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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
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2021 Performance Highlights
Canadian Natural's diverse and balanced asset base along with the Company's continued focus on
effective and efficient operations delivered several record operational and financial results in 2021.
These strong results created significant value for the Company's shareholders in the year.
2021
2020
2019
FINANCIAL ($ millions, except per common share amounts)
Product sales (1)
Net earnings (loss)
Per common share
– basic
– diluted
Adjusted net earnings (loss) from operations (2)
Per common share
– basic (3)
– diluted (3)
Cash flows from operating activities
Adjusted funds flow (2)
Per common share
– basic (3)
– diluted (3)
Cash flows used in investing activities
Net capital expenditures (2)
Long-term debt, net (4)
Shareholders' equity
Debt to book capitalization (4)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
32,854
7,664
6.49
6.46
7,420
6.28
6.25
14,478
13,733
11.63
11.57
3,703
4,908
13,950
36,945
27%
17,491
$
(435) $
(0.37) $
(0.37) $
(756) $
(0.64) $
(0.64) $
$
$
$
$
$
$
$
$
4,714
5,200
4.40
4.40
2,819
3,206
21,269
32,380
40%
24,394
5,416
4.55
4.54
3,795
3.19
3.18
8,829
10,267
8.62
8.61
7,255
7,121
20,843
34,991
37%
(1) Further details related to product sales are disclosed in the "Segmented Information" note to the Company's audited consolidated financial statements.
(2) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's annual Management's Discussion and
Analysis ("MD&A") for the year ended December 31, 2021, dated March 2, 2022, included in this annual report.
(3) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
(4) Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
TABLE OF CONTENTS
2021 Performance Highlights
Letter to our Shareholders
01
03
T1-T8 Our World-Class Team
06
09
57
58
2021 Year End Reserves
Management’s Discussion and Analysis
Consolidated Financial Statements
Management’s Report
Management’s Assessment of Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Notes to the Consolidated Financial Statements
59
60
66
103 Supplementary Oil and Gas Information
111
113
Ten Year Review
Corporate Information
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
INDEPENDENT QUALIFIED RESERVES
AUDITORS
PricewaterhouseCoopers LLP
Calgary, Alberta
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”.
All amounts are reported in Canadian currency unless
Abbreviations can be found on page 10.
METRIC CONVERSION CHART
CURRENCY
otherwise stated.
ABBREVIATIONS
To Convert
barrels
thousand cubic feet
feet
miles
acres
tonnes
To
Multiply by
cubic metres
cubic metres
metres
kilometres
hectares
tons
0.159
28.174
0.305
1.609
0.405
1.102
COMMON SHARE DIVIDEND
The Company paid its first dividend on its common shares on
April 1, 2001. Since then, dividends have been paid quarterly.
The following table shows the aggregate amount of the cash
dividends declared per common share of the Company and
accrued in each of its last three years ended December 31, 2021.
Cash dividends declared
per common share
$
2.00 $
1.70 $
1.50
2021
2020
2019
NOTICE OF ANNUAL MEETING
In light of the unprecedented public health impact as a result
of the outbreak of the novel coronavirus known as COVID-19,
Canadian Natural’s Annual and Special Meeting of the
Shareholders will be held in a virtual online format via live
webcast on Thursday, May 5, 2022 at 1:00 p.m. Mountain
Daylight Time. Please see our website, www.cnrl.com, for
any location 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 2021 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.
1
Canadian Natural 2021 Annual Report
Canadian Natural 2021 Annual Report
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OPERATING
Daily production, before royalties (1)
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
Barrels of oil equivalent (MBOE/d) (2)
Drilling activity (3)
North America
North Sea
Offshore Africa
2021
2020
2019
473
448
18
14
952
1,680
3
12
1,695
1,235
193
6
—
199
460
417
23
17
918
1,450
12
15
1,477
1,164
71
1
—
72
406
395
28
21
850
1,443
24
24
1,491
1,099
102
5
1
108
(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.
1,235,000
BOE/D
RECORD PRODUCTION
60%
OF LIQUIDS PRODUCTION IS
SCO, LIGHT CRUDE OIL & NGLS
Canadian Natural 2021 Annual Report
2
Letter to our Shareholders
Throughout 2021, our unique and diverse asset base combined with our track record of operational
excellence and our dedicated teams, delivered record average production volumes of 1,235 MBOE/d,
including record liquids production of 952 MBOE/d and record natural gas production of 1,695 MMcf/d,
representing an increase of approximately 71 MBOE/d over 2020 levels. Our strong operational results
during 2021 delivered robust annual adjusted funds flow of approximately $13.7 billion, which after
dividends of approximately $2.2 billion and capital expenditures, excluding acquisitions, of approximately
$3.5 billion, resulted in annual free cash flow of approximately $8.0 billion.
One of Canadian Natural's key strengths is the diversity of our world class assets. Strategically assembled and developed
over several decades, our top tier assets have a low decline rate as well as low maintenance capital relative to the size and
quality of our reserves, which affords us significant flexibility when balancing our four pillars of capital allocation: returns to
shareholders, balance sheet strength, resource value growth and opportunistic acquisitions. We delivered on all four of our
pillars in 2021. As we exited 2020, the COVID-19 pandemic continued to affect every aspect of our lives including global
energy markets which remained volatile. We took a prudent and conservative approach to planning our 2021 capital program
with the goal of focusing on safe, reliable and effective and efficient operations, maximizing value for our shareholders.
Strengthening commodity prices during the first half of 2021 increased our cash flow and by mid-year positioned us to balance
an expansion of our capital program with additional debt repayment and increases to both dividends and share repurchases.
In November 2021 the Board of Directors enhanced our free cash flow allocation policy which, once the Company’s net
debt was below $15 billion, targeted to allocate 50% of free cash flow to the balance sheet, less strategic growth capital /
opportunistic acquisitions, and 50% of free cash flow to share repurchases. This free cash flow allocation policy was a
significant development in 2021 and provided transparency and structure to the allocation of future free cash flows.
Throughout 2021, we significantly increased returns to shareholders. We announced two increases to our quarterly dividend for
a combined annual increase of 38% to $2.35 per share annually. Direct returns to shareholders in 2021 totaled approximately
$3.8 billion, comprised of our sustainable and growing dividend of approximately $2.2 billion and share repurchases throughout
the year which totaled approximately $1.6 billion, as well as indirect returns to shareholders through net debt reduction of
approximately $7.3 billion. In early 2022, we further increased our quarterly dividend by 28% to $0.75 per share quarterly,
equal to $3.00 per share annualized, continuing the Company’s leading track record of 22 consecutive years of dividend
increases with a compound annual growth rate of 22% over that period of time.
Environmental, Social and Governance ("ESG") performance remained a top priority in 2021. We target to incorporate ESG
practices that strengthen our long term sustainability across all aspects of our business. Since 2009, Canadian Natural
has invested $3.9 billion in research and development, driving the necessary improvements that reduced our corporate
Greenhouse Gas (“GHG”) emission intensity by 18% and methane emissions by 28% from 2016 levels as we move toward
our target of net zero emissions in the oil sands. 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 goal of net zero oil sands emissions intensity.
In June, Canadian Natural together with oil sands industry participants formally announced the Oil Sands Pathways to Net Zero
initiative, known as Pathways. The goal of this unique alliance, working collectively with the federal and Alberta governments,
is to achieve net zero GHG emissions from oil sands operations by 2050 to help Canada meet its climate goals, including its
Paris Agreement commitments and 2050 net zero aspirations. We look forward to sharing more about this initiative in the
coming years.
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.
~$7.3 BILLION
NET DEBT REDUCTION
~$3.8 BILLION
RETURNED TO SHAREHOLDERS
3
Canadian Natural 2021 Annual Report
N. MURRAY EDWARDS
Executive Chairman
TIM S. MCKAY
President
MARK A. STAINTHORPE
Chief Financial Officer and
Senior Vice-President, Finance
Operationally, 2021 was a strong year for Canadian Natural. Our asset base remained one of the strongest in our industry,
underpinned by our long life, no decline Oil Sands Mining and Upgrading asset base. These assets generate significant free
cash flow due to the low cost of maintaining production, amenable to economic margin enhancement and long-term GHG
emissions reducing investments. Oil Sands Mining and Upgrading production was approximately 36% of total corporate
production in 2021, averaging record annual production of 448,133 bbl/d of high value Synthetic Crude Oil ("SCO"), an increase
of more than 7% compared to 2020 levels.
Canadian Natural’s North American E&P operations include crude oil, natural gas and NGL producing assets and represented
approximately 61% of the Company’s total production volumes in 2021 on a BOE basis. These assets delivered 472,621 bbl/d
of liquids production, including record thermal in situ production of 259,284 bbl/d. Natural gas prices strengthened during
2021 creating an opportunity for Canadian Natural to capitalize on the Company’s deep inventory of high-quality natural gas
opportunities, resulting in average daily natural gas production of 1,680 MMcf/d, an increase of 16% compared to 2020 levels.
Canadian Natural is a unique E&P company that is delivering free cash flow, strong and growing returns to shareholders and
increasing returns on capital. Canadian Natural has a strong track record of optimizing capital allocation to our four pillars and
we believe 2022 will continue our track record of maximizing shareholder value. The 2022 capital budget of approximately
$4.3 billion, consists of approximately $3.6 billion of base capital and strategic growth capital of approximately $0.7 billion,
driving annual production growth of approximately 60,000 BOE/d from 2021 production levels. Having achieved net debt
of approximately $14.0 billion at year end 2021, we target to balance the allocation of free cash flow to debt reduction,
less strategic growth capital / opportunistic acquisitions, and to share repurchases, on a 50/50 basis per the free cash flow
allocation policy. We believe this positions Canadian Natural to balance near term returns to shareholders with longer term
investments in the Company’s balanced and strategic asset base.
Finally, the COVID-19 pandemic affected our employees in different ways but it has taught us all the importance of supporting
each other to ensure we continued to deliver safe, reliable, effective and efficient operations across all areas of our business.
In the context of collaboration and resiliency, we would like to thank our employees, contractors and stakeholders for your
commitment to operational excellence, adhering to our protocols and supporting each other by working together. You are a
corporate advantage that underpins the ongoing success of our business and are the source of our continuous improvement
culture. We believe Canadian Natural remains well-positioned to continue delivering long-term value to our shareholders
through top tier effective and efficient operations, a robust balance sheet, and the focus of our dedicated people.
N. MURRAY EDWARDS
Executive Chairman
TIM S. MCKAY
President
MARK A. STAINTHORPE
Chief Financial Officer and
Senior Vice-President, Finance
Note: Refer to page 5 and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for additional details.
Canadian Natural 2021 Annual Report
4
NON-GAAP AND OTHER FINANCIAL MEASURES
This report includes references to non-GAAP and other financial measures as defined in National Instrument 52-112 – Non-
GAAP and Other Financial Measures Disclosure. These financial measures are used by the Company to evaluate its financial
performance, financial position or cash flow and are not defined by IFRS and therefore are referred to as non-GAAP and other
financial measures. These measures used by the Company may not be comparable to similar measures presented by other
companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial
measure presented in the Company's financial statements.
FREE CASH FLOW
Free cash flow is a non-GAAP financial measure that represents cash flows from operating activities, as determined in
accordance with IFRS, as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change
in non-cash working capital from operating activities, abandonment, certain movements in other long-term assets, less net
capital expenditures before net property acquisitions and dividends on common shares. The Company considers free cash
flow a key measure in demonstrating the Company’s ability to generate cash flow to fund future growth through capital
investment, pay returns to shareholders, and to repay debt.
($ millions)
Adjusted Funds Flow (1)
Less: Net Capital Expenditures (1)
Net Property Acquisitions (2)
Dividends on Common Shares
Free Cash Flow
2021
2020
$
13,733
$
5,200
$
4,908
(1,425)
2,170
3,206
(505)
1,950
$
8,080
$
549
$
2019
10,267
7,121
(3,298)
1,743
4,701
(1) Refer to the descriptions and reconciliations to the most directly comparable GAAP measure, as applicable, provided in the “Non-GAAP and Other Financial
Measures” section of the Company's MD&A.
(2) Amount includes net exploration and evaluation asset dispositions and net property acquisitions and the acquisition of a 5% net carried interest on an
existing oil sands lease in the second quarter of 2021 per the Company’s MD&A.
CAPITAL BUDGET
Capital budget is a forward looking non-GAAP financial measure. The capital budget is based on net capital expenditures
(Non-GAAP Financial Measure) and excludes net property acquisition costs. Refer to the "Non-GAAP and Other Financial
Measures" section of the Company's MD&A for more details on Net Capital Expenditures.
5
Canadian Natural 2021 Annual Report
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, A. Abakar, Z. Abbas, T. Abbasi, D. Abbott, J. Abbott, M. Abbott, I. Abdi, A. Abdolmaleki, S. Abdulghany, M. Abdulrhman, A. Abeda, W. Abeda,
D. Abel, V. Abeng, T. Abercrombie, G. Abou Mechrek, R. Abrams, N. Abro, C. Abt, D. Ackerman, R. Ackerman, J. Acosta, J. Acteson-Grill, N. Adair, T. Adair, I. Adam, S. Adam,
T. Adam, D. Adams, K. Adams, M. Adams, D. Adamson, C. Adan, T. Adbous, A. Adebayo, O. Adebayo, M. Aden, A. Adesanya, K. Adesanya, O. Adigun, B. Adjoussou, B. Adkins,
N. Agarwal, J. Agate, F. Agbadou, A. Agnihotri, K. Agombar, I. Agu, O. Agu, U. Agu, R. Aguilera Maestre, A. Agustin, C. Agyemang-Badu, A. Ahmad, I. Ahmad, J. Ahmad, K.
Ahmad, M. Ahmad, N. Ahmad, R. Ahmad, S. Ahmad, A. Ahmadi, M. Ahmadi, F. Ahmadloo, A. Ahmari, R. Ahmed, S. Ahmed, N. Ahonon, M. Ahoonmanesh, R. Aikens, D. Aikins,
G. Ailsby, T. Ailsby, J. Airton, S. Aitken, S. Ajayi, T. Ajayi, O. Ajbouni, J. Ajedegba, L. Ajijolaiya, S. Akhtar, R. Akinde, D. Akins, A. Akinsanya, J. Akolkar, N. Akolkar, S. Akolkar, C.
Alarcon, E. Albert, J. Alcala, E. Alconcel, N. Aldi, J. Aleman, D. Alexander, J. Alexander, P. Alexander, S. Alexander, G. Ali, R. Aliazas, H. Aljanabi, M. Al-Kaisy, P. Allain, C. Allan,
E. Allan, J. Allan, E. Allard, J. Allard, A. Allen, B. Allen, J. Allen, T. Allen, W. Allen, J. Allison, R. Allison, S. Allport, J. Allsop, M. Almestar Bustamante, S. Almstrong, J. Alonso,
Y. Al-Saeedi, A. Al-Saleem, R. Al-Samarrai, S. Al-Siani, A. Alstad, J. Alvarez, J. Alvarez Luzon, B. Alyman, C. Amadi, D. Amalaman, G. Amalia, J. Aman, M. Amar, T. Amara, A.
Amay, B. Amer, K. Amer, J. Amero, E. Amos, W. Amy, A. Amyotte, D. Anctil, J. Andel, D. Andersen, J. Andersen, T. Andersen, A. Anderson, B. Anderson, C. Anderson, D.
Anderson, G. Anderson, J. Anderson, K. Anderson, L. Anderson, M. Anderson, N. Anderson, R. Anderson, S. Anderson, W. Anderson, I. Andonov, D. Andreoli, C. Andres, B.
Andrews, E. Andrews, K. Andrews, T. Andrews, E. Anfort, C. Angeles, G. Angeles, P. Angell, L. Angen, K. Angerman, M. Anis, R. Annett, L. Anongba, A. Ansell, C. Ansong-
Danquah, D. Ansorger, R. Anstett, V. Anstey, E. Antle, J. Antle, C. Antoine, M. Antoine, A. Anton, K. Antonishyn, A. Antunes, S. Anwar, H. Aparicio Ramos, P. Appiah, J. Aquila,
R. Aranguren, F. Arano, L. Arbour, R. Arcilla, H. Arias, L. Arias, J. Arizaleta, S. Arjomandi, J. Arkley, R. Armagost, T. Armfelt, A. Armstrong, D. Armstrong, J. Armstrong, B.
Arneson, B. Arnold, C. Arnold, J. Arnold, A. Arowosebe, F. Arrau, F. Arrieta, M. Arsenault, K. Arstall, A. Arthur Brown, B. Artz, S. Arunachalam, A. Arya, B. Asake, D. Asfeday,
J. Ashe, R. Askes, A. Aslam, R. Aslin, R. Asmundson, R. Aspden, S. Aspden, H. Aspeslet, M. Asselstine, D. Assinger, J. Asso, V. Assohou-Ouattara, J. Assoignon, A. Assoum,
A. Astalos, R. Astalos, I. Astete, M. Atchudda Reddy, N. Athavan, K. Atieh, A. Atienza, R. Atkins, J. Atkinson, K. Atkinson, L. Attreo, E. Au, G. Au, J. Auch, P. Aucoin, J. Audia,
A. Auger, L. Auger, P. Auger, S. Auger, C. Aular, L. Austin, R. Austin, A. Avery, B. Avery, F. Avery, S. Avery, M. Avila, C. Aviles, O. Ayanleke, A. Ayasse, W. Ayles, A. Ayoub, J.
Ayub, F. Azam, Z. Azim, Y. Babaoglu, A. Babiarz, A. Babiker, O. Babiker, M. Bachand, C. Bachelet, C. Bachman, W. Bachmeier, A. Baciulica, C. Backer, A. Badamchi Zadeh, W.
Bader, C. Badger, N. Badgley, O. Baffoh, N. Bagheri, K. Bagley, M. Bahiraei, D. Baichev, D. Baier, J. Baier, M. Bailer, R. Bailer, A. Bailey, B. Bailey, J. Bailey, K. Bailey, S. Bailey,
T. Bailey, S. Baillargeon, M. Baillie, B. Bain, E. Bain, C. Baird, D. Baisley, D. Bak, L. Bakaas, A. Baker, C. Baker, D. Baker, J. Baker, R. Baker, A. Bakhtiary Fard, D. Bakkar, J.
Bakker, J. Balacang, B. Balaski, B. Baldonado, J. Baldonado, C. Baldwin, G. Baldwin, M. Baldwin, R. Baldwin, M. Baleja, P. Balfour, R. Balfour, I. Balicanta, J. Balkam, G. Ball,
J. Ball, L. Ball, M. Ball, P. Ball, J. Ballard, S. Ballas, B. Balog, D. Balogoum, A. Balsom, D. Balson, J. Baltesson, B. Baluyot, B. Bam, R. Bama, L. Bamba, B. Bamber, R. Banack,
J. Banak, D. Banash, J. Banawa, N. Banerjee, R. Banfield, S. Banfield, O. Bango, S. Banik, L. Banks, C. Ban-Nelson, R. Bannerholt, B. Bannis, M. Banwait, R. Barabe, L. Barbaro,
G. Barber, J. Barbour, G. Barfield, K. Barham, M. Bari, M. Barilea, K. Barker, R. Barker, S. Barker, A. Barley, S. Barlund, D. Barnes, M. Barnes, N. Barnes, R. Barnes, V. Barnes,
B. Barnett, S. Barr, E. Barreto, C. Barrett, M. Barrett, R. Barrett, T. Barrett, S. Barriault, C. Barrie, D. Barron, R. Barron, S. Barrows, D. Barry, A. Barstad, G. Bartel, C. Bartels, P.
Barter, A. Bartko, B. Bartlett, M. Bartlett, D. Bartman, M. Bartoszewski, N. Bartsch, A. Barysheva, J. Basabe, K. Basarab, R. Basile, L. Basines, P. Bass, S. Basso, C. Bast, A.
Bastardo, H. Bastidas Martinez, C. Bastien, S. Basu, M. Batac, C. Bateman, D. Bateman, M. Bateman, P. Bateman, T. Bateman, D. Bath, L. Bath, M. Batovanja, D. Batt, U. Batta,
K. Batten, R. Batten, C. Battrum, J. Batuyong, D. Bauer, R. Bauer, T. Bauld, C. Baumgardner, J. Baxter, M. Baxter, A. Bayduza, 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, 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, K. Beazer, D. Bechtel, N. Beck, C. Becker,
R. Becker-Faubert, R. Beckner, S. Beckow, J. Beda, I. Bedard, L. Bedard, M. Bedard, D. Bedell, G. Bedi, M. Bednarchuk, S. Beebe, T. Beebe, M. Beeks, C. Beeler, K. Begg, W.
Behnke, G. Belanger, R. Belanger, H. Belas, L. Belcourt, R. Belcourt, J. Belik, R. Belisle, A. Bell, D. Bell, J. Bell, L. Bell, N. Bell, R. Bell, S. Bell, J. Bellavance, J. Beller, M. Beller,
A. Bellettini, J. Belliveau, A. Bellows, C. Bellows, Y. Belyavtsev, M. Belzile, M. Bembridge, A. Bendahmane, K. Bendahmane, C. Bender, R. Benedictson, M. Benko, D. Benn,
T. Benn, K. Benner, C. Bennett, D. Bennett, E. Bennett, J. Bennett, N. Bennett, R. Bennett, S. Bennett, A. Benoit, P. Benoit, D. Bensley, M. Benson, A. Benson- Bartko, J. Bent,
A. Bentley, R. Bentley, I. Bentsianov, J. Berdan, J. Beresford, A. Berg, D. Berg, R. Berg, L. Berge, O. Bergeron, M. Bergeson, B. Bergley, J. Bergquist, J. Bergsma, D.
Berlinguette, J. Bernardin, T. Bernhard, J. Bernier, K. Berreth, R. Berry, W. Berscht, D. Bershadsky, S. Bertelmann, A. Bertrand, B. Bertrand, J. Bertrand, M. Bertucci, B. Berube,
R. Besinger, C. Best, J. Best, C. Betancur Pelaez, C. Bettany, T. Betteridge, S. Bettinson, R. Beveridge, W. Bewski, B. Beyer, J. Beytell, S. Bezpalchuk, J. Bezruchak, M.
Bezugley, A. Bhadauria, A. Bhaduri, L. Bhamare, J. Bhangoo, H. Bhathal, H. Bhatia, B. Bhatt, J. Bhatt, K. Bhatt, R. Bhatt, V. Bhekare, P. Bhojapoojary, J. Bianchini, L. Bianco, K.
Bibby, A. Bibo, J. Bick, S. Biddle, T. Biddlecombe, C. 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, W. Binda, B. Binns, 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, D. Black, J. Black, K. Black, N. Black, R. Black, W. Blackburn, T. Blackett, K. Blackmore, R.
Blackmore, S. Blackstone, 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, R. Blanchett, K. Blanchette, A. Blanco, G. Blanco, U. Blanco, W. Blanco, S. Blaquiere, E. Blawat, S. Blaydes, K.
Blencowe, J. Blesa, A. Blesa Gomez, M. Blinkhorn, S. Blize, R. Blondin, G. Blouin, P. Bluemke, J. Blume, 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, B. Bodner, G. Bodner, D. Bodoano, D. Boeckx, M. Boehm, D. Boehmer, M. Boggust, T.
Bohach, S. Bohay, B. Bohlken, J. Bohlken, E. Bohme, N. Bohning, J. Bohorquez, J. Boissoneault, C. Boisvert, J. Boisvert, M. Boisvert, B. Bokenfohr, D. Bokota, R. Boksteyn,
D. Bolam, S. Bolduc, C. Bolger, D. Bolster, B. Bolt, J. Bolt, P. Bolt, G. Bolzon, G. Bond, K. Bond, N. Bond, S. Bond, T. Bond, T. Bondaruk, A. Bone, A. Bonilla, K. Bonjour, E.
Bonnefon, C. Bonogofski, A. Bonwick, S. Booker, J. Boomgaarden, A. Boone, B. Boone, M. Boone, K. Booth, M. Booth, R. Booth, B. Borbely, K. Bordeleau, R. Bordeleau, C.
Borgel, P. Bork, J. Borkowski, S. Borkowsky, M. Borlaza, M. Born, N. Born, K. Borromeo, E. Borsa, E. Borsini Marin, M. Borst, S. Borys, D. Bosch, J. Bosch, S. Bosch, J.
Boschman, S. Bose, G. Bosma, L. Bosoi, P. Bossel, K. Bothwell, J. Botterill, D. Bouchard, L. Bouchard, T. Bouchard, J. Bouchard Lacoste, C. Boucher, T. Boucher, J. Boudreault,
K. Bougie, H. Boult, B. Boulton, J. Boulton, J. Bounds, C. Bourassa, L. Bourassa, R. Bourassa, T. Bourassa, J. Bourdon, J. Bourgeois, C. Bourlon, D. Bourque, S. Bourrie, C.
Boutier, M. Boutilier, R. Boutilier, D. Bouvier, K. Boven, C. Bowal, M. Bowal, C. Bowditch, J. Bowen, S. Bowers, D. Bowes, B. Bowie, J. Bowie, J. Bowman, R. Bowman, E.
Bown, W. Bowness, J. Boxer, D. Boyarski, R. Boyce, T. Boyce, S. Boychuk, J. Boyd, R. Boyd, J. Boyde, L. Boyde, A. Boyer, C. Boyer, R. Boyko, V. Boyko, D. Boyle, L. Boyle, N.
Boyle, D. Bradbury, A. Bradley, B. Bradley, G. Brady, J. Brady, M. Brady, J. Bragg, S. Braithwaite, N. Brake, S. Brake, T. Brake, J. Branderhorst, J. Brannick, B. Brant, D. Brant,
P. Brar, C. Brassard, M. Brataschuk, K. Bratt, K. Brattebo, R. Brattston, C. Braucht, C. Brausen, M. Brautigam, K. Bravo, L. Bravo, J. Brawn, T. Bray, A. Brazeau, J. Breau, F.
Brebant, M. Brecht, S. Bredy, A. Breen, D. Breen, M. Breen, D. Breitkreitz, D. Bremner, L. Brenton, R. Brenton, T. Bresson, K. Brethour, R. Bretzlaff, O. Breukel, A. Brewer, J.
Breytenbach, R. Brezinski, W. Briand, B. Bricker, M. Brideau, C. Bridger, J. Bridger, T. Brierley, M. Brietzke, C. Briggs, M. Briggs, J. Bright, L. Brinkworth, S. Brinson, S.
Brinston, J. Briscoe, P. Britton, S. Britton, J. Brock, M. Brock, A. Broderick, D. Broderick, S. Broderick, S. Broderson, S. Brodeur, D. Brodziak, G. Bronson, D. Brooks, J. Brooks,
R. Brooks, S. Broomfield, G. Brophy-Maclean, C. Brousseau, C. Brow, N. Brow, A. Brown, B. Brown, C. Brown, D. Brown, G. Brown, J. Brown, K. Brown, N. Brown, P. Brown,
R. Brown, S. Brown, T. Brown, W. Brown, D. Brownrigg, J. Bruce, R. Bruce, S. Bruce, T. Bruce, L. Bruchanski, R. Brue, K. Bruggencate, F. Brugger, D. Brulotte, 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, G. Bryks, J.
Bryla, M. Bryson, S. Bryson, C. Buan, G. Buchan, H. Buchan, J. Buchanan, M. Buchinski, J. Buck, L. Buck, D. Buckley, M. Buckley, G. Buckshaw, T. Budd, N. Budden, R. Budzen,
R. Bueckert, S. Bugden, N. Buhler, J. Buholzer, S. Bukhari, C. Bull, R. Bullen, T. Bullen, I. Bulloch, J. Bullock, G. Bungay, L. Bungay, D. Burak, T. Burchenski, J. Burdett, D.
Burgess, B. Burk, G. Burkart, T. Burkart, D. Burke, L. Burke, S. Burke, G. Burkhart, A. Burla, P. Burness, J. Burnett, A. Burnham, J. Burnouf, J. Burns, C. Burroughs, B. Burry,
D. Burry, K. Burry, S. Burry, D. Bursey, A. Burt, S. Burt, D. Burton, G. Burton, J. Burton, K. Burton, M. Burton, N. Burton, R. Burton, T. Burton, W. Burton, R. Busato, K. Bush,
J. Bushfield, T. Bushie, M. Butchart, C. Butler, D. Butler, I. Butler, M. Butler, R. Butler, T. Butler, B. Butt, K. Butt, Q. Butt, S. Butt, T. Butt, W. Butt, K. Butts, R. Butts, P. Buxton,
B. Bye, J. Byrne, M. Byrne, T. Byrnell, J. Byrtus, I. Byvald, L. Cabatuando, A.
Cabral, J. Cachene-Clark, T. Cadieux, R. Cahoon, A. Caines, H. Cairns, E.
Caissie, W. Calabio, B. Calder, J. Caldwell, P. Caldwell, C. Caleffi, D. Callander,
P. Callin, R. Calliou, M. Camargo, S. Cameron, T. 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, K.
Campeau, N. Campeau, W. Campeau, A. Campos, A. Campos Goitia, M.
Canchica, G. Cane, C. Canning, M. Canning, J. Cannon, E. Cantlon, M. Cao,
A. Caouette, G. Caouette, K. Cap, A. Capadosa, M. Capitaneanu, N.
Cappellani, 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, A. Carlotti,
J. Carlson, W. Carlson, D. Carnes, A. Caron, 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, X. Cartron, J. Cartwright, P. Cashin, K. Casimel, B. Cassell, E. Cassell,
T. Cassidy, D. Cassie, J. Cassivi, L. Casson, F. Castellanos, A. Castillo, C.
Castillo, K. Castle, J. Castro, J. Caswell, C. Cathcart, N. Catley, L. Catto, J.
Cauchie, D. Cavacciuti, D. Cavers, J. Cayabo, C. Cayer, D. Cazabon, C. Celis,
M. Cenon, A. Centeno, S. Cervantes, B. Chaba, D. Chadwick, A. Chafe, A.
Chaisson, P. Chakraborti, S. Chakraborty, S. Chakravarty, M. Chalaturnyk, A.
Chalifoux, C. Chalifoux, M. Chalmers, A. Chamanara, C. Chambers, T.
Chambers, L. Champagne, A. Chan, C. Chan, D. Chan, I. Chan, J. Chan, L.
Chan, R. Chan, S. Chan, T. Chan, J. Chandler, A. Chaney, J. Chanski, H.
Chaouach, K. Chapman, M. Chapman, S. Chapman, D. Chappelle, R. Chaput,
N. Charest, S. Charette, J. Charlebois, D. Charlish, Y. Charniauski, L. Charrois,
T1
Canadian Natural 2021 Annual Report 9,735
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.
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, H. Chen, K. Chen, L. Chen, T. Chen, X. Chen, Z. Chen, C. Cheng, N. Cheng, D. Chenier, N. Cheraghi, S. Cherian, Z. Cherniawsky, M. Chernichen, T. Cherry,
O. Chervyakova, B. Chester, J. Chester, A. Cheung, I. Cheung, K. Cheung, W. Cheung, L. Cheveldeaw, B. Cheyne, B. Chhualsingh, F. Chiasson, B. Chichak, K. Chichak, D. Chick,
B. Chicoine, D. Chidley, D. Childs, S. Childs, K. Chilibeck, A. Chin, S. Chin, Y. Chin, C. Ching, T. Chipiuk, M. Chiplin, B. Chisholm, T. Chisholm, T. Chislett, P. Chiu, R. Chmilar, C.
Cho, J. Chohan, D. Choi, E. Chojko, J. Cholka, N. Chondropoulos, R. Chong, B. Chopping, B. Chorney, M. Chorney, C. Chornohos, C. Chorostecki, M. Choudhry, S. Choudhury,
M. Chourio, A. Chow, J. Chow, K. Chow, S. Chow, R. Chowdhury, S. Chowdhury, A. Chramosta, A. Chretien, B. Christensen, L. Christensen, R. Christensen, T. Christensen, J.
Christian, N. Christian, R. Christian, K. Christiansen, S. Christiansen, D. Christianson, M. Christianson, C. Christie, D. Christie, R. 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, J. Churko, D. Chute, K. Chychul, V. Cimon, K.
Cisse-Banny, A. Cizek, D. Clapperton, W. Clapperton, T. Clare, S. Claringbull, A. Clark, C. Clark, J. Clark, K. Clark, R. Clark, T. Clark, B. Clarke, J. Clarke, K. Clarke, L. Clarke, M.
Clarke, O. Clarke, R. Clarke, S. Clarke, T. Clarke, W. Clarke, C. Clarkson, D. Clarkson, W. Clarkson, A. Cleghorn, J. Clelland, T. Clelland, R. Clemit, R. Clemmer, J. Clevenger, C.
Closs, Z. Closter, J. Clouter, R. Cloutier, J. Clowater, M. Cnossen, J. Coates, M. Coates, R. Coates, T. Coates, E. Cobaj, C. Cobaleda, D. Coburn, M. Cochet, B. Cochrane, E.
Cochrane, J. Cochrane, D. Cockerill, A. Codner, C. Codner, H. Cody, R. Coen, J. Coers, B. Colaco, L. Colborne, M. Colbourne, A. Cole, B. Cole, C. Cole, M. Cole, J. Coles, M.
Coles, L. Collard, A. Colleaux, P. Colley, D. Collicutt, M. Collie, B. Collins, C. Collins, J. Collins, M. Collins, O. Collins, R. Collins, S. Collins, T. Collins, C. Collinson, G. Collison,
A. Collyer, R. Colnar, E. Comeau, R. Comer, K. Compagnon, C. Compton, N. Compton, Q. Conacher, W. Conacher, M. Conejeros, E. Connell, M. Connell, M. Connellan, C.
Connolly, G. Connors, D. Conrad, B. Conroy, J. Conroy, T. Conroy, D. Conway, M. Conway, D. Conybeare, C. Cook, D. Cook, G. Cook, J. Cook, K. Cook, L. Cook, N. Cook, S.
Cook, G. Cooke, L. Cooke, A. Cookson, D. Cookson, K. Cookson, L. Cookson, H. Coolidge, J. Coombs, L. Coonan, L. Cooper, J. Cooze, C. Copeland, N. Copeland, R. Copland,
R. Coppard, M. Coppola, D. Corbett, J. Corbett, N. Corbett, N. Corbiere, F. Corbin, E. Corcoran, J. Corcoran, F. Cordingley, M. Corell, E. Coreman, I. Cormier, S. Cormier, V.
Cornejo, R. Cornish, S. Correll, C. Corrigan, D. Corrigan, R. Corrigan, C. Corry, B. Cortez, P. Corticelli, C. Corzo De Canchica, D. Cosby, G. Cossani, H. Costello, J. Costello, M.
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, J. Courtemanche,
B. Courtney, G. Courtney, T. Courtney, S. Courtoreille, P. Cousin, J. Cousins, M. Cousins, T. Coutney, P. Covell, E. Cowan, B. Cox, G. Cox, S. Cox, E. Cozicor, R. Craft, C. Craig,
D. Craig, G. Craig, P. Craig, R. Craig, H. Craigie, P. Cramb, S. Cramb, S. Cramm, M. Crane, S. Crane, A. Crawford, H. Crawley, J. Crawley, G. Crayford, N. Cressey, L. Cressman,
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, T. Cubrilo,
P. Cudak, J. Cudmore, E. Cuello, H. Cui, J. Cullen, M. Culligan, E. Cullimore, A. Cunanan, A. Cunningham, S. Cunningham, E. Cupac-Cingel, J. Curran, S. Curran, R. Currier, B.
Curry, M. Curry, K. Cusack, D. Cutler, J. Cutler, S. Cutler, J. Cuu, C. Cyr, D. Cyr, G. Cyr, J. Cyr, J. Cyrenne, D. Cyron, K. Cytko, P. Czajko, J. Czarnecki, M. Czerwinski, K. d’Abadie,
D. Dabas, V. Daboin, A. Dabrowski, M. Dacillo-Basallajes, F. Dadashov, R. Dadey, M. Dadi, G. Dafoe, J. Dafoe, C. Dahl, A. Dahmani, J. Dai, J. Daigle, B. Daignault, P. Dale, D.
Dalgarno, L. Dalgetty-Rouse, H. Dalipe, B. Dalley, G. Dalley, M. Dalton, G. Daly, G. Dalziel, R. Damer, D. D’Amour, E. Dana, A. Danbrook, T. Danbrook, W. Danchak, S.
Daneshmand, J. Daniels, T. Daniels, D. Danilkewich, 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, G. Davidson, J. Davidson, S. Davidson, T. Davidson, C. Davies, D. Davies, J. Davies, K. 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, B. Davis-Sorochuk, D. Dawe, L. Dawe, S.
Dawe, K. Dawson, R. Dawyduk, S. Day, T. Day, J. Daye, M. de Chavez, H. de Graaf, R. De Jesus, A. de Lara, 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, M. Dean, A. Dearaway, G. Dearden, C. Deaver, J. deBalinhard, T. Debler, S. Debnath, D.
Deboer, R. deBoer, W. DeBona, S. DeBruycker, P. DeBusschere, D. Dechaine, J. Dechaine, R. Dechaine, P. Dechant, R. Dechesne, B. Decker, D. Decker, J. Decker, K. Decker,
R. Decker, J. Decoeur, D. Decoine, W. Dedam, E. Dee, L. Deep, M. Deering, L. Defoort, S. DeFord, M. Degenstien, I. DeGrace, B. DeHaan, A. Deibert, R. Deitz, R. DeJong
Dyck, B. DeLair, L. Delaire, I. Delaney, P. Delany, E. DeLaRonde, J. Delaurier, C. Delawski, M. Dell, M. DelMastro, M. Delorme, R. Demarsh, A. Demencuik, C. DeMille, B.
Demirdal, C. DeMone, R. DeMott, G. Dempsey, M. Denault, D. Deneau, G. Denney, D. Dennison, S. Denny, C. Denslow, J. Dent, L. Depencier, H. Derakhshan, D. Derbyshire,
J. Derix, K. Derkowski, B. Derochie, M. Derry, A. Desai, C. Desai, G. Desai, P. Desai, R. Desai, S. Desai, M. Deschambeau, T. Deschamps, D. Deschenes, V. Deshpande, S.
Desjardins, C. Desjardins-Knowlden, G. Desjardins-Knowlden, C. Desjarlais, C. Desmarais, S. Desmarais, J. Desnoyers, L. Despins, D. Dessario, M. Detta, P. Deutcheu, K.
Deutsch, A. Deutscher, S. Deval, L. Devey, J. DeVries, T. Dew, C. Dewar, J. Dewar, T. Dewhurst, K. Deyaegher, M. Deyan, C. Deykers, G. Dhaliwal, H. Dhaliwal, J. Dhaliwal, M.
Dhaliwal, P. Dhalwala, B. Dhanesha, 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, A. Didenko, J. Diederich, S. Dietrich, D. Dietzen, P. Diggle, S. Diggle, M. Diiorio, E. Dillabough, R. Dillman, K. Dilts, A. Dimapilis, L. Dimion, W. Ding, X.
Ding, Y. Ding, M. Dingley, G. Dingwell, H. Dinn, M. Diomande, S. Dionne, R. Diputado, M. Dirk, S. Dirk, J. Disney, E. Ditzler, A. Dixit, C. Dixon, D. Dixon, R. Dixon, T. Dixon, K.
Do, M. Doak, 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. Domalain, R. Domazet, B. Dombrova, M. Dombrova, S. Dominguez, K. Donahue, K. Donald, E. Donaldson,
S. Donaldson, R. Donaleshen, M. Dong, J. Donnelly, J. Donovan, N. Donovan, J. Doonanco, S. Dorer, A. Dorey, M. Dorocicz, R. Dorton, J. Dorusak, A. Dosanjh, J. Dosman,
M. Doty, M. Doucet, D. Doucette, K. Doucette, A. Douglas, J. Douglas, J. Doust, T. Dove, R. Dow, A. Dowd, J. Dowd, J. Dowhay, A. Dowman, P. Downes, 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, K. Dreger, C. Drescher,
J. Drescher, D. Dresser, D. Dressler, C. Drevant, B. Drew, D. Drew, A. Driemel, A. Drier, B. Driscoll, S. Driscoll, E. Drolet, R. Drolet, R. Drosu, A. Drover, B. Drover, C. Drover,
J. Drover, N. Drover, R. Drummond, D. Drury, S. Dryden, S. Drysdall, M. D’Souza, P. D’Souza, V. D’Souza, C. Du, M. Du, P. Duan, C. Duane, C. Duarte, B. Dube, M. Dube, N.
Dube, R. Dube, T. Dube, A. Dubetz, T. Dubie, S. Dubli, G. Dubois, J. Dubuc, D. Duby, C. Dubyk, P. Duchesnay, J. Duchscherer, J. Duczek, P. Duda, S. Dudley, L. Dueck, T. Dueck,
G. Duff, C. Duffett, D. Duffy, K. Duford, E. Dufour, C. Duggan, M. Duguay, D. Duguid, A. Duhaime, E. Dulay, T. Dumba, O. Dumitrache, Y. Dumont, C. Dunbar, B. Duncan, H.
Duncan, J. Duncan, R. Duncan, D. Dunn, J. Dunn, N. Dunn, P. Dunn, R. Dunn, S. Dunn, J. Dunnigan, C. Dunsmore, J. Dunsmuir, D. DuPerrier, D. Dupuis, K. Dupuis, J. Durdle,
A. Durham, J. Duris, K. Durocher, B. Dusterhoft, J. Dutchak, J. Duthie, R. Duthie, N. Duval, R. Duval, C. Duynisveld, B. Dwyer, C. Dwyer, R. Dwyer, D. Dybala, J. Dybala, A.
Dyck, J. Dyck, J. Dyer, L. Dyke, B. Dzirasah, B. Eagle, J. Eagleson, M. Eamer, R. Earl, J. Easthope, B. Eastman, J. Eastman, J. Easton, K. Eberle, J. Ebonka, R. Ebuna, G. Ecker,
D. Edgington, A. Edmunds, A. Edoukou, D. Edwards, E. Edwards, J. Edwards, P. Edwards, T. Eeuwes, A. Effray, L. Egeland, R. Eggen, C. Eggleton, A. Eghbal, A. Egresits, C.
Ehnes, C. Ehresman, I. Eichelbaum, B. Eitzen, M. Ejo, D. Ekdahl, J. Ekelund, S. Ekra, S. Ekstrom, R. Elaschuk, N. Elderkin, M. Elgarni, M. El-Harakeh, D. Elia, T. Elias, M. Elias
Neira, P. Ellingson, B. Elliott, D. Elliott, H. Elliott, J. Elliott, L. Elliott, R. Elliott, S. Elliott, D. Ellis, K. Ellis, P. Ellison, C. Ellsworth, K. Ellsworth, A. Elmobarik, M. Elms, E. Elson,
T. Ely, C. Emberley, V. Embleton, H. Emery, C. Emmett, G. Emmott, J. Engel, K. Engelking, J. Engen, R. Engler, T. Engler, J. English, M. Enns, R. Enns, J. Entz, J. Epp, T. Epp,
J. Erasmus, S. Erb, D. Ereaut, B. Eresman, C. Erfle, B. Erickson, J. Erickson, S. Erickson, M. Erl, M. Ernst, P. Ersh, C. Erskine, D. Ertmoed, W. Esau, P. Escalona, O. Esharefasa,
N. Eskandar, G. Eskandari, M. Espejo, M. Espiritu, R. Esslemont, B. Estey, O. Estrada, D. Etherington, S. Etherington, A. Evans, D. Evans, J. Evans, R. Evans, T. Evans, R.
Evasco, J. Eveleigh, L. Eveleigh, A. Everson, C. Eves, A. Evoy, J. Ewald, J. Ewen, J. Eyma, V. Ezeronye, B. Facco, D. Fader, D. Fadnavis, R. Faechner, B. Fagan, M. Fahad, J.
Fahim, E. Faichney, S. Fairfield, M. Faiz, L. Fajdiga, K. Falconer, C. Falk, T. Falk, S. Fallahi, M. Fallen, Y. Fang, D. Fanning, H. Farah, M. Fardy, S. Farea, S. Farhan, A. Faria, H.
Farid, S. Farn, D. Farney, M. Farokhshad, A. Farquhar, 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, N. Fecteau, D. Fedoruk, C. Fedun, T. Fedyna, E. Feely, J.
Feener, D. Fehr, D. Feland, E. Feldkamp, J. Feldmeier, D. Feller, R. Fells, R. Feltham, E. Fender, M. Feng, L. Fentie, A. Ferdjallah, K. Ferdous, S. Ferenc, B. Ferguson, C.
Ferguson, H. Ferguson, M. Ferguson, R. Ferguson, S. Ferguson, M. Ferhatbegovic, B. Fernandes, A. Fernandez, E. Fernandez, L. Fernandez Exposito, N. Ferrer, M. Ferry, R.
Fersch, T. Fertig, W. Fessler, C. Fetter, L. Fetter, D. Fewer, J. Fewer, V. Fiacco, C. Fibke, D. Fichter, T. Fichter, M. Ficke, C. Ficko, C. Field, M. Fielden, J. Fielding, K. Fielding, W.
Fielding, B. Fifield, C. Filewych, C. Filgate, M. Filipponi, D. Fillier, T. Fillmore, B. Finch, D. Findlay, J. Findlay, N. Findlay, T. Findlay, A. Fink, B. Finlayson, J. Finley, D. Finnamore,
C. Finnebraaten, K. Finnerty, R. Finney, B. Finnie, E. Finnigan, T. Finnigan, C. Fischer, L. Fischer, W. Fischer, J. Fish, C. Fisher, D. Fisher, R. Fisher, B. Fitzgerald, C. Fitzgerald,
J. FitzGerald, S. Fitzner, R. Fitzpatrick, J. Fitzsimmons, B. Fitzsimons, M. Flahr, C. Flamont, J. Flamont, J. Flanegan, 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, 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, E. Follis, R. Folmer, P. Foming, G. Fondjo, B. Fong, Y. Fong, D. Fontaine, G. Fontaine, S. Fontaine,
L. Foote, R. Foran, D. Forbes, M. Forbes, D. Forbister, A. Forcade, G. Ford, R. Ford, T. Ford, W. Ford, G. Forde, J. Foreman, C. Forget, L. Forget, D. Forman, L. Forman, C.
Formanek, R. Formanek, T. Fornwald, G. Forrest, B. Forrester, R. Forrester, B. Forrister, J. Forsberg, B. Forshner, M. Forster, S. Forster, H. Forte, A. 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, V. Foster, D. Fotty, C. Fotur, O. Fouego, A. Fougere, R. Foulkes, G.
Fountain, J. Fountain, B. Fouracres, T. Foureyes, G. Fowler, J. Fowler, D. Fox, M. Foxton, S. Foxton, K. Fraboni, S. Fraino, F. Frame, C. Frampton, C. France, J. France, R. France,
M. Francescone, D. Franche, O. Franchi, D. Francis, J. Francis, M. Franco, D. Frank, A. Frankiw, K. Franklin, P. Fransen, K. Franson, W. Franson, S. Franssen, S. Frappier, R.
T2
Canadian Natural 2021 Annual Report
Frasch, B. Fraser, C. Fraser, G. Fraser, K. Fraser, M. Fraser,
R. Fraser, J. Frayn, K. Frazer, C. Freake, B. Frechette, S.
Freckelton, G. Freeman, M. Freeman, U. Freiberg, E.
Frejoles, J. French, R. French, B. Frenette, J. Frese, K.
Freyman, K. Friedrich, D. Friedt, A. Friesen, D. Friesen, F.
Friesen, J. Friesen, K. Friesen, N. Friesen, R. Friesen, A.
Frizorguer, D. Frizzell, C. Froc, J. Froc, A. Froh, C. Frosini,
C. Froude, S. Froude, A. Fry, X. Fu, N. Fucile, A. Fudge, B.
Fudge, C. Fudge, L. Fudge, R. Fudge, S. Fuhr, 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, T. Furuya, C. Fuster, A.
Fyith, J. Gaberel, A. Gabr, L. Gabriel, K. Gabrielson, D.
Gabruck, K. Gadzala, R. Gaetz, L. Gaffney, N. Gafuik, A.
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, J.
Gallon, M. Gallon, 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, L. Garvey, E. Gashaw, M.
Gates, J. Gatrell, S. Gauchan, C. Gaudet, F. Gaudet, G.
Gaudet, W. Gaugler, L. Gauld, M. Gaulin, D. Gauthier, J.
Gauthier, M. Gauthier, N. Gauthier, P. Gauthier, S. Gauthier,
K. Gautschi, T. Gaydos, G. Gayton, A. Gboko, B. Geall, J.
Geddes, D. Geitz, C. Geldart, O. Gelowitz, M. Gemmell, M. Genereux, C. Geng, G. Genge, C. George, J. George, M. George, R. Georgescu, J. Georget, S. Geremia, J. Gergely,
G. Gerla, J. Gerlinger, K. Gerow, E. Gervais, K. Gervais, M. Gervais, K. Gessner, T. Getchell, S. Getson, K. Getzinger, V. Ghadamyari, H. Ghazimoradi, M. Ghorbanie, J. Ghosh,
E. Ghoubrial, D. Gibb, I. Gibbon, S. Gibbon, E. Gibbs, C. Gibson, D. Gibson, S. Giefer, A. Gierach, C. Giesbrecht, D. Giesbrecht, E. Giesbrecht, J. Giesbrecht, T. Giesbrecht, J.
Gigg, D. Giggs, M. Giguere, G. Gilbert, C. Giles, M. Giles, S. Giles, T. Giles, V. Giles, J. Gilhang, D. Gill, K. Gill, L. Gill, M. Gill, N. Gill, R. Gill, S. Gill, J. Gillam, D. Gillan, S.
Gillespie, M. Gillies, A. Gillingham, D. Gillingham, E. Gillingham, J. Gillingham, L. Gillingham, S. Gillingham, E. Gillis, M. Gillund, C. Gilman, K. Gilman, D. Gilmer, E. Gimenez,
R. Gimoro, G. Gin, T. Ginigeme, K. Ginter, M. Ginter, K. Ginther, T. Ginther, L. Giraldo, D. Girard, G. Girard, S. Girard, D. Girouard, J. Girouard, P. Girouard, B. Gisby, M. Gisondo
Crawford, S. Gist, E. Giuliani, D. Gladue, J. Gladue, B. Glaicar, G. Glanville, D. Glasco, A. Glasrud, G. Glasser, K. Glavine, M. Glavine, J. Glen, J. Glendenning, G. Glenn, D.
Gliddon, D. Gloade, D. Glover, S. Glubish, M. Go, R. Go, F. Godbout, J. Godin, B. Godkin, D. Godwin, L. Goerzen, C. Gogol, J. Gogol, B. Gogowich, H. Goldberg, D. Golden, E.
Goldhart, P. Goldsney, A. Goll, D. Goll, P. Goll, M. Gomaa, C. Gomez, E. Gomez, J. Gomez, L. Gomez Torres, C. Gomuwka, E. Gong, K. Gong, M. Gonzales, I. Gonzalez, L.
Gonzalez, N. Gonzalez, Y. Gonzalez, P. Gonzalez Sierra, C. Good, P. Good, J. Goodair, C. Goodman, P. Goodman, P. Goodwin, W. Goodwin, B. Goodyear, K. Gordeyko, I. Gordon,
J. Gordon, K. Gordon, L. Gordon, S. Gordon, T. Gordon, J. Gorgichuk, D. Gorrie, J. Gorski, M. Gospodinov, B. Gosse, D. Gosse, R. Gosse, T. Gosse, Y. Gosselin, B. Gosselink,
B. Goudarzi, C. Goudreau, C. Gough, A. Gould, B. Gould, J. Gould, T. Goulding, J. Goulet, P. Goulet, G. Gouthro, J. Gover, N. Govindarajan Prithivirajan, A. Goyal, L. Goymer, J.
Graca, N. Grace, J. Grach, J. Grageda, C. Graham, G. Graham, J. Graham, M. Graham, R. Graham, S. Graham, T. Graham, E. Grandillo, R. Grandy, B. Granger, J. Granger, A.
Grant, C. Grant, J. Grant, L. Grant, M. Grant, R. Grant, S. Grant, B. Gravel, R. Graveline, R. Gravell, T. Graveson, A. Gray, B. Gray, C. Gray, D. Gray, L. Gray, N. Gray, R. Gray, S.
Gray, 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, K. Greenwood, M. Greenwood, R. Greenwood, T. Greig, A. Grenier, J. Grenon, A. Grewal, S. Grewal, B. Grice, C. Grice, R. Grice, R. Grieco, C. Grieder, R.
Griemann, S. Grier, D. Grieve, R. Grieve, J. Griffin, M. Griffin, P. Griffin, E. Griffiths, H. Griffiths, J. Griffiths, A. Grise, E. Grise, R. Griswold, R. Groenen, M. Grosseth, W.
Grotkowski, J. Grouchy, P. Grove, W. Grove, L. Groves, D. Grundner, D. Grzela, S. Gu, C. Guay, D. Guay, L. Gubenco, C. Gudjonson, S. Gue, P. Guedez, J. Guerin, D. Guevohe,
M. Gueye, D. Guglielmin, J. Guilmette, K. Guimond, C. Guinup, R. Guinup, A. Guitard, K. Gulamhusein, R. Gulati, S. Guled, R. Gulutzan, J. Gumbley, E. Gummeson, I. Gunning,
A. Gupta, J. Gurba, M. Gurin, R. Gurumurthy, E. Gushue, J. Gushue, T. Gushue, T. Gusnowski, R. Gussen, C. Gustafson, G. Gustafson, M. Gustafson, J. Gustavson, P. Gut, M.
Gutierrez, G. Gygi, J. Gysler, D. Ha, T. Ha, E. Haag, B. Haas, S. Haas, M. Haberoth, C. Hachey, L. Hachey, S. Hackett, E. Hadada, V. Haddad, L. Hadi, T. Hadji, N. Hadskis, S.
Haefliger, K. Hagan, T. Hagen, L. Hagg, A. Hagi-Memet, S. Hagman, K. Hague, S. Hahn, J. Haidasz, O. Haight, A. Haj Hamdan, M. Haj Hamdan, S. Hajar, S. Haji, S. Hajizadeh,
C. Hales, D. 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, B. Hallett, G. Hallett, S.
Hallgren, K. Halliday, 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, F.
Hames, L. Hamill, S. Hamill, A. Hamilton, D. 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, G. Hammoud, G. Hampson, C. Hampton, B. Hamrell, S.
Han, G. Hanas, E. Hancock, M. Hancock, B. Hancott, K. Hankins, R. Hanlon, S. Hanlon, E. Hann, R. Hann, W. Hanna, K. Hanrahan, A. Hansen, D. Hansen, J. Hansen, K. Hansen,
L. Hansen, M. Hansen, R. Hansen, V. Hansen, D. Hanson, K. Hanson, L. Hanson, R. Hanson, T. Hanson, I. Harb, B. Harbin, M. Harbin, L. Harder, C. Harding, P. Harding, G.
Hardisty, J. Hardisty, F. Hardy, H. Hardy, J. Hardy, A. Hare, A. Hargreaves, E. Harikumar, K. Harke, J. Harker, A. Harlal, D. Harley, E. Haroldson, G. Harper, R. Harriman, B. Harris,
C. Harris, J. Harris, M. Harris, S. Harris, C. Harrison, D. Harrison, N. Harrison, R. Harsany, D. Hart, C. Hartery, C. Hartl, P. Hartwick, A. Harty, J. Harty, B. Harvey, D. Harvey, J.
Harvey, R. Harvey, S. Harvey, M. Hashem, B. Hassan, I. Hassan, M. Hassan, O. Hassan, R. Hasselmann, B. Hassen, J. Hatala, J. Hatcher, G. Hatto, D. Haub, G. Haub, R.
Hauger, T. Hauger, B. Haugo, J. Haviland, S. Hawco, T. Hawco, D. Hawkins, H. Hawkins, S. Hawryliw, 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, N. Hazelwood, J. Hazin, S. He, T. He, Y. He, T. Head, M. Headrick, B.
Heagy, C. Heagy, J. Heagy, A. Heale, L. Healy, B. Hearn, B. Heasley, A. Heath, B. Heath, C. Heath, D. Heath, B. Heatley, S. Heaton, D. Heavens, S. Heawood, T. Hebel, B.
Hebert, D. Hebert, J. Hebert, M. Hebert, B. Hebner, S. Heck, D. Heemeryck, K. Heffernan, D. Hefford, C. Hehr, T. Heid, R. Heide, T. Heidebrecht, M. Heigl, R. Hein, R. Heinrichs,
B. Heise, R. Heiz, R. Helland, B. Helliker, R. Hellum, A. Hellyer, Q. Helm, D. Helms, R. Helyar, C. Hemington, D. Hemmelgarn, T. Hempel, B. Hemstock, C. Henderson, J.
Henderson, R. Henderson, S. Henderson, W. Henderson, F. Hendricks, K. Hendrickson, S. Hendry, K. Hennessey, A. Hennig, E. Henriquez, C. Henry, H. Henschel, D. Herauf,
K. Herba, C. Herbst, W. Hergott, D. Herman, W. Herman, A. Hernandez, E. Hernandez, G. Hernandez, M. Hernandez, P. Hernandez, C. Herring, R. Herrington, D. Hertzsprung,
M. Herzog, D. Heshka, R. Heska, A. Hess, B. Hess, M. Hessenbruch, B. Heugh, J. Hevey, B. Hewitt, J. Hewitt, M. Hewitt, T. Hewitt, T. Hewko, J. Hewlett, A. Heydari Gorji, A.
Heynen, C. Heywood, R. Hibbs, D. Hicke, M. Hickey, P. Hickey, R. Hickey, B. Hicks, R. Hicks, S. Hicks, D. Hiebert, L. Hiebert, R. Hiebert, M. Hiemstra, T. Hiemstra, E. Hietanen,
R. Higa, A. Higgins, L. Higgins, M. Higgins, R. Higgins, P. Higgitt, J. Higuerey De Sanchez, C. Hildahl, C. Hill, D. Hill, H. Hill, J. Hill, K. Hill, T. Hill, D. Hillier, S. Hillier, T. Hillier,
C. Hills, T. Hills, D. Hillyard, T. Hilsendager, B. Hindmarch, K. Hingley, W. Hinkle, T. Hinks, K. Hinton, N. Hinze, M. Hird, K. Hirsch, D. Hiscock, S. Hiscock, F. Hiscox, D. Hitra, J.
Ho, M. Ho, T. Ho, J. Hoare, W. Hobart, A. Hobbi, J. Hobbs, P.
Hocaloski, R. Hoda, G. Hodder, J. Hodder, D. Hodge, R.
Hodgins, A. Hoeg, N. Hoey, M. Hoffart, L. Hoffman, R.
Hoffman, M. Hofstrand, G. Hogan, S. Hogan, A. Hogg, J.
Hogg, M. Hogg, R. Hogg, B. Holaki, J. Holben, D. Holik, K.
Holladay, A. Holland, K. Holland, M. Holland, S. Holland, I.
Hollenbeck, P. Hollett, D. Holley, J. Holley, D. Hollingshead,
G. Holloway, J. Holloway, L. Holloway, J. Hollowell, C.
Holman, D. Holman, R. Holman, J. Holmes, K. Holmes, M.
Holmes, N. Holmes, T. Holmes, S. Holmstrom, B. Holthe, C.
Holthe, J. Holton, J. Holuk, A. Holz, J. Holz, G. Homann, Q.
Hong, D. Honing, C. Hood, J. Hood, G. Hook, J. Hook, A.
Hooper, J. Hooper, R. Hooper, A. Hope, S. Hopkins, Y.
Hopkins, N. Hopner, M. Hopp, T. Hopper, T. Hopwood, A.
Hordy, R. Horn, T. Hornberger, Z. Horne, D. Horner, A.
Hornseth, K. Hornseth, B. Horobec, C. Horseman, K.
Horvath, R. Horvath, J. Horyn, K. Hosker, J. Hoskins, B.
Hossain, M. Hossain, S. Hosseini, A. Hosseinpoor, T. Hou, S.
Houck, L. Houghton, R. Hourd, G. House, P. House, R.
House, T. House, L. Houseman, T. Houston, K. Hovdebo, D.
Howard, T. Howard, C. Howden, L. Howell, P. 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, R. Hrynyk, J. Hu, M. Hu, T. Hu, Y. Hu, D. Huang, J.
Huang, N. Huang, Q. Huang, G. Huber, M. Huber, R. Huber,
C. Huber-Yau, S. Hucal, D. Huchkowsky, J. Hucik, C. Hucul,
K. Huculak, W. Huddlestun, A. Hudkins, A. Hudson, D.
Hudson, P. Hudson, S. Huebner, K. Huey, J. Huffman, B.
Hughes, J. Hughes, M. Hughes, E. Huh, K. Hui, R. Hui, C.
Hulbert, D. Hull, F. Hulme, M. Human, R. Humphrey, J.
Humphreys, S. Humphreys, A. Humphries, C. Humphries, S.
Humphries, T. Humphries, M. Hunchak, I. Hundeby, M.
Hundessa, M. Hung, M. Hunsperger, C. Hunt, D. Hunt, M.
T3
Canadian Natural 2021 Annual Report Hunt, B. Hunter, C. Hunter, D. Hunter, K. Hunter, L. Hunter, P.
Hunter, R. Hunter, S. Hunter, T. Hunter, W. Hunter, M.
Hupchuk, K. Hupp, J. Hurd, K. Hurd, S. Hurley, R. Hurtado, R.
Hurtubise, A. Hussain, S. Hussaini, G. Hussey, C. Hussynec,
C. Hutchinson, D. Hutchinson, R. Hutchinson, C. Hutchison,
E. Hutton, A. Huynh, M. Huynh, M. Huys, S. Hwang, S. Hyatt,
K. Hygard, A. Hymanyk, A. Hynes, D. Hynes, E. Hynes, J.
Hynes, M. Hynes, N. Hynes, S. Hyrcha, G. Iannattone, K.
Ibrahim, S. Ibrahim, T. Idler, A. Idowu, G. Iervella, O. Ifediniru,
L. Iftemie, N. Ilchuk, S. Ilczynski, R. Imankulov, D. Imbeau, E.
Imbery, W. Imeson, K. Imlach, M. Imran, S. Imrie, J. Inch, R.
Inder, J. Inglis, R. Inglis, E. Ingram, G. Ingram, C. Inkster, J.
Inlow, B. Inman, C. Innes, M. Inscho, D. Ip, M. Ippolito, M.
Iqbal, R. Irani, J. Ireland, M. Irfan, J. Irons, K. Ironstand, R.
Irvine, S. Irwin, J. Isaacs, C. Isaka, C. Isea Natera, B. Ish, H.
Ishaque, O. Issa, J. Ivanova, B. Ivany, D. Ivany, L. Iversen, C.
Ives, J. Ivezic, M. Jablonski, 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, R.
Jakher, H. Jalali, M. Jalali, G. Jaleel, L. Jama, M. Jama, S.
Jamam, D. Jaman, T. Jaman, A. Jambrosic, D. James, R.
James, T. James, W. James, J. Jamieson, M. Jamieson, S.
Jamieson, T. Jamieson, D. Jamilano Jr., K. Jan, A. Janes, D.
Janes, J. Janes, L. Jans, S. Jansky, A. Janzen, L. Janzen, M.
Janzen, L. Jardie, C. Jardine, J. Jardine, S. Jardine, N.
Jaricha, C. Jarratt, B. Jarvis, J. Jarvis, K. Jarvis, K. Jaschke,
S. Jaume, K. Jay, M. Jay-Rivas, S. Jeanes, J. Jechow, W.
Jellison, G. Jenkins, J. Jenkins, T. Jenkins, J. Jenner, M.
Jenner, R. Jenner, R. Jenniex, S. Jenniex, B. Jennings, D.
Jennings, B. Jensen, K. Jensen, L. Jensen, Q. Jensen, R. Jensen, T. Jensen, V. Jensen, K. Jentas, H. Jeong, D. Jerkovic, M. Jeroncic, R. Jeronymo, T. Jervis, C. Jesso, M.
Jesso, J. Jesson, S. Jevne, M. Jewel, C. Jezowski, P. Jia, N. Jiang, S. Jiang, Y. Jiang, Z. Jiang, R. Jimeno, X. Jing, P. Jingar, N. Jivani, K. Jivraj, R. Jivraj, M. Joarder, J. Jocksch,
D. Jodoin, L. Jodoin, G. Joe, J. Joffre, I. Johanson, K. Johansson, 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, H. Johnston, N. Johnston, R. Johnston, S. 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, N. Jongkind, P. Joo, D. Jordan,
M. Jordan, B. Jorgensen, D. Jorgensen, M. Jorgensen, L. Jorgenson Donahue, D. Joseph, P. Joseph, 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, S. Jung, C. Jungen, R. Jungkind, G. Junio, T. Kabyn, A. Kachra, C. Kada, L. Kadutski,
A. Kaid, M. Kaid, G. Kailas, K. Kajorinne, H. Kakadiya, M. Kakooei, S. Kalbag, V. Kalbag, D. Kalinowski, A. Kalmet, D. Kalynchuk, B. Kamath, A. Kamieniak, A. Kamke, G. Kamon,
S. Kanarek, A. Kandasamy, S. Kandulva Chakrapany, J. Kane, S. Kane, K. Kang, N. Kang, Z. Kanji, R. Kanomata, J. Kanzig, P. Kapadia, S. Kapeluck, S. Kaplan, M. Kapp, Y. Karayan
Moosafi, R. Karlowsky, J. Karlson, S. Karlstrom, S. Karmakar, C. Karpiak, K. Kartushyn, P. Karval, 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, R. Kawano, K. Kay, O. Kay, G. Kaya, L.
Kayyali, G. Kazimirowich, D. Ke, M. Kealey, R. Kean, J. Kearley, M. Kearley, K. Keast, K. Keating, F. Kebede, M. Keck, B. Keddie, R. Keddie, A. Keebler, C. Keehn, A. Keeling, T.
Keenan, H. Keessar, P. Keglowitsch, P. Kehler, C. Kehoe, G. Keith, J. Kelenc, K. Keller, C. Kelley, C. Kellogg, J. Kelloway, K. Kelloway, M. Kelloway, R. Kelloway, C. Kelly, J. Kelly,
M. Kelly, P. Kelly, S. Kelsey, G. Kemp, L. Kempe, S. Kempner, J. Kempton, R. Kendall, S. Kendall, C. Kendell, D. Kendell, R. Kendell, D. Kendze, B. Kennedy, C. Kennedy, G.
Kennedy, J. Kennedy, K. Kennedy, M. Kennedy, R. Kennedy, S. Kennedy, W. Kennedy, S. Kenneway, J. Kenny, R. Kenny, L. Kenstavicius, D. 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, S. Khong, S. Kiasosua, I. Kidd, R. Kidd, D. Kidger, B. Kidmose, E. Kie, B. Kiedyk, C. Kiehn, L. Kiez, C. Kilback, D. Kilbreath, M. Kilcollins,
O. Kilo, B. Kim, H. Kim, C. Kimler, G. Kinch, M. Kinden, B. King, C. King, D. King, G. King, I. King, J. King, N. 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, W. Kirkpatrick, M. Kirkwood, B. Kiss, B. Kissel, J. Kissick, M. Kissoon,
C. Kitzan, B. Kiyawasew, G. Kjelshus, T. Kjemhus, J. Klapstein, D. Klassen, R. Klassen, C. Klatt, D. Klause, B. Klautt, R. Klautt, N. Klein, B. Klenk, R. Klimek, M. Klimkiewicz, E.
Klitiris, J. Klotz, G. Kluthe, R. Knee, W. Knelson, D. Kneteman, R. Kneteman, M. Kniebel, G. Knight, J. Knight, R. Knight, J. Knight-Ehiwe, J. Knipe, L. Knoblauch, D. Knoblich,
B. Knopf, D. Knott, J. Knox, K. Knox, C. Knudsen, P. Knull, D. Kobes, B. Kobzey, B. Koch, E. Kodjo Gaba, R. Koenig, K. Koffi, L. Koffi, S. Koffi, J. Kohlman, C. Kohls, B. Kohrs, J.
Kohut, B. Koizumi, C. Kolberg, M. Kolesnikov, D. Kolundzic, B. Koma, C. Komant, M. Komant, B. Komo, S. Kompally, B. Kondratowicz, B. Kone, L. Kone, V. Kone, Y. Kone, L.
Kong, D. Konowalec, R. Konrad, M. Konschuh, E. Kontuk, B. Kootenay, P. Korba, S. Korchagin, M. Koren, P. Kornacki, B. Korolischuk, D. Korrey, J. Kosanovich, A. Kosasih, I.
Koshcheev, D. Kosinski, J. Kosior, B. Kosowan, V. Kostic, K. Kostrub, R. Kostyshyn, B. Kotchi, K. Kotkas, M. Kotty, D. Kotze, M. Koua, C. Kouadio, P. Kouadio, A. Kouakou, D.
Kouame, A. Kouassi, H. Kouassi, A. Kourbaj, M. Koutou, M. Kovac, B. Kovacs, S. Kovacs, R. Kovalenko, R. Kovasin, R. Kovich, M. Kowalchuk, J. Kowalewski, R. Kowalski, R.
Kowbel, E. Kozak, M. Kozak, G. Kozakevich, A. Kozler, A. Kozlowski, B. Kozuback, K. Kra, K. Kramps, R. Kranitz, G. Krause, S. Krause, R. Krauss, R. Kravitz, B. Krawchuk, C.
Krawchuk, J. Krawetz, M. Krawetz, S. Krebs, J. Kreft, T. Kreics, B. Krell, J. Krenbrink, B. Kress, K. Krewulak, R. Krishnaiyer, A. Krishnamoorthy, R. Krishnamurthy, B. Kristianson,
K. Kristman, N. Krochmal, R. Kroeker, K. Krogh, P. Krol, U. Krstic, R. Krueger, G. Kruger, K. Kruger, G. Kruk, N. Krupka, T. Krushel, R. Ku, C. Kubik, C. Kucinar, G. Kucy, J. Kuhberg,
A. Kuir, M. Kulkarni, C. Kully, B. Kumar, P. Kumar, R. Kumar, S. Kumar, C. Kung, D. Kunitz, J. Kuntz, P. Kuppers, S. Kurczaba, D. Kurek, M. Kureshi, M. Kurowski, D. Kurtz, K.
Kurtz, R. Kurtz, G. Kushe, D. Kusmiadji, B. Kutash, K. Kuzevanova, F. Kuzmic, C. Kwan, R. Kwiatkowski, S. Kwiatkowski, V. Kwiatkowski, A. Kwon, J. Kwong, T. Ky, J. Kyes, D.
Kyle, J. Kynock, R. Kynock, A. Kyren-Stortz, D. Labby, J. LaBossiere, J. Laboucan, R. Laboucan, D. Labrecque, T. Lacey, A. LaChance, S. Lachance, J. Lacharite, K. Lacombe,
R. Lacombe, D. Lacroix, M. Lacroix, S. Lacroix, L. Lacuna, A. Laderoute, K. Ladji, K. Lafferty, S. Lafond, D. Lafontaine, R. Laforge, D. Lafreniere, L. Lafreniere, M. Lagimodiere,
B. Lagler, D. Lagos, S. Lagos, A. Laguduva, D. Laha, M. Laha, B. Lahoda, J. Lahoda, C. Lai, R. Lai, S. Lai, E. Laidlaw, A. Laing, R. Laing, S. Laird, A. Laite, M. Lake, K. Lal, P.
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D. Lameman, T. Laminski, J. Lamontagne, R. Lamontagne, J. Lamoureux, T. Lamoureux, W. Lamoureux, W. Lamptey, 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, C. Lang, J. Langdon, K. Langdon, G. Lange, L. Lange, N. Lange, O.
Lange, S. Lange, S. Langford, T. Langill, C. Langpap,
E. Langridge, 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, E. Larm, J. Larochelle, A. Larocque, J.
Larocque, E. LaRose, C. Larsen, E. Larsen, 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, R.
Latimer, M. LaTorre, P. Latus, J. Lau, L. Laube, A.
Lauder, B. Laughlin, P. Laughman, M. Lausen, R.
Lauze, J. Lauzon, M. Lavallee, D. Laventure, K.
Laverty, P. Lavery, B. Lavigne, J. Lavigne, C. Lavoie,
C. Lawford, P. Lawless, B. Lawrence, D. Lawrence,
L. Lawrence, R. Lawrence, S. Lawrence, W.
Lawrence, Y. Lawrence, R. Lawrie, G. Lawson, J.
Laya, C. Layes, K. Layland, P. Layland, S. Layton, K.
Layug, L. Le, M. Le, N. Le, T. Le, R. Le Manne, B.
Leach, T. Leach, R. Leahy, K. Leamon, L. Leamon, A.
Leather, M. Lebas, C. LeBlanc, E. LeBlanc, J.
LeBlanc, R. LeBlanc, T. Leblanc, W. LeBlanc, C.
Lebrun, S. Lebsack, S. Leclair, C. Ledrew, A. Lee, C.
Lee, D. Lee, G. Lee, J. Lee, K. Lee, L. Lee, M. Lee,
R. Lee, S. Lee, T. Lee, B. Leeman, J. Leeman, M.
Lefaivre, G. Lefebure, D. Lefebvre, S. Lefebvre, D.
Legault, K. Legault, J. Legere, P. Legere, M. Legge,
M. LeGrow, K. Lehal, B. Lehbauer, C. Lehmann, S.
Lei, T. Leibel, P. Leier, C. Leishman, M. Leitch, J.
Leman, R. Lemoine, Z. LeMoine, P. Leniuk, P.
Lennon, C. Lenz, S. Lenz, J. Lenzner, T. Leon, J.
Leonard, C. Leong, G. Leong, H. Leong, K. LePage,
T. LePage, S. Lepine, S. Lepp, L. Leppaie, P. Lepper,
Y. Lerner, C. Leroux, E. Leroy, D. LeSann, C.
Leschinski, T. Lesko, R. Leslie, S. Lester, B. Lesyk,
C. Lesyk, M. Lethaby, F. Letkeman, P. Letkeman, T.
T4
Canadian Natural 2021 Annual Report 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, E. Lewis, J. Lewis, K. Lewis, P. Lewis, T. Lewis,
W. Lewis, R. Lewiski, W. Leyland, V. Leyva, J. L’Hirondelle, B. Li,
H. Li, J. Li, Q. Li, S. Li, W. Li, Y. Li, B. Liang, N. Liang, S. Liao, C.
Liba, P. Libari, M. Liber, N. Liegman, S. Lien, C. Lieverse, J.
Lieverse, D. Lightburn, A. Likhar, H. Lim, M. Lim, F. Lin, J. Lin, Q.
Lin, Y. Lin, K. Linaker, B. Lind, S. Lindballe, K. Linder, T. Lindley, G.
Lindner, E. Lindsay, D. Lindskog, P. Linklater, J. Linton, R. Liske,
C. Little, G. Little, J. Little, S. Little, J. Littlechilds, C. Litwin, H.
Liu, J. 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, R. Lloy, P. Lloyd, R. Lloyd, Y. Lo, A. Lobban,
A. Lobbes, G. Lobdell, J. Lochansky, R. Locke, A. Lockhart, N.
Lockhart, R. Lockhart, C. Loder, J. Lodoen, K. Loewen, C.
Lofstrom, R. Logan, D. Loggie, C. Logozar, R. Logozar, J. Lok, 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, D. Lorenz, T.
Lorenz, J. Lorette, K. Lorette, M. Lorincz, B. Lorinczy, M. Loring,
M. Loshny, J. Lotito, T. Lougheed, A. Loughran, E. Louie, L. Louie,
S. Lourido, C. Love, D. Loveless, J. Loveless, W. Loveless, I.
Lovera-Figueroa, 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, M. Lubin, C. Lucas, G. Lucas, I. Lucas, J. Lucas,
T. Lucksinger, B. Lucy, E. Ludwig, S. Lui, L. Luiken, C. Luk, K.
Luk, K. Lukan, L. Lukey, H. Lund, W. Lundell, K. Lundrigan, V.
Lundrigan, E. Lunn, R. Lunn, J. Lunt, C. Lunzmann, X. Luo, B.
Luong, M. Lupul, B. Lush, D. Lush, J. Lush, R. Lusk, A. Lussier,
K. Lussier, C. Lutsch, D. Lutwick, J. Lutyck, K. Lutz, J. Luyt, A. Ly,
G. Lyall, K. Lyall, T. Lychuk, G. Lykidis, D. Lynch, L. Lynch, R.
Lynett, M. Lynn, W. Lyon, N. Lyons, D. Lysak, H. Ma, V. Ma, Y. Ma,
N. Maawia, M. MacBeth, L. MacCallum, K. MacComish, M.
MacConnell, L. Macdaid, A. MacDonald, C. Macdonald, D.
Macdonald, F. MacDonald, J. MacDonald, L. MacDonald, M.
MacDonald, P. MacDonald, R. Macdonald, T. Macdonald, W. MacDonald, G. MacDonell, A. MacDougall, J. MacDougall, M. MacDougall, S. MacDougall, C. MacEachern, J.
MacEachern, M. MacEachern, T. MacEachern, Y. Macedo, C. MacFarlane, O. MacFarlane, K. MacGillis, A. Macgillivray, D. MacGregor, G. MacGregor, S. MacGregor, T. Mach,
K. Machado Rodriguez, S. MacHale, R. Maciborski, J. Maciejewski, T. Macijuk, A. MacInnis, L. MacIntosh, J. MacIntyre, T. Macintyre, D. MacIsaac, D. MacIvor, A. Mack, C.
Mack, L. Mack, S. Mack, B. MacKay, C. Mackay, G. MacKay, K. MacKay, L. Mackay, M. MacKay, S. MacKay, R. Mackelvie, C. Mackenzie, D. Mackenzie, K. MacKenzie, M.
MacKenzie, S. MacKenzie, T. Mackenzie, B. MacKey, S. Mackey, T. Mackey, M. Mackie, A. MacKinnon, B. MacKinnon, K. MacKinnon, T. MacKinnon, F. Mackley, N. Macklin, T.
MacLaren, A. Maclean, B. Maclean, C. MacLean, E. MacLean, K. MacLean, M. MacLean, R. MacLean, A. Maclellan, D. Maclellan, G. MacLellan, J. 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, B. MacNeill, A. MacNiven, H. Macrae, M. MacRitchie, E. MacVicar, T. MacVicar, B. Macwilliams, C. Madadi, H. Madi, C. Madill, H. Madlung, D. Madoche, G.
Madsen, M. Maennchen, L. Maga, G. Magana, J. Magbanua, B. Mageza, S. Magill, C. Magnan, P. Magnan, D. Magnusson, M. Magnusson, J. Magpali, A. Magro, V. Magsila,
D. Magson, R. Maguet, D. Mah, M. Mah, R. Mah, N. Mahar, A. Maida, T. Mailandt, M. Mailhot, D. Maillet, E. Maillet, J. Maillet, M. Mailloux, R. Mailman, J. Mainville, R.
Mairena, B. Maisey, D. Maisey, M. Maitland, R. Maitripala, S. Majdnia, A. Majidi, P. Major, J. Makahnouk, M. Makhoul, D. Makin, M. Makin, L. Makowichuk, G. Makumbe, D.
Malabad, S. Malcolm, H. Maldonado, M. Malech, P. Malhame, A. Malimban, T. Malkova, J. Mallard, K. Mallard, S. Mallay, G. Mallette, T. Malley, C. Mallory, G. Malo, S. Maloney,
A. Maltseva, G. Malvar, O. Malyshev, S. Mamedov, D. Manarang, M. Manderscheid, D. Manengyao, L. Manfredi, J. Manful, J. Mangrove, G. Manhas, M. Manhera, T. Manji, P.
Manlapaz, D. Mann, G. Mann, K. Mann, R. Mann, S. Mann, J. Manning, P. Manoharan, J. Mansfield, D. Manshanden, R. Mantei, A. Manthorne, E. Mantilla, G. Manuel, J.
Manuel, R. Manuel, G. Manuel-Goodyear, J. Manychief, L. Manzano Weffer, C. Mar, H. Maralli, N. Maralli, D. Marazzo, G. Marceau, A. Marcel, A. Marchand, L. Marchand, S.
Marche, F. Marchesan, R. Marcichiw, A. Marcinkoski, T. Marcotte, L. Marcucci, N. Marcy, J. Margetson, W. Margison, E. Marilao, S. Marin, P. Marinzi, S. Marion, D. Mark, S.
Markle, S. Markosyan, B. Marks, K. Markstrom, P. Marolt, U. Maroney, B. Marple, T. Marquis, K. Marriner, R. Marrington, C. Marriott, A. Marsh, B. Marsh, C. Marsh, M. Marsh,
N. Marsh, P. Marsh, C. Marshall, D. Marshall, K. Marshall, S. Marshall, J. Marston, A. Martakoush, P. Martell, D. Martens, S. Martens, A. Marter, 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, J. Maruniak, K. Mashayekh, R. Maskoni, B. Mason, C. Mason, K. Mason, P. Mason, D. Massey, M. Massiah, K. Massick, A. Massicotte,
P. Massicotte, M. Mata, T. Matatko, A. Matchem, S. Matchett, 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, T. Matsushita, B. Matthews, C. Matthews, D. Matthews, E. Matthews, N.
Matthews, J. Matthiessen, R. Matychuk, P. Maurice, A. Maurier, N. Mavani, D. Mavridis, A. Mawer, V. Maximo, C. Maxsom, J. Maxwell, R. Maxwell, R. May, C. Maye, F. Mayell,
J. Mayer, S. Mayer, R. Mayers, A. Maynard, W. Maynard, B. Mayo, C. Mays, A. Mazur, C. Mazuryk, D. McAlister, D. McAllister, J. McAllister, M. McAlpine, D. McArthur, K.
McArthur, E. McAvoy, N. McBain, D. McBrearty, R. McBrien, T. McCabe, S. McCaffrey, S. McCann, D. McCarry, J. McCarthy, M. McCarthy, J. McCarty, D. McCarvill, K.
McClary, D. McClelland, I. McClelland, B. McClure, J. Mcclyment, B. McConachie, C. McConnell, M. McCormack, C. Mccoy, S. McCracken, K. McCrae, C. McCrea, G. McCrea,
J. McCrea, J. Mccready, G. Mccubbing, B. McCullagh, C. McCullough, D. McCullough, E. McCullough, R. McCullough, C. McDonald, D. McDonald, J. McDonald, K. McDonald,
M. McDonald, T. McDonald, L. McDonnell, K. McDougall, M.
McDougall, S. McDougall, J. McDowell, R. McEachnie, N. McElroy,
J. McEwen, W. McEwen, M. McFarlane, L. McFeeters, M.
McGannon, F. McGaw, L. McGean, C. Mcgee, D. McGee, L. McGee,
D. McGinnis, G. McGinnis, P. McGinnis, B. McGlone, G. Mcgonigal,
G. McGowan, A. McGrath, C. McGrath, D. Mcgrath, K. Mcgrath, L.
McGrath, M. McGrath, S. McGregor, T. McGregor, S. McHardy, L.
McHugh, K. McIlroy, D. McIlvaney, A. McIntosh, D. 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, N. McKay, R. McKay, S. McKay, T. McKay, N. McKeachnie, A.
McKee, T. McKee, W. McKellar, K. McKendry, N. McKendry, M.
McKenna, P. McKenna, T. McKenna, J. McKenzie, K. McKenzie, M.
McKenzie, R. McKenzie, R. McKeown, D. Mckersie, K. McKetiak, 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, M. McLaughlin, M. McLean, R. McLean, W. Mclean,
A. McLellan, C. McLellan, K. McLellan, T. McLellan, C. McLenaghan,
G. McLennan, C. McLeod, D. McLeod, I. McLeod, M. McLeod, R.
McLeod, S. McLeod, T. McLeod, P. Mcloughlin, L. McMahon, N.
McManus, J. McMaster, S. McMichael, J. McMillan, R. McNabb, R.
McNair, D. McNamara, K. McNaughton, R. McNaughton, J.
McNaull, M. McNay, D. McNeil, H. McNeil, J. McNeil, K. McNeil, P.
McNeil, R. McNeil, S. McNeill, T. McNelly, C. McPhail, L. McPhee,
R. McPhee, J. McPherson, K. McPherson, A. McQueen, E.
McQueen, J. McQueen, 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, K. Meh, M. Mehaney, F. Mehdiyev, N.
Mehta, P. Mehta, V. Mehta, C. Mejia, J. Mejia, B. Melanson, J.
Melanson, R. Melanson, T. Melindy, H. Mellafont, B. Meller, L.
Mello, G. Mellom, C. Mellott, D. Melnyk, K. Melnyk, M. Melnyk, R.
Melnyk, A. Melo, J. Melville, A. Menard, D. Menard, L. Mendenhall,
P. Mendes, M. Mendez, M. Mendonca, N. Meneses, F. Meng, D.
Menjivar, B. Mennie, P. Menzel, G. Merali, C. Mercer, G. Mercer, J.
Mercer, J. Mercier, C. Merkel, G. Merkel, D. Merkley, A. Merle, S.
Merralls, K. Merrill, C. Merritt, N. Merritt, R. Merritt, K. Mesenchuk,
U. Meservy, K. Mess, S. Metcalfe, T. Methuen, C. Metz, S. Meunier,
R. Mewis, C. Mews, D. Mews, R. Mews, T. Michaelis, L.
T5
Canadian Natural 2021 Annual Report Michalishen, C. Michalko, O. Michalsky, B. Michaud, T. Michel, M. Michelin, K. Mickel, N. Mickelson,
D. Midgley, K. Mielty, C. Mihai, J. Mihailoff, M. Miiller, T. Mijic, D. Mikalson, A. Mikhailov, S.
Mikloukhine, J. Miko, G. Milan Garcia, J. Milce, J. Mildenberger, R. Millar, D. Miller, G. Miller, J. Miller,
K. Miller, L. Miller, R. Miller, S. Miller, T. Miller, W. Miller, L. Milligan, C. Mills, D. Mills, G. Mills, H.
Mills, J. Mills, R. Mills, S. Mills, T. Mills, J. Millwater, A. Milne, J. Milne, T. Milne-McLean, D. Milward,
F. Mingle, A. Minhas, S. Minhas Chapman, M. 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, M. Mirzadeh, J. Mistecki, D.
Mistry, C. Mitchell, G. Mitchell, J. Mitchell, M. Mitchell, R. Mitchell, T. Mitchell, W. Mitchell, Y. Mitchell,
N. Mitchell-Banks, M. Mitton, R. Mkumbukwa, R. Moberly, 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, N. Molder, N. Molina, R. Mollison, J. Molnar, T. Mombourquette, R. Monahan, R.
Money, P. Monfette, F. Montefresco-Gentile, R. Monteith, J. Montgomery, M. Montinola, B. Moon, K.
Moon, P. Moon, J. Mooney, B. Moore, D. Moore, E. Moore, J. Moores, L. Mora, A. Morelli, K. Morency,
L. Moreno, A. Morey, C. Morfitt, C. Morgan, J. Morgan, T. Morgan, K. Mori, 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, A. Morrison, B. Morrison, C.
Morrison, D. Morrison, J. Morrison, S. Morrison, W. Morrow, S. Morse, D. Morsette, A. Mortlock, A.
Morton, K. Morton, L. Morton, M. Morvik, D. Mose, D. Moser, J. Moshenko, T. Moskol, P. Mossey, B.
Mossop, C. Mostowich, J. Mostyn, S. Mothersele, L. Motowylo, B. Mottle, J. Moul, S. Moul, L.
Mounkes, I. Mountain, M. Mousavi, S. Mousazadeh, O. Moussa, M. Mousseau, C. Mouta, D. Mouton,
R. Moyle, C. Moyls, M. Mubarak, T. Mudzviti, T. Mueller, T. Muessle, A. Mugford, R. Mugford, M.
Mughal, S. Muhammad, K. Muir, D. Muise, L. Muise, S. Muise, V. Mukerji, K. Mullaly, G. Mullen, S.
Muller, C. Mullett, B. Mulligan, R. Mullin, N. Mulvena, S. Mundt, K. Munn, A. Munro, J. Munro, L.
Munro, R. Munro, 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, M. Musaid, A. Mushava, I. Musiwarwo, W. Muss, D. Musselman, T. Musselman, N.
Musterer, Z. Musuna, A. Muthuswamy, R. Mutschler, T. Mutter, J. Mweshi, D. Myers, E. Myers, L.
Myhre, S. Myles, G. Nabi, 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, K. Najafian, S. Najeeb, L. Najoan, B. Nalder, N.
Namoca, E. Namur, M. Nandoria, J. Napier, R. Napier, S. Naqvi, P. Narayan, K. Narayanan, A. Narcise,
S. Naser, M. Nassir, D. Nater, M. Nathwani-Crowe, A. Naughton, D. Naugler, D. Navas, R. Navas, V.
Navratil, B. Nawaz, S. Nayak, C. Nazarko, N. N’Doye, B. N’Dure, T. Neacsu, D. Neal, N. Neale, M.
Neate, A. Neddjar, S. Needham, D. Neergaard, J. Neff, S. Negi, Y. Neguse, D. Neigum, A. Neilson, S.
Neilson, K. Nelligan, A. Nelson, B. Nelson, D. Nelson, J. Nelson, M. Nelson, R. Nelson, S. Nelson, V.
Nelson, A. Nemirsky, M. Nergaard, N. Nernberg, G. Nesbitt, B. Nessman, K. Netter, K. Nettesheim, G. Netzel, C. Neufeld, M. Neufeld, O. Neufeld, F. Neumaier, D. Neumann,
D. Nevil, W. Nevills, D. Newbury, R. Newitt, A. Newman, J. Newman, L. Newman, P. Newman, R. Newman, A. Newton, K. Newton, D. Ng, J. Ng, K. Ng, S. Ng, V. Nganzo, P.
N’Gbesso, H. Ngo, N. Ngo-Schneider, C. Nguyen, M. Nguyen, D. Niamke, F. Nichol, J. Nicholl, D. Nichols, J. Nichols, A. Nicholson, S. Nicholson, A. Nickel, D. Nickerson, K.
Nickerson, W. Nicklefork, J. Nicolajsen, E. Nicolas, T. Nicolas, B. Nicolaysen, J. Nicoll, J. Nie, C. Nielsen, K. Nielsen, M. Nielsen, T. Nielsen, O. Nieto, M. Nieves, M. Nikic, W.
Nikiforuk, C. Nikipelo, R. Nimco, T. Ninovska, M. Nippard, R. Nippard, S. Nippard, D. Nissen, J. Nistico, T. Nistor, O. Niven, R. Nixdorf, K. Nixon, P. Niziolek, N. Njoku, A. N’Kesse,
G. Noble, M. Nobles, C. Noel, D. Noel, P. Noel, A. 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, D. Norman, J. Norman, M. Norman, P. Norman, T. Norman, T. Normand, Y. Normand, C. Normandin, C. Normore, B. Norquay, L. Norrad, N. Northcott, K. Norton, R.
Norton, A. Noskey, K. Notenbomer, F. Nothnagel, J. Novak, D. Nowicki, R. Nunweiler, D. Nwagbogwu, R. Nycholat, C. Nyman, K. Nzemba, W. Oak, W. Oakes, A. Obad, D. Ober,
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, T. Oele, 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, S. O’Grady, D. Ogren, B. Ogurian, J. Oh, T. Oh, Y. Oh, T. Oickle, R. Okada, C. O’Keefe, E. O’Keefe, L. Okemow, A. Okeynan, R. Oksanen, K. Okuszko, E.
Okyere, F. Oladebo, P. Olaniyan, S. Olar, A. Olaski, B. Olaski, C. Oldfield, M. Oldford, S. O’Leary, B. Olenik, D. Olesen, B. Olheiser, D. Oliveira, D. Oliver, N. Oliver, A. Oliverio,
C. Olivier, D. Ollenberger, S. Ollerhead, J. Ollikka, V. Olofernes, G. Oloumi, K. Olsen, M. Olsen, R. Olsen, S. Olsen, C. Olson, D. Olson, J. Olson, M. Olson, P. Olson, S. Olson,
W. Olson, K. Olszewski, O. Oluwole, P. Onciul, D. O’Neil, T. O’Neill, D. Ong, K. Onuoha, P. Onyszko, C. Opper, M. O’Reilly, N. O’Reilly, J. O’Rourke, L. Orpilla Jr, A. Orr, B. Orr,
N. Orr, S. Orser, P. Ortega, R. Osachoff, C. Osborne, J. Osborne, G. Osbourne, D. O’Shea, J. Oshman, D. Osinchuk, M. Osman, K. Osmond, T. Osmond, L. Osorio, H. Osorio
Lobo, A. Ospino, B. Ostafichuk, A. Ostrzenski, J. O’Sullivan, C. Oswald, D. Oswald, J. Otis, K. Otoo, J. O’Toole, C. Ottenbreit, L. Otteson, M. Otteson, W. Otteson, J. Otto, D.
Ouattara, L. Ouch, D. Ouellette, J. Ouellette, S. Ouellette, E. Overbye, Z. 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, S. Pacholok, T. Packard, J. Paddington, R. Padilla, B. Padlewski, T. Padron, M. Pady, S. Page, M. Pagnucco, Q.
Pagnucco, T. Pagura, D. Pahljina, S. Paiement, K. Paige, R. Paine, K. Painter, J. Pak, V. Pak, A. Palani, C. Palchewich, D. Palmer, J. Palmer, K. Palmer, L. Palmer, O. Palomino, A.
Palou, J. Palsis, F. Pana, J. Panas, B. Panchal, V. Pandey, D. Pandher, S. Pandya, L. Pantazi, F. Pantilag, S. Panuganty, Y. Panya, A. Papadoulis, R. Papalia, M. Papcun, J. Papp, V.
Papuga, P. Paquette, L. Paquin, D. Paradis, E. Paradis, J. Paradis, T. Paradis, M. Paranjape, B. Parathundathil, G. Parchewsky, P. Parchure, M. Pardy, L. Paredes, C. Parenteau,
J. Parenteau, L. Parillo, R. Parillo, B. Parker, D. Parker, J. Parker, D. Parlee, M. Parmar, C. Paron, A. Parsons, M. Parsons, S. Parsons, T. Parsons, W. Parsons, 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, C. Paton, G. Paton, W. Patrick,
E. Patten, B. Patterson, C. Patterson, J. Patterson, K. Patterson, W. Patterson, C. Pattinson, C. Paul, G. Paul, J. Paul, K. Paul, T. Paul, M. Paulgaard, J. Paulsen, B. Paulson, B.
Paulssen, B. Pauwels, D. Pavelick, M. Pavlic, C. Pawlachuk, A. Pawlowich, M. Pawluk, C. Pay, C. Paylor, A. Payne, 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, T. Peats, T. Peciulis, G. Peddi, E. Peddle, D. Pedersen, J. Pedersen, K.
Pedersen, P. Pedersen, L. Pederson, B. Peebles, J. Peeke, M. Peeke, R. Peel, D. Peet, E. Pegg, C. Peifer, F. Pelayo, K. Pelayo, G. Pellegrino, D. Pelletier, M. Pelletier, A. Pelley,
I. Pelly, M. Pelypiw, D. Pemberton, L. Pena, Y. Peng, J. Penman, S. Penman, C. Pennell, T. Pennell, S. Pennemann, S. Penner, D. Penney, E. Penney, H. Penney, J. Penney, S.
Penny, J. Penzo, I. Pepper, D. Peramanu, S. Peramanu, R. Peraza, M. Perehudoff, J. Perepelecta, F. Perez, L. Perez, J. Perez-Licera, D. Perkins, M. Perkins, R. Perkins, J.
Pernitsch, J. Peroramas, C. Perran, D. Perreault, M. Perrin, N. Perron, C. Perry, D. Perry, G. Perry, J. Perry, O. Perry, R. Perry, S. Perry, T. Persaud, D. Perumal, B. Pesowski, P.
Peter, A. Peters, D. Peters, G. Peters, J. Peters, K. Peters, M. Peters, R. Peters, A. Peterson, B. Peterson, E. Peterson, K. 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, B. Phan,
L. Phan, K. Phibbs, B. Philibert, G. Philip, 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, W. Picard, E. Picard-Goulet, K. Picco, J. Picken, K. Pickering, A. Pickersgill, T. Pickett, B. Piderman, D. Pierce, J. Piercey, S. Piercey, T. Piercey, 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, S. Pinksen, T. Pinksen, K. Pinney, J. Pintaric, B. Pipa, J. Pipke, C. Pirnak, D. Pirvan, K. Pisio, M. Pitman, J. Pitoulis, M. Pitre, A. Pittman,
C. Pittman, D. Pittman, E. Pittman, I. Pittman, J. Pittman, M. Pittman, W. Pittman, M. Plamondon, R. Plamondon, E. Plante, J. Plata, D. Plepelic, I. Plesa, J. Plessis, G. Plews,
K. Plosz, G. Plouffe, T. Plouffe, J. Plowman, E. Plumb, J. Plummer,
I. Pocaterra, J. Pocock, S. Podhorodeski, H. Poffenroth, D. Pohl, A.
Poirier, D. Poirier, D. Poitras, J. Polacik, D. Pole, C. Pollard, R.
Pollard, T. Pollett, A. Pollock, J. Pollock, M. Pollock, J. Polsfut, G.
Pome Franco, L. Pomponio, S. Pon, M. Poncelet, D. Poncsak, B.
Pond, D. Pond, B. Ponjevic, N. Ponkiya, T. Poole, K. Poon, G. Pope,
T. Pope, C. Popko, J. Popoff, J. Popowich, M. Popowich, C.
Portelance, J. Portelli, A. Porter, C. Porter, I. Porter, L. Porter, T.
Posch, M. Posnikoff, P. Postlewaite, R. Postnikoff, C. Potorti, M.
Potorti, J. Potter, T. Potter, K. Potts, R. Potts, T. Potts, J. Poulin, R.
Poulter, K. Pounall, I. Pouncey, C. Povse, C. Powell, D. Powell, J.
Powell, P. Powell, R. Powell, A. Power, 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, D. Presley, C. Prest, A.
Preston, J. Preston, R. Preteau, A. Price, W. Price, J. Priest, D.
Pringle, T. Prins, R. Pritchett, S. Pritchett, K. Proc, G. Prochner, K.
Proctor, D. Procyshyn, M. Profiri, N. Proll, M. Pronk, M. Prosper,
D. Prostler, I. Proudfoot, D. Proulx, K. Prowse, T. Prudhomme, S.
Prud’Homme, C. Prybylski, C. Przybylski, S. Pshyk, 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, P. Pynn, J.
Pyper, A. Pyra, M. Qian, W. Qian, L. Qing, J. Qu, C. Quach, A.
Quan, G. Quan, A. Quarin, R. Quartermain, K. Quaschnick, J.
Quiba, D. Quigley, R. Quigley, S. Quigley, C. Quinlan, M. Quintin,
G. Quinton, B. Quipp, S. Qureshi, J. Raban Mardelli, J. Rabby, B.
Rabusic, M. Raby, P. Racette, D. Rachkewich, D. Raciborski, W.
Raczynski, L. Radesh, K. Radke, R. Radke, A. Radtke, M. Radu, J.
Rae, R. Rae, D. Raedts, W. Rafiq, I. Rafiyev, G. Raghavan Nair, S.
Raghuwanshi, J. Raher, A. Rahmani, M. Rahmani, P. Rai, S.
T6
Canadian Natural 2021 Annual Report Rainey, J. Rainnie, M. Raistrick, A. Raivio, K. Raj, M. Raj, S. Rajan, M. Rajic, J. Rajotte, J.
Ralph, P. Ralph, S. Raman, J. Ramazani, J. Rambold, D. Ramburrun, D. Ramirez, J. Ramirez,
M. Ramirez, P. Ramirez Perez, C. Ramos, J. Ramsay, M. Ramsay, S. Ramsay, K.
Ramsbottom, M. Rana, D. Randell, L. Randell, M. Randell, T. Randell, W. Randell, M.
Rankin, D. Ranola, J. Ransom, M. Raoufi, R. Raposo, S. Rasch, T. Rasheed, C. Rasko, K.
Raskob-Smith, S. Rasmussen, R. Raso, H. Rassi, W. Ratcliffe, D. Rath, S. Ratkovic, M.
Rattray, H. Ratzlaff, A. Rau, M. Rausch, B. Rawling, C. Rawson, S. Rawson, W. Rawson, A.
Ray, D. Ray, K. Ray, S. Ray, K. Rayment, D. Raymond, E. Rayner, J. Rayner, M. Raza, S.
Raza, K. Razniak, F. Re, B. Read, D. Read, W. Reashore, C. Reber, D. Reber, D.
Rechenmacher, G. Redding, B. Redlich, E. Redlon, 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, J. Reid, K. Reid, M. Reid, R. Reid, T. Reid, T. Reilly, D. Reimer, I. Reimer, M.
Reinders, T. Reinders, D. Reinhold, J. Reiniger, M. Reinkens, E. Reis, R. Reis, G. Reiter, H.
Reithaug, D. Rejman, D. Relkow, W. Remmer, C. Rempel, P. Rempel, T. Rempel, L. Ren, S.
Ren, R. Renaud, A. Rennie, J. Rennie, L. Rennie, J. Rentar, J. Repchuk, S. Resus, C.
Revereza, M. Rew, E. Reyes, O. Reyes, J. Reynolds, P. Reynolds, S. Reynolds, T. Reynolds,
D. Reznik, N. Rhemtulla, C. Rhode, I. Riach, S. Ricci, D. Rice, J. Rice, R. Rice, J. Richard,
K. Richard, M. Richard, B. Richards, C. Richards, D. Richards, H. Richards, T. Richards, A.
Richardson, K. Richardson, T. Richardson, B. Riche, P. Richer, W. Ricker, C. Ricketson, A.
Ricketts, M. Ricketts, W. Ricketts, C. Rico-Ospina, J. Rideout, R. Rideout, T. Rider, C.
Riegling, C. Ries, M. Rigg, D. Riley, S. Riley, D. Rinas, G. Ringheim, R. Rioux, S. Rioux, J.
Ripka, P. Riseley, J. Risling, S. Risling, L. Ritchat, D. Ritchie, L. Ritchie, R. Ritchie, K. Ritter,
A. Riutta, S. Rivard, E. Rivera, J. Rivera, M. Rizwan, D. Robbins, 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, 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, C. Rockwell, S. Rodberg, R. Rodden, T. Rodgers, J.
Rodriguez, M. Rodriguez, P. Roett, D. Rogal, K. Rogalsky, P. Rogatschnigg, C. Rogers, K.
Rogers, M. Rogers, S. Rogers, M. Rogne, L. Rojas, S. Rolling, K. Rolseth, P. Roman, L.
Romanchuk, T. Romanchuk, B. Romanovich, D. Romanyshyn, M. Rombough, A. Romero, G.
Romero, J. Romero, S. Rommelaere, A. Ronald, D. Rondeau, J. Roney, S. Roney, P. Ronnie,
B. Ronspies, J. Rooney, S. Roop, C. Root, A. Roozendaal, J. Ropson, B. Rose, C. Rose, J.
Rose, M. Rose, P. Rose, M. Rose-Atkins, R. Rosenthal, D. Rosgen, S. Roskey, M. Rosloot,
T. Rosner, A. Ross, E. Ross, I. Ross, J. Ross, M. Ross, R. Ross, W. Ross, R. Rossburger, G.
Rosser, J. Rostad, B. Rosychuk, B. Roszell, C. Roth, K. Roth, M. Roth, R. Roth, T. Roth, B.
Rott, J. Rotzoll, S. Rouf, D. Rough, D. Roughton, E. Roul, J. Rouleau, G. Rousselle, A.
Routhier, D. Routhier, R. Routhier, R. Routley, A. Rowbottom, M. Rowe, D. Rowley, M.
Rowley, F. Roxas, A. Roy, B. Roy, D. Roy, R. Roy, S. Roy, L. Roychowdhury, D. Royston, A.
Rozhkov, R. Rucks, Z. Ruda, V. Ruddy, D. Rudkevitch, K. Rudolf, C. Rudolph, K. Rudra, K.
Ruecker, L. Ruesga, S. Ruether, M. Ruetz, I. Rugg, M. Ruiz, S. Rumball, D. Rumbolt, T.
Rumbolt, J. Rumjan, D. Rumohr, J. Rushton, J. Rusk, N. Rusk, T. Rusnak, C. Russell, D.
Russell, E. Russell, S. Russell, T. Russell, R. Rustad, D. Rutberg, B. Rutherford, J.
Rutherford, M. Rutherford, D. Rutley, M. Rutter, T. Ruttle, H. Rutz, M. Ruzicka, N. Rvachew,
F. Rwirangira, 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, M. Sabo,
A. Sabourov, F. Sackey-Forson, J. Sacrey, N. Sacrey, S. Sacrey, V. Sacrey, J. Sagan, S.
Sagrafena, A. Saha, S. Sahoo, T. Sahraoui Hamdi, A. Sailer, A. Saini, B. Saini, J. Saini, P.
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,
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, A. Sampson, H. Sampson, J. Sampson, R. Sampson, T. Sampson, B. Samson, T. Samuelson, S. Samy, V. Sanchala, E. Sanchez, M.
Sanchez, P. Sanders, R. Sanders, T. Sanders, D. Sanderson, J. Sanderson, L. Sanderson, S. Sanderson, C. Sandford, S. Sandhar, N. Sandhawalia, J. Sandhu, G. Sando, T. Sanelli,
N. Sanftleben, J. Sangha, E. Sangroniz, E. Sanh, N. Sankaran, T. Santos, M. Santucci, J. Sanyal, 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, W. Sather, T. Satink,
M. Satra, H. Sattar, E. Saucier, J. Saucier, E. Saulnier, G. Saunders, L. Saunders, M. Saunders, S. Saurette, C. Sauve, J. Savage, C. Savard, F. Savaria, B. Savla, D. Savoie, M.
Savoie, C. Savostianik, C. Savoy, N. Sawchuk, S. Sawchuk, D. Saxty, C. Sayer, E. Sayewich, K. Sayko, K. Scagliarini, R. Scammell, J. Scarfe, J. Scarff, R. Schaap, T. Schable, K.
Schachtel, B. Schade, R. Schafer, D. Schaffer, M. Schanzenbach, G. Schappert, T. Schatkoske, R. Schatschneider, C. Schaub, P. Schaub, J. Schechtel, T. Scheers, C. Scheerschmidt,
L. Scheetz, A. Schell, S. Schellenberg, L. Schelske, L. Scheper, C. Scheu, D. Schick, J. Schick, S. Schick, A. Schill, C. Schiller, J. Schiller, L. Schiller, A. Schindel, C. Schindel, R.
Schlachter, M. Schlamp, D. Schledt, H. Schleedoorn, D. Schlosser, L. Schmaus, S. Schmid, A. Schmidt, J. Schmidt, K. Schmidt, N. Schmidt, R. Schmidt, T. Schmidt, P.
Schmuland, C. Schneider, D. Schneider, G. Schneider, M. Schneider, P. Schneider, S. Schneider, K. Schnell, S. Schnell, C. Schnepf, A. Schnick, C. Schnurer, J. Schoengut, E.
Schofield, N. Schofield, S. Schofield, B. Schole, R. Schonheiter, M. Schraven, 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, B. Schwab, D. Schwank, B. Schwartz, D. Schwarz, L. Schwetz, J. Schwindt, T.
Scimia, M. Scipior, R. Scoles, J. Scollard, B. Scott, D. Scott, E. Scott, G. Scott, J. Scott, K. Scott, M. Scott, R. Scott, S. Scott, T. 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, J. Seenum, B. Seewitz,
M. Seguin, R. Seguin, L. Sehn, K. Seidel, C. Seifridt, P. Seipp, K. Seitz, R. Sekel, B. Sekulich, E. Sekura, D. Selby, K. Self, J. Selin, M. Selman, R. Selvarajan, D. Semaan, A.
Semchanka, L. Semeniuk, K. Seminchuk, T. Senecal, T. Senger, P. Senk, T. Senner, H. Seo, F. Sepnio, C. Sereda, R. Sereda, S. Sereda, R. Serfas, R. Sergeew, 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, N. Shabalina, C.
Shackleton, M. Shad, B. Shah, H. Shah, M. Shah, N. Shah, R. Shah, S. Shah, V. Shah, M. Shahebrahimi, S. Shahzad, K. Shakir, K. Shakotko, V. Shakouri, O. Shams, A.
Shandroski, L. Shang, C. Shank, B. Shanmugam, J. Shannon, G. Shantz, A. Sharifi, A. Sharma, D. Sharma, K. Sharma, R. Sharma, T. Sharma, M. Sharman, N. Sharp, J. Sharpe,
K. Sharpe, R. Sharron, R. Shaver, B. Shaw, E. Shaw, K. Shaw, R. Shaw, O. Shaykina, K. Shea, L. Shea, B. Shearer, C. Shears, D. Sheaves, L. Sheaves, W. Sheaves, A. Shehata,
K. Sheikh, M. Sheikh, C. Shen, B. Shenton, R. Shepel, I. Shepherd, C. Sheppard, G. Sheppard, J. Sheppard, L. Sheppard, M. Sheppard, P. Sheppard, R. Sheppard, C.
Sherbanuk, A. Shergill, T. Sheridan, M. Sherman, R.
Sherman, A. Sherriffs, M. Sheth, N. Sheth, V. Shetty, D.
Shewchuk, L. Shi, A. Shideler, A. Shidhaye, C. Shields, A.
Shiers, N. Shihinski, S. Shiledarbaxi, K. Shill, C. Shimbashi,
P. Shiner, W. Shipley, B. Shipton, 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, T.
Shukin, H. Shukla, K. Shukla, D. Shular, J. Shumate, F.
Shupenia, S. Shymoniak, D. Shypitka, J. Shysh, C.
Sibeudu, I. Siddhanta, A. Siddiqui, M. Siddiqui, C. Sieben,
D. Sieben, J. Sieben, E. Siemens, M. Siewecke, A. Sifton,
R. Sigsworth, J. Sikora, W. Sikorski, L. Silas, T. Silbernagel,
D. Silk, A. Sillito, B. Silue, K. Silue, N. Silue, I. Silva, J.
Silva, L. Silva, J. Silver, G. Silvis, C. Simard, D. Simard, R.
Simard, D. Simbi, C. Simcock, G. Simmelink, L. Simmonds,
T. Simmonds, J. Simmons, C. Simms, D. Simms, F. Simms,
R. Simms, S. Simms, M. Simoes, A. Simon, T. Simon, 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, M. Sinkova-Hovdestad, A. Sinnett, B. Sinnicks, L.
Sinnicks, R. Sison, J. Sjonnesen, D. Skanderup, W. Skaret,
E. Skarsen, B. Skinner, R. Skinner, T. Skinner, M. Skipper,
J. Skjeie, G. Skoczek, 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, K. Slotwinski, J. Sloychuk, W. Slunt, S.
Slywka, P. Smart, R. Smart, Q. Smethurst, J. Smid, S.
Smiegielski, K. Smigelski, A. Smith, B. Smith, C. Smith, D.
Smith, E. Smith, G. Smith, J. Smith, K. Smith, M. Smith,
T7
Canadian Natural 2021 Annual Report R. Smith, S. Smith, T. Smith, C. Smitham, E. Smolyaninova, A. Smyl, B. Smyl,
R. Smyl, J. Sneddon, K. Snee, R. Snell, T. Snell, G. Snider, J. Snider, P. Snider,
I. Snook, J. Snow, K. Snow, K. Snowden, D. Snowdon, J. Snowdon, D. Snyder,
J. Soar, J. Soenen, D. Soetaert, D. Sohlbach, D. Sokoloski, K. Sokoloski, S.
Solanki, J. Solano, J. Soley, S. Solis, V. Sollid, M. Sollows, S. Soloshy, A.
Soloway, K. Soltys, L. Somerville, L. Sommer, W. Sommerfeld, R. Somorai, D.
Soni, A. Sonpal, N. Soodyall, W. Sookram, M. Soolagallu, T. Sopatyk, G.
Sopczak, H. Sorensen, R. Sorensen, C. Sorenson, M. Sorgard, 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, L. Speer, D. Spencer, S. Spencer, B.
Spendiff, E. Sperrer, D. Spidell, A. Spohn, C. Sporidis, M. Sprinkle, C. Sproat,
A. Spurrell, E. Spurrell, N. Spurrell, P. Spurvey, R. Spychka, C. Spykerman, N.
Squarek, J. Squire, 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, K.
St.Laurent, A. Stacey, K. Stacey,
I. Stacey-Salmon, P. Stackhouse, G.
Stadnichuk, S. Stadnichuk, S. Stadnyk, D. Stagg, J. Stagg, T. Stagg, M.
Stainthorpe, K. Stairs, J. Stajkowski, M. Stalker, B. Stamp, R. Stamp, A. Stan,
A. Standing, J. Stanford, B. Stang, C. Stang, M. Stang, R. Stang, R. Stanger, J.
Stanley, T. Stanley, A. Staples, J. Staples, P. Stapleton, K. Stark, L. Stark, R.
Staruiala, D. Staszewski, K. Staszkiewicz, S. Stauth, A. Stavropoulos, K.
Stawinski, M. Stebner, M. Stec, R. Steele, B. Steeves, L. Steeves, S. Stefan, T.
Stefansson, A. Stefura, M. Steinbach, I. Steiner, G. Steinke, J. Steinkey, S.
Steinkey, A. Stella, D. Stemmann, W. Stenhouse, G. Stephen, M. Stephens, T.
Stephens, B. Stephenson, J. Stephenson, L. Stephenson, G. Stetar, N.
Stevens, R. Stevens, A. Stevens-Dicks, D. Stevens-Dicks, A. Stevenson, H.
Stevenson, N. Stevenson, R. Stevenson, T. Stevers, B. Stewart, C. Stewart, D.
Stewart, J. Stewart, L. Stewart, M. Stewart, R. Stewart, T. Stewart, B. Stich, W. Stickel, G. Stickelmier, 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, D. Stormo, B. Stortz,
D. Stout, D. Stoyles, S. Strachan, R. Stranberg, C. Strand, W. Strand, J. Strandquist, R. Strang, D. Strankman, N. Strantz, B. Stratichuk, D. Stratmoen, M. Straughan, M. Street,
S. Street, R. 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, J. Studer, C. Study, J. Stuebing, G. Sturdy, F. Sturge, J. Sturge, P. Sturge, J. Sturgeon, D.
Sturrock, A. Styles, L. Su, W. Su, M. Suarez, V. Subasic, I. Subasinghe, V. Subban, J. Subramaniam, R. Subramaniam, B. Suchan, R. Sudan, 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, P. Sundaravadivelu,
C. Surgenor, A. Surugiu, G. Surugiu, T. Sutcliffe, C. Sutherland, D. Sutherland, C. Suttie, B. Sutton, P. Sutton, S. Sverdahl, T. Svoboda, A. Swain, D. Swain, S. Swain, T. Swallow,
D. Swan, J. Swannack, J. Swanson, E. Sweeney, S. Sweetapple, C. Swenarchuk, N. Swennumson, G. Swenson, E. Switzer, A. Sychak, K. Sydorko, D. Syed, W. Syed, T.
Sylvester, A. Symons, M. Symons, T. Sypher-Michel, D. Syrnyk, G. Sywake, N. Szalay, E. Szeto, C. Szmata, A. Szoke, M. Szoke, D. Sztukowski, D. Sztym, S. Szubzda, M. Szucs,
C. Szutiak, K. Szydlik, J. Ta, C. Tacadena, M. Tade, D. Taggart, A. Taghipour, A. Tahir, V. Tai, P. Taiani, M. Tainsh, D. Tainton, D. Tait, G. Tait, O. Tait, J. Taite, A. Tajik, D. Tajiri, G.
Talati, S. Talati, C. Talbot, J. Talbot, M. Talerico, 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,
J. Tanner, M. Tapley, G. Tapp, C. Tarache, A. Tarasenco, R. Tarasoff, C. Tardif, G. Tarditi, W. Tarkowski, M. Taron, B. Tasek, J. Tatarin, R. Tatro, N. Tavassoli, A. Taylor, C. Taylor,
G. Taylor, H. Taylor, J. Taylor, K. Taylor, L. Taylor, M. Taylor, N. Taylor, P. Taylor, R. Taylor, S. Taylor, J. Taylor-Kay, M. Teeple, J. Teixeira, F. Tejada, A. Telan, R. Tellier, B. Temesgen,
J. Temple, C. Templeton, S. Templeton, S. Tenhunen, K. Tenney, J. Teppin, E. Tertsakian, W. Ter way, G. Teske, A. Teslak, L. Tessier, W. Teszeri, W. Tetachuk, C. Tetreau, J.
Tettensor, B. Tetz, J. Tetz, S. Tetz, I. Tewfik, F. Thaddaues, L. Thai, T. Tham, P. Thannhauser, J. Theis, G. Theriault, G. Therrien, B. Thevarajah, G. Thibault, J. Thibeau, R.
Thibodeau, C. Thiessen, J. Thiessen, R. Thiessen, T. Thiessen, E. Thillman, M. Thoen, D. Thomas, E. Thomas, L. Thomas, S. Thomas, J. Thomas Cotton, T. Thomassen, A.
Thompson, C. Thompson, E. Thompson, I. Thompson, J. Thompson, K. Thompson, L. Thompson, R. Thompson, S. Thompson, T. Thompson, P. Thomsen, A. Thomson, J.
Thomson, K. Thomson, P. Thomson, S. Thomson, T. Thomson, W. Thomson, K. Thorburn, T. Thorburne, L. Thorhaug, J. Thorleifson, D. Thorne, L. Thorne, B. Thornhill, E.
Thornton, K. Thornton, N. Thorp, K. Thors, K. Threndyle, E. Thunaes, M. Thyer, T. Tian, M. Tiedje, P. Tieu, D. Tillapaugh, J. Tiller, D. Tilley, M. Tilley, K. Tillotson, T. Tillotson,
S. Timothy, N. Tindall, M. Tineo, D. Tipper, A. Tishchenko, B. Titus, D. Tiwary, R. Tiwary, C. Tkach, D. Tkachuk, K. Tobias, B. Tobin, C. Tobin, K. Tobin, V. Tobin, K. Tobler, B.
Todd, C. Todd, T. Tolen, D. Tomar, B. Tomchuk, G. Tomchuk, D. Tomiuk, J. Tomiuk, C. Tomlinson, K. Tomlinson, M. Tompkins, A. Tomszak, N. Tomte, L. Tong, W. Tong, T. Tonge,
M. Tonon, S. Tookey, A. Toop, V. Topacio, S. Topolnitsky, K. Tordon, P. Torrance, C. Torraville, F. Torraville, J. Torraville, N. Torres, D. Touchette, S. Touchette, D. Toullelan, T.
Tourand, M. Townsend, J. Tozer, O. Tozser, A. Tran, C. Tran, D. Tran, J. Tran, M. Trang, C. Trapp, G. Trask, L. Trautman, M. Travers, L. Traverse, P. Traverse, J. Tredger, G. Treen,
M. Trefon, J. Trelinski, W. Trelinski, J. Treliving, L. Tremblay, M. Tremblay, C. Tremblett, W. Tremblett, J. Trenholm, H. Trepanier, J. Trieu, J. Trieu-Ly, W. Trigger, A. Trinh, D.
Trinh, E. Triumbari, C. Troake, P. Troy, J. Trto, J. Trudeau, R. Trudeau, A. Truong, H. Truong, N. Truong, S. Truong, L. Tsaprailis, M. Tschaja, C. Tse, E. Tse, Y. Tse, G. Tsemenko,
M. Tsineli, Y. Tu, C. Tubi, A. Tuck, B. Tucker, D. Tucker, J. Tucker, R. Tucker, R. Tuerke, A. Tuico, D. Tuite, J. Tuite, S. Tulan, 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, S. Tutkaluk, R. Tuttle, I. Tutto,
B. Tuttosi, L. Tuttosi, J. Tweten, P. Twomey, D. Twyne, O. Tyan, A. Tyler, M. Tyler, W. Tymchuk, D. Tymchyna, R. Tymchyna, C. Tyssen, S. Uddenberg, J. Uddin, J. Uhlman, T.
Uhrich, S. Ulloa, J. Ulmer, E. Ulrich, J. Umali, O. Umana, M. Umeh, U. Umoh, L. Underhill, K. Under wood, N. Under wood, R. Under wood, T. Ung, B. Unrath, L. Unrau, H.
Unruh, P. Unruh, M. Upadhyay, S. Upadhyay, U. Upadhyaya, M. Uponi, J. Urdaneta, T. Urkow, C. Urlacher, K. Urmeneta, A. Ustariz, P. Uwabor, K. Uyanwune, R. Vachon, S.
Vadnai, K. Vaideswaran, M. Vajdik, V. Vajihinejad, A. Valentine, D. Valin, T. Valin, A. Valiquette, G. Valiquette, J. Valle, L. Vallee, M. Vallee, G. Vallis, A. Valmadrid, K. Van
Buskirk, C. Van de Reep, W. Van den Oever, M. van der Burgh, N. Van Der Mer we, A. Van Donkervoort, H. Van Dyck, B. van Dyke, N. Van Dyke, P. van Eerde, J. Van Es, D.
Van Genne, L. Van Genne, L. van Heerden, J. Van Nes, C. van Niekerk, F. Van Overloop, S. Van Rensburg, C. Van Rooijen, D. Van Rootselaar, C. Van Schoor, K. van Son, R.
Van Steinburg, R. van Zanden, M. Vanberg, B. Vanbeselaere, D. Vanbocquestal, J. Vancoughnett, J. Vandeligt, R. Vandemark, T. Vandemark, D. Vandenberg, G. Vander Veen,
N. Vandergriend, T. Vandermeer, V. Vandersluis, S. Vandervlis, J. Vandervoort, E. Vandette, E. Vanopian, G. van’t Wout, S. Varatharajan, C. Vare, N. Varey, S. Varey, M. Varga,
D. Varty, N. Vaschetto, A. Vasquez, C. Vasquez, M. Vasquez-Placid, G. Vassberg, J. Vasseur, R. Vassov, R. Vaudan, A. Vaughan, N. Vaughan, S. Vea, O. Vedmedenko, F.
Veenbaas, B. Veitch, S. Vekved, T. Vekved, B. Velagapudi, B. Velichka, T. Velichka, M. Velmurugan, R. Veloso, S. Venkatesh, G. Venkateshvaralu, R. Venn, D. Venning, J. Vera,
L. Verbaas, D. Verbeek, D. Verbicky, M. Verburg, A. Verge, J. Verge, M. Verge, K. Vernon, S. Veroba, J. Verot, B. Verreau, D. Versnick-Brown, K. Veysey, J. Vezina, C. Viana,
G. Vibert, J. Vicic, N. Vick, G. Viljoen, R. Villanueva, B. Villecourt, M. Villemaire, C. Villemere, N. Villeneuve, K. Vincent, R. Vincent, S. Vineham, B. Viney, R. Vinkle, A. Virk,
G. Virus, K. Virus, A. Visotto, K. Viswabharathi, R. Vivian, R. Vloet, S. Voight, B. Volkmann, J. Vollman, W. Volschenk, L. Vondermuhll, A. Vosburgh, A. Votta, A. Vredegoor, J.
Vrolson, N. Vu, N. Vucic, L. Vuong, Q. Vuong, G. Wack, E. Waddell, T. Waddell, K. Waddy, J. Wade, W. Wade, T. Wagil, D. Wagner, G. Wagner, J. Wagner, N. Wagner, M. Wahl,
D. Wakaruk, L. Wakaruk, L. Wakefield, T. Wakulchyk, A. Walchuk, D. Waldner, D. Waldo, K. Waldron, A. Walintschek, A. Walker, 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, T. Wallace, V. Wallace, M. Wallis,
V. Wallwork, T. Walraven, A. Walsh, B. Walsh, E. Walsh, L. Walsh, M. Walsh, P. Walsh, R. Walsh, S. Walsh, T. Walsh, W. Walsh, L. Walter, A. Walters, D. Walters, K. Walters,
I. Walton, K. Wambolt, N. Wan, C. Wang, H. Wang, J. Wang, L. Wang, Q. Wang, R. Wang, T. Wang, W. Wang, X. Wang, Z. Wang, B. Wangler, D. Wannas, T. Warburton, E.
Ward, K. Ward, R. Ward, B. Warehime, D. Warford, W. Warholik, C. Wark, W. Warman, F. Warraich, G. Warren, J. Warren, K. Warren, R. Warren, S. Warren, D. Warrington,
M. Warsame, B. Wartman, K. War waruk, J. Washburn, M. Washington, A. Wasikowski, P. Wassell, C. Wasylciw, J. Wasylik, W. Wasylucha, A. Watchorn, D. Waterfield, C.
Waters, D. Watson, G. Watson, J. Watson, M. Watson, S. Watson, D. Watt, G. Watt, B. Watton, B. Watts, T. Wawro, A. Wazir, B. Weatherby, D. Weatherby, M. Weatherby,
C. Weatherhead, A. Webb, G. Webb, P. Webb, B. Webber, J. Webber, O. Websdale, K. Webster, D. Weed, E. Weenink, B. Wegenast, B. Wei, Z. Wei, J. Weibrecht, J. Weigl,
J. Weik, C. Weingarten, R. Weir, R. Weisbrot, M. Weishaar, C. Weiss, J. Weller, P. Weller, B. Wellman, M. Wellman, 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, D. Werbowy, N. Wert, B. Weslake, E. Wessel, D. West, J.
West, R. West, M. Westad, D. Westbrook, K. Westland, B. Wetthuhn, T. Whalen, D. Wheating, L. Wheating, J. Wheaton, S. Wheaton, A. Wheeler, B. Wheeler, C. Wheeler,
K. Wheeler, L. Wheeler, C. Whelan, D. Whelan, K. 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, T. Whitehead, D. Whitehouse, N. Whiteknife, J. Whitelaw, A. Whiteside, C. Whitford, R. Whitman, H. Whitmore, K. Whitney, M.
Whittaker, A. Whitten, D. Whitty, A. Whitwell, L. Wichmann, R. Wicht, K. Wickenhauser, C. Wickwire, G. Wideman, M. Widing, A. Wiebe, D. Wiebe, N. Wiebe, T. Wiebe, D.
Wiege, T. Wielgus, B. Wiens, B. Wiesener, C. Wietzel, Z. Wigglesworth, S. Wight, T. Wight, D. Wijesingha, C. Wilbee, D. Wilbee, A. Wilcox, J. Wilcox, M. Wilcox, D. Wilde,
E. Wildeman, D. Wiles, R. Wiles, C. Wilk, T. Wilk, C. Wilkes, N. Wilkes, C. Wilkin, L. Wilkin, D. Wilkins, J. Wilkinson, K. Wilkinson, P. Will, D. Willard, E. Willard, A. Willcott,
B. Willcott, C. Willey, R. Willey, A. Williams, B. Williams, C. Williams, D. Williams, G. Williams, J. Williams, L. Williams, M. Williams, N. Williams, R. Williams, T. Williams,
W. Williams, C. Williamson, D. Williamson, J. Williamson, M. Williamson, J. Willick, M. Willis, S. Williscroft, J. Williston, D. Willms, S. Wills, G. Willshire, C. Willson, D.
Willson, A. Wilson, C. Wilson, D. Wilson, G. Wilson, H. Wilson, J. Wilson, L. Wilson, M. Wilson, S. Wilson, J. Wiltshire, A. Winfield, P. Winfield, B. Wingate, A. Wingert, J.
Winia, B. Winiarz, I. Winland, R. Winnicky, T. Winquist, R. Winslow, J. Winsor, L. Winsor, O. Winsor, W. Winsor, A. Winter, T. Winter, C. Winterhalt, G. Winters, R. Winters,
G. Wirachowsky, J. Wirachowsky, M. Wiseman, P. Wiseman, W. Wiseman, I. Wishart, N. Withers, C. Witiw, 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, J. Wolter, R. Wolters, A. Wong, C. Wong,
G. Wong, J. Wong, L. Wong, N. Wong, C. Woo, J. Woo, L. Woo, A. Wood, G. Wood, J. Wood, K. Wood, L. Wood, P. Wood, T. Woodburn, 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. Workun, M. Woroniuk, B. Worthington, C. Worthman, J. Wotten, B. Woytenko, C. Wright, L. Wright, R. Wright,
G. Wrinn, B. Wu, C. Wu, D. Wu, H. Wu, J. Wu, M. Wu, P. Wuorinen, B. Wurzer, A. Wutzke, K. Wutzke, G. Wyndham, D. Wyshynski, L. Wysocki, S. Wytrychowski, Y. Xiao, Y.
Xie, H. Xu, J. Xu, Q. Xu, Z. Xu, D. Yackel, A. Yaghoubi, N. Yagolnyk, K. Yakemchuk, K. Yakimowich, L. Yakiwchuk, D. Yang, L. Yang, D. Yanke, G. Yanota, K. Yao, W. Yao, H.
Yare, A. Yaremko, R. Yarmuch, J. Yaroslawsky, S. Yasin, M. Yaychuk, P. Yazdani, B. Yeboue, B. Yee, G. Yee, K. Yee, R. Yee, C. Yen, C. Yeoman, D. Yep, P. Yepes, J. Yeremiy, J.
Yeske, R. Yetman, 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, J. Yu, B. Yue, C. Yuen, D. Yuill, J. Yuill, R. Yuristy, R. Zabek,
A. Zabloski, T. Zabo, A. Zacharias, T. Zachoda, C. Zackowski, J. Zaderey, N. Zaderey, B. Zagoruy, E. Zahacy, B. Zaitsoff, S. Zakeri, D. Zambrano Suarez, R. Zamudio Baca, B.
Zandstra, D. Zanoni, C. Zaparyniuk, M. Zarichney, D. Zarowny, G. Zarowny, K. Zarowny, M. Zarowny, Z. Zarowny, S. Zawada, K. Zayac, D. Zazula, R. Zazula, S. Zbrodoff, K.
Zeer, G. Zeiler, 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, K. Zielinski, A. Zielke, D. Zilinski, C. Zimmerman, S. Zitaruk, R. Zoerb, A. Zoglauer, L. Zseder, J. Zuk, N. Zukiwski, S. Zukowski, S. Zwyer
T8
Canadian Natural 2021 Annual Report 2021 Year End Reserves
DETERMINATION OF RESERVES
For the year ended December 31, 2021, 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
A key differentiator for Canadian Natural is the strength, diversity and balance of our world class, top tier reserves. Strategically
assembled and developed over several decades, these assets have a low decline as well as low maintenance capital relative
to the size and quality of the reserves. The low maintenance capital requirements of our reserves affords the Company
significant flexibility when balancing our four pillars of capital allocation to maximize shareholder value.
■
Total proved reserves increased 6% to 12.813 billion BOE, with reserves additions and revisions of 1.158 billion BOE.
Total proved plus probable reserves increased 6% to 16.950 billion BOE, with reserves additions and revisions of
1.476 billion BOE.
•
The strength and depth of the Company's assets are evident as approximately 77% of total proved reserves are long
life low decline reserves. This results in a total proved BOE reserves life index (1) of approximately 30 years and a total
proved plus probable BOE reserves life index of approximately 40 years.
– Additionally, high value, zero decline SCO is approximately 55% of total proved reserves with a reserve life index
of approximately 45 years.
■
In 2021, Canadian Natural continued its track record of top tier finding and development costs:
•
•
FD&A (1) costs, excluding changes in Future Development Cost ("FDC"), are $4.01/BOE for total proved reserves and
$3.15/BOE for total proved plus probable reserves.
FD&A costs, including changes in FDC, are $5.88/BOE for total proved reserves and $5.49/BOE for total proved plus
probable reserves.
■
Total proved reserves additions and revisions replaced 2021 production by 257%. Total proved plus probable reserves
additions and revisions replaced 2021 production by 328%.
■ Proved developed producing reserves additions and revisions are 703 million BOE, replacing 2021 production by 156%.
The proved developed producing BOE reserves life index is approximately 21 years.
■
The net present value of future net revenues, before income tax, discounted at 10%, is approximately $86.9 billion
for proved developed producing reserves, approximately $120.3 billion for total proved reserves, and approximately
$145.9 billion for total proved plus probable reserves.
(1) Supplementary financial measure. Refer to the notes of the "2021 Year End Reserves" on page 8.
Canadian Natural 2021 Annual Report
6
Summary of Company Gross Reserves
as of December 31, 2021
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
135
50
115
300
125
424
83
11
74
169
80
249
215
—
56
270
118
388
587
32
2,012
2,631
1,706
4,337
6,960
—
37
6,998
537
7,535
4,494
262
7,413
12,168
8,080
20,249
130
5
283
418
224
643
8,859
142
3,812
12,813
4,137
16,950
Reconciliation of Company Gross Reserves
as of December 31, 2021
Forecast Prices and Costs
TOTAL PROVED
Total Company
December 31, 2020
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2021
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)
315
—
1
3
—
—
—
14
(5)
(28)
300
177
—
7
4
—
—
—
13
(9)
(23)
169
265
—
—
—
1
—
—
22
2
(20)
270
2,483
—
119
—
19
—
—
—
105
(95)
2,631
6,962
—
—
—
—
—
—
—
199
(164)
6,998
9,465
—
598
170
3
1,715
(1)
309
528
(619)
12,168
326
—
15
13
—
59
—
10
13
(18)
418
12,106
—
243
47
21
345
—
110
392
(451)
12,813
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, 2020
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2021
463
—
2
4
—
—
—
18
(34)
(28)
424
260
—
10
6
—
—
—
18
(22)
(23)
249
395
—
—
—
2
—
—
7
5
(20)
388
4,157
—
158
—
23
—
—
2
91
(95)
4,337
15,922
7,496
—
—
— 1,004
687
—
—
4
— 2,979
(1)
—
368
—
(94)
202
(619)
(164)
7,535
20,249
500
—
30
21
—
100
—
11
(1)
(18)
643
15,925
—
368
146
26
596
—
116
224
(451)
16,950
7
Canadian Natural 2021 Annual Report
NOTES TO RESERVES:
1.
2.
3.
Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.
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.
Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserves estimates are the
3-consultant-average of price forecasts developed by Sproule Associates Limited, GLJ Ltd. and McDaniel & Associates
Consultants Ltd., dated December 31, 2021:
Crude Oil and NGLs
WTI
WCS
Canadian Light Sweet
Cromer LSB
Edmonton C5+
Brent
Natural Gas
AECO
US$/bbl
C$/bbl
C$/bbl
C$/bbl
C$/bbl
US$/bbl
C$/MMBtu
BC Westcoast Station 2
C$/MMBtu
Henry Hub
US$/MMBtu
2022
2023
2024
2025
2026
72.83
74.42
86.82
87.30
91.85
75.33
3.56
3.48
3.85
68.78
69.17
80.73
82.30
85.53
71.46
3.21
3.14
3.44
66.76
66.54
78.01
79.69
82.98
69.62
3.05
2.98
3.17
68.09
67.87
79.57
81.29
84.63
71.01
3.11
3.03
3.24
69.45
69.23
81.16
82.92
86.33
72.44
3.17
3.10
3.30
All prices increase at a rate of 2% per year after 2026.
4.
5.
6.
7.
8.
9.
A foreign exchange rate of 0.7967 US$/C$ for 2022 and 0.7967 US$/C$ after 2022 was used in the year end
2021 evaluation.
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.
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.
Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive
of production.
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.
Reserves Life Index is based on the amount for the relevant reserves category divided by the 2022 proved developed
producing production forecast prepared by the Independent Qualified Reserves Evaluators.
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 2021 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 2021 and net changes in FDC from December 31, 2020 to December 31, 2021 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, 2021 and forecast estimates of ADR costs attributable to
future development activity.
Canadian Natural 2021 Annual Report
8
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
Non-GAAP and Other Financial Measures
Outlook
Other
10
11
13
14
18
20
21
23
27
29
30
33
35
37
38
39
40
44
46
47
53
53
9
Canadian Natural 2021 Annual Report
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
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
Financial Accounting Standards Board
Floating Production, Storage and
Offloading Vessel
greenhouse gas
gigajoules
gigajoules per day
Horizon
Horizon Oil Sands
IASB
International Accounting Standards Board
IBOR
IFRS
LIBOR
Mbbl
Mbbl/d
MBOE
Interbank Offered Rate
International Financial Reporting Standards
London Interbank Offered Rate
thousand barrels
thousand barrels per day
thousand barrels of oil equivalent
MBOE/d
thousand barrels of oil equivalent per day
Mcf
Mcfe
Mcf/d
MMbbl
MMBOE
MMBtu
MMcf
MMcf/d
NGLs
NWRP
NYMEX
NYSE
OPEC+
PRT
SAGD
SCO
SEC
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
New York Mercantile Exchange
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
SOFR
Secured Overnight Financing Rate
Tcf
TSX
UK
US
trillion cubic feet
Toronto Stock Exchange
United Kingdom
United States
US GAAP
generally accepted accounting principles
in the United States
US$
WCS
WCS Heavy
Differential
WTI
United States dollars
Western Canadian Select
WCS Heavy Differential from WTI
West Texas Intermediate reference
location at Cushing, Oklahoma
Canadian Natural 2021 Annual Report
10
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, the Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby Thermal Oil Sands Project,
the Jackfish Thermal Oil Sands Project and 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 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 2022 targets
provided with respect to budgeted capital expenditures, and the timing and impact of the Oil Sands Pathways to Net Zero
("Pathways") initiative, government support for Pathways and the ability to achieve net zero emissions from oil production, 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 earlier 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 any 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
11
Canadian Natural 2021 Annual Report
long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of
the Company's provision for taxes; and other circumstances affecting revenues and expenses.
The Company's operations have been, and in the future may be, affected by political developments and by national, federal,
provincial, 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 AND OTHER FINANCIAL MEASURES
This MD&A includes references to non-GAAP measures, which include non-GAAP and other financial measures as defined
in National Instrument 52-112 – Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). Non-GAAP measures are
used by the Company to evaluate its financial performance, financial position or cash flow. Descriptions of the Company's
non-GAAP and other financial measures included in this MD&A, and reconciliations to the most directly comparable GAAP
measure, as applicable, are provided in the “Non-GAAP and Other Financial Measures” 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, 2021. It should also be read in conjunction with the Company's MD&A for the three months and year ended
December 31, 2021. 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 2021 financial results compared to 2020 and 2019,
unless otherwise indicated. In addition, this MD&A details the Company's targeted capital program for 2022. Additional
information relating to the Company, including its quarterly MD&A for the three months and year ended December 31, 2021,
its Annual Information Form for the year ended December 31, 2021, and its audited consolidated financial statements for
the year ended December 31, 2021, 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 2, 2022.
Canadian Natural 2021 Annual Report
12
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.
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.
(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.
13
Canadian Natural 2021 Annual Report
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 (3)
– diluted (3)
Cash flows from operating activities
Adjusted funds flow (2)
Per common share
– basic (3)
– diluted (3)
Dividends declared per common share (4)
Total assets
Total long-term liabilities
Cash flows used in investing activities
Net capital expenditures (2)
Average realized price
Crude oil and NGLs - Exploration and Production ($/bbl) (3)
Natural gas - Exploration and Production ($/Mcf) (5)
SCO - Oil Sands Mining and Upgrading ($/bbl) (3)
Daily production, before royalties (BOE/d)
Crude oil and NGLs (bbl/d)
Natural gas (MMcf/d) (6)
2021
32,854
29,256
2,716
7,664
6.49
6.46
7,420
6.28
6.25
14,478
13,733
11.63
11.57
2.00
76,665
32,298
3,703
4,908
63.71
4.07
77.95
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2020
17,491
15,579
1,478
(435)
(0.37)
(0.37)
(756)
(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
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2019
24,394
22,950
1,419
5,416
4.55
4.54
3,795
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
1,234,906
1,164,136
1,098,957
952,404
1,695
917,958
1,477
850,393
1,491
(1) Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements.
(2) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(4) On November 3, 2021, the Board of Directors approved a 25% increase in the quarterly dividend to $0.5875 per common share,
from $0.47 per common share. On March 3, 2021, the Board of Directors approved an 11% increase in the quarterly dividend to $0.47 per common share,
from $0.425 per common share. On March 4, 2020, the Board of Directors approved a 13% increase in the quarterly dividend to $0.425 per common share,
from $0.375 per common share. On March 6, 2019, the Board of Directors approved a 12% increase in the quarterly dividend to $0.375 per common share,
from $0.335 per common share. The dividend policy undergoes periodic review by the Board of Directors and is subject to change.
(5) Calculated as natural gas sales divided by sales volumes.
(6) Natural gas production volumes approximate sales volumes.
Canadian Natural 2021 Annual Report
14
CONSOLIDATED NET EARNINGS (LOSS) AND ADJUSTED NET EARNINGS (LOSS)
For 2021, the Company reported net earnings of $7,664 million compared with a net loss of $435 million for 2020 (2019 – net
earnings of $5,416 million). Net earnings for 2021 included non-operating items (after-tax) of $244 million compared with
$321 million for 2020 (2019 – $1,621 million) related to the effects of share-based compensation, risk management activities,
fluctuations in foreign exchange rates including the impact of a realized foreign exchange loss on repayment of US dollar debt
securities, the realized foreign exchange gain on the settlement of the cross currency swaps, the gain on acquisitions, the
(gain) loss from investments, government grant income under the provincial well-site rehabilitation programs, and a provision
relating to the Keystone XL pipeline project. Excluding these items, adjusted net earnings from operations for 2021 were
$7,420 million compared with an adjusted net loss from operations of $756 million for 2020 (2019 – adjusted net earnings
from operations of $3,795 million).
The net earnings and the adjusted net earnings from operations for 2021 compared with a net loss and adjusted net loss from
operations for 2020 primarily reflected:
■
■
■
■
■
higher realized SCO sales price (1) in the Oil Sands Mining and Upgrading segment;
higher crude oil and NGLs netbacks (1) and natural gas netbacks (1) in the Exploration and Production segments;
higher natural gas sales volumes in the North America segment;
higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; and
lower depletion, depreciation and amortization expense.
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
acquisitions, income from NWRP, and the (gain) loss from investments, also contributed to the movements in net earnings
(loss) for 2021 from 2020. 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 2021 were $14,478 million compared with $4,714 million for 2020 (2019 – $8,829
million). The increase in cash flows from operating activities for 2021 from 2020 were primarily due to the factors previously
noted related to the fluctuations in net earnings (loss) from operations, as well as due to the impact of changes in non-cash
working capital, and excluding the impact of changes in depletion, depreciation and amortization expense.
Adjusted funds flow for 2021 was $13,733 million ($11.63 per common share) compared with $5,200 million for 2020 ($4.40
per common share) (2019 – $10,267 million; $8.62 per common share). The increase in adjusted funds flow for 2021 from
2020 was primarily due to the factors noted above related to the fluctuations in cash flows from operating activities excluding
the impact of the net change in non-cash working capital, abandonment expenditures excluding the impact of government
grant income under the provincial well-site rehabilitation programs, 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
Crude oil and NGLs production before royalties for 2021 increased 4% to average 952,404 bbl/d from 917,958 bbl/d in 2020
(2019 – 850,393 bbl/d). Natural gas production before royalties for 2021 increased 15% to average 1,695 MMcf/d from 1,477
MMcf/d in 2020 (2019 – 1,491 MMcf/d). Total production before royalties for 2021 of 1,234,906 BOE/d increased 6% from
1,164,136 BOE/d in 2020 (2019 – 1,098,957 BOE/d). Crude oil and NGLs and natural gas production volumes are discussed in
detail in the "Daily Production" section of this MD&A.
(1) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
15
Canadian Natural 2021 Annual Report
PRODUCT PRICES
In the Company’s Exploration and Production segments, the 2021 realized crude oil and NGLs prices (1) increased 100%
to average $63.71 per bbl from $31.90 per bbl in 2020 (2019 – $55.08 per bbl), and the 2021 realized natural gas
price (1) increased 70% to average $4.07 per Mcf from $2.40 per Mcf in 2020 (2019 – $2.34 per Mcf). In the Oil Sands
Mining and Upgrading segment, the Company’s 2021 realized SCO sales price increased 77% to average $77.95 per bbl from
$43.98 per bbl in 2020 (2019 – $70.18 per bbl). Crude oil and NGLs and natural gas prices are discussed in detail in the
"Business Environment", "Realized Product Prices - 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 2021 crude oil and NGLs production expense (2) increased 18%
to average $14.71 per bbl from $12.42 per bbl in 2020 (2019 – $13.81 per bbl), and the natural gas production expense (2)
averaged $1.18 per Mcf in 2021 and 2020 (2019 – $1.22 per Mcf). In the Oil Sands Mining and Upgrading segment, the
Company's 2021 production cost (2) averaged $20.91 per bbl and was comparable with $20.46 per bbl in 2020 (2019 –
$22.56 per bbl). Crude oil and NGLs and natural gas production expense is discussed in detail in the "Exploration and
Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.
SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company’s quarterly financial results for the eight most recently completed quarters:
($ millions, except per common share amounts)
2021
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)
2020
Product sales (1)
Crude oil and NGLs
Natural gas
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
Total
32,854
29,256
2,716
7,664
6.49
6.46
Total
17,491
15,579
1,478
(435)
(0.37)
(0.37)
$
$
$
$
$
$
$
$
$
$
$
$
Dec 31
10,190
8,979
958
2,534
2.16
2.14
Dec 31
5,219
4,592
496
749
0.63
0.63
Sep 30
Jun 30
Mar 31
$
$
$
$
$
$
$
$
$
$
$
$
8,521
7,607
694
2,202
1.87
1.86
Sep 30
4,676
4,202
338
408
0.35
0.35
$
$
$
$
$
$
$
$
$
$
$
$
7,124
6,382
509
1,551
1.31
1.30
Jun 30
2,944
2,462
307
(310)
(0.26)
(0.26)
$
$
$
$
$
$
$
$
$
$
$
$
7,019
6,288
555
1,377
1.16
1.16
Mar 31
4,652
4,323
337
(1,282)
(1.08)
(1.08)
$
$
$
$
$
$
$
$
$
$
$
$
(1) Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements.
(1) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2) Calculated as respective production expense divided by respective sales volumes.
Canadian Natural 2021 Annual Report
16
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 in North America; 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.
■ Crude oil and NGLs sales volumes – Fluctuations in production from the Kirby and Jackfish Thermal Oil Sands Projects,
fluctuations in production due to the cyclic nature of the Primrose thermal oil projects, fluctuations in the Company’s
drilling program in North America and the International segments, 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 high return projects,
drilling results, natural decline rates, the temporary shut-down and subsequent reinstatement of the Pine River Gas Plant,
and the impact and timing of acquisitions.
■ Production expense – Fluctuations primarily due to the impact of the demand and cost for services, fluctuations in
product mix and production volumes, the impact of seasonality, 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 cancellation
of 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 acquisitions, (gain) loss from investments and income from NWRP – Fluctuations due to the recognition of
gains on acquisitions, (gain) loss from the investments in PrairieSky Royalty Ltd. ("PrairieSky") and Inter Pipeline Ltd. ("IPL")
shares, and the distribution from NWRP in 2021.
■
Income taxes – Fluctuations due to statutory tax rate and other legislative changes substantively enacted in the
various periods.
17
Canadian Natural 2021 Annual Report
Business Environment
Global benchmark crude oil prices increased significantly throughout 2021, partially in response to the OPEC+ decision to
adhere to previously agreed upon production cut agreements. Additionally, global demand for crude oil increased due to
improved economic conditions, as the effects of COVID-19 became less impactful to the global economy. Improved economic
conditions continue to positively impact the outlook for crude oil prices, although market conditions remain uncertain.
During 2021, the Company continued to utilize federal and provincial government programs to support employment during the
COVID-19 pandemic, including in Canada, the provincial well-site rehabilitation program.
LIQUIDITY
As at December 31, 2021, the Company had undrawn bank credit facilities of $6,098 million. Including cash and cash
equivalents and short-term investments, the Company had approximately $7,151 million in liquidity (1). 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 continue to be a focus for the Company. On January 11, 2022, the Company
announced its 2022 base capital budget (2) targeted at approximately $3,645 million. The budget also includes incremental
strategic growth capital of approximately $700 million that targets to add future production and capacity in the Company's
long life low decline thermal in situ and Oil Sands Mining and Upgrading assets. Production for 2022 is targeted between
1,270,000 BOE/d and 1,320,000 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 2022 capital budget and production targets constitute forward-looking statements. Refer to the "Advisory" section of this
MD&A for further details on forward-looking statements.
On December 9, 2020, the Company announced its 2021 capital budget targeted at approximately $3,205 million, and on
August 5, 2021, the 2021 capital budget was increased to approximately $3,480 million, excluding acquisitions. Net capital
expenditures for 2021 were $4,908 million, including the impact of acquisitions. Refer to the “Net Capital Expenditures”
section of this MD&A for further details on the 2021 net capital expenditures.
During 2021, the Company completed the acquisition of all the issued and outstanding common shares of Storm Resources
Limited ("Storm") for total cash consideration of approximately $771 million. At closing, the acquisition also included the
assumption of long-term debt of approximately $183 million. Storm is involved in the exploration for and development of
natural gas and natural gas liquids in the Montney region of British Columbia.
During 2021, the Company also completed a number of other opportunistic acquisitions. Two acquisitions consisted of natural
gas assets located in the Montney region of British Columbia, with aggregate production of approximately 11,100 BOE/d. A
third acquisition consisted of a net carried interest on an existing oil sands lease held by the Company, from which all Horizon
production volumes are derived. Total cash consideration paid for these acquisitions was approximately $450 million.
During 2021, in accordance with a third-party offer to purchase, the Company elected to take total cash proceeds of $128
million, or $20.00 per common share, in exchange for its 6.4 million common share investment in IPL.
RISKS AND UNCERTAINTIES
COVID-19, including variants of concern, continues to have the potential to further disrupt the Company’s operations, projects
and financial condition through the disruption of the local or global supply chain and transportation services, or the loss of
manpower resulting from quarantines that affect the Company’s labour pools in their local communities, workforce camps
or operating sites or that are instituted by local health authorities as a precautionary measure, any of which may require the
Company to temporarily reduce or shutdown its operations depending on their extent and severity.
(1) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2) Forward looking non-GAAP Financial Measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net
acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on Net Capital Expenditures.
Canadian Natural 2021 Annual Report
18
BENCHMARK COMMODITY PRICES
(Yearly average)
WTI benchmark price (US$/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$)
2021
67.96
70.49
13.04
66.36
68.24
(0.28)
3.85
3.38
0.7979
0.7901
$
$
$
$
$
$
$
$
$
$
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
$
$
$
$
$
$
$
$
$
$
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 directly impacted by 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.
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$67.96
per bbl for 2021, an increase of 72% from US$39.40 per bbl for 2020 (2019 – US$57.04 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$70.49 per bbl for
2021, an increase of 67% from US$42.27 per bbl for 2020 (2019 – US$64.04 per bbl).
The increase in WTI and Brent pricing for 2021 from 2020 primarily reflected the OPEC+ decision to adhere to the previously
agreed upon production cut agreements. Additionally, global demand for crude oil increased due to improved economic
conditions as a result of the lessening of earlier COVID-19 restrictions.
The WCS Heavy Differential averaged US$13.04 per bbl for 2021, a slight widening of 4% from US$12.57 per bbl for 2020
(2019 – US$12.79 per bbl). The widening of the WCS Heavy Differential for 2021 from 2020 primarily reflected the increase in
WTI benchmark pricing and the widening of the US Gulf Coast heavy oil pricing.
The SCO price averaged US$66.36 per bbl for 2021, an increase of 83% from US$36.26 per bbl for 2020 (2019 – US$56.35
per bbl). The increase in SCO pricing for 2021 from 2020 primarily reflected the increase in WTI benchmark pricing.
NYMEX natural gas prices averaged US$3.85 per MMBtu for 2021, an increase of 85% from US$2.08 per MMBtu for 2020
(2019 – US$2.63 per MMBtu). The increase in NYMEX natural gas prices for 2021 from 2020 primarily reflected increased
North American demand in 2021, following the impact of COVID-19 in 2020, as well as lower storage levels.
AECO natural gas prices averaged $3.38 per GJ for 2021, an increase of 59% from $2.12 per GJ for 2020 (2019 – $1.54
per GJ). The increase in AECO natural gas prices for 2021 from 2020 primarily reflected lower storage levels and increased
NYMEX benchmark pricing.
19
Canadian Natural 2021 Annual Report
Analysis of Changes in Product Sales
($ millions)
North America
Changes due to
Changes due to
2019
Volumes
Prices
Other
2020 Volumes
Prices Other
2021
Crude oil and NGLs $ 9,679
$ 1,582
$ (3,781)
$ — $ 7,480
$
82
$ 6,916
$ — $ 14,478
1,150
6
8
—
84
—
10,835
1,590
(3,697)
Natural gas
Other (1)
North Sea
Crude oil and NGLs
Natural gas
Other (1)
Offshore Africa
Crude oil and NGLs
Natural gas
Other (1)
860
57
5
922
632
67
8
707
Oil Sands Mining
and Upgrading
Crude oil and NGLs
11,340
Other (1)
6
11,346
Midstream and
Refining
Midstream
activities
Refined product
sales and other (1)
Intersegment
eliminations
and other (2)
Product sales
Other (1)
88
—
88
496
—
496
—
35
35
—
—
(2)
(2)
—
—
10
10
1,242
41
8,763
417
12
3
432
318
42
18
378
(308)
(16)
—
(324)
(198)
2
—
(196)
(4,421)
—
(4,421)
—
133
133
7,389
139
7,528
—
—
—
—
—
—
(5)
202
197
(422)
31
(391)
83
202
285
74
31
105
(135)
(29)
—
(164)
(116)
(27)
—
(143)
470
—
470
—
—
—
—
—
—
193
—
275
(72)
(8)
—
(80)
(68)
(9)
—
(77)
560
—
560
—
—
—
—
—
—
1,049
—
7,965
262
1
—
263
170
(2)
—
168
6,084
—
6,084
—
—
—
—
—
—
—
78
78
—
—
(4)
(4)
—
—
(11)
(11)
—
(66)
(66)
(5)
479
474
(238)
(28)
(266)
2,484
119
17,081
607
5
(1)
611
420
31
7
458
14,033
73
14,106
78
681
759
(164)
3
(161)
Total
$ 24,394
$ 1,753
$ (8,638)
$ (18)
$ 17,491
$
678
$ 14,480
$ 205
$ 32,854
(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 increased 88% to $32,854 million for 2021 from $17,491 million for 2020 (2019 – $24,394 million). The increase
in product sales was primarily a result of increased WTI benchmark pricing due to increased demand for refined products as
a result of improved economic conditions. 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 2021, 3% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America
(2020 – 5%; 2019 – 7%). North Sea accounted for 2% of crude oil and NGLs and natural gas product sales for 2021 (2020 –
3%; 2019 – 4%), and Offshore Africa accounted for 1% of crude oil and NGLs and natural gas product sales for 2021 (2020
– 2%; 2019 – 3%).
Canadian Natural 2021 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) (2)
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) (3)
(excluding Midstream and Refining revenue)
Crude oil and NGLs
Natural gas
(1) SCO production before royalties excludes SCO consumed internally as diesel.
(2) Natural gas production volumes approximate sales volumes.
(3) 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)
2021
2020
2019
472,621
448,133
17,633
14,017
952,404
460,443
417,351
23,142
17,022
917,958
405,970
395,133
27,919
21,371
850,393
1,680
1,450
1,443
3
12
12
15
24
24
1,695
1,477
1,491
1,234,906
1,164,136
1,098,957
10%
5%
5%
21%
36%
23%
91%
9%
11%
5%
6%
21%
36%
21%
91%
9%
13%
5%
8%
15%
36%
23%
94%
6%
2021
2020
2019
404,637
410,385
17,588
13,354
420,906
413,363
23,086
16,306
356,794
375,048
27,866
20,078
845,964
873,661
779,786
1,593
1,406
1,400
3
11
12
14
24
22
1,607
1,432
1,446
1,113,878
1,112,364
1,020,749
21
Canadian Natural 2021 Annual Report
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 2021 production before royalties averaged 1,234,906 BOE/d, an increase of 6% from 1,164,136 BOE/d in 2020 (2019 –
1,098,957 BOE/d).
Record crude oil and NGLs production before royalties for 2021 averaged 952,404 bbl/d, an increase of 4% from 917,958
bbl/d for 2020 (2019 – 850,393 bbl/d). The increase in crude oil and NGLs production for 2021 from 2020 primarily reflected
strong operational performance in the Oil Sands Mining and Upgrading segment and increased thermal oil production. Crude
oil and NGLs production in North America Exploration and Production and Oil Sands Mining and Upgrading segments for
the comparable periods of 2020 reflected the impact of the Company's curtailment optimization strategy during mandatory
Government of Alberta curtailment.
Annual crude oil and NGLs production for 2021 was within the Company's previously issued target of 940,000 bbl/d and
980,000 bbl/s. The Company targets production levels in 2022 to average between 940,000 bbl/d and 982,000 bbl/d of
liquids production, including crude oil, SCO and NGLs. Production targets constitute forward-looking statements. Refer to the
"Advisory" section of this MD&A for further details on forward-looking statements.
Natural gas production before royalties accounted for 23% of the Company's total production in 2021 on a BOE basis. Natural
gas production for 2021 of 1,695 MMcf/d increased 15% from 1,477 MMcf/d for 2020 (2019 – 1,491 MMcf/d). The increase in
natural gas production for 2021 from 2020 primarily reflected strong drilling results and production volumes from acquisitions,
partially offset by natural field declines.
Annual natural gas production for 2021 was within the Company's previously issued target of 1,680 MMcf/d and 1,720
MMcf/d. The Company targets production levels in 2022 to average between 1,980 MMcf/d and 2,030 MMcf/d of natural
gas production. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for
further details on forward-looking statements.
North America – Exploration and Production
North America crude oil and NGLs production before royalties for 2021 averaged 472,621 bbl/d, an increase of 3% from
460,443 bbl/d for 2020 (2019 – 405,970 bbl/d). The increase in crude oil and NGLs production for 2021 from 2020 primarily
reflected increased thermal oil production and strong drilling results, partially offset by natural field declines.
Thermal oil production before royalties for 2021 averaged 259,284 bbl/d, an increase of 4% from 248,971 bbl/d for 2020
(2019 – 167,942 bbl/d). The increase in thermal oil production for 2021 from 2020 primarily reflected high utilization at Jackfish.
Pelican Lake heavy crude oil production before royalties averaged 54,390 bbl/d for 2021, a decrease of 4% from 56,535 bbl/d
for 2020 (2019 – 58,855 bbl/d), demonstrating Pelican Lake's long life low decline production.
Natural gas production before royalties for 2021 averaged 1,680 MMcf/d, an increase of 16% from 1,450 MMcf/d for 2020
(2019 – 1,443 MMcf/d). The increase in natural gas production for 2021 from 2020 primarily reflected strong drilling results and
production volumes from acquisitions, partially offset by natural field declines.
North America – Oil Sands Mining and Upgrading
Record SCO production before royalties for 2021 of 448,133 bbl/d increased 7% from 417,351 bbl/d for 2020 (2019 – 395,133
bbl/d). The increase in SCO production for 2021 from 2020 primarily reflected strong operational performance at AOSP
following the completion of expansion activities at Scotford in 2020.
North Sea
North Sea crude oil production before royalties for 2021 of 17,633 bbl/d decreased 24% from 23,142 bbl/d for 2020 (2019 –
27,919 bbl/d). The decrease in production for 2021 from 2020 primarily reflected natural field declines and planned maintenance
activities.
Offshore Africa
Offshore Africa crude oil production before royalties for 2021 decreased 18% to 14,017 bbl/d from 17,022 bbl/d for 2020
(2019 – 21,371 bbl/d). The decrease in production for 2021 from 2020 primarily reflected maintenance activities and natural
field declines.
Canadian Natural 2021 Annual Report
22
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
Exploration and Production
OPERATING HIGHLIGHTS
Crude oil and NGLs ($/bbl) (1)
Realized price (2)
Transportation (2)
Realized price, net of transportation (2)
Royalties (3)
Production expense (4)
Netback (2)
Natural gas ($/Mcf) (1)
Realized price (5)
Transportation (6)
Realized price, net of transportation
Royalties (3)
Production expense (4)
Netback (2)
Barrels of oil equivalent ($/BOE) (1)
Realized price (2)
Transportation (2)
Realized price, net of transportation (2)
Royalties (3)
Production expense (4)
Netback (2)
2021
—
727,439
727,439
2020
450,889
521,244
972,133
2019
344,726
519,504
864,230
2021
2020
2019
$
63.71
$
31.90
$
3.86
59.85
8.59
14.71
3.85
28.05
2.59
12.42
36.55
$
13.04
$
4.07
0.45
3.62
0.22
1.18
2.22
$
$
2.40
0.43
1.97
0.08
1.18
0.71
$
$
55.08
3.48
51.60
6.08
13.81
31.71
2.34
0.42
1.92
0.08
1.22
0.62
49.67
$
26.15
$
40.50
3.44
46.23
5.98
11.98
3.44
22.71
1.89
10.67
$
28.27
$
10.15
$
3.14
37.36
4.09
11.49
21.78
$
$
$
$
(1) For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales
volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3) Calculated as royalties divided by respective sales volumes.
(4) Calculated as production expense divided by respective sales volumes.
(5) Calculated as natural gas sales divided by natural gas sales volumes.
(6) Calculated as natural gas transportation expense divided by natural gas sales volumes.
23
Canadian Natural 2021 Annual Report
REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION
Crude oil and NGLs ($/bbl) (1)
North America (2)
North Sea (3)
Offshore Africa (3)
Average (2)
Natural gas ($/Mcf) (1) (3)
North America
North Sea
Offshore Africa
Average
Average ($/BOE) (1) (2)
2021
2020
2019
$
$
$
$
$
$
$
$
$
62.10
87.98
85.71
63.71
4.05
2.94
7.17
4.07
49.67
$
$
$
$
$
$
$
$
$
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
(1) For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales
volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3) Calculated as crude oil and NGLs sales and natural gas sales divided by respective sales volumes.
North America
North America realized crude oil and NGLs prices increased by $31.79 per bbl to average $62.10 per bbl for 2021 from $30.31
per bbl for 2020 (2019 – $51.43 per bbl), primarily due to higher WTI benchmark pricing.
The Company continues to focus on its crude oil blending 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 2021, the Company contributed approximately 152,000 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 that will provide waterborne access to international markets. The expansion is now under construction and
Trans Mountain Corporation targets a completion date of late 2023.
North America realized natural gas prices increased 73% to average $4.05 per Mcf for 2021 from $2.34 per Mcf for 2020
(2019 – $2.18 per Mcf). The increase in realized natural gas prices for 2021 from 2020 primarily reflected lower storage levels
and increased benchmark pricing.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
(Yearly average)
Wellhead Price (1)
Light and medium crude oil and NGLs ($/bbl)
Pelican Lake heavy crude oil ($/bbl)
Primary heavy crude oil ($/bbl)
Bitumen (thermal oil) ($/bbl)
Natural gas ($/Mcf)
2021
2020
2019
$
$
$
$
$
61.29
68.05
65.88
60.20
4.05
$
$
$
$
$
33.42
33.57
31.81
28.11
2.34
$
$
$
$
$
49.54
57.82
55.38
48.27
2.18
(1) Amounts expressed on a per unit basis are based on sales volumes of the respective product type.
North Sea
North Sea realized crude oil and NGLs prices increased 76% to average $87.98 per bbl for 2021 from $50.09 per bbl for 2020
(2019 – $86.76 per bbl). Realized crude oil and NGLs 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 increase in realized crude oil and NGLs prices for 2021 from 2020 reflected prevailing
Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.
Canadian Natural 2021 Annual Report
24
Offshore Africa
Offshore Africa realized crude oil and NGLs prices increased 68% to average $85.71 per bbl for 2021 from $50.95 per bbl for
2020 (2019 – $83.68 per bbl). Realized crude oil and NGLs prices per barrel in any particular year are dependent on the terms
of the various sales contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign
exchange rates at the time of lifting. The increase in realized crude oil and NGLs prices in 2021 reflected prevailing Brent
benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.
ROYALTIES – EXPLORATION AND PRODUCTION
Crude oil and NGLs ($/bbl) (1)
North America
North Sea
Offshore Africa
Average
Natural gas ($/Mcf) (1)
North America
Offshore Africa
Average
Average ($/BOE) (1)
2021
2020
2019
$
$
$
$
$
$
$
$
9.06
0.19
3.94
8.59
0.22
0.33
0.22
5.98
$
$
$
$
$
$
$
$
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
(1) Calculated as royalties divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial
Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
Government royalties on a significant portion of North America crude oil and NGLs production fall under the oil sands
royalty regime and are calculated on a project by project basis as a percentage of gross revenue less operating, capital and
abandonment costs incurred.
North America crude oil and NGLs and natural gas royalties for 2021 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 (1) averaged approximately 15% of product sales for 2021 compared with 9% of product sales
for 2020 (2019 – 13%). The increase in royalty rates for 2021 from 2020 was primarily due to higher benchmark prices together
with fluctuations in the WCS Heavy Differential.
Natural gas royalty rates averaged approximately 5% of product sales for 2021, compared with 3% of product sales for 2020
(2019 – 3%). The increase in royalty rates for 2021 from 2020 was primarily due to higher benchmark prices.
Offshore Africa
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 5% for 2021 compared with 4% of product sales for
2020 (2019 – 6%). Royalty rates as a percentage of product sales reflected the timing of liftings and the status of payout in
the various fields.
(1) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
25
Canadian Natural 2021 Annual Report
PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION
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)
2021
2020
2019
$
$
$
$
$
$
$
$
$
13.12
54.13
14.73
14.71
1.15
7.31
4.41
1.18
11.98
$
$
$
$
$
$
$
$
$
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
(1) Calculated as production expense divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other
Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
North America crude oil and NGLs production expense for 2021 averaged $13.12 per bbl, an increase of 17% from $11.21
per bbl for 2020 (2019 – $12.41 per bbl). The increase in crude oil and NGLs production expense per bbl for 2021 from 2020
reflected increased energy costs.
North America natural gas production expense for 2021 averaged $1.15 per Mcf, comparable with $1.14 per Mcf for 2020
(2019 – $1.16 per Mcf). Natural gas production expense per Mcf for 2021 primarily reflected higher production volumes and
the Company's strong focus on cost control.
North Sea
North Sea crude oil production expense for 2021 averaged $54.13 per bbl, an increase of 48% from $36.51 per bbl for 2020
(2019 – $36.39 per bbl). The increase in crude oil production expense per bbl for 2021 from 2020 primarily reflected lower
volumes on a relatively fixed cost base, as well as higher natural gas and CO2 costs. North Sea production expense also
reflected fluctuations in the Canadian dollar.
Offshore Africa
Offshore Africa crude oil production expense for 2021 averaged $14.73 per bbl, an increase of 11% from $13.29 per bbl for
2020 (2019 – $11.21 per bbl). The increase in crude oil production expense per bbl for 2021 from 2020 primarily reflected
timing of liftings from various fields that have different cost structures, together with lower volumes, on a relatively fixed cost
base. Offshore Africa production expense also reflected fluctuations in the Canadian dollar.
DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Depletion, depreciation and amortization
$/BOE (1)
2021
2020
$
3,569
$
3,780
$
160
142
3,871
13.49
$
$
277
190
4,247
15.45
$
$
$
$
2019
3,326
308
242
3,876
15.22
(1) Calculated as depletion, depreciation and amortization expense divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial
Measures" section of this MD&A.
Depletion, depreciation and amortization expense for 2021 of $13.49 per BOE decreased 13% from $15.45 per BOE for 2020
(2019 – $15.22 per BOE). The decrease in depletion, depreciation and amortization expense per BOE for 2021 from 2020
primarily reflected lower depletion rates in the North America Exploration and Production segment and lower volumes in the
North Sea, which has higher depletion rates.
Depletion, depreciation and amortization expense on an absolute and per BOE basis also reflects the impact of the timing of
liftings from each field in the North Sea and Offshore Africa.
Canadian Natural 2021 Annual Report
26
ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Asset retirement obligation accretion
$/BOE (1)
2021
2020
$
101
$
21
6
128
0.44
$
$
$
$
97
30
6
133
0.48
$
$
$
2019
95
28
6
129
0.51
(1) Calculated as asset retirement obligation accretion divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures"
section of this MD&A.
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 2021 of $0.44 per BOE decreased 8% from $0.48 per BOE for 2020 (2019 –
$0.51 per BOE). Fluctuations in asset retirement obligation accretion expense on a per BOE basis primarily reflect fluctuating
sales volumes.
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. Record SCO production in 2021 averaged 448,133 bbl/d, primarily reflecting strong
operational performance.
The Company incurred production costs, excluding natural gas costs, of $3,176 million ($19.45 per bbl) for 2021, a 7% increase
(comparable on a per bbl basis) from $2,968 million ($19.50 per bbl) for 2020, reflecting higher energy costs, offset by record
production volumes, together with the Company's strong focus on cost control.
REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING
($/bbl)
Realized SCO sales price (1)
Bitumen value for royalty purposes (2)
Bitumen royalties (3)
Transportation (1)
2021
77.95
58.39
6.62
1.21
$
$
$
$
2020
43.98
25.82
0.51
1.23
$
$
$
$
2019
70.18
50.79
3.31
1.29
$
$
$
$
(1) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2) Calculated as the quarterly average of the bitumen methodology price.
(3) Calculated as royalties divided by sales volumes. For SCO sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
The realized SCO sales price averaged $77.95 per bbl for 2021, an increase of 77% from $43.98 per bbl for 2020 (2019 –
$70.18 per bbl). The increase in the realized SCO sales price for 2021 compared to 2020 primarily reflected the increase in
WTI benchmark pricing.
The increase in bitumen royalties per bbl for 2021 from 2020 primarily reflected the impact of higher prevailing bitumen pricing
and AOSP reaching full payout.
Transportation expense averaged $1.21 per bbl for 2021, comparable with $1.23 per bbl for 2020 (2019 – $1.29 per bbl).
27
Canadian Natural 2021 Annual Report
PRODUCTION COSTS – OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 22 to the
Company’s audited consolidated financial statements.
($ millions)
Production costs, excluding natural gas costs
Natural gas costs
Production costs
($/bbl)
Production costs, excluding natural gas costs (1)
Natural gas costs (2)
Production costs (3)
Sales volumes (bbl/d)
$
$
$
$
2021
2020
3,176
$
2,968
$
238
146
2019
3,151
125
3,414
$
3,114
$
3,276
2021
2020
19.45
$
19.50
$
1.46
0.96
2019
21.70
0.86
20.91
$
20.46
$
22.56
447,230
415,741
397,735
(1) Calculated as production costs, excluding natural gas costs divided by sales volumes.
(2) Calculated as natural gas costs divided by sales volumes.
(3) Calculated as production costs divided by sales volumes.
Production costs for 2021 of $20.91 per bbl, were comparable with $20.46 per bbl for 2020 (2019 – $22.56 per bbl). Production
costs per bbl for 2021 as compared to 2020 primarily reflected the impact of higher energy costs, including natural gas and
diesel, offset by the impact of record production volumes, together with the Company's strong focus on cost control.
DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING
($ millions, except per bbl amounts)
Depletion, depreciation and amortization
$/bbl (1)
2021
1,838
11.26
$
$
2020
1,784
11.73
$
$
2019
1,656
11.41
$
$
(1) Calculated as depletion, depreciation and amortization divided by sales volumes. For SCO sales volumes, refer to the "Non-GAAP and Other Financial
Measures" section of this MD&A.
Depletion, depreciation and amortization expense for 2021 of $11.26 per bbl decreased 4% from $11.73 per bbl for 2020
(2019 – $11.41 per bbl). The decrease in depletion, depreciation and amortization on a per barrel basis primarily reflected the
impact of fluctuating sales volumes from underlying operations.
ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING
($ millions, except per bbl amounts)
Asset retirement obligation accretion
$/bbl (1)
2021
57
0.35
$
$
2020
72
0.47
$
$
2019
61
0.42
$
$
(1) Calculated as asset retirement obligation accretion divided by sales volumes. For SCO sales volumes, refer to the "Non-GAAP and Other Financial
Measures" section of this MD&A.
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 2021 of $0.35 per bbl decreased 26% from $0.47 per bbl for 2020 (2019 –
$0.42 per bbl). Fluctuations in asset retirement obligation accretion expense on a per barrel basis primarily reflect fluctuating
sales volumes.
Canadian Natural 2021 Annual Report
28
Midstream and Refining
($ millions)
Product sales
Midstream activities
NWRP, refined product sales and other
Segmented revenue
Less:
NWRP, refining toll
Midstream activities
Production expense
NWRP, transportation and feedstock costs
Depreciation
Income from NWRP
Equity loss from investment in NWRP
Segmented earnings (loss)
2021
2020
2019
$
78
$
83
$
681
759
213
21
234
550
15
(400)
—
202
285
166
18
184
181
15
—
—
$
360
$
(95)
$
88
—
88
—
20
20
—
14
—
287
(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% equity investment in NWRP. Approximately 27% 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 processes approximately 12,500 bbl/d (25% toll payer)
of bitumen feedstock for the Company and 37,500 bbl/d (75% toll payer) of bitumen feedstock for the Alberta Petroleum
Marketing Commission ("APMC"), an agent of the Government of Alberta. The Company is unconditionally obligated to pay its
25% pro rata share of the debt component of the monthly fee-for-service toll over the 40-year tolling period. Sales of diesel
and refined products and associated refining tolls are recognized in the Midstream and Refining segment. Production of ultra-
low sulphur diesel and other refined products for 2021 averaged 69,713 BOE/d (17,428 BOE/d to the Company), reflecting the
25% toll payer commitment (2020 – 58,694 BOE/d; 14,673 BOE/d to the Company).
On June 30, 2021, the equity partners together with the toll payers, agreed to optimize the structure of NWRP to better
align the commercial interests of the equity partners and the toll payers (the "Optimization Transaction"). As a result, North
West Refining Inc. transferred its entire 50% partnership interest in NWRP to APMC. The Company's 50% equity interest
remained unchanged.
Under the Optimization Transaction, the original term of the processing agreements was extended by 10 years from 2048
to 2058. NWRP retired higher cost subordinated debt, which carried interest rates of prime plus 6%, with lower cost senior
secured bonds at an average rate of approximately 2.55%, reducing interest costs to NWRP and associated tolls to the toll
payers. As such, NWRP repaid the Company's and APMC's subordinated debt advances of $555 million each. In addition, the
Company received a $400 million distribution from NWRP during 2021.
To facilitate the Optimization Transaction, NWRP issued $500 million of 1.20% series L senior secured bonds due December
2023, $500 million of 2.00% series M senior secured bonds due December 2026, $1,000 million of 2.80% series N senior
secured bonds due June 2031, and $600 million of 3.75% series O senior secured bonds due June 2051. Additionally, NWRP's
existing $3,500 million syndicated credit facility was amended. The $2,000 million revolving credit facility was extended by
three years to June 2024, and the $1,500 million non-revolving credit facility was reduced by $500 million to $1,000 million
and extended by two years to June 2023. As at December 31, 2021, NWRP had borrowings of $1,981 million under the
syndicated credit facility (December 31, 2020 – $2,866 million).
As at December 31, 2021, the cumulative unrecognized share of the equity loss and partnership distributions from NWRP
was $562 million (2020 – $153 million). The unrecognized share of the equity loss from NWRP for 2021 was $9 million and
partnership distributions were $400 million (2020 – unrecognized equity loss of $94 million; 2019 – recognized equity loss of
$287 million and unrecognized equity loss of $59 million).
29
Canadian Natural 2021 Annual Report
Corporate and Other
ADMINISTRATION EXPENSE
Expense ($ millions)
$/BOE (1)
Sales volumes (BOE/d) (2)
(1) Calculated as administration expense divided by sales volumes.
(2) Total Company sales volumes.
2021
366
0.81
$
$
2020
391
0.92
$
$
2019
344
0.86
$
$
1,233,457
1,166,862
1,095,379
Administration expense for 2021 of $0.81 per BOE decreased 12% from $0.92 per BOE for 2020 (2019 – $0.86 per
BOE). Administration expense per BOE decreased for 2021 from 2020 primarily due to higher sales volumes and higher
overhead recoveries.
SHARE-BASED COMPENSATION
($ millions)
Expense (recovery)
2021
2020
$
514
$
(82)
$
2019
223
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 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.
The Company recognized a $514 million share-based compensation expense for 2021, 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. An expense of $79 million related to PSUs granted to certain executive employees was included in the share-
based compensation expense for 2021 (2020 – $21 million expense; 2019 – $49 million expense).
INTEREST AND OTHER FINANCING EXPENSE
($ millions, except effective interest rate)
Interest and other financing expense
Interest income and other (1)
Capitalized interest (1)
2021
2020
$
711
$
756
$
32
—
72
24
Interest on long-term debt and lease liabilities (1)
$
743
$
852
$
2019
836
76
53
965
Average current and long-term debt balance (2)
$
18,935
$
22,446
$
22,017
Average lease liabilities balance (2)
1,619
1,708
1,707
Average long-term debt and lease liabilities (2)
$
20,554
$
24,154
$
23,724
Average effective interest rate (3) (4)
3.5%
3.5%
4.0%
Interest and other financing expense per $/BOE (5)
$
1.58
$
1.77
$
2.09
Sales volumes (BOE/d) (6)
1,233,457
1,166,862
1,095,379
(1) Item is a component of interest and other financing expense.
(2) The average of current and long-term debt and lease liabilities outstanding during the respective period.
(3) This is a non-GAAP ratio and may not be comparable to similar measures presented by other companies, and should not be considered an alternative
to or more meaningful than their most directly comparable financial measure presented in the Company's audited consolidated financial statements, as
applicable, as an indication of the Company's performance.
(4) Calculated as the total of interest on long-term debt and lease liabilities divided by the average long-term debt and lease liabilities balance for the respective
period. The Company presents its average effective interest rate for financial statement users to evaluate the Company’s average cost of debt borrowings.
(5) Calculated as interest and other financing expense divided by sales volumes.
(6) Total Company sales volumes.
Interest and other financing expense per BOE for 2021 decreased 11% to $1.58 per BOE from $1.77 per BOE for 2020 (2019 –
$2.09 per BOE). The decrease in interest and other financing expense per BOE for 2021 from 2020 was primarily due to higher
sales volumes and lower average debt levels in 2021, partially offset by lower interest income.
The Company’s average effective interest rate of 3.5% for 2021 was consistent with 2020.
Canadian Natural 2021 Annual Report
30
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency
exposures. These derivative financial instruments are not intended for trading or speculative purposes.
($ millions)
Natural gas financial instruments
Crude oil and NGLs financial instruments
Foreign currency contracts
Net realized loss
Natural gas financial instruments
Crude oil and NGLs financial instruments
Foreign currency contracts
Net unrealized loss (gain)
Net loss (gain)
2021
2020
2019
$
$
17
(1)
1
17
11
2
6
19
36
$
$
16
—
16
32
(36)
—
(3)
(39)
$
(7)
$
(1)
52
13
64
15
(17)
15
13
77
During 2021, net realized risk management losses were related to the settlement of natural gas financial instruments, crude
oil and NGLs financial instruments and foreign currency contracts. The Company recorded a net unrealized loss of $19 million
($16 million after-tax of $3 million) on its risk management activities for 2021 (2020 – $39 million unrealized gain, $31 million
after-tax of $8 million; 2019 – $13 million unrealized loss, $14 million after-tax recovery of $1 million).
Further details related to outstanding derivative financial instruments at December 31, 2021 are disclosed in note 19 to the
Company's audited consolidated financial statements.
FOREIGN EXCHANGE
($ millions)
Net realized loss (gain)
Net unrealized gain
Net gain (1)
2021
2020
78
$
(159)
$
(205)
(116)
(127)
$
(275)
$
2019
(22)
(548)
(570)
$
$
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange loss for 2021 was primarily due to foreign exchange rate fluctuations on settlement of
working capital items denominated in US dollars or UK pounds sterling and the repayment of US$500 million of 3.45% debt
securities. The net unrealized foreign exchange gain for 2021 was primarily related to the impact of a stronger Canadian dollar
with respect to outstanding US dollar debt and the reversal of the net unrealized foreign exchange loss on the repayment
of US$500 million of 3.45% debt securities. The US/Canadian dollar exchange rate at December 31, 2021 was US$0.7901
(December 31, 2020 – US$0.7840, December 31, 2019 – US$0.7713).
31
Canadian Natural 2021 Annual Report
INCOME TAXES
($ millions, except effective tax rates)
North America (1)
North Sea
Offshore Africa
PRT – North Sea
Other taxes
Current income tax
Deferred corporate income tax
Deferred PRT – North Sea
Deferred income tax
Income tax
Earnings (loss) before taxes
Effective tax rate on net earnings (loss) (2)
Income tax
Tax effect on non-operating items (3) (4)
Current PRT – North Sea
Other taxes
Effective tax on adjusted net earnings (loss)
Adjusted net earnings (loss) from operations (5)
Effective tax on adjusted net earnings (loss)
Adjusted net earnings (loss) from operations, before taxes
2021
2020
$
1,841
$
(245)
$
7
21
(34)
13
1,848
399
—
399
(4)
17
(31)
6
(257)
(181)
—
(181)
2,247
$
(438)
$
2019
354
112
44
(89)
13
434
(895)
1
(894)
(460)
9,911
$
(873)
$
4,956
23%
50%
(9)%
$
2,247
$
(438)
$
5
34
(13)
29
31
(6)
(460)
1,630
89
(13)
2,273
$
(384)
$
1,246
7,420
$
(756)
$
2,273
(384)
9,693
$
(1,140)
$
3,795
1,246
5,041
25%
$
$
$
$
$
Effective tax rate on adjusted net earnings (loss) from operations (6) (7)
23%
34%
(1) Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments.
(2) Calculated as total of current and deferred income tax divided by earnings (loss) before taxes.
(3) Includes the net tax effect of PSUs, unrealized risk management, abandonment expenditure recovery, the Keystone XL pipeline provision and legislative
changes to tax rates in adjusted net earnings (loss) from operations.
(4) 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.
(5) Non-GAAP Financial Measure. Refer to the "Non-GAAP and other Financial Measures" section of this MD&A.
(6) This is a non-GAAP ratio and may not be comparable to similar measures presented by other companies, and should not be considered an alternative
to or more meaningful than their most directly comparable financial measure presented in the Company's audited consolidated financial statements, as
applicable, as an indication of the Company's performance.
(7) Calculated as effective tax on adjusted net earnings (loss) divided by adjusted net earnings (loss) from operations, before taxes. The Company presents its effective
tax rate on adjusted net earnings (loss) from operations for financial statement users to evaluate the Company’s effective tax rate on its core business activities.
The effective tax rate on net earnings (loss) and adjusted net earnings (loss) from operations for 2021 and the comparable years
included the impact of non-taxable items in North America and the North Sea and the impact of differences in jurisdictional
income 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 2021 and the prior periods included the impact of carrybacks of
abandonment expenditures related to decommissioning activities at the Company's platforms in the North Sea.
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 2021, the Company filed Scientific Research and Experimental Development claims of approximately $229 million (2020 –
$246 million; 2019 – $250 million) relating to qualifying research and development expenditures for Canadian income tax purposes.
Canadian Natural 2021 Annual Report
32
Net Capital Expenditures (1) (2)
($ millions)
Exploration and Evaluation
2021
2020
2019
Net property (dispositions) acquisitions (3)
$
(11)
$
(31)
$
Net expenditures
Total Exploration and Evaluation
Property, Plant and Equipment
Net property acquisitions (3) (4) (5)
Well drilling, completion and equipping
Production and related facilities
Other
Total Property, Plant and Equipment
Total Exploration and Production
Oil Sands Mining and Upgrading
Project costs
Sustaining capital
Turnaround costs
Other (6)
Total Oil Sands Mining and Upgrading
Midstream and Refining
Head office
Abandonments expenditures, net (2)
Net capital expenditures
By segment
North America (3) (4) (5)
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream and Refining
Head office
Abandonments expenditures, net (2)
Net capital expenditures
90
74
164
3,208
775
1,028
81
5,092
5,256
436
933
118
38
10
34
296
7,121
12
1
1,112
918
802
64
2,896
2,897
236
1,035
145
331
1,747
9
23
232
36
5
536
429
580
60
1,605
1,610
258
839
196
30
5
19
249
1,323
1,525
4,908
$
3,206
$
$
$
2,662
$
1,389
$
4,831
173
62
1,747
9
23
232
122
99
1,323
5
19
249
$
4,908
$
3,206
$
196
229
1,525
10
34
296
7,121
(1) Net capital expenditures exclude the impact of lease assets and fair value and revaluation adjustments, and include non-cash transfers of property, plant
and equipment to inventory due to change in use.
(2) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3) Includes cash consideration of $91 million for exploration and evaluation assets and $3,126 million for property, plant and equipment acquired from Devon
Canada Corporation ("Devon") in 2019.
(4) Includes cash consideration of $771 million and the settlement of long-term debt of $183 million assumed in the acquisition of Storm in 2021.
(5) Includes cash consideration of $111 million and the settlement of long-term debt of $397 million assumed in the acquisition of Painted Pony Energy Ltd.
("Painted Pony") in 2020.
(6) Includes the acquisition of a 5% net carried interest on an existing oil sands lease in 2021.
The Company's strategy is focused on building a diversified asset base that is balanced among various products. In order to
facilitate efficient operations, the Company concentrates its activities in core areas. The Company focuses on maintaining its
land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration
risk. By owning associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby
increasing control over production expenses.
Net capital expenditures for 2021 were $4,908 million compared with $3,206 million for 2020.
During 2021, the Company completed the acquisition of all the issued and outstanding common shares of Storm for total
cash consideration of approximately $771 million. At closing, the acquisition also included the assumption of long-term debt
of approximately $183 million. Storm is involved in the exploration for and development of natural gas and natural gas liquids
in the Montney region of British Columbia.
33
Canadian Natural 2021 Annual Report
During 2021, the Company also completed a number of other opportunistic acquisitions. Two acquisitions consisted of natural
gas assets located in the Montney region of British Columbia. A third acquisition consisted of a net carried interest on an
existing oil sands lease held by the Company, from which all Horizon production volumes are derived. Total cash consideration
paid for these acquisitions was approximately $450 million.
2022 CAPITAL BUDGET
On January 11, 2022, the Company announced its 2022 base capital budget targeted at approximately $3,645 million. The
budget also includes incremental strategic growth capital of approximately $700 million that targets to add future production
and capacity in the Company's long life low decline thermal in situ and Oil Sands Mining and Upgrading assets.
The 2022 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further
details on forward-looking statements.
DRILLING ACTIVITY (1)
(number of net wells)
Net successful natural gas wells
Net successful crude oil wells (2)
Dry wells
Stratigraphic test / service wells
Total
Success rate (excluding stratigraphic test / service wells)
(1) Includes drilling activity for North America and International segments.
(2) Includes bitumen wells.
2021
49
149
1
393
592
99%
2020
2019
30
42
—
372
444
100%
19
86
3
447
555
97%
North America
During 2021, the Company drilled 49 net natural gas wells, 94 net primary heavy crude oil wells, 10 net Pelican Lake heavy
crude oil wells, 8 net bitumen (thermal oil) wells and 32 net light crude oil wells.
North Sea
During 2021, the Company drilled 5.9 net light crude oil wells.
Canadian Natural 2021 Annual Report
34
Liquidity and Capital Resources
($ millions, except ratios)
Adjusted working capital (1)
Long-term debt, net (2)
Shareholders’ equity
2021
(480)
13,950
36,945
$
$
$
2020
626
21,269
32,380
$
$
$
$
$
$
Debt to book capitalization (2)
After-tax return on average capital employed (3)
27%
16%
40%
—%
(1) Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
(2) Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
2019
241
20,843
34,991
37%
11%
As at December 31, 2021, 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 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 2021, the Company extended both of its $2,425 million revolving credit facilities originally maturing June 2022
and June 2023, to June 2024 and June 2025, respectively and increased each by $70 million. In accordance with the
terms of the extension, and by mutual agreement, $70 million of the original revolving credit facilities were not extended
and will mature upon the original maturity date of June 2022 and June 2023, respectively. The revolving syndicated
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 2021, the $1,000 million non-revolving term credit facility originally due February 2022, was extended to February
2023. Additionally in 2021, the facility was fully repaid and amended to allow for a re-draw of the full $1,000 million
until March 31, 2022.
• During 2021, the Company repaid $1,500 million of the $2,650 million non-revolving term credit facility due February
2023, reducing the outstanding balance to $1,150 million.
• During 2019, the Company entered into a $3,250 million non-revolving term credit facility with an original maturity of
June 2022, to finance the acquisition of assets from Devon. During 2021, the outstanding balance of $3,088 million
was repaid and the facility was cancelled.
35
Canadian Natural 2021 Annual Report
• During 2021, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to
$3,000 million of medium-term notes in Canada, which expires in August 2023. 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 2021, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to
US$3,000 million of debt securities in the United States, which expires in August 2023. 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 2021, the Company repaid US$500 million of 3.45% debt securities.
• 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, SOFR, US base rate or Canadian prime
rate.
•
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, 2021, the Company had undrawn bank credit facilities of $6,098 million. Including cash and cash
equivalents and short-term investments, the Company had approximately $7,151 million in liquidity. Additionally, the Company
had in place fully drawn term credit facilities of $1,150 million. The Company also has certain other dedicated credit facilities
supporting letters of credit.
As at December 31, 2021, the Company had total US dollar denominated debt with a carrying amount of $11,581 million
(US $9,151 million), before transaction costs and original issue discounts. This included $1,836 million (US$1,451 million)
hedged by way of a cross currency swap (US$550 million) and foreign currency forwards (US$901 million). The fixed
repayment amount of these hedging instruments is $1,805 million, resulting in a notional reduction of the carrying amount of
the Company’s US dollar denominated debt by approximately $31 million to $11,550 million as at December 31, 2021.
Net long-term debt was $13,950 million at December 31, 2021, resulting in a debt to book capitalization ratio of 27%
(December 31, 2020 – 40%, December 31, 2019 – 37%); 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,
2021 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, 2021, 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, 2021 are discussed in note 19 to the Company’s audited consolidated financial statements.
As at December 31, 2021, 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)
$
$
$
1,000
282
650
$
$
$
2,906
181
583
$
$
$
3,251
430
1,503
$
$
$
Thereafter
7,624
824
3,971
(1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
(2) Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $185 million; one to less
than two years, $149 million; two to less than five years, $426 million; and thereafter, $824 million.
(3) 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, 2021.
Canadian Natural 2021 Annual Report
36
SHARE CAPITAL
As at December 31, 2021, there were 1,168,369,000 common shares outstanding (December 31, 2020 – 1,183,866,000
common shares) and 38,327,000 stock options outstanding. As at March 1, 2022, the Company had 1,163,204,000 common
shares outstanding and 37,112,000 stock options outstanding.
On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.75 per common share,
beginning with the dividend payable on April 5, 2022. On November 3, 2021, the Board of Directors approved a 25% increase
in the quarterly dividend to $0.5875 per common share, from $0.47 per common share. On March 3, 2021, the Board of
Directors approved an 11% increase in the quarterly dividend to $0.47 per common share, from $0.425 per common share.
On March 4, 2020, the Board of Directors approved a 13% increase in the quarterly dividend to $0.425 per common share,
from $0.375 per common share. On March 6, 2019, the Board of Directors approved a 12% increase in the quarterly dividend
to $0.375 per common share, from $0.335 per common share. The dividend policy undergoes periodic review by the Board
of Directors and is subject to change.
On March 9, 2021, 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 59,278,474 common shares, over a 12-month period
commencing March 11, 2021 and ending March 10, 2022.
During 2021, the Company purchased 33,644,400 common shares at a weighted average price of $46.98 per common share
for a total cost of $1,581 million. Retained earnings were reduced by $1,297 million, representing the excess of the purchase
price of common shares over their average carrying value. Subsequent to December 31, 2021, the Company purchased
10,500,000 common shares at a weighted average price of $64.79 per common share for a total cost of $680 million.
On March 2, 2022, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with the
TSX to purchase, by way of a Normal Course Issuer Bid, up to 10% of the public float (as determined in accordance with the
rules of the TSX) of its issued and outstanding common shares. Subject to acceptance of the Notice of Intention by the TSX,
the purchases would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE.
Commitments and Contingencies
In the normal course of business, the Company has committed to certain payments. The following table summarizes the
Company’s commitments as at December 31, 2021:
($ millions)
2022
2023
2024
2025
2026
Thereafter
Product transportation and
processing (1) (2)
North West Redwater Partnership
service toll (3)
$
$
Offshore vessels and equipment $
Field equipment and power
Other
$
$
967
$
1,107
$
914
$
870
$
816
$
10,028
122
62
25
37
$
$
$
$
123
$
121
$
— $
21
27
$
$
— $
21
22
$
$
119
$
— $
21
20
$
$
97
$
3,671
— $
21
15
$
$
—
225
—
(1) Includes commitments pertaining to a 20-year product transportation agreement on the Trans Mountain Pipeline Expansion.
(2) The acquisition of Storm in 2021 and Painted Pony in 2020 included approximately $298 million and $2,400 million of product transportation and processing
commitments, respectively.
(3) Pursuant to the processing agreements, the Company pays its 25% pro rata share of the debt component of the monthly fee-for-service toll. Included in
the toll is $1,486 million of interest payable over the 40-year tolling period, ending in 2058.
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.
37
Canadian Natural 2021 Annual Report
Reserves
For the years ended December 31, 2021 and 2020, 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, 2021:
Total Proved
December 31, 2020
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2021 (1)
Total Proved Plus
Probable
December 31, 2020
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2021 (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)
315
—
1
3
—
—
—
14
(5)
(28)
300
177
—
7
4
—
—
—
13
(9)
(23)
169
265
2,483
6,962
9,465
326
12,106
—
—
—
1
—
—
22
2
(20)
270
—
119
—
19
—
—
—
105
(95)
—
—
—
—
—
—
—
199
(164)
—
598
170
3
1,715
(1)
309
528
(619)
2,631
6,998
12,168
—
15
13
—
59
—
10
13
—
243
47
21
345
—
110
392
(18)
418
(451)
12,813
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)
463
—
2
4
—
—
—
18
(34)
(28)
424
260
395
4,157
7,496
15,922
500
15,925
—
10
6
—
—
—
18
(22)
(23)
249
—
—
—
2
—
—
7
5
—
158
—
23
—
—
2
91
(20)
388
(95)
4,337
—
—
—
—
—
—
—
202
(164)
—
1,004
687
4
2,979
(1)
368
(94)
(619)
7,535
20,249
—
30
21
—
100
—
11
(1)
(18)
643
—
368
146
26
596
—
116
224
(451)
16,950
(1) Information in the reserves data tables may not add due to rounding. BOE values as presented may not calculate due to rounding.
At December 31, 2021, the total proved crude oil, bitumen (thermal oil) and NGLs reserves were 10,785 MMbbl, and total
proved plus probable crude oil, bitumen (thermal oil) and NGLs reserves were 13,576 MMbbl. Total proved reserves additions
and revisions replaced 174% of 2021 production. Additions to total proved reserves resulting from exploration and development
activities, acquisitions, dispositions and future offset additions amounted to 241 MMbbl, and additions to total proved plus
probable reserves amounted to 357 MMbbl. Net positive revisions amounted to 363 MMbbl for total proved reserves and 295
MMbbl for total proved plus probable reserves, primarily due to technical revisions.
Canadian Natural 2021 Annual Report
38
At December 31, 2021, the total proved natural gas reserves were 12,168 Bcf, and total proved plus probable natural gas
reserves were 20,249 Bcf. Total proved reserves additions and revisions replaced 537% of 2021 production. Additions to total
proved reserves resulting from exploration and development activities, acquisitions, dispositions and future offset additions
amounted to 2,485 Bcf, and additions to total proved plus probable reserves amounted to 4,673 Bcf. Net positive revisions
amounted to 837 Bcf for total proved reserves, primarily due to technical revisions and economic factors. Net positive revisions
amounted to 273 Bcf for total proved plus probable reserves, primarily due to economic factors.
The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence
procedures with each of the Company’s Independent Qualified Reserves Evaluators to review the qualifications of and
procedures used by each evaluator in determining the estimate of the Company’s quantities and related net present value of
future net revenue of the remaining reserves. Additional reserves 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;
■
■
Future legislative and regulatory developments related to environmental regulation, including but not limited to GHG
compliance costs and reduction targets;
The timing and pace of change to a low carbon economy is uncertain and the ability to access insurance and capital may
be adversely affected in the event that financial institutions, investors, insurers, rating agencies and/or lenders adopt more
restrictive decarbonisation policies;
■ 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 and the
certainty and timelines for regulatory processes;
■ 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;
■ 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;
39
Canadian Natural 2021 Annual Report
■ 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 the 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 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;
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, 2021.
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.
Canadian Natural 2021 Annual Report
40
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:
■ 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 were completed at Murchison and were advanced at Banff, Kyle, and Ninian North;
■
Tailings management in Oil Sands Mining to minimize fine tailings and promote progressive 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.
41
Canadian Natural 2021 Annual Report
The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of
approximately 60 years and have been discounted using a weighted average discount rate of 4.0% (2020 – 3.7%; 2019 –
3.8%). For 2021, the Company’s capital expenditures included $307 million for abandonment expenditures ($232 million
– abandonment expenditures, net) (2020 – $249 million; 2019 – $296 million). Refer to the “Non-GAAP and Other Financial
Measures” section of this MD&A for further details on abandonments expenditures, net. The Company’s estimated
discounted ARO at December 31, 2021 was as follows:
($ millions)
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream and Refining
2021
2020
$
4,021
$
2,899
821
170
1,793
1
$
6,806
$
787
174
1,999
2
5,861
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.
In 2021, the Alberta Energy Regulator announced a new Liability Management Framework, enforcing mandatory targets for
companies for the closure of inactive wells and facilities. These targets became effective January 1, 2022. The Company has
updated its forecasts of future expenditures to settle its ARO liability based on the set and forecasted annual targets. As a
result, the Company’s ARO liability as at December 31, 2021 has increased on an inflated and discounted basis due to earlier
forecasted expenditures to settle liabilities associated with the closure of inactive well and facilities located in Alberta.
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 is participating in the Oil Sands Pathways to Net Zero initiative, an alliance of oil sands producers working
collectively with federal and provincial governments, to achieve net zero GHG emissions from oil sands operations by 2050 to
help Canada meet its climate goals, including its Paris Agreement commitments and 2050 net zero aspirations.
The Company, through industry associations, 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 2021 Annual Report
42
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 40 - 45% from 2005 levels by 2030. The Canadian government
has also committed to cap and cut emissions from the oil and gas sector, with further details to be developed in 2022. Canada
has also committed to reduce methane emissions from the upstream oil and natural gas sector by 40 - 45% by 2025, and by
75% by 2030, as compared to 2012 levels for both the 2025 and 2030 targets. In December 2020, the federal government
announced its intention to increase the carbon price to $170/tonne in 2030. 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. The final version of the Clean
Fuel regulations are expected to be published in 2022.
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 $40/tonne for
emissions above the TIER-regulated limits in 2021 and is $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 $45/tonne of CO2e on fuel consumed and gas flared and vented
in the province. In February 2021, the British Columbia government announced that the carbon tax rate would increase to
$50/tonne effective April 1, 2022. 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, a new UK Emissions Trading Scheme ("ETS")
was launched on January 1, 2021. The new scheme is currently aligned with the EU ETS rules and applies to energy intensive
industries, the power generation sector and aviation. The Company continues to focus on implementing CO2 emission
reduction program opportunities at its facilities and on trading mechanisms to ensure compliance with requirements
now in effect.
43
Canadian Natural 2021 Annual Report
Accounting Policies and Standards
REGULATORY DEVELOPMENTS
On May 27, 2021, the Canadian Securities Administrators ("CSA") announced the adoption of NI 52-112 and related amendments.
This National Instrument replaces the previous CSA staff notice on Non-GAAP Measures. NI 52-112 governs how entities
present non-GAAP and other financial measures and ratios. The requirements apply to the Company's MD&A and certain
other disclosure documents for the year ended December 31, 2021.
CHANGES IN ACCOUNTING POLICIES
In August 2020, the IASB issued Interest Rate Benchmark Reform (Phase 2) in response to the Financial Stability Board's
mandated reforms to IBORs, with financial regulators proposing that current IBOR benchmark rates be replaced by a number
of new local currency denominated alternative benchmark rates. The Company adopted the amendments on January 1, 2021.
Adoption of these amendments did not have a significant impact on the Company's financial statements.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the
application of IFRS that have a significant impact on the financial results of the Company. In 2021, COVID-19 continued to
have an impact on the global economy, including the oil and gas industry. Business conditions in 2021 continued to reflect 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, 2021.
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 2021 Annual Report
44
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, including the potential impact of climate related matters and in accordance with related
government regulations. 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, including the potential impact of climate related matters and in accordance with related government regulations.
These individual assumptions may be subject to change.
The estimated present values of ARO related to long-term assets are recognized as a liability in the period in which they
are incurred. The provision for the ARO is estimated by discounting the expected future cash flows to settle the ARO at
the Company’s weighted average credit-adjusted risk-free interest rate, which is currently 4.0%. Subsequent to initial
measurement, the ARO is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes
in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is
recognized as asset retirement obligation accretion expense whereas changes in discount rates or estimated future cash
flows are capitalized to or derecognized from property, plant and equipment. Changes in estimates would impact accretion
and depletion expense in net earnings. In addition, differences between actual and estimated costs to settle the ARO, timing
of cash flows to settle the obligation and future inflation rates may result in gains or losses on the final settlement of the ARO.
D) Income Taxes
The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and
liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying amount of assets and
liabilities in the consolidated financial statements and their respective tax bases, using income tax rates substantively enacted
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.
45
Canadian Natural 2021 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 emissions credits and grants introduced in response
to the impact of COVID-19. Government grants are recognized in net earnings when there is reasonable assurance that the
Company will comply with the conditions attached to the grant and the grant will be received. Emissions performance and
offset credits generated under the Alberta TIER regulation are initially recorded at fair value as determined by the prescribed
Alberta TIER fund compliance rates in effect at the time the credits are recognized.
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, 2021, 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, 2021, 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 2021 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 2021 Annual Report
46
Non-GAAP and Other Financial Measures
This MD&A includes references to non-GAAP and other financial measures as defined in NI 52-112. These financial measures
are used by the Company to evaluate its financial performance, financial position or cash flow and include non-GAAP financial
measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial
measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial
measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures
presented by other companies, and should not be considered an alternative to or more meaningful than the most directly
comparable financial measure presented in the Company's audited consolidated financial statements, as applicable, as an
indication of the Company's performance. Descriptions of the Company’s non-GAAP and other financial measures included in
this MD&A, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below.
ADJUSTED NET EARNINGS (LOSS) FROM OPERATIONS
Adjusted net earnings (loss) from operations is a non-GAAP financial measure that adjusts net earnings (loss) as presented
in the Company's consolidated Statements of Earnings (Loss), for non-operating items (after-tax). 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. A reconciliation for adjusted net earnings (loss)
from operations is presented below.
($ millions)
Net earnings (loss)
Share-based compensation, net of tax (1)
Unrealized risk management loss (gain), net of tax (2)
Unrealized foreign exchange gain, net of tax (3)
Realized foreign exchange loss (gain), net of tax (4)
Gain on acquisitions, net of tax (5)
(Gain) loss from investments, net of tax (6)
Other, net of tax (7)
Effect of statutory tax rate and other legislative changes on deferred
income tax liabilities (8)
Non-operating items (after-tax)
2021
2020
$
7,664
$
(435)
$
495
16
(205)
118
(478)
(132)
(58)
—
(244)
(86)
(31)
(116)
(166)
(217)
185
110
—
(321)
2019
5,416
210
14
(548)
—
—
321
—
(1,618)
(1,621)
Adjusted net earnings (loss) from operations
$
7,420
$
(756)
$
3,795
(1) Share-based compensation includes costs incurred under the Company's Stock Option Plan and PSU plan. The fair value of the share-based compensation
is recognized as a liability on the Company’s balance sheets and periodic changes in the fair value are recognized in net earnings (loss). Pre-tax share-based
compensation for 2021 was an expense of $514 million (2020 – $82 million recovery; 2019 – $223 million expense).
(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 Company's audited
consolidated financial statements due to changes in prices of the underlying items hedged, primarily natural gas and foreign exchange. Pre-tax unrealized
risk management loss for 2021 was $19 million (2020 – $39 million gain; 2019 – $13 million loss).
(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). Pre- and after-tax amounts for these unrealized foreign
exchange gains are the same.
(4) During 2021, the Company repaid US$500 million of 3.45% debt securities, resulting in a pre- and after-tax foreign exchange loss of $118 million. 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. There was net zero tax impact on the settlement.
(5) During 2021, the Company completed two acquisitions resulting in a pre- and after-tax gain of $478 million. During 2020, the Company recognized a pre-
and after-tax gain of $217 million related to the acquisition of Painted Pony.
(6) The Company’s investments in PrairieSky and IPL have been accounted for at fair value through profit and loss and are measured each period with (gains)
losses recognized in net earnings (loss). There is net zero tax impact on these (gains) losses from investment.
(7) During 2021, the Company recognized the impact of government grant income under the provincial well-site rehabilitation programs of $75 million
($58 million after-tax). 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.
(8) 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 Company's deferred corporate income tax
liability decreased by $1,618 million, refer to "Income Taxes" section of this MD&A.
47
Canadian Natural 2021 Annual Report
ADJUSTED FUNDS FLOW
Adjusted funds flow is a non-GAAP financial measure that represents cash flows from operating activities as presented in the
Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment
expenditures excluding the impact of government grant income under the provincial well-site rehabilitation programs,
and movements in other long-term assets. The Company considers adjusted funds flow a key measure in evaluating its
performance, as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through
capital investment and to repay debt. A reconciliation for adjusted funds flow, from cash flows from operating activities is
presented below.
($ millions)
Cash flows from operating activities
Net change in non-cash working capital
Abandonment expenditures, net (1)
Movements in other long-term assets (2)
Adjusted funds flow
2021
2020
$
14,478
$
4,714
$
(964)
232
(13)
166
249
71
2019
8,829
1,033
296
109
$
13,733
$
5,200
$
10,267
(1) Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the “Abandonment Expenditures, net” section below.
(2) Includes the unamortized cost of the share bonus program, accrued interest on subordinated debt advances to NWRP and prepaid cost of service tolls.
ADJUSTED NET EARNINGS (LOSS) FROM OPERATIONS AND ADJUSTED FUNDS FLOW, PER SHARE
(BASIC AND DILUTED)
Adjusted net earnings (loss) from operations and adjusted funds flow, per share (basic and diluted), are non-GAAP ratios
that represent those non-GAAP measures divided by the weighted average number of basic and diluted common shares
outstanding for the period, respectively, as presented in note 17 to the Company's audited consolidated financial statements.
ABANDONMENT EXPENDITURES, NET
Abandonment expenditures, net, is a non-GAAP financial measure that represents the abandonment expenditures to
settle asset retirement obligations as reflected in the Company's annual capital budget. Abandonment expenditures, net is
calculated as abandonment expenditures, as presented in the Company's audited consolidated Statements of Cash Flows,
adjusted for the impact of government grant income under the provincial well-site rehabilitation programs. A reconciliation of
abandonment expenditures, net is presented below.
($ millions)
Abandonment expenditures
Government grants for abandonment expenditures
Abandonment expenditures, net
NETBACK
2021
2020
307
$
249
$
(75)
—
232
$
249
$
2019
296
—
296
$
$
Netback is a non-GAAP ratio that represents net cash flows provided from core activities after the impact of all costs associated
with bringing a product to market, on a per unit basis. The Company considers netback a key measure in evaluating its
performance, as it demonstrates the efficiency and profitability of the Company's activities. Refer to the "Operating Highlights
– Exploration and Production", "Per Unit Results – Exploration and Production", and "Per Unit Results – Oil Sands Mining and
Upgrading" sections of this MD&A for the netback calculations on a per unit basis for crude oil and NGLs, natural gas and on
a total barrels of oil equivalent basis.
The netback calculations include the non-GAAP financial measures: realized price and transportation, reconciled below to their
respective line item in note 22 to the Company's audited consolidated financial statements.
Canadian Natural 2021 Annual Report
48
REALIZED PRICE ($/BBL AND $/BOE) – EXPLORATION AND PRODUCTION
Realized price ($/bbl and $/BOE) is a non-GAAP ratio calculated as realized crude oil and NGLs sales and total realized BOE
sales (non-GAAP financial measures) divided by respective sales volumes. Realized crude oil and NGLs sales and total realized
BOE sales include the impact of blending costs and other by-product sales. The Company considers realized price a key
measure in evaluating its performance, as it demonstrates the realized pricing per unit the Company obtained on the market
for its crude oil and NGLs sales volumes and BOE sales volumes.
Reconciliations for Exploration and Production realized crude oil and NGLs sales and BOE sales and the calculations for
realized price are presented below.
($ millions, except bbl/d and $/bbl)
Crude oil and NGLs (bbl/d)
North America
North Sea
Offshore Africa
Sales volumes
Q1
Q2
Q3
Q4
2021
2020
2019
477,768
468,265
448,948
490,448
471,331
465,073
400,853
29,566
10,843
8,939
17,932
16,028
19,402
21,360
5,624
18,942
13,452
22,852
17,017
27,171
21,056
518,177
495,136
484,378
517,432
503,725
504,942
449,080
Crude oil and NGLs sales (1) (2)
$ 3,373
$ 3,655
$ 3,810
$ 4,667
$ 15,505
$ 8,215
$ 11,183
Less: Blending costs (3)
916
897
777
1,202
3,792
2,321
2,155
Realized crude oil and NGLs sales
$ 2,457
$ 2,758
$ 3,033
$ 3,465
$ 11,713
$ 5,894
$ 9,028
Realized price ($/bbl)
$ 52.68
$ 61.20
$ 68.06
$ 72.81
$ 63.71
$ 31.90
$ 55.08
(1) Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements.
(2) Includes other miscellaneous income in the segment.
(3) Blending costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation - Exploration and Production"
section.
($ millions, except BOE/d and $/BOE)
Q1
Q2
Q3
Q4
2021
2020
2019
Barrels of oil equivalent (BOE/d)
North America
North Sea
Offshore Africa
Sales volumes
741,904
733,874
731,962
797,185
751,330
706,799
641,327
30,180
12,444
9,624
20,659
16,427
20,652
21,940
7,781
19,512
15,385
24,805
19,517
31,167
25,151
784,528
764,157
769,041
826,906
786,227
751,121
697,645
Barrels of oil equivalent sales (1) (2)
$ 3,865
$ 4,119
$ 4,460
$ 5,581
$ 18,025
$ 9,511
$ 12,457
Less: Blending costs (3)
Less: Sulphur (income) expense
916
(2)
897
(4)
777
(3)
1,202
3,792
2,321
2,155
(12)
(21)
4
(12)
Realized barrels of oil equivalent sales $ 2,951
$ 3,226
$ 3,686
$ 4,391
$ 14,254
$ 7,186
$ 10,314
Realized price ($/BOE)
$ 41.80
$ 46.40
$ 52.09
$ 57.72
$ 49.67
$ 26.15
$ 40.50
(1) Barrels of oil equivalent sales includes crude oil and NGLs sales and natural gas sales in note 22 to the Company's audited consolidated
financial statements.
(2) Includes other miscellaneous income in the segment.
(3) Blending costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation - Exploration and
Production" section.
49
Canadian Natural 2021 Annual Report
TRANSPORTATION – EXPLORATION AND PRODUCTION
Transportation ($/BOE, $/bbl and $/Mcf) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure)
divided by the respective sales volumes. The Company calculates transportation to demonstrate its cost to deliver products
to the market excluding the impact of blending costs. A reconciliation for Exploration and Production transportation and the
calculations for transportation are presented below.
($ millions, except $ per unit amounts)
Q1
Q2
Q3
Q4
2021
2020
2019
Transportation, blending and
feedstock (1)
Less: Blending costs
Less: Other (2)
Transportation
$ 1,148
$ 1,146
$ 1,025
$ 1,461
$ 4,780
$ 3,409
$ 2,956
916
—
897
—
777
—
1,202
3,792
2,321
2,155
—
—
143
945
—
$
801
$
232
$
249
$
248
$
259
$
988
$
Transportation ($/BOE)
$ 3.29
$ 3.58
$ 3.50
$ 3.40
$ 3.44
$ 3.44
$ 3.14
Amounts attributed to crude oil and
NGLs
$
166
$
179
$
178
$
187
$
710
$
711
$
571
Transportation ($/bbl)
$ 3.56
$ 3.98
$ 4.00
$ 3.93
$ 3.86
$ 3.85
$ 3.48
Amounts attributed to natural gas
$
66
$
70
$
70
$
72
$
278
$
234
$
230
Transportation ($/Mcf)
$ 0.46
$ 0.48
$ 0.44
$ 0.42
$ 0.45
$ 0.43
$ 0.42
(1) Transportation, blending and feedstock in note 22 to the Company's audited consolidated financial statements.
(2) Transportation excludes the impact of a $143 million provision recognized in 2020, relating to the Keystone XL pipeline project.
NORTH AMERICA – REALIZED PRODUCT PRICES AND ROYALTIES
Realized crude oil and NGLs price ($/bbl) is a non-GAAP ratio calculated as realized crude oil and NGLs sales (non-GAAP
financial measure) divided by sales volumes. Realized crude oil and NGLs sales include the impact of blending costs. The
Company considers the realized crude oil and NGLs price a key measure in evaluating its performance, as it demonstrates the
realized pricing per unit that the Company obtained on the market for its crude oil and NGLs sales volumes.
Crude oil and NGLs royalty rate is a non-GAAP ratio that is calculated as crude oil and NGLs royalties divided by realized crude
oil and NGLs sales. The Company considers crude oil and NGLs royalty rate a key measure in evaluating its performance, as
it describes the Company’s royalties for crude oil and NGLs sales volumes on a per unit basis.
A reconciliation for North America realized crude oil and NGLs sales and the calculations for realized crude oil and NGLs prices
and the royalty rates are presented below.
($ millions, except $/bbl and royalty rates)
Crude oil and NGLs sales (1)
Less: Blending costs (2)
Realized crude oil and NGLs sales
Realized crude oil and NGLs prices ($/bbl)
Crude oil and NGLs royalties (3)
Crude oil and NGLs royalty rates
2021
2020
$
14,478
$
7,480
$
$
$
$
3,792
10,686
62.10
$
$
1,558
$
15%
2,321
5,159
30.31
464
9%
$
$
$
2019
9,679
2,155
7,524
51.43
959
13%
(1) Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements.
(2) Blending costs are a component of transportation, blending and feedstock expense as reconciled above in the "Transportation - Exploration and
Production" section.
(3) Item is a component of royalties in note 22 to the Company's audited consolidated financial statements.
Canadian Natural 2021 Annual Report
50
REALIZED PRODUCT PRICES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING
Realized SCO sales price ($/bbl) is a non-GAAP ratio calculated as realized SCO sales (non-GAAP financial measure) including
the impact of blending and feedstock costs, divided by SCO sales volumes. The Company considers realized SCO sales price
a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on
the market for its SCO sales volumes.
Transportation ($/bbl) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure) divided by SCO sales
volumes. The Company calculates transportation to demonstrate its cost to deliver product to the market excluding the impact
of blending and feedstock costs.
Reconciliations for Oil Sands Mining and Upgrading realized SCO sales and transportation and the calculations for realized
SCO sales price and transportation are presented below.
($ millions, except for bbl/d and $/bbl)
Q1
Q2
Q3
Q4
2021
2020
2019
SCO sales volumes (bbl/d)
469,953
366,843
467,772
483,972
447,230
415,741
397,735
Crude oil and NGLs sales (1) (2)
$ 2,983
$ 2,794
$ 3,848
$ 4,408
$ 14,033
$ 7,389
$ 11,307
Less: Blending and feedstock costs
251
251
339
468
1,309
695
1,119
Realized SCO sales
$ 2,732
$ 2,543
$ 3,509
$ 3,940
$ 12,724
$ 6,694
$ 10,188
Realized SCO sales price ($/bbl)
$ 64.60
$ 76.19
$ 81.54
$ 88.48
$ 77.95
$ 43.98
$ 70.18
Transportation, blending and
feedstock (3)
Less: Blending and feedstock costs
Transportation
Transportation ($/bbl)
$
$
$
297
251
$
294
251
$
387
339
$
527
468
$ 1,505
$
1,309
46
$
43
$
48
$
59
$
196
1.10
$ 1.26
$ 1.14
$ 1.33
$ 1.21
$
$
881
695
186
1.23
$ 1,306
1,119
187
1.29
$
$
(1) Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements.
(2) Excludes other miscellaneous income not pertaining to crude oil and NGLs sales.
(3) Transportation, blending and feedstock in note 22 to the Company's audited consolidated financial statements.
NET CAPITAL EXPENDITURES
Net capital expenditures is a non-GAAP financial measure that represents cash flows used in investing activities as presented
in the Company's audited consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital,
proceeds from investment, the repayment of NWRP subordinated debt advances, abandonment expenditures including the
impact of government grant income under the provincial well-site rehabilitation programs, and the settlement of long-term
debt assumed in acquisitions. The Company considers net capital expenditures a key measure in evaluating its performance,
as it provides an understanding of the Company’s capital spending activities in comparison to the Company’s annual capital
budget. A reconciliation of net capital expenditures is presented below.
($ millions)
Cash flows used in investing activities
Net change in non-cash working capital (1)
Proceeds from investment
Repayment of NWRP subordinated debt advances
Capital expenditures
Abandonment expenditures, net (2)
Settlement of long-term debt acquired (3)
Net capital expenditures
2021
2020
$
3,703
$
2,819
$
107
128
555
4,493
232
183
(383)
—
124
2,560
249
397
2019
7,255
(430)
—
—
6,825
296
—
$
4,908
$
3,206
$
7,121
(1) Includes net working capital and other long-term assets of $195 million related to the acquisition of assets from Devon in 2019.
(2) Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the “Abandonment Expenditures, net” section above.
(3) Relates to the settlement of long-term debt assumed in the acquisition of Storm in 2021 and Painted Pony in 2020.
51
Canadian Natural 2021 Annual Report
LIQUIDITY
Liquidity is a non-GAAP financial measure that represents the availability of readily available undrawn bank credit facilities,
cash and cash equivalents, and other highly liquid assets to meet short-term funding requirements and to assist in assessing
the Company's financial position. The following is the Company’s calculation of liquidity:
($ millions)
Undrawn bank credit facilities
Cash and cash equivalents
Investments
Liquidity
LONG-TERM DEBT, NET
2021
2020
$
6,098
$
4,958
$
744
309
184
305
2019
4,737
139
490
$
7,151
$
5,447
$
5,366
Long-term debt, net, is a capital management measure that represents long-term debt less cash and cash equivalents, as
disclosed in note 16 to the Company's audited consolidated financial statements.
DEBT TO BOOK CAPITALIZATION
Debt to book capitalization is a capital management measure intended to enable financial statement users to evaluate the
Company's capital structure, as disclosed in note 16 to the Company's audited consolidated financial statements.
AFTER-TAX RETURN ON AVERAGE CAPITAL EMPLOYED
After-tax return on average capital employed as defined by the Company is a non-GAAP ratio. The ratio is calculated as net
earnings (loss) plus after-tax interest and other financing expense for the twelve month trailing period; as a percentage of
average capital employed (defined as current and long-term debt plus shareholders' equity) for the twelve month trailing period.
The Company considers this ratio a key measure in evaluating the Company’s ability to generate profit and the efficiency with
which it employs capital. A reconciliation of the Company's after-tax return on average capital employed is presented below.
($ millions, except ratios)
Interest adjusted after-tax return:
Net earnings (loss), 12 months trailing
Interest and other financing expense, net of tax, 12 months trailing (1)
Interest adjusted after-tax return
12 months average current portion long-term debt (2)
12 months average long-term debt (2)
12 months average common shareholders' equity (2)
$
$
$
2021
2020
2019
7,664
$
(435)
$
547
8,211
$
571
136
$
5,416
612
6,028
1,483
$
1,842
$
2,640
16,769
34,458
20,162
33,026
19,078
33,660
12 months average capital employed
$
52,710
$
55,030
$
55,378
After-tax return on average capital employed
16%
—%
11%
(1) The blended tax rate on interest was 23% for December 31, 2021, 24% for December 31, 2020, and 27% for December 31, 2019.
(2) For the purpose of this non-GAAP ratio, the measurement of average current and long-term debt and common shareholders equity are determined on a
consistent basis, as an average of the opening and quarterly period end values for the 12 month trailing period for each of the periods presented.
Canadian Natural 2021 Annual Report
52
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.
2022 CAPITAL BUDGET
On January 11, 2022, the Company announced its 2022 base capital budget targeted at approximately $3,645 million. The
budget also includes incremental strategic growth capital of approximately $700 million that targets to add future production
and capacity in the Company's long life low decline thermal in situ and Oil Sands Mining and Upgrading assets.
The 2022 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further
details on forward-looking statements.
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
2021, excluding mark-to-market gains (losses) on risk management activities and is not necessarily indicative of future results.
Each separate line item in the sensitivity analysis shows the effect of a change in that variable only with all other variables
being held constant.
Price changes
Crude oil – WTI US$1.00/bbl
Excluding financial derivatives
Including financial derivatives
Natural gas – AECO C$0.10/Mcf
Excluding financial derivatives
Including financial derivatives
Volume changes
Crude oil – 10,000 bbl/d
Natural gas – 10 MMcf/d
Foreign currency rate change
$0.01 change in US$ (1)
Including financial derivatives
Interest rate change – 1%
Cash flows
from Operating
Activities
($ millions)
Cash flows
from Operating
Activities
(per common
share, basic)
Net
earnings
(loss)
($ millions)
Net
earnings
(loss)
(per common
share, basic)
$
$
$
$
$
$
$
$
311
310
31
27
170
10
268
13
$
$
$
$
$
$
$
$
0.26
0.26
0.03
0.02
0.14
0.01
0.23
0.01
$
$
$
$
$
$
$
$
311
310
31
27
144
5
142
13
$
$
$
$
$
$
$
$
0.26
0.26
0.03
0.02
0.12
—
0.12
0.01
(1) For details of financial instruments in place, refer to note 19 to the Company’s audited consolidated financial statements as at December 31, 2021.
53
Canadian Natural 2021 Annual Report
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
Q1
Q2
Q3
Q4
2021
2020
2019
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) (2)
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
478,736
478,314
454,888
478,738
472,621
460,443
405,970
468,803
361,707
468,126
493,406
448,133
417,351
395,133
19,959
11,854
16,458
16,239
16,294
13,531
17,860
14,421
17,633
14,017
23,142
17,022
27,919
21,371
979,352
872,718
952,839
1,004,425
952,404
917,958
850,393
1,585
1,594
1,698
1,841
1,680
1,450
1,443
4
9
4
16
2
8
3
13
3
12
12
15
24
24
1,598
1,614
1,708
1,857
1,695
1,477
1,491
742,871
743,923
737,902
785,476
752,620
702,168
646,443
468,803
361,707
468,126
493,406
448,133
417,351
395,133
20,574
13,455
17,143
18,966
16,694
14,781
18,441
16,577
18,203
15,950
25,095
19,522
31,915
25,466
1,245,703
1,141,739
1,237,503
1,313,900
1,234,906
1,164,136
1,098,957
(1) SCO production before royalties excludes SCO consumed internally as diesel.
(2) Natural gas production volumes approximate sales volumes.
Canadian Natural 2021 Annual Report
54
PER UNIT RESULTS – EXPLORATION AND PRODUCTION
Q1
Q2
Q3
Q4
2021
2020
2019
Crude oil and NGLs ($/bbl) (1)
Realized price (2)
Transportation (2)
Realized price, net of transportation (2)
Royalties (3)
Production expense (4)
Netback (2)
Natural gas ($/Mcf) (1)
Realized price (5)
Transportation (6)
Realized price, net of transportation
Royalties (3)
Production expense (4)
Netback (2)
Barrels of oil equivalent ($/BOE) (1)
Realized price (2)
Transportation (2)
Realized price, net of transportation (2)
Royalties (3)
Production expense (4)
Netback (2)
$ 52.68
$ 61.20
$ 68.06
$ 72.81
$ 63.71
$ 31.90
$ 55.08
3.56
49.12
5.69
14.56
3.98
57.22
8.50
13.75
4.00
64.06
9.46
14.78
3.93
68.88
10.67
15.70
3.86
59.85
8.59
14.71
3.85
28.05
2.59
12.42
3.48
51.60
6.08
13.81
$ 28.87
$ 34.97
$ 39.82
$ 42.51
$ 36.55
$ 13.04
$ 31.71
$ 3.42
$ 3.17
$ 4.13
$ 5.35
$ 4.07
$ 2.40
$ 2.34
0.46
2.96
0.16
1.27
0.48
2.69
0.12
1.19
0.44
3.69
0.22
1.17
0.42
4.93
0.35
1.12
0.45
3.62
0.22
1.18
0.43
1.97
0.08
1.18
0.42
1.92
0.08
1.22
$ 1.53
$ 1.38
$ 2.30
$ 3.46
$ 2.22
$ 0.71
$ 0.62
$ 41.80
$ 46.40
$ 52.09
$ 57.72
$ 49.67
$ 26.15
$ 40.50
3.29
38.51
4.10
12.20
3.58
42.82
5.77
11.42
3.50
48.59
6.45
11.91
3.40
54.32
7.48
12.33
3.44
46.23
5.98
11.98
3.44
22.71
1.89
10.67
3.14
37.36
4.09
11.49
$ 22.21
$ 25.63
$ 30.23
$ 34.51
$ 28.27
$ 10.15
$ 21.78
(1) For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales
volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3) Calculated as royalties divided by respective sales volumes.
(4) Calculated as production expense divided by respective sales volumes.
(5) Calculated as natural gas sales divided by natural gas sales volumes.
(6) Calculated as natural gas transportation expense divided by natural gas sales volumes.
PER UNIT RESULTS – OIL SANDS MINING AND UPGRADING
Q1
Q2
Q3
Q4
2021
2020
2019
Crude oil and NGLs ($/bbl) (1)
Realized SCO sales price (2)
$ 64.60
$ 76.19
$ 81.54
$ 88.48
$ 77.95
$ 43.98
$ 70.18
Bitumen royalties (3)
Transportation (2)
Production costs (4)
Netback (2)
2.88
1.10
5.92
1.26
8.21
1.14
9.16
1.33
6.62
1.21
0.51
1.23
3.31
1.29
19.82
25.46
19.86
19.55
20.91
20.46
22.56
$ 40.80
$ 43.55
$ 52.33
$ 58.44
$ 49.21
$ 21.78
$ 43.02
(1) For SCO sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3) Calculated as royalties divided by sales volumes.
(4) Calculated as production costs divided by sales volumes.
55
Canadian Natural 2021 Annual Report
TRADING AND SHARE STATISTICS
TSX – C$
Q1
Q2
Q3
Q4
2021
2020
Trading volume (thousands)
439,840
401,283
364,136
363,613
1,568,872
1,866,414
Share Price ($/share)
High
Low
Close
Market capitalization as at
December 31 ($ millions)
Shares outstanding
(thousands)
NYSE – US$
$
41.05
$ 46.36
$ 46.99
$ 55.59
$ 28.67
$ 36.23
$
37.82
$ 46.06
$ 38.85
$ 45.00
$ 46.31
$ 53.45
$
$
$
$
55.59
28.67
53.45
$
$
$
42.57
9.80
30.59
62,449
$
36,214
1,168,369
1,183,866
Trading volume (thousands)
243,664
177,553
188,674
185,714
795,605
1,058,121
Share Price ($/share)
High
Low
Close
Market capitalization as at
December 31 ($ millions)
Shares outstanding
(thousands)
$ 32.64
$
38.10
$
37.39
$ 44.33
$ 22.40
$ 28.86
$ 29.53
$ 36.37
$ 30.87
$ 36.28
$ 36.54
$ 42.25
$
$
$
$
44.33
22.40
42.25
$
$
$
32.79
6.71
24.05
49,364
$
28,472
1,168,369
1,183,866
Canadian Natural 2021 Annual Report
56
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
58
59
60
62
63
63
64
65
66
66
73
73
73
75
75
76
79
80
80
82
84
86
88
90
90
90
91
91
96
97
99
23. Remuneration of Directors and Senior Management
102
57
Canadian Natural 2021 Annual Report
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, 2021; and
the effectiveness of the Company’s internal control over financial reporting as at December 31, 2021.
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
VICTOR DAREL, CPA, CA
Vice-President, Finance and
Principal Accounting Officer
Calgary, Alberta, Canada
March 2, 2022
Canadian Natural 2021 Annual Report
58
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, 2021. 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, 2021, 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 2, 2022
59
Canadian Natural 2021 Annual Report
Report of Independent Registered Public
Accounting Firm
To the Shareholders and Board of Directors of Canadian Natural
Resources Limited
OPINIONS ON THE FINANCIAL STATEMENTS AND INTERNAL CONTROL OVER FINANCIAL REPORTING
We have audited the accompanying consolidated balance sheets of Canadian Natural Resources Limited and its subsidiaries
(together, the “Company”) as of December 31, 2021 and 2020, 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, 2021, 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, 2021, 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, 2021 and 2020, and its financial performance and its cash flows for each of
the three years in the period ended December 31, 2021 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, 2021, based on criteria established in Internal Control –
Integrated Framework (2013) issued by the COSO.
BASIS FOR OPINIONS
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal
control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included
in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express
opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting
based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United
States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. 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.
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.
Canadian Natural 2021 Annual Report
60
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”) balance in the North America Exploration and Production segment was $25.1 billion as of December 31, 2021.
Depletion, depreciation and amortization (“DD&A”) expense for the North America Exploration and Production segment was
$3.5 billion for the year ended December 31, 2021. In accordance with the Company’s accounting policies, crude oil and natural
gas properties in the North America Exploration and Production segment, excluding certain major components, are depleted
using the unit-of-production method based on proved reserves. 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. Management utilizes third party specialists, specifically independent
qualified reserve evaluators, to evaluate and review its estimates of crude oil and natural gas reserves. These estimates are
utilized for 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 by management, including the use of specialists, when developing the estimates,
specifically related to the estimates of crude oil and natural gas reserves 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 assumptions used in developing the estimates, including estimated future prices and
production costs, expected future rates of production, and the timing and amount of future development expenditures.
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 and the calculation of 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 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. The procedures performed also included, among other, evaluating whether the
assumptions used by management’s specialists related to estimated future prices and production costs, expected future
rates of production, and the timing and amount of future development expenditures were reasonable considering the current
and past performance of the Company, consistency with industry pricing forecasts, and whether they were consistent with
evidence obtained in other areas of the audit, as applicable. Additionally, these procedures also included testing the unit-of-
production rates used to calculate DD&A expense.
Chartered Professional Accountants
Calgary, Canada
March 2, 2022
We have served as the Company’s auditor since 1973.
61
Canadian Natural 2021 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 income taxes payable
Current portion of long-term debt
Current portion of other long-term liabilities
Long-term debt
Other long-term liabilities
Deferred income taxes
SHAREHOLDERS’ EQUITY
Share capital
Retained earnings
Accumulated other comprehensive (loss) income
Commitments and contingencies (note 20).
Approved by the Board of Directors on March 2, 2022.
Note
2021
2020
$
744
$
3,111
—
1,548
195
309
35
5,942
2,250
66,400
1,508
565
$
$
76,665
$
803
$
3,064
1,607
1,000
948
7,422
13,694
8,384
10,220
39,720
10,168
26,778
(1)
36,945
$
76,665
$
5
9
10
6
7
8
10
11
8,12
11
8,12
13
14
15
184
2,190
309
1,060
231
305
82
4,361
2,436
65,752
1,645
1,082
75,276
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
CATHERINE M. BEST
Chair of the Audit Committee
and Director
N. MURRAY EDWARDS
Executive Chairman of the Board of Directors
and Director
Canadian Natural 2021 Annual Report
62
Consolidated Statements of Earnings (Loss)
For the years ended December 31,
(millions of Canadian dollars, except per common share amounts)
Note
2021
2020
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
Gain on acquisitions
Income from North West Redwater Partnership
(Gain) loss from investments
Earnings (loss) before taxes
Current income tax expense (recovery)
Deferred income tax expense (recovery)
Net earnings (loss)
Net earnings (loss) per common share
Basic
Diluted
22
$
32,854
$
17,491
$
(2,797)
30,057
7,152
6,604
5,724
366
514
185
711
36
(127)
(478)
(400)
(141)
20,146
9,911
1,848
399
(598)
16,893
6,280
4,498
6,046
391
(82)
205
756
(7)
(275)
(217)
—
171
17,766
(873)
(257)
(181)
$
$
$
7,664
$
(435)
$
6.49
6.46
$
$
(0.37)
(0.37)
$
$
7,8
12
12
18
19
7
10
9,10
13
13
17
17
Consolidated Statements of Comprehensive
Income (Loss)
2019
24,394
(1,523)
22,871
6,277
4,699
5,546
344
223
190
836
77
(570)
—
—
293
17,915
4,956
434
(894)
5,416
4.55
4.54
2021
2020
$
7,664
$
(435)
$
2019
5,416
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
(2020 – $2 million, 2019 – $13 million)
Reclassification to net earnings (loss), net of taxes of
$1 million (2020 – $2 million, 2019 – $5 million)
Foreign currency translation adjustment
Translation of net investment
Other comprehensive loss, net of taxes
15
(7)
8
(17)
(9)
13
(15)
(2)
(24)
(26)
99
(41)
58
(146)
(88)
5,328
Comprehensive income (loss)
$
7,655
$
(461)
$
63
Canadian Natural 2021 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 (loss) income
Balance – beginning of year
Other comprehensive loss, net of taxes
Balance – end of year
Shareholders’ equity
Note
14
2021
2020
$
9,606
$
9,533
$
707
139
(284)
10,168
22,766
7,664
(2,355)
(1,297)
26,778
8
(9)
(1)
108
21
(56)
9,606
25,424
(435)
(2,008)
(215)
22,766
34
(26)
8
14
14
15
2019
9,323
360
53
(203)
9,533
22,529
5,416
(1,783)
(738)
25,424
122
(88)
34
$
36,945
$
32,380
$
34,991
Canadian Natural 2021 Annual Report
64
Consolidated Statements of Cash Flows
For the years ended December 31,
(millions of Canadian dollars)
Operating activities
Net earnings (loss)
Non-cash items
Depletion, depreciation and amortization
Share-based compensation
Asset retirement obligation accretion
Unrealized risk management loss (gain)
Unrealized foreign exchange gain
Gain on acquisitions
(Gain) loss from investments
Deferred income tax expense (recovery)
Realized foreign exchange loss (gain)
Other
Abandonment expenditures
Net change in non-cash working capital
Cash flows from operating activities
Financing activities
(Repayment) issuance of bank credit facilities and
commercial paper, net
Repayment of medium-term notes
(Repayment) issuance of US dollar debt securities
Settlement of long-term debt acquired
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 Canada Corporation assets
Proceeds from investment
Repayment of North West Redwater Partnership
subordinated debt advances
Net change in non-cash working capital
Cash flows used in investing activities
Increase 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
Note
2021
2020
2019
$
7,664
$
(435)
$
5,416
5,724
6,046
5,546
514
185
19
(205)
(478)
(132)
399
118
13
(307)
964
(82)
205
(39)
(116)
(217)
185
(181)
(166)
(71)
(249)
(166)
14,478
4,714
(6,151)
—
(628)
(183)
—
(209)
707
(2,170)
(1,581)
(10,215)
(1)
(4,492)
—
128
555
107
(3,703)
560
184
744
672
(62)
$
$
$
338
(1,100)
1,481
(397)
166
(225)
108
(1,950)
(271)
(1,850)
(5)
(2,555)
—
—
124
(383)
(2,819)
45
139
184
745
(29)
$
$
$
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)
38
101
139
865
445
21
11,21
11,21
11,21
7
8
6,21
7,22
6,7
9
10
21
$
$
$
65
Canadian Natural 2021 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 the 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 2021 Annual Report
66
(D) INVENTORY
Inventory is primarily comprised of product inventory, materials and supplies and other inventory, including emissions credits, 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 and other inventory is determined by reference to current market prices. Emissions credit inventory generated in the
normal course of business is initially measured in accordance with the Company's accounting policy for government grants.
(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 20 years.
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.
67
Canadian Natural 2021 Annual Report
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.
(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.
Canadian Natural 2021 Annual Report
68
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.
(K) ASSET RETIREMENT OBLIGATIONS
The Company provides for asset retirement obligations on all of its property, plant and equipment and certain exploration and
evaluation assets based on current legislation and industry operating practices. Provisions for asset retirement obligations
related to property, plant and equipment are recognized as a liability in the period in which they are incurred. Provisions are
measured at the present value of management’s best estimate of expenditures required to settle the obligation as at the
date of the balance sheets. Subsequent to the initial measurement, the obligation is adjusted to reflect the passage of time,
changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The
increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense, whereas
changes due to discount rates or estimated future cash flows are capitalized to or derecognized from property, plant and
equipment. Actual costs incurred upon settlement of the asset retirement obligation are charged against the provision.
(L) FOREIGN CURRENCY TRANSLATION
Functional and presentation currency
Items included in the financial statements of the Company’s subsidiary companies and partnerships are measured using the
currency of the primary economic environment in which the subsidiary operates (the "functional currency"). The consolidated
financial statements are presented in Canadian dollars, which is the Company’s functional currency.
The assets and liabilities of subsidiaries that have a functional currency different from that of the Company are translated into
Canadian dollars at the closing rate at the date of the balance sheets, and revenue and expenses are translated at the average
rate for the period. Cumulative foreign currency translation adjustments are recognized in other comprehensive income.
When the Company disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence
over a foreign operation, the foreign currency gains or losses accumulated in other comprehensive income related to the
foreign operation are recognized in net earnings.
Transactions and balances
Foreign currency transactions are translated into the functional currency of the Company and its subsidiaries and partnerships
using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the
settlement of foreign currency transactions and from the translation at balance sheet date exchange rates of monetary assets
and liabilities denominated in currencies other than the functional currency are recognized in net earnings.
(M) REVENUE RECOGNITION AND COSTS OF GOODS SOLD
Revenue from the sale of crude oil and NGLs and natural gas products is recognized when performance obligations in the sales
contract are satisfied and it is probable that the Company will collect the consideration to which it is entitled. Performance
obligations are generally satisfied at the point in time when the product is delivered to a location specified in a contract and
control passes to the customer. The Company assesses customer creditworthiness, both before entering into contracts and
throughout the revenue recognition process.
Contracts for sale of the Company’s products generally have terms of less than a year, with certain contracts extending
beyond one year. Contracts in North America generally specify delivery of crude oil and NGLs and natural gas throughout the
term of the contract. Contracts in the North Sea and Offshore Africa generally specify delivery of crude oil at a point in time.
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Canadian Natural 2021 Annual Report
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 in Offshore Africa is shared under the terms of various Production Sharing Contracts
("PSCs"). Product sales are divided into cost recovery oil and profit oil. Cost recovery oil allows the Company to recover its capital
and production costs and the costs carried by the Company on behalf of the respective government state oil companies (the
"Governments"). Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a
portion has been allocated to the Governments. The Governments’ share of profit oil attributable to the Company’s equity interest
is allocated to royalty expense and current income tax expense in accordance with the terms of the respective PSCs.
(O) INCOME TAX
The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and
liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying amount of assets
and liabilities in the consolidated financial statements and their respective tax bases.
Deferred income tax assets and liabilities are calculated using the substantively enacted income tax rates that are expected
to apply when the asset or liability is recovered. Deferred income tax assets or liabilities are not recognized when they arise
on the initial recognition of an asset or liability in a transaction (other than in a business combination) that, at the time of the
transaction, affects neither accounting nor taxable profit. Deferred income tax assets or liabilities are also not recognized on
possible future distributions of retained earnings of subsidiaries where the timing of the distribution can be controlled by the
Company and it is probable that a distribution will not be made in the foreseeable future, or when distributions can be made
without incurring income taxes.
Deferred income tax assets for deductible temporary differences and tax loss carryforwards are recognized to the extent that
it is probable that future taxable profits will be available against which the temporary differences or tax loss carryforwards
can be utilized. The carrying amount of deferred income tax assets is reviewed at each reporting date, and is reduced if it is
no longer probable that sufficient future taxable profits will be available against which the temporary differences or tax loss
carryforwards can be utilized.
Current income tax is calculated based on net earnings for the period, adjusted for items that are non-taxable or taxed in
different periods, using income tax rates that are substantively enacted at each reporting date. Income taxes are recognized
in net earnings or other comprehensive income, consistent with the items to which they relate.
(P) SHARE-BASED COMPENSATION
The Company’s Stock Option Plan (the "Option Plan") provides current employees with the right to elect to receive common
shares or a cash payment in exchange for stock options surrendered. The liability for awards granted to employees is initially
measured based on the grant date fair value of the awards and the number of awards expected to vest. The awards are
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.
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70
(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.
(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.
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Canadian Natural 2021 Annual Report
Upon termination of an interest rate swap designated as a fair value hedge, the interest rate swap is derecognized in the
consolidated balance sheets and the related long-term debt hedged is no longer revalued for subsequent changes in fair value
due to interest rates changes. The fair value adjustment due to interest rates on the long-term debt at the date of termination
of the interest rate swap is amortized to interest expense over the remaining term of the long-term debt.
Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt.
The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional
principal amounts on which the payments are based. Changes in the fair value of the foreign exchange component of cross
currency swap contracts designated as cash flow hedges related to the notional principal amounts are recognized in foreign
exchange gains and losses in net earnings. The effective portion of changes in the fair value of the interest rate component of
cross currency swap contracts designated as cash flow hedges is initially recognized in other comprehensive income and is
reclassified to interest expense when the hedged item is recognized in net earnings, with the ineffective portion recognized
in risk management activities in net earnings. Changes in the fair value of non-designated cross currency swap contracts are
recognized in risk management activities in net earnings.
Realized gains or losses on the termination of financial instruments that have been designated as cash flow hedges are deferred
under accumulated other comprehensive income and amortized into net earnings in the periods in which the underlying hedged
items are recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the
related derivative instrument, any unrealized derivative gain or loss is recognized in net earnings. Realized gains or losses on the
termination of financial instruments that have not been designated as hedges are recognized in net earnings.
Foreign currency forward contracts are periodically used to manage foreign currency cash requirements. The foreign currency
forward contracts involve the purchase or sale of an agreed upon amount of US dollars at a specified future date at forward
exchange rates. Changes in the fair value of foreign currency forward contracts designated as cash flow hedges are initially
recorded in other comprehensive income and are reclassified to foreign exchange gains and losses when the hedged item is
recognized in net earnings. Changes in the fair value of non-designated foreign currency forward contracts are recognized in
risk management activities in net earnings.
Embedded derivatives are derivatives that are included in a non-derivative host contract. Embedded derivatives are recorded
at fair value separately from the host contract when their economic characteristics and risks are not clearly and closely related
to the host contract, except when the host contract is an asset.
(S) GOVERNMENT GRANTS
The Company receives or is eligible for government grants, including emissions credits and grants introduced in response to
the impact of the novel coronavirus ("COVID-19"). Government grants are recognized in net earnings when there is reasonable
assurance that the Company will comply with the conditions attached to the grant and the grant will be received. Emissions
performance and offset credits generated under the Alberta Technology Innovation and Emissions Reduction (“TIER”)
regulation are initially recorded at the value prescribed by the Alberta TIER fund compliance rates in effect at the time the
credits are recognized.
(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 (loss) 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.
Canadian Natural 2021 Annual Report
72
2. Changes in Accounting Policies
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 current IBOR benchmark
rates be replaced by a number of new local currency denominated alternative benchmark rates. The Company adopted
the amendments on January 1, 2021. Adoption of these amendments did not have a significant impact on the Company's
financial statements.
3. Accounting Standards Issued But Not Yet Applied
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 were adopted January 1, 2022 and did not have a significant impact
on the Company's consolidated financial statements.
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 February 2021 the IASB issued amendments to IAS 1 to require entities to disclose their material accounting policy
information rather than their significant accounting policies. To support this amendment the IASB also amended IFRS
Practice Statement 2 “Making Materiality Judgements”. The amendments are effective January 1, 2023 with earlier adoption
permitted. The Company is assessing the impact of this amendment on its accounting policy disclosure.
In May 2021, the IASB issued amendments to IAS 12 "Income Taxes" to require companies to recognize deferred tax on
particular transactions that, on initial recognition, give rise to equal amounts of taxable and deductible temporary differences.
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.
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
including the potential impact of climate related matters and in accordance with related government regulations. 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, changes in the date
of abandonment due to changes in reserves life, and the potential impact of climate related matters and in accordance with
related government regulations. 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.
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Canadian Natural 2021 Annual Report
(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.
(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, 2021, COVID-19 continued to have an impact on the global economy, including the
oil and gas industry. Business conditions in 2021 continued to reflect 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 these 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.
Canadian Natural 2021 Annual Report
74
5. Inventory
Product inventory
Materials, supplies and other
6. Exploration and Evaluation Assets
2021
535
$
1,013
1,548
$
2020
390
670
1,060
$
$
Exploration and Production
North
America
North
Sea
Offshore
Africa
Oil Sands
Mining and
Upgrading
Total
Cost
At December 31, 2019
Additions/Acquisitions
Transfers to property, plant and equipment
Derecognitions and other
Foreign exchange adjustments
At December 31, 2020
Additions/Acquisitions
Transfers to property, plant and equipment
Derecognitions and other
At December 31, 2021
$
2,258
$
— $
40
(194)
(3)
—
2,101
30
(73)
(1)
—
—
—
—
—
—
—
—
$
2,057
$
— $
69
15
—
—
(1)
83
8
—
—
91
$
252
$
2,579
—
—
—
—
252
—
(150)
—
55
(194)
(3)
(1)
2,436
38
(223)
(1)
$
102
$
2,250
On December 17, 2021, the Company completed the acquisition of all the issued and outstanding common shares of Storm
Resources Ltd. ("Storm") for total cash consideration of $771 million, including $13 million of exploration and evaluation assets
(note 7).
During 2020, the Company completed the acquisition of all the issued and outstanding shares of Painted Pony Energy Ltd.
("Painted Pony") for total 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 the assets of Devon Canada Corporation ("Devon")
including thermal in situ and heavy crude oil assets, for total cash consideration of $3,412 million, including $91 million of
exploration and evaluation assets (note 7).
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Canadian Natural 2021 Annual Report
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, 2019
$ 72,627
$ 7,296
$ 3,933
$
45,016
$
451
$ 466
$ 129,789
Additions/Acquisitions
1,789
104
Transfers from E&E assets
Derecognitions and other (1)
Disposals
Foreign exchange adjustments
and other
At December 31, 2020
Additions/Acquisitions
Transfers from E&E assets
Derecognitions and other (1)
Foreign exchange adjustments
and other
194
(521)
(92)
—
73,997
4,146
73
(382)
—
(3)
—
(114)
7,283
208
—
3
94
—
—
—
(64)
3,963
48
—
—
1,328
—
(634)
—
—
45,710
1,526
150
(530)
—
(56)
(31)
—
6
—
—
—
—
457
9
—
—
—
19
—
—
—
—
485
23
—
—
—
3,340
194
(1,158)
(92)
(178)
131,895
5,960
223
(909)
(87)
At December 31, 2021
$ 77,834
$ 7,438
$ 3,980
$
46,856
$
466
$ 508
$ 137,082
Accumulated depletion and depreciation
At December 31, 2019
$ 46,577
$ 5,712
$ 2,712
$
6,247
$
153
$ 345
$ 61,746
Expense
Derecognitions and other (1)
Disposals
Foreign exchange adjustments
and other
3,676
(521)
(63)
247
(3)
—
161
—
—
(28)
(103)
(51)
At December 31, 2020
49,641
5,853
2,822
Expense
Derecognitions and other (1)
Foreign exchange adjustments
and other
3,468
(382)
149
3
118
—
5
(54)
(17)
7
1,668
(634)
—
8
7,289
1,733
(530)
15
—
—
—
168
15
—
—
25
—
—
—
370
25
—
5,792
(1,158)
(63)
(174)
66,143
5,508
(909)
(1)
(60)
At December 31, 2021
$ 52,732
$ 5,951
$ 2,923
$
8,499
$
183
$ 394
$ 70,682
Net book value
- at December 31, 2021
$ 25,102
$ 1,487
$ 1,057
- at December 31, 2020
$ 24,356
$ 1,430
$ 1,141
$
$
38,357
38,421
$
$
283
289
$
$
114
115
$ 66,400
$ 65,752
(1) An asset is derecognized when no future economic benefits are expected to arise from its continued use or disposal.
As at December 31, 2021, 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 2021, no interest was capitalized to property, plant and equipment (2020 – $24 million at a weighted average
capitalization rate of 3.5%; 2019 – $53 million at a weighted average capitalization rate of 4.0%).
As at December 31, 2021, property, plant and equipment included project costs, not subject to depletion and depreciation,
of $118 million in the Oil Sands Mining and Upgrading segment (2020 – $117 million in the Oil Sands Mining and
Upgrading segment).
Canadian Natural 2021 Annual Report
76
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 the total purchase consideration.
ACQUISITIONS IN 2021
Acquisition of Storm
On December 17, 2021, the Company completed the acquisition of all the issued and outstanding common shares of Storm
for total cash consideration of $771 million. Storm is involved in the exploration for and development of natural gas and natural
gas liquids in the Montney region of British Columbia.
The acquisition has been accounted for using the acquisition method of accounting. The allocation of the purchase price was
based on management's best estimates of the fair value of the assets 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
Working capital
Long-term debt
Asset retirement obligations
Other long-term liabilities
Deferred tax liability
Net assets acquired
$
1,114
13
20
(183)
(18)
(35)
(140)
771
$
In connection with the acquisition the Company assumed certain product transportation and processing commitments
(note 20).
The impact of revenue and revenue, less production and transportation and blending expenses ("net operating income")
generated by the acquisition from December 17, 2021 to December 31, 2021 was not significant. If the acquisition had
been completed on January 1, 2021, the Company estimates that pro forma revenue would have increased by an additional
$294 million and pro forma net operating income would have increased by an additional $205 million for the year ended
December 31, 2021. Readers are cautioned that pro forma estimates are not necessarily indicative of the results of operations
that would have resulted had the acquisition actually occurred on January 1, 2021, or of future results. Pro forma results are
based on available historical information for the assets as provided to the Company and do not include any synergies that have
or may arise subsequent to the acquisition date.
Other Acquisitions in 2021
During 2021, the Company completed two acquisitions of gas producing assets and related processing infrastructure in
the Montney region of British Columbia, including property, plant and equipment assets of $257 million and exploration and
evaluation assets of $13 million, for cash consideration of $131 million. In connection with the acquisitions, the Company
assumed asset retirement obligations of $58 million, other liabilities of $65 million, and recognized a deferred tax asset of
$462 million. A gain of $478 million was recognized as a result of the acquisitions, representing the excess of the fair value of
the net assets acquired compared with the total purchase consideration.
77
Canadian Natural 2021 Annual Report
ACQUISITIONS IN 2020
Acquisition of Painted Pony
On October 6, 2020, the Company completed the acquisition of all the issued and outstanding common shares of Painted
Pony for total cash consideration of $111 million.
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
$
$
750
15
204
(397)
(13)
(442)
211
328
111
217
In connection with the acquisition the Company assumed certain product transportation and processing commitments
(note 20).
ACQUISITIONS IN 2019
Acquisition of Thermal in Situ and Primary Heavy Crude Oil Assets
On June 27, 2019, the Company completed the acquisition of substantially all the assets of Devon including thermal in situ and
heavy crude oil assets, for total cash 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
and net operating income increased by approximately $590 million.
Other Acquisitions in 2019
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 and assumed associated asset retirement
obligations of $20 million. No net deferred income tax liabilities were recognized and no pre-tax gains were recognized on
these net transactions.
Canadian Natural 2021 Annual Report
78
8. Leases
LEASE ASSETS
Product
transportation
and storage
Field
equipment
and power
Offshore
vessels and
equipment
Office leases
and other
Total
At December 31, 2019
$
1,166
$
Additions (1)
Depreciation
Derecognitions
Foreign exchange adjustments
and other
17
(124)
(20)
(1)
317
121
(53)
(5)
(1)
$
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
Additions
Depreciation
Foreign exchange adjustments
and other
48
(110)
(2)
36
(57)
(4)
At December 31, 2021
$
974
$
354
$
—
(27)
(2)
99
$
4
(22)
(1)
81
88
(216)
(9)
$
1,508
(1) The acquisition of Painted Pony in 2020 included lease assets of $93 million (note 7).
LEASE ASSETS, BY SEGMENT
As at December 31, 2021 and 2020, 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
LEASE LIABILITIES
2021
$
308
$
1
101
1,027
71
$
1,508
$
2020
345
7
126
1,080
87
1,645
The Company measures its lease liabilities at the discounted value of its lease payments during the lease term. Lease
liabilities at December 31, 2021 and 2020, were as follows:
Lease liabilities
Less: current portion
2021
1,584
$
185
1,399
$
2020
1,690
189
1,501
$
$
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 2021 and 2020 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)
2021
450
62
65
1,089
$
$
$
$
$
$
$
$
2020
409
67
85
983
(1) During 2021, the Company capitalized $303 million (2020 - $197 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.
79
Canadian Natural 2021 Annual Report
9. Investments
As at December 31, 2021 and 2020, the Company had the following investments:
Investment in PrairieSky Royalty Ltd.
Investment in Inter Pipeline Ltd.
2021
309
$
—
309
$
2020
228
77
305
$
$
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,
2021 the market price per common share was $13.63 (December 31, 2020 – $10.09; December 31, 2019 – $15.23). As at
December 31, 2021, 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 (gain) loss from the investment in PrairieSky was comprised as follows:
(Gain) loss from investment
Dividend income
$
$
2021
2020
(81)
$
117
$
(7)
(9)
(88)
$
108
$
2019
55
(17)
38
INVESTMENT IN INTER PIPELINE LTD.
During 2021, in accordance with a third-party offer to purchase, the Company elected to take total cash proceeds of $128 million,
or $20.00 per common share, in exchange for its 6.4 million common share investment in Inter Pipeline Ltd ("Inter Pipeline").
The Company's investment did not constitute significant influence, and was accounted for at fair value through profit or loss,
measured at each reporting date. The market price per common share as at December 31, 2020 and December 31, 2019 was
$11.87 and $22.54, respectively.
The (gain) loss from the investment in Inter Pipeline was comprised as follows:
(Gain) loss from investment
Dividend income
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
2021
2020
$
$
(51)
$
(2)
(53)
$
68
(5)
63
$
$
2021
$
— $
157
140
126
177
600
35
$
565
$
2019
(21)
(11)
(32)
2020
555
162
136
121
190
1,164
82
1,082
(1) The acquisition of Painted Pony in 2020 included physical sales contracts (note 7).
Canadian Natural 2021 Annual Report
80
INVESTMENT IN NORTH WEST REDWATER PARTNERSHIP
The Company has a 50% equity investment in NWRP. NWRP operates a 50,000 barrels per day bitumen upgrader and refinery
that processes approximately 12,500 barrels per day (25% toll payer) of bitumen feedstock for the Company and 37,500
barrels per day (75% toll payer) of bitumen feedstock for the Alberta Petroleum Marketing Commission ("APMC"), an agent of
the Government of Alberta. The Company is unconditionally obligated to pay its 25% pro rata share of the debt component of
the monthly fee-for-service toll over the 40-year tolling period (note 20). Sales of diesel and refined products and associated
refining tolls are recognized in the Midstream and Refining segment (note 22).
On June 30, 2021, the equity partners together with the toll payers, agreed to optimize the structure of NWRP to better
align the commercial interests of the equity partners and the toll payers (the "Optimization Transaction"). As a result, North
West Refining Inc. transferred its entire 50% partnership interest in NWRP to APMC. The Company's 50% equity interest
remained unchanged.
Under the Optimization Transaction, the original term of the processing agreements was extended by 10 years from 2048
to 2058. NWRP retired higher cost subordinated debt, which carried interest rates of prime plus 6%, with lower cost senior
secured bonds at an average rate of approximately 2.55%, reducing interest costs to NWRP and associated tolls to the toll
payers. As such, NWRP repaid the Company's and APMC's subordinated debt advances of $555 million each. In addition, the
Company received a $400 million distribution from NWRP during 2021.
To facilitate the Optimization Transaction, NWRP issued $500 million of 1.20% series L senior secured bonds due December
2023, $500 million of 2.00% series M senior secured bonds due December 2026, $1,000 million of 2.80% series N senior
secured bonds due June 2031, and $600 million of 3.75% series O senior secured bonds due June 2051. Additionally, NWRP's
existing $3,500 million syndicated credit facility was amended. The $2,000 million revolving credit facility was extended by
three years to June 2024, and the $1,500 million non-revolving credit facility was reduced by $500 million to $1,000 million
and extended by two years to June 2023. As at December 31, 2021, NWRP had borrowings of $1,981 million under the
syndicated credit facility (December 31, 2020 – $2,866 million).
The assets, liabilities, partners’ equity, product sales and equity loss related to NWRP at December 31, 2021 and 2020 were
comprised as follows:
Current assets
Non-current assets
Current liabilities
Non-current liabilities
Partners’ equity (1)
Partners’ equity (1) at Company's 50% interest
Revenue (2)
Net loss (3)
2021
280
10,806
798
11,412
(1,124)
(562)
1,168
18
$
$
$
$
$
$
$
$
2020
230
11,098
3,146
8,488
(306)
(153)
1,348
188
$
$
$
$
$
$
$
$
(1) In 2021, NWRP paid partnership distributions at 100% interest of $800 million.
(2) Included in NWRP's revenue for 2021 is $294 million (2020 – $174 million) paid by the Company for its 25% share of the refining toll.
(3) Included in the net loss for 2021 is the impact of depreciation and amortization expense of $278 million (2020 – $214 million) and interest and other
financing expense of $412 million (2020 – $420 million).
The carrying value of the Company’s interest in NWRP is $nil, and as at December 31, 2021, the cumulative unrecognized share
of the equity loss and partnership distributions from NWRP was $562 million (2020 – $153 million). The unrecognized share
of the equity loss from NWRP for 2021 was $9 million and partnership distributions were $400 million (2020 – unrecognized
equity loss of $94 million; 2019 – recognized equity loss of $287 million and unrecognized equity loss of $59 million).
81
Canadian Natural 2021 Annual Report
11. Long-Term Debt
Canadian dollar denominated debt, unsecured
Bank credit facilities
Medium-term notes
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, 2021 – US$901 million;
December 31, 2020 – US$3,953 million)
Commercial paper (December 31, 2021 – US$nil;
December 31, 2020 – US$426 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)
2021
2020
$
— $
1,614
1,000
1,000
500
500
600
300
300
500
500
600
300
300
3,200
4,814
1,140
—
—
1,266
633
759
759
1,582
633
506
443
443
570
1,392
506
949
11,581
14,781
15
72
14,694
—
1,000
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
(1) The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the
outstanding debt.
(2) Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and
other professional fees.
$
13,694
$
20,110
Canadian Natural 2021 Annual Report
82
BANK CREDIT FACILITIES AND COMMERCIAL PAPER
As at December 31, 2021, the Company had undrawn bank credit facilities of $6,098 million. Additionally, the Company had in
place fully drawn term credit facilities of $1,150 million. Details of these facilities are described below. The Company also has
certain other dedicated credit facilities supporting letters of credit.
■
■
■
■
■
■
a $100 million demand credit facility;
a $1,000 million term credit facility maturing February 2023;
a $1,150 million non-revolving term credit facility maturing February 2023;
a $2,495 million revolving syndicated credit facility, with $70 million maturing June 2022, and $2,425 million maturing June
2024;
a $2,495 million revolving syndicated credit facility, with $70 million maturing June 2023, and $2,425 million maturing June
2025; 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, SOFR, US base rate or Canadian prime rate.
During 2021, the Company extended both of its $2,425 million revolving credit facilities originally maturing June 2022 and
June 2023, to June 2024 and June 2025, respectively and increased each by $70 million. In accordance with the terms of
the extension, and by mutual agreement, $70 million of the original revolving credit facilities were not extended and will
mature upon the original maturity date of June 2022 and June 2023, respectively. The revolving syndicated 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 2021, the $1,000 million non-revolving term credit facility originally due February 2022, was extended to
February 2023. Additionally in 2021, the facility was fully repaid and amended to allow for a re-draw of the full $1,000 million
until March 31, 2022.
During 2021, the Company repaid $1,500 million of the $2,650 million non-revolving term credit facility due February 2023,
reducing the outstanding balance to $1,150 million.
During 2019, the Company entered into a $3,250 million non-revolving term credit facility with an original maturity of
June 2022, to finance the acquisition of assets from Devon (note 7). During 2021, the outstanding balance of $3,088 million
was repaid and the facility was cancelled.
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,
2021 was 0.8% (December 31, 2020 – 1.1%), and on total long-term debt outstanding for the year ended December 31, 2021
was 3.5% (December 31, 2020 – 3.5%).
As at December 31, 2021, letters of credit and guarantees aggregating to $513 million were outstanding (December 31, 2020
- $489 million).
MEDIUM-TERM NOTES
During 2021, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to $3,000 million
of medium-term notes in Canada, which expires in August 2023. 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 issued $500 million of 1.45% medium-term notes due November 2023 and $300 million of 2.50%
medium-term notes due January 2028.
During 2020, the Company repaid $1,000 million of 2.89% medium term notes and $900 million of 2.05% medium term notes.
US DOLLAR DEBT SECURITIES
During 2021, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to
US$3,000 million of debt securities in the United States, which expires in August 2023. 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 2021, the Company repaid US$500 million of 3.45% 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.
83
Canadian Natural 2021 Annual Report
SCHEDULED DEBT REPAYMENTS
Scheduled debt repayments are as follows:
Year
2022
2023
2024
2025
2026
Thereafter
12. Other Long-Term Liabilities
Asset retirement obligations
Lease liabilities (note 8)
Share-based compensation
Risk management (note 19)
Transportation and processing contracts (1)
Other (2)
Less: current portion
$
$
$
$
$
$
$
$
2021
6,806
1,584
489
85
241
127
9,332
948
$
8,384
$
Repayment
1,000
2,906
1,133
1,518
600
7,624
2020
5,861
1,690
160
160
270
145
8,286
722
7,564
(1) The acquisition of Painted Pony in 2020 included product transportation and processing obligations (note 7).
(2) Includes $48 million (2020 – $72 million) related to the acquisition of the Joslyn oil sands project in 2018, payable in annual installments of $25 million.
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 4.0% (2020 – 3.7%; 2019 – 3.8%) and inflation rates of
up to 2% (December 31, 2020 – 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
2021
2020
$
5,861
$
5,771
$
5
76
(307)
185
1,716
(723)
(7)
6,806
249
5
13
(249)
205
(134)
253
(3)
5,861
184
$
6,557
$
5,677
$
2019
3,886
15
198
(296)
190
412
1,412
(46)
5,771
208
5,563
Canadian Natural 2021 Annual Report
84
Segmented Asset Retirement Obligations
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream and Refining
SHARE-BASED COMPENSATION
2021
2020
$
4,021
$
2,899
821
170
1,793
1
$
6,806
$
787
174
1,999
2
5,861
The liability for share-based compensation includes costs incurred under the Company’s Option and PSU plans. The Company’s
Option Plan provides current employees with the right to elect to receive common shares or a cash payment in exchange for
stock options surrendered. 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 expense (recovery)
Cash payment for stock options surrendered and
PSUs vested
Transferred to common shares
Other
Balance – end of year
Less: current portion
$
$
2021
160
514
(48)
(139)
2
489
329
160
2020
$
297
$
(82)
(39)
(21)
5
160
119
41
$
$
2019
124
223
(2)
(53)
5
297
227
70
Included within share-based compensation liability as at December 31, 2021 was $90 million (2020 – $49 million; 2019 –
$62 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.
$
$
$
$
2021
16.98
53.45
35.5%
4.4%
1.1%
4.7%
$
$
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%
4.2 years
4.3 years
4.4 years
The intrinsic value of vested stock options at December 31, 2021 was $112 million (2020 – $11 million; 2019 – $75 million).
85
Canadian Natural 2021 Annual Report
13. Income Taxes
The provision for income tax was as follows:
Expense (recovery)
2021
2020
Current corporate income tax – North America
$
1,841
$
(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 – North Sea
Deferred income tax
Income tax
(1) Petroleum Revenue Tax.
7
21
(34)
13
1,848
399
—
399
(4)
17
(31)
6
(257)
(181)
—
(181)
$
2,247
$
(438)
$
2019
354
112
44
(89)
13
434
(895)
1
(894)
(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
Income tax provision at statutory rate
Effect on income taxes of:
UK PRT and other taxes
Impact of deductible UK PRT and other taxes on corporate
income tax
Foreign and domestic tax rate differentials
Non-taxable portion of capital gains
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
2021
23.2%
2020
24.1%
$
2,298
$
(211)
$
(21)
11
(11)
(26)
98
—
(110)
16
(26)
18
(25)
11
(52)
(10)
(25)
—
(52)
(62)
(10)
(2)
2019
26.5%
1,313
(76)
32
(48)
(65)
47
(1,618)
—
(41)
(65)
61
$
2,247
$
(438)
$
(460)
Canadian Natural 2021 Annual Report
86
The following table summarizes the temporary differences that give rise to the net deferred income tax liability:
Deferred income tax liabilities
Property, plant and equipment and exploration and evaluation assets
$
12,254
$
11,922
2021
2020
Lease assets
Investments
Investment in North West Redwater Partnership
Unrealized risk management activities
Unrealized foreign exchange gain on long-term debt
Other
Deferred income tax assets
Asset retirement obligations
Lease liabilities
Share-based compensation
Loss carryforwards
Unrealized foreign exchange loss on long-term debt
349
35
850
12
14
78
380
14
767
—
—
8
13,592
13,091
(1,719)
(363)
(22)
(1,268)
—
(3,372)
(1,495)
(388)
(12)
(1,032)
(20)
(2,947)
10,144
Net deferred income tax liability
$
10,220
$
Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows:
2021
2020
2019
Property, plant and equipment and exploration and evaluation
assets
$
184
$
(158)
$
Lease assets
Unrealized foreign exchange 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
Other
(30)
34
19
(213)
25
(10)
202
21
83
—
84
(11)
29
(8)
(13)
6
4
(182)
(22)
174
—
—
The following table summarizes the movements of the net deferred income tax liability during the year:
$
399
$
(181)
$
(775)
414
55
(14)
(317)
(418)
(11)
170
(10)
179
1
(168)
(894)
Balance – beginning of year
$
10,144
$
10,539
$
11,451
2021
2020
2019
Deferred income tax expense (recovery)
Deferred income tax expense included in other
comprehensive loss
Foreign exchange adjustments
Business combinations (note 7)
Balance – end of year
399
1
(2)
(322)
(181)
—
(3)
(211)
(894)
8
(26)
—
$
10,220
$
10,144
$
10,539
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.
87
Canadian Natural 2021 Annual Report
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 year 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 $1,050 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.
14. Share Capital
AUTHORIZED
Preferred shares issuable in a series.
Unlimited number of common shares without par value.
Issued Common Shares
Balance – beginning of year
Issued 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
PREFERRED SHARES
2021
2020
Number
of shares
(thousands)
Amount
Number
of shares
(thousands)
Amount
1,183,866
$
9,606
1,186,857
$
9,533
18,147
—
707
139
3,979
—
(33,644)
(284)
(6,970)
108
21
(56)
1,168,369
$
10,168
1,183,866
$
9,606
Preferred shares are issuable in a series. If issued, the number of shares in each series, and the designation, rights, privileges,
restrictions and conditions attached to the shares will be determined by the Board of Directors of the Company.
DIVIDEND POLICY
The Company has paid regular quarterly dividends in each year since 2001. The dividend policy undergoes periodic review by
the Board of Directors and is subject to change.
On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.75 per common share,
beginning with the dividend payable on April 5, 2022. On November 3, 2021, the Board of Directors approved a 25% increase
in the quarterly dividend to $0.5875 per common share, from $0.47 per common share. On March 3, 2021, the Board of
Directors approved an 11% increase in the quarterly dividend to $0.47 per common share, from $0.425 per common share.
On March 4, 2020, the Board of Directors approved a 13% increase in the quarterly dividend to $0.425 per common share,
from $0.375 per common share. On March 6, 2019, the Board of Directors approved a 12% increase in the quarterly dividend
to $0.375 per common share, from $0.335 per common share. The dividend policy undergoes periodic review by the Board
of Directors and is subject to change.
Canadian Natural 2021 Annual Report
88
NORMAL COURSE ISSUER BID
On March 9, 2021, 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 59,278,474 common shares, over a 12-month period commencing March 11, 2021 and ending March 10, 2022.
For the year ended December 31, 2021, the Company purchased 33,644,400 common shares at a weighted average price of
$46.98 per common share for a total cost of $1,581 million. Retained earnings were reduced by $1,297 million, representing
the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2021,
the Company purchased 10,500,000 common shares at a weighted average price of $64.79 per common share for a total
cost of $680 million.
On March 2, 2022, 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 10% of the public float (as determined in accordance with the
rules of the TSX) of its issued and outstanding common shares. 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 TSX 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.
The following table summarizes information relating to stock options outstanding at December 31, 2021 and 2020:
Outstanding – beginning of year
Granted
Exercised for common shares
Surrendered for cash settlement
Forfeited
Outstanding – end of year
Exercisable – end of year
2021
2020
Stock options
(thousands)
Weighted
average
exercise price
Stock options
(thousands)
Weighted
average
exercise price
48,656
12,547
(18,147)
(1,324)
(3,405)
38,327
7,841
$
$
$
$
$
$
$
37.53
34.39
38.97
40.54
35.73
35.88
39.19
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
The range of exercise prices of stock options outstanding and exercisable at December 31, 2021 was as follows:
Range of exercise prices
$20.76 – $24.99
$25.00 – $29.99
$30.00 – $34.99
$35.00 – $39.99
$40.00 – $44.99
$45.00 – $49.99
$50.00 – $54.24
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
2,697
7,526
2,726
15,227
7,679
1,839
633
38,327
3.31
4.21
3.58
2.59
2.74
1.42
5.83
3.06
$
$
$
$
$
$
$
$
20.95
29.21
32.37
37.46
42.04
45.19
54.24
35.88
566
1
219
3,148
2,894
1,013
$
$
$
$
$
$
— $
7,841
$
20.76
28.63
32.56
37.34
43.23
45.14
—
39.19
89
Canadian Natural 2021 Annual Report
15. Accumulated Other Comprehensive (Loss) Income
The components of accumulated other comprehensive (loss) income, net of taxes, were as follows:
Derivative financial instruments designated as cash flow hedges
Foreign currency translation adjustment
2021
77
$
(78)
(1)
$
2020
69
(61)
8
$
$
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 current long-term debt and long-term debt less cash and cash equivalents divided by
the sum of the carrying value of shareholders' equity plus current long-term debt and long-term debt less cash and cash
equivalents. 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, 2021, the ratio was within the target range at 27%.
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
Less: cash and cash equivalents
Long-term debt, net
Total shareholders’ equity
Debt to book capitalization
$
$
$
2021
14,694
$
744
13,950
36,945
27%
$
$
2020
21,453
184
21,269
32,380
40%
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, 2021, the Company was in compliance with this covenant.
17. Net Earnings Per Common Share
Weighted average common shares outstanding
– basic (thousands of shares)
2021
2020
2019
1,181,250
1,181,768
1,190,977
Effect of dilutive stock options (thousands of shares)
5,307
—
2,129
Weighted average common shares outstanding
– diluted (thousands of shares)
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
1,186,557
1,181,768
1,193,106
$
$
$
7,664
6.49
6.46
$
$
$
(435)
(0.37)
(0.37)
$
$
$
5,416
4.55
4.54
In 2021, the Company excluded 3,496,000 potentially anti-dilutive stock options from the calculation of diluted earnings per
common share (year ended December 31, 2020 – 44,117,000; 2019 – 36,834,000).
Canadian Natural 2021 Annual Report
90
895
70
(53)
912
(76)
836
Total
744
3,111
309
140
(803)
(3,064)
(1,717)
Total
184
2,190
305
691
(667)
(2,346)
(1,922)
18. Interest and Other Financing Expense
2021
2020
2019
Interest and other financing expense:
Long-term debt
Lease liabilities
Less: amounts capitalized on qualifying assets
Total interest and other financing expense
Total interest income and other
$
681
$
785
$
62
—
743
(32)
711
67
(24)
828
(72)
$
756
$
Net interest and other financing expense
$
19. Financial Instruments
The carrying amounts of the Company’s financial instruments by category were as follows:
Asset (liability)
Financial
assets at
amortized cost
Fair value
through
profit or loss
Derivatives
used for
hedging
Financial
liabilities at
amortized cost
2021
— $
—
— $
—
— $
—
Cash and cash equivalents
$
744
$
Accounts receivable
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
Long-term debt (2)
3,111
—
—
—
—
—
—
309
—
—
—
(64)
—
305
—
—
—
(52)
—
—
140
—
—
(21)
—
119
2020
—
136
—
—
(108)
—
28
—
—
(803)
(3,064)
(1,632)
—
—
(667)
(2,346)
(1,762)
Asset (liability)
Financial
assets at
amortized cost
Fair value
through
profit or loss
Derivatives
used for
hedging
Financial
liabilities at
amortized cost
— $
—
— $
—
— $
—
Cash and cash equivalents
$
184
$
Accounts receivable
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
Long-term debt (2)
2,190
—
555
—
—
—
—
$
2,929
$
253
$
(21,453)
(21,453)
$
(26,228)
$
(23,018)
(1) Includes $1,584 million of lease liabilities (December 31, 2020 – $1,690 million) and $48 million of deferred purchase consideration payable over the next
two years (December 31, 2020 – $72 million).
(2) Includes the current portion of long-term debt.
91
Canadian Natural 2021 Annual Report
$
3,855
$
245
$
(14,694)
(14,694)
$
(20,193)
$
(15,974)
The carrying amounts of the Company’s financial instruments approximated their fair value, except for fixed rate long-term
debt. The fair values of the Company’s investments, recurring other long-term assets (liabilities) and fixed rate long-term debt
are outlined below:
Asset (liability) (1) (2)
Investments (3)
Other long-term assets
Other long-term liabilities
Fixed rate long-term debt (6) (7)
Asset (liability) (1) (2)
Investments (3)
Other long-term assets
Other long-term liabilities
Fixed rate long-term debt (6) (7)
Carrying amount
Fair value
2021
$
$
$
$
309
140
(133)
(13,554)
Carrying amount
$
$
$
$
305
691
(232)
(14,254)
$
$
$
$
$
$
$
$
Level 1
Level 2
Level 3 (4)
309
$
— $
— $
(15,420)
$
— $
140
(85)
$
$
— $
—
—
(48)
—
2020
Fair value
Level 1
Level 2
Level 3 (4) (5)
305
$
— $
— $
(16,598)
$
— $
136
(160)
$
$
— $
—
555
(72)
—
(1) Excludes financial assets and liabilities where the carrying amount approximates fair value due to the short-term nature of the asset orliability (cash and
cash equivalents, accounts receivable, accounts payable and accrued liabilities, and purchase consideration payable).
(2) There were no transfers between Level 1, 2 and 3 financial instruments.
(3) The fair values of the investments are based on quoted market prices.
(4) The fair value of the deferred purchase consideration included in other long-term liabilities is based on the present value of future cash payments.
(5) The fair value of NWRP subordinated debt was based on the present value of future cash receipts.
(6) The fair value of fixed rate long-term debt has been determined based on quoted market prices.
(7) Includes the current portion of fixed rate long-term debt.
Canadian Natural 2021 Annual Report
92
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 (1)
Crude oil (1)
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
2021
2020
$
(41)
(10)
(13)
(21)
140
55
$
5
$
(72)
135
(13)
55
$
(45)
—
(7)
(108)
136
(24)
5
(131)
131
(29)
(24)
$
$
$
$
(1) Commodity financial instruments acquired from Storm and Painted Pony in 2021 and 2020, respectively.
During 2021, the Company's ineffectiveness from cash flow hedges was $nil (2020 – loss of $1 million, 2019 – gain
of $3 million).
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
2021
$
(24)
$
(12)
82
9
55
(67)
$
122
$
2020
178
(32)
(168)
(2)
(24)
(126)
102
(1) Includes the fair value movement of commodity financial instruments included in acquisitions (note 7).
93
Canadian Natural 2021 Annual Report
Net loss (gain) from risk management activities for the years ended December 31, were as follows:
Net realized risk management loss
Net unrealized risk management loss (gain)
FINANCIAL RISK FACTORS
2021
17
19
36
$
$
2020
32
$
(39)
(7)
$
2019
64
13
77
$
$
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.
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, 2021, the Company had no
significant 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, 2021 the Company had the following cross currency swap contract outstanding:
Cross Currency Swap
Jan 2022
– Mar 2038
US$550
1.170
6.25%
Remaining term
Amount
Exchange
rate (US$/C$)
Interest
rate (US$)
Interest
rate (C$)
5.76%
The cross currency swap derivative financial instrument was designated as a hedge at December 31, 2021 and was classified
as a cash flow hedge.
In addition to the cross currency swap contracts noted above, at December 31, 2021, the Company had US$1,429 million of
foreign currency forward contracts outstanding, with original terms of up to 90 days, including US$901 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.
Canadian Natural 2021 Annual Report
94
FINANCIAL INSTRUMENT SENSITIVITIES
The following table summarizes the annualized sensitivities of the Company’s 2021 net earnings and other comprehensive
income to changes in the fair value of financial instruments outstanding as at December 31, 2021, resulting from changes in
the specified variable, with all other variables held constant. These sensitivities are prepared on a different basis than those
sensitivities disclosed in the Company’s other continuous disclosure documents, are limited to the impact of changes in a
specified variable applied to financial instruments only and do not represent the impact of a change in the variable on the
operating results of the Company taken as a whole. Further, these sensitivities are theoretical, as changes in one variable
may contribute to changes in another variable, which may magnify or counteract the sensitivities. In addition, changes in fair
value generally cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may
not be linear.
Interest rate risk
Increase interest rate 1%
Decrease interest rate 1%
Foreign currency exchange rate risk
Weakening of the Canadian dollar by US$0.01
Strengthening of the Canadian dollar by US$0.01
2021 (1)
2020 (1)
Increase
(decrease)
to net
earnings
Increase
(decrease)
to other
comprehensive
income
Increase
(decrease)
to net
earnings
Increase
(decrease)
to other
comprehensive
income
$
$
$
$
(13) $
13
$
(116) $
114
$
(29) $
39
$
(53) $
53
$
— $
— $
(126) $
123
$
(17)
20
—
—
(1) Based on the Company’s contracted natural gas and crude oil financial instruments at December 31, 2021 and December 31, 2020, a movement of
$0.10/MMBtu, $0.10/Mcf or $1.00/bbl would not have a significant impact on net earnings or other comprehensive income.
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, 2021, 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, 2020 – 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, 2021, the Company had net risk management assets
of $140 million with specific counterparties related to derivative financial instruments (December 31, 2020 – $129 million). The
carrying amount of financial assets approximates the maximum credit exposure.
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities.
Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources
of capital, consisting primarily of cash flow from operating activities, available credit facilities, commercial paper and access to
debt capital markets, to meet obligations as they become due. The Company believes it has adequate bank credit facilities to
provide liquidity to manage fluctuations in the timing of the receipt and/or disbursement of operating cash flows.
95
Canadian Natural 2021 Annual Report
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
$
$
$
$
$
803
3,064
1,000
282
650
$
$
$
$
$
— $
— $
2,906
181
583
$
$
$
— $
— $
3,251
430
1,503
$
$
$
—
—
7,624
824
3,971
(1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
(2) Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $185 million; one to less
than two years, $149 million; two to less than five years, $426 million; and thereafter, $824 million.
(3) 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, 2021.
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, 2021:
2022
2023
2024
2025
2026
Thereafter
Product transportation and
processing (1) (2)
North West Redwater Partnership
service toll (3)
Offshore vessels and equipment
Field equipment and power
Other
$
$
$
$
$
122
62
25
37
$
$
$
$
967
$ 1,107
$
$
914
121
$
$
870
119
$
$
816
$
10,028
97
$
3,671
123
— $
— $
— $
— $
21
27
$
$
21
22
$
$
21
20
$
$
21
15
$
$
—
225
—
(1) Includes commitments pertaining to a 20-year product transportation agreement on the Trans Mountain Pipeline Expansion.
(2) The acquisition of Storm in 2021 and Painted Pony in 2020 included approximately $298 million and $2,400 million of product transportation and processing
commitments, respectively (note 7).
(3) Pursuant to the processing agreements, the Company pays its 25% pro rata share of the debt component of the monthly fee-for-service toll. Included in
the toll is $1,486 million of interest payable over the 40-year tolling period, ending in 2058 (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.
Canadian Natural 2021 Annual Report
96
21. Supplemental Disclosure of Cash Flow Information
Changes in non-cash working capital:
Accounts receivable
Current income tax (liabilities) assets
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
2021
2020
2019
$
(850)
$
284
$
(1,310)
1,918
(487)
39
—
80
525
(154)
(295)
98
(56)
(117)
(147)
(254)
(62)
(164)
(194)
2
117
39
265
(23)
$
$
$
$
$
1,071
$
(549)
$
(1,268)
964
107
$
(166)
$
(383)
1,071
$
(549)
$
2021
2020
12
$
(11)
1
$
36
$
(31)
5
$
(1,033)
(235)
(1,268)
2019
73
—
73
(1) Included in Other long-term liabilities at December 31, 2021 is $48 million of deferred purchase consideration payable over the next two years
(December 31, 2020 – $72 million; 2019 - $95 million).
97
Canadian Natural 2021 Annual Report
The following table summarizes movements in the Company's liabilities arising from financing activities for the years' ended
December 31, 2021 and 2020:
Cash flow
hedges on
US dollar
debt
securities
Lease
liabilities
Liabilities
from
financing
activities
Long-term
debt
At December 31, 2019
$
20,982
$
(199)
$
1,809
$
22,592
Changes from financing cash flows:
Issue of long-term debt, net (1)
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 (2)
719
(397)
—
—
397
—
(248)
—
—
166
—
—
—
5
—
—
—
(225)
—
148
(42)
719
(397)
166
(225)
397
148
(285)
At December 31, 2020
21,453
(28)
1,690
23,115
Changes from financing cash flows:
Repayment of long-term debt, net (1)
Repayment of Storm long-term debt
Payment of lease liabilities
Non-cash changes:
Assumption of Storm long-term debt
Lease additions
Changes in foreign exchange and fair value (2)
(6,779)
(183)
—
183
—
20
—
—
—
—
—
(91)
—
—
(209)
—
88
15
(6,779)
(183)
(209)
183
88
(56)
At December 31, 2021
$
14,694
$
(119)
$
1,584
$
16,159
(1) Includes original issue discounts and premiums, and directly attributable transaction costs.
(2) Includes foreign exchange (gain) loss, changes in the fair value of cash flow hedges on US dollar debt securities, the amortization of original issue
discounts and premiums and directly attributable transaction costs, and derecognition of lease liabilities.
Canadian Natural 2021 Annual Report
98
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)
2021
2020
2019
2021
2020
2019
2021
2020
2019
2021
2020
2019
2021
2020
2019
2021
2020
2019
2021
2020
2019
North America
North Sea
Offshore Africa
Oil Sands Mining
and Upgrading
Midstream
and Refining
Inter–segment elimination
and Other
Total
Segmented product sales
Crude oil and NGLs (1)
$ 14,478 $
7,480 $ 9,679 $ 607 $
417 $ 860 $
420 $
318 $
632
$ 14,033 $ 7,389 $ 11,340 $
78 $
83 $
88 $
(360) $
(108) $
351 $ 29,256 $ 15,579 $ 22,950
3,569
3,780
3,326
160
277
308
142
190
242
1,838
1,784
1,656
Segmented expenses
Production
Transportation, blending and
feedstock (1) (3)
Depletion, depreciation and
amortization
Asset retirement obligation
accretion
Risk management activities
(commodity derivatives)
Gain on acquisitions
Income from NWRP
Equity loss from investments
Natural gas
Other income and revenue (2)
Total segmented product sales
Less: royalties
2,484
119
17,081
(1,694)
1,242
1,150
41
6
8,763
10,835
(503)
(998)
Segmented revenue
15,387
8,260
9,837
5
(1)
611
(1)
610
12
3
432
(1)
431
57
5
922
(2)
920
2,963
2,510
2,425
383
321
391
4,772
3,393
2,935
7
15
19
31
7
458
(21)
437
91
1
42
18
378
(16)
362
67
8
707
(42)
665
103
109
1
2
101
97
29
(478)
—
—
(20)
(217)
—
—
95
49
—
—
—
21
—
—
—
—
30
—
—
—
—
28
—
—
—
—
6
—
—
—
—
6
—
—
—
—
6
—
—
—
—
359
306
Total segmented expenses
10,956
9,543
8,830
571
643
746
240
300
Segmented earnings (loss)
$ 4,431 $
(1,283) $ 1,007 $
39 $
(212) $ 174 $
197 $
62 $
Non–segmented expenses
Administration
Share-based compensation
Interest and other financing
expense
Risk management activities
(other)
Foreign exchange gain
(Gain) loss from investments
Total non–segmented expenses
Earnings (loss) before taxes
Current income tax
Deferred income tax
Net earnings (loss)
(1) 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.
(2) 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.
(3) Includes a provision of $143 million relating to the Keystone XL pipeline project in the North America segment in 2020.
99
Canadian Natural 2021 Annual Report
3,414
3,114
3,276
234
184
56
7,152
6,280
6,277
1,505
881
1,306
550
181
437
6,604
4,498
4,699
—
73
—
139
—
6
14,106
7,528
11,346
(1,081)
(78)
(481)
13,025
7,450
10,865
57
—
—
—
—
72
—
—
—
—
61
—
—
—
— (400)
—
202
285
—
285
15
—
—
—
—
—
—
681
759
—
759
15
—
—
—
—
399
—
—
88
—
88
20
—
14
—
—
—
—
287
321
196
3
(161)
—
(161)
67
(231)
—
—
—
—
—
—
182
31
105
—
105
48
27
—
—
—
—
—
—
75
6,814
5,851
6,299
380
(164)
493
18,816
16,792
17,048
$ 6,211 $ 1,599 $ 4,566 $ 360 $
(95) $ (233) $
3 $
30 $
3 $ 11,241 $
101 $ 5,823
145
—
496
—
496
2,716
882
1,478
434
1,419
25
32,854
17,491
24,394
(2,797)
(598)
(1,523)
30,057
16,893
22,871
—
—
—
—
—
—
5,724
6,046
5,546
185
205
190
49
—
—
287
344
223
836
28
(570)
6
867
4,956
434
(894)
(20)
(217)
—
—
391
(82)
756
13
(275)
171
974
(873)
(257)
(181)
29
(478)
(400)
—
366
514
711
7
(127)
(141)
1,330
9,911
1,848
399
$ 7,664 $
(435) $ 5,416
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.
(millions of Canadian dollars)
2021
2020
2019
2021
2020
2019
2021
2020
2019
2021
2020
2019
2021
2020
2019
2021
2020
2019
2021
2020
2019
North America
North Sea
Offshore Africa
Oil Sands Mining
and Upgrading
Midstream
and Refining
Inter–segment elimination
and Other
Total
Crude oil and NGLs (1)
$ 14,478 $
7,480 $ 9,679 $ 607 $
417 $ 860 $
420 $
318 $
632
$ 14,033 $ 7,389 $ 11,340 $
78 $
83 $
88 $
(360) $
(108) $
351 $ 29,256 $ 15,579 $ 22,950
—
—
88
—
88
20
—
14
—
—
—
—
287
321
196
3
(161)
—
(161)
67
(231)
—
—
—
—
—
—
(164)
182
31
105
—
105
48
27
—
—
—
—
—
—
75
145
—
496
—
496
2,716
882
1,478
434
1,419
25
32,854
17,491
24,394
(2,797)
(598)
(1,523)
30,057
16,893
22,871
56
7,152
6,280
6,277
437
6,604
4,498
4,699
—
—
—
—
—
—
5,724
6,046
5,546
185
205
29
(478)
(400)
—
(20)
(217)
—
—
190
49
—
—
287
493
18,816
16,792
17,048
57
—
—
—
—
72
—
—
—
—
61
—
—
—
— (400)
15
—
—
—
—
399
15
—
—
—
—
—
380
Natural gas
Other income and revenue (2)
Total segmented product sales
Less: royalties
2,484
119
17,081
(1,694)
1,242
1,150
41
6
8,763
10,835
(503)
(998)
Segmented revenue
15,387
8,260
9,837
5
(1)
611
(1)
610
12
3
432
(1)
431
57
5
922
(2)
920
42
18
378
(16)
362
67
8
707
(42)
665
—
73
—
139
—
6
14,106
7,528
11,346
(1,081)
(78)
(481)
13,025
7,450
10,865
—
681
759
—
759
—
202
285
—
285
2,963
2,510
2,425
383
321
391
103
109
3,414
3,114
3,276
234
184
4,772
3,393
2,935
7
15
19
1
2
1,505
881
1,306
550
181
3,569
3,780
3,326
160
277
308
142
190
242
1,838
1,784
1,656
31
7
458
(21)
437
91
1
6
—
—
—
—
101
97
29
(478)
—
—
(20)
(217)
—
—
95
49
—
—
—
21
—
—
—
—
30
—
—
—
—
28
—
—
—
—
6
—
—
—
—
6
—
—
—
—
359
306
Segmented product sales
Segmented expenses
Production
Transportation, blending and
feedstock (1) (3)
Depletion, depreciation and
amortization
Asset retirement obligation
accretion
Risk management activities
(commodity derivatives)
Gain on acquisitions
Income from NWRP
Equity loss from investments
Non–segmented expenses
Administration
Share-based compensation
Interest and other financing
expense
(other)
Risk management activities
Foreign exchange gain
(Gain) loss from investments
Total non–segmented expenses
Earnings (loss) before taxes
Current income tax
Deferred income tax
Net earnings (loss)
Total segmented expenses
10,956
9,543
8,830
571
643
746
240
300
6,814
5,851
6,299
Segmented earnings (loss)
$ 4,431 $
(1,283) $ 1,007 $
39 $
(212) $ 174 $
197 $
62 $
$ 6,211 $ 1,599 $ 4,566 $ 360 $
(95) $ (233) $
3 $
30 $
3 $ 11,241 $
101 $ 5,823
366
514
711
7
(127)
(141)
1,330
9,911
1,848
399
391
(82)
756
13
(275)
171
974
(873)
(257)
(181)
344
223
836
28
(570)
6
867
4,956
434
(894)
$ 7,664 $
(435) $ 5,416
Canadian Natural 2021 Annual Report
100
CAPITAL EXPENDITURES (1)
2021
Non-cash
and fair value
changes (2)
Net
expenditures
Capitalized
costs
Net
expenditures
2020
Non-cash
and fair value
changes (2)
Capitalized
costs
Exploration and
evaluation assets
Exploration and
Production
North America
Offshore Africa
Oil Sands Mining
and Upgrading
Property, plant and
equipment
Exploration and
Production
North America (3) (4)
North Sea
Offshore Africa
Oil Sands Mining
and Upgrading (5)
Midstream and
Refining
Head office
$
$
(7) $
8
—
1
2,486
173
54
2,713
1,747
9
23
4,492
4,493
$
(36) $
(43) $
—
(150)
(186)
1,351
38
(6)
1,383
(601)
—
—
782
596
$
8
(150)
(185)
3,837
211
48
4,096
1,146
9
23
5,274
5,089
$
(7) $
12
(150) $
3
—
5
—
(147)
(157)
15
—
(142)
999
122
87
1,208
1,323
5
19
2,555
2,560
371
(21)
7
357
(629)
1
—
(271)
(418) $
$
1,370
101
94
1,565
694
6
19
2,284
2,142
(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 $771 million for the acquisition of Storm in 2021.
(4) Includes cash consideration paid of $111 million for the acquisition of Painted Pony in 2020.
(5) Net expenditures includes the acquisition of a 5% net carried interest on an existing oil sands lease during 2021, 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
2021
2020
30,645
1,561
1,332
40
42,016
886
185
76,665
$
$
29,094
1,624
1,407
81
41,567
1,301
202
75,276
$
$
101
Canadian Natural 2021 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
2021
2020
2
$
2
$
2019
2
2021
2020
2019
2
10
6
19
37
$
$
2
9
4
14
29
$
$
2
8
6
20
36
$
$
$
(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 2021 Annual Report
102
Supplementary Oil & Gas Information for the Fiscal
Year Ended December 31, 2021 (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, 2021, 2020, 2019 and 2018 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, 2021,
2020, 2019 and 2018 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 2021 and 2020 reserves for
SEC requirements.
Crude Oil and NGLs
Natural Gas
Canadian
Light Sweet
Cromer
LSB
Brent
Edmonton
C5+
Henry Hub
AECO
BC
Westcoast
Station 2
(C$/bbl)
(C$/bbl)
(US$/bbl)
(C$/bbl)
(US$/MMBtu)
(C$/MMBtu)
(C$/MMBtu)
WTI
(US$/bbl)
WCS
(C$/bbl)
2021:
66.34
67.68
77.87
78.17
68.92
83.05
3.68
3.39
2.90
2020:
39.77
34.84
45.02
45.55
43.43
50.41
2.16
2.17
2.10
A foreign exchange rate of US$0.7972/C$1.00 was used in the 2021 evaluation (2020 - US$0.7462/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, 2021, 2020, 2019 and 2018, 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, 2021, 2020, 2019 and 2018, 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.
103
Canadian Natural 2021 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, 2021, 2020, 2019 and 2018:
North America
Synthetic
Crude Oil Bitumen (2)
Crude
Oil &
NGLs
North
America
Total
North
Sea
Offshore
Africa
1,469
604
7,734
114
Crude Oil and NGLs (MMbbl) (1)
Net Proved Reserves
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
Reserves, December 31, 2020
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Economic revisions due to prices (5)
Revisions of prior estimates
5,661
334
—
—
—
(137)
(288)
(17)
5,554
708
—
—
—
(151)
701
36
6,847
—
—
—
—
(150)
(927)
174
18
169
666
—
(81)
3
(27)
2,216
8
49
—
—
(109)
207
41
2,413
101
19
—
—
(103)
(296)
155
Reserves, December 31, 2021
5,944
2,289
Net proved developed reserves
December 31, 2018
December 31, 2019
December 31, 2020
December 31, 2021
5,661
5,452
6,770
5,929
461
661
628
584
12
12
2
—
(49)
—
17
598
10
9
28
—
(45)
(94)
20
525
14
14
52
—
(45)
108
40
708
378
354
285
370
364
181
668
—
(267)
(285)
(28)
8,368
726
58
28
—
(305)
814
97
9,785
115
33
52
—
(297)
(1,115)
369
8,941
6,500
6,466
7,682
6,883
—
—
—
—
(10)
(1)
3
105
—
—
—
—
(8)
(12)
3
87
—
—
—
—
(6)
1
(3)
79
37
38
32
39
Total
7,919
364
181
668
—
(285)
(285)
(19)
8,544
726
58
28
—
71
—
—
—
—
(7)
1
6
70
—
—
—
—
(6)
(320)
3
4
71
—
—
—
—
(5)
(4)
2
64
34
39
37
38
805
103
9,943
115
33
52
—
(309)
(1,118)
368
9,083
6,571
6,543
7,751
6,960
(1) Information in the reserves data tables may not add due to rounding.
(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.
(5) Reflects the impact of increased royalties at Oil Sands Mining and Upgrading (SCO) and thermal Bitumen due to higher bitumen pricing resulting in higher
royalties and lower net reserves.
Canadian Natural 2021 Annual Report
104
2021 total proved Crude Oil and NGLs reserves decreased by 860 MMbbl:
■ Extensions and discoveries: Increase of 115 MMbbl primarily due to extension drilling/future offset additions at various
Bitumen properties.
■
Improved recovery: Increase of 33 MMbbl primarily due to increased recovery of thermal Bitumen at Jackfish and Kirby
properties and infill drilling/future offset additions at various Crude Oil and natural gas (NGLs) properties.
■ Purchases of reserves in place: Increase of 52 MMbbl primarily due to natural gas (NGLs) acquisitions in northeast
British Columbia.
■ Production: Decrease of 309 MMbbl.
■ Economic revisions due to prices: Decrease of 1,118 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and
thermal Bitumen properties due to higher bitumen pricing resulting in higher royalties and lower net reserves.
■ Revisions of prior estimates: Increase of 368 MMbbl primarily due to transfers from beyond the 50-year reserves life cutoff
at Oil Sands Mining and Upgrading (SCO) and improved performance at various North America and Offshore Africa Crude
Oil, Bitumen and natural gas (NGLs) properties.
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.
■ Revisions of prior estimates: Increase of 103 MMbbl primarily due to improved mine performance and mine model changes
at Oil Sands Mining and Upgrading (SCO) and improved performance at North America, North Sea and Offshore Africa
Crude Oil, Bitumen and various natural gas (NGLs) properties.
2019 total proved Crude Oil and NGLs reserves increased by 625 MMbbl:
■ Extensions and discoveries: Increase of 364 MMbbl primarily due to 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.
105
Canadian Natural 2021 Annual Report
Natural Gas (Bcf) (1)
Net Proved Reserves
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
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, 2021
Net proved developed reserves
December 31, 2018
December 31, 2019
December 31, 2020
December 31, 2021
North
America
North
Sea
Offshore
Africa
4,306
106
202
34
—
(511)
246
346
4,728
173
159
2,614
(4)
(515)
97
402
7,655
545
161
1,654
(1)
(581)
712
1,139
11,285
2,382
2,342
3,116
4,469
27
—
—
—
—
(9)
—
(2)
16
—
—
—
—
(4)
—
—
12
—
—
—
—
(1)
—
(3)
8
23
11
6
3
21
—
—
—
—
(8)
2
23
38
—
—
—
—
(5)
4
(3)
34
—
—
—
—
(4)
(4)
—
25
12
28
22
20
Total
4,354
106
202
34
—
(528)
248
367
4,782
173
159
2,615
(4)
(524)
100
399
7,701
545
161
1,654
(1)
(587)
708
1,136
11,318
2,417
2,381
3,144
4,492
(1) Information in the reserves data tables may not add due to rounding.
2021 total proved Natural Gas reserves increased by 3,617 Bcf primarily due to the following:
■ Extensions and discoveries: Increase of 545 Bcf primarily due to extension drilling/future offsets additions in the Montney
formation of northwest Alberta and northeast British Columbia.
■
Improved recovery: Increase of 161 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of
northwest Alberta and northeast British Columbia.
■ Purchases of reserves in place: Increase of 1,654 Bcf primarily due to the Storm Resources Ltd. and other acquisitions in
northeast British Columbia.
■ Sales of reserves in place: Decrease of 1 Bcf from Natural Gas properties in North America.
■ Production: Decrease of 587 Bcf.
■ Economic revisions due to prices: Increase of 708 Bcf primarily due to increased Natural Gas price in North America.
■ Revisions of prior estimates: Increase of 1,136 Bcf primarily due to overall positive revisions in several North American
core areas as a result of increased performance and category transfers from probable to proved.
Canadian Natural 2021 Annual Report
106
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.
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.
Capitalized Costs Related to Crude Oil and Natural Gas Activities
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
2021
$
$
North
America
124,690
2,159
126,849
(61,231)
North
Sea
7,438
—
7,438
(5,951)
Offshore
Africa
3,980
$
$
91
4,071
(2,923)
Total
136,108
2,250
138,358
(70,105)
Net capitalized costs
$
65,618
$
1,487
$
1,148
$
68,253
(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
$
$
83
4,046
(2,822)
Total
130,953
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
2019
$
$
North
America
117,643
2,510
120,153
(52,824)
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
107
Canadian Natural 2021 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
2021
North
America
North
Sea
Offshore
Africa
Total
$
1,371
$
— $
— $
1,371
26
4
4,301
$
5,702
$
—
8
48
56
$
—
—
208
208
$
2020
North
America
North
Sea
Offshore
Africa
$
750
$
— $
— $
15
22
2,338
$
3,125
$
—
—
104
104
—
15
94
$
109
$
2019
26
12
4,557
5,966
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
$
—
33
233
266
$
91
71
5,269
8,836
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,
2021, 2020 and 2019 are summarized in the following tables:
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
2021
North
America
North
Sea
Offshore
Africa
Total
$
23,111
$
611
$
438
$
24,160
(6,377)
(1,176)
(5,407)
(158)
—
(2,317)
(383)
(7)
(160)
(21)
33
(29)
(91)
(1)
(142)
(6)
—
(50)
(6,851)
(1,184)
(5,709)
(185)
33
(2,396)
$
7,676
$
44
$
148
$
7,868
Canadian Natural 2021 Annual Report
108
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
(millions of Canadian dollars)
Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
Production
Transportation
Depletion, depreciation and amortization
Asset retirement obligation accretion
Petroleum revenue tax
Income tax
Results of operations
2020
North
America
North
Sea
Offshore
Africa
Total
$
12,520
$
432
$
354
$
13,306
(5,624)
(1,258)
(5,564)
(169)
—
23
(321)
(15)
(277)
(30)
31
72
$
(72)
$
(108)
$
2019
(103)
(1)
(190)
(6)
—
(13)
41
(6,048)
(1,274)
(6,031)
(205)
31
82
$
(139)
North
America
North
Sea
Offshore
Africa
Total
$
17,348
$
920
$
676
$
18,944
(5,701)
(968)
(4,982)
(156)
—
(1,468)
(391)
(19)
(308)
(28)
88
(105)
(109)
(2)
(242)
(6)
—
(79)
$
4,073
$
157
$
238
$
(6,201)
(989)
(5,532)
(190)
88
(1,652)
4,468
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":
109
Canadian Natural 2021 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
2021
North
America
North
Sea
Offshore
Africa
Total
$ 679,123
$
7,791
$
5,581
$ 692,495
(238,144)
(77,375)
(81,860)
281,744
(201,227)
(4,074)
(1,857)
(719)
1,141
(142)
(1,818)
(1,142)
(565)
2,056
(788)
(244,036)
(80,374)
(83,144)
284,941
(202,157)
Standardized measure of future net cash flows
$
80,517
$
999
$
1,268
$
82,784
(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)
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
(203,599)
(72,935)
(27,178)
100,481
(74,395)
(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
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)
2021
2020
2019
Sales of crude oil and natural gas produced, net of production costs
$
(16,149) $
(6,127) $
(11,807)
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
Canadian Natural 2021 Annual Report
74,558
2,948
(2,773)
4,010
(1)
(186)
3,460
6,638
(17,232)
55,273
27,511
(46,055)
626
(153)
947
(1)
5,295
7,718
(4,830)
6,566
(36,014)
63,525
$
82,784
$
27,511
$
(3,515)
5,883
(1,889)
7,418
—
(3,384)
8,062
447
1,984
3,199
60,326
63,525
110
Ten Year Review
Years ended December 31
FINANCIAL INFORMATION (C$ millions, except per share amounts)
Net earnings (loss)
7,664
2021
2020
(435)
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 (1)
Balance sheet information (C$ millions)
Adjusted working capital (2)
Exploration and evaluation assets
Property, plant and equipment, net
Total assets
Long-term debt (3)
Shareholders' equity
SHARE INFORMATION
Common shares outstanding (thousands)
Weighted average shares outstanding
- basic (thousands)
Weighted average shares outstanding
- diluted (thousands)
Dividends declared ($/share) (4)
Trading statistics
TSX – C$
Trading volume (thousands)
Share Price ($/share)
High
Low
Close
NYSE – US$
Trading volume (thousands)
Share Price ($/share)
High
Low
Close
RATIOS
Debt to book capitalization (5)
After-tax return on average capital
employed (6)
Daily production before royalties per ten
thousand common shares (BOE/d)
Total proved plus probable reserves per
common share (BOE) (7)
Net asset value ($/share) (9)
2019
2018
2017
2016
2015
2014
2013
2012
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
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
1,892
1.72
1.72
6,209
6,013
5.48
5.47
5,927
6,308
(1,574)
2,609
46,487
51,754
9,661
25,772
(1,264)
2,611
44,028
48,980
8,736
24,283
6.49
6.46
14,478
13,733
11.63
11.57
3,703
4,908
(480)
2,250
66,400
76,665
14,694
36,945
(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
1,168,369 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
1,181,250 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
1,186,557 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
0.42
1.10
0.92
0.58
2.00
1.50
1.70
1.34
0.94
0.90
1,568,872 1,866,414
904,013
806,254
588,422
653,727
728,033
717,580
683,003
729,700
55.59
28.67
53.45
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
795,605 1,058,121
679,697
796,971
608,008
892,220
951,311
812,521
645,403
844,647
44.33
22.40
42.25
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
27%
40%
37%
39%
41%
39%
38%
33%
27%
26%
16%
—%
11%
10.6
9.8
9.3
6%
9.0
14.5
119.36
13.5
71.62
12.0
97.09
11.1
101.89
6%
—%
(1)%
10%
7.9
9.7
7.3
8.3
7.8
8.3
7.2
8.1
7%
6.2
7.3
7%
6.0
7.2
81.41
74.77
73.39
78.99
72.41
62.38
(1) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
(2) Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
(3) Long-term debt includes current portion of long-term debt.
(4) On March 2, 2022, the Board of Directors approved a quarterly dividend of $0.75 per common share, an increase from the previous quarterly dividend of
$0.5875 per common share. The dividend is payable on April 5, 2022.
(5) Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
(6) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
(7) Based upon company gross reserves (forecast price and costs, before royalties), using year end common shares outstanding.
(8) 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.
111
Canadian Natural 2021 Annual Report
Years ended December 31
COMPANY NET RESERVES (8)
Crude oil and NGLs (MMbbl)
Company net total proved reserves
North America
North Sea
Offshore Africa
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
8,740
8,980
8,129
7,163
6,423
3,909
3,645
3,380
3,290
3,268
79
64
96
70
109
70
119
72
120
70
134
74
158
74
204
78
224
80
227
85
8,883
9,147
8,307
7,354
6,613
4,117
3,877
3,662
3,594
3,580
Company net proved plus probable reserves (after royalties)
North America
North Sea
Offshore Africa
10,883
11,151
10,231
9,456
8,353
6,015
5,806
5,609
5,135
5,119
117
85
160
94
175
93
186
98
180
102
252
108
284
113
308
119
325
122
332
127
11,085
11,405
10,499
9,740
8,635
6,375
6,203
6,036
5,582
5,578
Natural gas (Bcf)
Company net total proved reserves (after royalties)
North America
North Sea
Offshore Africa
11,076
8,373
5,795
6,005
6,032
5,845
5,383
5,054
3,684
3,540
8
25
12
32
16
37
27
21
21
15
41
23
39
21
83
36
91
38
82
48
11,109
8,417
5,849
6,053
6,068
5,909
5,443
5,173
3,813
3,670
Company net total proved plus probable reserves (after royalties)
North America
North Sea
Offshore Africa
Total company net proved reserves
(after royalties) (MMBOE)
Total company net proved plus probable
reserves (after royalties) (MMBOE)
OPERATING INFORMATION
Daily production (before royalties) (10)
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 (6) (11)
Average crude oil and NGLs price ($/bbl) (12)
Average natural gas price ($/Mcf)
Average SCO price ($/bbl) (13)
18,315
13,884
8,556
8,681
8,454
7,888
7,361
6,791
5,138
4,907
11
39
17
48
21
52
38
44
32
47
85
55
96
50
114
68
125
70
102
76
18,364
13,949
8,630
8,763
8,533
8,028
7,507
6,973
5,333
5,085
10,734
10,549
9,282
8,363
7,625
5,102
4,784
4,524
4,230
4,191
14,146
13,730
11,938
11,202
10,057
7,713
7,454
7,198
6,471
6,426
473
448
18
14
952
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
1,680
1,450
1,443
1,490
1,601
1,622
1,663
1,527
1,130
1,198
3
12
1,695
1,235
63.71
4.07
77.95
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
(9) Net present value, discounted at 10%, of the future net revenue (before income tax and excluding the ARO for existing development as at December 31,
2021) 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 (2021 to 2015, $300/acre from 2014 to 2012), less net debt divided
by 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.
(10) Numbers may not add due to rounding.
(11) Product prices reflect realized product prices before blending costs, transportation costs and exclude risk management activities.
(12) Average crude oil and NGLs pricing excludes SCO.
(13) For years 2017 to 2021, average SCO product price includes AOSP realized product prices net of blending and feedstock costs.
Canadian Natural 2021 Annual Report
112
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)
Corporate Director
Calgary, Alberta
N. Murray Edwards, O.C.
Corporate Director
St. Moritz, Switzerland
*Dawn L. Farrell (1)(3)(4)
Corporate Director
Calgary, Alberta
*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
*Honourable Frank J. McKenna, P.C., O.C., O.N.B., Q.C. (2)(4)
Deputy Chair, TD Bank Group
Cap Pelé, New Brunswick
*David A. Tuer (1)(5)
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 to be independent by the Nominating, Governance and Risk
Committee of the Board of Directors and pursuant to the independent
standards established under National
the
New York Stock Exchange Corporate Governance Listing Standards.
Instrument 58-101
and
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
Calvin J. Bast
Senior Vice-President, Production
Bryan C. Bradley
Senior Vice-President, Marketing
Trevor J. Cassidy
Senior Vice-President, Thermal
Jay E. Froc
Senior Vice-President, Oil Sands Mining and Upgrading
Dwayne F. Giggs
Senior Vice-President, Exploration
Ron K. Laing
Senior Vice-President, Corporate Development and Land
Pamela A. McIntyre
Senior Vice-President, Safety, Risk Management
and Innovation
Robin S. Zabek
Senior Vice-President, Exploitation
Erin L. Lunn
Vice-President, Land
Paul M. Mendes
Vice-President, Legal, General Counsel and
Corporate Secretary
Kyle G. Pisio
Vice-President, Drilling, Completions and Asset Retirement
Roy D. Roth
Vice-President, Facilities and Pipelines
113
Canadian Natural 2021 Annual Report
2021 Performance Highlights
Canadian Natural's diverse and balanced asset base along with the Company's continued focus on
effective and efficient operations delivered several record operational and financial results in 2021.
These strong results created significant value for the Company's shareholders in the year.
FINANCIAL ($ millions, except per common share amounts)
Product sales (1)
Net earnings (loss)
Per common share
– basic
– diluted
Adjusted net earnings (loss) from operations (2)
Per common share
– basic (3)
– diluted (3)
Cash flows from operating activities
Adjusted funds flow (2)
Per common share
– basic (3)
– diluted (3)
Cash flows used in investing activities
Net capital expenditures (2)
Long-term debt, net (4)
Shareholders' equity
Debt to book capitalization (4)
2021
2020
2019
32,854
17,491
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
7,664
6.49
6.46
7,420
6.28
6.25
14,478
13,733
11.63
11.57
3,703
4,908
13,950
36,945
27%
(435) $
(0.37) $
(0.37) $
(756) $
(0.64) $
(0.64) $
$
$
$
$
$
$
$
$
4,714
5,200
4.40
4.40
2,819
3,206
21,269
32,380
40%
24,394
5,416
4.55
4.54
3,795
3.19
3.18
8,829
10,267
8.62
8.61
7,255
7,121
20,843
34,991
37%
(1) Further details related to product sales are disclosed in the "Segmented Information" note to the Company's audited consolidated financial statements.
(2) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's annual Management's Discussion and
Analysis ("MD&A") for the year ended December 31, 2021, dated March 2, 2022, included in this annual report.
(3) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
(4) Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
59
60
66
Management’s Assessment of Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Notes to the Consolidated Financial Statements
Management’s Discussion and Analysis
103 Supplementary Oil and Gas Information
Consolidated Financial Statements
Management’s Report
111
Ten Year Review
113
Corporate Information
TABLE OF CONTENTS
2021 Performance Highlights
Letter to our Shareholders
2021 Year End Reserves
01
03
06
09
57
58
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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 10.
METRIC CONVERSION CHART
To Convert
barrels
thousand cubic feet
feet
miles
acres
tonnes
To
Multiply by
cubic metres
cubic metres
metres
kilometres
hectares
tons
0.159
28.174
0.305
1.609
0.405
1.102
COMMON SHARE DIVIDEND
The Company paid its first dividend on its common shares on
April 1, 2001. Since then, dividends have been paid quarterly.
The following table shows the aggregate amount of the cash
dividends declared per common share of the Company and
accrued in each of its last three years ended December 31, 2021.
Cash dividends declared
per common share
$
2.00 $
1.70 $
1.50
2021
2020
2019
NOTICE OF ANNUAL MEETING
In light of the unprecedented public health impact as a result
of the outbreak of the novel coronavirus known as COVID-19,
Canadian Natural’s Annual and Special Meeting of the
Shareholders will be held in a virtual online format via live
webcast on Thursday, May 5, 2022 at 1:00 p.m. Mountain
Daylight Time. Please see our website, www.cnrl.com, for
any location 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 2021 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 2021 Annual Report
Canadian Natural 2021 Annual Report
114
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2100, 855 – 2 Street S.W.
Calgary, AB T2P 4J8
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(403) 517-6700
(403) 517-7350
ir@cnrl.com
www.cnrl.com
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