2020 Performance Highlights
Canadian Natural’s diverse and balanced asset base along with a continued focus on effective and
efficient operations delivered industry leading free cash flow, creating significant value for the Company’s
shareholders in 2020.
FINANCIAL ($ millions, except per common share amounts)
Product sales
Net earnings (loss)
Per common share
– basic
– diluted
Adjusted net earnings (loss) from operations (1)
Per common share
– basic
– diluted
Cash flows from operating activities
Adjusted funds flow (2)
Per common share
– basic
– diluted
Cash flows used in investing activities
Net capital expenditures (3)
Long-term debt (4)
Shareholders’ equity
Debt to book capitalization (5)
2020
2019
2018
17,491
$
24,394 $
22,282
(435) $
5,416 $
2,591
(0.37) $
(0.37) $
4.55 $
4.54 $
2.13
2.12
(756) $
3,795 $
3,263
(0.64) $
(0.64) $
3.19 $
3.18 $
2.68
2.67
4,714
5,200
4.40
4.40
2,819
3,206
21,453
32,380
$
$
$
$
$
$
$
$
8,829 $
10,121
10,267 $
9,088
8.62 $
8.61 $
7,255 $
7,121 $
7.46
7.43
4,814
4,731
20,982 $
20,623
34,991 $
31,974
40%
37%
39%
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(1) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes in evaluating its 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 the Company’s Management’s Discussion and Analysis (“MD&A”).
(2) Adjusted funds flow is a non-GAAP measure that the Company considers a key measure in evaluating its performance 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 the Company’s 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. The reconciliation “Net Capital Expenditures, as Reconciled to Cash Flows used in
Investing Activities” is presented in the “Net Capital Expenditures” section of the Company’s MD&A.
(4) Includes the current portion of long-term debt.
(5) Calculated as net current and long-term debt; divided by the book value of common shareholders’ equity plus net current and long-term debt.
TABLE OF CONTENTS
2020 Performance Highlights
Letter to our Shareholders
01
03
T1-T8 Our World Class Team
05
08
48
49
2020 Year-End Reserves
Management’s Discussion and Analysis
Consolidated Financial Statements
Management’s Report
1
Management’s Assessment of Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Notes to the Consolidated Financial Statements
Supplementary Oil and Gas Information
50
51
58
95
103 Ten-Year Review
105 Corporate Information
Canadian Natural 2020 Annual Report
OPERATING
Daily production, before royalties (1)
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) (2)
Drilling activity (3)
North America
North Sea
Offshore Africa
2020
2019
2018
460
417
23
17
918
406
395
28
21
850
351
426
24
20
821
1,450
1,443
1,490
12
15
1,477
1,164
71
1
–
72
24
24
1,491
1,099
102
5
1
108
32
26
1,548
1,079
504
4
2
510
(1) Numbers may not add due to rounding.
(2) 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.
(3) Net wells. Excludes net stratigraphic test and service wells.
1,164,000
BOE/D
TOTAL PRODUCTION
47%
OF BOE PRODUCTION IS SCO,
LIGHT CRUDE OIL & NGLS
Canadian Natural 2020 Annual Report
2
Letter to our Shareholders
The impact of the COVID-19 pandemic in 2020 affected the very way we conducted our lives and the
way we operated our businesses. Through the year we took protocols to protect our stakeholders and
would like to thank our employees, contractors, suppliers and shareholders for their support through
this challenging year. Despite the challenges of COVID-19 in 2020, the Company had a strong year
operationally and financially. Our effective and efficient operations and long life low decline asset base
proved their robustness in this challenging year. We were nimble in 2020, quickly lowering capital with
minimal impact to annual production as we stayed within the Company’s original production guidance
range, effectively managing through a volatile commodity price environment and low crude oil demand.
This was achieved through the commitment and hard work of our employees, who were rewarded with
no economic layoffs due to the impacts of COVID-19. In 2020 the Company generated strong adjusted
funds flow while effectively allocating to the Company’s four pillars of capital allocation; balance sheet
strength, returns to shareholders, resource value growth, and opportunistic acquisitions.
Canadian Natural achieved record annual average production of 1,164 MBOE/d in 2020, a 6% increase compared to 2019
levels. The resilience and sustainability of our business model was evident in 2020 as annual adjusted funds flow was strong
at approximately $5.3 billion, excluding the provision relating to the Keystone XL pipeline project. Excluding the Painted
Pony acquisition costs and the Keystone XL provision, we completely covered our capital program, and dividend, generating
approximately $690 million in free cash flow in 2020. Canadian Natural exited 2020 with a strong balance sheet, as net debt,
before acquisitions, was essentially unchanged from 2019 levels and liquidity remained strong with approximately $5.4 billion
available including cash and cash equivalents and short-term investments. Canadian Natural was patient and disciplined,
maintaining its 13% quarterly dividend increase in March 2020 of $0.425 per common share throughout the year. Additionally,
in March 2021, the sustainability of our free cash flow generation provided the Board of Directors confidence to increase our
dividend by 11% to $1.88 per common share annually, marking the 21st consecutive year of dividend increases.
Environmental, Social and Governance (“ESG”) performance remains a top priority and investments to improve the
Company’s performance and reduce environmental footprint continue. The Company’s unique portfolio, supported by long
life low decline assets affords Canadian Natural numerous opportunities to deploy new technology and capture innovation
to reduce the Company’s Greenhouse Gas (“GHG”) emissions, while enhancing economic margins through continuous
improvement initiatives. Canadian Natural has a defined pathway that is driving a long-term reduction of GHG emissions
through an integrated emissions management strategy that includes investment in research, technology and innovation, all of
which contribute to the Company reaching its aspirational goal of net zero oil sands emissions. Over the last decade Canadian
Natural has invested $3.7 billion in research and development, driving the necessary improvements to help the Company
successfully reduce our corporate GHG emission intensity by 18% and methane emissions by 28%, from 2016 levels. Our
safety record is top tier, as corporate total recordable injury frequency (“TRIF”) improved to 0.21 in 2020, a reduction of 58%
from 2016 levels. The Company also reached significant environmental milestones, including the cumulative sequestration at
our Quest facility of five million tonnes of CO2 captured from the Scotford Upgrader and the cumulative planting of two and
a half million trees at our Oil Sands Mining and Upgrading operations.
Canadian Natural is committed to a long-term presence in the communities where we operate in Canada, the United
Kingdom and Africa. This group of stakeholders includes more than 24,000 landowners, 160 municipalities and 80 Indigenous
communities in Western Canada, as well as industry, governments, regulators, academia, and non-governmental groups. The
Company works with these diverse communities to identify opportunities for education and training, employment, business
development and community investment. Canadian Natural also has a strong commitment to corporate governance, which
assures stakeholders that the Company always operates with the highest levels of integrity and ethical standards.
Oil Sands Mining and Upgrading was approximately 36% of total corporate production, averaging 417,351 bbl/d of Synthetic
Crude Oil (“SCO”), an increase of 6% compared to 2019 levels and the segment delivered impressive results through a
combination of high utilization and operational enhancements. Canadian Natural achieved record low annual operating costs
of $20.46/bbl of SCO, a decrease of $2.10/bbl or 9% from 2019 levels. During planned turnaround activities at AOSP, gross
capacity at the Scotford Upgrader was increased by 20,000 bbl/d to 320,000 bbl/d. The long life, zero decline, high value
nature of these assets at Horizon and AOSP continue to deliver free cash flow, maximizing value for our shareholders.
$1.70/common share
$2.2 BILLION
ANNUAL DIVIDENDS
RETURNED TO SHAREHOLDERS
3
Canadian Natural 2020 Annual Report
N. MURRAY EDWARDS
Executive Chairman
TIM S. MCKAY
President
MARK A. STAINTHORPE
Chief Financial Officer and
Senior Vice-President, Finance
Thermal in situ oil sands operations produced a record 248,971 bbl/d, which represented approximately 21% of total production
in 2020, an increase of 48% over 2019 levels. This increase was primarily the result of a full year of operatorship at Jackfish,
as well as increased production at Kirby North. Thermal in situ operating costs decreased by 13% to $9.44/bbl compared to
2019 levels, primarily as a result of operational synergies and higher production levels, offset by higher fuel costs. Canadian
Natural continued to see positive results during 2020 from its on-going solvent enhanced oil recovery technology pilot at Kirby
South, targeting increased bitumen production, a reduction in the steam-to-oil ratio of up to 50%, a reduction of GHG intensity
of up to 50% and a high solvent recovery. The Company will continue to monitor results of the pilot throughout 2021 as this
technology has the potential for application throughout the Company’s extensive thermal in situ asset base.
Canadian Natural’s North American E&P operations include crude oil, natural gas and NGL producing assets and represented
approximately 40% of the Company’s total BOE production in 2020. These assets delivered 211,472 bbl/d of liquids production,
a decrease of 11% from 2019 levels as a result of natural declines and strategic decisions to limit capital investment. Natural
gas prices strengthened during 2020 creating an opportunity for Canadian Natural to capitalize on the Company’s deep
inventory of high-quality natural gas opportunities, resulting in production averaging 1,450 MMcf/d, comparable with 2019
levels. Strong base production, highly economic volumes additions and acquired production in the second half of the year
resulted in significant exit rate volume of 1,624 MMcf/d in December 2020.
International operations averaged production of approximately 40,100 bbl/d in 2020, a decrease of 19% from 2019 levels,
primarily as a result of the cessation of production at the Banff and Kyle fields in the North Sea and natural declines. In
offshore South Africa, where Canadian Natural holds a 20% non-operated working interest, the operator made a significant
gas condensate discovery during the second half of 2020. The operator is currently evaluating development scenarios
following the successful discovery wells.
Canadian Natural is optimistic for 2021 and confident that its portfolio of assets underpinned by a significant base of long
life low decline assets, combined with our flexible, high value E&P assets make Canadian Natural a truly unique, sustainable
and robust company. The 2021 capital budget of approximately $3.2 billion drives annual production growth of approximately
61,000 BOE/d at the mid-point from 2020 levels and robust free cash flow generation at annual strip pricing of approximately
US$57 WTI per barrel, which is targeted to be allocated towards strengthening the Company’s balance sheet.
Through the hard work and dedication of Canadian Natural’s committed and talented teams, the Company remains well-
positioned to continue to deliver effective and efficient operations and top-tier operational results. Canadian Natural is
committed to sustainable, growing returns to shareholders and reducing our environmental footprint through innovative
technology and a culture of continuous improvement and targets to build upon its history of creating premium value for
its shareholders.
N. MURRAY EDWARDS
Executive Chairman
TIM S. MCKAY
President
MARK A. STAINTHORPE
Chief Financial Officer and
Senior Vice-President, Finance
Canadian Natural 2020 Annual Report
4
Our World-Class Team
Our proven strategy and disciplined business approach are supported by our dedicated teams and
experienced management team. Canadian Naturals exponential growth reflects dedication, planning and
resilience from its main resource: our employees.
G. Aalders, E. Aasen, A. Abadier, L. Abadier, A. Abakar, Z. Abbas, T. Abbasi, D. Abbott, M. Abbott, I. Abdi, A. Abdolmaleki, M. Abdulrhman, A. Abeda, W. Abeda, D. Abel, R. Abel, V.
Abeng, T. Abercrombie, G. Abou Mechrek, R. Abrams, A. Abramyan, N. Abro, C. Acharya, J. Acosta, J. Acteson-Grill, T. Adair, I. Adam, S. Adam, A. Adams, D. Adams, K. Adams, M.
Adams, D. Adamson, P. Adamson, C. Adan, T. Adbous, D. Addinall, A. Adebayo, Y. Adebayo, S. Adel, M. Aden, A. Adesanya, O. Adigun, B. Adjoussou, B. Adkins, N. Agarwal, J. Agate,
F. Agbadou, A. Agnihotri, K. Agombar, I. Agu, U. Agu, R. Aguilera Maestre, A. Agustin, C. Agyemang-Badu, A. Ahmad, I. Ahmad, J. Ahmad, M. Ahmad, N. Ahmad, R. Ahmad, S. Ahmad,
A. Ahmadi, M. Ahmadi, F. Ahmadloo, A. Ahmari, R. Ahmed, S. Ahmed, M. Ahoonmanesh, R. Aidoo, R. Aikens, D. Aikins, G. Ailsby, J. Airton, S. Aitken, S. Ajayi, T. Ajayi, J. Ajedegba,
L. Ajijolaiya, S. Akhtar, R. Akinde, D. Akins, A. Akinsanya, J. Akolkar, N. Akolkar, S. Akolkar, C. Alarcon, J. Alcala, E. Alconcel, N. Aldi, J. Aleman, A. Alexander, D. Alexander, J.
Alexander, P. Alexander, A. Ali, G. Ali, R. Aliazas, H. Aljanabi, M. Al-Kaisy, C. Allan, E. Allan, J. Allan, E. Allard, J. Allard, L. Allegretto, A. Allen, B. Allen, J. Allen, T. Allen, W. Allerton, J.
Allison, R. Allison, S. Allport, J. Allsop, A. Almaktary, S. Almstrong, Y. Alnumi, J. Alonso, Y. Al-Saeedi, R. Al-Samarrai, S. Al-Siani, A. Alstad, J. Alvarez, B. Alyman, D. Amalaman, G.
Amalia, J. Aman, M. Amar, T. Amara, A. Amay, A. Amer, B. Amer, K. Amer, J. Amero, D. Ames, E. Amos, W. Amy, A. Amyotte, D. Anctil, J. Andel, D. Andersen, T. Andersen, A.
Anderson, B. Anderson, C. Anderson, D. Anderson, J. Anderson, K. Anderson, L. Anderson, M. Anderson, N. Anderson, P. Anderson, R. Anderson, S. Anderson, W. Anderson, I.
Andonov, D. Andreoli, C. Andres, B. Andrews, D. Andrews, K. Andrews, T. Andrews, E. Anfort, C. Angeles, P. Angell, L. Angen, K. Angerman, M. Anis, L. Anongba, M. Ansah-Sam, A.
Ansell, C. Ansong-Danquah, D. Ansorger, R. Anstett, V. Anstey, L. Antal, W. Anthony, E. Antle, C. Antoine, M. Antoine, A. Anton, K. Antonishyn, J. Antoniuk, A. Antunes, H. Aparicio
Ramos, P. Appiah, J. Aquila, R. Aranguren, F. Arano, L. Arbour, J. Argan, H. Arias, L. Arias, J. Arizaleta, S. Arjomandi, J. Arkley, T. Armfelt, A. Armstrong, D. Armstrong, J. Armstrong,
J. Arnault, B. Arneson, B. Arnold, C. Arnold, J. Arnold, V. Aron, F. Arrau, F. Arrieta, M. Arsenault, K. Arstall, A. Arthur Brown, B. Artz, S. Arunachalam, B. Asake, J. Ashe, Z. Ashmore,
A. Aslam, M. Aslam, R. Aslin, R. Asmundson, R. Aspden, S. Aspden, H. Aspeslet, M. Asselstine, D. Assinger, J. Asso, V. Assohou-Ouattara, J. Assoignon, 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, J. Auch, J. Aucoin, P. Aucoin, W. Aucoin, A.
Auger, D. Auger, L. Auger, P. Auger, S. Auger, C. Aular, C. Austin, R. Austin, F. Avery, S. Avery, M. Avila, C. Aviles, O. Awodein, A. Ayasse, W. Ayles, A. Ayoub, J. Ayub, F. Azam, Z.
Azim, A. Babiarz, O. Babiker, K. Babu, C. Bachelet, C. Bachman, W. Bachmeier, C. Backer, A. Badamchi Zadeh, W. Bader, N. Badgley, O. Baffoh, G. Baggs, N. Bagheri, K. Bagley, A.
Bagnall, M. Bahiraei, B. Bahlieda, D. Baichev, D. Baier, J. Baier, R. Bailer, A. Bailey, B. Bailey, J. Bailey, K. Bailey, S. Bailey, T. Bailey, S. Baillargeon, M. Baillie, B. Bain, E. Bain, C. Baird,
E. Baird, D. Baisley, D. Bak, L. Bakaas, A. Baker, C. Baker, D. Baker, J. Baker, R. Baker, A. Bakhtiary Fard, F. Bakita, D. Bakkar, J. Bakker, J. Balacang, M. Balan, B. Balaski, B. Baldonado,
J. Baldonado, C. Baldwin, G. Baldwin, M. Baldwin, R. Baldwin, M. Baleja, R. Balfour, I. Balicanta, J. Balkam, C. Balko, G. Ball, J. Ball, L. Ball, M. Ball, P. Ball, K. Ballantyne, J. Ballard,
S. Ballas, B. Balog, D. Balogoum, A. Balsom, D. Balson, J. Baltesson, 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, M. Banwait, R. Barabe, L. Barbaro, D. Barber, G. Barber, J. Barbour, L.
Bardoel, G. Barfield, M. Bari, M. Barilea, R. Barker, S. Barker, S. Barlund, D. Barnes, M. Barnes, N. Barnes, R. Barnes, V. Barnes, B. Barnett, D. Barr, S. Barr, E. Barreto, C. Barrett, M.
Barrett, R. Barrett, T. Barrett, S. Barriault, C. Barrie, D. Barron, R. Barron, D. Barry, A. Barstad, G. Bartel, P. Barter, B. Bartlett, C. Bartlett, M. Bartlett, D. Bartman, M. Bartman, N.
Bartsch, A. Barysheva, J. Basabe, K. Basarab, N. Basi, R. Basile, L. Basines, P. Bass, S. Basso, C. Bast, A. Bastardo, H. Bastidas Martinez, C. Bastien, S. Basu, M. Batac, S. Batarseh,
C. Bateman, M. Bateman, P. Bateman, T. Bateman, G. Bates-Vasileiou, D. Bath, L. Bath, S. Batina, M. Batovanja, D. Batt, U. Batta, R. Batten, C. Battrum, B. Battyanie, D. Bauer, R.
Bauer, T. Bauld, C. Baumgardner, J. Baxter, J. Bayles, D. Bayley, F. Bayuk, A. Bazowski, B. Beach, A. Beacon, W. Beals, C. Beaman, G. Beamish, J. Beamish, D. Bean, G. Bean, R.
Bear, C. Beaton, G. Beaton, N. Beaton, A. Beattie, C. Beattie, S. Beattie, J. Beauchamp, S. Beauchamp, C. Beaudoin, J. Beaudoin, R. Beaudoin, C. Beaudrie, B. Beaulac, J. Beaulieu,
M. Beaulieu, L. Beaunoyer, M. Beaunoyer, J. Becaria, D. Bechtel, N. Beck, C. Becker, H. Becker, R. Becker-Faubert, R. Beckner, S. Beckow, J. Beda, L. Bedard, M. Bedard, D. Bedell,
G. Bedi, M. Bednarchuk, S. Beebe, T. Beebe, M. Beeks, C. Beeler, K. Begg, W. Behnke, J. Behrens, A. Belah, R. Belanger, H. Belas, L. Belcourt, R. Belcourt, J. Belik, R. Belisle, A.
Bell, D. Bell, J. Bell, K. Bell, L. Bell, N. Bell, R. Bell, S. Bell, J. Bellavance, J. Beller, M. Beller, E. Bellerose, A. Bellettini, J. Belliveau, A. Bellows, C. Bellows, M. Belzile, M. Bembridge,
A. Bendahmane, K. Bendahmane, C. Bender, R. Benedictson, M. Benko, D. Benn, T. Benn, K. Benner, C. Bennett, D. Bennett, J. Bennett, R. Bennett, S. Bennett, A. Benoit, P. Benoit,
D. Bensley, M. Benson, A. Benson- Bartko, A. Bentley, R. Bentley, I. Bentsianov, J. Berdan, D. Berg, R. Berg, L. Berge, O. Bergeron, J. Bergeson, M. Bergeson, B. Bergley, J. Bergsma,
D. Berlinguette, J. Bernardin, T. Bernhard, J. Bernier, K. Berreth, R. Berry, W. Berscht, D. Bershadsky, S. Bertelmann, G. Bertolin, A. Bertrand, B. Bertrand, J. Bertrand, M. Bertsch, M.
Bertucci, B. Berube, R. Besinger, C. Best, J. Best, C. Betancur Pelaez, T. Betteridge, S. Bettinson, W. Bewski, B. Beyer, J. Beytell, S. Bezpalchuk, J. Bezruchak, M. Bezugley, A.
Bhadauria, A. Bhaduri, L. Bhamare, J. Bhangoo, H. Bhathal, H. Bhatia, J. Bhatt, K. Bhatt, R. Bhatt, V. Bhekare, J. Bianchini, L. Bianco, M. Bibars, K. Bibby, A. Bibo, J. Bick, S. Biddle, T.
Biddlecombe, C. Bieber, D. Bieber, D. Bielech, E. Bieleski, D. Biendarra, D. Biener, V. Biesinger, K. Biever, C. Biggin, M. Biggs, A. Bilal, D. Biles, B. Bill, L. Billard, T. Billard, J. Bilous,
D. Bilston, M. Binder, B. Binns, R. Bintz, C. 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,
C. Bisson, D. Bittner, J. Bizuk, A. Black, B. Black, C. Black, J. Black, K. Black, R. Black, V. Black, P. Blackburn, W. Blackburn, T. Blackett, K. Blackmore, R. Blackmore, T. Blackwell, A.
Blacquiere, D. Blain, G. Blain, A. Blair, D. Blair, K. Blair, L. Blair, J. Blais, A. Blake, D. Blake, J. Blake, L. Blake, T. Blake, P. Blakely, B. Blakney, J. Blanc, A. Blanchard, D. Blanchard, G.
Blanchard, T. Blanchard, R. Blanchett, K. Blanchette, A. Blanco, G. Blanco, U. Blanco, W. Blanco, L. Bland, S. Blaquiere, E. Blawat, S. Blaydes, K. Blencowe, J. Blesa, A. Blesa Gomez,
N. Bligh, M. Blinkhorn, S. Blize, R. Blonar, R. Blondin, G. Blouin, P. Bluemke, J. Blume, J. Blundon, C. Blyan, C. Boadas Salazar, J. Bobbett, A. Bobrowski, H. Bocalan, 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. Boeckx, M. Boehm, D. Boehmer, D. Boettcher, D. Boettger,
M. Boggust, L. Boghici, T. Bohach, A. Bohemier, B. Bohlken, J. Bohlken, E. Bohme, N. Bohning, J. Bohorquez, J. Boire, J. Boissoneault, C. Boisvert, J. Boisvert, M. Boisvert, D. Bokota,
R. Boksteyn, S. Bolduc, G. Bolin, D. Bolster, B. Bolt, J. Bolt, G. Bolzon, G. Bond, K. Bond, N. Bond, S. Bond, T. Bond, E. Bondarenko, T. Bondaruk, N. Bonderoff, A. Bone, C. Bonebrake,
A. Bonilla, E. Bonnefon, C. Bonogofski, A. Bonwick, T. Bonwick, S. Booker, J. Boomgaarden, A. Boone, B. Boone, C. Boos, K. Booth, M. Booth, B. Borbely, K. Bordeleau, R. Bordeleau,
J. Borg, C. Borgel, C. Borgland, P. Bork, J. Borkowski, S. Borkowsky, M. Borlaza, M. Born, N. Born, D. Borowski Grimaldi, K. Borromeo, E. Borsa, E. Borsini Marin, M. Borst, J. Borstel,
K. Borysiuk, D. Bosch, J. Bosch, S. Bosch, J. Boschman, S. Bose, G. Bosma, L. Bosoi, P. Bossel, A. Botha, H. Botha, K. Bothwell, J. Botterill, D. Bouchard, L. Bouchard, T. Bouchard,
J. Bouchard Lacoste, C. Boucher, T. Boucher, J. Boudreault, K. Bougie, B. Boulton, J. Boulton, T. Bouma, J. Bounds, C. Bourassa, L. Bourassa, R. Bourassa, S. Bourassa, T. Bourassa,
J. Bourdon, J. Bourgeois, C. Bourlon, D. Bourque, S. Bourrie, C. Boutier, M. Boutilier, D. Bouvier, K. Boven, C. Bowal, M. Bowal, C. Bowditch, S. Bowers, D. Bowes, B. Bowie, J. Bowie,
M. Bowles, J. Bowman, K. Bowman, N. Bowman, E. Bown, W. Bowness, J. Boxer, D. Boyarski, R. Boyce, T. Boyce, S. Boychuk, J. Boyd, R. Boyd, J. Boyde, A. Boyer, C. Boyer, V.
Boyko, D. Boyle, L. Boyle, N. Boyle, D. Bradbury, A. Bradley, B. Bradley, P. Bradley, P. Bradner, G. Brady, J. Brady, M. Brady, J. Bragg, S. Braithwaite, N. Brake, S. Brake, J.
Branderhorst, J. Brannick, B. Brant, D. Brant, P. Brar, C. Brassard, M. Brataschuk, K. Bratt, K. Brattebo, R. Brattston, C. Brausen, M. Brautigam, K. Bravo, L. Bravo, T. Bray, A. Brazeau,
J. Breau, M. Brecht, S. Bredy, D. Breen, M. Breen, S. Breen, B. Brekke, E. Brekke, D. Bremner, C. Brennan, L. Brennan, M. Brennan, J. Brenton, L. Brenton, R. Brenton, T. Bresson,
K. Brethour, T. Bretzer, R. Bretzlaff, A. Brewer, J. Breytenbach, R. Brezinski, W. Briand, S. Briard, B. Bricker, M. Brideau, C. Bridger, J. Bridger, M. Brietzke, C. Briggs, M. Briggs, J.
Bright, L. Brinkworth, S. Brinson, S. Brinston, J. Briscoe, C. Brisebois, L. Brisebois, B. Britton, P. Britton, S. Britton, J. Brock, M. Brock, K. Brocke, A. Broderick, S. Broderson, S.
Brodeur, T. Brodie, D. Brodziak, E. Broidioi, K. Bromley, J. Bronkhorst, G. Bronson, D. Brooks, J. Brooks, R. Brooks, S. Broomfield, G. Brophy-Maclean, K. Brosowsky, 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, S. Brown, T.
Brown, W. Brown, D. Brownrigg, J. Bruce, R. Bruce, T. Bruce, L. Bruchanski, A. Brucker, R. Brue, K. Bruggencate, F. Brugger, V. Brule, S. Brulotte, N. Brummitt, D. Brundige, R.
Brundige, K. Bruner, M. Brunet, M. Brushett, R. Bryan, B. Bryant, P. Bryant, R. Bryant, T. Bryant, T. Brydges, E. Bryenton, H. Bryenton, B. Bryks, J. Bryla, M. Bryson, S. Bryson, G.
Buchan, P. Buchanan, C. Buchholz, M. Buchinski, J. Buck, D. Buckley, M. Buckley, G. Buckshaw, T. Budd, N. Budden, R. Bueckert, S. Bugden, W. Bugiak, N. Buhler, S. Bukhari, C.
Bull, R. Bullen, T. Bullen, I. Bulloch, J. Bullock, G. Bungay, L. Bungay, Q. Bunten-Walberg, D. Burak, T. Burchenski, L. Burden, J. Burdett, D. Burgess, B. Burk, G. Burkart, T. Burkart,
D. Burke, L. Burke, S. Burke, G. Burkhart, P. Burness, J. Burnett, J. Burnouf, J. Burns, R. Burris, C. Burroughs, B. Burry, D. Burry, S. Burry, D. Bursey, A. Burt, S. Burt, G. Burton, J.
Burton, K. Burton, M. Burton, N. Burton, R. Burton, T. Burton, W. Burton, R. Busato, K. Bush, D. Bushey, J. Bushfield, T. Bushie, N. Bussiere, M. Butchart, C. Butler, D. Butler, H.
Butler, I. Butler, M. Butler, R. Butler, T. Butler, D. Butlin, B. Butt, K. Butt, M. Butt, Q. Butt, S. Butt, T. Butt, W. Butt, M. Buttigieg, K. Butts, R. Butts, P. Buxton, B. Bye, J. Byrne, M.
Byrne, J. Byrtus, I. Byvald, L. Cabatuando, A. Cabral, J. Cachene-Clark, T. Cadieux, R. Cahoon, B. Cain, A. Caines, H. Cairns, E. Caissie, W. Calabio, B. Calder, L. Calder, J. Caldwell, P.
Caldwell, C. Caleffi, D. Callander, C. Callihoo, P. Callin, R. Calliou, M. Camargo, S.
Cameron, A. Campbell, B. Campbell, C. Campbell, D. Campbell, E. Campbell, G.
Campbell, K. Campbell, N. Campbell, P. Campbell, S. Campbell, W. Campbell, A.
Campeau, N. Campeau, W. Campeau, A. Campos, M. Canchica, G. Cane, C.
Canning, M. Canning, J. Cannon, E. Cantlon, J. Cantwell, M. Cao, A. Caouette, D.
Caouette, G. Caouette, K. Cap, A. Capadosa, M. Capitaneanu, L. Cappelle, M.
Capstick, B. Carabin, G. Carde, A. Cardenas, L. Cardenas Schulz, F. Cardinal, L.
Cardinal, R. Cardinal, W. Cardinal, M. Carew, J. Carey, W. Carey, D. Carleton, J.
Carleton, T. Carleton, K. Carlos, F. Carlos Sanchez, J. Carlson, W. Carlson, D.
Carnes, D. Caron, R. Caron, S. Caron, G. Carpo, C. Carr, D. Carr, J. Carr, L.
Carranza, V. Carrasco Rueda, M. Carrier, T. Carrier, D. Carroll, I. Carroll, J. Carroll,
M. Carroll, R. Carroll, S. Carroll, C. Carruthers, C. Carsh, B. Carson, E. Cartaya, D.
Carter, E. Carter, J. Carter, K. Carter, N. Carter, R. Carter, S. Carter Hicks, C.
Cartier, X. Cartron, J. Cartwright, G. Case, P. Cashin, B. Cassell, T. Cassidy, D.
Cassie, J. Cassivi, L. Casson, F. Castellanos, A. Castillo, K. Castle, C. Castro, J.
Castro, J. Caswell, A. Cater, N. Catley, L. Catto, J. Cauchie, L. Caul, D. Cavacciuti,
A. Cavanagh, N. Cavanagh, D. Cavers, J. Cayabo, C. Cayer, D. Cazabon, C. Celis,
M. Cenon, A. Centeno, S. Cervantes, B. Chaba, D. Chadwick, A. Chafe, A.
Chaisson, S. Chakraborty, S. Chakravarty, M. Chalaturnyk, A. Chalifoux, C.
Chalifoux, M. Chalmers, A. Chamanara, C. Chambers, T. 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, A. Chaney, J. Chanski, T. Chantler, H.
Chaouach, K. Chapman, M. Chapman, S. Chapman, B. Chapple, R. Chaput, W.
Charanek, N. Charest, S. Charette, D. Charlish, J. Charlton, Y. Charniauski, L.
Charrois, R. Chartrand, P. Chase, A. Chatman, A. Chatterjee, M. Chaudhry, D.
Chauvet, S. Chavda, D. Chavez, M. Chawla, T. Chayko, C. Chaytor, P. Chaytor, M.
Chechile, W. Cheladyn, B. Chen, C. Chen, D. Chen, H. Chen, K. Chen, T. Chen, X.
T1
Canadian Natural 2020 Annual Report 9,993
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.
Chen, Z. Chen, C. Cheng, J. Cheng, N. Cheng, D. Chenier, N. Cheraghi, Z. Cherniawsky, M. Chernichen, T. Cherry, O. Chervyakova, B. Chester, J. Chester, A. Chesterman, D. Chetcuti,
A. Cheung, I. Cheung, J. Cheung, K. Cheung, W. Cheung, L. Cheveldeaw, B. Cheyne, B. Chhualsingh, F. Chiasson, B. Chichak, K. Chichak, D. Chick, T. Chick, D. Chidley, D. Childs, S.
Childs, A. Chin, S. Chin, Y. Chin, C. Ching, T. Chipiuk, M. Chiplin, A. Chisholm, B. Chisholm, T. Chisholm, T. Chislett, P. Chiu, J. Chohan, D. Choi, J. Cholka, N. Chondropoulos, R. Chong,
B. Chopping, B. Chorney, M. Chorney, C. Chornohos, C. Chorostecki, S. Choudhury, M. Chourio, A. Chow, K. Chow, R. Chowdhury, S. Chowdhury, G. Choy, A. Chretien, B. Christensen,
L. Christensen, R. Christensen, T. Christensen, J. Christian, N. Christian, K. Christiansen, S. Christiansen, D. Christianson, M. Christianson, D. Christie, R. Christie, S. Christie, T.
Christie, J. Chrobot, A. Chu, C. Chua, R. Chubaty, G. Chubbs, D. Chudobiak, V. Chui, H. Chung, H. Church, C. Churchill, D. Churchill, G. Churchill, J. Churchill, N. Churchill, J. Churko,
D. Chute, K. Chychul, O. Chyon, V. Cimon, K. Cisse-Banny, D. Clapperton, 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, T. Clarke, W. Clarke, C. Clarkson, D. Clarkson, W. Clarkson, S. Clavette, J. Clelland, T. Clelland, R. Clemit, R. Clemmer, J. Clevenger, C. Closs,
Z. Closter, A. Clouston, J. Clouter, R. Cloutier, J. Clowater, M. Cnossen, J. Coates, R. Coates, T. Coates, E. Cobaj, C. Cobaleda, D. Coburn, M. Cochet, B. Cochrane, E. Cochrane, J.
Cochrane, D. Cockerill, F. Codd, E. Code, A. Codner, C. Codner, K. Codner, H. Cody, R. Coen, J. Coers, M. Coffin, L. Colborne, M. Colbourne, A. Cole, B. Cole, C. Cole, M. Cole, P.
Cole, J. Coleman, M. Coles, P. Colley, D. Collicutt, M. Collie, B. Collins, J. Collins, M. Collins, O. Collins, R. Collins, S. Collins, C. Collinson, C. Colliou, A. Collison, G. Collison, A. Collyer,
R. Colnar, E. Comeau, R. Comer, K. Compagnon, W. Compagnon, C. Compton, Q. Conacher, E. Connell, M. Connell, M. Connellan, K. Conner, G. Connors, P. Connors, D. Conrad, B.
Conroy, J. Conroy, S. Constant, D. Conway, M. Conway, D. Conybeare, C. Cook, D. Cook, G. Cook, J. Cook, K. Cook, L. Cook, N. Cook, P. Cook, S. Cook, G. Cooke, H. Cooke, J. Cooke,
L. Cooke, A. Cookson, D. Cookson, K. Cookson, L. Cookson, H. Coolidge, J. Coombs, K. Coombs, L. Coonan, L. Cooper, M. Cooper, J. Cooze, R. Copan, C. Copeland, N. Copeland, R.
Copland, R. Coppard, M. Coppola, D. Corbett, N. Corbett, N. Corbiere, F. Corbin, E. Corcoran, J. Corcoran, F. Cordingley, M. Corell, E. Coreman, I. Cormier, S. Cormier, V. Cornejo, D.
Cornish, R. Cornish, S. Correll, C. Corrigan, D. Corrigan, R. Corrigan, D. Corriveau, C. Corry, B. Cortez, P. Corticelli, C. Corzo De Canchica, D. Cosby, G. Cossani, H. Costello, J. Costello,
S. Costello, J. Costigan, B. Cote, C. Cote, E. Cote, J. Cote, A. Cote Simard, E. Cotten, L. Cottreau, L. Coulibaly, S. Coulibaly, D. Coull, J. Courchene, R. Courchesne, J. Courtemanche,
B. Courtney, G. Courtney, T. Courtney, D. Courts, P. Cousin, J. Cousins, M. Cousins, T. Coutney, P. Covell, E. Cowan, B. Cox, G. Cox, J. Cox, R. Cox, E. Cozicor, W. Crabtree, R. Craft,
C. Craig, D. Craig, R. Craig, H. Craigie, K. Cramb, P. Cramb, S. Cramb, S. Cramm, M. Crane, S. Crane, A. Crawford, H. Crawley, J. Crawley, G. Crayford, N. Cressey, L. Cressman, R.
Crichton, P. Crisby, C. Critch, J. Critch, R. Critchard, D. Crittall, A. Critten, W. Crockford, A. Croft, S. Croft, G. Crooks, A. Crosby, D. Crosley, T. Crosley, C. Cross, R. Cross, T. Cross, D.
Crossley, S. Croteau, K. Crouser, T. Crouser, C. Crowe, S. Crowe, D. Crowle, E. Crowley, P. Crozier, D. Crum, L. Cruttenden, J. Cruz, A. Csabay, B. Csatari, S. Cseke, P. Cudak, E.
Cuello, H. Cui, J. Cullen, M. Culligan, E. Cullimore, A. Cunanan, A. Cunningham, D. Cunningham, S. Cunningham, E. Cupac-Cingel, J. Curran, S. Curran, S. Currie, R. Currier, B. Curry,
K. Cusack, M. Cusson, D. Cutler, J. Cutler, S. Cutler, J. Cuu, C. Cyr, D. Cyr, G. Cyr, S. Cyr, J. Cyrenne, D. Cyron, K. Cytko, P. Czajko, J. Czarnecki, M. Czerwinski, R. Czerwony, K.
d’Abadie, V. Daboin, A. Dabrowski, M. Dacillo-Basallajes, F. Dadashov, R. Dadey, M. Dadi, G. Dafoe, J. Dafoe, W. Dagley, C. Dahl, J. Dai, J. Daigle, B. Daignault, P. Dale, D. Dalgarno,
L. Dalgetty-Rouse, H. Dalipe, J. Dallaire, B. Dalley, G. Dalley, M. Dalton, G. Daly, G. Dalziel, R. Damer, D. D’Amour, E. Dana, C. Danaher, A. Danbrook, T. Danbrook, W. Danchak, S.
Daneshmand, J. Daniels, T. Daniels, D. Danilkewich, G. Dann, I. Dantiwala, C. Danyluk, P. Danyluk, D. Daraban, S. Darai, M. D’arcangelo, A. Dareichuk, V. Darel, E. Dargatz, C. Daria,
M. Darling, S. Darrah, D. Das, F. Daub, D. Dave, M. Dave, C. Davey, G. David, L. David, P. David, G. Davidson, 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, S. Davis, T. Davis, E. Davison, P. Davison, D. Dawe, L. Dawe, J. Dawson, R.
Dawyduk, S. Day, T. Day, J. Daye, V. Daze, M. de Chavez, H. de Graaf, R. De Jesus, R. de Jong, R. De Leeuw, B. De Lorenzo, D. De Oliveira, R. de Ruiter, V. de Ruiter, C. de Wit, B.
de Witt, B. Deacon, K. Deacon-Rosamond, I. Deaconu, P. Deagle, A. Dean, M. Dean, R. Dean, A. Dearaway, G. Dearden, C. Deaver, T. Debler, R. Debnath, S. Debnath, D. Deboer, R.
deBoer, W. DeBona, S. DeBruycker, P. DeBusschere, D. Dechaine, J. Dechaine, M. Dechaine, R. Dechaine, P. Dechant, R. Dechesne, B. Decker, D. Decker, J. Decker, R. Decker, J.
Decoeur, D. Decoine, W. Dedam, E. Dee, L. Deep, M. Deering, L. Defoort, S. DeFord, B. DeHaan, A. Deibert, R. DeJong Dyck, B. DeLair, I. Delaney, P. Delany, E. DeLaRonde, J.
Delaurier, A. Delavarmoghaddam, C. Delawski, M. Dell, M. DelMastro, M. DeLorme, R. Demarsh, B. Demirdal, C. DeMone, R. DeMott, G. Dempsey, S. Dempsey, M. Denault, D.
Deneau, G. Denney, S. Dennis, D. Dennison, S. Denny, C. Denslow, J. Dent, L. Depencier, H. Derakhshan, D. Derbyshire, J. deRidder, J. Derix, K. Derkowski, B. Derochie, M. Derry,
A. Desai, C. Desai, D. Desai, G. Desai, R. Desai, S. Desai, M. Deschambeau, T. Deschamps, D. Deschenes, A. Desharnais, V. Deshpande, D. Desjardins, C. Desjardins-Knowlden, G.
Desjardins-Knowlden, C. Desmarais, S. Desmarais, J. Desnoyers, 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, K. Deyaegher, M. Deyan, G. Dhaliwal, H. Dhaliwal, J. Dhaliwal, M. Dhaliwal, P. Dhalwala, B. Dhanesha, K. Dhanoa, J. Dharamsi, M. Dhariwal,
K. Diallo, B. Diamond, L. Diane, D. Diaz, L. Diaz, M. Diaz, A. Dick, R. Dicken, K. Dickey, A. Dicks, E. Dicks, B. Dickson, C. Dickson, G. Dickson, A. Didenko, J. Diederich, S. Dietrich, P.
Diggle, S. Diggle, M. Diiorio, I. Dikau, A. Dillabough, E. Dillabough, R. Dillman, K. Dilts, A. Dimapilis, L. Dimion, X. Ding, Y. Ding, M. Dingley, G. Dingwell, H. Dinn, R. Dinn, K. Dinney,
M. Diomande, S. Dionne, R. Diputado, M. Dirk, S. Dirk, E. Ditzler, A. Dixit, C. Dixon, D. Dixon, R. Dixon, T. Dixon, K. Do, W. Dobchuk, C. Dobek, G. Dobek, L. Dobson, S. Dobson, R.
Docksteader, L. Dodd, R. Dodunski, R. Doering, J. Doetzel, A. Doherty-Snelgrove, J. Doiron, K. Doiron, G. Dolan, P. Dolan, S. Dolhanty, D. Dolynchuk, D. Doma, G. Doma, G. Domalain,
R. Domazet, B. Dombrova, M. Dombrova, D. Domin, K. Donahue, K. Donald, E. Donaldson, S. Donaldson, R. Donaleshen, M. Dong, J. Donohoe, J. Donovan, N. Donovan, J. Doonanco,
S. Dorer, A. Dorey, J. Dorusak, A. Dosanjh, J. Dosman, I. Dosso, M. Doty, M. Doucet, D. Doucette, A. Douglas, J. Douglas, J. Doust, T. Dove, R. Dow, A. Dowd, J. Dowd, J. Dowhay,
P. Downes, A. Downey, D. Downey, J. Downey, P. Downey, A. Downs, R. Doyer, G. Doyle, S. Doyon, R. Drainville, S. Drake, P. Drapeau, G. Draper, K. Draper, T. Draper, W. Draper,
J. Dreaddy, S. Drebit, K. Dreger, C. Drescher, J. Drescher, D. Dressler, C. Drevant, B. Drew, D. Drew, B. Driscoll, S. Driscoll, T. Driscoll, E. Drolet, R. Drolet, R. Drosu, A. Drover, B.
Drover, J. Drover, R. Drover, R. Drummond, C. Drury, D. Drury, S. Dryden, S. Drysdall, H. D’Souza, P. D’Souza, V. D’Souza, C. Du, M. Du, M. Du Preez, P. Duan, C. Duane, C. Duarte,
B. Dube, M. Dube, N. Dube, R. Dube, T. Dube, A. Dubetz, T. Dubie, G. Dubois, J. Dubois, L. DuBois, J. Dubuc, D. Duby, C. Dubyk, M. Ducey, R. Ducey, R. Ducharme, P. Duchesnay,
J. Duchscherer, J. Duczek, P. Duda, L. Dueck, G. Duff, C. Duffett, D. Duffy, K. Duford, E. Dufour, P. Dugay, C. Duggan, D. Duguid, A. Duhaime, A. Dumanowski, J. Dumas, T. Dumba,
O. Dumitrache, Y. Dumont, C. Dunbar, B. Duncan, H. Duncan, J. Duncan, R. Duncan, S. Duncan, D. Dunn, J. Dunn, N. Dunn, P. Dunn, R. Dunn, S. Dunn, J. Dunnigan, C. Dunsmore, J.
Dunsmuir, D. DuPerrier, D. Dupuis, J. Durdle, A. Durham, J. Duris, K. Durocher, B. Dusterhoft, J. Dutchak, J. Duthie, R. Duthie, O. Dutka, N. Duval, R. Duval, M. Dux, C. Duynisveld,
B. Dwyer, C. Dwyer, R. Dwyer, D. Dybala, J. Dybala, A. Dyck, C. Dyck, J. Dyer, L. Dyke, B. Dzirasah, K. Dzwonek, B. Eagle, J. Eagleson, M. Eamer, R. Earl, J. Easthope, B. Eastman,
J. Eastman, J. Easton, K. Eberle, R. Ebuna, G. Ecker, D. Edgington, A. Edmunds, A. Edoukou, A. Edugyan, D. Edwards, J. Edwards, P. Edwards, T. Edwards, T. Eeuwes, S. Effiong, A.
Effray, L. Egeland, R. Eggen, C. Eggleton, A. Egresits, C. Ehalt, C. Ehnes, C. Ehresman, M. Eidet, B. Eitzen, M. Ejo, D. Ekdahl, S. Ekstrom, R. Elaschuk, I. Elgarni, M. Elgarni, M. El-
Harakeh, D. Elia, T. Elias, M. Elias Neira, C. Elkink, K. Elladen, P. Ellingson, B. Elliott, D. Elliott, H. Elliott, J. Elliott, R. Elliott, S. Elliott, T. Elliott, D. Ellis, K. Ellis, R. Ellis, S. Ellis, P. Ellison,
C. Ellsworth, K. Ellsworth, A. Elmobarik, M. Elms, O. El-Sayed, E. Elson, J. Elson, T. Ely, C. Emberley, V. Embleton, H. Emery, G. Emmott, J. Engel, K. Engelking, R. Engler, T. Engler,
J. English, M. Enns, J. Entz, J. Epp, T. Epp, J. Erasmus, S. Erb, D. Ereaut, B. Eresman, D. Eresman, C. Erfle, B. Erickson, J. Erickson, S. Erickson, M. Ernst, P. Ersh, C. Erskine, D.
Ertmoed, W. Esau, P. Escalona, O. Esharefasa, N. Eskandar, G. Eskandari, M. Espejo, L. Espie-Winsor, A. Espindola, M. Espiritu, R. Esslemont, B. Estey, O. Estrada, J. Etcheverry, D.
Etherington, S. Etherington, A. Evans, D. Evans, J. Evans, R. Evans, T. Evans, R. Evasco, K. Evdokimoff, J. Eveleigh, L. Eveleigh, S. Eveleigh, A. Everson, C. Eves, J. Ewald, J. Ewen,
J. Eyma, B. Eyolfson, V. Ezeronye, B. Facco, D. Fader, R. Faechner, B. Fagan, M. Fahad, E. Faichney, S. Fairfield, M. Faiz, S. Fallahi, M. Fallen, Y. Fang, D. Fanning, T. Fanoiki, H. Farah,
S. Farea, S. Farhan, A. Faria, H. Farid, S. Farn, D. Farney, M. Farokhshad, A. Farquhar, D. Farrell, G. Farrell, J. Farrell, T. Farrell, R. Farrer, T. Farrer, D. Farrow, S. Farrow, S. Faruqi, W.
Faryna, B. Fast, R. Fast, S. Fast, A. Faucher, C. Faucher, 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, D. Feland, J. Feland, E. Feldkamp, J. Feldmeier, D. Feller, R. Fells, R. Feltham,
E. Fender, M. Feng, L. Fentie, A. Ferdjallah, K. Ferdous, S. Ferenc, K. Ference, B. Ferguson, C. Ferguson, H. Ferguson, M. Ferguson, R. Ferguson, S. Ferguson, M. Ferhatbegovic, B.
Fernandes, A. Fernandez, E. Fernandez, J. Fernandez, L. Fernandez Exposito, N. Ferrer, M. Ferry, R. Fersch, S. Fetinko, C. Fetter, L. Fetter, D. Fewer, J. Fewer, V. Fiacco, C. Fibke, D.
Fichter, T. Fichter, M. Ficke, C. Ficko, B. Field, C. Field, M. Fielden, J. Fielding, K. Fielding, W. Fielding, B. Fifield, C. Filewych, C. Filgate, 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, E. Finnigan, K. Finnigan, T. Finnigan, C. Fischer, L. Fischer, W. Fischer, J.
Fish, C. Fisher, D. Fisher, B. Fitzgerald, C. Fitzgerald, J. FitzGerald, S. Fitzner, R. Fitzpatrick, S. Fitzpatrick, K. Flack, M. Flahr, C. Flamont, J. Flamont, D. Flannery, B. Fleck, M. Flegel,
A. Fleming, D. Fleming, J. Fleming, P. Fleming, S. Fleming, T. Fleming, N. Flemming, A. Fletcher, J. Fletcher, L. Fletcher, P. Flett, R. Flett, M. Flette, J. Fleury, B. Flier, T. Flight, B.
Flockhart, I. Florea, B. Flottvik, J. Fluney, B. Flynn, C. Flynn, J. Flynn, R. Flynn, S. Flynn, C. Fogal, D. Fokema, S. Foline, E. Follis, R. Folmer, P. Foming, G. Fondjo, Y. Fong, A. Fontaine,
D. Fontaine, G. Fontaine, R. Fontaine, B. Foord, R. Foran, D. Forbes, M. Forbes, D. Forbister, A. Forcade, G. Ford, T. Ford, W. Ford, J. Foreman, B. Forest, C. Forget, L. Forget, D.
Forman, C. Formanek, R. Formanek, T. Fornwald, G. Forrest, B. Forrester, R. Forrester, B. Forrister, J. Forsberg, B. Forshner, K. Forshner, M. Forster, S. Forster, H. Forte, A. Fortier,
C. Fortier, D. Fortin, J. Forward, B. Foss, S. Foss, D. Fosseneuve, B. Foster, C. Foster, D. Foster, J. Foster, K. Foster, R. Foster, S. Foster, D. Fotty, C. Fotur, O. Fouego, A. Fougere,
K. Foulds, R. Foulkes, G. Fountain, J. Fountain, B. Fouracres, H. Fowell, J. Fowler, D. Fox, J. Fox, M. Foxton, S. Foxton, K. Fraboni, S. Fraino, C. Frampton, C. France, R. France, M.
T2
Canadian Natural 2020 Annual Report
Francescone, D. Franche, O. Franchi, D. Francis, N. Franck,
M. Franco, C. Frank, D. 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, J. Frayn, K.
Frazer, C. Freake, B. Frechette, A. Freeman, G. Freeman, M.
Freeman, U. Freiberg, E. Frejoles, J. French, R. French, B.
Frenette, K. Frenzel, J. Frese, K. Freyman, K. Friedrich, D.
Friedt, W. Friend, D. Friesen, F. Friesen, H. Friesen, J.
Friesen, K. Friesen, M. Friesen, N. Friesen, R. Friesen, A.
Frizorguer, D. Frizzell, C. Froc, J. Froc, A. Froh, C. Froude, S.
Froude, A. Fry, T. Fryer, X. Fu, N. Fucile, B. Fudge, C. Fudge,
L. Fudge, R. Fudge, K. Fujimoto, D. Fukushima, W. Fulkerson,
J. Fuller, D. Fung, J. Fung, S. Fung-Yau, C. Funk, K. Funk, R.
Funk, M. Funke, J. Furey, M. Furey, A. Furgiuele, A. Furlong,
L. Furlong, T. Furuya, C. Fuster, A. Fyith, A. Gabr, K.
Gabrielson, D. Gabruck, K. Gadzala, R. Gaetz, N. Gafuik, A.
Gage, J. Gage, C. Gagne, D. Gagne, D. Gagnon, E. Gagnon, 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, S. Gallo, M. Gallon, G.
Galloway, J. Galotta, W. Gamache, B. Gamble, D. Gamblin, C.
Gamboa, L. Gamboa, F. Gan, A. Gandhi, P. Gandhi, V. Gandhi,
J. Ganie, D. Ganske, B. Gantz, V. Gapaz, M. Garbin, A. Garcia,
C. Garcia, A. Garcia Varganova, D. Gardham, K. Gardiner, S.
Gardiner, E. Gardner, S. Gardner, J. Gareau, R. Gareau, T.
Gareau, R. Garg, V. Garg, K. Garland, A. Garneau, W. Garner,
T. Garthwaite, L. Garvey, E. Gashaw, M. Gates, J. Gatrell, S.
Gauchan, C. Gaudet, F. Gaudet, G. Gaudet, W. Gaugler, L.
Gauld, M. Gaulin, N. Gautam, C. Gauthier, D. Gauthier, J.
Gauthier, M. Gauthier, N. Gauthier, P. Gauthier, S. Gauthier, T. Gauthier, K. Gautschi, S. Gavronsky, T. Gaydos, G. Gayton, N. Gazdag, A. Gboko, B. Geall, J. Geddes, D. Geitz, O.
Gelowitz, M. Gemmell, J. Genereux, M. Genereux, C. Geng, G. Genge, B. Gensollen del Barco, P. Gentles, C. George, J. George, M. George, M. Georgescu, R. Georgescu, J. Georget,
S. Geremia, J. Gergely, B. Gerke, G. Gerla, J. Gerlinger, K. Gernat, K. Gerow, S. Gerow, E. Gervais, K. Gervais, M. Gervais, K. Gessner, T. Getchell, S. Getson, K. Getzinger, V.
Ghadamyari, L. Ghasem Rashid, H. Ghazimoradi, M. Ghorbanie, J. Ghosh, E. Ghoubrial, D. Gibb, I. Gibbon, S. Gibbon, E. Gibbs, D. Gibson, J. Giebelhaus, S. Giefer, A. Gierach, C.
Giesbrecht, D. Giesbrecht, E. Giesbrecht, J. Giesbrecht, T. Giesbrecht, J. Gigg, D. Giggs, G. Gilbert, J. Gilbert, C. Giles, M. Giles, S. Giles, T. Giles, V. Giles, J. Gilhang, J. Gill, K. Gill,
L. Gill, M. Gill, N. Gill, R. Gill, S. Gill, J. Gillam, D. Gillan, J. Gillatt, S. Gillespie, M. Gillies, A. Gillingham, D. Gillingham, J. Gillingham, L. Gillingham, S. Gillingham, E. Gillis, E. Gillmore,
M. Gillund, C. Gilman, K. Gilman, E. Gimenez, R. Gimoro, G. Gin, K. Ginter, M. Ginter, K. Ginther, T. Ginther, L. Giraldo, D. Girard, G. Girard, S. Girard, S. Girbav, D. Girouard, J. Girouard,
P. Girouard, B. Gisby, M. Gisondo Crawford, E. Giuliani, D. Gladue, J. Gladue, B. Glaicar, G. Glanville, D. Glasco, A. Glasrud, K. Glavine, M. Glavine, R. Gleasure, J. Glen, J. Glendenning,
G. Glenn, D. Gliddon, D. Gloade, D. Glover, S. Glubish, M. Go, R. Go, J. Godin, B. Godkin, D. Godwin, L. Goerzen, C. Goeson, C. Gogol, J. Gogol, B. Gogowich, H. Goldberg, D. Golden,
E. Goldhart, P. Goldsney, A. Goll, D. Goll, P. Goll, M. Gomaa, R. Goman, C. Gomez, E. Gomez, J. Gomez, C. Gomuwka, E. Gong, K. Gong, M. Gonzales, I. Gonzalez, N. Gonzalez, Y.
Gonzalez, C. Good, P. Good, J. Goodair, A. Goodine, C. Goodman, P. Goodman, W. Goodwin, B. Goodyear, J. Goodyear, R. Gooler, J. Gorai, K. Gordeyko, I. Gordon, J. Gordon, K.
Gordon, L. Gordon, S. Gordon, T. Gordon, J. Gorgichuk, D. Gorrie, J. Gorski, R. Goshi, B. Gosse, D. Gosse, R. Gosse, T. Gosse, Y. Gosselin, B. Gosselink, C. Goudreau, C. Gough, A.
Gould, B. Gould, J. Gould, T. Goulding, C. Goulet, J. Goulet, P. Goulet, J. Gourlie, G. Gouthro, S. Gouthro, J. Gover, A. Goyal, M. Goyal, L. Goymer, J. Graca, R. Graf Jr., L. Graff, J.
Grageda, C. Graham, D. Graham, G. Graham, J. Graham, M. Graham, R. Graham, S. Graham, T. Graham, E. Grandillo, I. Grandy, R. Grandy, B. Granger, J. Granger, A. Grant, C. Grant,
J. Grant, L. Grant, M. Grant, R. Grant, S. Grant, T. Grant, B. Gravel, R. Graveline, R. Gravell, T. Graveson, A. Gray, B. Gray, C. Gray, D. Gray, J. Gray, L. 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, K. Greenwood, M. Greenwood, R. Greenwood, A. Grenier, J. Grenon, J. Greter, A. Grewal, S. Grewal, B. Grice, C. Grice, R. Grice, C. Grieder, R.
Griemann, S. Grier, D. Grieve, R. Grieve, J. Griffin, M. Griffin, P. Griffin, E. Griffiths, J. Griffiths, K. Griffiths, A. Grise, R. Griswold, R. Groenen, A. Groeneveld, M. Grosseth, A. Grossi,
W. Grotkowski, J. Grouchy, B. Grove, P. Grove, L. Groves, D. Grundner, D. Grzela, S. Gu, Y. Guan, V. Guardia-Mendez, C. Guay, D. Guay, C. Gudjonson, C. Gudmundson, S. Gue, P.
Guedez, J. Guerin, D. Guevohe, M. Gueye, D. Guglielmin, A. Guillen, J. Guilmette, K. Guimond, C. Guinup, R. Guinup, A. Guitard, A. Gulamhusein, K. Gulamhusein, R. Gulati, S. Guled,
R. Gulutzan, J. Gumbley, I. Gunning, R. Gunning, A. Gupta, J. Gurba, E. Gushue, J. Gushue, T. Gushue, T. Gusnowski, R. Gussen, C. Gustafson, G. Gustafson, M. Gustafson, J.
Gustavson, P. Gut, M. Gutierrez, R. Gutknecht, J. Gysler, D. Ha, T. Ha, E. Haag, B. Haahr, B. Haas, C. Haas, S. Haas, M. Haberoth, C. Hachey, L. Hachey, K. Hachey-Lalonde, S. Hackett,
E. Hadada, V. Haddad, L. Hadi, T. Hadji, N. Hadskis, S. Haefliger, K. Hagan, S. Hagan, T. Hagen, L. Hagg, A. Hagi-Memet, C. Hagstrom, K. Hague, S. Hahn, J. Haidasz, O. Haight, K.
Haines, A. Haj Hamdan, M. Haj Hamdan, S. Hajar, S. Haji, S. Hajizadeh, S. Halaburda, C. Hales, D. Halewich, K. Halewich, B. Haley, R. Haley, J. Halford, D. Halifax, B. Hall, C. Hall, J.
Hall, M. Hall, R. Hall, S. Hall, S. Halland, S. Hallas, R. Halldorson, G. Hallett, R. Hallock, A. Halvorson, A. Hamad, C. Hambly, B. Hamborg, A. Hameed, K. Hameed, J. Hamel, P. Hamel,
T. Hamel, J. Hamelin, B. Hamer, D. Hamer, S. Hamill, A. Hamilton, D. Hamilton, G. Hamilton, J. Hamilton, K. Hamilton, M. Hamilton, R. Hamilton, T. Hamilton, T. Hamitaj, K. Hamm, A.
Hammami, M. Hammel, S. Hammel, R. Hammer, D. Hammerlindl, K. Hammersley, S. Hammersley, B. Hammond, G. Hammond, M. Hammond, C. Hampton, B. Hamrell, E. Han, G.
Hanas, E. Hancock, M. Hancock, B. Hancott, R. Hanlon, S. Hanlon, E. Hann, R. Hann, B. Hanna, A. Hansen, D. Hansen, J. Hansen, K. Hansen, L. Hansen, R. Hansen, V. Hansen, D.
Hanson, K. Hanson, L. Hanson, R. Hanson, T. Hanson, I. Harb, B. Harbin, C. Harder, L. Harder, C. Harding, P. Harding, G. Hardisty, J. Hardisty, B. Hardy, F. Hardy, H. Hardy, J. Hardy,
A. Hare, A. Hargreaves, E. Harikumar, K. Harke, J. Harker, A. Harlal, D. Harley, E. Haroldson, B. Harpell, J. Harpell, G. Harper, E. Harrietha, R. Harrietha, R. Harriman, A. Harris, B. Harris,
C. Harris, J. Harris, M. Harris, S. Harris, W. Harris, C. Harrison, D. Harrison, N. Harrison, R. Harsany, D. Hart, C. Hartery, C. Hartl, P. Hartwick, A. Harty, J. Harty, A. Harvey, B. Harvey,
D. Harvey, J. Harvey, K. Harvey, P. Harvey, R. Harvey, S. Harvey, M. Hashem, I. Hashi, B. Hassan, I. Hassan, M. Hassan, O. Hassan, R. Hasselmann, B. Hassen, C. Hassenrueck, J.
Hatala, J. Hatcher, G. Hatto, D. Haub, G. Haub, R. Hauger, T. Hauger, B. Haugo, J. Haukeness, W. Hausch, M. Havig, A. Hawco, S. Hawco, T. Hawco, C. Hawkings, D. Hawkins, H.
Hawkins, S. Hawryliw, A. Hawthorne, S. Haxton, N. Hay, D. Hayashi, C. Hayden, E. Hayden, J. Hayden, D. 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. He, K. Head, T. Head, M. Headrick, B. Heagy, C. Heagy, J. Heagy, A. Heale, L. Healy, K. Heard, B. Hearn, B.
Heasley, A. Heath, B. Heath, C. Heath, D. Heath, L. Heath, B. Heatley, D. Heavens, S. Heawood, T. Hebel, B. Hebert, D. Hebert, J. Hebert, M. Hebert, S. Heck, T. Heck, D. Heemeryck,
K. Heffernan, C. Heffner, D. Hefford, C. Hehr, T. Heid, R. Heide, T. Heidebrecht, M. Heigl, R. Hein, J. Heinen, R. Heinrichs, B. Heise, R. Heiz, R. Helland, B. Helliker, R. Hellum, A.
Hellyer, Q. Helm, D. Helms, R. Helyar, C. Hemington, D. Hemmelgarn, W. Hemminger, T. Hempel, B. Hemstock, J. Henderson, R. Henderson, S. Henderson, W. Henderson, E.
Hendrickson, K. Hendrickson, T. Hendriks, S. Hendry, K. Hennessey, A. Hennig, E. Henriquez, C. Henry, H. Henschel, D. Herauf, K. Herba, C. Herbst, W. Hergott, B. Herman, D.
Herman, W. Herman, A. Hernandez, E. Hernandez, G. Hernandez, M. Hernandez, P. Hernandez, G. Herrebout, C. Herring, R. Herrington, D. Hertzsprung, M. Herzog, D. Heshka, R.
Heska, A. Hess, B. Hess, M. Hessenbruch, B. Heugh, A. Heuthorst, J. Hevey, J. Hewitt, K. Hewitt, M. Hewitt, T. Hewitt, T. Hewko, J. Hewlett, K. Hewlin, A. Heydari Gorji, C. Heywood,
R. Hibbs, D. Hicke, M. Hickey, P. Hickey, R. Hickey, B. Hicks, R. Hicks, 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, C. Hill, D. Hill, H. Hill, J. Hill,
K. Hill, T. Hill, D. Hillier, J. Hillier, M. Hillier, R. Hillier, S. Hillier,
C. Hills, T. Hills, D. Hillyard, T. Hilsendager, R. Hilton, B.
Hindmarch, K. Hingley, W. Hinkle, T. Hinks, K. Hinton, N. Hinze,
M. Hird, K. Hirsch, D. Hiscock, S. Hiscock, F. Hiscox, D. Hitra,
G. Ho, J. Ho, M. Ho, T. Ho, J. Hoare, W. Hobart, A. Hobbi, J.
Hobbs, P. Hocaloski, R. Hoda, C. Hodder, G. Hodder, J. Hodder,
O. Hodder, D. Hodge, R. Hodgins, D. Hodgson, A. Hoeg, C.
Hoeppner, A. Hoey, N. Hoey, M. Hoffart, L. Hoffman, R.
Hoffman, M. Hofstrand, G. Hogan, S. Hogan, A. Hogg, M.
Hogg, R. Hogg, B. Holaki, J. Holben, D. Holik, K. Holladay, A.
Holland, K. Holland, M. Holland, C. Hollands, I. Hollenbeck, P.
Hollett, D. Holley, D. Hollingshead, G. Holloway, J. Holloway, L.
Holloway, J. Hollowell, C. Holman, D. Holman, R. Holman, J.
Holmes, K. Holmes, M. Holmes, T. Holmes, M. Holt, B. Holthe,
C. Holthe, J. Holton, J. Holuk, D. Holwell, A. Holz, J. Holz, G.
Homann, D. Honing, C. Hood, D. Hood, J. Hood, G. Hook, J.
Hook, J. Hooper, R. Hooper, S. Hopkins, Y. Hopkins, N. Hopner,
M. Hopp, C. Hopps, T. Hopwood, A. Hordy, R. Horn, T.
Hornberger, Z. Horne, A. Hornseth, K. Hornseth, B. Horobec, K.
Horvath, R. Horvath, J. Horyn, K. Hosker, B. Hossain, M.
Hossain, S. Hosseini, A. Hosseinpoor, T. Hou, S. Houck, L.
Houghton, E. Houlihan, A. House, G. House, P. House, R.
House, T. House, L. Houseman, K. Hovdebo, T. Howard, C.
Howden, L. Howell, K. Howes, P. Howie, S. Howlader, J.
Howse, M. Hoyles, T. Hoyles, R. Hoyt, B. Hoza, J. Hripko, D.
Hrycak, T. Hrycay, B. Hryniw, A. Hrynkevych, R. Hrynyk, J. Hu,
M. Hu, T. Hu, Y. Hu, D. Huang, J. Huang, N. Huang, Q. Huang,
G. Huber, R. Huber, W. Hubert, C. Huber-Yau, S. Hucal, J.
Hucik, T. Huckabone, K. Huculak, W. Huddlestun, A. Hudkins,
A. Hudson, D. Hudson, L. Hudson, P. Hudson, S. Huebner, K.
Huey, V. Huey, J. Huffman, B. Hughes, D. Hughes, J. Hughes,
T3
Canadian Natural 2020 Annual Report E. Huh, K. Hui, R. Hui, M. Hulan, C. Hulbert, D. Hull, F. Hulme,
M. Human, R. Humphrey, J. Humphreys, A. Humphries, C.
Humphries, S. Humphries, T. Humphries, I. Hundeby, M.
Hundessa, M. Hung, C. Hunt, D. Hunt, M. Hunt, B. Hunter, C.
Hunter, D. Hunter, K. Hunter, L. Hunter, P. Hunter, R. Hunter, S.
Hunter, W. Hunter, M. Hupchuk, K. Hupp, J. Hurd, K. Hurd, C.
Hurford, G. Hurley, S. Hurley, R. Hurtado, R. Hurtubise, N.
Husain, A. Hussain, S. Hussaini, G. Hussey, C. Hussynec, T.
Hustad, A. Hutchinson, C. Hutchinson, D. Hutchinson, R.
Hutchinson, C. Hutchison, R. Hutscal, E. Hutton, A. Huynh, M.
Huys, S. Hwang, S. Hyatt, K. Hygard, A. Hymanyk, A. Hynes, D.
Hynes, E. Hynes, J. Hynes, K. Hynes, M. Hynes, N. Hynes, S.
Hyrcha, G. Iannattone, L. Iannattone, R. Ibbotson, K. Ibrahim, S.
Ibrahim, T. Idler, G. Iervella, N. Ilchuk, R. Imankulov, D. Imbeau,
E. Imbery, W. Imeson, K. Imlach, M. Imran, S. Imrie, J. Inch, R.
Inder, C. Inglis, J. Inglis, R. Inglis, E. Ingram, G. Ingram, C.
Inkster, B. Inman, C. Innes, M. Inscho, D. Ip, M. Ippolito, M.
Iqbal, R. Irani, J. Ireland, R. Ireton, M. Irfan, J. Irons, K. Ironstand,
R. Irvine, S. Irwin, J. Isaacs, C. Isaka, C. Isea Natera, B. Ish, H.
Ishaque, U. Islam, O. Issa, J. Ivanova, B. Ivany, L. Iversen, C.
Ives, J. Ivezic, C. Jabusch, M. Jackman, B. Jackson, D. Jackson,
G. Jackson, J. Jackson, K. Jackson, R. Jackson, S. Jackson, T.
Jackson, J. Jacob, S. Jacob, C. Jacobs, J. Jacobs, K. Jacobs, M.
Jacobs, K. Jacobson, A. Jacques, A. Jacula, C. Jacula, M.
Jacula, D. Jaeger, A. Jaffer, H. Jaggard, M. Jahangiri, R.
Jahanshahi, V. Jain, M. Jaindl, K. Jaji, R. Jakher, R. Jakubowski,
H. Jalali, M. Jalali, G. Jaleel, M. Jama, S. Jamam, D. Jaman, T.
Jaman, A. Jambrosic, D. James, T. James, W. James, J.
Jamieson, M. Jamieson, R. Jamieson, S. Jamieson, T.
Jamieson, D. Jamilano Jr., A. Janes, D. Janes, J. Janes, Z.
Janosova-Den Boer, S. Jansky, T. Janusc, A. Janzen, L. Janzen,
M. Janzen, L. Jardie, C. Jardine, J. Jardine, S. Jardine, N.
Jaricha, C. Jarocki, C. Jarratt, B. Jarvis, J. Jarvis, K. Jarvis, K. Jaschke, S. Jaume, K. Jay, M. Jay-Rivas, N. Jeang, J. Jechow, W. Jellison, G. Jenkins, J. Jenkins, T. Jenkins, R. Jenner,
R. Jenniex, S. Jenniex, D. Jennings, A. Jensen, B. Jensen, D. Jensen, K. Jensen, L. Jensen, Q. Jensen, R. Jensen, T. Jensen, V. Jensen, D. Jerkovic, M. Jeroncic, R. Jeronymo, T.
Jervis, C. Jesso, M. Jesso, T. Jessome, J. Jesson, S. Jevne, M. Jewel, C. Jezowski, N. Jiang, S. Jiang, Y. Jiang, Z. Jiang, R. Jimeno, X. Jing, P. Jingar, N. Jivani, K. Jivraj, R. Jivraj, D.
Joa, M. Joarder, P. Jobin, N. Jobson, J. Jocksch, D. Jodoin, L. Jodoin, G. Joe, J. Joffre, G. Johal, I. Johanson, K. Johansson, T. Johns, A. Johnson, B. Johnson, C. Johnson, D. Johnson,
G. Johnson, I. Johnson, J. Johnson, K. Johnson, M. Johnson, N. Johnson, R. Johnson, S. Johnson, T. Johnson, A. Johnston, D. Johnston, H. Johnston, M. Johnston, N. Johnston, R.
Johnston, C. Johnstone, G. Johnstone, S. Johnstone, D. Johnston-Watson, J. Jonasson, A. Jones, B. Jones, C. Jones, D. Jones, E. Jones, G. Jones, K. Jones, L. Jones, M. Jones, N.
Jones, R. Jones, V. Jones, N. Jongkind, P. Joo, J. Jorawsky, D. Jordan, M. Jordan, B. Jorgensen, C. Jorgensen, D. Jorgensen, M. Jorgensen, L. Jorgenson Donahue, D. Joseph, P.
Joseph, A. Jose-Sadzius, A. Joshi, H. Joshi, T. Joshi, U. Joshi, S. Joshua, S. Josselyn, R. Jost, M. Jovic, D. Jowsey, L. Joy, M. Juanerio, R. Jubinville, T. Juett, A. Juhasz, K. Juhasz,
A. Junaid, J. Jung, S. Jung, C. Jungen, R. Jungkind, G. Junio, C. Jurgenliemk, K. Jurouloff, T. Kabyn, A. Kachra, C. Kada, T. Kadi, T. Kadikoff, L. Kadutski, C. Kaglea, A. Kaid, M. Kaid,
G. Kailas, K. Kajorinne, H. Kakadiya, M. Kakooei, S. Kalbag, V. Kalbag, O. Kalinchuk, L. Kalinin, D. Kalinowski, J. Kallis, A. Kalmet, D. Kalynchuk, A. Kamate, B. Kamath, E. Kambylis, A.
Kamieniak, A. Kamke, G. Kamon, S. Kanarek, A. Kandasamy, S. Kandulva Chakrapany, J. Kane, L. Kane, R. Kane, S. Kane, K. Kang, N. Kang, Z. Kanji, J. Kanzig, P. Kapadia, S. Kapeluck,
M. Kapp, Y. Karayan Moosafi, P. Karimi, R. Karlowsky, J. Karlson, S. Karlstrom, S. Karmakar, T. Karnes, C. Karpan, M. Karpan, C. Karpiak, K. Kartushyn, P. Karval, D. Kary, U. Karymbaev,
E. Kasatkin, N. Kashirina, C. Kaskiw, M. Kaspers, L. Kassapian, A. Katebi, M. Kathan, D. Katnick, H. Katrip, A. Katyayan, J. Kaufman, M. Kaur, S. Kaur, S. Kaushik, T. Kavalec, J. Kavanagh,
T. Kawadza, K. Kay, O. Kay, G. Kaya, L. Kayyali, G. Kazimirowich, D. Ke, M. Kealey, R. Kean, J. Kearley, M. Kearley, R. Kearns, K. Keating, F. Kebede, M. Keck, B. Keddie, R. Keddie, A.
Keebler, C. Keehn, T. Keenan, P. Keglowitsch, P. Kehler, C. Keil, G. Keith, J. Kelenc, F. Keller, K. Keller, C. Kelley, E. Kellough, J. Kelloway, M. Kelloway, R. Kelloway, C. Kellsey, C.
Kelly, J. Kelly, M. Kelly, P. Kelly, S. Kelsey, T. Kemmer, G. Kemp, L. Kempe, S. Kempner, J. Kempton, R. Kendall, S. Kendall, C. Kendell, D. Kendell, R. Kendell, M. Kendrick, D. Kendze,
B. Kennedy, G. Kennedy, J. Kennedy, K. Kennedy, M. Kennedy, R. Kennedy, S. Kennedy, W. Kennedy, J. Kenny, R. Kenny, L. Kenstavicius, D. Kent, M. Kent, S. Kent, V. Kenyon, K.
Keough, S. Kermanshachi, S. Kernachan, C. Kerpan, J. Kerr, S. Kerr, S. Kers, D. Ketchum, D. Kett, B. Kevol, I. Khabarova, M. Khalil, T. Khambalkar, A. Khan, F. Khan, G. Khan, M. Khan,
S. Khan, N. Khatri, R. Khatri, J. Kho, F. Khodayari, S. Khong, S. Kiasosua, I. Kidd, R. Kidd, D. Kidger, B. Kidmose, B. Kiedyk, C. Kiehn, K. Kieley, C. Kilback, D. Kilbreath, M. Kilcollins, C.
Killick, O. Kilo, B. Kim, H. Kim, C. Kimler, D. Kimmie, M. Kinden, B. King, C. King, D. King, G. King, I. King, J. King, M. King, N. King, R. King, T. King, W. King, R. Kingcott, T. Kingsbury,
K. Kinnaird, S. Kinnear, C. Kinniburgh, P. Kip, B. Kirby-Graham, T. Kirchner, M. Kireev, T. Kirilo, D. Kirkham, L. Kirkpatrick, M. Kirkwood, A. Kiss, B. Kiss, B. Kissel, M. Kissoon, G.
Kjelshus, T. Kjemhus, J. Klaffl, J. Klapstein, D. Klassen, J. Klassen, R. Klassen, C. Klatt, D. Klause, R. Klautt, B. Klenk, R. Klimek, M. Klimkiewicz, E. Klitiris, J. Klotz, G. Kluthe, C.
Knapper, R. Knee, S. Knelsen, W. Knelson, R. Kneteman, M. Kniebel, G. Knight, J. Knight, R. Knight, J. Knight-Ehiwe, J. Knipe, L. Knoblauch, D. Knoblich, B. Knopf, D. Knott, W. Knouse,
J. Knox, K. Knox, P. Knull, M. Kobelka, D. Kobes, B. Kobzey, B. Koch, M. Koch, E. Kodjo Gaba, R. Koenig, K. Koffi, L. Koffi, S. Koffi, C. Kohls, B. Kohrs, J. Kohut, B. Koizumi, C. Kolberg,
M. Kolenchuk, M. Kolesnikov, D. Kolundzic, B. Koma, C. Komant, M. Komant, S. Kompally, M. Kondor, B. Kondratowicz, B. Kone, L. Kone, V. Kone, Y. Kone, L. Kong, D. Konowalec,
M. Konschuh, E. Kontuk, B. Kootenay, R. Kootnekoff, S. Korchagin, M. Koren, P. Kornacki, B. Korolischuk, C. Koroluk, D. Korrey, J. Kosanovich, A. Kosasih, I. Koshcheev, D. Kosinski,
J. Kosior, B. Kosowan, V. Kostic, K. Kostrub, B. Kotchi, K. Kotkas, M. Kotty, D. Kotze, M. Koua, P. Kouadio, A. Kouakou, D. Kouame, A. Kouassi, H. Kouassi, G. Koumba Lendoye, A.
Kourbaj, M. Koutou, B. Kovacs, S. Kovacs, R. Kovalenko, R. Kovasin, M. Kowalchuk, J. Kowalewski, R. Kowalski, K. Kowbel, R. Kowbel, M. Kozak, E. Kozakevich, G. Kozakevich, T.
Kozina, A. Kozler, A. Kozlowski, B. Kozuback, D. Krajci, B. Kraljic, J. Kramers, K. Kramps, R. Kranitz, T. Kratz, W. Kraus, G. Krause, R. Krauss, R. Kravitz, B. Krawchuk, C. Krawchuk, D.
Krawec, J. Krawetz, M. Krawetz, J. Kreft, T. Kreics, M. Kreiser, B. Krell, J. Krenbrink, B. Kress, K. Krewulak, A. Krishnamoorthy, R. Krishnamurthy, D. Krismer, B. Kristianson, K.
Kristman, N. Krochmal, R. Kroeker, K. Krogh, P. Krol, R. Krueger, G. Kruger, K. Kruger, G. Kruk, N. Krupka, N. Krush, T. Krushel, R. Ku, C. Kubik, C. Kucinar, G. Kucy, J. Kuhberg, M.
Kulkarni, C. Kully, B. Kumar, P. Kumar, R. Kumar, S. Kumar, C. Kung, D. Kunitz, J. Kunka, J. Kuntz, P. Kuppers, S. Kurczaba, D. Kurek, M. Kureshi, M. Kurowski, K. Kurschenska, D.
Kurtz, K. Kurtz, R. Kurtz, F. Kurucz, G. Kushe, D. Kusmiadji, B. Kutash, K. Kuzevanova, F. Kuzmic, C. Kwan, K. Kwan, R. Kwiatkowski, S. Kwiatkowski, V. Kwiatkowski, A. Kwon, J.
Kwong, T. Ky, J. Kyes, K. Kyffin, D. Kyle, J. Kynock, R. Kynock, T. La Grange, D. Labby, J. LaBossiere, J. Laboucan, R. Laboucan, D. Labrecque, T. Lacey, A. LaChance, N. Lachance,
S. Lachance, J. Lacharite, K. Lacombe, R. Lacombe, P. Lacoste-Bouchet, D. Lacroix, M. Lacroix, S. Lacroix, L. Lacuna, A. Laderoute, K. Ladji, K. Lafferty, S. Lafond, D. Lafontaine, R.
Laforge, D. Lafreniere, L. Lafreniere, G. Lagace, M. Lagimodiere, A. Laguduva, M. Laha, B. Lahoda, D. Lahoda, J. Lahoda, C. Lai, R. Lai, S. Lai, E. Laidlaw, A. Laing, R. Laing, S. Laird,
M. Lake, J. Lakes, K. Lal, P. Lalani, J. Laliberte, P. Lalonde, C. Lam, E. Lam, I. Lam, J. Lam, M. Lam, N. Lam, R. Lam, S. Lam, K. Lamb, T. Lamb, Z. Lamba, D. Lambert, E. Lambert, J.
Lambert, D. Lameman, T. Laminski, J. Lamontagne, R.
Lamontagne, J. Lamoureux, T. Lamoureux, W.
Lamoureux, W. Lamptey, A. Landry, E. Landry, G.
Landry, J. Landry, L. Landry, M. Landry, S. Landry, Y.
Landry, X. Landry-Pellerin, W. Landsburg, B. Lane, M.
Lane, S. Lane, W. Lane, R. Lanfranchi, J. Langdon, K.
Langdon, G. Lange, L. Lange, N. Lange, O. Lange, S.
Lange, S. Langford, W. Langford, T. Langill, J.
Langman, C. Langpap, K. Langworthy, B. Lanh, R.
Laniec, C. Lanthier, L. Lanza, S. Lanza, C. Lapp, C.
Lappin, M. Larade, G. Laramee, G. Lardner, S. Larkam,
J. Larkin, J. Larochelle, A. Larocque, J. Larocque, G.
Larrivee, R. Larsen, J. Larson, L. Larson, P. Larson, R.
Larson, B. Larsson, A. Laser, J. LaSha Pool, M. Laslo,
C. Lassey, W. Latchuk, A. Latif, Z. Latif, C. Latimer, M.
LaTorre, P. Latus, J. Lau, S. Lau, L. Laube, A. Lauder,
B. Laughlin, P. Laughman, K. Laurin, M. Lausen, R.
Lauze, J. Lauzon, D. Laventure, K. Laverty, P. Lavery,
B. Lavigne, J. Lavigne, C. Lavoie, Y. Law, P. Lawless,
S. Lawlor, B. Lawrence, D. Lawrence, E. Lawrence, L.
Lawrence, R. Lawrence, S. Lawrence, W. Lawrence,
Y. Lawrence, R. Lawrie, G. Lawson, J. Laya, C. Layes,
K. Layland, P. Layland, T. Layland, S. Layton, K. Layug,
G. Lazaruk, L. Le, M. Le, N. Le, T. Le, R. Le Manne, B.
Leach, T. Leach, R. Leahy, C. Leamon, K. Leamon, L.
Leamon, A. Leather, M. Lebas, C. LeBlanc, E. LeBlanc,
J. Leblanc, R. Leblanc, T. Leblanc, W. LeBlanc, C.
Lebrun, S. LeBrun, S. Lebsack, S. Leclair, G. Ledger, C.
Ledrew, A. Lee, C. Lee, D. Lee, J. Lee, K. Lee, L. Lee,
M. Lee, R. Lee, S. Lee, T. Lee, B. Leeman, M. Lefaivre,
G. Lefebure, D. Lefebvre, S. Lefebvre, M. LeForte, D.
Legault, K. Legault, J. Legere, P. Legere, M. Legge, M.
LeGrow, K. Lehal, B. Lehbauer, C. Lehmann, M.
Lehouillier, S. Lei, T. Leibel, P. Leier, M. Leitch, S.
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T4
Canadian Natural 2020 Annual Report T. Lemon, P. Leniuk, P. Lennon, C. Lenz, S. Lenz, J. Lenzner, T. Leon, C. Leong, G. Leong, H. Leong,
K. Lepage, T. LePage, S. Lepine, S. Lepp, L. Leppaie, P. Lepper, Y. Lerner, C. Leroux, E. Leroy, C.
Leschinski, T. Lesko, R. Leslie, S. Lester, B. Lesyk, C. Lesyk, K. Letby, M. Lethaby, F. Letkeman, P.
Letkeman, T. Letkeman, A. Letourneau, M. Letourneau, H. Lett, A. Leung, D. Leung, J. Leung, K.
Leung, M. Leung, P. Leung, R. Leung, Y. Leung, J. Levac, J. Levesque, R. Levesque, S. Lewchuk,
C. Lewis, D. Lewis, J. Lewis, K. Lewis, P. Lewis, T. Lewis, W. Lewis, R. Lewiski, W. Leyland, N.
L’Heureux, J. L’Hirondelle, B. Li, H. Li, J. Li, Q. Li, S. Li, W. Li, Y. Li, B. Liang, S. Liao, C. Liba, P.
Libari, M. Liber, N. Liegman, H. Lien, S. Lien, C. Lieverse, J. Lieverse, D. Lightburn, A. Likhar, D.
Lilburn, H. Lim, M. Lim, F. Lin, H. Lin, J. Lin, Q. Lin, Y. Lin, K. Linaker, B. Lind, S. Lindballe, K. Linder,
T. Lindley, G. Lindner, E. Lindsay, D. Lindskog, A. Linggon, D. Link, P. Linklater, N. Linnell, J. Linton,
M. Liou-McKinstry, R. Liske, C. Little, G. Little, J. Little, S. Little, J. Littlechilds, C. Litwin, H. Liu, J.
Liu, L. Liu, M. Liu, T. Liu, W. Liu, X. Liu, Y. Liu, J. Liu Prest, E. Liv, J. Lively, J. Livingston, K.
Livingston, R. Livingston, S. Livingstone, C. Lizee, J. Llanos, R. Lloy, M. Lloyd, R. Lloyd, A. Lobban,
A. Lobbes, G. Lobdell, J. Lochansky, F. Locke, R. Locke, T. Locke, A. Lockhart, N. Lockhart, R.
Lockhart, C. Loder, J. Lodoen, K. Loewen, S. Loewen, C. Lofstrom, C. Logan, R. Logan, S. Logan,
D. Loggie, R. Logozar, R. Loke, J. Lomada, D. Londo, C. Long, D. Long, Y. Long, S. Longman, S.
Longson, C. Longston, I. Lonsbury, K. Loo, K. Lopez, J. Lopez Sanchez, D. Lord, N. Lord, C.
Lorenson, N. Lorentz, T. Lorenz, J. Lorette, K. Lorette, M. Lorincz, B. Lorinczy, M. Loring, K. Lorteau,
M. Loshny, M. Lotfi, J. Lotito, T. Lougheed, A. Loughran, E. Louie, L. Louie, S. Lourido, J. Louw, C.
Love, M. Love, D. Loveless, J. Loveless, W. Loveless, I. Lovera-Figueroa, M. Lovestrom, E. Lovmo,
N. Low, C. Lowe, D. Lowe, C. Lowen, J. Lowen, K. Loyer, L. Loyola, E. Lozano, C. Lozinski-Kumpula,
A. Lu, J. Lu, M. Lu, G. Lucas, I. Lucas, J. Lucas, B. Lucy, E. Ludwig, S. Lui, L. Luiken, C. Luk, K. Luk,
K. Lukan, L. Lukey, H. Lund, W. Lundell, K. Lundrigan, E. Lunn, R. Lunn, J. Lunt, C. Lunzmann, X.
Luo, M. Lupul, B. Lush, J. Lush, R. Lusk, A. Lussier, K. Lussier, C. Lutsch, D. Lutwick, J. Lutyck, K.
Lutz, A. Ly, K. Lyall, T. Lychuk, G. Lykidis, D. Lynch, L. Lynch, R. Lynett, M. Lynn, M. Lyon, W. Lyon,
N. Lyons, R. Lyric, D. Lysak, H. Ma, V. Ma, N. Maawia, M. MacBeth, L. MacCallum, K. MacComish,
M. MacConnell, L. Macdaid, A. MacDonald, C. MacDonald, D. Macdonald, J. MacDonald, L.
MacDonald, M. MacDonald, P. MacDonald, R. Macdonald, T. MacDonald, W. MacDonald, G.
MacDonell, A. MacDougall, J. MacDougall, M. MacDougall, S. MacDougall, T. Macdougall-Sinclair,
C. MacEachern, J. MacEachern, L. MacEachern, M. MacEachern, T. MacEachern, Y. Macedo, C.
MacFarlane, M. Macfarlane, K. MacGillis, A. Macgillivray, D. MacGregor, G. MacGregor, K. Machado
Rodriguez, S. MacHale, R. Maciborski, J. Maciejewski, T. Macijuk, A. MacInnis, B. MacInnis, S.
MacInnis, L. MacIntosh, J. MacIntyre, T. Macintyre, A. Mack, C. Mack, L. Mack, S. Mack, B.
MacKay, C. Mackay, G. MacKay, K. Mackay, L. Mackay, M. MacKay, S. MacKay, R. Mackelvie, A.
MacKenzie, C. Mackenzie, D. Mackenzie, K. MacKenzie, M. MacKenzie, S. MacKenzie, T. Mackenzie,
V. MacKenzie, B. MacKey, P. Mackey, S. Mackey, T. Mackey, M. Mackie, A. MacKinnon, B.
MacKinnon, J. MacKinnon, K. MacKinnon, T. MacKinnon, P. Mackintosh, N. Macklin, T. MacLaren, B. Maclean, C. MacLean, E. MacLean, K. MacLean, M. MacLean, R. MacLean, A.
MacLellan, D. Maclellan, G. MacLellan, M. MacLellan, J. MacLennan, A. MacLeod, I. MacLeod, J. MacLeod, L. MacLeod, M. MacLeod, T. MacLeod, W. MacLeod, N. MacMillan, S.
Macmullin, A. Macneil, B. MacNeil, C. Macneil, J. Macneil, A. MacNiven, W. MacPherson, B. MacPhie, H. Macrae, M. MacRitchie, E. MacVicar, T. MacVicar, B. Macwilliams, C.
Madadi, A. Madhukar, H. Madi, R. Madigan, C. Madill, H. Madlung, D. Madoche, G. Madsen, L. Madsen, M. Maennchen, L. Maga, D. Maganga, J. Magbanua, D. Magee, B. Mageza,
S. Magill, C. Magnan, D. Magnusson, M. Magnusson, J. Magpali, A. Magro, V. Magsila, D. Magson, R. Maguet, D. Mah, M. Mah, R. Mah, N. Mahar, K. Mahboobi, Z. Mahe, A. Maida,
T. Mailandt, M. Mailhot, D. Maillet, E. Maillet, J. Maillet, P. Mailloux, R. Mailman, J. Mainville, R. Mairena, B. Maisey, D. Maisey, S. Majdnia, J. Majeau, A. Majidi, P. Major, J.
Makahnouk, M. Makhoul, D. Makin, M. Makin, L. Makowichuk, G. Makumbe, A. Malabad, D. Malabad, E. Malabad, J. Malazdrewicz, S. Malcolm, H. Maldonado, M. Malech, P.
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Malyshev, S. Mamedov, F. Manangu, D. Manarang, M. Manderscheid, D. Mandley, D. Manengyao, L. Manfredi, J. Manful, J. Mangrove, M. Manhera, T. Manji, E. Mankowski, D. Mann,
G. Mann, K. Mann, R. Mann, S. Mann, J. Manning, K. Manolov, J. Mansfield, D. Manshanden, R. Mantei, A. Manthorne, E. Mantilla, G. Manuel, J. Manuel, G. Manuel-Goodyear, L.
Manzano Weffer, H. Maralli, N. Maralli, D. Marazzo, G. Marceau, A. Marcel, L. Marchand, N. Marchand, F. Marchesan, M. Marchi, R. Marcichiw, A. Marcinkoski, T. Marcotte, L.
Marcucci, N. Marcy, J. Margetson, W. Margison, 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, K. Marriner, R. Marrington, C. Marriott, A. Marsh, B. Marsh, M. Marsh, P. Marsh, C. Marshall, D. Marshall, G. Marshall, S. Marshall, J.
Marston, A. Martakoush, P. Martell, D. Martens, S. Martens, B. Martin, C. Martin, D. Martin, J. Martin, K. Martin, M. Martin, S. Martin, T. Martin, D. Martinat, S. Martin-Courtright, S.
Martinella, M. Martinez, Z. Martinez, D. Martinez Gomez, O. Martis, D. Martyn, R. Martyn, M. Martynuik, A. Martyshuk, M. Martyshuk, J. Maruniak, K. Mashayekh, R. Maskoni, B.
Mason, C. Mason, K. Mason, R. Mason, D. Massey, M. Massiah, K. Massick, A. Massicotte, P. Massicotte, M. Mata, A. Matatko, T. Matatko, A. Matchem, H. Mateen, D. Mathers, D.
Matheson, E. Matheson, L. Matheson, S. Matheson, T. Matheson, A. Mathew, L. Mathew, D. Mathieson, F. Mathieson, C. Mathiot, J. Matkowski, B. Matsalla, N. Matsushita, A.
Matthews, B. Matthews, C. Matthews, D. Matthews, E. Matthews, N. Matthews, J. Matthiessen, R. Matychuk, P. Maurice, S. Maurice, A. Maurier, N. Mavani, D. Mavridis, A. Mawer,
V. Maximo, C. Maxsom, J. Maxwell, R. Maxwell, K. May, R. May, C. Maye, F. Mayell, J. Mayer, S. Mayer, R. Mayers, A. Maynard, W. Maynard, A. Mayo, B. Mayo, C. Mays, A. Mazur,
C. Mazuryk, H. Mc Gee, D. McAlister, C. Mcallister, D. McAllister, J. McAllister, M. McAlpine, D. McArthur, K. Mcarthur, E. McAvoy, N. McBain, D. McBrearty, K. McBride, R. McBrien,
G. McCabe, T. McCabe, S. McCaffrey, R. McCallum, S. McCann, D. McCarry, J. McCarthy, J. McCarty, K. McClary, D. McClelland, I. McClelland, B. McClure, J. Mcclyment, B.
McConachie, C. McConnell, M. McCormack, C. Mccoy, S. McCracken, B. McCrady, K. McCrae, C. McCrea, G. McCrea, J. McCrea, J. Mccready, S. McCreery, G. Mccubbing, B.
McCullagh, B. McCullough, C. McCullough, D. McCullough, E. McCullough, R. McCullough, A. McDaniel, C. McDonald, D. McDonald, J. McDonald, K. McDonald, T. McDonald, L.
McDonnell, K. McDougall, M. McDougall, S. McDougall, J. McDowell, R. McEachnie, M. McElroy, N. McElroy, J. McEwen, W. McEwen, J. Mcfarland, M. McFarlane, B. McFaul, L.
McFeeters, M. McGannon, F. McGaw, L. McGean, D. McGee, L. McGee, P. McGinnis, G. Mcgonigal, C. McGovern, G. McGowan, A. McGrath, C. McGrath, D. Mcgrath, K. Mcgrath,
L. McGrath, M. McGrath, T. McGrath, S. McGregor, T. McGregor, S. McHardy, L. McHugh, D. McIlvaney, A. McIntosh, G. McIntosh, M. Mcintosh, W. McIntosh, C. McIntyre, P.
McIntyre, R. McIntyre, C. McIver, T. McKague, B. Mckay, C. McKay, J. McKay, K. McKay, L. McKay, N. McKay, R. McKay, S. McKay, T. McKay, N. McKeachnie, T. McKee, W. McKellar,
N. McKendry, M. McKenna, P. McKenna, T. McKenna, B. McKenzie, K.
McKenzie, M. McKenzie, R. McKenzie, D. Mckersie, H. McKiel, C.
McKim, S. McKinney, A. McKinnon, J. Mckinnon, K. Mckinnon, S.
McKinnon, R. McLachlen, M. McLane, C. McLaren, D. McLaren, M.
McLaren, H. McLarty, S. McLaughlan, T. Mclaughlan, K. McLaughlin,
R. McLaughlin, K. McLean, M. McLean, N. McLean, R. McLean, W.
Mclean, A. McLellan, B. McLellan, C. McLellan, J. McLellan, K.
McLellan, T. McLellan, C. McLenaghan, M. McLenehan, G. McLennan,
C. McLeod, D. McLeod, I. McLeod, M. McLeod, S. McLeod, T.
McLeod, P. Mcloughlin, G. McMahon, L. McMahon, K. McMann, N.
McManus, J. McMaster, R. McMaster, S. McMichael, J. McMillan, R.
McNabb, R. McNair, D. McNamara, K. McNaughton, R. McNaughton,
M. McNay, D. McNeil, H. McNeil, K. McNeil, M. McNeil, P. McNeil, R.
McNeil, T. McNelly, L. McPhee, R. McPhee, J. McPherson, K.
McPherson, J. McQuade, C. McQuaker, A. McQueen, E. McQueen, J.
McQueen, C. McQuiggin, L. McQuiston, K. McRae, R. McRae, A.
McSharry, J. McTamney, B. McTavish, T. McTavish, C. McWhan, C.
McWhinnie, M. Meade, D. Meador, B. Meadus, P. Meadus, S.
Meagher, M. Meckelborg, M. Medhurst, I. Medina, N. Medina, D.
Medlicott Lymburner, B. Medway, J. Meeks, K. Meh, M. Mehaney, F.
Mehdiyev, N. Mehta, V. Mehta, D. Meier, C. Mejia, J. Mejia, B.
Melanson, D. Melanson, J. Melanson, R. Melanson, T. Melindy, H.
Mellafont, L. Mello, G. Mellom, C. Mellott, K. Melnyk, M. Melnyk, R.
Melnyk, A. Melo, J. Melville, A. Menard, L. Mendenhall, P. Mendes, M.
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Merritt, U. Meservy, S. Metcalfe, T. Methuen, C. Metz, S. Meunier, R.
Mewis, C. Mews, D. Mews, R. Mews, T. Michaelis, L. Michalishen, C.
Michalko, B. Michaud, T. Michel, M. Michelin, K. Mickel, N. Mickelson,
J. Miclat, D. Midgley, K. Mielty, J. Mihai, J. Mihailoff, M. Miiller, D.
Mikalson, A. Mikhailov, S. Mikloukhine, J. Miko, G. Milan Garcia, J.
Milce, J. Mildenberger, R. Miles, R. Millar, B. Miller, D. Miller, G. Miller,
J. Miller, L. Miller, R. Miller, S. Miller, T. Miller, W. Miller, L. Milligan, C.
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Minick, W. Minni, W. Minns, D. Mino, J. Minor, A. Minty, J. Minty, A.
Mir, S. Mir, T. Mir, W. Mirabal, A. Mirza, B. Mirza, W. Mirza, O.
Mishchenko, J. Mistecki, D. Mistry, C. Mitchell, G. Mitchell, J. Mitchell,
M. Mitchell, R. Mitchell, T. Mitchell, W. Mitchell, Y. Mitchell, N.
T5
Canadian Natural 2020 Annual Report Mitchell-Banks, M. Mitton, P. Mo, V. Modak, B. Moelbert, I. Moffat, J. Moffat, R. Mogensen, A. Mognin, A.
Mohamed, S. Mohamed, B. Mohammed, G. Mohammed, A. Mohideen, J. Mohl, D. Moisan, M. Molde, N.
Molder, N. Molina, R. Mollison, J. Molnar, T. Mombourquette, R. Monahan, R. Money, P. Monfette, C.
Montague, F. Montefresco-Gentile, R. Monteith, J. Montgomery, M. Montinola, S. Moojelsky, K. Moon, P.
Moon, B. Moore, D. Moore, E. Moore, J. Moores, L. Mora, A. Morado, A. Morelli, K. Morency, L. Moreno,
J. Moretto, A. Morey, C. Morgan, J. Morgan, T. Morgan, M. Moriarty, A. Morin, J. Morin, M. Morin, P.
Morin, R. Morin, J. Morley, R. Morley, K. Morphy, K. Morrell, B. Morris, D. Morris, I. Morris, J. Morris, K.
Morris, M. Morris, S. Morris, J. Morriseau, C. Morrison, J. Morrison, S. Morrison, C. Morriss, W. Morrow,
S. Morse, D. Morsette, A. Mortlock, K. Morton, L. Morton, M. Morvik, D. Mose, D. Moser, J. Moshenko,
T. Moskol, M. Moss, P. Mossey, C. Mostowich, J. Mostyn, S. Mothersele, L. Motowylo, B. Mottle, S.
Moul, L. Mounkes, I. Mountain, P. Mouori Mbani, S. Mousazadeh, O. Moussa, M. Mousseau, D. Mouton,
R. Moyle, C. Moyls, M. Mubarak, W. Mudryk, T. Mudzviti, T. Mueller, Z. Mueller, T. Muessle, A. Mugford,
R. Mugford, M. Mughal, S. Muhammad, K. Muir, D. Muise, L. Muise, G. Mullen, S. Muller, C. Mullett, B.
Mulligan, R. Mullin, N. Mulvena, S. Mundt, K. Munn, A. Munro, J. Munro, L. Munro, R. Munro, C. Murdoch,
J. Murdoch, G. Murley, A. Murphy, B. Murphy, C. Murphy, D. Murphy, J. Murphy, K. Murphy, P. Murphy,
R. Murphy, T. Murphy, J. Murrant, B. Murray, C. Murray, G. Murray, L. Murray, S. Murray, E. Murrin, S.
Murrin, M. Musaid, A. Mushava, I. Musiwarwo, W. Muss, D. Musselman, T. Musselman, N. Musterer, Z.
Musuna, A. Muthuswamy, R. Mutschler, T. Mutter, I. Muwhen, J. Mweshi, D. Myers, E. Myers, L. Myhre,
S. Myles, D. Myshak, G. Nabi, J. Nachtigal, B. Nadeau, S. Nadeau, M. Naderikia, S. Nagare, A. Nagra, J.
Nagy, J. Nagy-Kolodychuk, L. Nahas, J. Naidu, J. Nair, R. Nair, S. Nair, S. Najeeb, L. Najoan, B. Nalder, N.
Namoca, E. Namur, J. Napier, R. Napier, C. Naqvi, H. Naqvi, S. Naqvi, P. Narayan, K. Narayanan, A. Narcise,
S. Naser, D. Nater, M. Nathwani-Crowe, A. Naughton, D. Naugler, P. Nava, D. Navas, R. Navas, V. Navratil,
M. Nawab, B. Nawaz, S. Nayak, C. Nazarko, N. N’Doye, T. Neacsu, D. Neal, N. Neale, M. Neate, A. Neddjar,
D. Neergaard, J. Neff, S. Negi, Y. Neguse, D. Neigum, A. Neilson, S. Neilson, D. Nein, K. Nelligan, A.
Nelson, B. Nelson, C. Nelson, D. Nelson, J. Nelson, K. Nelson, M. Nelson, R. Nelson, V. Nelson, M.
Nergaard, N. Nernberg, G. Nesbitt, B. Nessman, K. Netter, K. Nettesheim, G. Netzel, C. Neufeld, O.
Neufeld, F. Neumaier, D. Neumann, D. Nevil, W. Nevills, A. Nevokshonoff, D. Newbury, B. Newell, R.
Newitt, A. Newman, J. Newman, L. Newman, P. Newman, R. Newman, A. Newton, K. Newton, D. Ng, J.
Ng, K. Ng, R. Ng, S. Ng, V. Nganzo, P. N’Gbesso, H. Ngo, N. Ngo-Schneider, H. Ngowe, C. Nguyen, M.
Nguyen, S. Nguyen, T. Nguyen, H. Ni, D. Niamke, F. Nichol, J. Nicholl, D. Nichols, J. Nichols, A. Nicholson,
J. Nicholson, S. Nicholson, A. Nickel, D. Nickerson, K. Nickerson, J. Nicolajsen, E. Nicolas, T. Nicolas, J.
Nicoll, J. Nie, C. Nielsen, K. Nielsen, M. Nielsen, T. Nielsen, O. Nieto, M. Nieves, P. Nihon, W. Nikiforuk, C.
Nikipelo, R. Nimco, T. Ninovska, R. Nippard, S. Nippard, D. Nissen, J. Nistico, O. Niven, R. Nixdorf, K. Nixon,
P. Niziolek, A. N’Kesse, G. Noble, M. Nobles, C. Noel, D. Noel, P. Noel, A. Noftall, Z. Noftall, J. Noga, B.
Nolan, P. Nolan, R. Nolan, S. Nolan, B. Nolin, G. Nolin, R. Noot, W. Nordin, J. Norgaard, A. Nori, A. Noriel, V. Norkin, B. Norman, D. Norman, J. Norman, M. Norman, P. Norman, R.
Norman, T. Norman, T. Normand, Y. Normand, C. Normore, B. Norquay, L. Norrad, J. Norris, K. Norton, R. Norton, B. Noseworthy, A. Noskey, K. Notenbomer, F. Nothnagel, E. Notter,
J. Novak, O. Novikova, D. Nowicki, R. Nunweiler, D. Nwagbogwu, R. Nycholat, C. Nyen, E. Nyenhuis, C. Nyman, W. Oak, R. Oakes, W. Oakes, K. Oaks, A. Obad, D. Ober, J. Oberg,
N. Obi, F. Obiri, P. Oblozinsky, S. O’Bomsawin-Corriveau, E. Oborowsky, B. O’Brien, D. O’Brien, H. O’Brien, P. O’Brien, J. Obrigewitsch, J. Obuck, M. Ochran, J. O’Connell, M.
O’Connell, G. O’Connor, D. Oczkowski, M. Odo, P. O’Donnell, T. Oele, J. Oestreicher, H. Offet, I. Offor, E. Ofuya, L. O’Gallagher, J. Oganwu, O. Ogbodo, I. Ogbuke, A. Ogden, M.
Ogden, M. Ogg, A. Ogilvie, D. Ogilvie, J. O’Grady, D. Ogren, B. Ogurian, J. Oh, T. Oh, T. Oickle, R. Okada, C. O’Keefe, E. O’Keefe, S. O’Keefe, L. Okemow, A. Okeynan, R. Oksanen,
K. Okuszko, E. Okyere, F. Oladebo, P. Olaniyan, S. Olar, B. Olaski, M. Oldford, S. O’Leary, B. Olenik, D. Olesen, B. Olheiser, T. Olinek, D. Oliver, N. Oliver, A. Oliverio, C. Olivier, D.
Ollenberger, S. Ollerhead, J. Ollikka, V. Olofernes, G. Oloumi, J. Olsen, K. Olsen, M. Olsen, R. Olsen, S. Olsen, C. Olson, D. Olson, J. Olson, V. Olson, W. Olson, K. Olszewski, O.
Oluwole, M. Omosun, P. Onciul, D. O’Neil, D. Ong, K. Onuoha, P. Onyszko, C. Opper, C. Oragui, R. O’Regan, A. O’Reilly, M. O’Reilly, N. O’Reilly, M. Orosz, J. O’Rourke, L. Orpilla Jr,
A. Orr, N. Orr, S. Orser, M. Ortega, P. Ortega, K. Orth, R. Osachoff, C. Osborne, J. Osborne, D. O’Shea, J. Oshman, D. Osinchuk, M. Osman, K. Osmond, T. Osmond, L. Osorio, H.
Osorio Lobo, A. Ospino, B. Ostenberg, A. Ostrzenski, J. O’Sullivan, D. Oswald, J. Otis, J. O’Toole, G. Ott, C. Ottenbreit, L. Otteson, W. Otteson, J. Otto, T. Otway, T. Ouart, L. Ouch,
D. Ouellette, J. Ouellette, S. Ouellette, E. Overbye, M. Overwater, A. Owsianicki, A. Oxford, M. Oxford, P. Oza, P. Ozar, A. Paananen, L. Paananen, J. Paarsmarkt, M. Pachan, F.
Pacheco, M. Pacheco, D. Pacholok, S. Pacholok, T. Packard, J. Paddington, R. Padilla, T. Padron, M. Pady, S. Page, Q. Pagnucco, T. Pagura, G. Pahl, D. Pahljina, S. Paiement, K. Paige,
R. Paine, K. Painter, J. Pak, V. Pak, A. Palani, C. Palchewich, B. Pallan, B. Palmer, D. Palmer, E. Palmer, J. Palmer, K. Palmer, L. Palmer, O. Palomino, A. Palou, J. Palsis, F. Pana, I.
Panas, J. Panas, B. Panchal, V. Pandey, D. Pandher, S. Pandya, L. Pantazi, F. Pantilag, S. Panuganty, A. Papadoulis, M. Papcun, J. Papp, V. Papuga, P. Paquette, R. Paquette, L. Paquin,
D. Paradis, E. Paradis, J. Paradis, T. Paradis, M. Paranjape, B. Parathundathil, G. Parchewsky, P. Parchure, M. Pardy, E. Parece, L. Paredes, B. Parent, B. Parenteau, C. Parenteau, J.
Parenteau, L. Parillo, R. Parillo, B. Parker, D. Parker, J. Parker, D. Parlee, M. Parmar, C. Paron, B. Parsons, C. Parsons, G. Parsons, M. Parsons, S. Parsons, T. Parsons, W. Parsons, A.
Partsch, K. Pascoe, J. Pashko, M. Pasichnuk, W. Pasko, J. Pasos, N. Pasowisty, E. Pastor, A. Patel, B. Patel, D. Patel, H. Patel, J. Patel, K. Patel, M. Patel, N. Patel, P. Patel, R. Patel,
S. Patel, T. Patel, V. Patel, N. Pateliya, C. Pater, A. Paterson, H. Paterson, J. Paterson, B. Patey, D. Patey, I. Patey, J. Patey, M. Patey, T. Patey, J. Patience, P. Patil, K. Patmore, C.
Paton, G. Paton, C. Patrie, E. Patten, B. Patterson, C. Patterson, J. Patterson, K. Patterson, W. Patterson, Z. Patterson, C. Pattinson, C. Paul, G. Paul, J. Paul, K. Paul, T. Paul, M.
Paulgaard, E. Paulin, J. Paulsen, B. Paulson, B. Paulssen, B. Pauwels, D. Pavelick, M. Pavlic, M. Pavuluri, C. Pawlachuk, A. Pawlowich, M. Pawluk, C. Pay, C. Paylor, B. Payne, C. Payne,
D. Payne, G. Payne, J. Payne, M. Payne, P. Payne, S. Payson, P. Pazienza, K. Peach, B. Peacock, E. Peacock, L. Peacock, D. Pearson, E. Pearson, J. Pearson, T. Peats, T. Peciulis, M.
Peck, E. Peddle, D. Pedersen, J. Pedersen, K. Pedersen, P. Pedersen, S. Pedersen, B. Pederson, C. Pederson, L. Pederson, B. Peebles, J. Peeke, M. Peeke, R. Peel, D. Peet, K.
Peeters, E. Pegg, C. Peifer, F. Pelayo, K. Pelayo, M. Pelkey, G. Pellegrino, D. Pelletier, M. Pelletier, T. Pelletier, I. Pelly, M. Pelypiw, D. Pemberton, L. Pena, Y. Peng, J. Penman, C.
Pennell, T. Pennell, S. Pennemann, S. Penner, T. Penner, C. Penney, D. Penney, E. Penney, J. Penney, M. Penney, P. Penney, J. Penzo, I. Pepper, K. Pepper, D. Peramanu, S.
Peramanu, R. Peraza, M. Perdue, C. Peregrym, M. Perehudoff, S. Perehudoff, J. Perepelecta, F. Perez, L. Perez, J. Perez-Licera, D. Perkins, M. Perkins, R. Perkins, S. Perkins, T.
Perkins, J. Pernitsch, J. Peroramas, D. Perreault, N. Perron, B. Perry, C. Perry, D. Perry, G. Perry, J. Perry, O. Perry, R. Perry, S. Perry, V. Perry, T. Persaud, B. Persson, D. Perumal, B.
Pesowski, P. Peter, D. Peters, G. Peters, J. Peters, K. Peters, M. Peters, R. Peters, E. Petersen, A. Peterson, B. Peterson, E. Peterson, J. Peterson, M. Peterson, S. Peterson, T.
Peterson, C. Petkau, D. Petkau, B. Petkus, L. Petrillo, N. Petrola, R. Pettigrew, B. Pettipas, S. Pettit, D. Petz, A. Pewekar, K. Peyman, J. Peyton, K. Pfannmuller, R. Pfriem, L. Pham, L.
Phan, B. Phillips, D. Phillips, J. Phillips, K. Phillips, L. Phillips, T. Phillips, D. Philp, B. Philpott, T. Philpott, Z. Philpott-Belzil, G. Phinney, M. Phippen, L. Phoenix, L. Picard, W. Picard, E.
Picard-Goulet, K. Picco, J. Picken, K. Pickering, A. Pickersgill, P. Pickersgill, B. Piderman, D. Pierce, J. Piercey, S. Piercey, J. Pieroway, S. Pierzchala, A. Pietrusik, R. Pighin, J. Pihowich,
J. Pike, P. Pilecki, B. Pilgrim, S. Pilgrim, T. Pilgrim, M. Pili, D. Pilisko, J. Piliszanski, R. Pillai, L. Pillaveethil, N. Pilote, J. Pilsner, G. Pimienta, C. Pinchak, M. Pineda, L. Pineda Perez, E.
Pinituj-Flores, T. Pinksen, J. Pintaric, B. Pipa, J. Pipke, C. Pirnak, D. Pirvan, K. Pisio, M. Pitman, M. Pitre, A. Pittman, C. Pittman, D. Pittman, E. Pittman, I. Pittman, J. Pittman, M.
Pittman, S. Pittman, W. Pittman, S. Pituka, M. Plamondon, R. Plamondon, E. Plante, J. Plata, D. Plepelic, I. Plesa, J. Plessis, G. Plews, N. Plouffe, S. Plouffe, T. Plouffe, J. Plowman,
J. Plummer, I. Pocaterra, J. Pocock, S. Podhorodeski, A. Poetker, H. Poffenroth, D. Pohl, A. Poirier, D. Poirier, D. Poitras, J. Polacik, D. Pole, E. Poliquin, C. Pollard, R. Pollard, T. Pollard,
T. Pollett, A. Pollock, J. Pollock, M. Pollock, J. Polsfut, M. Polujan, G. Pome Franco, S. Pon, M. Poncelet, D. Poncsak, B. Pond, D. Pond, J. Pond, B. Ponjevic, N. Ponkiya, H.
Ponnurangan, T. Poole, K. Poon, G. Pope, T. Pope, C., J. Popoff, J. Popowich, M. Popowich, C. Portelance, J. Portelli, A. Porter, C. Porter, I. Porter, L. Porter, M. Posnikoff, P.
Postlewaite, R. Postnikoff, N. Pothier, C. Potorti, M. Potorti, J. Potter, T. Potter, K. Potts, R. Potts, J. Poulin, R. Poulter, K. Pounall, I. Pouncey, C. Povse, C. Powell, D. Powell, J. Powell,
P. Powell, R. Powell, B. Power, C. Power, E. Power, J. Power, K.
Power, L. Power, M. Power, P. Power, S. Power, T. Power, M.
Prajapati, D. Prasad, G. Pratch, G. Prather, K. Pratt, R. Pratt, S. Pratt,
L. Praud, W. Prawdzik, D. Prediger, M. Preece, J. Prefontaine, D.
Preshyon, J. Preshyon, D. Presley, A. Preston, J. Preston, R. Preteau,
A. Price, W. Price, J. Priest, D. Pringle, T. Prins, A. Pritchard, R.
Pritchett, S. Pritchett, K. Proc, G. Prochner, K. Proctor, D. Procyshyn,
M. Profiri, N. Proll, M. Pronk, J. Properzi, M. Prosper, D. Prostler, I.
Proudfoot, D. Proulx, T. Prudhomme, S. Prud’Homme, C. Prybylski,
C. Przybylski, S. Pshyk, Y. Puerto, J. Puhl, C. Pumphrey, M.
Pumphrey, A. Punko, K. Pupneja, S. Pupneja, B. Purcell, S. Purchase,
C. Purdy, J. Purdy, T. Purves, D. Pushak, S. Pushak, M. Pye, J. Pyke,
R. Pyke, W. Pyne, F. Pynn, J. Pyper, A. Pyra, M. Qian, W. Qian, L.
Qing, J. Qu, C. Quach, A. Quan, G. Quan, L. Quan, A. Quarin, R.
Quartermain, K. Quaschnick, K. Quayle-Thomson, J. Quiba, D.
Quigley, R. Quigley, S. Quigley, C. Quinlan, M. Quintin, G. Quinton,
B. Quipp, S. Qureshi, J. Raban Mardelli, L. Rabbitt, J. Rabby, B.
Rabusic, M. Raby, D. Rach, D. Rachkewich, D. Raciborski, W.
Raczynski, L. Radesh, K. Radke, R. Radke, A. Radtke, M. Radu, J.
Rae, R. Rae, I. Rafiyev, G. Raghavan Nair, J. Raher, A. Rahmani, M.
Rahmani, P. Rai, J. Rainnie, M. Raistrick, A. Raivio, K. Raj, M. Raj, J.
Rajotte, J. Ralph, P. Ralph, S. Raman, J. Ramazani, D. Ramburrun, D.
Ramirez, J. Ramirez, M. Ramirez, P. Ramirez, R. Ramirez, C. Ramos,
J. Ramsay, M. Ramsay, S. Ramsay, K. Ramsbottom, D. Randell, L.
Randell, M. Randell, T. Randell, W. Randell, R. Rane, J. Rankin, M.
Rankin, D. Ranola, J. Ransom, P. Rao, M. Raoufi, R. Raposo, S.
Rasch, T. Rasheed, C. Rasko, K. Raskob-Smith, S. Rasmussen, R.
Raso, H. Rassi, W. Ratcliffe, D. Rath, R. Rathburn, S. Ratkovic, M.
Rattray, H. Ratzlaff, A. Rau, M. Rausch, B. Rawling, C. Rawson, W.
Rawson, A. Ray, B. Ray, D. Ray, K. Ray, S. Ray, K. Rayment, D.
Raymond, E. Rayner, J. Rayner, R. Rayner, M. Raza, K. Razniak, F.
Re, B. Read, D. Read, W. Reashore, R. Reaume, C. Reber, D. Reber,
T6
Canadian Natural 2020 Annual Report D. Rechenmacher, Y. Redda, G. Redding, B. Redlich, E. Redlon, J. Redmann, G. Reed, J. Reed,
S. Reed, P. Regan, R. Reginato, C. Regnier, R. Regnier, P. Regular, H. Rehman, M. Rehman, B.
Reid, C. Reid, D. Reid, E. Reid, G. Reid, J. Reid, K. Reid, M. Reid, R. Reid, T. Reid, D. Reilly, H.
Reilly, S. Reilly, T. Reilly, D. Reimer, I. Reimer, M. Reinders, T. Reinders, J. Reiniger, T.
Reiniger, M. Reinkens, E. Reis, R. Reis, G. Reiter, H. Reithaug, T. Reitsma, D. Rejman, D.
Relkow, B. Relland, P. Rellosa, W. Remmer, C. Rempel, L. Rempel, P. Rempel, T. Rempel, L.
Ren, S. Ren, R. Renaud, T. Renkema, A. Rennie, J. Rennie, L. Rennie, M. Reno, J. Rentar, J.
Repchuk, S. Resus, C. Revereza, M. Rew, E. Reyes, O. Reyes, J. Reynolds, P. Reynolds, S.
Reynolds, T. Reynolds, M. Rezkallah, D. Reznik, N. Rhemtulla, C. Rhode, I. Riach, G. Ricard, S.
Ricci, D. Rice, J. Rice, R. Rice, C. Richard, J. Richard, K. Richard, M. Richard, B. Richards, C.
Richards, D. Richards, G. Richards, H. Richards, A. Richardson, K. Richardson, T. Richardson,
B. Riche, P. Richer, W. Ricker, C. Ricketson, A. Ricketts, M. Ricketts, W. Ricketts, R. Riddell,
J. Riddle, J. Rideout, M. Rideout, R. Rideout, T. Rider, C. Riegling, C. Ries, W. Riewe, M. Rigg,
A. Riley, D. Riley, S. Riley, D. Rimmer, D. Rinas, G. Ringheim, R. Rioux, S. Rioux, J. Ripka, P.
Riseley, J. Risling, S. Risling, S. Ristic, L. Ritchat, D. Ritchie, R. Ritchie, D. Ritter, K. Ritter, A.
Riutta, S. Rivard, E. Rivera, J. Rivera, O. Rizvi, M. Rizwan, T. Robb, N. Robbins, R. Roberge, A.
Robert, C. Roberts, D. Roberts, J. Roberts, M. Roberts, G. Robertson, M. Robertson, P.
Robertson, S. Robertson, K. Robertson-Baldwin, B. Robia, J. Robichaud, M. Robideau, H.
Robillard, A. Robinson, B. Robinson, D. Robinson, G. Robinson, J. Robinson, K. Robinson, M.
Robinson, N. Robinson, S. Robinson, T. Robinson, W. Robleto, C. Robson, S. Robson, A.
Rocha, L. Roche, J. Rochemont, R. Rock, S. Rodberg, T. Rodgers, J. Rodriguez, M. Rodriguez,
P. Roett, D. Rogal, K. Rogalsky, P. Rogatschnigg, C. Rogers, K. Rogers, S. Rogers, M. Rogne,
M. Rogozinski, L. Rojas, S. Rolling, K. Rolseth, T. Rolseth, P. Roman, L. Romanchuk, T.
Romanchuk, D. Romanyshyn, M. Rombough, A. Romero, G. Romero, J. Romero, S.
Rommelaere, D. Rondeau, J. Roney, S. Roney, L. Rong, P. Ronnie, A. Rook, J. Rooney, M.
Rooney, S. Roop, C. Root, A. Roozendaal, T. Rosciski, B. Rose, C. Rose, J. Rose, K. Rose, M.
Rose, P. Rose, R. Rose, M. Rose-Atkins, R. Rosenthal, D. Rosgen, S. Roskey, M. Rosloot, T.
Rosner, A. Ross, D. Ross, E. Ross, I. Ross, J. Ross, M. Ross, R. Ross, W. Ross, R. Rossburger,
G. Rosser, G. Rosso, J. Rostad, B. Rosychuk, R. Rosychuk, B. Roszell, C. Roth, K. Roth, M.
Roth, R. Roth, T. Roth, B. Rott, T. Rotzien, J. Rotzoll, S. Rouf, D. Rough, D. Roughton, N.
Rouidi, J. Rouleau, A. Routhier, D. Routhier, R. Routhier, R. Routley, K. Row, A. Rowbottom,
M. Rowe, S. Rowein, D. Rowley, M. Rowley, C. Rowsell, P. Rowsell, F. Roxas, A. Roy, B. Roy,
D. Roy, R. Roy, S. Roy, D. Royston, Z. Ruda, V. Ruddy, D. Rudkevitch, K. Rudolf, C. Rudolph, K.
Rudra, K. Ruecker, L. Ruesga, S. Ruether, D. Rueve, I. Rugg, M. Ruggles, M. Ruiz, S. Rumball,
D. Rumbolt, T. Rumbolt, J. Rumjan, M. Rundle, J. Rusk, N. Rusk, T. Rusnak, C. Russell, D.
Russell, E. Russell, J. Russell, P. Russell, S. Russell, T. Russell, R. Rustad, D. Rutberg, B.
Rutherford, J. Rutherford, M. Rutherford, S. Rutherford, D. Rutley, M. Rutter, T. Ruttle, H. Rutz,
N. Rvachew, F. Rwirangira, S. Ryali, J. Ryalls, A. Ryan, C. Ryan, D. Ryan, K. Ryan, M. Ryan, T.
Ryan, S. Ryback, R. Rybchinsky, C. Ryder, D. Ryder, J. Ryll, C. Rymut, J. Saaedi, E. Saar, J.
Saastad, R. Saastad, R. Sabas, M. Sabo, A. Sabourov, J. Sachs, F. Sackey-Forson, J. Sacrey, N.
Sacrey, S. Sacrey, V. Sacrey, J. Saeed, J. Sagan, S. Sagrafena, A. Saha, K. Sahni, S. Sahoo, A.
Saini, J. Sair, K. Saiyed, K. Sakowsky, R. Sakwattanapong, A. Salakunov, A. Salaudeen, A.
Salazar, C. Salazar, D. Salazar, E. Salazar, N. Salazar, P. Salazar Misslin, A. Saleh, E. Saleh, O.
Saleh, M. Salehi, J. Sali, M. Salman, E. Salmon, A. Salonga, S. Saltwater, B. Saluk, J. Salvador,
R. Salyn, C. Salzl, A. Samadi, A. Samarathunge, S. Samida, M. Samimi, K. Samms, A.
Samoisette, D. Sampang, J. Sampang, S. Sampanthamoorthy, A. Sampson, H. Sampson, J.
Sampson, T. Sampson, B. Samson, R. Samson, T. Samuelson, S. Samy, V. Sanchala, E.
Sanchez, M. Sanchez, R. Sanchez Hernandez, M. Sanders, P. Sanders, R. Sanders, T. Sanders,
D. Sanderson, I. Sanderson, L. Sanderson, S. Sanderson, C. Sandford, S. Sandhar, N.
Sandhawalia, G. Sando, T. Sanelli, N. Sanftleben, J. Sangha, E. Sangroniz, L. Sanoko, M.
Santarossa, T. Santos, M. Santucci, J. Sanyal, R. Sarabin, J. Sarai, A. Saran, S. Saran, R. Sarauskas, A. Sarawanski, M. Sarbah, D. Saretsky, D. Sargent, M. Saric, I. Sarjeant, S. Sarkar,
D. Sarmiento, A. Saroop, A. Sartori, M. Sartoris, M. Sas, S. Sashuk, G. Sasidharan, B. Sather, T. Sather, M. Satra, H. Sattar, E. Saucier, J. Saucier, E. Saulnier, G. Saunders, L. Saunders,
M. Saunders, S. Saurette, J. Savage, C. Savard, F. Savaria, B. Savla, D. Savoie, M. Savoie, C. Savostianik, A. Savtchenko, S. Sawchuk, B. Sawler, A. Saxena, D. Saxty, C. Sayer, R.
Sayer, E. Sayewich, K. Sayko, K. Scagliarini, R. Scammell, J. Scarfe, J. Scarff, B. Scarth, R. Scarth, R. Schaap, T. Schable, K. Schachtel, B. Schade, D. Schaffer, B. Schamehorn, M.
Schanzenbach, G. Schappert, T. Schatkoske, R. Schatschneider, C. Schaub, P. Schaub, J. Schechtel, J. Schedlosky, C. Scheerschmidt, A. Schell, S. Schell, S. Schellenberg, L. Schelske,
L. Scheper, C. Scherger, C. Scheu, D. Schick, J. Schick, S. Schick, A. Schill, K. Schille, C. Schiller, J. Schiller, L. Schiller, A. Schindel, C. Schindel, R. Schlachter, G. Schlamp, M. Schlamp,
D. Schledt, D. Schlosser, D. Schmaltz, L. Schmaus, S. Schmid, A. Schmidt, J. Schmidt, K. Schmidt, N. Schmidt, R. Schmidt, T. Schmidt, P. Schmuland, D. Schneider, G. Schneider, M.
Schneider, P. Schneider, S. Schneider, K. Schnell, S. Schnell, C. Schnepf, A. Schnick, J. Schnieder, R. Schnieder, D. Schnitzler, C. Schnurer, J. Schoengut, E. Schofield, N. Schofield,
S. Schofield, L. Schonhoffer, M. Schreiner, K. Schroeder, R. Schroeder, S. Schroeder, R. Schuh, N. Schuler, E. Schulte, C. Schultz, D. Schultz, J. Schultz, P. Schultz, S. Schultz, M.
Schultze, T. Schulz, K. Schumacher, D. Schwank, R. Schwank, B. Schwartz, D. Schwarz, C. Schwenning, L. Schwetz, J. Schwindt, T. Scimia, R. Scoles, J. Scollard, C. Scott, D. Scott,
E. Scott, G. Scott, J. Scott, K. Scott, M. Scott, R. Scott, S. Scott, R. Scoville, M. Scragg, J. Scribner, R. Scrimshaw, C. Scullion, S. Seabrook, M. Seafoot, K. Seaman, C. Sears, G. Seaton,
T. Seaward, M. Sebastian, S. Sedghi, K. Seehagel, D. Seel, C. Seely, M. Seguin, L. Sehn, K. Seidel, P. Seipp, K. Seitz, R. Sekel, B. Sekulich, E. Sekura, D. Selby, K. Self, D. Selinger, M.
Selman, R. Selvarajan, T. Semashkewich, A. Semchanka, L. Semeniuk, K. Seminchuk, R. Senecal, T. Senecal, T. Senger, P. Senk, T. Senner, H. Seo, F. Sepnio, A. Sequeira, C. Sereda,
R. Sereda, B. Serfas, R. Serfas, P. Sergeant, J. Serino, E. Serniak, R. Serson, K. Setareh-Kokab, B. Severight, J. Seward, B. Sewell, C. Sexsmith, P. Sexton, S. Seyed Tarrah, G.
Sgambaro, M. Sgambaro, R. Sgambaro, C. Shackleton, M. Shad, B. Shah, H. Shah, M. Shah, N. Shah, R. Shah, S. Shah, V. Shah, M. Shahebrahimi, S. Shahzad, S. Shaikh, K. Shakir, K.
Shakotko, V. Shakouri, A. Shandroski, L. Shang, C. Shank, B. Shanmugam, J. Shannon, T. Shao, A. Sharifi, A. Sharma, D. Sharma, K. Sharma, R. Sharma, T. Sharma, M. Sharman, N.
Sharp, J. Sharpe, K. Sharpe, T. Sharpe, R. Sharron, R. Shaver, B. Shaw, E. Shaw, K. Shaw, M. Shaw, R. Shaw, O. Shaykina, K. Shea, L. Shea, C. Shears, D. Sheaves, L. Sheaves, W.
Sheaves, A. Shehata, K. Sheikh, M. Sheikh, O. Sheikh, C. Shen, B. Shenton, R. Shepel, I. Shepherd, C. Sheppard, D. Sheppard, G. Sheppard, J. Sheppard, M. Sheppard, P. Sheppard,
R. Sheppard, T. Sheppard, A. Shergill, T. Sheridan, M. Sherman, R. Sherman, S. Sherman, A. Sherriffs, M. Sheth, N. Sheth, V. Shetty, C. Sheward, D. Shewchuk, L. Shi, A. Shideler, C.
Shields, J. Shields, A. Shiers, N. Shihinski, S. Shiledarbaxi, K. Shill, C. Shimbashi, P. Shiner, W. Shipley, J. Shire, V. Shirhatti, B. Shmoury, B. Shmyr, M. Shobeiri, N. Shohel, R.
Shonhiwa, S. Short, T. Short, D. Shortland, D. Shortreed, J. Shott, M. Shott, C. Shoup, S. Shravge, R. Shrestha, L. Shuai, M. Shukalov, T. Shukin, K. Shukla, D. Shular, J. Shumate, F.
Shupenia, S. Shymoniak, D. Shypitka, J. Shysh, C. Sibeudu, I. Siddhanta, A. Siddiqui, M. Siddiqui, R. Sidloski, C. Sieben, D. Sieben, J. Sieben, E. Siemens, R. Siewert, A. Sifton, R.
Sigsworth, J. Sikora, W. Sikorski, L. Silas, R. Silbernagel, T.
Silbernagel, B. Silue, N. Silue, I. Silva, J. Silva, L. Silva, J.
Silver, G. Silvis, C. Simard, D. Simard, K. Simard, R. Simard,
D. Simbi, C. Simcock, G. Simmelink, T. Simmonds, J.
Simmons, C. Simms, D. Simms, F. Simms, R. Simms, M.
Simoes, A. Simon, P. Simon, T. Simon, R. Simper, G.
Simpkins, C. Simpson, D. Simpson, G. Simpson, J. Simpson,
L. Simpson, R. Simpson, S. Simpson, W. Simpson, C. Sims,
D. Sinclair, E. Sinclair, R. Sinclair, S. Sinclair, D. Sine, A.
Singh, H. Singh, K. Singh, S. Singh, Y. Singh, S. Singla, M.
Sinkova-Hovdestad, A. Sinnett, B. Sinnicks, L. Sinnicks, R.
Sison, J. Sjonnesen, D. Skanderup, W. Skaret, B. Skinner, T.
Skinner, M. Skipper, J. Skjeie, G. Skoczek, J. Skog, Z. Skoko,
M. Skolski, R. Skrepnek, S. Skulmoski, M. Skulski, J. Skwara,
M. Skyrpan, M. Slavin, K. Slemko, D. Slemp, A. Sleno, A.
Slipchuk, J. Sloan, M. Sloan, R. Sloan, R. Slobodian, K.
Slotwinski, J. Sloychuk, S. Slywka, E. Smart, N. Smart, P.
Smart, R. Smart, J. Smid, S. Smiegielski, C. Smillie, A. Smith,
B. Smith, C. Smith, D. Smith, E. Smith, G. Smith, J. Smith, K.
Smith, L. Smith, M. Smith, R. Smith, S. Smith, T. Smith, C.
Smitham, L. Smollet, E. Smolyaninova, A. Smyl, R. Smyl, J.
Sneddon, K. Snee, R. Snell, T. Snell, G. Snider, J. Snider, I.
Snook, J. Snow, K. Snow, D. Snowdon, J. Snowdon, D.
Snyder, J. Soar, J. Soenen, D. Sohlbach, D. Sokoloski, S.
Solanki, J. Solano, J. Soley, V. Sollid, M. Sollows, S. Soloshy,
A. Soloway, K. Soltys, L. Somerville, L. Sommer, R. Somorai,
D. Soni, A. Sonpal, N. Soodyall, W. Sookram, M. Soolagallu,
T. Sopatyk, G. Sopczak, H. Sorensen, R. Sorensen, C.
Sorenson, L. Sorge, I. Soro, C. Sorochan, L. Sorochan, D.
Soroko, L. Soucy, M. Soucy, R. Soucy, A. Soundararaj, L.
Soutar, J. Southern, E. Spagrud, D. Spanics, M. Sparks, E.
Spearman, B. Speedtsberg, G. Speer, D. Spencer, R.
T7
Canadian Natural 2020 Annual Report Spencer, S. Spencer, B. Spendiff, D. Spidell, K. Spiker, A.
Spohn, M. Spreacker, M. Sprinkle, C. Spurr, A. Spurrell, E.
Spurrell, N. Spurrell, P. Spurvey, R. Spychka, C. Spykerman, N.
Squarek, J. Squire, C. Squires, P. Squires, T. Squires, R. Sran,
A. Sriram, S. St. Croix, R. St. Jean, R. St. Martin, J. St. Onge, E.
St. Pierre, M. St. Pierre, R. St. Pierre, L. Staats, A. Stacey, K.
Stacey, I. Stacey-Salmon, P. Stackhouse, G. Stadnichuk, S.
Stadnichuk, S. Stadnyk, D. Stagg, J. Stagg, K. Stagg, T. Stagg,
M. Stainthorpe, K. Stairs, J. Stajkowski, M. Stalker, B. Stamp,
R. Stamp, A. Stan, A. Standing, J. Stanford, C. Stang, M. Stang,
R. Stang, R. Stanger, M. Stangl, J. Stanley, T. Stanley, A.
Staples, J. Staples, P. Stapleton, K. Stark, L. Stark, R. Staruiala,
R. Stasiuk, D. Staszewski, K. Staszkiewicz, S. Stauth, A.
Stavropoulos, K. Stawinski, E. Stearns, M. Stebner, M. Stec, R.
Steele, B. Steeves, L. Steeves, S. Stefan, T. Stefansson, A.
Stefura, M. Stein, M. Steinbach, J. Steinkey, S. Steinkey, D.
Stemmann, W. Stenhouse, G. Stephen, M. Stephens, T.
Stephens, B. Stephenson, J. Stephenson, L. Stephenson, G.
Stetar, G. Stevens, N. Stevens, R. Stevens, A. Stevens-Dicks,
D. Stevens-Dicks, A. Stevenson, M. Stevenson, N. Stevenson,
R. Stevenson, T. Stevers, C. Stewart, D. Stewart, J. Stewart, L.
Stewart, M. Stewart, R. Stewart, T. Stewart, B. Stich, W.
Stickel, R. Stieben, M. Stiefel, D. Stinn, M. St-Jacques, M.
Stobart, D. Stobbe, J. Stober, M. Stockes, C. Stocking, M.
Stockton, C. Stoddard, J. Stokes, T. Stokke, S. Stoller, C. Stolz,
T. Stolz, D. Stone, M. Stone, T. Stone, M. Stordahl, J. Storey,
D. Stormo, B. Stortz, D. Stout, R. Stoutenberg, D. Stoyles, S.
Strachan, A. Stranaghan, R. Stranberg, C. Strand, W. Strand, J.
Strandquist, C. Strang, R. Strang, D. Strankman, N. Strantz, B.
Stratichuk, D. Stratmoen, M. Straughan, M. Street, S. Street,
R. Stretch, W. Stretch, H. Strickland, R. Strickland, R. Striegler,
J. Strilchuk, M. Stroh, J. Strong, R. Strong, M. Stronski, R.
Struski, D. Strynadka, D. Stuart, L. Stuart, P. Stuart, C. Stubbs, G. Stuber, K. Stuckey, P. Stuckey, V. Stuckey, N. Stuckless, R. Stuckless, T. Stuckless, C. Study, J. Stuebing, G. Sturdy,
F. Sturge, J. Sturge, P. Sturge, J. Sturgeon, P. Sturgeon, D. Sturrock, A. Styles, L. Su, W. Su, M. Suarez, V. Subasic, I. Subasinghe, V. Subban, J. Subramaniam, R. Subramaniam, B.
Suchan, A. Suhel, R. Sukkel, J. Sukoveoff, J. Sullivan, M. Sullivan, R. Sullivan, T. Sullivan, P. Sultanian, B. Summerfelt, C. Summers, D. Summers, E. Summers, E. Sumner, T. Sun, X.
Sun, U. Sundar, U. Sundaram, P. Sundaravadivelu, C. Surgenor, A. Surugiu, G. Surugiu, L. Sutcliffe, T. Sutcliffe, C. Sutherland, D. Sutherland, K. Sutherland, L. Sutherland, B. Sutton,
P. Sutton, S. Sverdahl, T. Svoboda, A. Swain, D. Swain, S. Swain, T. Swallow, D. Swan, M. Swan, J. Swannack, C. Swanson, J. Swanson, N. Swanson, R. Swarnkar, E. Sweeney, S.
Sweetapple, C. Swenarchuk, N. Swennumson, E. Switzer, A. Sychak, K. Sydorko, D. Syed, W. Syed, J. Sykes, T. Sylvester, D. Sylvestre, B. Symington, A. Symons, M. Symons, D.
Syrnyk, G. Sywake, N. Szalay, E. Szeto, C. Szmata, A. Szoke, C. Szpecht, D. Sztukowski, D. Sztym, S. Szubzda, M. Szucs, C. Szutiak, K. Szydlik, J. Ta, C. Tacadena, M. Tade, D. Taggart,
A. Taghipour, P. Taiani, M. Tainsh, D. Tainton, D. Tait, G. Tait, O. Tait, J. Taite, A. Tajik, D. Tajiri, S. Takala, G. Talati, S. Talati, C. Talbot, J. Talbot, M. Talerico, C. Tallack, D. Tallas, B.
Talma, K. Tam, B. Tamas, B. Tan, C. Tan, K. Tan, S. Tan, M. Tanasescu, B. Tancowny, L. Tang, X. Tang, T. Tanigami, M. Tapley, G. Tapp, C. Tarache, A. Tarasenco, R. Tarasoff, C. Tardif,
G. Tarditi, B. Tarkowski, M. Taron, D. Tarrant, B. Tasek, J. Tatarin, R. Tatro, N. Tavassoli, A. Taylor, B. Taylor, C. Taylor, H. Taylor, J. Taylor, K. Taylor, L. Taylor, M. Taylor, N. Taylor, P.
Taylor, R. Taylor, S. Taylor, W. Taylor, J. Taylor-Kay, M. Teeple, A. Tegnander, P. Teha, J. Teixeira, S. Tejpar, A. Telan, M. Teleptean, R. Tellier, B. Temesgen, J. Temple, C. Templeton,
S. Tenhunen, L. Tennant, K. Tenney, J. Teppin, G. Teske, A. Teslak, L. Tessier, W. Teszeri, W. Tetachuk, C. Tetreau, J. Tettensor, B. Tetz, J. Tetz, S. Tetz, F. Thaddaues, L. Thai, T.
Tham, P. Thannhauser, J. Thauberger, J. Theis, S. Theoret, G. Theriault, B. Thevarajah, W. Thew, R. Thibodeau, C. Thiessen, J. Thiessen, R. Thiessen, T. Thiessen, M. Thoen, D.
Thomas, E. Thomas, L. Thomas, M. Thomas, S. Thomas, J. Thomas Cotton, T. Thomassen, G. Thomlison, A. Thompson, C. Thompson, E. Thompson, I. Thompson, J. Thompson, K.
Thompson, L. Thompson, R. Thompson, S. Thompson, T. Thompson, J. Thomsen, P. Thomsen, A. Thomson, J. Thomson, K. Thomson, P. Thomson, S. Thomson, T. Thomson, W.
Thomson, K. Thorburn, T. Thorburne, L. Thorhaug, J. Thorleifson, B. Thorn, D. Thorne, L. Thorne, B. Thornhill, E. Thornton, K. Thornton, N. Thorp, K. Thors, K. Threndyle, E. Thunaes,
D. Thurman, M. Thyer, T. Tian, M. Tiedje, P. Tieu, B. Tiffin, T. Tilbury, D. Tillapaugh, J. Tiller, D. Tilley, M. Tilley, K. Tillotson, T. Tillotson, S. Timothy, N. Tindall, M. Tineo, D. Tipper, B.
Titus, D. Tiwary, R. Tiwary, C. Tkach, B. Tobin, C. Tobin, K. Tobin, V. Tobin, K. Tobler, B. Todd, C. Todd, S. Todd, T. Tolen, D. Tomar, B. Tomchuk, G. Tomchuk, D. Tomiuk, C. Tomlinson,
M. Tompkins, A. Tomszak, N. Tomte, W. Tong, M. Tonon, S. Tookey, A. Toop, V. Topacio, S. Topolnitsky, K. Tordon, P. Torrance, C. Torraville, F. Torraville, J. Torraville, N. Torres, D.
Toth, D. Touchette, S. Touchette, D. Toullelan, T. Tourand, M. Townsend, O. Tozser, A. Tran, C. Tran, D. Tran, J. Tran, M. Trang, C. Trapp, G. Trask, L. Trautman, M. Travers, P. Traverse,
J. Tredger, G. Treen, J. Treen, J. Trelinski, W. Trelinski, J. Treliving, L. Tremblay, M. Tremblay, C. Tremblett, W. Tremblett, J. Trenholm, J. Trieu, J. Trieu-Ly, W. Trigger, A. Trinh, D.
Trinh, J. Trinier, E. Triumbari, C. Troake, P. Troy, J. Trto, J. Trudeau, R. Trudeau, F. Truefitt, B. Trumpf, A. Truong, H. Truong, S. Truong, H. Tsagalas, L. Tsaprailis, C. Tse, Y. Tse, G.
Tsemenko, M. Tsineli, D. Tsui, Y. Tu, A. Tuck, B. Tucker, D. Tucker, J. Tucker, R. Tucker, R. Tuerke, A. Tuico, D. Tuite, S. Tulan, B. Tulk, J. Tulk, B. Tulloch, N. Tulloch, B. Tumbach, P.
Tung, M. Tunke, T. Tupper, T. Turbide, J. Turcotte, T. Turgeon, B. Turner, C. Turner, D. Turner, J. Turner, P. Turner, S. Turner, D. Turpin, T. Turpin, V. Turska, S. Turton, R. Tuttle, I.
Tutto, L. Tuttosi, J. Tweten, P. Twomey, D. Twyne, O. Tyan, A. Tyler, M. Tyler, D. Tymchyna, R. Tymchyna, N. Tynan, C. Tyssen, J. Uddin, S. Udupa, T. Uhrich, S. Ulloa, J. Ulmer, C.
Ulrich, E. Ulrich, J. Umali, O. Umana, U. Umoh, A. Umpleby, L. Underhill, K. Underwood, N. Underwood, R. Underwood, T. Ung, B. Unrath, L. Unrau, H. Unruh, P. Unruh, M. Upadhyay,
S. Upadhyay, U. Upadhyaya, C. Upham, M. Uponi, D. Urban, L. Urbina, J. Urdaneta, C. Urlacher, A. Ustariz, P. Uwabor, K. Uyanwune, R. Vachon, S. Vadnai, K. Vaideswaran, M. Vajdik,
V. Vajihinejad, 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, C. Van de Reep,
W. Van den Oever, M. van der Burgh, N. 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
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D. Vanbocquestal, J. Vancoughnett, K. Vandaelle, J. Vandeligt, R. Vandemark, T. Vandemark, D. Vandenberg, G. Vander Veen, N. Vandergriend, J. Vanderkley, T. Vandermeer, A.
Vandersalm, J. Vandervoort, E. Vanopian, G. van’t Wout, L. Varela Avendano, S. Varey, M. Varga, D. Varty, N. Vaschetto, A. Vashisht, A. Vasquez, C. Vasquez, M. Vasquez-Placid, J.
Vasseur, R. Vassov, R. Vaudan, A. Vaughan, N. Vaughan, O. Vedmedenko, F. Veenbaas, S. Vekved, B. Velagapudi, B. Velichka, M. Velmurugan, R. Veloso, R. Veneracion, S. Venkatesh,
G. Venkateshvaralu, R. Venn, D. Venning, J. Vera, L. Verbaas, D. Verbeek, D. Verbicky, M. Verburg, A. Verge, J. Verge, M. Verge, B. Verhoeven, K. Vernon, S. Veroba, J. Verot, B.
Verreau, D. Versnick-Brown, S. Vetsch, K. Veysey, J. Vezina, C. Viana, G. Vibert, J. Vicic, N. Vick, D. Vickery, G. Viljoen, R. Villanueva, J. Villemaire, M. Villemaire, C. Villemere, K.
Vincent, R. Vincent, R. Vindevoghel, S. Vineham, B. Viney, R. Vinkle, G. Virus, K. Virus, A. Visotto, R. Vivian, N. Vizcuna Alvarado, R. Vloet, S. Voight, B. Volkmann, R. Volkmann, J.
Vollman, W. Volschenk, L. Vondermuhll, A. Vosburgh, A. Votta, A. Vredegoor, J. Vrolson, N. Vucic, L. Vuong, Q. Vuong, G. Wack, E. Waddell, T. Waddell, K. Waddy, J. Wade, W. Wade,
T. Wagil, C. Wagner, D. Wagner, G. Wagner, J. Wagner, K. Wagner, N. Wagner, M. Wahl, D. Wakaruk, L. Wakaruk, L. Wakefield, T. Wakulchyk, A. Walchuk, D. Waldner, K. Waldron,
A. Walintschek, C. Walker, D. Walker, G. Walker, J. Walker, K. Walker, R. Walker, S. Walker, T. Walker, K. Walko, D. Wall, S. Wall, A. Wallace, C. Wallace, D. Wallace, E. Wallace, H.
Wallace, K. Wallace, V. Wallace, M. Wallis, V. Wallwork, T. Walraven, A. Walsh, B. Walsh, E. Walsh, M. Walsh, P. Walsh, R. Walsh, S. Walsh, T. Walsh, W. Walsh, L. Walter, A. Walters,
D. Walters, J. Walters, I. Walton, K. Wambolt, N. Wan, D. Wanchuk, C. Wang, H. Wang, J. Wang, L. Wang, R. Wang, S. Wang, T. Wang, W. Wang, X. Wang, Y. Wang, Z. Wang, B.
Wangler, D. Wannas, S. Waquan, T. Warburton, E. Ward, K. Ward, R. Ward, B. Warehime, D. Warford, W. Warholik, J. Waring, C. Wark, W. Warman, F. Warraich, G. Warren, J. Warren,
K. Warren, R. Warren, S. Warren, D. Warrington, M. Warsame, K. Warwaruk, J. Washburn, M. Washington, A. Wasikowski, P. Wassell, C. Wasylciw, W. Wasylucha, D. Waterfield, C.
Waters, D. Watson, G. Watson, J. Watson, K. Watson, M. Watson, S. Watson, D. Watt, G. Watt, B. Watton, B. Watts, J. Watts, T. Wawro, B. Weatherby, D. Weatherby, C.
Weatherhead, H. Weaver, A. Webb, G. Webb, P. Webb, R. Webb, B. Webber, D. Webber, J. Webber, O. Websdale, K. Webster, D. Weed, E. Weening, E. Weenink, B. Wegenast, B.
Wei, Z. Wei, J. Weibrecht, J. Weigl, J. Weik, D. Weimer, C. Weingarten, R. Weir, G. Weisbeck, R. Weisbrot, M. Weishaar, C. Weiss, J. Weller, P. Weller, B. Wellman, M. Wellman, A.
Wells, C. Wells, D. Wells, E. Wells, L. Wells, N. Wells, R. Wells, T. Wells, A. Welsh, W. Welte, W. Welygan, Z. Wen, G. Weng, P. Wenger, J. Wenisch, G. Wennberg, P. Wennerstrom,
A. Wentworth, J. Wentworth, K. Wenzel, D. Werbowy, C. Werner, N. Wert, B. Weslake, E. Wessel, D. West, R. West, M. Westad, D. Westbrook, K. Westland, B. Wetthuhn, D.
Wheating, L. Wheating, J. Wheaton, S. Wheaton, A. Wheeler, B. Wheeler, C. Wheeler, J. Wheeler, K. Wheeler, L. Wheeler, N. Wheeler, C. Whelan, D. Whelan, K. Whelan, R. Whelan,
R. Whelan-Maloney, A. White, B. White, D. White, F. White, H. White, J. White, M. White, P. White, R. White, S. White, T. White, Z. White, J. Whitehead, L. Whitehead, V. Whitehead,
D. Whitehouse, K. Whiteknife, N. Whiteknife, J. Whitelaw, A. Whiteside, C. Whitford, R. Whitman, H. Whitmore, K. Whitney, M. Whittaker, A. Whitten, H. Whitten, D. Whitty, A.
Whitwell, K. Wickenhauser, A. Wickins, C. Wickwire, G. Wideman, M. Widing, A. Wiebe, D. Wiebe, M. Wiebe, N. Wiebe, T. Wiebe, D. Wiege, T. Wielgus, B. Wiesener, C. Wietzel, Z.
Wigglesworth, S. Wight, T. Wight, D. Wijesingha, C. Wilbee, D. Wilbee, A. Wilcott, J. Wilcox, M. Wilcox, D. Wilde, E. Wildeman, D. Wiles, R. Wiles, C. Wilk, T. Wilk, C. Wilkes, N.
Wilkes, D. Wilkins, J. Wilkinson, K. Wilkinson, P. Will, D. Willard, E. Willard, B. Willburn, A. Willcott, B. Willcott, J. Willems, R. Willey, A. Williams, B. Williams, C. Williams, G. Williams,
M. Williams, N. Williams, R. Williams, T. Williams, W. Williams, C. Williamson, D. Williamson, J. Williamson, K. Williamson, M. Williamson, J. Willick, M. Willis, R. Willis, S. Williscroft,
J. Williston, D. Willms, S. Wills, G. Willshire, C. Willson, D. Willson, M. Wilschut, A. Wilson, C. Wilson, D. Wilson, G. Wilson, H. Wilson, J. Wilson, K. Wilson, L. Wilson, M. Wilson, S.
Wilson, W. Wilson, J. Wiltshire, A. Winfield, P. Winfield, B. Wingate, A. Wingert, J. Winia, B. Winiarz, I. Winland, R. Winnicky, L. Winquist, T. Winquist, R. Winslow, J. Winsor, O.
Winsor, T. Winter, C. Winterhalt, G. Winters, R. Winters, G. Wirachowsky, J. Wirachowsky, M. Wiseman, P. Wiseman, W. Wiseman, I. Wishart, M. Witmer, Z. Witt, B. Wittenborn,
C. Wlad, A. Wlos, M. Woehleke, D. Woitas, J. Woitas, T. Woitte, R. Wojtowicz, S. Wolf, D. Wolfe, J. Wolfe, D. Wollum, C. Woloshyn, J. Wolstenholme, B. Wolstoncroft, J. Wolter,
R. Wolters, A. Wong, C. Wong, G. Wong, J. Wong, K. Wong, L. Wong, N. Wong, C. Woo, J. Woo, L. Woo, A. Wood, G. Wood, L. Wood, P. Wood, R. Woodburne, J. Woodd, M.
Woodfin, S. Woodfine, N. Woodford, S. Woodford, T. Woodford, A. Woodger, C. Woodhead, M. Woodhead, D. Woods, J. Woods, T. Woods, M. Woodske, J. Wooldridge, B. Wooley,
S. Woolfitt, T. Woolley, R. Woolner, R. Wootton, M. Workman, M. Workun, M. Woroniuk, B. Worthington, C. Worthman, J. Wotten, B. Woytenko, K. Woytiuk, T. Wozney, C. Wright,
L. Wright, R. Wright, G. Wrinn, B. Wu, C. Wu, D. Wu, H. Wu, J. Wu, M. Wu, P. Wuorinen, B. Wurzer, K. Wutzke, E. Wylie, G. Wyman, G. Wyndham, D. Wyshynski, L. Wysocki, S.
Wytrychowski, Y. Xia, Y. Xiao, Y. Xie, H. Xu, J. Xu, Q. Xu, Z. Xu, M. Xue, D. Yackel, K. Yakemchuk, K. Yakimowich, L. Yakiwchuk, J. Yamniuk, P. Yan, D. Yang, L. Yang, D. Yanke, G.
Yanota, K. Yao, L. Yao, W. Yao, H. Yare, A. Yaremko, R. Yarmuch, J. Yaroslawsky, S. Yasin, M. Yaychuk, P. Yazdani, B. Ye, P. Yeboah, B. Yeboue, B. Yee, G. Yee, R. Yee, C. Yen, D.
Yep, P. Yepes, J. Yeremiy, J. Yeske, A. Yevtushenko, C. Ying, O. Ying, Y. Ying, J. Yip, K. Yip, L. Yip, F. Yohannes, R. Yong, J. Yoo, F. York, P. York, A. Yoshikawa, X. You, M. Youell,
B. Young, D. Young, E. Young, J. Young, L. Young, M. Young, P. Young, S. Young, T. Young, N. Younis, P. Youssef, R. Yowney, E. Yu, G. Yu, J. Yu, M. Yu, C. Yuen, D. Yuill, J. Yuill,
R. Yuristy, S. Yuzyk, R. Zabek, A. Zabloski, A. Zacharias, C. Zacharias, T. Zachoda, C. Zackowski, J. Zaderey, N. Zaderey, B. Zagoruy, S. Zagozewski, E. Zahacy, B. Zaitsoff, S. Zakeri,
R. Zamudio Baca, B. Zandstra, D. Zanoni, C. Zaparyniuk, S. Zardynezhad, D. Zarowny, G. Zarowny, K. Zarowny, M. Zarowny, Z. Zarowny, S. Zawada, K. Zayac, D. Zazula, R. Zazula, S.
Zbrodoff, K. Zeer, T. Zeiser, I. Zelazny, D. Zelman, B. Zembik, D. Zemlak, A. Zenide, W. Zeniuk, G. Zeran, K. Zern, J. Zerpa, K. Zerr, M. Zerr, S. Zgurski, B. Zhang, J. Zhang, M. Zhang,
Q. Zhang, W. Zhang, X. Zhang, Y. Zhang, Z. Zhang, B. Zhao, L. Zhao, R. Zhao, G. Zheng, S. Zheng, W. Zheng, H. Zhou, Q. Zhou, Y. Zhou, J. Zhu, L. Zhu, W. Zhu, E. Zhuromsky, P. Zia,
S. Ziadeh, C. Ziebart, K. Zielinski, A. Zielke, D. Zilinski, E. Zimmer, C. Zimmerman, R. Zoerb, A. Zoglauer, L. Zseder, J. Zuk, S. Zukanovic, N. Zukiwski, S. Zukowski, S. Zwyer, S. Zyha.
T8
Canadian Natural 2020 Annual Report 2020 Year-End Reserves
DETERMINATION OF RESERVES
For the year ended December 31, 2020, the Company retained Independent Qualified Reserves Evaluators (IQREs), Sproule
Associates Limited, Sproule International Limited and GLJ Ltd., to evaluate and review all of the Company’s proved and
proved plus probable reserves. The evaluation and review was conducted and prepared 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.
Additional reserves information is disclosed in the Company’s Annual Information Form.
RESERVES INFORMATION HIGHLIGHTS
■ Canadian Natural’s crude oil, SCO, bitumen, natural gas and NGL reserves were evaluated and reviewed by Independent
Qualified Reserves Evaluators. The following highlights are based on the Company’s reserves using forecast prices and
costs at December 31, 2020 (all reserves values are Company Gross unless stated otherwise).
■
Total proved reserves increased 10% to 12.106 billion BOE with reserves additions and revisions of 1.538 billion BOE.
Total proved plus probable reserves increased 12% to 15.925 billion BOE with reserves additions and revisions of
2.099 billion BOE.
•
The strength and depth of the Company’s assets are evident as approximately 80% of total proved reserves are long
life low decline. This results in a total proved BOE reserves life index of 29.8 years and a total proved plus probable
BOE reserves life index of 39.2 years.
– Additionally, high value, zero decline, SCO is approximately 58% of total proved reserves with a reserve life index
of approximately 45 years.
■ Canadian Natural’s 2020 performance has once again consistently delivered superior finding and development costs:
•
•
Finding, Development and Acquisition (“FD&A”) costs, excluding changes in Future Development Cost (“FDC”), are
$1.91/BOE for total proved reserves and $1.40/BOE for total proved plus probable reserves.
FD&A costs, including changes in FDC, are $4.46/BOE for total proved reserves and $3.46/BOE for total proved plus
probable reserves.
■
Total proved reserves additions and revisions replaced 2020 production by 361%. Total proved plus probable reserves
additions and revisions replaced 2020 production by 493%.
■ Proved developed producing reserves additions and revisions are 1.032 billion BOE, replacing 2020 production by 242%.
The proved developed producing BOE reserves life index is 21.2 years.
■
The net present value of future net revenues, before income tax, discounted at 10%, is $80.7 billion for total proved
reserves, $98.0 billion for total proved plus probable reserves and $61.4 billion for proved developed producing reserves.
5
Canadian Natural 2020 Annual Report
Summary of Company Gross Reserves
As of December 31, 2020
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)
Total Company
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
142
24
149
315
148
463
81
12
84
177
82
260
216
—
49
265
130
395
580
27
1,876
2,483
1,674
4,157
6,870
—
92
6,962
534
7,496
3,725
264
5,476
9,465
6,457
15,922
98
4
225
326
174
500
8,607
111
3,388
12,106
3,819
15,925
Reconciliation of Company Gross Reserves
As of December 31, 2020
Forecast Prices and Costs
TOTAL PROVED
Total Company
December 31, 2019
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2020
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)
357
—
2
3
—
1
—
(20)
4
(31)
315
202
—
—
3
—
—
—
(10)
8
(26)
177
293
—
—
—
—
—
—
(13)
6
(21)
265
2,438
—
17
—
73
—
—
—
45
(91)
2,483
6,352
—
720
—
—
—
—
—
43
(153)
6,962
6,460
—
226
290
—
2,932
(4)
(197)
297
(541)
9,465
275
—
11
13
—
31
—
(8)
19
(15)
326
10,993
—
787
66
73
521
(1)
(83)
175
(426)
12,106
TOTAL 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)
Total Company
December 31, 2019
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2020
Canadian Natural 2020 Annual Report
519
—
3
4
—
1
—
(18)
(15)
(31)
463
293
—
1
4
—
—
—
(13)
1
(26)
260
425
—
—
—
—
—
—
(5)
(4)
(21)
395
4,108
—
21
—
106
—
—
—
13
(91)
4,157
6,897
—
717
—
—
—
—
—
34
(153)
7,496
9,607
—
374
384
—
6,238
(5)
(249)
113
(541)
15,922
408
—
20
17
—
62
—
(9)
17
(15)
500
14,252
—
825
88
106
1,102
(1)
(86)
65
(426)
15,925
6
NOTES TO RESERVES:
1. Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.
2.
Information in the reserves data tables may not add due to rounding. BOE values and oil and gas metrics may not
calculate exactly due to rounding.
3. 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
WCS
Canadian Light Sweet
Cromer LSB
Edmonton C5+
Brent
Natural gas
AECO
BC Westcoast Station 2
Henry Hub
US$/bbl
C$/bbl
C$/bbl
C$/bbl
C$/bbl
US$/bbl
C$/MMBtu
C$/MMBtu
US$/MMBtu
2021
2022
2023
2024
2025
46.00
43.51
54.55
54.55
55.84
48.00
2.86
2.76
3.00
48.00
46.10
57.14
56.64
58.40
50.00
2.78
2.68
3.00
53.00
52.60
63.64
62.64
64.82
55.00
2.69
2.59
3.00
54.06
53.65
64.91
63.89
66.11
56.10
2.75
2.64
3.06
55.14
54.72
66.21
65.17
67.44
57.22
2.80
2.69
3.12
All prices increase at a rate of 2%/year after 2025.
A foreign exchange rate of 0.7700 US$/C$ for 2021 and 0.7700 US$/C$ after 2021 was used in the year-end 2020
evaluation.
4. A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil
(6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an
energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency
at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl
conversion ratio may be misleading as an indication of value.
5. Oil and gas metrics included herein are commonly used in the crude 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.
6. Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive
of production.
7. 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.
8. Reserves Life Index is based on the amount for the relevant reserves category divided by the 2021 proved developed
producing production forecast prepared by the Independent Qualified Reserves Evaluators.
9. Finding, Development and Acquisition (“FD&A”) costs excluding changes in Future Development Costs (“FDC”) are
calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2020 by the sum
of total additions and revisions for the relevant reserves category.
10. FD&A costs including changes in FDC are calculated by dividing the sum of total exploration, development and acquisition
capital costs incurred in 2020 and net changes in FDC from December 31, 2019 to December 31, 2020 by the sum of
total additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and
reclamation costs.
11. Abandonment, decommissioning and reclamation (“ADR”) costs included in the calculation of the Future Net Revenue
(FNR) consist of both the Company’s total Asset Retirement Obligation (“ARO”), before inflation and discounting, for
development existing as at December 31, 2020 and forecast estimates of ADR costs attributable to future development
activity.
7
Canadian Natural 2020 Annual Report
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 and Refining
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
9
10
12
13
18
20
21
23
27
28
29
32
34
36
37
38
39
42
44
45
45
Canadian Natural 2020 Annual Report
8
Definitions and Abbreviations
AECO
AIF
AOSP
API
ARO
bbl
bbl/d
Bcf
Bcf/d
Bitumen
BOE
BOE/d
Brent
C$
CAGR
CAPEX
CO2
CO2e
Crude oil
CSS
EOR
E&P
FASB
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
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
barrels of oil equivalent
barrels of oil equivalent per day
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
MMcf/d
NGLs
NWRP
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
million cubic feet per day
natural gas liquids
North West Redwater Partnership
NYMEX
New York Mercantile Exchange
NYSE
OPEC+
PRT
SAGD
SCO
SEC
Tcf
TSX
UK
US
US$
WCS
WCS Heavy
Differential
WTI
New York Stock Exchange
Organization of the Petroleum Exporting
Countries Plus
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
generally accepted accounting principles
in the United States
United States dollars
Western Canadian Select
WCS Heavy Differential from WTI
West Texas Intermediate reference
location at Cushing, Oklahoma
Financial Accounting Standards Board
US GAAP
Horizon
Horizon Oil Sands
IASB
International Accounting Standards Board
9
Canadian Natural 2020 Annual Report
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",
"aspiration" 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 targets 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, without limitation, those
in relation to the Company's assets at Horizon, AOSP, Primrose thermal oil projects, the Pelican Lake water and polymer
flood projects, the Kirby Thermal Oil Sands Project, the Jackfish Thermal Oil Sands Project, 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, NGLs or SCO that the Company may be reliant upon to transport its products
to market, the development and deployment of technology and technological innovations, the assumption of operations at
processing facilities, the financial capacity of the Company to complete its growth projects and responsibly and sustainably
grow in the long term, and the "Outlook" section of this MD&A, particularly in reference to the 2021 targets 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 (including as a result of effects of the novel coronavirus
("COVID-19") pandemic and the actions of OPEC+) which may impact, among other things, demand and supply for and
market prices of the Company’s products, and the availability and cost of resources required by the Company's operations;
volatility of and assumptions regarding crude oil and natural gas and NGLs prices including due to actions of OPEC+ taken in
response to COVID-19 or otherwise; fluctuations in currency and interest rates; assumptions on which the Company’s current
targets are 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 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, maintain, and operate 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; the Company’s ability to meet its targeted production levels; 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 (including production curtailments mandated by the Government of Alberta); 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
sufficiency of the Company’s liquidity to support its growth strategy and to sustain its operations in the short, medium, and
long term; the strength of the Company’s balance sheet; the flexibility of the Company’s capital structure; the adequacy of the
Canadian Natural 2020 Annual Report
10
Company’s provision for taxes; the continued availability of the Canada Emergency Wage Subsidy ("CEWS") or other subsidies;
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, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other
amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection
regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove
incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact
of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent
upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all
information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed
in this 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 in this MD&A, 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 and net capital expenditures. These financial measures are
not defined by IFRS and therefore are referred to as non-GAAP financial measures. The non-GAAP financial measures used by
the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP
financial measures to evaluate its performance. The non-GAAP financial 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 financial 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 financial 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 financial 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
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 for the year ended December 31,
2020. It should also be read in conjunction with the Company's MD&A for the three months and year ended December 31,
2020, 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 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 in this MD&A for information purposes only.
The following discussion and analysis refers primarily to the Company’s 2020 financial results compared to 2019 and 2018,
unless otherwise indicated. In addition, this MD&A details the Company's targeted capital program for 2021. Additional
information relating to the Company, including its quarterly MD&A for the three months and year ended December 31, 2020,
its Annual Information Form for the year ended December 31, 2020, and its audited consolidated financial statements for
the year ended December 31, 2020, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. Information
on the Company's website does not form part of and is not incorporated by reference in this MD&A. This MD&A is dated
March 3, 2021.
11
Canadian Natural 2020 Annual Report
Objectives and Strategy
The Company’s objectives are to increase crude oil and natural gas production, reserves, cash flow and net asset value (1)
on a per common share basis through the economic and sustainable 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 in a
sustainable and responsible way, maintaining a commitment to environmental stewardship and safety excellence.
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, development and exploration;
■ Balance between sources and terms of debt financing and a strong financial position; and
■ Commitment to environmental stewardship throughout the decision-making process.
(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 and embrace
the key piece of the Company's mission statement: "doing it right". 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 the Company’s
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. The Company's financial discipline, commitment to a strong balance sheet, and capacity to internally generate
cash flows provides the means to responsibly and sustainably grow in the long term.
Canadian Natural 2020 Annual Report
12
Financial and Operational Highlights
($ millions, except per common share amounts)
Product sales (1)
Crude oil and NGLs
Natural gas
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
Dividends declared per common share (4)
Total assets
Total long-term liabilities
Cash flows used in investing activities
Net capital expenditures (5)
Average sales price (6)
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)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2020
17,491
15,579
1,478
$
$
$
(435) $
(0.37) $
(0.37) $
2019
24,394
22,950
1,419
5,416
4.55
4.54
(756) $
3,795
(0.64) $
(0.64) $
4,714
5,200
4.40
4.40
1.70
75,276
37,818
2,819
3,206
31.90
2.40
43.98
$
$
$
$
$
$
$
$
$
$
$
$
3.19
3.18
8,829
10,267
8.62
8.61
1.50
78,121
36,493
7,255
7,121
55.08
2.34
70.18
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
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
1,164,136
1,098,957
1,078,813
917,958
1,477
850,393
1,491
820,778
1,548
Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements.
(1)
(2) Adjusted net earnings (loss) from operations is a non-GAAP financial 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 its 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.
(3) Adjusted funds flow is a non-GAAP financial 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 expenditures and movements in other long-term assets,
including the unamortized cost of the share bonus program, accrued interest on subordinated debt advances to NWRP and prepaid cost of service tolls.
The Company considers adjusted funds flow a key measure in evaluating its performance 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.
(4) On March 3, 2021, the Board of Directors approved an increase in the quarterly dividend to $0.47 per common share, beginning with the dividend payable
on April 5, 2021. On March 4, 2020, the Board of Directors approved an increase in the quarterly dividend to $0.425 per common share. On March 6, 2019,
the Board of Directors approved an increase in the quarterly dividend to $0.375 per common share. On February 28, 2018, the Board of Directors approved
an increase in the quarterly dividend to $0.335 per common share.
(5) Net capital expenditures is a non-GAAP financial measure that represents cash flows used in investing activities as presented in the Company's
consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, the repayment of NWRP subordinated debt advances,
investment in other long-term assets, abandonment expenditures and other. The Company considers net capital expenditures a key measure as it provides
an understanding of the Company’s capital spending activities in comparison to the Company's annual capital budget. The reconciliation "Net Capital
Expenditures, as Reconciled to Cash Flows used in Investing Activities" is presented in the "Net Capital Expenditures" section of this MD&A. Net capital
expenditures may not be comparable to similar measures presented by other companies.
(6) Net of blending and feedstock costs and excluding risk management activities.
13
Canadian Natural 2020 Annual Report
ADJUSTED NET EARNINGS (LOSS) FROM OPERATIONS, AS RECONCILED TO NET EARNINGS (LOSS)
($ 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 (gain) loss, net of tax (3)
Realized foreign exchange gain on settlement of cross currency swaps,
net of tax (4)
Realized foreign exchange loss on repayment of US dollar debt
securities, net of tax (5)
Gain on acquisition, disposition and revaluation, net of tax (6)
Loss from investments, net of tax (7) (8)
Provision for pipeline project, net of tax (9)
2020
2019
$
(435)
$
5,416
$
(86)
(31)
(116)
(166)
—
(217)
185
110
210
14
(548)
—
—
—
321
—
Effect of statutory tax rate and other legislative changes on deferred
income tax liabilities (10)
—
(1,618)
2018
2,591
(146)
(36)
706
—
146
(372)
374
—
—
Adjusted net earnings (loss) from operations
$
(756)
$
3,795
$
3,263
(1) Share-based compensation includes costs incurred under the Company's Stock Option Plan and Performance Share Unit ("PSU") plan. The Company’s
Stock Option Plan provides for a cash payment option. The PSU plan provides certain executive employees of the Company with the right to receive a cash
payment, the amount of which is determined by individual employee performance and the extent to which certain other performance measures are met.
Accordingly, the fair value of the outstanding vested options is recognized 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 recognized 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 2020, the Company settled the US$500 million cross currency swaps designated as cash flow hedges of the US$500 million 3.45% US dollar debt
securities due November 2021. The Company realized cash proceeds of $166 million on settlement.
(5) During 2018, the Company repaid US$600 million of 1.75% notes and US$400 million of 5.90% notes.
(6) During 2020, the Company recognized a pre- and after-tax gain of $217 million related to the acquisition of Painted Pony Energy Ltd. ("Painted Pony"). During
2018, the Company recognized 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 recognized a pre-tax gain of $277 million ($263 million after-tax)
related to acquisitions in the North America Exploration and Production segment. The Company recognized 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.
The Company's investment in the 50% owned NWRP is accounted for using the equity method of accounting. Included in the non-cash loss from
investments is the Company's pro rata share of NWRP's equity loss recognized for the period.
The Company’s investments in PrairieSky Royalty Ltd. ("PrairieSky") and Inter Pipeline Ltd. ("Inter Pipeline") have been accounted for at fair value through
profit and loss and are remeasured each period with changes in fair value recognized in net earnings (loss).
(7)
(8)
(9) During 2020, the Company recognized a provision in transportation, blending and feedstock expense of $143 million ($110 million after-tax) relating to the
Keystone XL pipeline project.
(10) All substantively enacted adjustments in applicable income tax rates and other legislative changes are applied to the 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 recognized
in net earnings (loss) during the period the legislation is substantively enacted. During 2019, the Government of Alberta enacted legislation that decreased
the provincial corporate income tax rate from 12% to 11% effective July 1, 2019, with a further 1% rate reduction every year on January 1 until the provincial
corporate income tax rate is 8% on January 1, 2022. As a result of this corporate income tax rate reduction, the Company's deferred corporate income tax
liability decreased by $1,618 million. During 2020, the Government of Alberta substantively enacted legislation to accelerate this reduction, lowering the
corporate tax rate from 10% to 8%, effective July 1, 2020. This acceleration did not have a significant impact on the Company's deferred corporate income
tax liability for 2020.
ADJUSTED FUNDS FLOW, AS RECONCILED TO CASH FLOWS FROM OPERATING ACTIVITIES
($ millions)
Cash flows from operating activities
Net change in non-cash working capital
Abandonment expenditures (1)
Other (2)
Adjusted funds flow
2020
$
4,714
$
166
249
71
2019
8,829
1,033
296
109
2018
$
10,121
(1,346)
290
23
$
5,200
$
10,267
$
9,088
(1)
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.
(2) Movements in other long-term assets, including the unamortized cost of the share bonus program, accrued interest on subordinated debt advances to
NWRP and prepaid cost of service tolls.
Canadian Natural 2020 Annual Report
14
CONSOLIDATED NET EARNINGS (LOSS) AND ADJUSTED NET EARNINGS (LOSS)
For 2020, the Company reported a net loss of $435 million compared with net earnings of $5,416 million for 2019 (2018 – net
earnings of $2,591 million). The net loss for 2020 included net after-tax income of $321 million related to the effects of share-
based compensation, risk management activities, fluctuations in foreign exchange rates, the foreign exchange gain on the
settlement of the cross currency swaps, the gain on acquisition, disposition and revaluation, the loss from investments, and
a provision relating to the Keystone XL pipeline project (2019 – $1,621 million after-tax income; 2018 – $672 million after-tax
expense). Excluding these items, the adjusted net loss from operations for 2020 was $756 million compared with adjusted
net earnings from operations of $3,795 million for 2019 (2018 – adjusted net earnings from operations of $3,263 million).
The net loss and the adjusted net loss from operations for 2020 compared with net earnings and adjusted net earnings from
operations for 2019 primarily reflected:
■
■
■
lower crude oil and NGLs netbacks in the Exploration and Production segments;
lower realized SCO prices in the Oil Sands Mining and Upgrading segment; and
higher depletion, depreciation and amortization;
partially offset by:
■
■
■
higher crude oil and NGLs sales volumes in the North America Exploration and Production segment;
higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; and
higher natural gas netbacks in the Exploration and Production segments.
A detailed reconciliation of the changes in the Company's product sales is provided in the "Analysis of Changes in Product
Sales" section of this MD&A.
The impacts of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the gain on
acquisition, disposition, and revaluation, and the impact of statutory tax rate and other legislative changes on deferred income
tax liabilities also contributed to the movements in net earnings (loss) for 2020 from 2019. These items are discussed in detail
in the relevant sections of this MD&A.
CASH FLOWS FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW
Cash flows from operating activities for 2020 were $4,714 million compared with $8,829 million for 2019 (2018 – $10,121
million). The decrease in cash flows from operating activities for 2020 from 2019 were primarily due to the factors previously
noted relating to the fluctuations in net earnings (loss) and adjusted net earnings (loss) from operations (excluding the effects
of depletion, depreciation and amortization, the gain on acquisition, disposition and revaluation and the impact of statutory
tax rate and other legislative changes on deferred income tax liabilities), as well as due to the impact of changes in non-cash
working capital.
Adjusted funds flow for 2020 was $5,200 million ($4.40 per common share) compared with $10,267 million for 2019 ($8.62
per common share) (2018 – $9,088 million; $7.46 per common share). The decrease in adjusted funds flow for 2020 from 2019
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 expenditures and movements in other long-term assets,
including the unamortized cost of the share bonus program, accrued interest on subordinated debt advances to NWRP and
prepaid cost of service tolls.
PRODUCTION VOLUMES
Total production of crude oil and NGLs before royalties for 2020 increased 8% to average 917,958 bbl/d from 850,393
bbl/d in 2019 (2018 – 820,778 bbl/d). The increase in crude oil and NGLs production for 2020 from 2019 primarily reflected
the acquisition of Jackfish assets, increased thermal oil production at Kirby North, and high utilization rates and operational
enhancements in the Oil Sands Mining and Upgrading segment.
Total natural gas production before royalties for 2020 averaged 1,477 MMcf/d, comparable with 1,491 MMcf/d in 2019 (2018
– 1,548 MMcf/d).
Total production before royalties for 2020 of 1,164,136 BOE/d increased 6% from 1,098,957 BOE/d in 2019 (2018 – 1,078,813
BOE/d). Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production" section of
this MD&A.
15
Canadian Natural 2020 Annual Report
PRODUCT PRICES
The Company’s realized pricing reflects prevailing benchmark pricing. In the Company’s Exploration and Production segments,
the 2020 crude oil and NGLs sales price decreased 42% to average $31.90 per bbl from $55.08 per bbl in 2019 (2018 – $46.92
per bbl), and the 2020 natural gas price increased 3% to average $2.40 per Mcf from $2.34 per Mcf in 2019 (2018 – $2.61
per Mcf). In the Oil Sands Mining and Upgrading segment, the Company’s 2020 SCO sales price decreased 37% to average
$43.98 per bbl from $70.18 per bbl in 2019 (2018 – $68.61 per bbl). Crude oil and NGLs and natural gas product prices are
discussed in detail in the "Business Environment", "Exploration and Production" and the "Oil Sands Mining and Upgrading"
sections of this MD&A.
PRODUCTION EXPENSE
In the Company’s Exploration and Production segments, the 2020 crude oil and NGLs production expense decreased 10%
to average $12.42 per bbl from $13.81 per bbl in 2019 (2018 – $15.69 per bbl), and the 2020 natural gas production expense
decreased 3% to average $1.18 per Mcf from $1.22 per Mcf in 2019 (2018 – $1.36 per Mcf). In the Oil Sands Mining and
Upgrading segment, the Company's 2020 production cost decreased 9% to average $20.46 per bbl from $22.56 per bbl in
2019 (2018 – $21.75 per bbl). Crude oil and NGLs and natural gas production expense is discussed in detail in the "Exploration
and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.
SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company’s quarterly financial results for the eight most recently completed quarters:
($ millions, except per common share amounts)
2020
Product sales (1)
Crude oil and NGLs
Natural gas
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
($ millions, except per common share amounts)
2019
Product sales (1)
Crude oil and NGLs
Natural gas
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
Total
17,491
15,579
1,478
(435)
(0.37)
(0.37)
Total
24,394
22,950
1,419
5,416
4.55
4.54
$
$
$
$
$
$
$
$
$
$
$
$
Dec 31
5,219
4,592
496
749
0.63
0.63
Dec 31
6,335
5,947
382
597
0.50
0.50
$
$
$
$
$
$
$
$
$
$
$
$
Sep 30
4,676
4,202
338
408
0.35
0.35
Sep 30
6,587
6,324
257
1,027
0.87
0.87
$
$
$
$
$
$
$
$
$
$
$
$
Jun 30
2,944
2,462
307
(310)
(0.26)
(0.26)
Jun 30
5,931
5,597
324
2,831
2.37
2.36
$
$
$
$
$
$
$
$
$
$
$
$
Mar 31
4,652
4,323
337
(1,282)
(1.08)
(1.08)
Mar 31
5,541
5,082
456
961
0.80
0.80
$
$
$
$
$
$
$
$
$
$
$
$
(1)
Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements.
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 OPEC+ and its impact
on world supply; the impact of geopolitical and market uncertainties, including those due to COVID-19 and in connection
with governmental responses to COVID-19, on worldwide benchmark pricing; the impact of shale oil production in North
America; the impact of the WCS Heavy Differential from WTI including the impact of a shortage of takeaway capacity out
of the Western Canadian Sedimentary Basin (the "Basin"); the impact of the differential between WTI and Brent benchmark
pricing in the North Sea and Offshore Africa; and the impact of production curtailments mandated by the Government of
Alberta that came into effect on January 1, 2019 and were suspended effective December 1, 2020.
■ 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.
Canadian Natural 2020 Annual Report
16
■ Crude oil and NGLs sales volumes – Fluctuations in production due to the cyclic nature of the Company’s Primrose
thermal oil projects, production from the Kirby Thermal Oil Sands Project, the results from the Pelican Lake water and
polymer flood projects, fluctuations in the Company’s drilling program in North America and the International segments,
the impact and timing of acquisitions, including the acquisition of assets from Devon Canada Corporation ("Devon"), as
well as the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, production curtailments
mandated by the Government of Alberta that came into effect January 1, 2019 and were suspended effective December
1, 2020, and the impact of shut-in production due to lower demand during COVID-19. Sales volumes also reflected
fluctuations due to timing of liftings and maintenance activities in the International segments.
■ Natural gas sales volumes – Fluctuations in production due to the Company’s allocation of capital to higher return
crude oil projects, natural decline rates, shut-in production due to low commodity prices and the impact and timing of
acquisitions, including the acquisition of Painted Pony.
■ 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, the impact of increased carbon tax and energy costs,
cost optimizations across all segments, the impact and timing of acquisitions, the impact of turnarounds and pitstops in
the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments.
■ Transportation, blending and feedstock expense – Fluctuations due to the provision recognized relating to the Keystone
XL pipeline project in 2020.
■ Depletion, depreciation and amortization expense – Fluctuations due to changes in sales volumes including the impact
and timing of acquisitions and dispositions, proved reserves, asset retirement obligations, finding and development costs
associated with crude oil and natural gas exploration, estimated future costs to develop the Company’s proved undeveloped
reserves, fluctuations in International sales volumes subject to higher depletion rates, and the impact of turnarounds and
pitstops in the Oil Sands Mining and Upgrading segment.
■ Share-based compensation – Fluctuations due to the measurement of fair market value 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.
■
■
Interest expense – Fluctuations due to changing long-term debt levels, and the impact of movements in benchmark
interest rates on outstanding floating rate long-term debt.
Foreign exchange – Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the
Company receives 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.
■ Gain on acquisition and gains/losses on investments – Fluctuations due to the recognition of a gain on the acquisition
of Painted Pony, fair value changes in the investments in PrairieSky and Inter Pipeline shares, and the equity loss on the
Company's interest in NWRP.
■
Income tax expense – Fluctuations due to statutory tax rate and other legislative changes substantively enacted in the
various periods.
17
Canadian Natural 2020 Annual Report
Business Environment
Global benchmark crude oil prices decreased significantly in the first half of 2020 due to the erosion of global demand,
reflecting the severity of COVID-19 and related economic conditions. In April 2020, in response to the collapse of crude oil
prices, OPEC+ agreed to cut 9.7 MMbbl/d of production through July 2020. As the global economy improved in the latter
part of the year, OPEC+ agreed to ease these production cuts to 7.2 MMbbl/d, as of January 2021. Furthermore, the initial
rollout of the COVID-19 vaccine in the fourth quarter of 2020 had an overall positive impact on global demand for crude oil.
Pricing improved in the fourth quarter of 2020 with WTI benchmark pricing averaging US$42.67 per bbl and the WCS Heavy
Differential averaging US$9.30 per bbl. Subsequent to December 31, 2020, Saudi Arabia committed to reduce its production
by 1.0 MMbbl/d, which had a further positive impact on crude oil pricing.
PRODUCTION FLEXIBILITY AND COST CONTROL
The Company continues to be nimble and act decisively to make appropriate operational improvements to increase efficiencies
and cost control and mitigate the impact of the decline in commodity pricing across all of its operations. To mitigate the impact
of realized pricing on certain crude oil products, the Company optimizes the production profile across its diverse asset base.
The Company implemented changes to its compensation program in light of current commodity volatility, and these changes
had an immediate impact on the Company's costs, effective April 2020. The Company is also working diligently to reduce
production costs wherever possible, asking all stakeholders to contribute to the sustainability of operations.
The Company continued to prioritize the optimization of higher value light crude oil, NGLs and SCO, representing approximately
47% of total corporate BOE production volumes for 2020. Optimization of production volumes continues to be a key focus of
the Company at current commodity price levels.
Production costs throughout 2020 also reflected the impact of measures to promote social distancing and other precautionary
measures related to COVID-19 at the Company's head office and field locations, both internationally and in North America.
The Company continues to mitigate the impact of these costs through its focus on cost control and efficiencies across the
asset base.
CANADA EMERGENCY WAGE SUBSIDY
On March 27, 2020, in response to COVID-19, the Government of Canada announced the CEWS. The CEWS enables eligible
Canadian employers who have been impacted by COVID-19 to apply for a subsidy of a specified amount of eligible employee
wages. The Company was eligible for the subsidy in 2020 as its qualifying revenues declined by the specified amount as
compared with the prior year reference period.
LIQUIDITY
As at December 31, 2020, the Company had undrawn revolving bank credit facilities of $4,958 million. Including cash and cash
equivalents and short-term investments, the Company had approximately $5,447 million in liquidity. The Company also has
certain other dedicated credit facilities supporting letters of credit.
The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital
structure. Refer to the “Liquidity and Capital Resources” section of this MD&A for further details.
CAPITAL SPENDING
Safe, reliable, effective and efficient operations continues to be a focus for the Company. On December 9, 2020, the Company
announced its 2021 capital budget targeted at approximately $3,205 million, of which $1,345 million is related to conventional
and unconventional assets and $1,860 million is allocated to long-life low decline assets. Production for 2021 is targeted
between 1,190,000 BOE/d and 1,260,000 BOE/d. Annual budgets are developed and scrutinized throughout the year and can
be changed, if necessary, in the context of price volatility, project returns and the balancing of project risks and time horizons.
The 2021 capital budget and production targets constitute forward-looking information. Refer to the "Advisory" section of this
MD&A for further details on forward-looking statements.
RISKS AND UNCERTAINTIES
COVID-19 continues to have the potential to further disrupt the Company’s operations, projects and financial condition
through the disruption of the local or global supply chain and transportation services, or the loss of manpower resulting from
quarantines that affect the Company’s labour pools in their local communities, workforce camps or operating sites or that are
instituted by local health authorities as a precautionary measure, any of which may require the Company to temporarily reduce
or shutdown its operations depending on their extent and severity.
Canadian Natural 2020 Annual Report
18
BENCHMARK COMMODITY PRICES
(Yearly average)
WTI benchmark price (US$/bbl)
Dated Brent benchmark price (US$/bbl)
WCS Heavy Differential from WTI (US$/bbl)
SCO price (US$/bbl)
Condensate benchmark price (US$/bbl)
Condensate Differential from WTI (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$)
2020
39.40
42.27
12.57
36.26
36.97
2.43
2.08
2.12
0.7454
0.7840
$
$
$
$
$
$
$
$
$
$
2019
57.04
64.04
12.79
56.35
52.84
4.20
2.63
1.54
0.7536
0.7713
$
$
$
$
$
$
$
$
$
$
2018
64.78
71.12
26.29
58.62
60.98
3.80
3.08
1.45
0.7717
0.7328
$
$
$
$
$
$
$
$
$
$
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 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. Product revenue continued to be
impacted by the volatility of 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.
On January 1, 2019, the Government of Alberta implemented a mandatory curtailment program that has been successful in
mitigating the discount in crude oil pricing received in Alberta for both light crude oil and heavy crude oil. The Government of
Alberta extended the mandatory curtailment program to December 31, 2021; however, curtailment production limits were
suspended effective December 1, 2020 and curtailment orders will only be issued in 2021 if deemed necessary by the
Government of Alberta.
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$39.40
per bbl for 2020, a decrease of 31% from US$57.04 per bbl for 2019 (2018 – US$64.78 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$42.27 per bbl for
2020, a decrease of 34% from US$64.04 per bbl for 2019 (2018 – US$71.12 per bbl).
The decrease in WTI and Brent pricing for 2020 from 2019 primarily reflected significant reductions in refinery utilization due
to decreased demand for refined products as a result of COVID-19, resulting in an oversupply of crude oil in the market.
The WCS Heavy Differential averaged US$12.57 per bbl for 2020, comparable with US$12.79 per bbl for 2019 (2018 – US$26.29
per bbl).
The SCO price averaged US$36.26 per bbl for 2020, a decrease of 36% from US$56.35 per bbl for 2019 (2018 –
US$58.62 per bbl). The decrease in SCO pricing for 2020 from 2019 primarily reflected decreases in WTI benchmark pricing.
NYMEX natural gas prices averaged US$2.08 per MMBtu for 2020, a decrease of 21% from US$2.63 per MMBtu for 2019
(2018 – US$3.08 per MMBtu). The decrease in NYMEX natural gas prices for 2020 from 2019 primarily reflected supply
exceeding North American demand due to the impact of COVID-19, and lower Liquefied Natural Gas exports.
AECO natural gas prices averaged $2.12 per GJ for 2020, an increase of 38% from $1.54 per GJ for 2019 (2018 – $1.45 per
GJ). The increase in AECO natural gas prices for 2020 from 2019 primarily reflected lower production levels from the Basin.
19
Canadian Natural 2020 Annual Report
Analysis of Changes in Product Sales
($ millions)
North America
Changes due to
Changes due to
2018
Volumes
Prices Other
2019
Volumes
Prices Other
2020
Crude oil and NGLs $ 7,254
$ 1,055
$ 1,375
$
(5)
$ 9,679
$ 1,582
$ (3,781)
$ — $ 7,480
1,256
—
8,510
(40)
—
(76)
—
1,015
1,299
10
6
11
—
—
5
5
1
8
(3)
1,150
6
8
—
84
—
10,835
1,590
(3,697)
860
57
5
922
632
67
8
707
(135)
(29)
—
(164)
(116)
(27)
—
(143)
(308)
(16)
—
(324)
(198)
2
—
(196)
—
35
35
—
—
(2)
(2)
—
—
10
10
1,242
41
8,763
417
12
3
432
318
42
18
378
(56)
(12)
Natural gas
Other (1)
North Sea
Crude oil and NGLs
Natural gas
Other (1)
Offshore Africa
Crude oil and NGLs
Natural gas
Other (1)
753
140
—
893
628
70
—
698
Oil Sands Mining
and Upgrading
Crude oil and NGLs
11,521
Other (1)
—
11,521
Midstream and
Refining
Midstream
activities
Refined products
and other (1)
Intersegment
eliminations
and other (2)
Product sales
Other (1)
102
—
102
558
—
558
114
(34)
—
80
72
(5)
—
67
(710)
—
(710)
—
—
—
—
—
—
(7)
(49)
—
(56)
1
—
(55)
560
—
560
—
—
—
—
—
—
(31)
11,340
6
6
(25)
11,346
470
—
470
(4,421)
—
(4,421)
—
133
133
7,389
139
7,528
(14)
—
(14)
(62)
—
(62)
88
—
88
496
—
496
—
—
—
—
—
—
—
—
—
—
—
—
(5)
202
197
(422)
31
(391)
83
202
285
74
31
105
Total
$ 22,282
$
452
$ 1,748
$ (88)
$ 24,394
$ 1,753
$ (8,638)
$ (18)
$ 17,491
(1)
Includes the sale of diesel and other refined products and other income, including government grants and recoveries associated with the joint operations
partners' share of the costs of lease contracts.
(2) 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 decreased 28% to $17,491 million for 2020 from $24,394 million for 2019 (2018 – $22,282 million). The decrease
in product sales was primarily a result of lower WTI benchmark pricing due to decreased demand for refined products as a
result of COVID-19. The decrease in realized pricing was partially offset by the impact of increased crude oil and NGLs sales
volumes following the acquisition of Jackfish assets, increased thermal oil production at Kirby North, and high utilization
rates and operational enhancements in the Oil Sands Mining and Upgrading segment. Crude oil and NGLs and natural gas
pricing are discussed in detail in the "Business Environment", "Exploration and Production" and the "Oil Sands Mining and
Upgrading" sections of this MD&A. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily
Production" section of this MD&A.
For 2020, 5% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America
(2019 – 7%; 2018 – 7%). North Sea accounted for 3% of crude oil and NGLs and natural gas product sales for 2020 (2019 – 4%;
2018 – 4%), and Offshore Africa accounted for 2% of crude oil and NGLs and natural gas product sales for 2020 (2019 – 3%;
2018 – 3%).
Canadian Natural 2020 Annual Report
20
Daily Production
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 and Refining revenue)
Crude oil and NGLs
Natural gas
(1) SCO production before royalties excludes SCO consumed internally as diesel.
(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)
2020
2019
2018
460,443
417,351
23,142
17,022
917,958
405,970
395,133
27,919
21,371
350,961
426,190
23,965
19,662
850,393
820,778
1,450
1,443
1,490
12
15
24
24
32
26
1,477
1,491
1,548
1,164,136
1,098,957
1,078,813
11%
5%
6%
21%
36%
21%
91%
9%
13%
5%
8%
15%
36%
23%
94%
6%
13%
6%
8%
10%
39%
24%
93%
7%
2020
2019
2018
420,906
413,363
23,086
16,306
356,794
375,048
27,866
20,078
303,956
405,731
23,902
18,450
873,661
779,786
752,039
1,406
1,400
1,432
12
14
24
22
32
23
1,432
1,446
1,487
1,112,364
1,020,749
999,857
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 2020 production before royalties averaged 1,164,136 BOE/d, an increase of 6% from 1,098,957 BOE/d in 2019 (2018 –
1,078,813 BOE/d).
21
Canadian Natural 2020 Annual Report
Crude oil and NGLs production before royalties for 2020 averaged 917,958 bbl/d, an increase of 8% from 850,393 bbl/d for 2019
(2018 – 820,778 bbl/d). The increase in crude oil and NGLs production for 2020 from 2019 primarily reflected the acquisition of
Jackfish assets, increased thermal oil production at Kirby North, and high utilization rates and operational enhancements in the
Oil Sands Mining and Upgrading segment. Production for 2020 and 2019 reflected the impact of the Company's curtailment
optimization strategy as a result of mandatory Government of Alberta curtailment, which was suspended effective December
1, 2020.
Natural gas production before royalties accounted for 21% of the Company's total production in 2020 on a BOE basis. Natural
gas production for 2020 of 1,477 MMcf/d was comparable with 1,491 MMcf/d for 2019 (2018 – 1,548 MMcf/d).
Due to the uncertainty regarding COVID-19, the Company withdrew its 2020 corporate production guidance, however, annual
2020 crude oil and NGLs and natural gas production before royalties was within the previously issued corporate guidance
range.
North America – Exploration and Production
North America crude oil and NGLs production before royalties for 2020 averaged 460,443 bbl/d, an increase of 13% from
405,970 bbl/d for 2019 (2018 – 350,961 bbl/d). The increase in crude oil and NGLs production for 2020 from 2019 primarily
reflected the acquisition of Jackfish assets, increased thermal oil production at Kirby North, and the optimization of steam
cycles at Primrose. Production for 2020 and 2019 reflected the impact of mandatory Government of Alberta curtailment,
which was suspended effective December 1, 2020.
Thermal oil production before royalties for 2020 averaged 248,971 bbl/d, an increase of 48% from 167,942 bbl/d for 2019 (2018
– 107,839 bbl/d). The increase in thermal oil production for 2020 from 2019 primarily reflected volumes from the acquisition
of Jackfish assets, together with increased production from Kirby North and the optimization of steam cycles at Primrose.
Pelican Lake heavy crude oil production before royalties averaged 56,535 bbl/d for 2020, a decrease of 4% from 58,855 bbl/d
for 2019 (2018 – 63,082 bbl/d), demonstrating Pelican Lake’s long-life low decline production.
Natural gas production before royalties for 2020 of 1,450 MMcf/d increased slightly from 1,443 MMcf/d for 2019 (2018 – 1,490
MMcf/d). The increase in natural gas production for 2020 from 2019 primarily reflected added volumes from opportunities
identified by the Company in the first half of 2020 and the acquisition of Painted Pony on October 6, 2020, partially offset by
the impact of natural field declines.
North America – Oil Sands Mining and Upgrading
SCO production before royalties for 2020 of 417,351 bbl/d increased 6% from 395,133 bbl/d for 2019 (2018 – 426,190 bbl/d).
The increase in SCO production for 2020 from 2019 primarily reflected high utilization rates and operational enhancements,
partially offset by the impact of planned maintenance activities.
North Sea
North Sea crude oil production before royalties for 2020 of 23,142 bbl/d decreased 17% from 27,919 bbl/d for 2019 (2018 –
23,965 bbl/d). The decrease in production for 2020 from 2019 primarily reflected the permanent cessation of production at the
Banff and Kyle fields on June 1, 2020 and natural field declines.
Offshore Africa
Offshore Africa crude oil production before royalties for 2020 decreased 20% to 17,022 bbl/d from 21,371 bbl/d for 2019 (2018
– 19,662 bbl/d). The decrease in production for 2020 from 2019 primarily reflected natural field declines.
Corporate Production Targets for 2021
The Company targets production levels in 2021 to average between 920,000 bbl/d and 980,000 bbl/d of liquids production,
including crude oil, SCO and NGLs and between 1,620 MMcf/d and 1,680 MMcf/d of natural gas production. Production
targets constitute forward-looking information. Refer to the "Advisory" section of this MD&A for further details on forward-
looking statements.
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 segments on crude oil volumes held in various storage
facilities or FPSOs, as follows:
(bbl)
North Sea
Offshore Africa
2020
450,889
521,244
972,133
2019
344,726
519,504
864,230
2018
71,832
404,475
476,307
Canadian Natural 2020 Annual Report
22
Exploration and Production
OPERATING HIGHLIGHTS
Crude oil and NGLs ($/bbl) (1)
Sales price (2)
Transportation (3)
Realized sales price, net of transportation
Royalties
Production expense
Netback
Natural gas ($/Mcf) (1)
Sales price
Transportation
Realized sales price, net of transportation
Royalties
Production expense
Netback
Barrels of oil equivalent ($/BOE) (1)
Sales price (2)
Transportation (3)
Realized sales price, net of transportation
Royalties
Production expense
Netback
2020
2019
2018
$
31.90
$
55.08
$
46.92
3.85
28.05
2.59
12.42
3.48
51.60
6.08
13.81
13.04
$
31.71
$
2.40
0.43
1.97
0.08
1.18
0.71
$
$
2.34
0.42
1.92
0.08
1.22
0.62
$
$
3.08
43.84
5.08
15.69
23.07
2.61
0.47
2.14
0.08
1.36
0.70
26.15
$
40.50
$
34.62
$
$
$
$
3.44
22.71
1.89
10.67
3.14
37.36
4.09
11.49
$
10.15
$
21.78
$
2.96
31.66
3.27
12.71
15.68
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
(3) Excludes the impact of a $143 million provision recognized in 2020, relating to the Keystone XL pipeline project.
PRODUCT PRICES
Crude oil and NGLs ($/bbl) (1) (2)
North America
North Sea
Offshore Africa
Average
Natural gas ($/Mcf) (1)
North America
North Sea
Offshore Africa
Average
Average ($/BOE) (1) (2)
2020
2019
2018
$
$
$
$
$
$
$
$
$
30.31
50.09
50.95
31.90
2.34
2.74
7.77
2.40
26.15
$
$
$
$
$
$
$
$
$
51.43
86.76
83.68
55.08
2.18
6.52
7.41
2.34
40.50
$
$
$
$
$
$
$
$
$
41.82
87.41
90.95
46.92
2.33
12.08
7.34
2.61
34.62
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
North America – Product Prices
North America realized crude oil prices decreased 41% to average $30.31 per bbl for 2020 from $51.43 per bbl for 2019 (2018
– $41.82 per bbl), primarily due to lower WTI benchmark pricing due to decreased demand for refined products as a result of
COVID-19.
North America realized natural gas prices increased 7% to average $2.34 per Mcf for 2020 from $2.18 per Mcf for 2019 (2018
– $2.33 per Mcf). The increase in realized natural gas prices for 2020 from 2019 primarily reflected lower production levels
from the Basin.
23
Canadian Natural 2020 Annual Report
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 2020, the
Company contributed approximately 145,000 bbl/d of heavy crude oil blends to the WCS stream.
The Company has 20-year transportation agreements to ship 94,000 bbl/d of crude oil on the proposed Trans Mountain Pipeline
Expansion ("TMX"). The Canadian Energy Regulator ("CER") (formerly The National Energy Board) provided its recommendation
that construction of the pipeline should proceed and the Federal cabinet approved the project on June 18, 2019. The majority
of the TMX route has been approved but in October 2020, Trans Mountain applied for a variance from the CER to approve a
route change for a portion of the route. In January 2021, the CER issued a hearing order in respect of the alternative route.
Construction of the TMX is approximately 20% complete. However, construction activities have been subject to certain
disruptions and temporary suspensions in 2020 and 2021 related to COVID-19 impacts and other matters. TMX construction
is scheduled for completion by the end of 2022.
The Company also has 20-year transportation agreements to ship 200,000 bbl/d of crude oil on the proposed TC Energy
Keystone XL Pipeline. The presidential permit granted in 2019 was revoked on January 20, 2021 following the US presidential
inauguration. All pre-construction activities have been halted by TC Energy while it evaluates its potential options in light of
the latest regulatory hurdles. The Company has recognized a provision of $143 million ($110 million after-tax) in transportation,
blending and feedstock expense related to these matters.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
(Yearly average)
Wellhead Price (1) (2)
Light and medium crude oil and NGLs ($/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.
2020
2019
2018
$
$
$
$
$
33.42
33.57
31.81
28.11
2.34
$
$
$
$
$
49.54
57.82
55.38
48.27
2.18
$
$
$
$
$
52.87
43.30
38.98
33.66
2.33
North Sea – Product Prices
North Sea realized crude oil prices decreased 42% to average $50.09 per bbl for 2020 from $86.76 per bbl for 2019 (2018
– $87.41 per bbl). Realized crude oil prices per barrel in any particular year are dependent on the terms of the various sales
contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign exchange rates at the
time of lifting. The decrease in realized crude oil prices for 2020 from 2019 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 decreased 39% to average $50.95 per bbl for 2020 from $83.68 per bbl for 2019 (2018
– $90.95 per bbl). Realized crude oil prices per barrel in any particular year are dependent on the terms of the various sales
contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign exchange rates at
the time of lifting. The decrease in realized crude oil prices in 2020 reflected prevailing Brent benchmark pricing at the time of
liftings, together with the impact of movements in the Canadian dollar.
Canadian Natural 2020 Annual Report
24
ROYALTIES
Crude oil and NGLs ($/bbl) (1)
North America
North Sea
Offshore Africa
Average
Natural gas ($/Mcf) (1)
North America
Offshore Africa
Average
Average ($/BOE) (1)
2020
2019
2018
$
$
$
$
$
$
$
$
2.72
0.12
2.17
2.59
0.07
0.37
0.08
1.89
$
$
$
$
$
$
$
$
6.56
0.16
4.74
6.08
0.07
0.63
0.08
4.09
$
$
$
$
$
$
$
$
5.36
0.22
6.00
5.08
0.07
1.00
0.08
3.27
(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.
North America crude oil and natural gas royalties for 2020 and the comparable periods reflected movements in benchmark
commodity prices. North America crude oil royalties also reflected fluctuations in the WCS Heavy Differential and changes in
the production mix between high and low royalty rate product types.
Crude oil and NGLs royalty rates averaged approximately 9% of product sales for 2020 compared with 13% of product sales
for 2019 (2018 – 14%). The decrease in royalty rates for 2020 from 2019 primarily reflected lower realized crude oil prices.
Natural gas royalty rates averaged approximately 3% of product sales for 2020, comparable with 3% of product sales for 2019
(2018 – 4%).
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 4% for 2020 compared with 6% of product sales for
2019 (2018 – 7%). 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 ($/bbl) (1)
North America
North Sea
Offshore Africa
Average
Natural gas ($/Mcf) (1)
North America
North Sea
Offshore Africa
Average
Average ($/BOE) (1)
(1) Amounts expressed on a per unit basis are based on sales volumes.
2020
2019
2018
$
$
$
$
$
$
$
$
$
11.21
36.51
13.29
12.42
1.14
3.72
3.58
1.18
10.67
$
$
$
$
$
$
$
$
$
12.41
36.39
11.21
13.81
1.16
3.40
2.60
1.22
11.49
$
$
$
$
$
$
$
$
$
13.48
39.89
26.34
15.69
1.25
5.29
2.76
1.36
12.71
25
Canadian Natural 2020 Annual Report
North America – Production Expense
North America crude oil and NGLs production expense for 2020 averaged $11.21 per bbl, a decrease of 10% from $12.41
per bbl for 2019 (2018 – $13.48 per bbl). The decrease in crude oil and NGLs production expense per bbl for 2020 from 2019
primarily reflected the impact of increased thermal oil volumes, together with operating cost synergies at Jackfish.
North America natural gas production expense for 2020 averaged $1.14 per Mcf, comparable with $1.16 per Mcf for 2019 (2018
– $1.25 per Mcf). Natural gas production expense per Mcf for 2020 from 2019 primarily reflected the Company's strategy to
own and control its infrastructure and its continued focus on cost control.
North Sea – Production Expense
North Sea crude oil production expense for 2020 averaged $36.51 per bbl, comparable with $36.39 per bbl for 2019 (2018 –
$39.89 per bbl).
Offshore Africa – Production Expense
Offshore Africa crude oil production expense for 2020 averaged $13.29 per bbl, an increase of 19% from $11.21 per bbl for
2019 (2018 – $26.34 per bbl). The increase in crude oil production expense per bbl for 2020 from 2019 was primarily due to
lower volumes on a relatively fixed cost base. Offshore Africa production expense also reflected fluctuations in the Canadian
dollar.
DEPLETION, DEPRECIATION AND AMORTIZATION
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Expense
$/BOE (1)
2020
2019
$
3,780
$
3,326
$
277
190
4,247
15.45
$
$
308
242
3,876
15.22
$
$
$
$
2018
3,132
257
201
3,590
15.12
(1) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, depreciation and amortization expense for 2020 of $15.45 per BOE was comparable with $15.22 per BOE for 2019
(2018 – $15.12 per BOE).
ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Expense
$/BOE (1)
2020
97
30
6
133
0.48
$
$
$
2019
95
28
6
129
0.51
$
$
$
2018
87
29
9
125
0.53
$
$
$
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement
obligation due to the passage of time.
Asset retirement obligation accretion expense for 2020 of $0.48 per BOE decreased 6% from $0.51 per BOE for 2019 (2018 –
$0.53 per BOE). Fluctuations in asset retirement obligation accretion expense on a per BOE basis primarily reflect fluctuating
sales volumes.
Canadian Natural 2020 Annual Report
26
Oil Sands Mining and Upgrading
OPERATING HIGHLIGHTS
The Company continues to focus on safe, reliable and efficient operations and leveraging its technical expertise across the
Horizon and AOSP sites. Production in 2020 averaged 417,351 bbl/d, reflecting the ramp-up of production after the completion
of expansion activities at AOSP and the successful planned maintenance activities at Horizon, as well as the impact of the
Company's curtailment optimization strategy, including the suspension of mandatory Government of Alberta curtailment
effective December 1, 2020.
The Company incurred production costs, excluding natural gas costs, of $2,968 million for 2020, a $183 million, or 6%
decrease from 2019.
PRODUCT PRICES, ROYALTIES AND TRANSPORTATION
($/bbl) (1)
SCO realized sales price (2)
Bitumen value for royalty purposes (3)
Bitumen royalties (4)
Transportation
2020
43.98
25.82
0.51
1.23
$
$
$
$
2019
70.18
50.79
3.31
1.29
$
$
$
$
2018
68.61
40.02
3.09
1.61
$
$
$
$
(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 averaged $43.98 per bbl for 2020, a decrease of 37% from $70.18 per bbl for 2019 (2018 – $68.61
per bbl). The decrease in the realized SCO sales price for 2020 compared to 2019 primarily reflected the decrease in WTI
benchmark pricing.
Transportation expense averaged $1.23 per bbl for 2020, comparable with $1.29 per bbl for 2019 (2018 – $1.61 per bbl).
PRODUCTION COSTS
The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 22 to the
Company’s audited consolidated financial statements.
($ millions)
Production costs, excluding natural gas costs
Natural gas costs
Production costs
($/bbl) (1)
Production costs, excluding natural gas costs
Natural gas costs
Production costs
Sales (bbl/d)
(1) Amounts expressed on a per unit basis are based on sales volumes.
$
$
$
$
2020
2019
2,968
$
3,151
$
146
125
2018
3,265
102
3,114
$
3,276
$
3,367
2020
2019
19.50
$
21.70
$
0.96
0.86
20.46
$
22.56
$
2018
21.09
0.66
21.75
415,741
397,735
424,112
Production costs for 2020 decreased by $2.10 per bbl or 9% to $20.46 per bbl from $22.56 per bbl for 2019 (2018 – $21.75
per bbl). The decrease in production costs per bbl for 2020 from 2019 primarily reflected high reliability and operational
enhancements at both Horizon and AOSP. The Company continued to focus on cost control and efficiencies across the entire
asset base.
DEPLETION, DEPRECIATION AND AMORTIZATION
($ millions, except per bbl amounts)
Expense
$/bbl (1)
2020
1,784
11.73
$
$
2019
1,656
11.41
$
$
2018
1,557
10.06
$
$
(1) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, depreciation and amortization expense for 2020 of $11.73 per bbl was comparable with $11.41 per bbl for 2019 (2018
– $10.06 per bbl). Fluctuations in depletion, depreciation and amortization on a per barrel basis primarily reflect fluctuating
sales volumes from different underlying operations.
27
Canadian Natural 2020 Annual Report
ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per bbl amounts)
Expense
$/bbl (1)
2020
72
0.47
$
$
2019
61
0.42
$
$
2018
61
0.40
$
$
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement
obligation due to the passage of time.
Asset retirement obligation accretion expense for 2020 of $0.47 per bbl increased 12% from $0.42 per bbl for 2019 (2018 –
$0.40 per bbl). Fluctuations in asset retirement obligation accretion expense on a per barrel basis primarily reflect fluctuating
sales volumes.
Midstream and Refining
($ millions)
Product sales
2020
2019
2018
Crude oil and NGLs, midstream activities
$
83
$
NWRP, refined product sales
Segmented revenue
Less:
Production expenses
NWRP, refining toll
Midstream
NWRP, transportation and feedstock costs
Depreciation
Equity loss from investment in NWRP
Segmented earnings (loss) before taxes
202
285
166
18
181
15
—
$
88
—
88
—
20
—
14
287
102
—
102
—
21
—
14
5
62
$
(95)
$
(233)
$
The Company's Midstream and Refining 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 NWRP. Approximately 30% of the Company's
heavy crude oil production was 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 crude oils.
NWRP operates a 50,000 bbl/d bitumen upgrader and refinery that targets to process 12,500 bbl/d of bitumen feedstock
for the Company and 37,500 bbl/d of bitumen feedstock for the Alberta Petroleum Marketing Commission, an agent of the
Government of Alberta, under a 30-year fee-for-service tolling agreement.
On June 1, 2020, the refinery achieved the Commercial Operation Date, pursuant to the terms of the tolling agreement. The
Company is unconditionally obligated to pay its 25% pro rata share of the debt tolls over the 30-year tolling period. For the
year ended December 31, 2020, production of ultra-low sulphur diesel and other refined products averaged 58,694 BOE/d
(14,673 BOE/d to the Company).
NWRP has a secured $3,500 million syndicated credit facility, of which $2,000 million is revolving and matures in June 2021
and the remaining $1,500 million is fully drawn on a non-revolving basis. In 2019, NWRP extended the $1,500 million non-
revolving facility, previously scheduled to mature in February 2020, to February 2021. Subsequent to December 31, 2020,
NWRP extended the $1,500 million non-revolving facility to June 2021. As at December 31, 2020, NWRP had borrowings of
$2,866 million under the secured syndicated credit facility.
The Company's unrecognized share of the equity loss from NWRP for 2020 was $94 million (December 31, 2019 – recognized
equity loss of $287 million and unrecognized equity loss of $59 million; December 31, 2018 – recognized equity loss of $5
million). As at December 31, 2020, the cumulative unrecognized share of losses from NWRP was $153 million (December 31,
2019 – $59 million).
Canadian Natural 2020 Annual Report
28
Corporate and Other
ADMINISTRATION EXPENSE
($ millions, except per BOE amounts)
Expense
$/BOE (1)
2020
391
0.92
$
$
2019
344
0.86
$
$
2018
325
0.83
$
$
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for 2020 of $0.92 per BOE increased 7% from $0.86 per BOE for 2019 (2018 – $0.83 per BOE).
Administration expense per BOE increased for 2020 from 2019 primarily due to lower overhead recoveries and increased
corporate and personnel costs.
SHARE-BASED COMPENSATION
($ millions)
(Recovery) expense
2020
2019
$
(82)
$
223
$
2018
(146)
The Company’s Stock Option Plan provides employees with the right to receive common shares or a cash payment in exchange
for stock options surrendered. The PSU plan provides certain executive employees of the Company with the right to receive a
cash payment, the amount of which is determined by individual employee performance and the extent to which certain other
performance measures are met.
The Company recognized an $82 million share-based compensation recovery for 2020, primarily as a result of the measurement
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 2020 was an expense of $21 million related to PSUs
granted to certain executive employees (2019 – $49 million expense; 2018 – $8 million expense). For 2020, the Company
charged $5 million of share-based compensation costs to the Oil Sands Mining and Upgrading segment (2019 – $5 million
charged, 2018 – $19 million recovered).
INTEREST AND OTHER FINANCING EXPENSE
($ millions, except per BOE amounts and interest rates)
Expense, gross
Less: capitalized interest
Expense, net
$/BOE (1)
Average effective interest rate
$
$
$
2020
2019
780
$
889
$
24
756
1.77
3.5%
$
$
53
836
2.09
4.0%
$
$
2018
808
69
739
1.88
3.9%
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest and other financing expense for 2020 decreased from 2019 primarily due to lower interest rates. Capitalized
interest of $24 million for 2020 was related to residual project activities at Horizon.
Net interest and other financing expense per BOE for 2020 decreased 15% to $1.77 per BOE from $2.09 per BOE for 2019
(2018 – $1.88 per BOE). The decrease in net interest and other financing expense per BOE for 2020 from 2019 was primarily
due to lower average interest rates.
The Company’s average effective interest rate for 2020 decreased from 2019 primarily due to the impact of lower benchmark
interest rates on the Company's outstanding bank credit facilities and US commercial paper program.
29
Canadian Natural 2020 Annual Report
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency
exposures. These derivative financial instruments are not intended for trading or speculative purposes.
($ millions)
Foreign currency contracts
Natural gas financial instruments
Crude oil and NGLs financial instruments
Net realized loss (gain)
Foreign currency contracts
Natural gas financial instruments
Crude oil and NGLs financial instruments
Net unrealized (gain) loss
Net (gain) loss
2020
2019
2018
$
$
$
$
$
16
16
—
32
$
$
(3)
$
(36)
—
(39)
(7)
$
$
13
(1)
52
64
15
15
(17)
13
77
$
$
$
$
$
(77)
5
(27)
(99)
(47)
(4)
16
(35)
(134)
During 2020, net realized risk management losses were related to the settlement of foreign currency contracts and natural gas
financial instruments. The Company recorded a net unrealized gain of $39 million ($31 million after-tax) on its risk management
activities for 2020, including the impact of natural gas financial instruments from the Painted Pony acquisition in 2020 (2019 –
$13 million unrealized loss, $14 million after-tax; 2018 – $35 million unrealized gain, $36 million after-tax).
Further details related to outstanding derivative financial instruments at December 31, 2020 are disclosed in note 19 to the
Company's audited consolidated financial statements.
FOREIGN EXCHANGE
($ millions)
Net realized (gain) loss
Net unrealized (gain) loss
Net (gain) loss (1)
2020
2019
(159)
$
(22)
$
(116)
(548)
(275)
$
(570)
$
2018
121
706
827
$
$
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange gain for 2020 was primarily due to foreign exchange rate fluctuations on settlement of
working capital items denominated in US dollars or UK pounds sterling, and the settlement of the US$500 million cross
currency swaps in 2020. The net unrealized foreign exchange gain for 2020 was primarily related to the impact of a stronger
Canadian dollar with respect to outstanding US dollar debt. The net unrealized (gain) loss for each of the periods presented
reflected the impact of the cross currency swaps, including the settlement of US$500 million in cross currency swaps in
2020 (2020 – unrealized loss of $150 million, 2019 – unrealized loss of $71 million, 2018 – unrealized gain of $118 million). The
US/Canadian dollar exchange rate at December 31, 2020 was US$0.7840 (December 31, 2019 – US$0.7713, December 31,
2018 – US$0.7328).
Canadian Natural 2020 Annual Report
30
INCOME TAXES
($ millions, except income tax rates)
North America (1)
North Sea
Offshore Africa
PRT – North Sea
Other taxes
Current income tax (recovery) expense
Deferred corporate income tax (recovery) expense
Deferred PRT – North Sea
Deferred income tax (recovery) expense
Income tax (recovery) expense
Income tax rate and other legislative changes
2020
$
(245)
$
(4)
17
(31)
6
(257)
(181)
—
(181)
(438)
—
$
2019
354
112
44
(89)
13
434
(895)
1
(894)
(460)
1,618
$
(438)
$
1,158
$
2018
312
28
54
(29)
9
374
540
17
557
931
—
931
Effective income tax rate on adjusted net earnings (loss) from operations (2)
34%
25%
21%
Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments.
(1)
(2) Excludes the impact of current and deferred PRT and other current income tax.
The effective income tax rate for 2020 and the comparable years included the impact of non-taxable items in North America
and North Sea and the impact of differences in jurisdictional income and tax rates in the countries in which the Company
operates, in relation to net earnings (loss).
The current corporate income tax and PRT in the North Sea in 2020 and the comparable years included the impact of
carrybacks of abandonment expenditures related to decommissioning activities at the Company's platforms in the North Sea.
During 2019, the Government of Alberta enacted legislation that decreased the provincial corporate income tax rate from
12% to 11% effective July 1, 2019, with a further 1% rate reduction every year on January 1 until the provincial corporate
income tax rate is 8% on January 1, 2022. As a result of this corporate income tax rate reduction, the Company's deferred
corporate income tax liability decreased by $1,618 million for 2019. During 2020, the Government of Alberta substantively
enacted legislation to accelerate this reduction, lowering the corporate tax rate from 10% to 8%, effective July 1, 2020. This
acceleration did not have a significant impact on the Company's deferred corporate income tax liability for 2020.
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.
During 2020, the Company filed Scientific Research and Experimental Development claims of approximately $246 million
(2019 – $250 million; 2018 – $265 million) relating to qualifying research and development expenditures for Canadian income
tax purposes.
31
Canadian Natural 2020 Annual Report
Net Capital Expenditures (1)
($ millions)
Exploration and Evaluation
2020
2019
2018
Net property (dispositions) acquisitions (2)
$
(31)
$
Net expenditures
Total Exploration and Evaluation
Property, Plant and Equipment
Net property acquisitions (2) (3)
Well drilling, completion and equipping
Production and related facilities
Capitalized interest and other
Total Property, Plant and Equipment
Total Exploration and Production
Oil Sands Mining and Upgrading
Project costs
Sustaining capital
Turnaround costs
Acquisitions of Exploration and Evaluation assets (4)
Capitalized interest and other
Total Oil Sands Mining and Upgrading
Midstream and Refining
Abandonments (5)
Head office
Total net capital expenditures
By segment
North America (2) (3)
North Sea
Offshore Africa
Oil Sands Mining and Upgrading (4)
Midstream and Refining
Abandonments (5)
Head office
Total
36
5
536
429
580
60
1,605
1,610
258
839
196
—
30
$
90
74
164
3,208
775
1,028
81
5,092
5,256
436
933
118
—
38
(74)
122
48
98
1,446
1,262
106
2,912
2,960
438
665
112
218
14
1,323
1,525
1,447
5
249
19
10
296
34
13
290
21
3,206
$
7,121
$
4,731
1,389
$
4,831
$
2,671
$
$
122
99
1,323
5
249
19
196
229
1,525
10
296
34
131
158
1,447
13
290
21
$
3,206
$
7,121
$
4,731
(1) Net capital expenditures exclude the impact of lease assets and fair value and revaluation adjustments, and include non-cash transfers of property, plant
(2)
(3)
(4)
and equipment to inventory due to change in use.
Includes cash consideration paid of $91 million for exploration and evaluation assets and $3,126 million for property, plant and equipment acquired from
Devon in 2019.
Includes cash consideration of $111 million and the settlement of long-term debt of $397 million assumed in the acquisition of Painted Pony in 2020.
In the third quarter of 2018, total purchase consideration for the acquisition of the Joslyn oil sands project included $222 million for exploration and evaluation
assets and $4 million for asset retirement obligations assumed. In the fourth quarter of 2018, following integration of the Joslyn oil sands project into the
Horizon mine plan and determination of proved crude oil reserves, the exploration and evaluation assets were transferred to property, plant, and equipment.
(5) Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table.
Canadian Natural 2020 Annual Report
32
NET CAPITAL EXPENDITURES, AS RECONCILED TO CASH FLOWS USED IN INVESTING ACTIVITIES
($ millions)
2020
2019
Cash flows used in investing activities
$
2,819
$
7,255
$
(383)
124
—
249
397
(430)
—
—
296
—
2018
4,814
(345)
—
(28)
290
—
Net change in non-cash working capital (1)
Repayment of NWRP subordinated debt (2)
Investment in other long-term assets
Abandonment expenditures (3)
Other (4)
Net capital expenditures
$
3,206
$
7,121
$
4,731
Includes net working capital and other long-term assets of $195 million related to the acquisition of assets from Devon in 2019.
(1)
(2) Relates to a partial repayment of the Company's subordinated debt advances to NWRP.
(3)
The Company excludes abandonment expenditures from "Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities" in the "Financial
and Operational Highlights" section of this MD&A.
(4) Relates to the settlement of long-term debt assumed in the acquisition of Painted Pony in 2020.
The Company’s strategy is focused on building a diversified asset base that is balanced among various products. In order to
facilitate efficient operations, the Company concentrates its activities in core areas. The Company focuses on maintaining its
land inventories to enable the continuous development of play types and geological trends, greatly reducing overall exploration
risk. By owning associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby
increasing control over production expenses.
DRILLING ACTIVITY (1)
(number of net wells)
Net successful natural gas wells
Net successful crude oil wells (2)
Dry wells
Stratigraphic test / service wells
Total
Success rate (excluding stratigraphic test / service wells)
(1)
(2)
Includes drilling activity for North America and International segments.
Includes bitumen wells.
2020
2019
30
42
—
372
444
100%
19
86
3
447
555
97%
2018
18
483
9
615
1,125
98%
North America
During 2020, the Company targeted 30 net natural gas wells, 6 net primary heavy crude oil wells, 6 net bitumen (thermal oil)
wells and 29 net wells targeting light crude oil.
North Sea
During 2020, the Company completed 1 gross light crude oil well (1.0 on a net basis).
33
Canadian Natural 2020 Annual Report
Liquidity and Capital Resources
($ 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
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)
2020
2019
$
626
$
241
$
2018
(601)
$
21,453
$
20,982
$
20,623
184
139
101
$
21,269
$
20,843
$
20,522
$
9,606
$
9,533
$
9,323
22,766
25,424
8
34
22,529
122
$
32,380
$
34,991
$
31,974
40%
37%
(1)%
—%
37%
30%
16%
11%
39%
34%
8%
6%
Includes the current portion of long-term debt (2020 - $1,343 million, 2019 - $2,391 million, 2018 - $1,141 million).
Long-term debt is stated at its carrying value, net of original issue discounts and premiums and transaction costs.
(1) Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
(2)
(3)
(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 (defined as
current and long-term debt plus shareholders' equity) for the year.
As at December 31, 2020, 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 "Business Environment"
section and 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 market
conditions. 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.
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;
■ 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;
■ 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;
■ Monitoring the Company's ability to fulfill financial obligations as they become due or the ability to monetize assets in a
timely manner at a reasonable price;
■ Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant
packages; and
■ Reviewing the Company's borrowing capacity:
• During 2020, the Company issued $500 million of 1.45% notes due November 2023 and $300 million of 2.50%
notes due January 2028. After issuing these securities, the Company had $2,200 million remaining on its base shelf
prospectus that allows for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada,
which expires in August 2021. 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.
Canadian Natural 2020 Annual Report
34
• During 2020, the Company issued US$600 million of 2.05% notes due July 2025 and US$500 million of 2.95% notes
due July 2030. After issuing these securities, the Company had US$1,900 million remaining on its 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 2021. 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 2020, the Company repaid $900 million of 2.05% medium-term notes and repaid $1,000 million of 2.89%
medium-term notes.
•
Each of the Company’s $2,425 million revolving credit 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 the Company's revolving term credit 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.
• Borrowings under the Company's non-revolving term credit 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.
As at December 31, 2020, the non-revolving term credit facilities were fully drawn.
• During 2020, the $750 million non-revolving term credit facility, originally due February 2021, was extended to February
2022 and increased to $1,000 million. Subsequent to December 31, 2020, the facility was extended to February 2023.
• During 2019, the Company entered into a $3,250 million non-revolving term credit facility to finance the acquisition
of assets from Devon. During 2020, the Company repaid $162.5 million related to the required annual amortization,
reducing the facility balance to $3,088 million. Subsequent to December 31, 2020, the Company repaid a further
$362.5 million on the faciltity, reducing the outstanding balance to $2,725 million, and satisfying the required annual
amortization of $162.5 million originally due in June 2021. The facility matures in June 2022.
•
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 revolving bank credit facilities for amounts outstanding under this
program.
As at December 31, 2020, the Company had undrawn revolving bank credit facilities of $4,958 million. Including cash and
cash equivalents and short-term investments, the Company had approximately $5,447 million in liquidity. Additionally, the
Company had in place fully drawn term credit facilities of $6,738 million. The Company also has certain other dedicated credit
facilities supporting letters of credit. At December 31, 2020, the Company had $544 million drawn under its commercial paper
program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
As at December 31, 2020, the Company had total US dollar denominated debt with a carrying amount of $16,746 million
(US$13,129 million), before transaction costs and original issue discounts. This included $6,287 million (US$4,929 million)
hedged by way of a cross currency swap (US$550 million) and foreign currency forwards (US$4,379 million). The fixed
repayment amount of these hedging instruments is $6,337 million, resulting in a notional increase of the carrying amount of
the Company’s US dollar denominated debt by approximately $50 million to $16,796 million as at December 31, 2020.
During 2020, the Company settled the US$500 million cross currency swaps designated as cash flow hedges of the US$500
million 3.45% US dollar debt securities due November 2021. The Company realized cash proceeds of $166 million on
settlement.
Net long-term debt was $21,269 million at December 31, 2020, resulting in a debt to book capitalization ratio of 40%
(December 31, 2019 – 37%, December 31, 2018 – 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 are
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,
2020 are discussed in note 11 to the Company’s audited consolidated financial statements.
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, 2020, the Company was in compliance with this covenant.
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. Further details related to the Company’s commodity derivative financial instruments outstanding at
December 31, 2020 are discussed in note 19 of the Company’s audited consolidated financial statements.
35
Canadian Natural 2020 Annual Report
The maturity dates of long-term debt and other long-term liabilities and related interest payments were as follows:
Less than
1 year
1 to less than
2 years
2 to less than
5 years
Long-term debt (1)
Other long-term liabilities (2)
Interest and other financing expense (3)
$
$
$
1,343
345
776
$
$
$
4,887
200
693
$
$
$
7,051
435
1,619
$
$
$
Thereafter
8,279
942
4,452
(1)
(2)
(3)
Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
Lease payments included within other long-term liabilities reflect principal payments only and are as follows: less than one year, $189 million; one to less
than two years, $162 million; two to less than five years, $397 million; and thereafter, $942 million.
Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest
and foreign exchange rates as at December 31, 2020.
SHARE CAPITAL
As at December 31, 2020, there were 1,183,866,000 common shares outstanding (December 31, 2019 – 1,186,857,000
common shares) and 48,656,000 stock options outstanding. As at March 2, 2021, the Company had 1,185,574,000 common
shares outstanding and 53,829,000 stock options outstanding.
On March 3, 2021, the Board of Directors approved an increase in the quarterly dividend to $0.47 per common share,
beginning with the dividend payable on April 5, 2021. On March 4, 2020, the Board of Directors approved an increase in
the quarterly dividend to $0.425 per common share. On March 6, 2019, the Board of Directors approved an increase in the
quarterly dividend to $0.375 per common share. On February 28, 2018, the Board of Directors approved an increase in the
quarterly dividend to $0.335 per common share. The dividend policy undergoes periodic review by the Board of Directors and
is subject to change.
On May 21, 2019, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities
of the TSX, alternative Canadian trading platforms, and the NYSE, up to 59,729,706 common shares, over a 12-month period
commencing May 23, 2019 and ending May 22, 2020. The Company did not renew its Normal Course Issuer Bid after its
expiry in May 2020.
During 2020, the Company purchased 6,970,000 common shares at a weighted average price of $38.84 per common share
for a total cost of $271 million. Retained earnings were reduced by $215 million, representing the excess of the purchase price
of common shares over their average carrying value.
On March 3, 2021, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with
the TSX to purchase, by way of a Normal Course Issuer Bid, up to 5.0% of its issued and outstanding common shares for the
purpose of repurchasing a number of common shares approximately equal to the number of options exercised throughout the
year in order to eliminate dilution for shareholders. Subject to acceptance of the Notice of Intention by the TSX, the purchases
would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE.
Commitments and Contingencies
In the normal course of business, the Company has committed to certain payments. The following table summarizes the
Company’s commitments as at December 31, 2020:
($ millions)
Product transportation and processing (1) (2)
$
North West Redwater Partnership service toll (3) $
Offshore vessels and equipment
Field equipment and power
Other
$
$
$
2021
870
163
64
28
25
$
$
$
$
$
2022
817
160
9
21
21
$
$
$
$
$
2023
858
160
$
$
2024
841
156
2025
Thereafter
$
$
809
150
$ 10,370
$
2,694
— $
— $
— $
21
21
$
$
21
22
$
$
21
22
$
$
—
246
16
(1)
Includes commitments pertaining to a 20-year product transportation agreement on the Trans Mountain Pipeline Expansion. In addition, the Company has
entered into certain product transportation agreements on pipelines that have not yet received regulatory and other approvals.
The acquisition of Painted Pony in 2020 included approximately $2,400 million of product transportation and processing commitments.
(2)
(3) Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt component of the monthly cost of
service tolls. Included in the cost of service tolls is $1,169 million of interest payable over the 30-year tolling period.
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.
Canadian Natural 2020 Annual Report
36
Reserves
For the years ended December 31, 2020 and 2019, the Company retained Independent Qualified Reserves Evaluators to
evaluate and review all of the Company’s total proved and total proved plus probable reserves. The evaluation and review
was conducted and prepared 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 following are reconciliation tables of the company gross total proved and total proved plus probable reserves using
forecast prices and costs as at the effective date of December 31, 2020:
Total Proved
December 31, 2019
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2020 (1)
Total Proved Plus
Probable
December 31, 2019
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2020 (1)
Light and
Medium
Crude Oil
Primary
Heavy
Crude Oil
Pelican
Lake
Heavy
Crude Oil
Bitumen
(Thermal
Oil)
Synthetic
Crude Oil
Natural
Gas
Natural
Gas
Liquids
Barrels
of Oil
Equivalent
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(Bcf)
(MMbbl)
(MMBOE)
357
—
2
3
—
1
—
(20)
4
(31)
315
202
293
2,438
6,352
6,460
275
10,993
—
—
3
—
—
—
(10)
8
(26)
177
—
—
—
—
—
—
(13)
6
(21)
265
—
17
—
73
—
—
—
45
—
720
—
—
—
—
—
43
(91)
2,483
(153)
6,962
—
226
290
—
2,932
(4)
(197)
297
(541)
9,465
—
11
13
—
31
—
(8)
19
(15)
326
—
787
66
73
521
(1)
(83)
175
(426)
12,106
Light and
Medium
Crude Oil
Primary
Heavy
Crude Oil
Pelican
Lake
Heavy
Crude Oil
Bitumen
(Thermal
Oil)
Synthetic
Crude Oil
Natural
Gas
Natural
Gas
Liquids
Barrels
of Oil
Equivalent
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(Bcf)
(MMbbl)
(MMBOE)
519
—
3
4
—
1
—
(18)
(15)
(31)
463
293
—
1
4
—
—
—
(13)
1
(26)
260
425
4,108
6,897
9,607
408
14,252
—
—
—
—
—
—
(5)
(4)
(21)
395
—
21
—
106
—
—
—
13
—
717
—
—
—
—
—
34
(91)
(153)
—
374
384
—
6,238
(5)
(249)
113
(541)
4,157
7,496
15,922
—
20
17
—
62
—
(9)
17
(15)
500
—
825
88
106
1,102
(1)
(86)
65
(426)
15,925
Information in the reserves data tables may not add due to rounding. BOE values as presented may not calculate due to rounding.
(1)
At December 31, 2020, the total proved crude oil, bitumen (thermal oil) and NGLs reserves were 10,528 MMbbl, and
total proved plus probable crude oil, bitumen (thermal oil) and NGLs reserves were 13,271 MMbbl. Total proved reserves
additions and revisions replaced 282% of 2020 production. Additions to total proved reserves resulting from exploration
and development activities, acquisitions, dispositions and future offset additions amounted to 872 MMbbl, and additions to
total proved plus probable reserves amounted to 955 MMbbl. Net positive revisions amounted to 75 MMbbl for total proved
reserves and 1 MMbbl for total proved plus probable reserves, primarily due to technical revisions.
At December 31, 2020, the total proved natural gas reserves were 9,465 Bcf, and total proved plus probable natural gas
reserves were 15,922 Bcf. Total proved reserves additions and revisions replaced 656% of 2020 production. Additions to total
proved reserves resulting from exploration and development activities, acquisitions, dispositions and future offset additions
amounted to 3,445 Bcf, and additions to total proved plus probable reserves amounted to 6,991 Bcf. Net positive revisions
amounted to 100 Bcf for total proved reserves, primarily due to technical revisions, and net negative revisions amounted to
136 Bcf for total proved plus probable reserves, primarily due to economic factors.
37
Canadian Natural 2020 Annual Report
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 information is annually disclosed in the AIF.
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.
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:
■ Volatility in the prevailing prices of crude oil and NGLs, natural gas and refined products;
■
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;
■ Regulatory risk related to approval for exploration and development activities, which can add to costs or cause delays in
projects;
■
Labour risk associated with securing the manpower necessary to complete capital projects in a timely and cost effective
manner;
■ Operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas
and in mining, extracting and upgrading the Company’s bitumen products;
■
Timing and success of integrating the business and operations of acquired companies and assets;
■ Credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts, including
derivative financial instruments and physical sales contracts as part of a hedging program;
■
■
Interest rate risk associated with the Company’s ability to secure financing on commercially acceptable terms;
Foreign exchange risk due to 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, including GHG and carbon;
■ 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;
■ Epidemics or pandemics, such as COVID-19, have the potential to disrupt the Company’s operations, projects and financial
condition through the disruption of the local or global supply chain and transportation services, or the loss of manpower
resulting from quarantines that affect the Company’s labour pools in their local communities, workforce camps or operating
sites or that are instituted by local health authorities as a precautionary measure, any of which may require the Company to
temporarily reduce or shutdown its operations depending on the extent and severity of a potential outbreak and the areas
or operations impacted. Depending on the severity, a large scale epidemic or pandemic could impact the international
demand for commodities and have a corresponding impact on the prices realized by the Company, which could have a
material adverse effect on the Company's financial condition;
■
■
■
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;
Canadian Natural 2020 Annual Report
38
■
Liquidity risk related to the Company's ability to fulfill financial obligations as they become due or ability to liquidate assets
in a timely manner at a reasonable price; 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.
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 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 has safety, integrity and environmental management systems to recover and process crude oil and natural gas
resources safely, efficiently, and in an environmentally sustainable manner and mitigate risk.
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, 2020.
Environment
The Company has a Corporate Statement on Environmental Management that affirms environmental stewardship as a
fundamental value of the Company. The Company continues to invest in people, proven and new 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 interests and values of the people using the land in
proximity to its operations, and where appropriate, adapts projects to recognize those matters.
The crude oil and natural gas industry is experiencing incremental increases in costs related to environmental regulation
compliance, particularly in North America and the North Sea. Existing and expected legislation and regulations may require the
Company to address and mitigate the effect of its activities on the environment. The Company believes it meets all existing
environmental standards and regulations and has included appropriate amounts in its capital expenditure budget to continue
to meet current environmental protection requirements. Increasingly stringent laws and regulations may have an adverse
effect on the Company’s future net earnings.
The Company’s associated environmental risk management strategies incorporate working with legislators and regulators
on any new or revised policies, legislation or regulations to 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 quality and emissions, ground and surface 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:
39
Canadian Natural 2020 Annual Report
■ Environmental planning to assess impacts and implement avoidance and mitigation programs in order to maintain
biodiversity for terrestrial and aquatic systems and high value ecosystems;
■ 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;
■ Mitigation of the Company's climate change impacts through implementation of various CO2 emissions reduction and
carbon capture projects including: CO2 injection for EOR, CO2 injection in tailings and the Quest carbon capture and storage
facility; a methane emissions reduction program, including solution gas conservation to reduce methane venting, and an
equipment retrofit program to reduce methane emissions from pneumatic equipment; and 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;
■ Groundwater monitoring for all thermal in situ and mine operations;
■ Effective reclamation and decommissioning programs 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 provides the
foundation for the enhancement of biodiversity and functional wildlife habitats. In the Company's International operations,
decommissioning activities continued at Banff, Kyle, Murchison, Ninian North and Olowi;
■
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;
■ An active spill prevention and management program; and
■ An internal environmental management system for compliance audit and inspection programs 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 3.7% (2019 – 3.8%; 2018 – 5.0%). For 2020,
the Company’s capital expenditures included $249 million for abandonment expenditures (2019 – $296 million; 2018 – $290
million). The Company’s estimated discounted ARO at December 31, 2020 was as follows:
($ millions)
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream and Refining
2020
2019
$
2,899
$
2,792
787
174
1,999
2
$
5,861
$
816
161
2,000
2
5,771
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.
GREENHOUSE GAS AND OTHER EMISSIONS
The Company has a large, diversified and balanced portfolio and a risk management strategy which incorporates an integrated
GHG emissions reduction strategy and investments in technology and innovation to improve its GHG performance. The
Company’s integrated GHG emissions reduction strategy includes: 1) integrating emissions reduction in project planning and
operations; 2) leveraging technology to create value and enhance performance; 3) investing in research and development and
supporting collaboration with industry, entrepreneurs, academia and governments; 4) focusing on continuous improvement
to drive long-term emissions reduction; 5) leading in carbon capture, sequestration and storage; 6) engaging in policy and
regulatory development (including trading capacity and offsetting emissions); and, 7) reviewing and developing new business
opportunities and trends.
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 to support emissions reductions and properly reflect
a balanced approach to sustainable development. 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.
Canadian Natural 2020 Annual Report
40
Governments in jurisdictions in which the Company operates have developed or are developing GHG regulations as part of
their national and international climate change commitments. The Company uses existing GHG regulations to determine
the impact of compliance costs on current and future projects. The Company monitors the development of GHG regulations
on an ongoing basis in the jurisdictions in which it operates to assess the impact of future regulatory developments on
the Company's operations and planned projects. 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 natural gas sector by 40 - 45% by 2025, as compared to 2012 levels.
In December 2020, the federal government announced its intention to surpass Canada's reduction target under the Paris
agreement, to increase the carbon price to $170/tonne in 2030, and to establish additional methane reduction targets for
2030 and 2035. The federal government is also developing: (i) a comprehensive management system for air pollutants and
has released regulations pertaining to certain boilers, heaters and compressor engines operated by the Company; and (ii) a
Clean Fuel Standard, which may affect production and consumption of fuels in Canada. Draft regulations under the Clean Fuel
Standard were released in 2020 and are planned to take effect in December 2022. Aspects of the Clean Fuel Standard could
potentially increase the cost of liquid fuels consumed in the Company's operations while also providing a potential mechanism
to generate offset credits.
Carbon pricing regulatory systems in all provinces are subject to annual review by the federal government to assess the
adequacy of the provincial systems against the federal Greenhouse Gas Pollution Pricing Act. Such future reviews may affect
the carbon price and/or the stringency of provincial systems.
Effective January 1, 2020, the GHG regulation (the Carbon Competitiveness Incentive Regulation) was replaced with the
Technology Innovation and Emissions Reduction Regulation ("TIER"). The coverage of TIER has expanded to include all of
the Company's assets in Alberta (as an alternative to the federal fuel charge). The carbon price in Alberta was $30/tonne for
emissions above the TIER-regulated limits in 2020, and the Alberta government increased the price to $40/tonne in 2021 and
has announced its intention to increase the price to $50/tonne in 2022, in alignment with the federal carbon pricing schedule.
Facilities with emissions in previous years above 100,000 tonnes of CO2e/year, or that have voluntarily opted into TIER are
required to comply with the regulation. The non-operated Scotford Upgrader and the North West Redwater bitumen upgrader
and refinery are also subject to compliance under the regulations.
In British Columbia, carbon tax is currently being assessed at $40/tonne of CO2e on fuel consumed and gas flared and vented
in the province. Further increases in the carbon tax rate are currently paused as part of the British Columbia government's
COVID-19 response plan, however, it is expected that increases will resume as COVID-19 relief measures are eased. The
British Columbia government has implemented a program (the CleanBC Plan) to partially mitigate the impact of the carbon
tax increases on emissions intensive trade exposed (EITE) sectors.
As part of its Prairie Resilience Plan, the Saskatchewan government has a regulation ("The Management and Reduction of
Greenhouse Gases (Standards and Compliance) Regulations") that applies to facilities emitting more than 25 kilotonnes of
CO2e annually and required the North Tangleflags in situ heavy oil facility and the Senlac in situ heavy crude oil facility to meet
reduction targets for GHG emissions in 2020. This regulation also enables facilities below the threshold to aggregate and opt
into the Saskatchewan regulatory system as an alternative to the federal fuel charge.
In Manitoba, the federal output-based pricing system applies for facilities with emissions greater than or equal to 10 kilotonnes
of CO2e annually, and the federal fuel charge applies for facilities with emissions of less than 10 kilotonnes of CO2e annually.
By 2025, the federal government has committed to reduce methane emissions from the oil and gas sector by 40% to 45%
below 2012 levels. The federal government's methane regulation came into effect on January 1, 2020 and applies nationally
unless provinces reach equivalency agreements with the federal government, under which the federal regulation would not
be in effect for those jurisdictions. The provinces of British Columbia, Alberta and Saskatchewan have implemented provincial
methane regulations, and have reached equivalency agreements with the federal government. Accordingly, the applicable
provincial methane regulations govern in the three western provinces whereas the federal methane regulation applies to
methane emissions in the province of Manitoba.
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.
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. Following the
UK's withdrawal from the European Union ("EU") on January 31, 2020, the UK continued to participate in the EU ETS for the
2020 compliance year. The post 2020 regulatory framework in the UK will broadly follow EU ETS rules and apply to energy
intensive industries, the power generation sector and aviation. The new UK Registry is expected to be launched in 2021.
The UK has confirmed that EU allowances will not be transferable into the UK Registry. 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.
41
Canadian Natural 2020 Annual Report
Accounting Policies and Standards
CHANGES IN ACCOUNTING POLICIES
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 permit a simplified assessment of whether an acquired set of activities and assets is a group
of assets rather than a business. The amendments apply to business combinations after the date of adoption. The Company
prospectively adopted the amendments on January 1, 2020.
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 judgements related to the preparation of
financial statements. The Company prospectively adopted the amendments on January 1, 2020.
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. In 2020, COVID-19 had an impact
on the global economy, including the oil and gas industry. Business conditions in 2020 reflected the market uncertainty
associated with COVID-19. The Company has taken into account the impacts of COVID-19 and the unique circumstances
it has created in making estimates, assumptions, and judgements in the preparation of the audited consolidated financial
statements, and continues to monitor the developments in the business environment and commodity market. 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, 2020.
A) Depletion, Depreciation and Amortization and Impairment
Exploration and evaluation ("E&E") costs relating to activities to explore and evaluate crude oil and natural gas properties
are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies,
seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset
retirement costs. E&E assets are carried forward until technical feasibility and commercial viability of extracting a mineral
resource is determined. Technical feasibility and commercial viability of extracting a mineral resource is considered to be
determined when an assessment of proved reserves is made. The judgements associated with the estimation of proved
reserves are described below in "Crude Oil and Natural Gas Reserves".
An alternative acceptable accounting method for E&E costs under IFRS 6 "Exploration for and Evaluation of Mineral Resources"
is to charge exploratory dry holes and geological and geophysical exploration costs incurred after having obtained the legal
rights to explore an area against net earnings in the period incurred rather than capitalizing to E&E assets.
E&E assets are tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may
exceed their recoverable amount, by comparing the relevant costs to the fair value of related Cash Generating Units ("CGUs"),
aggregated at a segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark
commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes,
significant increases in estimated future exploration or development expenditures, or significant adverse changes in the
applicable legislative or regulatory frameworks. The determination of the fair value of CGUs requires the use of assumptions
and estimates including future commodity prices, expected production volumes, quantity of reserves, asset retirement
obligations, future development and production costs, discount rates and income taxes. Changes in assumptions used in
determining the recoverable amount could affect the carrying value of the related assets and CGUs.
Property, plant and equipment is measured at cost less accumulated depletion and depreciation and impairment provisions.
Crude oil and natural gas properties in the Exploration and Production segments are depleted using the unit-of-production
method over proved reserves, except for major components, which are depreciated using a straight-line method over their
estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with
future estimated development expenditures required to develop proved reserves. Estimates of proved reserves have a
significant impact on net earnings, as they are a key input to the calculation of depletion expense.
The Company assesses property, plant and equipment for impairment discounted at rates currently ranging from 10% to
12% whenever events or changes in circumstances indicate that the carrying value of an asset or group of assets may not
be recoverable. Indications of impairment include the existence of low commodity prices for an extended period, significant
downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or
significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the
Company performs an impairment test related to the specific assets at the CGU level.
Canadian Natural 2020 Annual Report
42
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 3.7%. Subsequent to initial
measurement, the ARO is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes
in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is
recognized as asset retirement obligation accretion expense whereas changes in discount rates or estimated future cash
flows are capitalized to or derecognized from property, plant and equipment. Changes in estimates would impact accretion
and depletion expense in net earnings. In addition, differences between actual and estimated costs to settle the ARO, timing
of cash flows to settle the obligation and future inflation rates may result in gains or losses on the final settlement of the ARO.
D) Income Taxes
The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and
liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying amount of assets
and liabilities in the consolidated financial statements and their respective tax bases, using income tax rates substantively
enacted that are expected to apply when the asset or liability is recovered. Accounting for income taxes requires the Company
to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with
respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of
tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company
recognizes a liability for a tax filing position based on its assessment of the probability that additional taxes may ultimately be
due.
E) Risk Management Activities
The Company periodically uses derivative financial instruments to manage its commodity price, foreign currency and interest
rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative
purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value.
The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions,
the Company primarily relied on external, readily-observable quoted market inputs including crude oil and natural gas forward
benchmark commodity prices and volatility, Canadian and United States forward interest rate yield curves, and Canadian and
United States foreign exchange rates, discounted to present value as appropriate. The carrying amount of a risk management
liability is adjusted for the Company’s own credit risk. The resulting fair value estimates may not necessarily be indicative of
the amounts that could be realized or settled in a current market transaction and these differences may be material.
43
Canadian Natural 2020 Annual Report
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 timing and future forfeiture rates. At each period end, stock options outstanding are remeasured
for changes in the estimated fair value of the liability.
H) Leases
Purchase, extension and termination options are included in certain of the Company's leases to provide operational flexibility.
To measure the lease liability, the Company uses judgement to assess the likelihood of exercising these options. These
assessments are reviewed when significant events or circumstances indicate that the likelihood of exercising these options
may have changed. The Company also uses estimates to determine its incremental borrowing costs if the interest rate implicit
in the lease is not readily determinable.
(I) Government Grants
The Company receives or is eligible for government grants, including those introduced in response to the impact of COVID-19.
Government grants are recognized when there is reasonable assurance that the Company will comply with the conditions
attached to the grant and the grant will be received. Grants that are intended to compensate for expenses incurred are
classified as other income.
Control Environment
The Company’s management, including the President and the Chief Financial Officer and Vice-President, Finance and
Principal Accounting Officer, evaluated the effectiveness of disclosure controls and procedures as at December 31, 2020, 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 Vice-President, Finance and Principal
Accounting Officer, also evaluated the effectiveness of internal control over financial reporting as at December 31, 2020, 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 2020 that have materially affected, or are reasonably likely to materially affect, internal
control over financial reporting.
While the Company’s management believes that the Company’s disclosure controls and procedures and internal control
over financial reporting provide a reasonable level of assurance they are effective, they recognize that all control systems
have inherent limitations. Because of its inherent limitations, the Company’s control systems may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
Canadian Natural 2020 Annual Report
44
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.
2021 CAPITAL BUDGET
On December 9, 2020, the Company announced its 2021 capital budget targeted at approximately $3,205 million, of which
$1,345 million is related to conventional and unconventional assets and $1,860 million is allocated to long-life low decline
assets.
Other
SENSITIVITY ANALYSIS
The following table is indicative of the annualized sensitivities of cash flows from operating activities and net earnings due to
changes in certain key variables. The analysis is based on business conditions and sales volumes during the fourth quarter of
2020, excluding mark-to-market gains (losses) on risk management activities and is not necessarily indicative of future results.
Each separate line item in the sensitivity analysis shows the effect of a change in that variable only with all other variables
being held constant.
Cash flows
from Operating
Activities
($ millions)
Cash flows
from Operating
Activities
(per common
share, basic)
Net
earnings
(loss)
($ millions)
Net
earnings
(loss)
(per common
share, basic)
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)
$
$
$
$
$
$
315
315
26
21
99
3
$
$
$
$
$
$
0.27
0.27
0.02
0.02
$
$
$
$
0.08
$
— $
315
315
26
21
$
$
$
$
70
$
— $
Including financial derivatives
$
139
$
Interest rate change – 1%
$
53
$
0.12
0.05
$
$
4
53
$
$
0.27
0.27
0.02
0.02
0.06
—
—
0.05
(1)
For details of financial instruments in place, refer to note 19 to the Company’s audited consolidated financial statements as at December 31, 2020.
45
Canadian Natural 2020 Annual Report
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
Q1
Q2
Q3
Q4
2020
2019
2018
Crude oil and NGLs (bbl/d)
North America – Exploration and
Production
North America – Oil Sands Mining
and Upgrading (1)
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 (1)
North Sea
Offshore Africa
Total
456,877
413,506
494,952
475,889
460,443
405,970
350,961
438,101
464,318
350,633
417,089
417,351
395,133
426,190
27,755
15,943
26,627
17,444
21,220
17,537
17,057
17,155
23,142
17,022
27,919
21,371
23,965
19,662
938,676
921,895
884,342
927,190
917,958
850,393
820,778
1,407
1,431
1,340
1,623
1,450
1,443
1,490
23
10
15
16
5
17
4
17
12
15
24
24
32
26
1,440
1,462
1,362
1,644
1,477
1,491
1,548
691,435
651,929
718,315
746,333
702,168
646,443
599,310
438,101
464,318
350,633
417,089
417,351
395,133
426,190
31,561
17,655
29,201
20,039
21,959
20,379
17,774
20,002
25,095
19,522
31,915
25,466
29,264
24,049
1,178,752
1,165,487
1,111,286 1,201,198
1,164,136
1,098,957
1,078,813
(1) SCO production before royalties excludes SCO consumed internally as diesel.
PER UNIT RESULTS – EXPLORATION AND PRODUCTION
Crude oil and NGLs ($/bbl) (1)
Sales price (2)
Transportation (3)
Realized sales price,
net of transportation
Royalties
Production expense
Netback
Natural gas ($/Mcf) (1)
Sales price
Transportation
Realized sales price,
net of transportation
Royalties
Production expense
Netback
Barrels of oil equivalent ($/BOE) (1)
Sales price (2)
Transportation (3)
Realized sales price,
net of transportation
Royalties
Production expense
Netback
Q1
Q2
Q3
Q4
2020
2019
2018
$ 25.90
$ 18.97
$ 40.14
$ 40.56
$ 31.90
$ 55.08
$ 46.92
3.87
22.03
2.34
13.71
4.20
14.77
1.48
12.53
3.60
36.54
3.03
11.03
3.81
36.75
3.34
12.47
3.85
28.05
2.59
12.42
3.48
51.60
6.08
13.81
3.08
43.84
5.08
15.69
$ 5.98
$
0.76
$ 22.48
$ 20.94
$ 13.04
$
31.71
$ 23.07
$ 2.22
$
0.46
1.76
0.05
1.31
$ 0.40
$
2.03
0.41
1.62
0.05
1.15
0.42
$ 2.31
$ 2.94
$ 2.40
$
0.42
1.89
0.07
1.18
0.42
2.52
0.13
1.10
0.43
1.97
0.08
1.18
$ 0.64
$ 1.29
$ 0.71
$
2.34
0.42
1.92
0.08
1.22
0.62
$
$
2.61
0.47
2.14
0.08
1.36
0.70
$ 21.90
$ 16.57
$ 32.28
$ 32.61
$ 26.15
$ 40.50
$ 34.62
3.50
18.40
1.70
11.87
3.61
12.96
1.05
10.55
3.28
3.37
29.00
29.24
2.25
9.84
2.44
10.43
3.44
22.71
1.89
10.67
3.14
37.36
4.09
11.49
2.96
31.66
3.27
12.71
$ 4.83
$
1.36
$ 16.91
$ 16.37
$ 10.15
$
21.78
$
15.68
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
(3) Excludes the impact of a $143 million provision recognized in the fourth quarter of 2020, relating to the Keystone XL pipeline project.
Canadian Natural 2020 Annual Report
46
PER UNIT RESULTS – OIL SANDS MINING AND UPGRADING
Q1
Q2
Q3
Q4
2020
2019
2018
Crude oil and NGLs ($/bbl) (1)
SCO sales price (2)
Bitumen royalties (3)
Transportation
Production costs
Netback
$ 50.88
$ 29.11
$ 48.92
$ 48.56
$ 43.98
$ 70.18
$
68.61
0.87
1.28
20.76
0.15
0.97
17.74
0.46
1.30
0.59
1.36
0.51
1.23
3.31
1.29
23.81
20.20
20.46
22.56
3.09
1.61
21.75
$ 27.97
$ 10.25
$ 23.35
$ 26.41
$ 21.78
$ 43.02
$
42.16
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending and feedstock costs.
(3) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes.
TRADING AND SHARE STATISTICS
TSX – C$
Q1
Q2
Q3
Q4
2020
2019
Trading volume (thousands)
462,841
588,540
358,734
456,299
1,866,414
904,013
Share Price ($/share)
High
Low
Close
Market capitalization as at
December 31 ($ millions)
Shares outstanding
(thousands)
NYSE – US$
$42.57
$9.80
$19.25
$30.10
$16.55
$23.55
$28.20
$21.25
$21.34
$32.49
$19.77
$30.59
$42.57
$9.80
$30.59
$42.56
$30.01
$42.00
$36,214
$49,848
1,183,866
1,186,857
Trading volume (thousands)
301,186
334,981
211,582
210,372
1,058,121
679,697
Share Price ($/share)
High
Low
Close
Market capitalization as at
December 31 ($ millions)
Shares outstanding
(thousands)
$32.79
$22.50
$6.71
$13.55
$11.77
$17.43
$21.21
$15.85
$16.01
$25.55
$14.85
$24.05
$32.79
$6.71
$24.05
$32.56
$22.58
$32.35
$28,472
$38,395
1,183,866
1,186,857
47
Canadian Natural 2020 Annual Report
Consolidated Financial Statements
Table of Contents
Management’s Report
Management’s Assessment of Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Earnings (Loss)
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Changes in Equity
Consolidated Statements of Cash Flows
Notes to the Consolidated Financial Statements
1. Accounting Policies
2. Changes in Accounting Policies
3. Accounting Standards Issued But Not Yet Applied
4. Critical Accounting Estimates and Judgements
5. Inventory
6. Exploration and Evaluation Assets
7. Property, Plant and Equipment
8. Leases
9. Investments
10. Other Long-Term Assets
11. Long-Term Debt
12. Other Long-Term Liabilities
13. Income Taxes
14. Share Capital
15. Accumulated Other Comprehensive Income
16. Capital Disclosures
17. Net Earnings Per Common Share
18. Interest and Other Financing Expense
19. Financial Instruments
20. Commitments and Contingencies
21. Supplemental Disclosure of Cash Flow Information
22. Segmented Information
23. Remuneration of Directors and Senior Management
49
50
51
54
55
55
56
57
58
58
65
65
66
67
68
69
71
72
73
74
76
78
81
82
83
83
84
84
89
90
91
94
Canadian Natural 2020 Annual Report
48
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, 2020; and
the effectiveness of the Company’s internal control over financial reporting as at December 31, 2020.
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
MARK STAINTHORPE, CFA
Chief Financial Officer and
Senior Vice-President, Finance
CHRIS GRAYSTON, CA
Vice-President, Finance and
Principal Accounting Officer
Calgary, Alberta, Canada
March 3, 2021
49
Canadian Natural 2020 Annual Report
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, 2020. 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, 2020, as stated in their accompanying Report of
Independent Registered Public Accounting Firm.
TIM S. MCKAY
President
MARK STAINTHORPE, CFA
Chief Financial Officer and
Senior Vice-President, Finance
Calgary, Alberta, Canada
March 3, 2021
Canadian Natural 2020 Annual Report
50
Report of Independent Registered Public
Accounting Firm
To the Shareholders and Board of Directors of Canadian Natural Resources Limited
OPINIONS ON THE CONSOLIDATED 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, 2020 and 2019, 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,
2020, 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, 2020, 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, 2020 and 2019, and its financial performance and its cash flows for each of
the three years in the period ended December 31, 2020 in conformity with International Financial Reporting Standards as
issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control –
Integrated Framework (2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for
leases as of January 1, 2019 due to the adoption of IFRS 16, Leases.
BASIS FOR OPINIONS
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal
control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included
in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express
opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting
based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United
States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. 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.
51
Canadian Natural 2020 Annual Report
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.
CRITICAL AUDIT MATTERS
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial
statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts
or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective,
or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate
opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The impact of crude oil and natural gas reserves on property, plant and equipment assets in the North America Exploration
and Production segment
As described in Notes 1, 4 and 7 to the Company’s consolidated financial statements, the property, plant and equipment
(“PP&E”) balances in the North America Exploration and Production segment was $24.4 billion as at December 31, 2020.
Depletion, depreciation and amortization (“DD&A”) expense for the North America Exploration and Production segment was
$3.7 billion for the year ended December 31, 2020. In accordance with the Company’s accounting policies, crude oil and natural
gas properties in the North America Exploration and Production segment, excluding major components, are depleted using
the unit-of-production method based on proved reserves. PP&E assets are grouped for recoverability assessment purposes
into cash generating units (“CGU”) and a CGU’s recoverable amount is the higher of its fair value less costs of disposal and its
value in use. The assessment of a CGU’s recoverability requires the use of estimates and assumptions, including information
on future commodity prices, expected production volumes, quantity of crude oil and natural gas reserves, asset retirement
obligations, future development and operating costs, after-tax discount rates and income taxes. Estimates of the Company’s
crude oil and natural gas reserves 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 judgments. Management utilizes third party specialists, specifically independent qualified
reserve evaluators, to evaluate, review and report to the Company’s management and Board of Directors on its estimates
of crude oil and natural gas reserves. These estimates are utilized for both the determination of the recoverable amounts of
PP&E and the calculation of DD&A expense.
The principal considerations for our determination that performing procedures relating to the impact of crude oil and natural
gas reserves on PP&E assets in the North America Exploration and Production segment is a critical audit matter are that
there was a significant amount of judgment required by management, including the use of specialists, when developing
the estimates, specifically related to the estimates of crude oil and natural gas reserves and the recoverable amount of the
PP&E assets in the North America Exploration and Production segment. This led to a high degree of auditor judgment, effort
and subjectivity in performing procedures and evaluating evidence obtained related to the significant assumptions used in
developing the estimates, including estimates of expected future rates of production, future commodity pricing and future
development and operating costs.
Canadian Natural 2020 Annual Report
52
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall
opinion on the consolidated financial statements. These procedures included testing the effectiveness of internal controls
in the North America Exploration and Production segment relating to management’s estimates of the Company’s crude oil
and natural gas reserves, management’s assessment of PP&E recoverability and the calculation of DD&A expense. These
procedures also included, among others, testing management’s process for determining the recoverable amount of PP&E and
DD&A expense for the North America Exploration and Production segment. Testing management’s process for determining
these estimates included (i) evaluating the appropriateness of the methods used by management in making these estimates;
(ii) testing the completeness, accuracy and relevance of underlying data used in management’s analysis in developing these
estimates; (iii) evaluating the significant assumptions used in developing the underlying estimates, including assumptions of
expected future rates of production, future commodity pricing and future development and operating costs; and (iv) testing
the unit-of-production rates used to calculate DD&A expense. The work of management’s specialists was used in performing
the procedures to evaluate the reasonableness of the estimates of crude oil and natural gas reserves used to determine
DD&A expense and the recoverable amount of PP&E for the North America Exploration and Production segment. As a basis
for using this work, the specialists’ qualifications were understood, and the Company’s relationship with the specialists was
assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests
of data used by the specialists and an evaluation of the specialists’ findings. Evaluating the significant assumptions used by
management’s specialists also involved evaluating whether the assumptions used were reasonable considering the past
performance of the Company, consistency with industry pricing forecasts and whether they were consistent with evidence
obtained in other areas of the audit.
Chartered Professional Accountants
Calgary, Canada
March 3, 2021
We have served as the Company’s auditor since 1973.
53
Canadian Natural 2020 Annual Report
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
Lease assets
Other long-term assets
LIABILITIES
Current liabilities
Accounts payable
Accrued liabilities
Current portion of long-term debt
Current portion of other long-term liabilities
Long-term debt
Other long-term liabilities
Deferred income taxes
SHAREHOLDERS’ EQUITY
Share capital
Retained earnings
Accumulated other comprehensive income
Commitments and contingencies (note 20).
Approved by the Board of Directors on March 3, 2021
Note
2020
2019
$
184
$
2,190
309
1,060
231
305
82
4,361
2,436
65,752
1,645
1,082
139
2,465
13
1,152
174
490
54
4,487
2,579
68,043
1,789
1,223
$
75,276
$
78,121
$
667
$
2,346
1,343
722
5,078
20,110
7,564
10,144
42,896
9,606
22,766
8
32,380
$
75,276
$
816
2,611
2,391
819
6,637
18,591
7,363
10,539
43,130
9,533
25,424
34
34,991
78,121
5
9
10
6
7
8
10
11
8,12
11
8,12
13
14
15
CATHERINE M. BEST
N. MURRAY EDWARDS
Chair of the Audit Committee
and Director
Executive Chairman of the Board
of Directors and Director
Canadian Natural 2020 Annual Report
54
Consolidated Statements of Earnings (Loss)
For the years ended December 31
(millions of Canadian dollars, except per common share amounts)
Note
2020
2019
22
$
17,491
$
24,394
$
Product sales
Less: royalties
Revenue
Expenses
Production
Transportation, blending and feedstock
Depletion, depreciation and amortization
Administration
Share-based compensation
Asset retirement obligation accretion
Interest and other financing expense
Risk management activities
Foreign exchange (gain) loss
Gain on acquisition, disposition and revaluation
Loss from investments
Earnings before taxes
Current income tax (recovery) expense
Deferred income tax (recovery) expense
Net earnings (loss)
Net earnings (loss) per common share
Basic
Diluted
(598)
16,893
6,280
4,498
6,046
391
(82)
205
756
(7)
(275)
(217)
171
17,766
(873)
(257)
(181)
(1,523)
22,871
6,277
4,699
5,546
344
223
190
836
77
(570)
—
293
17,915
4,956
434
(894)
2018
22,282
(1,255)
21,027
6,464
4,189
5,161
325
(146)
186
739
(134)
827
(452)
346
17,505
3,522
374
557
$
$
$
(435)
$
5,416
$
2,591
(0.37)
(0.37)
$
$
4.55
4.54
$
$
2.13
2.12
7, 8
12
12
18
19
6,7
9,10
13
13
17
17
Consolidated Statements of Comprehensive
Income (Loss)
2020
2019
$
(435)
$
5,416
$
2018
2,591
For the years ended December 31
(millions of Canadian dollars)
Net earnings (loss)
Items that may be reclassified subsequently to net
earnings
Net change in derivative financial instruments designated
as cash flow hedges
Unrealized income, net of taxes of $2 million
(2019 – $13 million, 2018 – $nil)
Reclassification to net earnings (loss), net of taxes of $2 million
(2019 – $5 million, 2018 – $6 million)
Foreign currency translation adjustment
Translation of net investment
Other comprehensive income (loss), net of taxes
13
(15)
(2)
(24)
(26)
99
(41)
58
(146)
(88)
5
(39)
(34)
224
190
2,781
Comprehensive income (loss)
$
(461)
$
5,328
$
55
Canadian Natural 2020 Annual Report
Consolidated Statements of Changes in Equity
For the years ended December 31
(millions of Canadian dollars)
Share capital
Balance – beginning of year
Issued upon exercise of stock options
Previously recognized liability on stock options exercised
for common shares
Purchase of common shares under Normal Course
Issuer Bid
Balance – end of year
Retained earnings
Balance – beginning of year
Net earnings (loss)
Dividends on common shares
Purchase of common shares under Normal Course
Issuer Bid
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
14
14
15
2020
2019
2018
$
9,533
$
9,323
$
108
21
(56)
9,606
25,424
(435)
(2,008)
(215)
22,766
34
(26)
8
360
53
(203)
9,533
22,529
5,416
(1,783)
(738)
25,424
122
(88)
34
9,109
332
120
(238)
9,323
22,612
2,591
(1,630)
(1,044)
22,529
(68)
190
122
$
32,380
$
34,991
$
31,974
Canadian Natural 2020 Annual Report
56
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 (gain) loss
Realized foreign exchange gain on settlement of cross currency swaps
Realized foreign exchange loss on repayment of US dollar debt securities
Gain on acquisition, disposition and revaluation
Loss from investments
Deferred income tax (recovery) expense
Other
Abandonment expenditures
Net change in non-cash working capital
Cash flows from operating activities
Financing activities
Issue (repayment) of bank credit facilities and commercial paper, net
Repayment of medium-term notes
Issue (repayment) of US dollar debt securities
Settlement of Painted Pony long-term debt
Proceeds on settlement of cross currency swaps
Payment of lease liabilities
Issue of common shares on exercise of stock options
Dividends on common shares
Purchase of common shares under Normal Course Issuer Bid
Cash flows used in financing activities
Investing activities
Net expenditures on exploration and evaluation assets
Net expenditures on property, plant and equipment
Acquisition of Devon assets (1)
Repayment of NWRP subordinated debt advances
Investment in other long-term assets
Net change in non-cash working capital
Cash flows used in investing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents – beginning of year
Cash and cash equivalents – end of year
Interest paid on long-term debt, net
Income taxes (received) paid
21
11,21
11,21
11,21
7
8
6,21
7,22
10
21
Note
2020
2019
2018
$
(435) $
5,416
$
2,591
6,046
5,546
5,161
(82)
205
(39)
(116)
(166)
—
(217)
185
(181)
(71)
(249)
(166)
4,714
338
(1,100)
1,481
(397)
166
(225)
108
(1,950)
(271)
(1,850)
(5)
(2,555)
—
124
—
(383)
(2,819)
223
190
13
(548)
—
—
—
321
(894)
(109)
(296)
(1,033)
8,829
2,025
(1,000)
—
—
—
(237)
360
(1,743)
(941)
(1,536)
(73)
(3,535)
(3,412)
—
—
(235)
(7,255)
45
139
184
745
$
$
(29) $
38
101
139
865
445
$
$
$
$
$
$
(146)
186
(35)
706
—
146
(452)
374
557
(23)
(290)
1,346
10,121
(1,595)
—
(1,236)
—
—
—
332
(1,562)
(1,282)
(5,343)
(266)
(4,175)
—
—
(28)
(345)
(4,814)
(36)
137
101
911
(225)
(1)
The acquisition of assets from Devon Canada Corporation ("Devon") in 2019 includes net working capital and other long-term assets of $195 million (note 7).
57
Canadian Natural 2020 Annual Report
Notes to the Consolidated Financial Statements
(tabular amounts in millions of Canadian dollars, unless otherwise stated)
1. Accounting Policies
Canadian Natural Resources Limited (the "Company") is a senior independent crude oil and natural gas exploration, development
and production company. The Company’s exploration and production operations are focused in North America, largely in
Western Canada; the United Kingdom ("UK") portion of the North Sea; and Côte d’Ivoire 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 Athabasca Oil Sands Project ("AOSP").
Within Western Canada, in the "Midstream and Refining" segment, the Company maintains certain activities that include
pipeline operations, an electricity co-generation system and an investment in the North West Redwater Partnership ("NWRP"),
a general partnership formed to upgrade and refine bitumen 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. If the Company’s share of the joint venture’s loss equals
or exceeds its interest in the joint venture, the Company discontinues recognizing its share of further losses. The Company
resumes recognizing profits when its share of profits exceeds the accumulated share of losses not recognized.
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.
Canadian Natural 2020 Annual Report
58
(D) INVENTORY
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 ("FPSO"). 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.
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
certain 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.
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Midstream, Refining and Head Office
The Company capitalizes all costs that expand the capacity or extend the useful life of the midstream, refining and head office
assets. Midstream and Refining 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. 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.
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(J) LEASES
At inception of a contract, the Company assesses whether a contract is, or contains a lease. A contract is, or contains a lease
if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To
assess whether a contract conveys the right to control the use of an identified asset, the Company assesses whether: the
contract involves the use of an identified asset; the Company has the right to obtain substantially all of the economic benefits
from the use of the asset throughout the period of use; and, the Company has the right to direct the use of the asset.
The Company recognizes a lease asset and a lease liability at the commencement date of the lease contract, which is the
date that the lease asset is available to the Company. The lease asset is initially measured at cost. The cost of a lease asset
includes the amount of the initial measurement of the lease liability, lease payments made prior to the commencement date,
initial direct costs and estimates of the asset retirement obligation, if any. Subsequent to initial recognition, the lease asset is
depreciated using the straight-line method over the earlier of the end of the useful life of the lease asset or the lease term.
Lease liabilities are initially measured at the present value of lease payments discounted at the rate implicit in the lease,
or if not readily determinable, the Company's incremental borrowing rate. Lease payments include fixed lease payments,
variable lease payments based on indices or rates, residual value guarantees, and purchase options expected to be exercised.
Subsequent to initial recognition, the lease liability is measured at amortized cost using the effective interest method. Lease
liabilities are remeasured if there are changes in the lease term or if the Company changes its assessment of whether it is
reasonably certain it will exercise a purchase, extension or termination option. Lease liabilities are also remeasured if there
are changes in the estimate of the amounts payable under the lease due to changes in indices or rates, or residual value
guarantees.
Lease assets are reported in a separate caption in the consolidated balance sheet. Lease liabilities are reported within other
long-term liabilities in the consolidated balance sheet.
Depreciation on lease assets used in the construction of property, plant and equipment is capitalized to the cost of those
assets over their period of use until such time as the property, plant and equipment is substantially available for its intended
use.
Where the Company acts as the operator of a joint operation, the Company recognizes 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
are recognized as other income in the consolidated statements of earnings.
On January 1, 2019 the Company adopted IFRS 16 "Leases" and as permitted in the transition requirements of the standard,
the Company continues to account for leases for the year ended December 31, 2018 in accordance with the Company's
previous accounting policy for leases as follows:
Finance leases, which transfer substantially all of the risks and rewards incidental to ownership of the leased item to the
Company, are capitalized at the commencement of the lease term at the fair value of the leased property or, if lower, at the
present value of the minimum lease payments. Capitalized leased assets are depreciated over the shorter of the estimated
useful life of the asset or the lease term. Operating lease payments are recognized in net earnings over the lease term.
(K) ASSET RETIREMENT OBLIGATIONS
The Company provides for asset retirement obligations on all of its property, plant and equipment 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.
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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.
(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.
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(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
remeasured 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 Performance Share Unit ("PSU") plan provides certain executive employees of the Company with the right to receive a
cash payment, the amount of which is determined by individual employee performance and the extent to which certain other
performance measures are met. PSUs vest three years from original grant date. The liability for PSUs is initially measured
in reference to the Company's stock price and the number of awards expected to vest and is remeasured at each reporting
period for changes in the fair value of the liability.
The unamortized costs of employer contributions to the Company’s share bonus program are included in other long-term
assets.
(Q) FINANCIAL INSTRUMENTS
The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost;
financial liabilities at amortized cost; and fair value through profit or loss. All financial instruments are measured at fair value
on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial
instrument.
Fair value through profit or loss financial instruments are subsequently measured at fair value with changes in fair value
recognized in net earnings. All other categories of financial instruments are measured at amortized cost using the effective
interest method.
Cash and cash equivalents, accounts receivable and certain other long-term assets are classified as financial assets at
amortized cost since it is the Company’s intention to hold these assets to maturity and the related cash flows are 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.
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(R) RISK MANAGEMENT ACTIVITIES
The Company periodically uses derivative financial instruments to manage its commodity price, foreign currency and interest
rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative
purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value.
The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions,
the Company primarily relied on external, readily-observable market inputs including quoted commodity prices and volatility,
interest rate yield curves, and foreign exchange rates. The carrying amount of a risk management liability is adjusted for the
Company’s own credit risk.
The Company documents all derivative financial instruments that are formally designated as hedging transactions at the
inception of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the
hedging relationship is evaluated, both at inception of the hedge and on an ongoing basis.
The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil
and natural gas in order to protect its cash flow for its capital expenditure programs. The effective portion of changes in the
fair value of derivative commodity price contracts formally designated as cash flow hedges is initially recognized in other
comprehensive income and is reclassified to risk management activities in net earnings in the same period or periods in
which the commodity is sold or purchased. The ineffective portion of changes in the fair value of these designated contracts is
recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural
gas commodity price contracts are recognized in risk management activities in net earnings.
The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on certain
long-term debt instruments. 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.
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(S) GOVERNMENT GRANTS
The Company receives or is eligible for government grants, including those introduced in response to the impact of the novel
coronavirus ("COVID-19"). Government grants are recognized when there is reasonable assurance that the Company will
comply with the conditions attached to the grant and the grant will be received. Grants that are intended to compensate for
expenses incurred are classified as other income.
(T) COMPREHENSIVE INCOME (LOSS)
Comprehensive income (loss) is comprised of the Company’s net earnings and other comprehensive income (loss). Other
comprehensive income (loss) 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.
(U) 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.
(V) 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.
(W) DIVIDENDS
Dividends on common shares are recognized in the Company’s financial statements in the period in which the dividends are
declared by the Board of Directors.
2. Changes in Accounting Policies
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 permit a simplified assessment of whether an acquired set of activities and assets is a group
of assets rather than a business. The amendments apply to business combinations after the date of adoption. The Company
prospectively adopted the amendments on January 1, 2020.
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 judgements related to the preparation of
financial statements. The Company prospectively adopted the amendments on January 1, 2020.
3. Accounting Standards Issued But Not Yet Applied
In January 2020, the IASB issued amendments to IAS 1 "Presentation of Financial Statements" to clarify that liabilities are
classified as either current or non-current, depending on the existence of the substantive right at the end of the reporting
period for an entity to defer settlement of the liability for at least twelve months after the reporting period. The amendments
are effective January 1, 2023 with early adoption permitted. The amendments are required to be adopted retrospectively. The
Company is assessing the impact of these amendments on its consolidated financial statements.
In May 2020, the IASB issued amendments to IAS 16 “Property, Plant and Equipment” to require proceeds received from
selling items produced while the entity is preparing the asset for its intended use to be recognized in net earnings, rather
than as a reduction in the cost of the asset. The amendments are effective January 1, 2022 with early adoption permitted. The
Company is assessing the impact of these amendments on its consolidated financial statements.
In August 2020, the IASB issued Interest Rate Benchmark Reform (Phase 2) in response to the Financial Stability Board’s
mandated reforms to InterBank Offered Rates (“IBORs”), with financial regulators proposing that they be replaced by a
number of new local currency denominated alternative benchmark rates. The amendments are effective for annual periods
beginning on or after January 1, 2021 and are to be applied retrospectively, with early adoption permitted. The Company is
assessing the impact of IBOR reform and the IASB amendments and does not expect that these amendments will have a
significant impact on the Company's consolidated financial statements.
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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.
(C) INCOME TAXES
The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the Company
to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with
respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of
tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company
recognizes a liability for a tax filing position based on its assessment of the probability that additional taxes may ultimately be
due.
(D) FAIR VALUE OF DERIVATIVES AND OTHER FINANCIAL INSTRUMENTS
The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The
Company uses its judgement to select a variety of methods and make assumptions that are primarily based on market
conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in
measuring the value of financial instruments that are not traded in active markets, including quoted commodity prices and
volatility, interest rate yield curves and foreign exchange rates.
(E) PURCHASE PRICE ALLOCATIONS
Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on
their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates,
assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts
assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties together
with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities
and future net earnings due to the impact on future depletion, depreciation, and amortization expense and impairment tests.
(F) SHARE-BASED COMPENSATION
The Company has made various assumptions in estimating the fair values of stock options granted under its Option Plan,
including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding
are remeasured for changes in the 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.
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(H) IMPAIRMENT OF ASSETS
The recoverable amount of a CGU or an individual asset has been determined as the higher of the CGUs' or the assets'
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) LEASES
Purchase, extension and termination options are included in certain of the Company's leases to provide operational flexibility.
To measure the lease liability, the Company uses judgement to assess the likelihood of exercising these options. These
assessments are reviewed when significant events or circumstances indicate that the likelihood of exercising these options
may have changed. The Company also uses estimates to determine its incremental borrowing costs if the interest rate implicit
in the lease is not readily determinable.
(J) 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.
(K) IMPACT OF COVID-19
For the year ended December 31, 2020, COVID-19 had an impact on the global economy, including the oil and gas industry.
Business conditions in 2020 reflected the market uncertainty associated with COVID-19. The Company has taken into account
the impacts of COVID-19 and the unique circumstances it has created in making estimates, assumptions and judgements
in the preparation of the consolidated financial statements, and continues to monitor the developments in the business
environment and commodity market. Actual results may differ from estimated amounts, and those differences may be
material.
5. Inventory
Product inventory
Materials and supplies
2020
390
670
$
1,060
$
2019
468
684
1,152
$
$
The Company recorded a write-down of its product inventory of $nil from cost to net realizable value as at December 31, 2020
(2019 – $4 million).
67
Canadian Natural 2020 Annual Report
6. Exploration and Evaluation Assets
Exploration and Production
North
America
North Sea
Offshore
Africa
Cost
At December 31, 2018
$
2,348
$
— $
Additions
Acquisition of Devon assets (note 7)
Transfers to property, plant and equipment
Foreign exchange adjustments
At December 31, 2019
Additions/Acquisitions
Transfers to property, plant and equipment
Derecognitions and other
Foreign exchange adjustments
38
91
(219)
—
2,258
40
(194)
(3)
—
—
—
—
—
—
—
—
—
—
37
33
—
—
(1)
69
15
—
—
(1)
Oil Sands
Mining and
Upgrading
Total
$
252
$
2,637
—
—
—
—
252
—
—
—
—
71
91
(219)
(1)
2,579
55
(194)
(3)
(1)
At December 31, 2020
$
2,101
$
— $
83
$
252
$
2,436
On October 6, 2020, the Company completed the acquisition of all of the issued and outstanding shares of Painted Pony
Energy Ltd. for cash consideration of $111 million, including $15 million of exploration and evaluation assets (note 7).
During 2019, the Company completed the acquisition of substantially all of the assets of Devon including thermal in situ
and heavy crude oil assets, for total cash purchase consideration of $3,412 million, including $91 million of exploration and
evaluation assets (note 7).
During 2018, 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
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.
During 2018, 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 term of the various agreements, in the event of a commercial crude
oil or natural gas discovery on the exploration right and conversion to a production right, additional cash payments would be
made to the Company.
Canadian Natural 2020 Annual Report
68
7. Property, Plant and Equipment
Oil Sands
Mining and
Upgrading
Midstream
and
Refining
Head
Office
Total
Exploration and Production
North
America North Sea
Offshore
Africa
Cost
At December 31, 2018
$ 67,007 $
7,321 $ 5,471 $
43,147 $
441 $
435 $ 123,822
Additions
Acquisition of Devon assets
Transfers from E&E assets
Derecognitions (1)
Foreign exchange adjustments and
other
At December 31, 2019
Additions/Acquisitions
Transfers from E&E assets
Derecognitions
Disposals
Foreign exchange adjustments and
other
2,613
3,325
219
(537)
349
—
—
—
233
—
—
2,154
—
—
(1,515)
(285)
—
(374)
(256)
—
72,627
1,789
194
(521)
(92)
7,296
104
—
(3)
—
3,933
94
—
—
—
—
(114)
(64)
45,016
1,328
—
(634)
—
—
10
—
—
—
—
34
—
—
(3)
—
5,393
3,325
219
(2,340)
(630)
451
466
129,789
6
—
—
—
—
19
—
—
—
—
3,340
194
(1,158)
(92)
(178)
At December 31, 2020
$ 73,997 $
7,283 $ 3,963 $
45,710 $
457 $
485 $ 131,895
Accumulated depletion
and depreciation
At December 31, 2018
Expense
Derecognitions (1)
Foreign exchange adjustments and
other
At December 31, 2019
Expense
Derecognitions
Disposals
Foreign exchange adjustments and
other
$ 43,881 $
5,735 $ 4,203 $
4,981 $
138 $
325 $ 59,263
3,215
(537)
256
—
214
(1,515)
1,564
(285)
18
(279)
(190)
(13)
46,577
3,676
(521)
(63)
5,712
247
(3)
—
2,712
161
—
—
(28)
(103)
(51)
6,247
1,668
(634)
—
8
15
—
—
23
(3)
—
153
345
15
—
—
—
25
—
—
—
5,287
(2,340)
(464)
61,746
5,792
(1,158)
(63)
(174)
At December 31, 2020
$ 49,641 $
5,853 $ 2,822 $
7,289 $
168 $
370 $ 66,143
Net book value
- at December 31, 2020
$ 24,356 $
1,430 $ 1,141 $
38,421 $
289 $
115 $ 65,752
- at December 31, 2019
$ 26,050 $
1,584 $ 1,221 $
38,769 $
298 $
121 $ 68,043
(1)
Following demobilization of the FPSO at the Olowi field, Gabon in 2019, the Company derecognized property, plant and equipment and associated
accumulated depletion and depreciation of $1,515 million.
As at December 31, 2020, the Company assessed the recoverability of its property, plant and equipment and its exploration
and evaluation assets, and determined the carrying amounts of all of its cash generating units 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 2020, pre-tax interest of $24 million (2019 – $53 million; 2018 – $69 million) was capitalized to property, plant and
equipment using a weighted average capitalization rate of 3.5% (2019 – 4.0%; 2018 – 3.9%).
69
Canadian Natural 2020 Annual Report
As at December 31, 2020, the Company recognized certain project costs, not subject to depletion and depreciation, of
$117 million in the Oil Sands Mining and Upgrading segment (2019 – $115 million in the Oil Sands Mining and Upgrading
segment).
Acquisitions in the current and comparative years have been accounted for as business combinations 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.
ACQUISITION OF PAINTED PONY ENERGY LTD. ("PAINTED PONY")
On October 6, 2020, the Company completed the acquisition of all the issued and outstanding shares of Painted Pony for total
cash consideration of $111 million. Painted Pony is involved in the exploration for and development of natural gas and natural
gas liquids in Northeast British Columbia.
The allocation of the purchase price was based on management's best estimates of the fair value of the assets acquired and
liabilities assumed as of the acquisition date. The below amounts are estimates, and may be subject to change based on the
receipt of new information.
The following provides a summary of the net assets acquired relating to the acquisition:
Property, plant and equipment
Exploration and evaluation assets
Other long-term assets
Long-term debt
Asset retirement obligations
Other long-term liabilities
Deferred tax asset
Net assets acquired
Less: cash consideration
Gain on acquisition (1)
$
$
750
15
204
(397)
(13)
(442)
211
328
111
217
(1) Gain on acquisition of $217 million represents the excess of the fair value of the net assets acquired compared with the total purchase consideration.
In connection with the acquisition the Company assumed certain product transportation and processing commitments (note
20).
ACQUISITION OF THERMAL IN SITU AND PRIMARY HEAVY CRUDE OIL ASSETS
On June 27, 2019, the Company completed the acquisition of substantially all of the assets of Devon including thermal in situ
and heavy crude oil assets, for total cash purchase consideration of $3,412 million.
In connection with the acquisition, the Company arranged a $3,250 million committed term facility (note 11) and assumed
certain product transportation commitments (note 20).
The following provides a summary of the net assets acquired relating to the acquisition:
Property, plant and equipment
Exploration and evaluation assets
Inventory, prepaids and other long-term assets
Accrued liabilities
Asset retirement obligations
Net assets acquired
$
3,325
91
195
(21)
(178)
$
3,412
As a result of the acquisition, during the year ended December 31, 2019, revenue increased by approximately $1,540 million to
$22,871 million and revenue, less production and transportation, blending and feedstock expenses increased by approximately
$590 million to $11,895 million.
OTHER ACQUISITIONS AND DERECOGNITIONS
During 2019, the Company acquired a number of producing crude oil and natural gas properties in the North America
Exploration and Production segment for net cash consideration of $80 million (2018 – $170 million) and assumed associated
asset retirement obligations of $20 million (2018 – $13 million). No net deferred income tax liabilities were recognized (2018 –
$nil) and no pre-tax gains were recognized on these net transactions (2018 – pre-tax gain of $47 million).
Canadian Natural 2020 Annual Report
70
During 2018, 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.
During 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).
8. Leases
LEASE ASSETS
Product
transportation
and storage
Field
equipment
and power
Offshore
vessels and
equipment
Office leases
and other
Total
$
332
$
252
$
132
$ 1,539
At January 1, 2019 (1)
$
Additions
Depreciation
Derecognitions
Foreign exchange adjustments and other
823
452
(106)
—
(3)
At December 31, 2019
$
1,166
$
Additions (2)
Depreciation
Derecognitions
Foreign exchange adjustments and other
17
(124)
(20)
(1)
43
(54)
(6)
2
317
121
(53)
(5)
(1)
12
(72)
—
(10)
20
(27)
—
(1)
527
(259)
(6)
(12)
$
182
$
124
$ 1,789
7
(51)
(10)
—
3
(26)
—
(1)
148
(254)
(35)
(3)
At December 31, 2020
$
1,038
$
379
$
128
$
100
$ 1,645
(1)
(2)
The Company adopted IFRS 16 "Leases" on January 1, 2019 using the modified retrospective approach.
The acquisition of Painted Pony in 2020 included lease assets of $93 million (note 7).
LEASE ASSETS, BY SEGMENT
As at December 31, 2020 and 2019, the Company had the following lease assets by segment:
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Head office
2020
$
345
$
7
126
1,080
87
$
1,645
$
2019
300
38
154
1,191
106
1,789
71
Canadian Natural 2020 Annual Report
LEASE LIABILITIES
The Company measures its lease liabilities at the discounted value of its lease payments during the lease term. Lease
liabilities at December 31, 2020 and 2019 were as follows:
Lease liabilities
Less: current portion
2020
1,690
$
189
1,501
$
2019
1,809
233
1,576
$
$
In addition to the lease assets disclosed above, on an ongoing basis the Company enters into short-term leases related to its
Exploration and Production and Oil Sands Mining and Upgrading activities.
Other amounts included in net earnings and cash flows during 2020 and 2019 are provided below:
Expenses relating to short-term leases (1)
Interest expense on lease liabilities
Variable lease payments not included in the measurement of lease liabilities
Total cash outflows for leases (2)
2020
409
67
85
983
$
$
$
$
$
$
$
$
(1) During 2020, the Company capitalized $197 million (2019 - $305 million) of short-term leases as additions to property, plant and equipment.
(2) Comprised of cash outflows relating to lease liabilities, short-term leases, and variable lease payments.
9. Investments
As at December 31, 2020 and 2019, the Company had the following investments:
Investment in PrairieSky Royalty Ltd.
Investment in Inter Pipeline Ltd.
2020
228
$
77
305
$
$
$
2019
448
70
118
1,178
2019
345
145
490
INVESTMENT IN PRAIRIESKY ROYALTY LTD.
The Company’s investment of 22.6 million common shares of PrairieSky Royalty Ltd. ("PrairieSky") does not constitute
significant influence, and is accounted for at fair value through profit or loss, measured at each reporting date. As at December
31, 2020, the market price per common share was $10.09 (December 31, 2019 - $15.23). As at December 31, 2020, the
Company’s investment in 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 from the investment in PrairieSky was comprised as follows:
Fair value loss from PrairieSky
Dividend income from PrairieSky
2020
2019
$
$
117
$
(9)
108
$
55
$
(17)
38
$
2018
326
(17)
309
INVESTMENT IN INTER PIPELINE LTD.
The Company's investment of 6.4 million common shares of Inter Pipeline Ltd. ("Inter Pipeline") does not constitute significant
influence, and is accounted for at fair value through profit or loss, measured at each reporting date. As at December 31, 2020,
the markety price per common share was $11.87 (December 31, 2019 - $22.54). As at December 31, 2020, the Company's
investment in Inter Pipeline was classified as a current asset. Inter Pipeline is in the business of oil sands transportation,
natural gas liquids processing and conventional oil pipelines in Canada and bulk liquid storage in Europe.
The loss (gain) from the investment in Inter Pipeline was comprised as follows:
Fair value loss (gain) from Inter Pipeline
Dividend income from Inter Pipeline
2020
68
(5)
63
$
$
2019
(21)
(11)
(32)
$
$
2018
43
(11)
32
$
$
On February 22, 2021, Brookfield Infrastructure Partners L.P. commenced a formal offer to purchase all issued and outstanding
Inter Pipeline common shares for $16.50 per common share. The offer is open for acceptance until Monday, June 7, 2021.
Canadian Natural 2020 Annual Report
72
10. Other Long-Term Assets
North West Redwater Partnership
Prepaid cost of service toll
Risk management (note 19)
Long-term inventory
Other (1)
Less: current portion
$
$
2020
555
162
136
121
190
1,164
82
$
1,082
$
2019
652
130
290
121
84
1,277
54
1,223
(1)
The acquisition of Painted Pony in 2020 included physical sales contracts valued at $111 million (note 7).
INVESTMENT IN NORTH WEST REDWATER PARTNERSHIP
The Company has a 50% equity investment in and has made subordinated debt advances of $555 million to NWRP (2019 -
$652 million), including accrued interest. The subordinated debt is repayable over 10 years commencing July 2021, and bears
interest at prime plus 6%. During the year ended December 31, 2020, $124 million of the subordinated debt was repaid to
the Company. NWRP operates a 50,000 barrels per day bitumen upgrader and refinery that targets to process 12,500 barrels
per day of bitumen feedstock for the Company and 37,500 barrels per day of bitumen feedstock for the Alberta Petroleum
Marketing Commission, an agent of the Government of Alberta, under a 30-year fee-for-service tolling agreement.
On June 1, 2020, the refinery achieved the Commercial Operation Date ("COD"), pursuant to the terms of the tolling agreement.
The Company is unconditionally obligated to pay its 25% pro rata share of the debt tolls over the 30-year tolling period (note
20). Subsequent to COD, sales of diesel and refined products and associated refining tolls are recognized in the Midstream
and Refining segment.
NWRP has a secured $3,500 million syndicated credit facility, of which $2,000 million is revolving and matures in June 2021
and the remaining $1,500 million is fully drawn on a non-revolving basis. In 2019, NWRP extended the $1,500 million non-
revolving facility, previously scheduled to mature in February 2020, to February 2021. Subsequent to December 31, 2020,
NWRP extended the $1,500 million non-revolving facility to June 2021. As at December 31, 2020, NWRP had borrowings
of $2,866 million under the syndicated credit facility, which was classified as current (December 31, 2019 - $2,715 million
classified as long-term).
The unrecognized share of the equity loss from NWRP for 2020 was $94 million (December 31, 2019 - recognized equity
loss of $287 million and unrecognized equity loss of $59 million; December 31, 2018 - recognized equity loss of $5 million).
As at December 31, 2020, the cumulative unrecognized share of equity losses from NWRP was $153 million (December 31,
2019 – $59 million).
The assets, liabilities, partners’ equity, product sales and equity loss related to NWRP and the Company’s 50% interest at
December 31, 2020 and 2019 were comprised as follows:
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Partners’ equity
Revenue (3)
Net loss
2020 (1)
2019 (2)
NWRP
100% interest
Company
50% interest
NWRP
100% interest
Company
50% interest
$
$
$
$
$
$
$
230
11,098
3,146
8,488
(306)
1,348
188
$
$
$
$
$
$
$
115
5,549
1,573
4,244
(153)
674
94
$
$
$
$
$
$
$
248
11,328
384
11,310
(118)
1,736
692
$
$
$
$
$
$
$
124
5,664
192
5,655
(59)
868
346
(1)
(2)
(3)
In 2020, included in the net loss is the impact of depreciation and amortization expense at 100% interest of $214 million (50% interest - $107 million) and
interest and other financing expense at 100% interest of $420 million (50% interest - $210 million).
In 2019, included in the net loss is the impact of depreciation and amortization expense at 100% interest of $152 million (50% interest - $76 million) and
interest and other financing expense at 100% interest of $398 million (50% interest - $199 million).
Included in NWRP’s revenue for the period subsequent to COD in 2020, is $174 million paid by the Company for its 25% share of the refining toll.
73
Canadian Natural 2020 Annual Report
11. Long-Term Debt
Canadian dollar denominated debt, unsecured
Bank credit facilities
Medium-term notes
2.05% debentures due June 1, 2020
2.89% debentures due August 14, 2020
3.31% debentures due February 11, 2022
1.45% debentures due November 16, 2023
3.55% debentures due June 3, 2024
3.42% debentures due December 1, 2026
2.50% debentures due January 17, 2028
4.85% debentures due May 30, 2047
US dollar denominated debt, unsecured
Bank credit facilities (December 31, 2020 – US$3,953 million;
December 31, 2019 – US$3,745 million)
Commercial paper (December 31, 2020 – US$426 million;
December 31, 2019 – US$254 million)
US dollar debt securities
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)
2.05% due July 15, 2025 (US$600 million)
3.85% due June 1, 2027 (US$1,250 million)
2.95% due July 15, 2030 (US$500 million)
7.20% due January 15, 2032 (US$400 million)
6.45% due June 30, 2033 (US$350 million)
5.85% due February 1, 2035 (US$350 million)
6.50% due February 15, 2037 (US$450 million)
6.25% due March 15, 2038 (US$1,100 million)
6.75% due February 1, 2039 (US$400 million)
4.95% due June 1, 2047 (US$750 million)
Long-term debt before transaction costs and original issue discounts, net
Less: original issue discounts, net (1)
transaction costs (1) (2)
Less: current portion of commercial paper
current portion of other long-term debt (1) (2)
2020
2019
$
1,614
$
1,688
—
—
1,000
500
500
600
300
300
900
1,000
1,000
—
500
600
—
300
4,814
5,988
5,041
544
638
1,276
638
765
765
1,595
638
510
446
446
574
1,403
510
957
16,746
21,560
18
89
21,453
544
799
$
20,110
$
4,855
329
648
1,296
648
778
—
1,621
—
519
454
454
583
1,426
519
972
15,102
21,090
17
91
20,982
329
2,062
18,591
(1)
(2)
The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the
outstanding debt.
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.
Canadian Natural 2020 Annual Report
74
BANK CREDIT FACILITIES AND COMMERCIAL PAPER
As at December 31, 2020, the Company had undrawn revolving bank credit facilities of $4,958 million. Additionally, the
Company had in place fully drawn term credit facilities of $6,738 million. Details of these facilities are described below. The
Company also has certain other dedicated credit facilities supporting letters of credit. At December 31, 2020, the Company
had $544 million drawn under its commercial paper program, and reserved capacity under its revolving bank credit facilities
for amounts outstanding under this program.
■
■
■
■
■
■
■
a $100 million demand credit facility;
a $1,000 million non-revolving term credit facility maturing February 2022;
a $2,425 million revolving syndicated credit facility maturing June 2022;
a $3,088 million non-revolving term credit facility maturing June 2022;
a $2,650 million non-revolving term credit facility maturing February 2023;
a $2,425 million revolving syndicated credit facility maturing June 2023; and
a £5 million demand credit facility related to the Company’s North Sea operations.
Borrowings under the Company's non-revolving term credit 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. As at December 31,
2020, the non-revolving term credit facilities were fully drawn.
During 2020, the $750 million non-revolving term credit facility, originally due February 2021, was extended to February 2022
and increased to $1,000 million. Subsequent to December 31, 2020, the facility was extended to February 2023.
During 2019, the Company fully repaid and cancelled the $1,800 million non-revolving term credit facility scheduled to mature
in May 2020. In addition, the $2,200 million non-revolving term credit facility, originally due October 2020, was extended to
February 2023 and increased to $2,650 million.
During 2019, the Company entered into a $3,250 million non-revolving term credit facility to finance the acquisition of assets
from Devon (note 7). During 2020, the Company repaid $162.5 million related to the required annual amortization, reducing
the facility balance to $3,088 million. Subsequent to December 31, 2020, the Company repaid a further $362.5 million on the
facility, reducing the outstanding balance to $2,725 million, and satisfying the required annual amortization of $162.5 million
originally due in June 2021. The facility matures in June 2022.
During 2019, the Company extended the $2,425 million revolving syndicated credit facility, of which $330 million was originally
due June 2019 and $2,095 million was originally due June 2021, to 2023. The revolving credit facilities are extendible annually
at the mutual agreement of the Company and the lenders. If the facilities are not extended, the full amount of the outstanding
principal would be repayable on the maturity date. Borrowings under the Company's revolving term credit 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 2019, the Company reduced the £15 million demand credit facility related to the Company's North Sea operations, to
£5 million.
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 revolving 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,
2020 was 1.1% (December 31, 2019 – 2.5%), and on total long-term debt outstanding for the year ended December 31, 2020
was 3.5% (December 31, 2019 – 4.0%).
As at December 31, 2020, letters of credit and guarantees aggregating to $489 million were outstanding (December 31, 2019
- $468 million).
MEDIUM-TERM NOTES
During 2020, the Company issued $500 million of 1.45% medium-term notes due November 2023 and $300 million of 2.50%
medium-term notes due January 2028.
After issuing these securities, the Company had $2,200 million remaining on its base shelf prospectus that allows for the
offer for sale from time to time of up to $3,000 million of medium-term notes in Canada, which expires August 2021. 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 2020, the Company repaid $1,000 million of 2.89% medium term notes and $900 million of 2.05% medium term
notes.
During 2019, the Company repaid $500 million of 2.60% medium-term notes and $500 million of 3.05% medium-term notes.
75
Canadian Natural 2020 Annual Report
US DOLLAR DEBT SECURITIES
During 2020, the Company issued US$600 million of 2.05% notes due July 2025 and US$500 million of 2.95% notes due
July 2030.
After issuing these securities, the Company had US$1,900 million remaining on its 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
2021. 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
2021
2022
2023
2024
2025
Thereafter
12. Other Long-Term Liabilities
Asset retirement obligations
Lease liabilities (note 8) (1)
Share-based compensation
Risk management (note 19)
Deferred purchase consideration (2)
Other (3)
Less: current portion
$
$
$
$
$
$
$
$
2020
5,861
1,690
160
160
72
343
8,286
722
The acquisition of Painted Pony in 2020 included lease liabilities of $93 million (note 7).
(1)
(2) Relates to the acquisition of the Joslyn oil sands project in 2018, payable in annual installments of $25 million over the next three years.
The acquisition of Painted Pony in 2020 included product transportation and processing obligations valued at $268 million (note 7).
(3)
$
7,564
$
Repayment
1,343
4,887
4,383
1,138
1,530
8,279
2019
5,771
1,809
297
112
95
98
8,182
819
7,363
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 discounted using a weighted average discount rate of 3.7% (2019 – 3.8%; 2018 – 5.0%) and inflation rates of
up to 2% (December 31, 2019 – 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 and timing estimates
Change in discount rates
Foreign exchange adjustments
Balance – end of year
Less: current portion
Canadian Natural 2020 Annual Report
2020
2019
$
5,771
$
3,886
$
5
13
(249)
205
(134)
253
(3)
5,861
184
15
198
(296)
190
412
1,412
(46)
5,771
208
$
5,677
$
5,563
$
2018
4,327
19
6
(290)
186
(111)
(334)
83
3,886
186
3,700
76
Segmented Asset Retirement Obligations
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream and Refining
2020
2019
$
2,899
$
2,792
787
174
1,999
2
$
5,861
$
816
161
2,000
2
5,771
SHARE-BASED COMPENSATION
The liability for share-based compensation includes costs incurred under the Company’s Stock Option Plan and PSU plans. The
Company’s Stock 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 PSU plan provides certain executive employees of the Company with the right
to receive a cash payment, the amount of which is determined by individual employee performance and the extent to which
certain other performance measures are met.
The Company recognizes a liability for potential cash settlements under these plans. The current portion of the liability
represents the maximum amount of the liability payable within the next twelve month period if all vested stock options and
PSUs are settled in cash.
Balance – beginning of year
Share-based compensation (recovery) expense
Cash payment for stock options surrendered and PSUs
vested
Transferred to common shares
Charged to (recovered from) Oil Sands Mining and
Upgrading, net
Balance – end of year
Less: current portion
2020
$
297
$
(82)
(39)
(21)
5
160
119
$
2019
124
223
(2)
(53)
5
297
227
$
41
$
70
$
2018
414
(146)
(5)
(120)
(19)
124
92
32
Included within share-based compensation liability as at December 31, 2020 was $49 million (2019 – $62 million; 2018 –
$13 million) related to PSUs granted to certain executive employees.
The fair value of stock options outstanding was estimated using the Black-Scholes valuation model with the following weighted
average assumptions:
Fair value
Share price
Expected volatility
Expected dividend yield
Risk free interest rate
Expected forfeiture rate
Expected stock option life (1)
(1) At original time of grant.
$
$
$
$
2020
3.47
30.59
39.8%
5.6%
0.3%
4.3%
$
$
2019
7.88
42.00
26.7%
3.6%
1.7%
4.3%
2018
3.33
32.94
27.4%
4.1%
1.9%
4.2%
4.3 years
4.4 years
4.4 years
The intrinsic value of vested stock options at December 31, 2020 was $11 million (2019 – $75 million; 2018 – $27 million).
77
Canadian Natural 2020 Annual Report
13. Income Taxes
The provision for income tax was as follows:
(Recovery) expense
2020
Current corporate income tax – North America
$
(245)
$
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.
(4)
17
(31)
6
(257)
(181)
—
(181)
$
2019
354
112
44
(89)
13
434
(895)
1
(894)
2018
312
28
54
(29)
9
374
540
17
557
931
$
(438)
$
(460)
$
The provision for income tax is different from the amount computed by applying the combined statutory Canadian federal and
provincial income tax rates to earnings before taxes. The reasons for the difference are as follows:
Canadian statutory income tax rate
2020
24.1%
2019
26.5%
Income tax provision at statutory rate
$
(211)
$
1,313
$
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
(25)
11
(52)
(10)
(25)
—
(52)
(62)
(10)
(2)
(76)
32
(48)
(65)
47
(1,618)
—
(41)
(65)
61
$
(438)
$
(460)
$
2018
27.0%
951
(3)
3
6
142
(41)
—
(119)
(136)
142
(14)
931
Canadian Natural 2020 Annual Report
78
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
$
11,922
$
12,074
2020
2019
Lease assets
Unrealized risk management activities
Investments
Investment in North West Redwater Partnership
Other
Deferred income tax assets
Asset retirement obligations
Lease liabilities
Share-based compensation
Loss carryforwards
Unrealized foreign exchange loss on long-term debt
Deferred PRT
Net deferred income tax liability
380
—
14
767
8
412
27
36
593
52
13,091
13,194
(1,495)
(388)
(12)
(1,032)
(20)
—
(1,488)
(416)
(16)
(685)
(49)
(1)
(2,947)
(2,655)
$
10,144
$
10,539
Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows:
2020
2019
2018
Property, plant and equipment and exploration and evaluation assets
$
(158)
$
(775)
$
Lease assets
Unrealized foreign exchange loss (gain) on long-term debt
Unrealized risk management activities
Asset retirement obligations
Lease liabilities
Share-based compensation
Loss carryforwards
Investments
Investment in North West Redwater Partnership
Deferred PRT
PRT deduction for corporate income tax
Other
(11)
29
(8)
(13)
6
4
(182)
(22)
174
—
—
—
414
55
(14)
(317)
(418)
(11)
170
(10)
179
1
—
(168)
$
(181)
$
(894)
$
281
—
(75)
18
175
—
(5)
(61)
(50)
162
17
(7)
102
557
79
Canadian Natural 2020 Annual Report
The following table summarizes the movements of the net deferred income tax liability during the year:
Balance – beginning of year
$
10,539
$
11,451
$
2020
2019
Deferred income tax (recovery) expense
Deferred income tax expense (recovery) included in other
comprehensive income
Foreign exchange adjustments
Business combinations (note 6,7)
Balance – end of year
(181)
—
(3)
(211)
(894)
8
(26)
—
$
10,144
$
10,539
$
11,451
2018
10,975
557
(6)
41
(116)
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 2019, the Government of Alberta enacted legislation that decreased the provincial corporate income tax rate from 12%
to 11% effective July 2019, with a further 1% rate reduction every year on January 1 until the provincial corporate income
tax rate is 8% on January 1, 2022. As a result of this corporate income tax rate reduction, the Company's deferred corporate
income tax liability decreased by $1,618 million for the years ended December 31, 2019. During 2020, the Government
of Alberta substantively enacted legislation to accelerate this reduction, lowering the corporate tax rate from 10% to 8%,
effective July 1, 2020. This acceleration did not have a significant impact on the Company's deferred corporate income tax
liability at December 31, 2020.
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.
Canadian Natural 2020 Annual Report
80
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
2020
Number
of shares
(thousands)
Amount
2019
Number
of shares
(thousands)
Amount
1,186,857
$
9,533
1,201,886
$
9,323
Issued upon exercise of stock options
3,979
108
10,871
360
Previously recognized liability on stock options exercised for
common shares
—
Purchase of common shares under Normal Course Issuer Bid
(6,970)
21
(56)
—
(25,900)
53
(203)
Balance – end of year
1,183,866
$
9,606
1,186,857
$
9,533
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 3, 2021, the Board of Directors declared a quarterly dividend of $0.47 per common share, an increase from the
previous quarterly dividend of $0.425 per common share, beginning with the dividend payable on April 5, 2021. On March
4, 2020, the Board of Directors declared a quarterly dividend of $0.425 per common share, an increase from the previous
quarterly dividend of $0.375 per common share. 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. On February 28,
2018, the Board of Directors declared a quarterly dividend of $0.335 per common share.
NORMAL COURSE ISSUER BID
On May 21, 2019, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities
of the Toronto Stock Exchange ("TSX"), alternative Canadian trading platforms, and the New York Stock Exchange ("NYSE"), up
to 59,729,706 common shares, over a 12-month period commencing May 23, 2019 and ending May 22, 2020. The Company
did not renew its Normal Course Issuer bid after its expiry in May 2020.
For the year ended December 31, 2020, the Company purchased 6,970,000 common shares at a weighted average price of
$38.84 per common share for a total cost of $271 million. Retained earnings were reduced by $215 million, representing the
excess of the purchase price of common shares over their average carrying value.
On March 3, 2021, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with
the TSX to purchase, by way of a Normal Course Issuer Bid, up to 5.0% of its issued and outstanding common shares for the
purpose of repurchasing a number of common shares approximately equal to the number of options exercised throughout the
year in order to eliminate dilution for shareholders. Subject to acceptance of the Notice of Intention by the TSX, the purchases
would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE.
SHARE-BASED COMPENSATION – 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 7%" plan, whereby the aggregate number of common shares that may be reserved for issuance
under the plan shall not exceed 7% of the common shares outstanding from time to time.
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Canadian Natural 2020 Annual Report
The following table summarizes information relating to stock options outstanding at December 31, 2020 and 2019:
Outstanding – beginning of year
Granted
Exercised for common shares
Surrendered for cash settlement
Forfeited
Outstanding – end of year
Exercisable – end of year
2020
2019
Stock options
(thousands)
Weighted
average
exercise price
Stock options
(thousands)
Weighted
average
exercise price
47,646
12,032
(3,979)
(757)
(6,286)
48,656
17,970
$
$
$
$
$
$
$
38.04
32.89
27.24
29.34
39.65
37.53
39.59
46,685
16,314
(10,871)
(1,003)
(3,479)
47,646
17,057
$
$
$
$
$
$
$
37.92
34.84
33.16
34.52
37.65
38.04
38.74
The range of exercise prices of stock options outstanding and exercisable at December 31, 2020 was as follows:
Range of exercise prices
$ 20.76
$ 25.00
$ 30.00
$ 35.00
$ 40.00
$ 45.00
-
-
-
-
-
-
$ 24.99
$ 29.99
$ 34.99
$ 39.99
$ 44.99
$ 46.74
Stock options outstanding
Stock options exercisable
Stock options
outstanding
(thousands)
Weighted
average
remaining
term (years)
Weighted
average
exercise price
Stock options
exercisable
(thousands)
Weighted
average
exercise price
3,829
1,975
4,177
22,495
12,935
3,245
48,656
3.86
1.81
4.23
3.44
1.53
2.40
2.90
$
$
$
$
$
$
$
21.12
28.48
32.37
37.49
43.57
45.21
37.53
944
1,362
378
4,721
8,884
1,681
17,970
$
$
$
$
$
$
$
21.64
28.85
32.40
37.42
43.54
45.18
39.59
15. Accumulated Other Comprehensive Income
The components of accumulated other comprehensive income, net of taxes, were as follows:
Derivative financial instruments designated as cash flow hedges
Foreign currency translation adjustment
2020
69
$
(61)
8
$
2019
71
(37)
34
$
$
Canadian Natural 2020 Annual Report
82
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, 2020, the ratio was within the target range at 40%.
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
$
$
2020
21,269
32,380
40%
$
$
2019
20,843
34,991
37%
(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, 2020, the Company was in compliance with this covenant.
17. Net Earnings Per Common Share
Weighted average common shares outstanding
– basic (thousands of shares)
2020
2019
2018
1,181,768
1,190,977
1,218,798
Effect of dilutive stock options (thousands of shares)
—
2,129
4,960
Weighted average common shares outstanding
– diluted (thousands of shares)
Net earnings (loss)
Net earnings per common share
– basic
– diluted
1,181,768
1,193,106
1,223,758
$
$
$
(435)
(0.37)
(0.37)
$
$
$
5,416
4.55
4.54
$
$
$
2,591
2.13
2.12
In 2020, the Company excluded 44,117,000 potentially anti-dilutive stock options from the calculation of diluted earnings per
common share (year ended December 31, 2019 – 36,834,000; 2018 – 23,458,000).
83
Canadian Natural 2020 Annual Report
867
—
(69)
798
(59)
739
Total
2,190
305
691
(667)
(2,346)
(1,922)
18. Interest and Other Financing Expense
2020
2019
2018
Interest and other financing expense:
Long-term debt
Lease liabilities (1)
Less: amounts capitalized on qualifying assets
Total interest and other financing expense
Total interest income
$
785
$
895
$
67
(24)
828
(72)
70
(53)
912
(76)
Net interest and other financing expense
$
756
$
836
$
(1)
The Company adopted IFRS 16 "Leases" on January 1, 2019 using the modified retrospective approach.
19. Financial Instruments
The carrying amounts of the Company’s financial instruments by category were as follows:
2020
Asset (liability)
Financial
assets at
amortized cost
Fair value
through
profit or loss
Derivatives
used for
hedging
Financial
liabilities at
amortized cost
Accounts receivable
$
2,190
$
— $
— $
— $
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
Long-term debt (2)
—
555
—
—
—
—
305
—
—
—
(52)
—
$
2,745
$
253
$
—
136
—
—
(108)
—
28
2019
—
—
(667)
(2,346)
(1,762)
(21,453)
(21,453)
$
(26,228)
$
(23,202)
Asset (liability)
Financial
assets at
amortized cost
Fair value
through
profit or loss
Derivatives
used for
hedging
Financial
liabilities at
amortized cost
Total
Accounts receivable
$
2,465
$
— $
— $
— $
2,465
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
Long-term debt (2)
—
652
—
—
—
—
490
—
—
—
(21)
—
—
290
—
—
(91)
—
—
—
(816)
(2,611)
(1,904)
490
942
(816)
(2,611)
(2,016)
(20,982)
(20,982)
$
3,117
$
469
$
199
$
(26,313)
$
(22,528)
(1)
(2)
Includes $1,690 million of lease liabilities (December 31, 2019 – $1,809) and $72 million of deferred purchase consideration payable over the next three
years (December 31, 2019 – $95 million).
Includes the current portion of long-term debt.
Canadian Natural 2020 Annual Report
84
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)
2020
Carrying amount
Fair value
Level 1
Level 2
Level 3 (4) (5)
$
$
$
$
305
691
(232)
(14,254)
$
$
$
$
305
$
— $
— $
(16,598)
$
2019
— $
136
(160)
$
$
— $
—
555
(72)
—
Carrying amount
Fair value
Level 1
Level 2
Level 3 (4) (5)
$
$
$
$
490
942
(207)
(14,110)
$
$
$
$
490
$
— $
— $
(15,938)
$
— $
290
(112)
$
$
— $
—
652
(95)
—
(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 payable).
There were no transfers between Level 1, 2 and 3 financial instruments.
The fair values of the investments are based on quoted market prices.
The fair value of the deferred purchase consideration included in other long-term liabilities is based on the present value of future cash payments.
The fair value of NWRP subordinated debt is based on the present value of future cash receipts.
The fair value of fixed rate long-term debt has been determined based on quoted market prices.
Includes the current portion of fixed rate long-term debt.
(2)
(3)
(4)
(5)
(6)
(7)
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
Natural gas fixed price swaps
Natural gas basis swaps
Foreign currency forward contracts
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
Other long-term liabilities
2020
2019
$
(5)
$
(40)
(7)
(108)
136
(24)
$
5
$
(131)
131
(29)
(24)
$
$
$
$
(3)
(8)
(10)
(91)
290
178
8
(112)
282
—
178
85
Canadian Natural 2020 Annual Report
During 2020, the Company recognized a loss of $1 million (2019 – gain of $3 million, 2018 – gain of $2 million) related to
ineffectiveness arising from cash flow hedges.
The estimated fair values 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
interest rate yield curves, and Canadian and United States forward 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 (liability) were
recognized in the financial statements as follows:
Asset (liability)
Balance – beginning of year
Net change in fair value of outstanding derivative financial instruments
recognized in:
Risk management activities (1)
Foreign exchange
Other comprehensive income (loss)
Balance – end of year
Less: current portion
2020
$
178
$
(32)
(168)
(2)
(24)
(126)
$
102
$
(1)
Includes the fair value movement of commodity financial instruments included in the acquisition of Painted Pony in 2020 (note 7).
Net (gain) loss from risk management activities for the years ended December 31 were as follows:
Net realized risk management loss (gain)
Net unrealized risk management (gain) loss
2020
32
$
(39)
(7)
$
2019
64
13
77
$
$
$
$
2019
356
(13)
(231)
66
178
(104)
282
2018
(99)
(35)
(134)
Canadian Natural 2020 Annual Report
86
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, 2020, the Company had the following derivative financial instruments outstanding. All of these instruments
were assumed in the acquisition of Painted Pony in 2020:
Remaining term
Weighted
average volume
Weighted
average price
Natural Gas
Fixed price swap
Jan 2021 - Dec 2021
37,337 GJ/d
$2.03/GJ
Jan 2021 - Dec 2021
31,178 MMBtu/d
US$2.46/MMBtu
Jan 2021 - Dec 2021
20,808 MMBtu/d
US$2.54/MMBtu
Jan 2021 - Dec 2021
17,466 MMBtu/d
US$2.70/MMBtu
Index
AECO
DAWN
NYMEX
SUMAS
Differential swap
Jan 2021 - Aug 2021
20,000 GJ/d
$0.29/GJ
AECO-STN 2
Basis swap
Jan 2021 - Dec 2023
53,333 MMBtu/d
US$1.23/MMBtu
Jan 2024 - Dec 2025
20,000 MMBtu/d
US$0.97/MMBtu
Jan 2021 - Dec 2021
20,000 MMBtu/d
US$0.09/MMBtu
AECO
AECO
DAWN
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, 2020, the Company had no
interest rate swap contracts outstanding.
FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated
long-term debt, commercial paper and working capital. The Company is also exposed to foreign currency exchange rate risk
on transactions conducted in other currencies and in the carrying value of its foreign subsidiaries. The Company periodically
enters into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on
US dollar denominated long-term debt, commercial paper and working capital. The cross currency swap contracts require the
periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based.
At December 31, 2020 the Company had the following cross currency swap contracts outstanding:
Cross Currency Swaps
Jan 2021 – Mar 2038
Remaining term
Amount
US$550
Exchange
rate (US$/C$)
Interest
rate (US$)
1.170
6.25%
Interest
rate (C$)
5.76%
All cross currency swap derivative financial instruments were designated as hedges at December 31, 2020 and were classified
as cash flow hedges.
In addition to the cross currency swap contracts noted above, at December 31, 2020, the Company had US$4,951 million of
foreign currency forward contracts outstanding, with original terms of up to 90 days, including US$4,379 million designated
as cash flow hedges.
During 2020, the Company settled the US$500 million cross currency swaps designated as cash flow hedges of the US$500
million 3.45% US dollar debt securities due November 2021. The Company realized cash proceeds of $166 million on
settlement.
87
Canadian Natural 2020 Annual Report
FINANCIAL INSTRUMENT SENSITIVITIES
The following table summarizes the annualized sensitivities of the Company’s 2020 net earnings (loss) and other comprehensive
loss to changes in the fair value of financial instruments outstanding as at December 31, 2020, 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.
2020
Increase
(decrease)
to other
comprehensive
income
Increase
(decrease) to
net earnings
Increase
(decrease) to
net earnings
2019
Increase
(decrease)
to other
comprehensive
income
Commodity price risk
Increase AECO fixed price swap $0.10/Mcf
Decrease AECO fixed price swap $0.10/Mcf
Increase natural gas fixed price swap US$0.10 MMBtu
Decrease natural gas fixed price swap US$0.10 MMBtu
Increase natural gas basis swap US$0.10 MMBtu
Decrease natural gas basis swap US$0.10 MMBtu
Interest rate risk
Increase interest rate 1%
Decrease interest rate 1%
Foreign currency exchange rate risk
Weakening of the Canadian dollar by US$0.01
Strengthening of the Canadian dollar by US$0.01
$
$
$
$
$
$
$
$
$
$
(1) $
1
$
(2) $
2
$
(8) $
8
$
(53) $
53
$
(126) $
123
$
— $
— $
— $
— $
— $
— $
(1) $
1
$
— $
— $
(1) $
1
$
(17) $
20
$
(48) $
48
$
— $
— $
(103) $
100
$
—
—
—
—
—
—
(21)
24
—
—
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, 2020, 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
(December 31, 2019 – 1%).
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, 2020, the Company had net risk management assets
of $129 million with specific counterparties related to derivative financial instruments (December 31, 2019 – $265 million). The
carrying amount of financial assets approximates the maximum credit exposure.
Canadian Natural 2020 Annual Report
88
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
Long-term debt (1)
Other long-term liabilities (2)
Interest and other financing expense (3)
Less than
1 year
1 to less than
2 years
2 to less than
5 years
Thereafter
$
$
$
$
$
667
2,346
1,343
345
776
$
$
$
$
$
— $
— $
4,887
200
693
$
$
$
— $
— $
7,051
435
1,619
$
$
$
—
—
8,279
942
4,452
(1)
(2)
(3)
Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $189 million; one to less
than two years, $162 million; two to less than five years, $397 million; and thereafter $942 million.
Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest
and foreign exchange rates at December 31, 2020.
20. Commitments and Contingencies
In the normal course of business, the Company has committed to certain payments. The following table summarizes the
Company’s commitments as at December 31, 2020:
2021
2022
2023
2024
2025
Thereafter
Product transportation and processing (1)(2)
$
North West Redwater Partnership service toll (3) $
Offshore vessels and equipment
Field equipment and power
Other
$
$
$
870
163
64
28
25
$
$
$
$
$
817
160
9
21
21
$
$
$
$
$
858
160
$
$
841
156
$
$
809
150
$ 10,370
$
2,694
— $ — $
— $
21
21
$
$
21
22
$
$
21
22
$
$
—
246
16
(1)
Includes commitments pertaining to a 20-year product transportation agreement on the Trans Mountain Pipeline Expansion. In addition, the Company has
entered into certain product transportation agreements on pipelines that have not yet received regulatory and other approvals.
The acquisition of Painted Pony in 2020 included approximately $2,400 million of product transportation and processing commitments (note 7).
(2)
(3) Pursuant to the processing agreements on June 1, 2018 the Company began paying its 25% pro rata share of the debt component of the monthly cost of
service tolls. Included in the cost of service tolls is $1,169 million of interest payable over the 30-year tolling period (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.
89
Canadian Natural 2020 Annual Report
21. Supplemental Disclosure of Cash Flow Information
Changes in non-cash working capital:
Accounts receivable
Current income tax assets (liabilities)
Inventory
Prepaids and other
Other long-term assets
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
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 on exploration and evaluation assets
2020
2019
2018
$
284
$
(1,310)
$
1,233
(295)
98
(56)
(117)
(147)
(254)
(62)
(164)
(194)
2
117
39
265
(23)
$
$
$
$
$
(549)
$
(1,268)
$
(166)
$
(1,033)
$
(383)
(235)
(549)
$
(1,268)
$
2020
36
$
(31)
5
$
2019
73
—
73
$
$
471
(74)
(3)
—
(7)
(268)
(351)
1,001
1,346
(345)
1,001
2018
282
(16)
266
(1)
Included in Other long-term liabilities at December 31, 2020 is $72 million of deferred purchase consideration payable over the next three years
(December 31, 2019 – $95 million; 2018 - $118 million).
The following table summarizes movements in the Company's liabilities arising from financing activities for the years' ended
December 31, 2020 and 2019:
At January 1, 2019 (1)
Changes from financing cash flows:
Issue of long-term debt, net (2)
Payment of lease liabilities
Non-cash changes:
Lease additions
Changes in foreign exchange and fair value (3)
At December 31, 2019
Changes from financing cash flows:
Issue of long-term debt, net (2)
Repayment of Painted Pony long-term debt
Proceeds on settlement of cross currency swaps
Payment of lease liabilities
Non-cash changes:
Assumption of Painted Pony long-term debt
Lease additions
Changes in foreign exchange and fair value (3)
Cash flow
hedges on
US dollar debt
securities
Long-term
debt
Lease
liabilities
Liabilities
from financing
activities
$
20,623
$
(361)
$
1,539
$
21,801
1,025
—
—
(666)
20,982
719
(397)
—
—
397
—
(248)
—
—
—
162
(199)
—
—
166
—
—
—
5
—
(237)
527
(20)
1,809
—
—
—
(225)
—
148
(42)
1,025
(237)
527
(524)
22,592
719
(397)
166
(225)
397
148
(285)
At December 31, 2020
$
21,453
$
(28)
$
1,690
$
23,115
(1)
(2)
(3)
The Company adopted IFRS 16 "Leases" on January 1, 2019 using the modified retrospective approach.
Includes original issue discounts and premiums, and directly attributable transaction costs.
Includes foreign exchange (gain) loss, changes in the fair value of cash flow hedges on US dollar debt securities, the amortization of original issue discounts
and premiums and directly attributable transaction costs, and derecognition of lease liabilities.
Canadian Natural 2020 Annual Report
90
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 and Refining activities include the Company’s pipeline operations, an
electricity co-generation system and NWRP.
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)
Segmented product sales
North America
North Sea
Offshore Africa
2020
2019
2018
2020
2019
2018
2020
2019
2018
Crude oil and NGLs (1)
$ 7,480 $ 9,679 $ 7,254 $ 417 $
860 $
753 $ 318 $
632 $
628
Natural gas
1,242
1,150
1,256
Other income and revenue (2)
41
6
—
Total segmented product sales
8,763
10,835
8,510
(503)
(998)
8,260
9,837
(723)
7,787
2,510
2,425
2,405
3,393
2,935
2,587
3,780
3,326
3,132
97
(20)
(217)
—
95
49
—
—
87
(10)
(277)
—
12
3
432
(1)
431
321
15
277
30
—
—
—
57
5
922
(2)
920
391
19
308
28
—
—
—
140
—
893
(2)
891
405
22
257
29
—
(139)
—
574
42
18
378
(16)
362
103
1
190
6
—
—
—
67
8
707
(42)
665
109
2
242
6
—
—
—
300
359
70
—
698
(51)
647
208
2
201
9
—
(36)
—
384
263
9,543
8,830
7,924
643
746
$ (1,283) $ 1,007 $
(137) $
(212) $
174 $
317 $
62 $
306 $
Less: royalties
Segmented revenue
Segmented expenses
Production
Transportation, blending and
feedstock (1) (3)
Depletion, depreciation and
amortization
Asset retirement obligation
accretion
Realized risk management
(commodity derivatives)
Gain on acquisition, disposition
and revaluation
Equity loss from investments
Total segmented expenses
Segmented earnings (loss)
before the following
Non–segmented expenses
Administration
Share-based compensation
Interest and other financing
expense
Risk management activities
(other)
Foreign exchange (gain) loss
Loss from investments
Total non–segmented
expenses
Earnings (loss) before taxes
Current income tax (recovery)
expense
Deferred income tax (recovery)
expense
Net earnings (loss)
(1)
(2)
(3)
91
Includes blending and feedstock costs associated with the processing of third party bitumen and other purchased feedstock in the Oil Sands Mining and
Upgrading segment.
Includes the sale of diesel and other refined products and other income, including government grants and recoveries associated with the joint operations
partners' share of the costs of lease contracts.
Includes a provision of $143 million relating to the Keystone XL pipeline project in the North Amercia segment in 2020.
Canadian Natural 2020 Annual Report
Inter-segment elimination and Other includes internal and corporate transportation and electricity charges. Production,
processing and other purchasing and selling activities, that are not included in the preceding segments are also reported in
the segmented information as Inter-segment eliminations and Other.
Operating segments are reported in a manner consistent with the internal reporting provided to the Company’s chief operating
decision makers.
Oil Sands Mining
and Upgrading
Midstream and Refining
Inter–segment
elimination and Other
Total
2020
2019
2018
2020
2019
2018
2020
2019
2018
2020
2019
2018
$ 7,389
$11,340 $11,521 $
83 $
88 $
102 $
(108) $
351 $
410 $ 15,579 $ 22,950 $ 20,668
—
139
—
6
—
—
7,528
11,346
11,521
(78)
(481)
(479)
7,450
10,865
11,042
3,114
3,276
3,367
881
1,306
1,087
1,784
1,656
1,557
72
—
—
—
61
—
—
—
61
—
—
—
—
202
285
—
285
184
181
15
—
—
—
—
5,851
6,299
6,072
380
—
—
88
—
88
20
—
14
—
—
—
287
321
—
—
102
—
102
21
—
14
—
—
—
5
40
182
31
105
—
105
48
27
—
—
—
—
—
75
145
—
496
—
496
56
437
—
—
—
—
—
148
—
558
—
558
58
491
—
—
—
—
—
1,478
1,419
1,614
434
25
—
17,491
24,394
22,282
(598)
(1,523)
(1,255)
16,893
22,871
21,027
6,280
6,277
4,498
4,699
6,464
4,189
6,046
5,546
5,161
205
190
(20)
(217)
49
—
—
287
186
(10)
(452)
5
493
549
16,792
17,048
15,543
$ 1,599 $ 4,566 $ 4,970 $
(95) $
(233) $
62 $
30 $
3 $
9 $
101 $ 5,823 $ 5,484
391
(82)
756
13
344
223
836
28
(275)
(570)
6
171
974
325
(146)
739
(124)
827
341
867
1,962
(873)
4,956
3,522
(257)
434
(181)
(894)
374
557
$
(435) $ 5,416 $ 2,591
Canadian Natural 2020 Annual Report
92
CAPITAL EXPENDITURES (1)
2020
Non-cash
and fair value
changes (2)
Net
expenditures
Capitalized
costs
Net
expenditures
2019
Non-cash
and fair value
changes (2)
Capitalized
costs
Exploration and
evaluation assets
Exploration and
Production
North America (3)
Offshore Africa
Property, plant and
equipment
Exploration and
Production
$
$
(7)
$
(150)
$
(157)
$
12
5
3
15
$
(147)
$
(142)
$
129
35
164
$
$
(219)
$
(2)
(221)
$
(90)
33
(57)
North America (3)(4)
$
North Sea
Offshore Africa (5)
Oil Sands Mining
and Upgrading (6)
Midstream and Refining
Head office
999
122
87
1,208
1,323
5
19
$
371
$
1,370
$
4,702
$
(21)
7
357
(629)
1
—
101
94
1,565
694
6
19
196
194
5,092
1,525
10
34
918
153
(1,476)
(405)
344
—
(3)
$
5,620
349
(1,282)
4,687
1,869
10
31
$
2,555
$
(271)
$
2,284
$
6,661
$
(64)
$
6,597
(1)
This table provides a reconciliation of capitalized costs, reported in note 6 and note 7, to net expenditures reported in the investing activities section of the
statements of cash flows. The reconciliation excludes the impact of foreign exchange adjustments.
(2) Derecognitions, asset retirement obligations, transfer of exploration and evaluation assets, and other fair value adjustments.
(3)
Includes cash consideration paid of $91 million for exploration and evaluation assets and $3,126 million for property, plant and equipment acquired from
Devon in 2019.
Includes cash consideration paid of $111 million for the acquisition of Painted Pony in 2020.
Includes a derecognition of property, plant and equipment of $1,515 million following the FPSO demobilization at the Olowi field, Gabon in 2019.
(4)
(5)
(6) Net expenditures include capitalized interest and share-based compensation.
SEGMENTED ASSETS
Exploration and Production
North America
North Sea
Offshore Africa
Other
Oil Sands Mining and Upgrading
Midstream and Refining
Head office
2020
2019
$
29,094
$
30,963
1,624
1,407
81
41,567
1,301
202
$
75,276
$
1,948
1,529
30
42,006
1,418
227
78,121
93
Canadian Natural 2020 Annual Report
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
2020
2019
2
$
2
$
2018
2
2020
2019
2018
2
9
4
14
29
$
$
2
8
6
20
36
$
$
2
8
4
15
29
$
$
$
(1) Senior management identified above are consistent with the disclosure on Named Executive Officers provided in the Company’s Information Circular to
shareholders for the respective years.
Canadian Natural 2020 Annual Report
94
Supplementary Oil & Gas Information for the Fiscal
Year Ended December 31, 2020 (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, 2020, 2019, 2018 and 2017 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 in 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, 2020,
2019, 2018 and 2017 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 2020 and 2019 reserves for SEC
requirements.
WTI
Cushing
Oklahoma
(US$/bbl)
2020:
WCS
(C$/bbl)
Crude Oil and NGLs
Natural Gas
Canadian
Light Sweet
Cromer
LSB
North Sea
Brent
Edmonton
C5+
Henry Hub
Louisiana
AECO
BC
Westcoast
Station 2
(C$/bbl)
(C$/bbl)
(US$/bbl)
(C$/bbl)
(US$/MMBtu)
(C$/MMBtu)
(C$/MMBtu)
39.77
34.84
45.02
45.55
43.43
50.41
2.16
2.17
2.10
2019:
55.73
57.29
66.77
66.85
62.54
68.71
2.54
2.02
1.13
A foreign exchange rate of US$0.7462/C$1.00 was used in the 2020 evaluation (2019 - US$0.7520/C$1.00), 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, 2020, 2019, 2018 and 2017, the reports by GLJ 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, 2020, 2019, 2018 and 2017, 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.
95
Canadian Natural 2020 Annual Report
The following tables summarize the Company's proved and proved developed crude oil and natural gas reserves, net of
royalties, as at December 31, 2020, 2019, 2018 and 2017:
North America
Synthetic
Crude Oil Bitumen(2)
Crude
Oil &
NGLs
North
America
Total
North
Sea
Offshore
Africa
Crude Oil and NGLs (MMbbl) (1)
Net Proved Reserves
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
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Economic revisions due to prices (3)
Revisions of prior estimates
Reserves, December 31, 2019
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Economic revisions due to prices (4)
Revisions of prior estimates
4,956
744
—
—
—
(148)
—
109
5,661
334
—
—
—
(137)
(288)
(17)
5,554
708
—
—
—
(151)
701
36
1,365
151
10
2
(4)
(64)
(45)
54
1,469
18
169
666
—
(81)
3
(27)
2,216
8
49
—
—
(109)
207
41
Reserves, December 31, 2020
6,847
2,413
Net proved developed reserves
December 31, 2017
December 31, 2018
December 31, 2019
December 31, 2020
4,967
5,661
5,452
6,770
410
461
661
628
594
6,915
17
50
7
—
(47)
(18)
1
604
12
12
2
—
(49)
—
17
598
10
9
28
—
(45)
(94)
20
525
399
378
354
285
912
60
9
(4)
(259)
(63)
164
7,734
364
181
668
—
(267)
(285)
(28)
8,368
726
58
28
—
(305)
814
97
9,785
5,776
6,500
6,466
7,682
107
—
1
7
—
(9)
11
(3)
114
—
—
—
—
(10)
(1)
3
105
—
—
—
—
(8)
(12)
3
87
28
37
38
32
69
—
3
—
—
(6)
1
4
71
—
—
—
—
(7)
1
6
70
—
—
—
—
(6)
3
4
71
21
34
39
37
Total
7,091
912
64
16
(4)
(274)
(51)
165
7,919
364
181
668
—
(285)
(285)
(19)
8,544
726
58
28
—
(320)
805
103
9,943
5,825
6,571
6,543
7,751
Information in the reserves data tables may not add due to rounding.
(1)
(2) 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.
(3) Reflects the impact of increased royalties at Oil Sands Mining and Upgrading (SCO) due to higher bitumen pricing resulting in higher royalties and lower
net reserves.
(4) Reflects the impact of decreased royalties at Oil Sands Mining and Upgrading (SCO) and thermal Bitumen due to lower bitumen pricing resulting in lower
royalties and higher net reserves.
Canadian Natural 2020 Annual Report
96
■
s.
(SCO)
and improved
Revisions of prior estimates: Increase of 103 MMbbl primarily due to improved mine performance and mine model
changes at Oil Sands Mining and Upgrading
performance at North America, North Sea and Offshore
Africa Crude Oil, Bitumen and various natural gas (NGLs) propertie
2020 total proved Crude Oil and NGLs reserves increased by 1,400 MMbbl:
■ Extensions and discoveries: Increase of 726 MMbbl primarily due to the pit extension at Oil Sands Mining and Upgrading
(SCO) and extension drilling/future offset additions at various Bitumen, Crude Oil and natural gas (NGLs) properties.
■
Improved recovery: Increase of 58 MMbbl primarily due to increased steamflood recovery of Bitumen at Primrose and infill
drilling/future offset additions at various Bitumen, Crude Oil and natural gas (NGLs) properties.
■ Purchases of reserves in place: Increase of 28 MMbbl primarily of NGLs from the acquisition of Painted Pony Energy Ltd.
■ Production: Decrease of 320 MMbbl.
■ Economic revisions due to prices: Increase of 805 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and thermal
Bitumen properties due to lower bitumen pricing resulting in lower royalties and higher net reserves, partially offset by
uneconomic reserves at several North America Bitumen (primary heavy crude oil) and Crude Oil properties.
Natural Gas (Bcf) (1)
Net Proved Reserves
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
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, 2019
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, 2020
Net proved developed reserves
December 31, 2017
December 31, 2018
December 31, 2019
December 31, 2020
North
America
North
Sea
Offshore
Africa
5,199
4,306
90
414
67
(3)
(523)
(746)
(192)
106
202
34
—
(511)
246
346
4,728
173
159
2,614
(4)
(515)
97
402
7,655
3,081
2,382
2,342
3,116
(11)
25
—
—
—
—
—
13
27
—
—
—
—
(9)
—
(2)
16
—
—
—
—
(4)
—
—
12
22
23
11
6
Total
5,240
90
414
67
(3)
(542)
(748)
(164)
4,354
106
202
34
—
(528)
248
367
4,782
173
159
2,615
(4)
(524)
100
399
7,701
3,112
2,417
2,381
3,144
16
—
—
—
—
(8)
(2)
15
21
—
—
—
—
(8)
2
23
38
—
—
—
—
(5)
4
(3)
34
9
12
28
22
(1)
Information in the reserves data tables may not add due to rounding.
2020 total proved Natural Gas reserves increased by 2,919 Bcf primarily due to the following:
■ Extensions and discoveries: Increase of 173 Bcf primarily due to extension drilling/future offset additions in the Montney
■
Improved recovery: Increase of 159 Bcf primarily due to infill drilling/future offset additions in the Montney and other
unconventional formations of northwest Alberta and northeast British Columbia.
■ Purchases of reserves in place: Increase of 2,615 Bcf primarily due to the acquisition of Painted Pony Energy Ltd.
■ Sales of reserves in place: Decrease of 4 Bcf from Natural Gas properties in North America.
■ Production: Decrease of 524 Bcf.
■ Economic revisions due to prices: Increase of 100 Bcf primarily due to increased Natural Gas price in North America.
■ Revisions of prior estimates: Increase of 399 Bcf primarily due to overall positive revisions in several North America core
areas as a result of increased recovery and category transfers from probable to proved, partially offset by removal of future
extension and infill undeveloped reserves in North America properties due to revised Company development plans.
2019 total proved Crude Oil and NGLs reserves increased by 625 MMbbl:
■ Extensions and discoveries: Increase of 364 MMbbl primarily due to the transfer of reserves from the probable category
at Oil Sands Mining and Upgrading (SCO) and extension drilling/future offset additions at various Bitumen, Crude Oil and
natural gas (NGLs) properties.
■
Improved recovery: Increase of 181 MMbbl primarily due to increased steamflood recovery at the Primrose thermal oil
(Bitumen) project.
■ Purchases of reserves in place: Increase of 668 MMbbl primarily due to Bitumen property acquisitions from Devon Canada.
■ Production: Decrease of 285 MMbbl.
■ Economic revisions due to prices: Decrease of 285 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) due to
higher Bitumen pricing resulting in higher royalties and lower net reserves.
■ Revisions of prior estimates: Decrease of 19 MMbbl primarily due to the 50-year reserves life cutoff at the Primrose
thermal oil (Bitumen) project, increased royalties at Oil Sands Mining and Upgrading (SCO) as a result of lower operating
costs, and the removal of future extension and infill undeveloped reserves in certain Crude Oil and Bitumen properties
due to revised Company development plans, offset by improved performance at the Pelican Lake (Crude Oil) project and
various natural gas (NGLs) properties.
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 to property acquisitions in North America and North
Sea core areas.
■ Sales of reserves in place: Decrease of 4 MMbbl from the primary heavy crude oil (Bitumen) area.
and other unconventional formations of northwest Alberta and northeast British Columbia.
■ 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).
97
Canadian Natural 2020 Annual Report
Canadian Natural 2020 Annual Report
98
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2021-03-12 8:29:56 AM
Natural Gas (Bcf) (1)
Net Proved Reserves
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
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, 2019
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, 2020
Net proved developed reserves
December 31, 2017
December 31, 2018
December 31, 2019
December 31, 2020
North
America
North
Sea
Offshore
Africa
5,199
90
414
67
(3)
(523)
(746)
(192)
4,306
106
202
34
—
(511)
246
346
4,728
173
159
2,614
(4)
(515)
97
402
7,655
3,081
2,382
2,342
3,116
25
—
—
—
—
(11)
—
13
27
—
—
—
—
(9)
—
(2)
16
—
—
—
—
(4)
—
—
12
22
23
11
6
16
—
—
—
—
(8)
(2)
15
21
—
—
—
—
(8)
2
23
38
—
—
—
—
(5)
4
(3)
34
9
12
28
22
Total
5,240
90
414
67
(3)
(542)
(748)
(164)
4,354
106
202
34
—
(528)
248
367
4,782
173
159
2,615
(4)
(524)
100
399
7,701
3,112
2,417
2,381
3,144
(1)
Information in the reserves data tables may not add due to rounding.
2020 total proved Natural Gas reserves increased by 2,919 Bcf primarily due to the following:
■ Extensions and discoveries: Increase of 173 Bcf primarily due to extension drilling/future offset additions in the Montney
and other unconventional formations of northwest Alberta and northeast British Columbia.
■
Improved recovery: Increase of 159 Bcf primarily due to infill drilling/future offset additions in the Montney and other
unconventional formations of northwest Alberta and northeast British Columbia.
■ Purchases of reserves in place: Increase of 2,615 Bcf primarily due to the acquisition of Painted Pony Energy Ltd.
■ Sales of reserves in place: Decrease of 4 Bcf from Natural Gas properties in North America.
■ Production: Decrease of 524 Bcf.
■ Economic revisions due to prices: Increase of 100 Bcf primarily due to increased Natural Gas price in North America.
■ Revisions of prior estimates: Increase of 399 Bcf primarily due to overall positive revisions in several North America core
areas as a result of increased recovery and category transfers from probable to proved, partially offset by removal of future
extension and infill undeveloped reserves in North America properties due to revised Company development plans.
Canadian Natural 2020 Annual Report
98
2019 total proved Natural Gas reserves increased by 428 Bcf primarily due to the following:
■ Extensions and discoveries: Increase of 106 Bcf primarily due to extension drilling/future offset additions in the Montney
formation of northwest Alberta and northeast British Columbia.
■
Improved recovery: Increase of 202 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 34 Bcf primarily due to property acquisitions in several North America core
areas.
■ Production: Decrease of 528 Bcf.
■ Economic revisions due to prices: Increase of 248 Bcf primarily due to increased Natural Gas price in North America.
■ Revisions of prior estimates: Increase of 367 Bcf primarily due to overall positive revisions in several North America and
Offshore Africa core areas as a result of increased recovery and category transfers from probable to proved. The increase
is also due to improved economics on undeveloped reserves which, when combined with lower long term royalty rates,
results in increased net, after royalties, reserves.
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.
■ Sales 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.
Capitalized Costs Related to Crude Oil and Natural Gas Activities
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
2020
North
America
119,707
$
$
2,353
122,060
(56,930)
North
Sea
7,283
—
7,283
(5,853)
Offshore
Africa
3,963
$
Total
$
130,953
83
4,046
(2,822)
2,436
133,389
(65,605)
Net capitalized costs
$
65,130
$
1,430
$
1,224
$
67,784
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
$
$
North
America
117,643
2,510
120,153
(52,824)
2019
$
North
Sea
7,296
—
7,296
(5,712)
Offshore
Africa
3,933
69
4,002
(2,712)
Total
$
128,872
2,579
131,451
(61,248)
Net capitalized costs
$
67,329
$
1,584
$
1,290
$
70,203
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
North
America
110,154
$
$
2,600
112,754
(48,862)
2018
$
North
Sea
7,321
—
7,321
(5,735)
Offshore
Africa
5,471
37
5,508
(4,203)
Total
$
122,946
2,637
125,583
(58,800)
Net capitalized costs
$
63,892
$
1,586
$
1,305
$
66,783
99
Canadian Natural 2020 Annual Report
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
2020
North
America
North
Sea
Offshore
Africa
$
750
$
— $
— $
15
22
2,338
3,125
$
$
—
—
104
104
—
15
94
$
109
$
2019
Total
750
15
37
2,536
3,338
North
America
North
Sea
Offshore
Africa
Total
$
3,405
$
— $
— $
3,405
91
38
4,687
8,221
$
—
—
349
349
$
2018
—
33
233
266
$
91
71
5,269
8,836
North
America
North
Sea
Offshore
Africa
$
$
214
340
116
3,245
$
127
$
— $
—
—
110
237
$
(89)
35
212
158
$
$
3,915
$
Total
341
251
151
3,567
4,310
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,
2020, 2019 and 2018 are summarized in the following tables:
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of royalties,
2020
North
America
North
Sea
Offshore
Africa
Total
blending and feedstock costs
$
12,520
$
432
$
354
$
13,306
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
(5,624)
(1,258)
(5,564)
(169)
—
23
(321)
(15)
(277)
(30)
31
72
(103)
(1)
(190)
(6)
—
(13)
(6,048)
(1,274)
(6,031)
(205)
31
82
$
(72)
$
(108)
$
41
$
(139)
Canadian Natural 2020 Annual Report
100
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of royalties,
2019
North
America
North
Sea
Offshore
Africa
Total
blending and feedstock costs
$
17,348
$
920
$
676
$
18,944
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,
(5,701)
(968)
(4,982)
(156)
—
(1,468)
(391)
(19)
(308)
(28)
88
(105)
(109)
(2)
(242)
(6)
—
(79)
(6,201)
(989)
(5,532)
(190)
88
(1,652)
$
4,073
$
157
$
238
$
4,468
2018
North
America
North
Sea
Offshore
Africa
Total
blending and feedstock costs
$
16,065
$
891
$
647
$
17,603
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
(5,772)
(929)
(4,689)
(148)
—
(1,223)
(405)
(22)
(257)
(29)
12
(76)
$
3,304
$
114
$
(208)
(2)
(201)
(9)
—
(51)
176
(6,385)
(953)
(5,147)
(186)
12
(1,350)
$
3,594
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":
101
Canadian Natural 2020 Annual Report
(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 (1)
(203,599)
(72,935)
(27,178)
100,481
(74,395)
Standardized measure of future net cash flows
$
26,086
$
(1)
Includes the impact of abandonment expenditures timing.
2020
North
America
North
Sea
Offshore
Africa
Total
$
404,193
$
5,873
$
4,172
$
414,238
(3,259)
(2,130)
(141)
343
278
621
(1,746)
(1,032)
(217)
1,177
(373)
(208,604)
(76,097)
(27,536)
102,001
(74,490)
$
804
$
27,511
(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
2019
North
America
North
Sea
Offshore
Africa
Total
$
515,864
$
10,030
$
5,858
$
531,752
(194,076)
(70,879)
(53,759)
197,150
(136,616)
(4,893)
(2,648)
(936)
1,553
(1)
(2,081)
(1,076)
(547)
2,154
(715)
(201,050)
(74,603)
(55,242)
200,857
(137,332)
Standardized measure of future net cash flows
$
60,534
$
1,552
$
1,439
$
63,525
(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)
(63,202)
(60,526)
183,442
(126,699)
(5,148)
(2,909)
(1,484)
2,461
(545)
(2,284)
(1,099)
(626)
2,438
(771)
(200,819)
(67,210)
(62,636)
188,341
(128,015)
Standardized measure of future net cash flows
$
56,743
$
1,916
$
1,667
$
60,326
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)
2020
2019
2018
Sales of crude oil and natural gas produced, net of production costs
$
(6,127)
$
(11,807)
$
(10,229)
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
(46,055)
626
(153)
947
(1)
5,295
7,718
(4,830)
6,566
(36,014)
63,525
(3,515)
5,883
(1,889)
7,418
—
(3,384)
8,062
447
1,984
3,199
60,326
20,386
2,807
(698)
396
(55)
2,711
6,119
(955)
(7,061)
13,421
46,905
$
27,511
$
63,525
$
60,326
Canadian Natural 2020 Annual Report
102
Ten-Year Review
Years ended December 31
FINANCIAL INFORMATION (C$ millions, except per share amounts)
Net earnings (loss)
2020
(435)
2019
2018
2017
2016
2015
2014
2013
2012
2011
2,591
2.13
2.12
10,121
9,088
7.46
7.43
4,814
4,731
(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
513
2,632
65,170
73,867
22,458
31,653
(204)
(0.19)
(0.19)
3,452
4,293
3.90
3.89
3,811
3,794
1,056
2,382
50,910
58,648
16,805
26,267
(637)
(0.58)
(0.58)
5,632
5,785
5.29
5.28
5,465
3,853
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
(1,574)
2,609
46,487
51,754
9,661
25,772
1,892
1.72
1.72
6,209
6,013
5.48
5.47
5,927
6,308
(1,264)
2,611
44,028
48,980
8,736
24,283
2,643
2.41
2.40
6,243
6,547
5.98
5.94
5,963
6,414
(894)
2,475
41,631
47,278
8,571
22,898
5,416
4.55
4.54
8,829
10,267
8.62
8.61
7,255
7,121
241
2,579
68,043
78,121
20,982
34,991
(0.37)
(0.37)
4,714
5,200
4.40
4.40
2,819
3,206
626
2,436
65,752
75,276
21,453
32,380
1,183,866 1,186,857 1,201,886 1,222,769 1,110,952 1,094,668 1,091,837 1,087,322 1,092,072 1,096,460
1,181,768 1,190,977 1,218,798 1,175,094 1,100,471 1,093,862 1,091,754 1,088,682 1,097,084 1,095,582
1,181,768 1,193,106 1,223,758 1,182,823 1,100,471 1,093,862 1,096,822 1,090,541 1,099,519 1,102,582
0.36
1.50
1.70
1.10
1.34
0.58
0.90
0.42
0.94
0.92
1,866,414
904,013
806,254
588,422
653,727
728,033
717,580
683,003
729,700
800,044
42.57
9.80
30.59
42.56
30.01
42.00
49.08
30.11
32.94
47.00
35.90
44.92
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
1,058,121
679,697
796,971
608,008
892,220
951,311
812,521
645,403
844,647
937,481
32.79
6.71
24.05
32.56
22.58
32.35
38.19
21.85
24.13
36.78
27.53
35.72
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
40%
37%
39%
41%
39%
38%
33%
27%
26%
27%
Per share – basic ($/share)
Per share – diluted ($/share)
Cash flows from operating activities
Adjusted funds flow (1)
Per share – basic ($/share)
Per share – diluted ($/share)
Cash flows used in investing activities
Net capital expenditures (2)
Balance sheet information (C$ millions)
Working capital surplus (deficiency)
Exploration and evaluation assets
Property, plant and equipment, net
Total assets
Long-term debt
Shareholders' equity
SHARE INFORMATION
Common shares outstanding (thousands)
Weighted average shares outstanding
– basic (thousands)
Weighted average shares outstanding
– diluted (thousands)
Dividends declared ($/share) (3)
Trading statistics
TSX – C$
Trading volume (thousands)
Share Price ($/share)
High
Low
Close
NYSE – US$
Trading volume (thousands)
Share Price ($/share)
High
Low
Close
RATIOS
Debt to book capitalization (4)
Return on average common shareholders'
equity, after tax (4)
Daily production before royalties per ten
thousand common shares (BOE/d)
Total proved plus probable reserves per
common share (BOE) (5)
Net asset value ($/share) (6)
(1%)
16%
9.8
9.3
8%
9.0
13.5
71.62
12.0
97.09
11.1
101.89
8%
7.9
9.7
(1%)
(2%)
14%
7.3
8.3
7.8
8.3
7.2
8.1
9%
6.2
7.3
8%
6.0
7.2
12%
5.5
6.9
81.41
74.77
73.39
78.99
72.41
62.38
70.37
(1) 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 Management’s Discussion and Analysis (“MD&A”).
(2) 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.
(3) On March 3, 2021, the Board of Directors approved a quarterly dividend of $0.47 per common share, an increase from the previous quarterly dividend of
$0.425 per common share. The dividend is payable on April 5, 2021.
(4) Refer to the “Liquidity and Capital Resources” section of the MD&A for the definitions of these items.
(5) Based upon company gross reserves (forecast price and costs, before royalties), using year-end common shares outstanding.
103
Canadian Natural 2020 Annual Report
Years ended December 31
OPERATING INFORMATION
Crude oil and NGLs (MMbbl) (7)
Company net total proved reserves
North America
North Sea
Offshore Africa
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
8,980
8,129
7,163
6,423
3,909
3,645
3,380
3,290
3,268
3,007
96
70
109
70
119
72
120
70
134
74
158
74
204
78
224
80
227
85
228
87
9,147
8,307
7,354
6,613
4,117
3,877
3,662
3,594
3,580
3,322
Company net total proved plus probable reserves
North America
North Sea
Offshore Africa
Natural gas (Bcf) (7)
Company net total proved reserves
North America
North Sea
Offshore Africa
11,151
10,231
9,456
8,353
6,015
5,806
5,609
5,135
5,119
4,777
160
94
175
93
186
98
180
102
252
108
284
113
308
119
325
122
332
127
349
131
11,405
10,499
9,740
8,635
6,375
6,203
6,036
5,582
5,578
5,257
8,373
5,795
6,005
6,032
5,845
5,383
5,054
3,684
3,540
3,778
12
32
16
37
27
21
21
15
41
23
39
21
83
36
91
38
82
48
98
54
8,417
5,849
6,053
6,068
5,909
5,443
5,173
3,813
3,670
3,930
Company net total proved plus probable reserves
North America
North Sea
Offshore Africa
Total Company net proved reserves
(MMBOE)
Total Company net proved plus probable
reserves (after royalties) (MMBOE)
Daily production (before royalties) (8)
Crude oil and NGLs (Mbbl/d)
North America –
Exploration and Production
North America –
Oil Sands Mining and Upgrading
North Sea
Offshore Africa
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Total production (before royalties) (MBOE/d)
Product pricing
Average crude oil and NGLs price ($/bbl) (9)
Average natural gas price ($/Mcf) (9)
Average SCO price ($/bbl) (9) (10)
13,884
8,556
8,681
8,454
7,888
7,361
6,791
5,138
4,907
5,125
17
48
21
52
38
44
32
47
85
55
96
50
114
68
125
70
102
76
134
83
13,949
8,630
8,763
8,533
8,028
7,507
6,973
5,333
5,085
5,342
10,549
9,282
8,363
7,625
5,102
4,784
4,524
4,230
4,191
3,977
13,730
11,938
11,202
10,057
7,713
7,454
7,198
6,471
6,426
6,147
460
417
23
17
918
406
395
28
21
850
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
296
40
30
23
389
1,450
1,443
1,490
1,601
1,622
1,663
1,527
1,130
1,198
1,231
12
15
1,477
1,164
31.90
2.40
43.98
24
24
1,491
1,099
55.08
2.34
70.18
32
26
1,548
1,079
46.92
2.61
68.61
39
22
1,662
962
48.57
2.76
63.98
38
31
1,691
806
36.93
2.32
58.59
36
27
1,726
852
41.13
3.16
61.39
7
21
1,555
790
77.04
4.83
100.27
4
24
1,158
671
73.81
3.30
99.18
2
20
1,220
655
72.44
2.70
90.74
7
19
1,257
599
79.16
3.99
101.48
(6) Net present value, discounted at 10%, of the future net revenue (before income tax and excluding the ARO for development existing as at December 31,
2020) 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 (2020 to 2015, $300/acre from 2014 to 2011), less net debt and using
common shares outstanding. Net debt is long term debt plus/minus the working capital deficit/surplus. Future development costs and abandonment and
reclamation costs attributable to future development activity have been applied against the future net revenue.
(7) Company net reserves are company gross reserves after royalties. Reserves data may not add due to rounding and BOE values may not calculate exactly
due to rounding.
(8) Numbers may not add due to rounding.
(9) Product prices reflect realized product prices before transportation costs.
(10) For years 2017 to 2020, average SCO product price includes AOSP realized product prices net of blending and feedstock costs.
Canadian Natural 2020 Annual Report
104
Corporate Information
Board of Directors
*Catherine M. Best, FCA, ICD.D (1)(2)
Corporate Director
Calgary, Alberta
*M. Elizabeth Cannon, O.C.(3)(4)(5)
Past President and Professor Emeritus,
University of Calgary
Calgary, Alberta
N. Murray Edwards, O.C.
Corporate Director
St. Moritz, Switzerland
*Christopher L. Fong (3)(5)
Corporate Director
Calgary, Alberta
*Ambassador Gordon D. Giffin (1)(4)
Partner, Dentons US LLP
Atlanta, Georgia
*Wilfred A. Gobert (1)(2)(4)
Corporate Director
Calgary, Alberta
Steve W. Laut (5)
Corporate Director
Calgary, Alberta
Tim S. McKay (3)
President,
Canadian Natural Resources Limited
Calgary, Alberta
Senior Officers
N. Murray Edwards
Executive Chairman
Tim S. McKay
President
Darren M. Fichter
Chief Operating Officer, Exploration and Production
Scott G. Stauth
Chief Operating Officer, Oil Sands
Mark A. Stainthorpe
Chief Financial Officer and Senior Vice-President, Finance
Troy J.P. Andersen
Senior Vice-President, Canadian Conventional
Field Operations
Bryan C. Bradley
Senior Vice-President, Marketing
Trevor J. Cassidy
Senior Vice-President, Thermal
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
*Honourable Frank J. McKenna, P.C., O.C., O.N.B., Q.C. (2)(4)
Deputy Chair, TD Bank Group
Cap Pelé, New Brunswick
Pamela A. McIntyre
Senior Vice-President, Safety, Risk Management
and Innovation
*David A. Tuer (1)(5)
Corporate Director
Calgary, Alberta
*Annette M. Verschuren, O.C. (2)(3)
Chairman and Chief Executive Officer, NRSTOR Inc.
Toronto, Ontario
(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
the Nominating, Governance and
Risk Committee of the Board of Directors and pursuant to the indepen-
dent standards established under National
the
New York Stock Exchange Corporate Governance Listing Standards.
Instrument 58-101 and
independent by
to be
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
105
Canadian Natural 2020 Annual Report
Corporate Offices
HEAD OFFICE
Canadian Natural Resources Limited
2100, 855 – 2 Street S. W.
Calgary, Alberta 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 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 9.
METRIC CONVERSION CHART
To Convert
barrels
thousand cubic feet
feet
miles
acres
tonnes
To
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, 2020.
Cash dividends declared
per common share (1)
(1) Annualized dividend value.
2020
2019
2018
$1.70
$1.50
$1.34
NOTICE OF ANNUAL MEETING
Canadian Natural’s Annual Meeting of the Shareholders will be
held in a virtual online format via live webcast on Thursday, May
6, 2021 at 1:00 p.m. Mountain Daylight Time. Please see our
website, www.cnrl.com, for information updates.
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 2020 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.
Canadian Natural 2020 Annual Report
106
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