1,045)
(466)
142
1,867
160
89
3,064
95
12
461
255
101
3,525
(166)
1,063
9,592
5,454
15,046
–
–
13
21
80
19
114
–
194
19
$
4,175 $
(1,211)
$
2,964 $
12,755 $
6,029
$
18,784
(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) The above noted figures for 2017 exclude the impact of a pre-tax cash gain of $35 million on the disposition of certain exploration and evaluation assets.
(4) The above noted figures for 2018 exclude the impact of a pre-tax cash gain of $16 million on the disposition of certain exploration and evaluation assets.
(5) Net expenditures for Oil Sands Mining and Upgrading include capitalized interest and share-based compensation.
(6) Included in 2017 is 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
96
2018
2017
$
27,199 $
28,705
1,699
1,471
33
39,634
1,413
110
$
71,559 $
1,854
1,331
29
40,559
1,279
110
73,867
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
23. 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
$
$
$
2018
2 $
2017
3 $
2016
2
2018
2017
2016
2 $
8
4
15
29 $
3 $
10
5
17
35 $
3
9
5
15
32
(1) Senior management identified above are consistent with the disclosure on Named Executive Officers provided in the Company’s Information Circular to
shareholders for the respective years.
97
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
Supplementary Oil & Gas Information for the
Fiscal Year Ended December 31, 2018 (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, 2018, 2017, 2016, and 2015 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, 2018,
2017, 2016, and 2015 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 2018 reserves for SEC requirements.
Crude Oil and NGLs
Natural Gas
WTI Cushing
Oklahoma
(US$/bbl)
65.55
WCS
(C$/bbl)
53.67
Canadian
Light Sweet
(C$/bbl)
70.32
Cromer
LSB
(C$/bbl)
75.54
North Sea
Brent
Edmonton
C5+
(US$/bbl)
72.09
(C$/bbl)
80.65
Henry Hub
Louisiana
(US$/MMBtu)
3.02
AECO
(C$/MMBtu)
1.46
BC
Westcoast
Station 2
(C$/MMBtu)
1.25
A foreign exchange rate of US$1.00/C$1.2821 was used in the 2018 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, 2018, 2017, 2016,and 2015, 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, 2018, 2017, 2016 and 2015, 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.
98
Canadian Natural 2018 Annual Report Premium 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, 2018, 2017, 2016, and 2015:
North America
Synthetic
Crude Oil Bitumen(1)
Crude
Oil &
NGLs
North
America
Total
North
Sea
Offshore
Africa
Total
Crude Oil and NGLs (MMbbl)
Net Proved Reserves
Reserves, December 31, 2015
2,283
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
–
–
–
–
(45)
108
196
1,263
46
5
3
–
(71)
23
32
Reserves, December 31, 2016
2,542
1,301
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
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, 2018
Net proved developed reserves
December 31, 2015
December 31, 2016
December 31, 2017
December 31, 2018
–
–
2,232
–
(100)
–
282
4,956
744
–
–
–
(148)
–
109
5,661
2,194
2,527
4,967
5,661
28
7
37
–
(70)
18
44
1,365
151
10
2
(4)
(64)
(45)
54
1,469
411
384
410
461
471
4,017
119
73
4,209
15
14
15
–
(43)
(19)
51
504
17
19
67
–
(44)
17
14
594
17
50
7
–
(47)
(18)
1
604
341
353
399
378
61
19
18
–
(159)
112
279
4,347
45
26
2,336
–
(214)
35
340
6,915
912
60
9
(4)
(259)
(63)
164
7,734
2,946
3,264
5,776
6,500
–
1
–
–
(9)
(10)
(8)
93
–
1
–
–
(9)
18
4
107
–
1
7
–
(9)
11
(3)
114
3
12
28
37
–
2
–
–
(8)
1
6
74
–
–
–
–
(6)
1
–
69
–
3
–
–
(6)
1
4
71
41
31
21
34
61
22
18
–
(176)
103
277
4,514
45
27
2,336
–
(229)
54
344
7,091
912
64
16
(4)
(274)
(51)
165
7,919
2,990
3,307
5,825
6,571
(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.
99
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. 2018 total proved Crude Oil and NGLs reserves increased by 828 MMbbl primarily due to the following:
■■ Extensions and discoveries: Increase of 912 MMbbl primarily due to the addition of the Horizon South Pit to the Horizon
oil sands mining and upgrading Project ("Horizon") (SCO), 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 64 MMbbl primarily due to infill drilling/future offset additions at various primary heavy
crude oil (Bitumen), thermal (Bitumen), Crude Oil and natural gas (NGLs) properties as well as thermal (Bitumen) improved
recovery additions.
■■ Purchases of reserves in place: Increase of 16 MMbbl primarily due property acquisitions in North America and North Sea
core areas.
■■ Sale of reserves in place: Decrease of 4 MMbbl from the primary heavy crude oil (Bitumen) area.
■■ Production: Decrease of 274 MMbbl.
■■ Economic revisions due to prices: Decrease of 51 MMbbl primarily due to increased royalties at thermal (Bitumen) and
Pelican Lake (Crude Oil) projects resulting from higher prices and uneconomic reserves at several North America natural
gas (NGLs) core areas, partially offset by improved reserve life economics at the North Sea.
■■ Revisions of prior estimates: Increase of 165 MMbbl primarily due to geological model changes and improved mine/
extraction/upgrading performance at the oil sands mining and upgrading projects (SCO) and improved recoveries at
Primrose (Bitumen).
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 (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.
100
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent. Natural Gas (Bcf)
Net Proved Reserves
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
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, 2018
Net proved developed reserves
December 31, 2015
December 31, 2016
December 31, 2017
December 31, 2018
North
America
North
Sea
Offshore
Africa
4,523
176
166
85
(5)
(571)
(572)
792
4,594
261
179
106
–
(558)
403
214
5,199
90
414
67
(3)
(523)
(746)
(192)
4,306
2,883
2,805
3,081
2,382
38
–
–
–
–
(14)
(10)
11
25
–
–
–
–
(14)
5
9
25
–
–
–
–
(11)
–
13
27
26
18
22
23
21
–
3
–
–
(11)
1
11
25
–
–
–
–
(7)
(1)
(1)
16
–
–
–
–
(8)
(2)
15
21
15
18
9
12
Total
4,582
176
169
85
(5)
(596)
(581)
814
4,644
261
179
106
–
(579)
407
222
5,240
90
414
67
(3)
(542)
(748)
(164)
4,354
2,924
2,841
3,112
2,417
2018 total proved Natural Gas reserves decreased by 886 Bcf primarily due to the following:
■■ Extensions and discoveries: Increase of 90 Bcf primarily due to extension drilling/future offset additions in the Montney
formation of northwest Alberta and northeast British Columbia.
■■
Improved recovery: Increase of 414 Bcf primarily due to infill drilling/future offset additions in the Montney formation of
northwest Alberta and northeast British Columbia.
■■ Purchases of reserves in place: Increase of 67 Bcf primarily due to property acquisitions in several North America core
areas.
■■ Sale of reserves in place: Decrease of 3 Bcf.
■■ Production: Decrease of 542 Bcf.
■■ Economic revisions due to prices: Decrease of 748 Bcf due to uneconomic reserves at several North America Natural Gas
core areas.
■■ Revisions of prior estimates: Decrease of 164 Bcf primarily due to the removal of future extension and infill undeveloped
reserves at several North America properties as a result of revised Company development plans.
101
Canadian Natural 2018 Annual Report Premium 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 production 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 production costs.
Capitalized Costs Related to Crude Oil and Natural Gas Activities
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
2018
North
America
North
Sea
Offshore
Africa
Total
$
110,154 $
7,321 $
5,471 $
122,946
2,600
112,754
(48,862)
–
7,321
(5,735)
37
5,508
(4,203)
Net capitalized costs
$
63,892 $
1,586 $
1,305 $
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
2017
North
America
North
Sea
Offshore
Africa
$
106,900 $
7,126 $
4,881 $
2,541
109,441
(44,779)
–
7,126
(5,653)
91
4,972
(3,719)
Net capitalized costs
$
64,662 $
1,473 $
1,253 $
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
2016
North
America
North
Sea
Offshore
Africa
$
88,685 $
7,380 $
5,132 $
2,306
90,991
(41,139)
–
7,380
(5,584)
76
5,208
(3,797)
Net capitalized costs
$
49,852 $
1,796 $
1,411 $
102
2,637
125,583
(58,800)
66,783
Total
118,907
2,632
121,539
(54,151)
67,388
Total
101,197
2,382
103,579
(50,520)
53,059
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
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
2018
North
America
North
Sea
Offshore
Africa
$
214 $
127 $
– $
340
116
3,245
–
–
110
(89)
35
212
$
3,915 $
237 $
158 $
2017
North
America
North
Sea
Offshore
Africa
Total
341
251
151
3,567
4,310
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
$
50 $
– $
– $
–
17
4,125
$
4,192 $
–
–
186
186 $
–
9
116
125 $
Total
50
–
26
4,427
4,503
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, 2018, 2017, and 2016 are summarized in the following tables:
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
$
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
2018
North
America
North
Sea
Offshore
Africa
16,065 $
891 $
647 $
(5,772)
(929)
(4,689)
(148)
–
(1,223)
(405)
(22)
(257)
(29)
12
(76)
(208)
(2)
(201)
(9)
–
(51)
$
3,304 $
114 $
176 $
Total
17,603
(6,385)
(953)
(5,147)
(186)
12
(1,350)
3,594
103
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
$
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
$
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
2017
North
America
North
Sea
Offshore
Africa
13,083 $
784 $
578 $
(4,962)
(790)
(4,463)
(128)
–
(740)
(400)
(31)
(509)
(27)
78
42
(226)
(1)
(205)
(9)
–
(28)
Total
14,445
(5,588)
(822)
(5,177)
(164)
78
(726)
$
2,000 $
(63) $
109 $
2,046
2016
North
America
North
Sea
Offshore
Africa
7,791 $
565 $
577 $
(3,478)
(623)
(4,127)
(95)
–
(403)
(48)
(458)
(35)
333
(200)
(2)
(262)
(12)
–
$
143
(389) $
18
(28) $
(22)
79 $
Total
8,933
(4,081)
(673)
(4,847)
(142)
333
139
(338)
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":
104
Canadian Natural 2018 Annual Report Premium 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
2018
North
America
North
Sea
Offshore
Africa
Total
$
500,557 $
12,002 $
6,447 $
519,006
(193,387)
(5,148)
(2,284)
(200,819)
(63,202)
(60,526)
183,442
(126,699)
(2,909)
(1,484)
2,461
(545)
(1,099)
(626)
2,438
(771)
(67,210)
(62,636)
188,341
(128,015)
Standardized measure of future net cash flows
$
56,743 $
1,916 $
1,667 $
60,326
(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
2017
North
America
North
Sea
Offshore
Africa
Total
$
413,180 $
8,740 $
4,786 $
426,706
(198,304)
(4,168)
(1,876)
(204,348)
(61,169)
(35,645)
118,062
(73,171)
(2,853)
(595)
1,124
(59)
(1,258)
(248)
1,404
(455)
Standardized measure of future net cash flows
$
44,891 $
1,065 $
949 $
(millions of Canadian dollars)
Future cash inflows
Future production costs
Future development costs and asset
retirement obligations
Future income taxes
Future net cash flows
10% annual discount for timing of future cash flows
2016
North
America
North
Sea
Offshore
Africa
Total
$
206,729 $
5,999 $
4,129 $
216,857
(92,070)
(3,284)
(1,659)
(97,013)
(42,167)
(15,396)
57,096
(33,590)
(3,249)
280
(254)
271
(1,234)
(125)
1,111
(319)
Standardized measure of future net cash flows
$
23,506 $
17 $
792 $
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)
2018
2017
Sales of crude oil and natural gas produced, net of production costs
$
(10,229) $
(8,013) $
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
20,386
2,807
(698)
396
(55)
2,711
6,119
(955)
(7,061)
13,421
46,905
7,466
481
(5,548)
25,782
–
4,245
3,075
(662)
(4,236)
22,590
24,315
$
60,326 $
46,905 $
2016
(4,159)
(7,305)
700
1,750
352
(2)
3,668
3,527
(2,137)
385
(3,221)
27,536
24,315
105
(65,280)
(36,488)
120,590
(73,685)
46,905
(46,650)
(15,241)
57,953
(33,638)
24,315
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
Ten-Year Review
2017
2018
513
2,632
65,170
73,867
22,458
31,653
(601)
2,637
64,559
71,559
20,623
31,974
2,397
2.04
2.03
7,262
7,347
6.25
6.21
13,102
17,129
2,591
2.13
2.12
10,121
9,088
7.46
7.43
4,814
4,731
Years ended December 31
FINANCIAL INFORMATION (1) (Cdn $ millions, except per share amounts)
Net earnings (loss)
Per share – basic ($/share)
Per share – diluted ($/share)
Cash flows from operating activities
Adjusted funds flow (2)
Per share – basic ($/share)
Per share – diluted ($/share)
Cash flows used in investing activities
Net capital expenditures (3)
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)
Weighted average shares outstanding
– basic (thousands)
Weighted average shares outstanding
– diluted (thousands)
Dividends declared ($/share) (4)
Trading statistics (1)
TSX – C$
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 (5)
Return on average common shareholders'
equity, after tax (5)
Daily production before royalties per
49.08 $
30.11 $
32.94 $
38.19 $
21.85 $
24.13 $
47.00 $
35.90 $
44.92 $
36.78 $
27.53 $
35.72 $
796,971
608,008
806,254
588,422
1.34 $
$
$
$
$
$
$
39%
41%
8%
8%
ten thousand common shares (BOE/d) (1)
Total proved plus probable reserves
per common share (BOE) (1) (6)
Net asset value ($/share) (1) (7)
9.0
11.1
$ 101.89 $
2016
2015
2014
2013
2012
2011
2010 (8)
2009 (9)
(204)
(0.19)
(0.19)
3,452
4,293
3.90
3.89
3,811
3,794
(637)
(0.58)
(0.58)
5,632
5,785
5.29
5.28
5,465
3,853
1,056
2,382
50,910
58,648
16,805
26,267
1,193
2,586
51,475
59,275
16,794
27,381
3,929
3.60
3.58
8,459
9,587
8.78
8.74
11,177
11,744
(673)
3,557
52,480
60,200
14,002
28,891
2,270
2.08
2.08
7,218
7,477
6.87
6.86
7,006
7,274
1,892
1.72
1.72
6,209
6,013
5.48
5.47
5,927
6,308
2,643
2.41
2.40
6,243
6,547
5.98
5.94
5,963
6,414
1,673
1.54
1.53
6,282
6,333
5.82
5.78
5,189
5,514
(1,574)
2,609
46,487
51,754
9,661
25,772
(1,264)
2,611
44,028
48,980
8,736
24,283
(894)
2,475
41,631
47,278
8,571
22,898
(1,200)
2,402
38,429
42,954
8,485
20,368
1,580
1.46
1.46
5,812
6,090
5.62
5.62
3,558
2,997
(514)
–
39,115
41,024
9,658
19,426
1,201,886 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
1,218,798 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
1,223,758 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
0.21
$
0.575 $
0.94 $
0.36 $
0.30 $
0.90 $
0.92 $
0.42 $
1.10 $
653,727
728,033
717,580
683,003
729,700
800,044
661,832 1,040,320
46.74 $
21.27 $
42.79 $
42.46 $
25.01 $
30.22 $
49.57 $
31.00 $
35.92 $
36.04 $
28.44 $
35.94 $
41.12 $
25.58 $
28.64 $
50.50 $
27.25 $
38.15 $
45.00 $
31.97 $
44.35 $
39.50
17.93
38.00
892,220
951,311
812,521
645,403
844,647
937,481
759,327 1,514,614
35.28 $
14.60 $
31.88 $
34.46 $
18.94 $
21.83 $
46.65 $
26.53 $
30.88 $
33.92 $
26.98 $
33.84 $
41.38 $
25.01 $
28.87 $
52.04 $
25.69 $
37.37 $
44.77 $
30.00 $
44.42 $
38.26
13.85
35.98
39%
38%
33%
27%
26%
27%
29%
33%
(1%)
(2%)
14%
7.9
7.3
7.8
7.2
9%
6.2
8%
6.0
12%
8%
8%
5.5
5.8
5.3
9.7
81.41 $
8.3
74.77 $
8.3
73.39 $
8.1
78.99 $
7.3
72.41 $
7.2
62.38 $
6.9
70.37 $
6.3
64.58 $
5.8
64.92
(1) Restated to reflect two-for-one share splits in May 2010.
(2) Adjusted funds flow (previously referred to as funds flow from operations) is a non-GAAP measure that the Company considers key 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 derivation of this measure is discussed in the MD&A.
(3) Net capital expenditures is a non-GAAP measure that the Company considers a key measure as it provides an understanding of the Company’s capital spending activities in comparison
to the Company's annual capital budget. For additional information and details, refer to the net capital expenditures table in the Company's MD&A.
(4) On March 6, 2019, the Board of Directors approved a quarterly dividend of $0.375 per common share, an increase from the previous quarterly dividend of $0.335 per common share.
The dividend is payable on April 1, 2019.
(5) Refer to the “Liquidity and Capital Resources” section of the MD&A for the definitions of these items.
(6) Based upon company gross reserves (forecast price and costs, before royalties), using year-end common shares outstanding. Prior to 2010, Company gross reserves were prepared
using constant prices and costs.
106
Canadian Natural 2018 Annual Report Premium Value. Defined Growth. Independent.
2018
2017
2016
2015
2014
2013
2012
2011
2010 (8)
2009 (9)
Years ended December 31
OPERATING INFORMATION
Crude oil and NGLs (MMbbl) (10)
Company net proved reserves (after royalties)
North America
North Sea
Offshore Africa
7,163
119
72
7,354
Company net proved plus probable reserves (after royalties)
North America
North Sea
Offshore Africa
9,456
186
98
9,740
Natural gas (Bcf) (10)
Company net proved reserves (after royalties)
North America
North Sea
Offshore Africa
6,005
27
21
6,053
Company net proved plus probable reserves (after royalties)
North America
North Sea
Offshore Africa
8,681
38
44
8,763
6,423
120
70
6,613
8,353
180
102
8,635
6,032
21
15
6,068
8,454
32
47
8,533
3,909
134
74
4,117
6,015
252
108
6,375
5,845
41
23
5,909
7,888
85
55
8,028
3,645
158
74
3,877
5,806
284
113
6,203
5,383
39
21
5,443
7,361
96
50
7,507
3,380
204
78
3,662
5,609
308
119
6,036
5,054
83
36
5,173
6,791
114
68
6,973
3,290
224
80
3,594
5,135
325
122
5,582
3,684
91
38
3,813
5,138
125
70
5,333
3,268
227
85
3,580
5,119
332
127
5,578
3,540
82
48
3,670
4,907
102
76
5,085
3,007
228
87
3,322
4,777
349
131
5,257
3,778
98
54
3,930
5,125
134
83
5,342
2,763
252
101
3,116
4,293
376
149
4,818
3,638
78
76
3,792
4,870
107
113
5,090
2,664
240
123
3,027
4,172
387
179
4,738
3,027
67
85
3,179
3,992
94
124
4,210
Total net proved reserves
(after royalties) (MMBOE)
Total net proved plus probable reserves
8,363
7,625
5,102
4,784
4,524
4,230
4,191
3,977
3,748
3,557
(after royalties) (MMBOE)
11,202
10,057
7,713
7,454
7,198
6,471
6,426
6,147
5,666
5,440
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) (11)$
Average natural gas price ($/Mcf) (11)
$
Average SCO price ($/bbl) (11) (12)
$
351
426
24
20
821
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
1,490
32
26
1,548
1,079
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
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
46.92 $
2.61 $
68.61 $
48.57 $
2.76 $
63.98 $
36.93 $
2.32 $
58.59 $
41.13 $
3.16 $
77.04 $
4.83 $
61.39 $ 100.27 $
73.81 $
3.30 $
99.18 $
79.16 $
72.44 $
2.70 $
3.99 $
90.74 $ 101.48 $
65.81 $
4.08 $
77.89 $
57.68
4.53
70.83
(7) 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, 2018) 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 (2018 to 2015, $300/acre for core unproved property from 2014 to 2010, $250/acre for core undeveloped land in 2009), less net debt and using
common shares outstanding. Net debt is long term debt plus/minus the working capital deficit/surplus. Future development costs and abandonment and reclamation costs attributable
to future development activity have been applied against the future net revenue.
(8) 2010 comparative figures have been restated in accordance with IFRS issued at December 31, 2011.
(9) 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.
(10) For the years 2010 to 2018, company net reserves were prepared using forecast prices and costs; prior to 2010, company net reserves were prepared using constant prices
and costs.
(11) For the years 2011 to 2018, product prices reflect realized product prices before transportation costs. Prior to 2011, product prices were reported net of transportation costs.
(12) For years 2017 and 2018, average SCO product price includes AOSP realized product prices net of blending and feedstock costs.
107
Canadian Natural 2018 Annual Report Premium 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.
Corporate Director
London, England
*Timothy W. Faithful (1)(3)
Corporate Director
London, England
*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 (5)
Executive Vice-Chairman,
Canadian Natural Resources Limited
Calgary, Alberta
Tim S. McKay (3)
President, Canadian Natural Resources Limited
Calgary, Alberta
*Honourable Frank J. McKenna, P.C., O.C., O.N.B., Q.C. (2)(4)
Deputy Chair, TD Bank Group
Cap Pelé, New Brunswick
*David A. Tuer (1)(5)
Chairman, Optiom Inc.
Calgary, Alberta
*Annette M. Verschuren, O.C. (2)(3)
Chairman and Chief Executive Officer, NRSTOR Inc.
Toronto, Ontario
108
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
Pamela A. McIntyre
Senior Vice-President, Safety, Risk Management
and Innovation
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
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 of 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.
Canadian Natural 2018 Annual Report Premium 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 13.
METRIC CONVERSION CHART
To convert
To
barrels
thousand cubic feet
feet
miles
acres
tonnes
cubic metres
cubic metres
metres
kilometres
hectares
tons
Multiply by
0.159
28.174
0.305
1.609
0.405
1.102
COMMON SHARE DIVIDEND
The Company paid its first dividend on its common shares
on April 1, 2001. Since then, dividends have been paid
quarterly. The following table shows the aggregate amount
of the cash dividends declared per common share of the
Company and accrued in each of its last three years ended
December 31, 2018.
Cash dividends declared
per common share(1)
(1) Annualized dividend value.
2018
2017
2016
$1.34
$1.10
$0.94
NOTICE OF ANNUAL MEETING
Canadian Natural’s Annual and Special Meeting of the
Shareholders will be held on Thursday, May 9, 2019 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 2018 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 2018 Annual Report Premium Value. Defined Growth. Independent.
2100, 855 – 2 Street S.W.
Calgary, AB T2P 4J8
T
F
E
(403) 517-6700
(403) 517-7350
ir@cnrl.com
www.cnrl.com