2100, 855 – 2 Street S.W.
Calgary, AB T2P 4J8
T (403) 517-6700
F (403) 517-7350
E ir@cnrl.com
www.cnrl.com
2022 ANNUAL REPORT
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233409_CNQ_2022_AR_Cover_converted.indd 1-3
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2022 Performance Highlights
Canadian Natural's diverse and balanced asset base along with the Company's flexible capital allocation
strategy and continued focus on effective and efficient operations delivered record operational and
financial results in 2022. These strong results generated substantial free cash flow, significant returns to
shareholders and strong reserves growth 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)
2022
2021
2020
49,530 $
32,854 $
17,491
10,937 $
7,664 $
9.64 $
9.52 $
6.49 $
6.46 $
12,863 $
7,420 $
11.33 $
11.19 $
6.28 $
6.25 $
19,391 $
14,478 $
19,791 $
13,733 $
17.44 $
17.22 $
4,987 $
5,471 $
11.63 $
11.57 $
3,703 $
4,908 $
(435)
(0.37)
(0.37)
(756)
(0.64)
(0.64)
4,714
5,200
4.40
4.40
2,819
3,206
10,525 $
13,950 $
38,175 $
36,945 $
22%
27%
21,269
32,380
40%
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(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, 2022, dated March 1, 2023, 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
01
03
T1-T8
06
09
57
58
2022 Performance Highlights
Letter to Shareholders
Our World-Class Team
2022 Year End Reserves
Management's Discussion and Analysis
Consolidated Financial Statements
Management's Report
59
60
66
101
111
113
Managements's Assessment of Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Notes to the Consolidated Financial Statements
Supplementary Oil and Gas Information
Ten Year Review
Corporate Information
1
Canadian Natural 2022 Annual Report
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
2022
2021
2020
480
426
13
14
933
473
448
18
14
952
460
417
23
17
918
2,075
1,680
1,450
2
13
2,090
1,281
390
—
—
390
3
12
1,695
1,235
193
6
—
199
12
15
1,477
1,164
71
1
—
72
(1) Numbers may not add due to rounding.
(2) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This
conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to
natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
(3) Net wells. Excludes net stratigraphic test and service wells.
1,281,434
BOE/D
RECORD PRODUCTION
60%
OF LIQUIDS PRODUCTION IS
SCO, LIGHT CRUDE OIL & NGLS
Canadian Natural 2022 Annual Report
2
Letter to Shareholders
In 2022, the strength of our balanced, diverse asset base combined with our flexible capital allocation
strategy yielded substantial free cash flow (1) generation and strong reserve growth, which resulted
in significant returns to our shareholders. We achieved record annual production of approximately
1,281 MBOE/d in 2022, an increase of 4% from 2021 levels, and 8% growth on a production per share basis.
This growth was largely driven by our strategic investment in our robust natural gas assets, which resulted
in 23% production growth from 2021 levels in our natural gas assets, achieving record annual natural gas
production of approximately 2.1 Bcf/d. Our culture of continuous improvement, focus on cost control and
disciplined capital allocation continue to drive strong operational and financial results, maximizing value for
our shareholders. Canadian Natural generated approximately $19.8 billion in adjusted funds flow in 2022,
resulting in free cash flow of approximately $10.9 billion, after total dividend payments and base capital
expenditures excluding net acquisitions and strategic growth capital. We were able to deliver significant
returns to shareholders in 2022, totaling approximately $10.5 billion through $5.6 billion in share
repurchases and $4.9 billion in dividends, including a special dividend of $1.50 per common share paid in
August 2022. This equates to approximately $9.25 per share in direct returns to shareholders in 2022.
In 2022, the Board of Directors approved two separate increases to our quarterly dividend, for a combined increase of 45%, to
$0.85 per common share. Subsequent to year end, the Board of Directors approved an additional 6% increase in the quarterly
dividend to $0.90 per common share from $0.85 per common share, demonstrating the confidence that the Board of Directors
has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline
asset base. The Company has a leading track record of 23 consecutive years of dividend increases, with a compound annual
growth rate of 21% over that time period. 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 2022, through our disciplined and flexible approach to planning with a goal
of safe, reliable, effective and efficient operations, maximizing value for our shareholders.
We maintained a strong balance sheet and reduced our net debt by approximately $3.4 billion in 2022, closing the year with
approximately $10.5 billion in net debt. In just two years, we have reduced our net debt by $10.7 billion or approximately 50%
from the beginning of 2021.
Our free cash flow allocation policy is unique and balanced, providing significant returns to shareholders through dividends and
share repurchases while continuing to strengthen the balance sheet. In 2022, we allocated approximately 50% of the
Company's free cash flow, as defined in our current policy, to share repurchases and 50% to the balance sheet. Concurrently
with the release of Canadian Natural's year end results, the Company enhanced its free cash flow allocation policy due to being
in a strong financial position and having a sustainable cash flow profile, particularly when you compare our debt levels to the
size, diversity, and long life low decline nature of our high value reserves. As a result, the Board of Directors has confidence in
the sustainability and resilience of the Company to support accelerating incremental shareholder returns to 100% of free cash
flow when the Company’s net debt reaches $10 billion. Once the Company's net debt reaches $10 billion, the free cash
allocation policy will be adjusted to define free cash flow as adjusted funds flow less dividends, less total capital expenditures in
the year.
As a result of our diversified portfolio, we achieved annual realized natural gas pricing of $6.55/Mcf in 2022, which was
approximately 17% above the AECO benchmark price. In addition, our high value synthetic crude oil ("SCO") captured a strong
price premium to WTI of US$4.43/bbl, driving strong realized SCO pricing of $117.69/bbl, which on an annual basis represents
approximately 46% of our total liquids volumes and generates significant free cash flow for the Company.
~$10.9 BILLION
RETURNED TO SHAREHOLDERS
~$3.4 BILLION
NET DEBT REDUCTION
3
Canadian Natural 2022 Annual Report
N. MURRAY EDWARDS
Executive Chairman
TIM S. MCKAY
President
MARK A. STAINTHORPE
Chief Financial Officer and
Senior Vice-President, Finance
Canadian Natural's total proved reserves increased by 6% to 13.587 billion BOE, replacing 2022 production by 265%.
This provides the Company with a total proved BOE reserves life index ("RLI") of approximately 32 years and reflects the
strength and depth of our assets. We continued to deliver strong total proved finding, development and acquisition ("FD&A")
costs, including changes in future development costs, of $8.39/BOE in 2022.
Canadian Natural is committed to supplying safe, reliable and responsible energy, along with reducing its environmental
footprint. We incorporate Environmental, Social and Governance ("ESG") practices that strengthen our long term sustainability
across all aspects of our business. In 2022, we announced a new environmental target to reduce corporate scope 1 and 2
absolute GHG emissions by 40% by 2035, in addition to our other robust environmental targets. We have a defined journey to
net zero emissions in oil sands operations and are working collaboratively with our industry peers through the Pathways Alliance
to achieve this goal. It is important we work together with both federal and provincial governments to achieve climate goals, in
an economically feasible manner. We are also an industry leader in abandonment and reclamation activity and through our
active program, we have abandoned more than 3,000 wells per year in each of the last two years. At this pace, we would be
able to achieve 100% abandonment of our current inventory of inactive wells in approximately 10 years.
Canadian Natural is committed to safe, effective and efficient operations, and creating a shared value in the communities where
we operate in Canada, the United Kingdom and Africa. This group of stakeholders includes more than 24,000 landowners, over
160 municipalities and more than 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. In 2022, we worked with 167 Indigenous businesses through which approximately $684
million in contracts were awarded, a 20% increase from 2021 levels.
Canadian Natural is a unique E&P company that has a strong track record of delivering free cash flow, increasing returns to
shareholders and strong returns on capital through the optimizing of capital allocation to our four pillars, maximizing value for our
shareholders. Our 2023 capital budget of approximately $5.2 billion
of base capital
and strategic growth capital of approximately $1.0 billion (1), driving annual targeted production growth of approximately
70,000 BOE/d, or 6% from 2022 levels. We remain committed to sustainable, growing shareholder returns, a strong balance
sheet and reducing our environmental footprint through innovative technology and continuous improvement, continuing to build
upon its history of creating premium value for our shareholders.
consists of approximately $4.2 billion
(1)
(1)
We would like to thank our employees and contractors for their hard work and commitment to deliver safe, reliable, effective
and efficient operations across all areas of the business. Your commitment to operational excellence underpins the ongoing
success of the business and our culture of working together and continuous improvement positions Canadian Natural well to
continue to drive long-term shareholder value.
N. MURRAY EDWARDS
TIM S. MCKAY
MARK A. STAINTHORPE
Executive Chairman
President
Chief Financial Officer and
Senior Vice-President, Finance
(1) Refer to page 5 and the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for additional details.
Canadian Natural 2022 Annual Report
4
NON-GAAP AND OTHER FINANCIAL MEASURES
This report includes references to non-GAAP and other financial measures as defined in National Instrument 52-112 – Non-
GAAP and Other Financial Measures Disclosure. These financial measures are used by the Company to evaluate its financial
performance, financial position or cash flow and are not defined by IFRS and therefore are referred to as non-GAAP and other
financial measures. These measures used by the Company may not be comparable to similar measures presented by other
companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial
measure presented in the Company's financial statements.
FREE CASH FLOW
Free cash flow is a non-GAAP financial measure that represents adjusted funds flow adjusted for base capital expenditures and
dividends on common shares. The Company considers free cash flow a key measure in demonstrating the Company’s ability to
generate cash flow to fund future growth through capital investment, pay returns to shareholders and to repay debt.
($ millions)
Adjusted Funds Flow (1)
Less: Base Capital Expenditures (2)
Dividends on Common Shares
Free Cash Flow
2022
2021
$
19,791 $
13,733 $
3,956
4,926
4,908
2,170
$
10,909 $
8,080 $
2020
5,200
3,206
1,950
549
(1) Refer to the descriptions and reconciliations to the most directly comparable GAAP measure, which are provided in the “Non-GAAP and Other Financial
Measures” section of the Company's MD&A for the year ended December 31, 2022 dated March 1, 2023, included in this annual report.
(2)
Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of Company's MD&A for the year ended
December 31, 2022 dated March 1, 2023 for more details on net capital expenditures.
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 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.
LONG-TERM DEBT, NET
Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term
debt less cash and cash equivalents.
5
Canadian Natural 2022 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, L. Abadier, E. Abajifar, A. Abakar, Z. Abbas, T. Abbasi, D. Abbott, J. Abbott, M. Abbott, A. Abd, M. Abd Al Razzek, Y. Abdallah, I. Abdi, M. Abdi, W. Abdi, A.
Abdolmaleki, S. Abdulghany, M. Abdullahi, M. Abdulrhman, A. Abeda, W. Abeda, D. Abel, V. Abeng, T. Abercrombie, K. Abolino, G. Abou Mechrek, A. Abraham, B. Abraham, R. Abrams,
J. Abreu Sarache, N. Abro, N. Absamatova, M. Abu-Rumman, C. Acharya, M. Acharya, D. Acheson, D. Ackerman, R. Ackerman, J. Acosta, J. Acteson-Grill, N. Adair, I. Adam, S. Adam,
T. Adam, D. Adams, K. Adams, M. Adams, D. Adamson, C. Adan, T. Adbous, D. Addinall, A. Adebayo, O. Adebayo, M. Aden, A. Adesanya, K. Adesanya, O. Adigun, B. Adjoussou, B.
Adkins, S. Adnitt, N. Agarwal, J. Agate, F. Agbadou, A. Agnihotri, I. Agu, O. Agu, U. Agu, R. Aguilera Maestre, A. Agustin, M. Agyby, C. Agyemang-Badu, J. Ahmad, K. Ahmad, M.
Ahmad, N. Ahmad, R. Ahmad, S. Ahmad, A. Ahmadi, M. Ahmadi, F. Ahmadloo, A. Ahmari, N. Ahmed, R. Ahmed, S. Ahmed, N. Ahonon, M. Ahoonmanesh, D. Aikins, G. Ailsby, J.
Airton, S. Aitken, S. Ajayi, T. Ajayi, O. Ajbouni, J. Ajedegba, L. Ajijolaiya, M. Akbar, S. Akhtar, D. Akins, A. Akinsanya, J. Akolkar, N. Akolkar, S. Akolkar, J. Akrong, C. Alarcon, R. Alarcon
Atienza, E. Albert, A. Alcala, J. Alcala, E. Alconcel, N. Aldi, T. Aldred, J. Aleman, S. Alex, D. Alexander, J. Alexander, P. Alexander, S. Alexander, J. Al-Harake, G. Ali, S. Ali, R. Aliazas,
H. Aljanabi, M. Al-Kaisy, P. Allain, C. Allan, J. Allan, A. Allen, J. Allen, T. Allen, W. Allen, J. Allison, S. Allport, J. Allsop, M. Almestar Bustamante, J. Alonso, Y. Al-Saeedi, A. Al-Saleem,
R. Al-Samarrai, S. Al-Siani, A. Alstad, J. Alvarez, J. Alvarez Luzon, J. Alves de Sousa Segundo, B. Alyman, C. Amadi, D. Amalaman, G. Amalia, M. Amar, T. Amara, A. Amay, V. Amberkar,
B. Amer, J. Amero, H. Amin, F. Amjed, J. Amond, E. Amos, A. Amu, W. Amy, A. Amyotte, M. Ancheta, J. Andel, D. 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, T. Anderson, W. Anderson, I. Andonov, A. Andrade, D. Andreoli, C. Andres,
B. Andrews, E. Andrews, K. Andrews, L. Andrews, T. Andrews, E. Anfort, C. Angeles, G. Angeles, P. Angell, L. Angen, K. Angerman, B. Anhorn, M. Anis, R. Annett, C. Anokwute, A.
Ansell, D. Ansorger, L. Antal, W. Anthony, E. Antle, C. Antoine, M. Antoine, A. Anton, K. Antonishyn, J. Antoniuk, A. Antunes, S. Anwar, T. Aos, P. Appiah, J. Aquila, R. Aranguren, F.
Arano, C. Arban, L. Arbour, R. Arcilla, H. Arias, L. Arias, J. Arkley, N. Arlt, R. Armagost, T. Armfelt, A. Armstrong, D. Armstrong, J. Armstrong, J. Arnault, B. Arneson, B. Arnold, C.
Arnold, J. Arnold, A. Arowosebe, F. Arrau, F. Arrieta, L. Arsenault, M. Arsenault, K. Arstall, A. Arthur Brown, B. Artz, A. Arya, D. Asfeday, J. Ashe, Z. Ashraf, J. Ashton, A. Aslam, R.
Aslin, S. Aspden, H. Aspeslet, D. Assinger, J. Asso, V. Assohou-Ouattara, J. Assoignon, A. Astalos, R. Astalos, I. Astete, M. Atchudda Reddy, E. Atdayev, N. Athavan, A. Atienza, R.
Atkins, J. Atkinson, K. Atkinson, T. Atkinson, L. Attreo, E. Au, G. Au, M. Au, J. Auch, P. Aucoin, W. Aucoin, J. Audia, A. Auger, P. Auger, S. Auger, C. Aular, M. Austerman, C. Austin, R.
Austin, A. Avery, B. Avery, F. Avery, A. Avhad, M. Avila, O. Ayanleke, A. Ayasse, W. Ayles, J. Ayub, F. Azam, Z. Azim, B. Babiak, A. Babiarz, A. Babiker, O. Babiker, M. Bachand, C.
Bachelet, C. Bachman, W. Bachmeier, C. Backer, A. Badamchi Zadeh, C. Badger, J. Badh, O. Baffoh, N. Bagheri, K. Bagley, A. Bagnall, M. Bahiraei, B. Bahlieda, R. Bahme, D. Baichev,
D. Baier, J. Baier, S. Baig, 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, E. Baird, D. Baisley, D.
Bak, L. Bakaas, A. Baker, C. Baker, J. Baker, A. Bakhtiary Fard, D. Bakkar, J. Bakker, J. Balacang, B. Balan, K. Balan, D. Balaraman, B. Balaski, B. Baldonado, J. Baldonado, C. Baldwin,
G. Baldwin, M. Baldwin, R. Baldwin, M. Baleja, P. Balfour, R. Balfour, M. Balino, 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, R. Banerd, R. Banfield, S. Banfield, O. Bango, S. Banik, J.
Banks, L. Banks, C. Ban-Nelson, R. Bannerholt, J. Banta, R. Barabe, M. Barakat, L. Barbaro, J. Barbeau, 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, B. Barnett, S. Barr, C. Barrett, M. Barrett, T. Barrett, S. Barriault, C. Barrie, D. Barriobero, D. Barron, R.
Barron, B. Barrow, S. Barrows, D. Barry, A. Barstad, M. Barta, G. Bartel, C. Bartels, P. Barter, A. Bartko, E. 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, C. Bastien, S. Basu, M. Batac, S. Batarseh, C. Bateman, D. Bateman, M. Bateman, P. Bateman,
T. Bateman, D. Bates, D. Bath, L. Bath, R. Bath, M. Batovanja, D. Batt, K. Batten, R. Batten, C. Battrum, J. Batuyong, D. Bauer, R. Bauer, T. Bauld, C. Baumgardner, J. Baxter, M. Baxter,
A. Bayduza, S. Baykan, A. Bayko, J. Bayles, D. Bayley, M. Bayley, F. Bayuk, A. Bazowski, B. Beach, J. 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, C. Beaudoin, J. Beaudoin, R. Beaudoin, C. Beaudrie, B. Beaulac, J. Beaulieu, M. Beaulieu, L.
Beaunoyer, M. Beaunoyer, A. Beausoleil, K. Beazer, D. Bechtel, N. Beck, R. Beck, C. Becker, R. Becker-Faubert, R. Beckner, S. Beckow, J. Beda, I. Bedard, L. Bedard, M. Bedard, R.
Bedard, D. Bedell, M. Bednarchuk, S. Beebe, T. Beebe, M. Beeks, C. Beeler, K. Begg, C. Begon, W. Behnke, W. Bei, A. Belah, G. Belanger, R. Belanger, H. Belas, L. Belcourt, R.
Belcourt, J. Belik, R. Belisle, B. Bell, D. Bell, J. Bell, L. Bell, N. Bell, R. Bell, S. Bell, J. Bellavance, M. Beller, E. Bellerose, A. Bellettini, J. Belliveau, A. Bellows, C. Bellows, M. Belzile,
M. Bembridge, D. Benassi, D. Bencharsky, M. Bencik, K. Bendahmane, C. Bender, J. Bendza, R. Benedictson, M. Benko, D. Benn, T. Benn, K. Benner, C. Bennett, D. Bennett, E.
Bennett, J. Bennett, N. Bennett, R. Bennett, S. Bennett, D. Bennett-Nimijean, A. Benoit, D. Benoit, J. Benoit, M. Benoit, P. Benoit, D. Bensley, K. Benson, M. Benson, A. Benson-
Bartko, J. Bent, A. Bentley, P. Bentley, R. Bentley, I. Bentsianov, J. Berdan, A. Berg, D. Berg, R. Berg, L. Berge, O. Bergeron, M. Bergeson, B. Bergley, J. Bergquist, C. Bergsma, J.
Bergsma, A. Berhe, D. Berlinguette, J. Bernardin, T. Bernhard, J. Bernier, K. Berreth, C. Berry, R. Berry, D. Bershadsky, S. Bertelmann, T. Bertoia, A. Bertrand, B. Bertrand, J. Bertrand,
R. Bertrand, M. Bertucci, B. Berube, R. Besinger, C. Best, J. Best, C. Betancur Pelaez, C. Bettany, T. Betteridge, R. Beveridge, W. Bewski, B. Beyer, J. Beytell, S. Bezpalchuk, J.
Bezruchak, M. Bezugley, A. Bhadauria, A. Bhaduri, M. Bhakri, J. Bhangoo, H. Bhathal, H. Bhatia, B. Bhatt, J. Bhatt, K. Bhatt, R. Bhatt, V. Bhatt, I. Bhatti, V. Bhekare, P. Bhojapoojary,
N. Bhoria, J. Bhuie, J. Bianchini, L. Bianco, A. Bibo, J. Bick, S. Biddle, T. Biddlecombe, D. Bieber, D. Bielech, E. Bieleski, D. Biendarra, D. Biener, V. Biesinger, K. Biever, A. Bigelow,
C. Biggin, M. Biggs, A. Bilal, D. Biles, L. Billard, T. Billard, J. Bilna, J. Bilous, D. Bilston, D. Bingham, B. Binns, C. Bird, D. Birnie, 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, J. Bizuk, J. Blachford, A. Black, B. Black, C. Black, D. Black, J. Black, N. Black, R. Black,
V. Black, W. Blackburn, T. Blackett, K. Blackmore, R. Blackmore, T. Blackwell, D. Blain, G. Blain, A. Blair, D. Blair, K. Blair, K. Blais, A. Blake, D. Blake, J. Blake, L. Blake, T. Blake, P.
Blakely, J. Blanc, A. Blanchard, D. Blanchard, G. Blanchard, K. Blanchette, A. 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, J. Blundon, C. Blyan, N. Blyth, C. Boadas Salazar, J. Bobbett, R. Bock, G. Boddy, J. Bodell, R. Bodell, S. Bodell, A.
Bodnar, K. Bodnar, V. Bodnarchuk, B. Bodner, G. Bodner, D. Boeckx, M. Boehm, R. Boese, D. Boettcher, M. Boggust, L. Boghici, T. Bohach, A. Bohemier, B. Bohlken, J. Bohlken, E.
Bohme, N. Bohning, J. Bohorquez, J. Boissoneault, C. Boisvert, J. Boisvert, M. Boisvert, B. Bokenfohr, D. Bokota, R. Boksteyn, R. Boland-Elliott, S. Bolduc, C. Bolger, S. Bolson, D.
Bolster, B. Bolt, J. Bolt, P. Bolt, G. Bolzon, J. Bonami-McRae, G. Bond, K. Bond, N. Bond, S. Bond, T. Bond, T. Bondaruk, A. Bone, J. Bonifacio, M. Bonin, C. Bonogofski, A. Bonwick,
S. Booker, G. Boomgaarden, J. Boomgaarden, B. Boone, K. Booth, M. Booth, R. Booth, T. Booth, B. Borbely, K. Bordeleau, R. Bordeleau, R. Borjigin, P. Bork, J. Borkowski, M. Borlaza,
M. Born, N. Born, K. Borromeo, E. Borsa, E. Borsini Marin, M. Borst, S. Borys, J. Bosch, S. Bosch, S. Bose, D. Boser, G. Bosma, L. Bosoi, P. Bossel, A. Botezatu, K. Bothwell, Z.
Bothwell, J. Botterill, D. Bouchard, R. Bouchard, T. Bouchard, J. Bouchard Lacoste, T. Boucher, J. Boudreault, K. Bougie, H. Boult, J. Boulton, T. Bouma, J. Bounds, L. Bourassa, R.
Bourassa, S. Bourassa, T. Bourassa, J. Bourdon, J. Bourgeois, C. Bourlon, D. Bourque, M. Boutilier, R. Boutilier, J. Boutkan, D. Bouvier, K. Boven, C. Bowal, M. Bowal, C. Bowditch,
D. Bowe, J. Bowen, S. Bowers, D. Bowes, B. Bowie, J. Bowie, J. Bowman, N. Bowman, R. Bowman, E. Bown, R. Bowness, W. Bowness, J. Boxer, D. Boyarski, R. Boyce, T. Boyce,
J. Boyd, R. Boyd, J. Boyde, A. Boyer, C. Boyer, R. Boyko, V. Boyko, D. Boyle, N. Boyle, D. Bradbury, A. Bradley, B. Bradley, P. Bradley, S. Bradley, T. Bradley, G. Brady, M. Brady, J.
Bragg, A. Brahme, S. Braithwaite, S. Brake, T. Brake, J. Branderhorst, B. Brandle, M. Brandsema, J. Brannick, D. Brant, 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, B. Brazzoni, J. Breaks, J. Breau, F. Brebant, M. Brecht, S. Bredy, A. Breen, D. Breen, M. Breen,
S. Breen, T. Breen, J. Breker, D. Bremner, C. Brennan, F. Brennan, L. Brennan, M. Brennan, L. Brenton, R. Brenton, T. Bresson, R. Bretzlaff, O. Breukel, A. Brewer, R. Brezinski, W.
Briand, M. Brideau, C. Bridger, D. Bridger, J. Bridger, M. Brietzke, C. Briggs, M. Briggs, J. Bright, L. Brinkworth, S. Brinson, S. Brinston, L. Brisebois, P. Britton, S. Britton, M.
Briukhanov, P. Brkich, A. Brochu, J. Brock, M. Brock, K. Brocke, D. Broderick, S. Broderick, S. Broderson, S. Brodeur, D. Brodziak, J. Bronkhorst, G. Bronson, B. Brooks, D. Brooks, J.
Brooks, R. Brooks, S. Broomfield, G. Brophy-Maclean, K. Brost, A. Brousseau, 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, D. Brulotte, S.
Brulotte, S. Brummelhuis, N. Brummitt, D. Brundige, R. Brundige, K. Bruner, M. Brunet, C. Brunette, R. Bryan, B. Bryant, P. Bryant, R. Bryant, T. Bryant, T. Brydges, E. Bryenton, H.
Bryenton, R. Bryer, G. Bryks, J. Bryla, D. Bryson, M. Bryson, S. Bryson, C. Buan, G. Buchan, H. Buchan, J. Buchanan, C. Buchholz, M. Buchinski, J. Buck, D. Buckley, M. Buckley, S.
Buckley, G. Buckshaw, T. Budd, R. Budzen, R. Bueckert, S. Bugden, N. Buhler, K. Buitrago Sanchez, S. Bukhari, C. Bull, R. Bullen, J. Bullock, G. Bungay, L. Bungay, I. Bunting, B. Bunz,
T. Burchenski, J. Burdett, A. Burger, G. Burhoe, B. Burk, G. Burkart, T. Burkart, C. Burke, D. Burke, L. Burke, M. Burke, S. Burke, G. Burkhart, J. Burnett, A. Burnham, J. Burnouf, J.
Burns, C. Burroughs, R. Burrows, B. Burry, D. Burry, K. Burry, M. Burry, S. Burry, D. Bursey, C. Burshtinski, A. Burt, J. Burt, S. Burt, G. Burton, J. Burton, K. Burton, M. Burton, N.
Burton, R. Burton, T. Burton, W. Burton, B. Bury, R. Busato, K. Bush, T. Bushie, G.
Bushore, D. Bussey, N. Bussiere, M. Butchart, C. Butler, D. Butler, I. Butler, M.
Butler, R. Butler, T. Butler, D. Butlin, B. Butt, K. Butt, M. Butt, Q. Butt, S. Butt, T.
Butt, W. Butt, R. Butts, P. Buxton, B. Bye, J. Byrne, M. Byrne, T. Byrnell, J. Byrtus,
I. Byvald, L. Cabatuando, A. Cabral, T. Cadieux, R. Cahoon, H. Cai, A. Caines, H.
Cairns, E. Caissie, W. Calabio, B. Calder, J. Caldwell, P. Caldwell, R. Caldwell, S.
Caldwell, C. Caleffi, P. Callin, R. Calliou, M. Camargo, R. Cameron, S. Cameron, T.
Cameron, A. Campbell, B. Campbell, C. Campbell, D. Campbell, E. Campbell, G.
Campbell, J. Campbell, K. Campbell, N. Campbell, P. Campbell, R. 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, K. Cap, A. Capadosa, N. Cappellani, L.
Cappelle, M. Capstick, B. Carabin, G. Carde, A. Cardenas, F. Cardinal, L. Cardinal,
R. Cardinal, W. Cardinal, M. Carew, S. Carew, J. Carey, W. Carey, J. Carleton, T.
Carleton, K. Carlos, F. Carlos Sanchez, A. Carlotti, J. Carlson, W. Carlson, D. Carnes,
A. Caron, D. Caron, R. Caron, S. Caron, G. Carpo, D. Carr, L. Carranza, V. Carrasco
Rueda, M. Carrier, T. Carrier, D. Carroll, I. Carroll, J. Carroll, M. Carroll, R. Carroll, S.
Carroll, C. Carsh, B. Carson, R. Carstairs, E. Cartaya, D. Carter, E. Carter, J. Carter,
K. Carter, X. Cartron, J. Cartwright, P. Cashin, K. Casimel, B. Cassell, E. Cassell, J.
Casselman, J. Cassidy, T. Cassidy, D. Cassie, C. Cassity, L. Casson, F. Castellanos,
A. Castillo, C. Castillo, K. Castle, J. Castro, J. Caswell, M. Cater, C. Cathcart, N.
Catley, M. Cator, J. Cauchie, D. Cavacciuti, A. Cave, D. Cavers, J. Cayabo, C. Cayer,
D. Cazabon, C. Celis, M. Celis, M. Cenon, A. Centeno, S. Cervantes, B. Chaba, D.
Chadwick, S. Chadwick, A. Chafe, C. Chafe, D. Chafe, A. Chaisson, P. Chakraborti,
S. Chakraborty, S. Chakravarty, A. Chalifoux, C. Chalifoux, A. Chamanara, C.
Chambers, T. Chambers, K. Champagne, L. Champagne, A. Chan, C. Chan, D.
T1
Canadian Natural 2022 Annual Report 10,035
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.
Chan, I. Chan, J. Chan, R. Chan, S. Chan, T. Chan, J. Chandler, A. Chaney, J. Chanski, H. Chaouach, K. Chapman, M. Chapman, D. Chappelle, B. Chapple, T. Chapple, W. Charanek, N.
Charest, S. Charette, R. Charitra, D. Charlish, Y. Charniauski, L. Charrois, A. Chartrand, C. Chartrand, R. Chartrand, A. Chatman, M. Chaudhry, R. Chaulk, D. Chauvet, S. Chavda, D.
Chavez, S. Chavez, M. Chawla, T. Chayko, C. Chaytor, P. Chaytor, M. Chechile, W. Cheladyn, B. Chen, C. Chen, G. Chen, H. Chen, K. Chen, N. Chen, T. Chen, X. Chen, Z. Chen, C.
Cheng, L. Cheng, N. Cheng, D. Chenier, N. Cheraghi, Z. Cherniawsky, M. Chernichen, T. Cherry, O. Chervyakova, B. Chester, A. Cheung, J. Cheung, K. Cheung, W. Cheung, L.
Cheveldeaw, B. Cheyne, H. Chhokar, B. Chhualsingh, B. Chichak, K. Chichak, D. Chick, B. Chicoine, D. Chidley, S. Chikuse, S. Childs, K. Chilibeck, R. Chilton, A. Chin, Y. Chin, C. Ching,
T. Chipiuk, M. Chiplin, A. Chisholm, B. Chisholm, T. Chisholm, T. Chislett, P. Chiu, R. Chmilar, C. Cho, J. Chohan, D. Choi, S. Choi, E. Chojko, J. Cholka, N. Chondropoulos, R. Chong,
B. Chopping, B. Chorney, M. Chorney, C. Chornohos, C. Chorostecki, J. Chou, S. Choudhury, M. Chourio, A. Chow, J. Chow, K. Chow, D. Chowdhry, R. Chowdhury, S. Chowdhury, G.
Choy, A. Chramosta, B. Christensen, E. Christensen, L. Christensen, R. Christensen, T. Christensen, N. Christian, R. Christian, K. Christiansen, S. Christiansen, D. Christianson, M.
Christianson, C. Christie, D. Christie, R. Christie, S. Christie, T. Christie, A. Chu, C. Chua, R. Chubaty, G. Chubbs, J. Chubey, D. Chudobiak, V. Chui, H. Chung, R. Chuong, D. Churchill,
G. Churchill, J. Churchill, J. Churko, D. Chute, K. Chychul, V. Cimon, M. Cirankewitsch, A. Cizek, B. Clannon, D. Clapperton, W. Clapperton, C. Clarance, S. Claringbull, A. Clark, C.
Clark, J. Clark, K. Clark, L. Clark, R. Clark, T. Clark, B. Clarke, J. Clarke, K. Clarke, L. Clarke, N. Clarke, O. Clarke, R. Clarke, S. Clarke, T. Clarke, W. Clarke, C. Clarkson, D. Clarkson, W.
Clarkson, A. Cleghorn, P. Cleghorn, J. Clelland, T. Clelland, R. Clemit, R. Clemmer, J. Clevenger, C. Closs, Z. Closter, A. Clouston, J. Clouter, R. Cloutier, J. Clowater, M. Cnossen, J.
Coates, M. Coates, R. Coates, T. Coates, E. Cobaj, C. Cobaleda, D. Coburn, M. Cochet, B. Cochrane, E. Cochrane, J. Cochrane, D. Cockerill, B. Cockman, A. Codner, C. Codner, R.
Coen, J. Coers, K. Coffin, L. Coffin, B. Colaco, L. Colborne, M. Colbourne, A. Cole, B. Cole, C. Cole, M. Cole, P. Cole, J. Coleman, W. Coleman, 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, C. Collinson, G. Collison, A. Collyer, R. Colnar, L. Colombo, E.
Comeau, K. Comeau, R. Comer, K. Compagnon, C. Compton, N. Compton, Q. Conacher, M. Conejeros, M. Connell, M. Connellan, D. Conner, B. Connors, D. Conrad, B. Conroy, J.
Conroy, T. Conroy, D. Conway, E. Conway, M. Conway, D. Conybeare, D. Cook, G. Cook, J. Cook, K. Cook, L. Cook, N. Cook, S. Cook, H. Cooke, L. Cooke, D. Cookson, K. Cookson, L.
Cookson, H. Coolidge, H. Cooling, J. Coomber, J. Coombs, K. Coombs, T. Coome, L. Cooper, M. Cooper, J. Cooze, R. Copan, C. Copeland, N. Copeland, R. Coppard, M. Coppola, D.
Corbett, J. Corbett, N. Corbett, F. Corbin, E. Corcoran, J. Corcoran, F. Cordingley, M. Corell, A. Corless, D. Cormier, I. Cormier, V. Cornejo, S. Correll, C. Corrigan, D. Corrigan, J.
Corrigan, C. Corry, G. Cortes, B. Cortez, P. Corticelli, C. Corzo De Canchica, D. Cosby, G. Cossani, J. Costello, M. Costello, S. Costello, J. Costigan, B. Cote, E. Cote, J. Cote, A. Cote
Simard, E. Cotten, L. Coulibaly, S. Coulibaly, D. Coull, J. Courchene, J. Courtemanche, B. Courtney, T. Courtney, D. Courtoreille, S. Courtoreille, P. Cousin, K. Cousineau, J. Cousins,
M. Cousins, P. Covell, R. Coventry, D. Cowan, E. Cowan, J. Cowan, C. Cowie, R. Cowling, B. Cox, G. Cox, S. Cox, E. Cozicor, W. Crabtree, R. Craft, C. Craig, D. Craig, G. Craig, R.
Craig, T. Craig, H. Craigie, P. Cramb, S. Cramb, S. Cramm, M. Crane, S. Crane, A. Crawford, C. Crawford, M. Crawford, J. Crawley, N. Cressey, L. Cressman, C. Criddle, M. Crisan, P.
Crisby, C. Critch, J. Critch, D. Crittall, A. Croft, S. Croft, G. Crooks, A. Crosby, D. Crosley, T. Crosley, C. Cross, G. Cross, R. Cross, T. Cross, D. Crossley, A. Croswell, A. Croucher, K.
Crouser, T. Crouser, C. Crowe, D. Crowle, E. Crowley, M. Crowshaw, P. Crozier, D. Crum, L. Cruttenden, J. Cruz, J. Cryer, A. Csabay, B. Csatari, P. Cudak, J. Cudmore, C. Cui, H. Cui,
J. Cullen, M. Culligan, E. Cullimore, A. Cunanan, A. Cunningham, E. Cupac, J. Curkan, J. Curran, S. Curran, R. Currier, B. Curry, M. Curry, K. Cusack, D. Cutler, J. Cutler, S. Cutler, J.
Cuu, A. Cyr, C. Cyr, D. Cyr, G. Cyr, J. Cyr, J. Cyrenne, D. Cyron, K. Cytko, J. Czech, M. Czerwinski, K. d’Abadie, D. Dabas, V. Daboin, A. Dabrowski, M. Dacillo-Basallajes, A. Dada, F.
Dadashov, R. Dadey, M. Dadi, A. Dafoe, G. Dafoe, J. Dafoe, W. Dagley, M. Daguro, C. Dahl, A. Dahmani, J. Dai, L. Dai, J. Daigle, B. Daignault, P. Dale, D. Dalgarno, L. Dalgetty-Rouse,
H. Dalipe, R. Dallaire, B. Dalley, G. Dalley, G. Dallon, M. Dalton, G. Daly, G. Dalziel, R. Damer, D. D’Amour, E. Dana, A. Danbrook, T. Danbrook, K. Dancek, S. Daneshmand, W. Daniel,
J. Daniels, T. Daniels, D. Danilkewich, C. Danyluk, P. Danyluk, S. Daoudi, D. Daragan, S. Darai, M. D’arcangelo, A. Dareichuk, V. Darel, E. Dargatz, M. Darling, N. Darling, S. Daroch, D.
Das, F. Daub, D. Dave, M. Dave, C. Davey, G. David, L. David, G. Davidson, J. Davidson, K. Davidson, M. Davidson, S. Davidson, T. Davidson, C. Davies, D. Davies, J. Davies, K. 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, R. Day, S. Day, T. Day, J. Daye, V. Daze, M. de Chavez, H. de Graaf, A. De Groot, R. De Jesus, R. de Jong, R. De Leeuw, B. De Lorenzo, D. De Marchi, D. De Oliveira, R.
de Ruiter, V. de Ruiter, C. de Wit, B. de Witt, B. Deacon, K. Deacon-Rosamond, I. Deaconu, P. Deagle, R. Dean, A. Dearaway, G. Dearden, C. Deaver, J. deBalinhard, T. DeBiasio, T.
Debler, S. Debnath, D. Deboer, R. deBoer, W. DeBona, P. DeBusschere, D. Dechaine, J. Dechaine, R. Dechaine, P. Dechant, R. Dechesne, A. Decker, B. Decker, D. Decker, J. Decker,
R. Decker, J. Decoeur, D. Decoine, D. Decoste, W. Dedam, L. Deep, M. Deering, L. Defoort, S. DeFord, M. Degenstien, I. DeGrace, M. Degrazio, A. Deibert, E. Deisting, R. Deitz, R.
DeJong Dyck, M. Del Frari, B. DeLair, C. Delaire, L. Delaire, I. Delaney, P. Delany, E. DeLaRonde, C. Delawski, M. Deleeuw, K. DeLong, M. Delorme, R. Demarsh, A. Demencuik, C.
DeMille, B. Demirdal, J. Demmink, C. DeMone, R. DeMott, G. Dempsey, M. Denault, D. Deneau, A. Denisova, G. Denney, D. Dennison, S. Denny, C. Denslow, E. Densmore, J. Dent,
L. Depencier, H. Derakhshan, D. Derbyshire, J. Derix, K. Derkowski, B. Derochie, A. Desai, C. Desai, G. Desai, M. Desai, N. Desai, P. Desai, R. Desai, S. Desai, J. Deschambault, M.
Deschambeau, T. Deschamps, D. Deschenes, S. Deshpande, V. Deshpande, S. Desjardins, C. Desjardins-Knowlden, G. Desjardins-Knowlden, C. Desjarlais, A. Desmarais, C.
Desmarais, S. Desmarais, J. Desnoyers, L. Despins, D. Dessario, M. Detta, M. Dettbarn, P. Deutcheu, K. Deutsch, A. Deutscher, S. Deval, A. Deveau, L. Devey, N. Devlin, T. Dew, C.
Dewar, J. Dewar, T. Dewhurst, K. Deyaegher, M. Deyan, C. Deykers, G. Dhaliwal, H. Dhaliwal, J. Dhaliwal, M. Dhaliwal, T. Dhaliwal, P. Dhalwala, B. Dhanesha, J. Dharamsi, M.
Dhariwal, S. Dhudwal, B. Diakow, K. Diallo, B. Diamond, L. Diane, L. Diaz, M. Diaz, A. Dick, R. Dicken, K. Dickey, K. Dickie, A. Dicks, E. Dicks, N. Dicks, B. Dickson, C. Dickson, A.
Didenko, J. Diederich, E. Dieta, D. Dietzen, P. Diggle, M. Diiorio, A. Dillabough, E. Dillabough, A. Dimapilis, L. Dimion, N. Ding, X. Ding, Y. Ding, M. Dingley, G. Dingwell, R. Dingwell,
T. Dinh, H. Dinn, K. Dinney, M. Diomande, S. Dionne, R. Diputado, A. Diriye, M. Dirk, S. Dirk, J. Disney, T. Ditchburn, E. Ditzler, C. Dixon, D. Dixon, K. Dixon, R. Dixon, T. Dixon, D.
Dixson, K. Do, W. Dobchuk, C. Dobek, G. Dobek, L. Dobson, S. Dobson, R. Docksteader, R. Dodunski, R. Doering, J. Doetzel, A. Doherty-Snelgrove, J. Doiron, K. Doiron, P. Dolan, L.
Dolen, S. Dolhanty, D. Dolynchuk, P. Dolynchuk, D. Doma, G. Domalain, R. Domazet, B. Dombrova, M. Dombrova, D. Domin, K. Donahue, K. Donald, S. Donaldson, R. Donaleshen,
M. Dong, J. Dongas, J. Donnelly, J. Donovan, N. Donovan, J. Doonanco, A. Dorey, R. Dorton, J. Dorusak, A. Dosanjh, J. Dosman, M. Doty, M. Doucet, D. 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, A. Downs, R. Doyer, G. Doyle, S. Doyon, R. Drainville, S. Drake,
P. Drapeau, G. Draper, K. Draper, T. Draper, J. Dreaddy, S. Drebit, K. Dreger, J. Drescher, D. Dresser, D. Dressler, C. Drevant, B. Drew, D. Drew, A. Driemel, A. Drier, B. Driscoll, S.
Driscoll, T. Driscoll, E. Drolet, R. Drolet, R. Drosu, S. Drouin, A. Drover, C. Drover, J. Drover, N. Drover, T. Drover, R. Drummond, A. Druzhynin, S. Dryden, M. D’Souza, P. D’Souza, S.
D’souza, V. D’Souza, C. Du, M. Du, S. du Plessis, M. Du Preez, M. Dua, P. Duan, C. Duane, C. Duarte, B. Dube, M. Dube, N. Dube, R. Dube, T. Dubie, S. Dubli, J. Dubois, L. DuBois,
J. Dubuc, D. Duby, M. Ducey, J. Duchscherer, J. Duczek, P. Duda, S. Dudley, T. Dueck, C. Duffett, D. Duffy, K. Duford, E. Dufour, C. Duggan, W. Duggan, M. Duguay, D. Duguid, A.
Duhaime, E. Dulay, A. Dumanowski, T. Dumba, O. Dumitrache, Y. Dumont, C. Dunbar, B. Duncan, H. 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, J. Durkacz, K. Durocher, B. Dusterhoft, J. Dutchak, J. Duthie, K. Dutka, O.
Dutka, K. Dutot, N. Duval, R. Duval, T. Duxbury, J. Dwan, R. Dwernychuk, B. Dwyer, C. Dwyer, R. Dwyer, D. Dybala, J. Dybala, A. Dyck, M. Dyck, J. Dyer, L. Dyke, B. Dzirasah, M.
Dziwinski, B. Eagle, M. Eamer, R. Earl, A. Earle, V. Eason, J. Easthope, B. Eastman, J. Eastman, J. Easton, K. Eberle, R. Ebuna, K. Eckel, G. Ecker, D. Eckford, D. Edgington, R. Edlund,
A. Edoukou, D. Edwards, E. Edwards, J. Edwards, N. Edwards, P. Edwards, T. Edwards, A. Effray, L. Egeland, R. Eggen, T. Egginton, C. Eggleton, A. Eghbal, A. Egresits, T. Ehman, C.
Ehnes, C. Ehresman, I. Eichelbaum, T. Eidick, B. Eitzen, M. Ejo, D. Ekdahl, J. Ekelund, S. Ekra, S. Ekstrom, G. El Chayeb, R. Elaschuk, N. Elderkin, I. Elgarni, M. Elgarni, M. El-Harakeh,
T. Elias, M. Elias Neira, K. Elladen, N. Ellingson, P. Ellingson, M. Elliot, B. Elliott, D. Elliott, H. Elliott, J. Elliott, L. Elliott, R. Elliott, S. Elliott, K. Ellis, M. Ellis, P. Ellison, C. Ellsworth, K.
Ellsworth, A. Elmobarik, M. Elms, F. El-Rafih, A. El-Sayed, E. Elson, T. Ely, C. Emberley, V. Embleton, H. Emery, C. Emmett, G. Emmott, J. Engel, K. Engelking, R. Engler, T. Engler, J.
English, N. Ennis, M. Enns, R. Enns, J. Entz, C. Enyinnaya-Okidi, C. Epp, J. Epp, T. Epp, J. Erasmus, S. Erb, B. Eresman, C. Erfle, A. Erickson, B. Erickson, J. Erickson, M. Erl, B.
Erlandson, M. Ernst, P. Ersh, C. Erskine, D. Ertmoed, W. Esau, P. Escalona, N. Eskandar, G. Eskandari, M. Espejo, R. Espenido, A. Espindola, M. Espiritu, R. Esslemont, B. Estey, O.
Estrada, D. Etherington, S. Etherington, D. Evans, J. Evans, K. Evans, R. Evans, T. Evans, R. Evasco, J. Eveleigh, L. Eveleigh, S. Eveleigh, A. Everson, C. Eves, J. Ewald, S. Ewasiuk,
J. Eyma, B. Eyolfson, N. Ezeano, V. Ezeronye, T. Fabrick, B. Facco, D. Fader, D. Fadnavis, R. Faechner, C. Fafard-Langevin, B. Fagan, F. Fahad, M. Fahad, J. Fahim, E. Faichney, S.
Fairfield, C. Fairley, M. Faiz, L. Fajdiga, K. Falconer, W. Falconer, K. Falez, C. Falk, T. Falk, S. Fallahi, M. Fallen, Y. Fang, D. Fanning, T. Fanoiki, H. Farah, S. Farah, M. Fardy, S. Farhan,
A. Faria, H. Farid, M. Farman, S. Farn, D. Farney, M. Farokhshad, A. Farquhar, G. Farrell, J. Farrell, R. Farrell, T. Farrell, R. Farrer, T. Farrer, D. Farrow, S. Farrow, S. Faruqi, A. Faryna, B.
Fast, R. Fast, S. Fast, C. Faucher, S. Faucher, J. Faulkner, R. Faustini, E. Fauth, T. Fauth, C. Fayant, R. Fayant, M. Fear, R. Featherstone, N. Fecteau, M. Federucci, D. Fedoruk, E.
Fedossova, C. Fedun, T. Fedyna, E. Feely, D. Fehr, D. Feland, J. Feland, E. Feldkamp, J. Feldmeier, K. Fell, D. Feller, R. Fells, R. Feltham, E. Fender, M. Fender, X. Feng, L. Fentie, A.
Ferdjallah, S. Ferenc, K. Ference, B. Ferguson, C. Ferguson, H. Ferguson, J. Ferguson, M. Ferguson, R. Ferguson, S. Ferguson, M. Ferhatbegovic, B. Fernandes, A. Fernandez, E.
Fernandez, L. Fernandez Exposito, A. Feroz, M. Ferrer, N. Ferrer, M. Ferry, R. Fersch, T. Fertig, W. Fessler, S. Fetinko, C. Fetter, L. Fetter, D. Fewer, J. Fewer, C. Fibke, D. Fichter, T.
Fichter, M. Ficke, C. Ficko, M. Fielden, J. Fielding, K. Fielding, B. Fifield, C. Filewych, C. Filgate, M. Filipponi, D. Fillier, D. Fillion, T. Fillmore, M. Fincaryk, B. Finch, D. Findlay, J. Findlay,
N. Findlay, T. Findlay, A. Fink, B. Finlayson, J. Finley, C. Finnebraaten, R. Finney, B. Finnie, T. Finnigan, C. Fischer, L. Fischer, W. Fischer, C. Fisher, D. Fisher, B. Fitzgerald, C. Fitzgerald,
J. FitzGerald, S. Fitzner, J. Fitzsimmons, B. Fitzsimons, D. Fjeld, M. Flahr, C. Flamont, J. Flamont, J. Flanegan, D. Flannery, M. Flathers, B. Fleck, M. Flegel, A. Fleming, D. Fleming,
J. Fleming, N. Fleming, P. Fleming, S. Fleming, T. Fleming, N. Flemming, A. Fletcher, J. Fletcher, P. Flett, R. Flett, J. Fleury, B. Flier, T. Flight, B. Flockhart, I. Florea, B. Flottvik, B. Flynn,
C. Flynn, J. Flynn, R. Flynn, S. Flynn, C. Fogal, C. Foisy, K. Foisy, D. Fokema, D. Fokkens, R. Folmer, P. Foming, G. Fondjo, H. Fong, Y. Fong, D. Fontaine, G. Fontaine, K. Fontaine, L.
T2
Canadian Natural 2022 Annual Report
Fontaine, L. Foote, R. Foran, D. Forbes, G. Forbes, I. Forbes, M.
Forbes, S. Forbes, D. Forbister, T. Ford, W. Ford, G. Forde, C.
Forget, L. Forget, D. Forman, C. Formanek, R. Formanek, T.
Fornwald, G. Forrest, B. Forrester, R. Forrester, B. Forrister, B.
Forshner, S. Forster, H. Forte, A. Fortier, D. Fortin, A. Forward, J.
Forward, B. Foss, S. Foss, D. Fosseneuve, C. Foster, D. Foster,
J. Foster, K. Foster, R. Foster, S. Foster, D. Fotty, C. Fotur, O.
Fouego, A. Fougere, G. Fountain, J. Fountain, B. Fouracres, T.
Foureyes, G. Fowler, J. Fowler, A. Fowlis, A. Fox, D. Fox, J. Fox,
L. Fox, M. Foxton, S. Foxton, K. Fraboni, S. Fraino, C. Frampton,
C. France, J. France, R. France, M. Francescone, C. Francey, 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. Frasch, B. Fraser, C. Fraser, G. Fraser,
K. Fraser, M. Fraser, R. Fraser, A. Frayn, J. Frayn, K. Frazer, A.
Freake, G. Freake, B. Frechette, S. Freckelton, M. Freeman, U.
Freiberg, E. Frejoles, J. French, R. French, B. Frenette, K.
Frenzel, J. Frese, K. Freyman, K. Friedrich, D. Friedt, W. Friend,
A. Friesen, D. Friesen, F. Friesen, J. Friesen, K. Friesen, R.
Friesen, A. Frizorguer, D. Frizzell, C. Froc, J. Froc, B. Froggatt, C.
Frosini, C. Froude, S. Froude, T. Fryer, X. Fu, N. Fucile, A. Fudge,
C. Fudge, J. Fudge, L. Fudge, R. Fudge, S. Fuhr, K. Fujimoto, B.
Fujimoto-Johnston, D. Fukushima, W. Fulkerson, J. Fuller, G.
Fullido, D. Fung, F. Fung, J. Fung, S. Fung-Yau, K. Funk, R. Funk,
J. Furey, M. Furey, A. Furgiuele, A. Furlong, T. Furuya, C. Fuster,
A. Fyith, J. Gaberel, A. Gabr, K. Gabriel, L. Gabriel, D. Gabruck,
K. Gadzala, R. Gaetz, N. Gafuik, C. Gagne, D. Gagne, G. Gagne,
K. Gagne, T. Gagne, D. Gagnon, E. Gagnon, J. Gagnon, K.
Gagnon, S. Gagnon, W. Gail, S. Gailer, D. Gair, K. Gajjar, B.
Galbraith, P. Gale, M. Galea, J. Galey, R. Gallagher, C. Gallant, 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, D. Ganske, V. Gapaz, M. Garbin, A. Garcia, C. Garcia, J. Garcia, N. Garcia, A. Garcia Varganova, D. Gardham,
K. Gardiner, S. Gardiner, E. Gardner, S. Gardner, J. Gareau, R. Gareau, T. Gareau, R. Garg, V. Garg, D. Garland, K. Garland, W. Garner, R. Garrett, B. Garrow, L. Garvey, E. Gashaw, M.
Gates, S. Gauchan, C. Gaudet, F. Gaudet, G. Gaudet, L. Gauld, M. Gaulin, N. Gautam, C. Gauthier, D. Gauthier, J. Gauthier, M. Gauthier, N. Gauthier, S. Gauthier, A. Gboko, B. Geall,
J. Geddes, D. Geitz, C. Geldart, O. Gelowitz, M. Gemmell, M. Genereux, C. Geng, G. Genge, S. Genge, C. George, J. George, M. George, J. Georget, S. Geremia, G. Gerla, J.
Gerlinger, K. Gerow, E. Gervais, K. Gervais, M. Gervais, K. Gessner, S. Geta, T. Getchell, K. Getzinger, A. Ghanbaripour, H. Ghazimoradi, M. Ghorbanie, J. Ghosh, E. Ghoubrial, I.
Gibbon, E. Gibbs, C. Gibson, D. Gibson, S. Giefer, A. Gierach, M. Gierus, J. Gies, C. Giesbrecht, D. Giesbrecht, E. Giesbrecht, J. Giesbrecht, T. Giesbrecht, G. Giffin, J. Gigg, D. Giggs,
M. Giguere, G. Gilbert, C. Giles, M. Giles, S. Giles, T. Giles, V. Giles, J. Gilhang, D. Gill, G. Gill, H. Gill, K. Gill, L. Gill, M. Gill, N. Gill, S. Gill, J. Gillam, D. Gillan, S. Gillespie, M. Gillies,
D. Gillingham, J. Gillingham, L. Gillingham, S. Gillingham, E. Gillis, M. Gillund, C. Gilman, K. Gilman, D. Gilmer, E. Gimenez, R. Gimoro, G. Gin, K. 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, N. Gish, M. Gisondo Crawford, J. Gladue, B. Glaicar, D. Glasco, A.
Glasrud, G. Glasser, K. Glavine, M. Glavine, J. Glen, P. Glen, J. Glendenning, G. Glenn, N. Glidden, D. Gliddon, C. Glister, D. Gloade, D. Glover, S. Glubish, M. Go, R. Go, F. Godbout,
J. Godin, B. Godkin, D. Godwin, B. Goemans, L. Goerzen, C. Gogol, J. Gogol, B. Gogowich, H. Goldberg, D. Golden, E. Goldhart, P. Goldsney, A. Goll, D. Goll, P. Goll, C. Gomez, E.
Gomez, J. Gomez, J. Gomez Ramirez, L. Gomez Torres, C. Gomuwka, E. Gong, K. Gong, M. Gonzales, R. Gonzales, I. Gonzalez, L. Gonzalez, N. Gonzalez, Y. Gonzalez, P. Gonzalez
Sierra, C. Good, P. Good, J. Goodair, A. Goodine, P. Goodman, P. Goodwin, W. Goodwin, B. Goodyear, R. Gooler, K. Gordeyko, I. Gordon, J. Gordon, K. Gordon, S. Gordon, T. Gordon,
J. Gorgichuk, D. Gorrie, E. Gorrill, B. Gorski, J. Gorski, V. Goryachev, M. Goss, B. Gosse, D. Gosse, R. Gosse, T. Gosse, Y. Gosselin, B. Gosselink, B. Goudarzi, C. Goudreau, B. Gough,
C. Gough, B. Gould, J. Gould, S. Gould, T. Goulding, J. Goulet, J. Gourlie, G. Gouthro, S. Gouthro, J. Gover, A. Goyal, L. Goymer, J. Graca, N. Grace, J. Grach, M. Graf, J. Grageda, C.
Graham, J. Graham, M. Graham, S. Graham, T. Graham, E. Grandillo, I. Grandy, R. Grandy, B. Granger, J. Granger, A. Grant, C. Grant, I. Grant, J. 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, S. Gray, J. Greaves, 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. Greene-Thijs, R. Greening, K. Greenwood, M. Greenwood, R. Greenwood, N. Gregor,
A. Grenier, J. Grenon, A. Grewal, B. Grice, C. Grice, R. Grice, R. Grieco, C. Grieder, S. Grier, D. Grieve, R. Grieve, J. Griffin, M. Griffin, P. Griffin, J. Griffiths, J. Grijalva, K. Grimeau, A.
Grise, E. Grise, R. Griswold, R. Groenen, J. Groeneveld, M. Grosseth, W. Grotkowski, C. Grouchy, J. Grouchy, P. Grove, L. Groves, D. Grundner, D. Grzela, S. Gu, J. Guadarrama
Bracho, V. Guardia-Mendez, C. Guay, C. Gudjonson, S. Gue, D. Guevara Castellanos, D. Guevohe, D. Guglielmin, A. Guillen, J. Guilmette, K. Guimond, C. Guinup, R. Guinup, K.
Gulamhusein, R. Gulati, S. Guled, R. Gulutzan, J. Gumbley, E. Gummeson,
K. Gundersen, I. Gunning, A. Gupta, J. Gurba, C. Guriev, 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,
B. Guy-Bergey, J. Guzzi, G. Gygi, B. Gyles, J. Gysler, D. Ha, T. Ha, E. Haag, B.
Haas, S. Haas, C. Haavardsrud, G. Haberlin, M. Haberoth, A. Habtesgy, C.
Hachey, K. Hachey-Lalonde, S. Hackett, E. Hadada, V. Haddad, L. Hadi, T.
Hadji, N. Hadskis, S. Haefliger, S. Hagan, D. Hagel, T. Hagen, L. Hagg, A.
Hagi-Memet, S. Hagman, K. Hague, S. Hahn, J. Haidasz, A. Haj Hamdan, M.
Haj Hamdan, S. Haji, S. Hajizadeh, S. Halaburda, D. Halewich, K. Halewich,
M. Halewich, B. Haley, J. Halford, B. Halifax, D. Halifax, B. Hall, C. Hall, J.
Hall, M. Hall, R. Hall, S. Hall, S. Halland, L. Hallas, S. Hallas, R. Halldorson,
K. Halliday, R. Hallock, A. Halvorson, J. Ham, C. Hambly, B. Hamborg, A.
Hameed, K. Hameed, J. Hamel, P. Hamel, T. Hamel, J. Hamelin, B. Hamer, D.
Hamer, S. Hamill, A. Hamilton, C. Hamilton, D. Hamilton, G. Hamilton, J.
Hamilton, K. Hamilton, M. Hamilton, R. Hamilton, T. Hamilton, T. Hamitaj, K.
Hamm, A. Hammami, M. Hammel, S. Hammel, R. Hammer, D. Hammerlindl,
K. Hammersley, S. Hammersley, B. Hammond, G. Hammond, J. Hammond,
M. Hammond, R. Hammond, G. Hammoud, P. Hamnett, G. Hampson, C.
Hampton, B. Hamrell, E. Han, G. Hanas, E. Hancock, M. Hancock, B.
Hancott, S. Hancott, K. Hand, R. Hanlon, S. Hanlon, E. Hann, R. Hann, B.
Hanna, D. Hanna, W. Hanna, 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, C. Harbidge, B. Harbin, M.
Hardcastle, C. Harder, D. Hardes, C. Harding, P. Harding, G. Hardisty, J.
Hardisty, F. Hardy, H. Hardy, J. Hardy, A. Hare, E. Harikumar, A. Harlal, D.
Harley, J. Harmatys, E. Haroldson, J. Harpell, R. Harriman, A. Harris, B.
Harris, J. Harris, M. Harris, S. Harris, C. Harrison, D. Harrison, N. Harrison,
D. Hart, C. Hartery, C. Hartl, B. Hartman, P. Hartwick, A. Harty, J. Harty, B.
Harvey, D. Harvey, J. Harvey, K. Harvey, P. Harvey, R. Harvey, S. Harvey, M.
Hashem, I. Hashi, S. Haskell, B. Hassan, I. Hassan, M. Hassan, O. Hassan,
R. Hasselmann, B. Hassen, E. Hasson, M. Haswell, J. Hatala, B. Hatam, J.
Hatcher, G. Hatto, G. Haub, R. Hauger, T. Hauger, B. Haugo, J. Haviland, S.
Hawco, T. Hawco, C. Hawkings, D. Hawkins, H. Hawkins, S. Hawryliw, G.
Hawryluk, N. Hay, D. Hayashi, C. Hayden, E. Hayden, J. Hayden, D. Hayes, P.
Hayes, K. Hayko, D. Haynes, L. Haynes, M. Hays, A. Hayward, M. Hayward,
R. Hayward, T. Hayward, N. Hazelwood, J. Hazin, C. He, J. He, S. He, T. He,
Y. He, T. Head, M. Headrick, B. Heagy, C. Heagy, A. Heale, N. Heale, M.
Healey, L. Healy, B. Heasley, A. Heath, B. Heath, C. Heath, D. Heath, R.
Heather, L. Heath-Johnson, B. Heatley, S. Heaton, D. Heavens, S. Heawood,
T. Hebel, B. Hebert, D. Hebert, J. Hebert, M. Hebert, S. Heck, D. Heemeryck,
K. Heffernan, C. Heffner, D. Hefford, C. Hehr, T. Heid, R. Heide, J.
Heidebrecht, T. Heidebrecht, C. Hein, R. Hein, R. Heinrichs, B. Heise, R.
Heiz, R. Helland, B. Helliker, R. Hellum, Q. Helm, D. Helms, C. Hemington,
D. Hemmelgarn, T. Hempel, B. Hemstock, C. Henderson, D. Henderson, J.
Henderson, R. Henderson, S. Henderson, W. Henderson, F. Hendricks, K.
Hendrickson, T. Hendriks, C. Hendry, S. Hendry, K. Hennessey, A. Hennig, C.
Henry, U. Henshaw, D. Herauf, K. Herba, C. Herbst, G. Herbst, W. Hergott,
B. Herman, W. Herman, A. Hernandez, E. Hernandez, G. Hernandez, J.
Hernandez, M. Hernandez, P. Hernandez, C. Herring, R. Herrington, D.
Hertzsprung, M. Herzog, D. Heshka, R. Heska, A. Hess, A. Heugenhauser,
B. Heugh, J. Hevey, M. Hewitt, T. Hewitt, D. Hewko, T. Hewko, J. Hewlett, K.
T3
Canadian Natural 2022 Annual Report Hewlin, A. Heydari Gorji, A. Heynen, C. Heywood, R. Hibbs, D.
Hicke, M. Hickey, P. Hickey, R. Hicks, S. Hicks, L. Hiebert, R.
Hiebert, M. Hiemstra, T. Hiemstra, E. Hietanen, R. Higa, A.
Higgins, J. Higgins, L. Higgins, M. Higgins, R. Higgins, P. Higgitt, J.
Higuerey De Sanchez, M. Higuerey Rodriguez, C. Hildahl, J.
Hildebrandt, C. Hill, D. Hill, H. Hill, J. Hill, K. Hill, T. Hill, D. Hillier, R.
Hillier, T. Hillier, R. Hillis, C. Hills, T. Hills, D. Hillyard, T. Hilsendager,
Z. Hilsendager, B. Hindmarch, Z. Hines, A. Hinestroza Cordoba, W.
Hinkle, T. Hinks, N. Hinze, M. Hird, D. Hiscock, S. Hiscock, F.
Hiscox, D. Hitra, T. Hlewka, A. Ho, J. Ho, M. Ho, T. Ho, J. Hoare, W.
Hobart, A. Hobbi, J. Hobbs, P. Hocaloski, R. Hoda, C. Hodder, G.
Hodder, J. Hodder, D. Hodge, M. Hodge, R. Hodgins, J. Hodgson,
A. Hoeg, C. Hoeppner, N. Hoey, M. Hoffart, L. Hoffman, R.
Hoffman, M. Hofstrand, G. Hogan, L. Hogan, R. Hogan, S. Hogan,
A. Hogg, J. Hogg, L. Hogg, M. Hogg, R. Hogg, B. Holaki, J.
Holben, C. Holgate, D. Holik, K. Holladay, A. Holland, E. Holland, K.
Holland, M. Holland, S. Holland, P. Hollett, D. Holley, D.
Hollingshead, G. Holloway, L. Holloway, J. Hollowell, C. Holman,
D. Holman, R. Holman, G. Holmes, J. Holmes, M. Holmes, N.
Holmes, T. Holmes, S. Holmstrom, B. Holthe, C. Holthe, J. Holton,
J. Holuk, A. Holz, J. Holz, G. Homann, P. Hondl, L. Hong, Q. Hong,
D. Honing, C. Hood, J. Hood, G. Hook, J. Hook, J. Hooper, R.
Hooper, A. Hope, S. Hopkins, Y. Hopkins, M. Hopp, T. Hopwood, A.
Hordy, R. Horn, T. Hornberger, Z. Horne, A. Hornseth, K. Hornseth,
B. Horobec, K. Horvath, R. Horvath, C. Horwood, J. Horyn, K.
Hosker, J. Hoskins, B. Hossain, F. Hossain, M. Hossain, S.
Hosseini, M. Hosseininejad, A. Hosseinpoor, T. Hou, K. Hough, L.
Houghton, R. Hourd, G. House, P. House, R. House, T. House, L.
Houseman, G. Houston, T. Houston, K. Hovdebo, G. Howard, K.
Howard, T. Howard, C. Howden, L. Howell, M. Howell, K. Howes,
P. Howie, S. Howlader, J. Howse, M. Hoyles, T. Hoyles, R. Hoyt, B.
Hoza, J. Hripko, D. Hrycak, J. Hrycak, T. Hrycay, B. Hryniw, A.
Hrynkevych, R. Hrynyk, P. Hsieh, J. Hu, M. Hu, T. Hu, Y. Hu, D. Huang, J. 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, D. Hudson, P. Hudson, D. Hudye, S. Huebner, L. Hueser, V. Huey, J. Huffman, B. Hughes, J. Hughes, M. Hughes, E. Huh, C. Hulbert, D. Hull,
F. Hulme, M. Human, R. Humphrey, J. Humphreys, S. Humphreys, A. Humphries, C. Humphries, S. Humphries, T. Humphries, M. Hunchak, T. Hundal, I. Hundeby, M. Hundessa, M.
Hung, I. Hunkin, M. Hunsperger, C. Hunt, D. Hunt, M. 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, J. Hussynec, R. Hussynec, C. Hutchinson, R. Hutchinson, E. Hutton,
A. Huynh, M. Huynh, M. Huys, E. Hwang, S. Hwang, S. Hyatt, K. Hygard, A. Hymanyk, A. Hynes, D. Hynes, E. Hynes, J. Hynes, M. Hynes, N. Hynes, S. Hyrcha, G. Iannattone, L.
Iannattone, R. Ibbotson, K. Ibrahim, S. Ibrahim, T. Idler, M. Ierino, G. Iervella, O. Ifediniru, S. Ifemeje, N. Ilchuk, S. Ilczynski, R. Imankulov, D. Imbeau, E. Imbery, W. Imeson, K. Imlach,
M. Imran, S. Imrie, Y. Imtiaz, R. Inaray, 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, R. Ireton, M. Irfan, J. Irons, R. Irvine, R. Irwin, S. Irwin, J. Isaacs, C. Isea Natera, B. Ish, H. Ishaque, M. Islam, R. Islam, U. Islam, O. Issa, E. Issavi, H. Iturralde, M.
Ivanov, J. Ivanova, A. Ivany, B. Ivany, D. Ivany, L. Iversen, C. Ives, J. Ivezic, O. Iwoh, M. Jablonski, C. Jabusch, M. Jackman, B. Jackson, D. Jackson, J. Jackson, K. Jackson, R. Jackson,
S. Jackson, T. Jackson, D. Jacob, J. Jacob, S. Jacob, C. Jacobs, J. Jacobs, K. Jacobs, M. Jacobs, K. Jacobson, A. Jacques, A. Jacula, C. Jacula, D. Jaeger, J. Jaegli, A. Jaffer, H.
Jaggard, E. Jagrelius, M. Jahangiri, R. Jahanshahi, V. Jain, M. Jaindl, K. Jaji, R. Jakher, H. Jalali, M. Jalali, G. Jaleel, L. Jama, M. Jama, F. Jamah Khan, S. Jamam, T. Jaman, A.
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Jaspar, S. Jaume, K. Jay, M. Jay-Rivas, S. Jazayeri Dezfouli, S. Jeanes, J. Jechow, W. Jellison, Y. Jen, 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, T. Jensen, V. Jensen, K. Jentas, H. Jeong, D. Jerkovic, M. Jeroncic, T. Jervis, C. Jesso, M. Jesso,
T. Jessome, S. Jevne, M. Jewel, C. Jezowski, P. Jia, N. Jiang, S. Jiang, Y. Jiang, Z. Jiang, X. Jing, P. Jingar, K. Jivraj, R. Jivraj, M. Joarder, P. Jobin, 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, R. Johnson, S. Johnson, T.
Johnson, C. Johnston, D. Johnston, J. Johnston, L. Johnston, N. Johnston, R. Johnston, S. Johnston, C. Johnstone, D. Johnstone, G. Johnstone, A. Jolliffe, J. Jonasson, A. Jones,
B. Jones, C. Jones, D. Jones, E. Jones, G. Jones, K. Jones, L. Jones, M. Jones, R. Jones, N. Jongkind, P. Joo, M. Jordan, B. Jorgensen, D. Jorgensen, M. Jorgensen, L. Jorgenson
Donahue, D. Joseph, A. Joshi, H. Joshi, T. Joshi, U. Joshi, S. Joshua, S. Josselyn, R. Jost, D. Jowsey, L. Joy, M. Juanerio, R. Jubinville, T. Juett, P. Jugdev, A. Juhasz, K. Juhasz, A.
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M. Karpan, C. Karpiak, K. Kartushyn, P. Karval, U. Karymbaev, E. Kasatkin, M. Kashif, N. Kashirina, B. Kashuba, C. Kaskiw, M. Kaspers, F. Kassam, A. Katebi, D. Katnick, A. Katyayan,
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Khalil, T. Khambalkar, A. Khan, F. Khan, G. Khan, M. Khan, S. Khan, N. Khatri, R. Khatri, S. Khong, S. Kiasosua, I. Kidd, R. Kidd, B. Kidmose, E. Kie, B. Kiedyk, C. Kiehn, L. Kiez, C.
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King, R. Kingcott, T. Kingsbury, S. Kinnear, C. Kinniburgh, P. Kip, B. Kirby-Graham, T. Kirchner, M. Kireev, D. Kirkham, L. Kirkland, L. Kirkpatrick, W. Kirkpatrick, M. Kirkwood, B. Kiss, J.
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M. Klimkiewicz, E. Klitiris, J. Klok, L. Kloster, G. Kluthe, R. Knee, S. Knelsen, W. Knelson, D. Kneteman, R. Kneteman, M. Kniebel, G. Knight, J. Knight, P. Knight, R. Knight, J. Knipe,
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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, N. Koncohrada, M. Kondor, B.
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B. Krawchuk, C. Krawchuk, J. Krawetz, M. Krawetz, S.
Krebs, J. Kreft, T. Kreics, B. Krell, B. Kress, L. Kress, K.
Krewulak, R. Krishnaiyer, A. Krishnamoorthy, R.
Krishnamurthy, B. Kristianson, K. Kristman, N. Krochmal,
M. Kroeker, R. Kroeker, K. Krogh, P. Krol, U. Krstic, R.
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S. Kullman, C. Kully, T. Kulyk, B. Kumar, P. Kumar, R. Kumar,
S. Kumar, C. Kung, D. Kunitz, J. Kunka, J. Kuntz, P. Kuppers,
S. Kurczaba, D. Kurek, M. Kureshi, M. Kurowski, K.
Kurschenska, D. Kurtz, K. Kurtz, R. Kurtz, A. Kuruvilla, G.
Kushe, M. Kusk, S. Kuslivyy, D. Kusmiadji, B. Kutash, E.
Kutash, K. Kuzevanova, B. Kuziyamisa, F. Kuzmic, C. Kwan,
R. Kwiatkowski, S. Kwiatkowski, V. Kwiatkowski, J. Kwong,
T. Ky, J. Kyes, D. Kyle, M. Kyluik, J. Kynock, R. Kynock, A.
Kyren-Stortz, J. LaBossiere, A. Laboucan, J. Laboucan, R.
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Lachance, J. Lacharite, K. Lacombe, R. Lacombe, B.
Lacoursiere, D. Lacroix, M. Lacroix, R. Lacroix, S. Lacroix,
L. Lacuna, P. Ladera, A. Laderoute, K. Ladji, B. Lafferty, K.
Lafferty, D. Lafond, S. Lafond, D. Lafontaine, R. Laforge, L.
Lafreniere, B. Lagler, D. Lagos, S. Lagos, A. Laguduva, D.
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Landry, J. Landry, L. Landry, M. Landry, S. Landry, T.
T4
Canadian Natural 2022 Annual Report Landry, Y. Landry, X. Landry-Pellerin, W. Landsburg, B. Lane, M. Lane,
S. Lane, W. Lane, R. Lanfranchi, C. Lang, J. Langdon, G. Lange, L.
Lange, O. Lange, S. Lange, S. Langford, T. Langill, C. Langpap, B. Lanh,
R. Laniec, D. Lanouette, C. Lanthier, L. Lanza, S. Lanza, D. LaPlante, C.
Lapp, C. Lappin, M. Larade, G. Laramee, G. Lardner, S. Larkam, E.
Larm, J. Larochelle, A. Larocque, J. Larocque, E. LaRose, A. Larsen, 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, J.
Lathrop, A. Latif, Z. Latif, C. Latimer, R. Latimer, M. LaTorre, A. Latypov,
J. Lau, L. Laube, A. Lauder, P. Laughman, M. Lausen, S. Laut, R. Lauze,
J. Lauzon, M. Lavallee, D. Laventure, K. Laverty, P. Lavery, V. Laviano, B.
Lavigne, C. Lavoie, C. Lawford, P. Lawless, S. Lawlor, 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, L. Le, M. Le, N. Le, T. Le, R. Le Manne, B. Leach, T. Leach, R.
Leahy, C. Leamon, K. Leamon, L. Leamon, J. Learning, A. Leather, M.
Lebas, C. LeBlanc, H. Leblanc, J. LeBlanc, T. Leblanc, W. LeBlanc, C.
Lebrun, S. LeBrun, S. Lebsack, A. LeClair, S. Leclair, A. Leclerc, C.
Ledrew, A. Lee, B. Lee, C. Lee, D. Lee, J. Lee, K. Lee, L. Lee, M. Lee,
R. Lee, S. Lee, T. Lee, B. Leeman, J. Leeman, M. Lefaivre, G. Lefebure,
J. Lefebure, D. Lefebvre, M. Lefebvre, S. Lefebvre, K. Legault, J.
Legere, P. Legere, M. Legge, M. LeGrow, K. Lehal, B. Lehbauer, C.
Lehmann, S. Lei, P. Leier, C. Leishman, M. Leitch, B. Lekach, J. Leman,
D. Lemieux, R. Lemoine, Z. LeMoine, P. Leniuk, P. Lennon, C. Lenz, S.
Lenz, J. Lenzner, T. Leon, J. Leonard, C. Leong, G. Leong, H. Leong, S.
Lepine, S. Lepp, L. Leppaie, Y. Lerner, C. Leroux, E. Leroy, C. Leschinski,
T. Lesko, R. Leslie, S. Lester, B. Lesyk, C. Lesyk, M. Lethaby, F.
Letkeman, T. Letkeman, M. Letourneau, H. Lett, B. Letwin, D. Leung, J.
Leung, K. Leung, M. Leung, P. Leung, R. Leung, J. Levac, O. Levesque,
R. Levesque, S. Levins, C. Lewis, D. Lewis, J. Lewis, K. Lewis, P.
Lewis, R. Lewis, T. Lewis, W. Lewis, R. Lewiski, V. Leyva, A. Li, B. Li, H.
Li, J. Li, M. Li, Q. Li, S. Li, W. Li, Y. Li, O. Liadi, B. Liang, N. Liang, S.
Liao, C. Liba, P. Libari, M. Liber, N. Liegman, S. Lien, C. Lieverse, J.
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Y. Lin, T. Lind, S. Lindballe, K. Linder, T. Lindley, G. Lindner, E. Lindsay,
D. Lindskog, B. Lingard, A. Linggon, P. Linklater, N. Linnell, J. Linton,
M. Liou-McKinstry, R. Liske, C. Little, G. Little, J. Little, S. Little, J. Littlechilds, C. Litwin, H. Liu, J. Liu, M. Liu, T. Liu, W. Liu, X. Liu, Y. Liu, J. Liu Prest, E. Liv, R. Livingston, S.
Livingstone, M. Lizcano, C. Lizee, R. Lloy, M. Lloyd, P. Lloyd, R. Lloyd, Y. Lo, A. Lobban, A. Lobbes, G. Lobdell, J. Lochansky, L. Lock Wu, F. Locke, R. Locke, T. Locke, W. Locke, A.
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M. Lorincz, B. Lorinczy, M. Loring, K. Lorteau, M. Loshny, J. Lotito, T. Lougheed, A. Loughran, E. Louie, C. Love, M. Love, D. Loveless, J. Loveless, W. Loveless, I. Lovera-Figueroa,
E. Lovmo, B. Low, N. Low, C. Lowe, D. Lowe, J. Lowe, C. Lowen, J. Lowen, J. Lowry, K. Loyer, L. Loyola, C. Lozano, C. Lozinski-Kumpula, A. Lu, J. Lu, C. Lucas, G. Lucas, J. Lucas,
T. Lucksinger, E. Ludwig, S. Lui, L. Luiken, C. Luk, K. Luk, K. Lukan, L. Lukey, H. Lund, K. Lund, W. Lundell, K. Lundrigan, E. Lunn, R. Lunn, J. Lunt, X. Luo, B. Luong, M. Lupul, B.
Lush, D. Lush, J. Lush, R. Lushman, R. Lusk, A. Lussier, K. Lussier, C. Lutsch, D. Lutwick, J. Lutyck, K. Lutz, J. Luyt, J. Ly, G. Lyall, K. Lyall, T. Lychak, T. Lychuk, G. Lykidis, D. Lynch,
L. Lynch, S. Lynch, R. Lynett, M. Lynn, B. Lynott, W. Lyon, N. Lyons, D. Lysak, P. M Hislop, H. Ma, J. Ma, Y. Ma, N. Maawia, M. MacBeth, K. MacComish, M. MacConnell, L. Macdaid,
A. MacDonald, B. Macdonald, C. Macdonald, D. MacDonald, F. MacDonald, I. MacDonald, J. MacDonald, L. MacDonald, M. MacDonald, P. MacDonald, R. Macdonald, T. Macdonald,
W. MacDonald, G. MacDonell, A. MacDougall, J. MacDougall, M. MacDougall, S. MacDougall, T. Macdougall-Sinclair, C. MacEachern, J. MacEachern, M. MacEachern, T. MacEachern,
Y. Macedo, B. MacFarlane, O. MacFarlane, K. MacGillis, A. Macgillivray, D. MacGregor, G. MacGregor, S. MacGregor, T. MacGregor, T. Mach, K. Machado Rodriguez, S. MacHale, R.
Maciborski, J. Maciejewski, T. Macijuk, A. MacInnis, L. MacIntosh, J. MacIntyre, T. Macintyre, D. MacIsaac, M. MacIsaac-Jones, D. MacIvor, A. Mack, C. Mack, K. Mack, L. Mack, S.
Mack, C. Mackay, G. MacKay, L. Mackay, M. MacKay, S. MacKay, R. Mackelvie, A. Mackenzie, C. Mackenzie, D. Mackenzie, K. MacKenzie, M. MacKenzie, S. Mackenzie, T. Mackenzie,
B. MacKey, S. Mackey, A. MacKinnon, B. MacKinnon, G. Mackinnon, K. MacKinnon, T. MacKinnon, W. Mackinnon, F. Mackley, N. Macklin, T. MacLaren, A. Maclean, C. MacLean, E.
MacLean, M. MacLean, R. MacLean, S. Maclean, A. Maclellan, G. MacLellan, J. MacLellan, M. MacLellan, J. MacLennan, A. MacLeod, C. Macleod, I. MacLeod, J. MacLeod, L.
MacLeod, M. MacLeod, S. MacLeod, W. MacLeod, N. MacMillan, S. Macmullin, T. Macmurran, A. Macneil, B. MacNeil, C. Macneil, J. MacNeil, B. MacNeill, W. MacPherson, H.
Macrae, M. MacRitchie, E. MacVicar, T. MacVicar, B. Macwilliams, C. Madadi, F. Madanat, P. Maddela, C. Madill, H. Madlung, D. Madoche, G. Madsen, L. Madsen, M. Maennchen, L.
Maga, J. Magbanua, C. Magdiak, C. Mageau, B. Mageza, S. Magill, C. Magnan, D. Magnusson, M. Magnusson, J. Magpali, V. Magsila, R. Maguet, D. Mah, J. Mah, M. Mah, R. Mah,
M. Mahar, N. Mahar, Z. Mahe, J. Mahon, A. Maida, T. Mailandt, M. Mailhot, D. Maillet, M. Mailloux, R. Mailman, J. Mainville, R. Mairena, B. Maisey, D. Maisey, S. Majdnia, A. Majidi,
P. Major, J. Makahnouk, N. Makarova, M. Makhoul, D. Makin, M. Makin, L. Makowichuk, G. Makumbe, D. Malabad, C. Malbog, S. Malcolm, H. Maldonado, M. Malech, P. Malhame,
M. Malik, W. Malik, A. Malimban, T. Malkova, J. Mallard, K. Mallard, S. Mallay, G. Mallette, T. Malley, C. Mallory, G. Malo, J. Maloney, A. Maltseva, G. Malvar, M. Malyk, O. Malyshev,
S. Mamedov, J. Manalastas, M. Manderscheid, D. Manengyao, L. Manfredi, J. Manful, J. Mangrove, G. Manhas, M. Manhera, T. Manji, P. Manlapaz, A. Manlongat, D. Mann, G. Mann,
K. Mann, P. Mann, R. Mann, S. Mann, J. Manning, P. Manoharan, K. Manolov, S. Manolov, 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, A. Marcel, A. Marchand, L. Marchand, S. Marche, F. Marchesan, M.
Marchi, R. Marcichiw, A. Marcinkoski, M. Marcotte, T. Marcotte, L. Marcucci, J. Margel, J. Margetson, W. Margison, V. Maries, E. Marilao, S. Marin, P. Marinzi, S. Marion, D. Mark, S.
Markle, S. Markosyan, B. Marks, K. Markstrom, P. Marolt, U. Maroney, B. Marple, A. Marquez Socorro,
T. Marquis, S. Marra, 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, M.
Martell, P. Martell, D. Martens, A. Marter, A. Martin, B. Martin, C. Martin, D. Martin, J. Martin, K.
Martin, M. Martin, S. Martin, T. Martin, D. Martinat, S. Martin-Courtright, S. Martinella, Z. Martinez, O.
Martis, D. Martyn, R. Martyn, M. Martynuik, A. Martyshuk, M. Martyshuk, J. Maruniak, K. Mashayekh,
R. Masih, R. Maskoni, B. Mason, C. Mason, K. Mason, P. Mason, D. Massey, A. Massicotte, P.
Massicotte, M. Mata, A. Matatko, T. Matatko, A. Matchem, S. Matchett, H. Mateen, D. Mathers, D.
Matheson, E. Matheson, P. Matheson, S. Matheson, T. Matheson, A. Mathew, L. Mathew, D.
Mathieson, F. Mathieson, E. Mathieson-Allan, C. Mathiot, J. Mathis, B. Matsalla, K. Matsalla, T.
Matsushita, B. Matthews, C. Matthews, E. Matthews, N. Matthews, J. Matthiessen, R. Mattson, R.
Matychuk, P. Maurice, S. Maurice, A. Maurier, D. Mavridis, A. Mawer, V. Maximo, C. Maxsom, J.
Maxwell, R. Maxwell, K. May, R. May, C. Maye, F. Mayell, M. Mayen, J. Mayer, R. Mayers, A. Maynard,
W. Maynard, B. Mayo, C. Mays, A. Mazur, C. Mazuryk, H. Mc Gee, D. McAlister, M. McAlpine, D.
McArthur, R. McArthur, E. McAvoy, N. McBain, J. McBride, R. McBrien, T. McCabe, S. McCaffrey, A.
McCalla, J. McCallum, S. McCann, D. McCarry, J. McCarthy, J. McCarty, D. McCarvill, K. McClary, A.
McClean, G. McClean, D. McClelland, I. McClelland, J. Mcclyment, B. McConachie, C. McConnell, M.
McCormack, A. McCormick, C. Mccoy, S. McCracken, K. McCrae, C. McCrea, G. McCrea, J. McCrea,
S. McCreery, G. Mccubbing, B. McCullagh, C. McCullough, D. McCullough, R. McCullough, C.
McDonald, D. McDonald, J. McDonald, K. McDonald, M. McDonald, L. McDonnell, K. McDougall, M.
McDougall, S. McDougall, J. McDowell, R. McEachnie, N. McElroy, J. McEwen, W. McEwen, M.
McFarlane, A. McFaul, B. McFaul, L. McFeeters, M. McGannon, N. McGarry, F. McGaw, L. McGean,
D. McGee, L. McGee, D. McGinnis, P. McGinnis, B. McGlone, A. McGrath, C. McGrath, D. Mcgrath, K.
Mcgrath, L. McGrath, M. McGrath, T. McGrath, S. McGregor, T. McGregor, K. McGroarty, S. McHardy,
L. McHugh, D. McIlvaney, D. McIntosh, G. McIntosh, W. McIntosh, C. McIntyre, P. McIntyre, R.
McIntyre, C. McIver, B. Mckay, J. McKay, L. McKay, N. McKay, R. McKay, S. McKay, T. McKay, N.
McKeachnie, T. McKeddie, A. McKee, T. McKee, W. McKellar, N. McKendry, F. McKenna, M. McKenna,
P. McKenna, T. McKenna, A. McKenzie, J. McKenzie, K. McKenzie, M. McKenzie, R. McKeown, D.
Mckersie, H. McKiel, C. McKim, S. McKinney, A. McKinnon, J. Mckinnon, K. Mckinnon, S. McKinnon,
R. McLachlen, M. McLane, C. McLaren, D. McLaren, K. McLaren, H. McLarty, T. Mclaughlan, J.
McLaughlin, M. McLaughlin, M. McLean, R. McLean, W. Mclean, A. McLellan, C. McLellan, K.
McLellan, T. McLellan, M. McLenehan, B. McLennan, G. McLennan, C. McLeod, D. McLeod, I.
McLeod, R. McLeod, S. McLeod, T. McLeod, P. Mcloughlin, L. McMahon, K. McMann, J. McMaster, S.
McMichael, J. McMillan, R. McNabb, R. McNair, D. McNamara, K. McNaughton, R. McNaughton, K.
McNay, M. McNay, A. McNeil, D. McNeil, G. McNeil, H. McNeil, J. McNeil, K. McNeil, M. McNeil, P.
McNeil, Q. McNeil, R. McNeil, S. McNeill, T. McNelly, L. McPhee, R. McPhee, B. Mcpherson, J.
McPherson, K. McPherson, A. McQueen, E. McQueen, K. McRae, R. McRae, A. McSharry, J.
McTamney, B. McTavish, C. McWhan, C. McWhinnie, M. Meade, D. Meador, B. Meadus, P. Meadus,
S. Meagher, M. Meckelborg, M. Medhurst, I. Medina, N. Medina, R. Medley, D. Medlicott Lymburner,
N. Meethal, E. Meginbir, K. Meh, M. Mehaney, F. Mehdiyev, E. Mehlhaff, S. Mehrotra, N. Mehta, V.
Mehta, E. Meister, J. Mejia, C. Mejia Botero, B. Melanson, D. Melanson, J. Melanson, R. Melanson,
T5
Canadian Natural 2022 Annual Report T. Melindy, H. Mellafont, B. Meller, L. Mello, K. Melnyk, M. Melnyk, A. Melo, J. Melville, A. Menard, L.
Mendenhall, P. Mendes, M. Mendonca, S. Mendonca, A. Mendoza, N. Meneses, F. Meng, D. Menjivar, B.
Mennie, P. Menzel, G. Merali, J. Merasty, G. Mercer, J. Mercer, L. Mercer, J. Mercier, M. Merhi, C. Merkel,
G. Merkel, D. Merkley, A. Merle, S. Merralls, K. Merrill, C. Merritt, N. Merritt, R. Merritt, U. Meservy, K.
Mess, S. Metcalfe, T. Methuen, C. Metz, S. Meunier, R. Mewis, C. Mews, D. Mews, R. Mews, J. Meyer, L.
Michalishen, C. Michalko, Z. Michalski, B. Michaud, J. Michaud, T. Michel, M. Michelin, K. Mickel, N.
Mickelson, D. Midgley, K. Mielty, C. Mihai, J. Mihailoff, T. Mijic, D. Mikalson, A. Mikhailov, K. Mikkelson, S.
Mikloukhine, J. Miko, G. Milan Garcia, J. Milce, R. Miles, R. Millar, B. Miller, 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, S. Milnthorp, D. Milward, V. miner,
F. Mingle, A. Minhas, M. Minick, W. Minni, W. Minns, D. Mino, J. Minor, A. Mir, S. Mir, T. Mir, W. Mirabal, B.
Mirza, W. Mirza, M. Mirzadeh, D. Misner, J. Mistecki, D. Mistry, C. Mitchell, G. Mitchell, J. Mitchell, R.
Mitchell, T. Mitchell, W. Mitchell, N. Mitchell-Banks, M. Mitton, R. Mkumbukwa, J. Mo, V. Modak, B.
Moelbert, I. Moffat, J. Moffat, R. Mogensen, A. Mognin, H. Moh, A. Mohamed, S. Mohamed, G. Mohammed,
A. Mohideen, J. Mohl, D. Moisan, J. Molde, N. Molder, N. Molina, A. Molina-Wright, R. Mollison, J. Molnar,
K. Molzan, T. Mombourquette, R. Monahan, R. Money, P. Monfette, C. Montague, L. Monteith, R. Monteith,
J. Montgomery, M. Montinola, K. Moon, J. Mooney, D. Moore, E. Moore, J. Moores, L. Mora, M. Moradi, A.
Morelli, K. Morency, H. Moreno, L. Moreno, C. Morgan, J. Morgan, S. Morgan, T. Morgan, G. Mori, M.
Moriarty, A. Morin, J. Morin, M. Morin, P. Morin, R. Morin, D. Mork, J. Morley, R. Morley, S. Morman, K.
Morphy, K. Morrell, S. Morrey, B. Morris, D. Morris, I. Morris, J. Morris, K. Morris, P. Morris, S. Morris, J.
Morriseau, A. Morrison, B. Morrison, C. Morrison, D. Morrison, J. Morrison, S. Morrison, S. Morse, D.
Morsette, A. Mortlock, A. Morton, M. Morvik, D. Mose, D. Moser, T. Moser, J. Moshenko, T. Moskol, M.
Moss, P. Mossey, B. Mossop, J. Mostyn, S. Mothersele, L. Motowylo, S. Moul, L. Mounkes, I. Mountain, S.
Mourou, M. Mousavi, S. Mousazadeh, M. Mousseau, C. Mouta, J. Moyer, R. Moyle, C. Moyls, W. Mrazek, Y.
Mu, M. Mubarak, T. Mudzviti, T. Mueller, T. Muessle, R. Mugford, M. Mughal, F. Muhammad, S. Muhammad,
K. Muir, D. Muise, S. Muise, V. Mukerji, K. Mullaly, B. Mullen, G. Mullen, C. Mullett, B. Mulligan, R. Mullin,
N. Mulvena, M. Munday-Galbraith, S. Mundt, K. Munn, A. Munro, J. Munro, L. Munro, R. Munro, M.
Munyuza, G. Murley, A. Murphy, B. Murphy, C. Murphy, D. Murphy, J. Murphy, P. Murphy, R. Murphy, T.
Murphy, J. Murrant, B. Murray, C. Murray, G. Murray, K. Murray, L. Murray, S. Murray, E. Murrin, A. Murrison,
A. Mushava, I. Music, I. Musiwarwo, W. Muss, D. Musselman, T. Musselman, N. Musterer, Z. Musuna, A.
Muthuswamy, R. Mutschler, T. Mutter, I. Muwhen, J. Mweshi, D. Myers, S. Myles, J. Nachtigal, B. Nadeau,
C. Nadeau, S. Nadeau, M. Naderikia, S. Nagare, A. Nagra, J. Nagy, J. Nagy-Kolodychuk, J. Naidu, K. Naik, J.
Nair, R. Nair, S. Nair, K. Najafian, S. Najeeb, L. Najoan, R. Nakonechny, B. Nalder, N. Namoca, E. Namur, M.
Nandoria, J. Napier, R. Napier, C. Naqvi, S. Naqvi, P. Narayan, R. Narayan, K. Narayanan, A. Narcise, S. Naser,
A. Nasir, N. Nasser, M. Nassir, D. Nater, M. Nathwani-Crowe, D. Naugler, P. Nava, D. Navas, R. Navas, V.
Navratil, B. Nawaz, S. Nayak, O. Nazari, C. Nazarko, B. N’Dure, D. Neal, S. Neal, N. Neale, M. Neate, E.
Nechushkina, A. Neddjar, S. Needham, D. Neergaard, S. Negi, Y. Neguse, D. Neigum, A. Neilson, S. Neilson, K. Nelligan, A. Nelson, B. Nelson, C. Nelson, D. Nelson, J. Nelson, R.
Nelson, S. Nelson, T. Nelson, A. Nemirsky, M. Nergaard, N. Nernberg, G. Nesbitt, A. Nesenbaum, B. Nessman, K. Netter, K. Nettesheim, G. Netzel, C. Neufeld, M. Neufeld, O.
Neufeld, F. Neumaier, D. Neumann, D. Nevil, W. Nevills, D. Newbury, A. Newcommon, W. Newhouse, R. Newitt, A. Newman, J. Newman, K. Newman, L. Newman, P. Newman, R.
Newman, A. Newton, K. Newton, J. Ng, K. Ng, J. Ngabonziza, V. Nganzo, P. N’Gbesso, E. Ngo, H. Ngo, N. Ngo-Schneider, C. Nguyen, J. Nguyen, M. Nguyen, S. Nguyen, T. Nguyen,
H. Ni, D. Niamke, H. Niazi, J. Nicholl, D. Nichols, J. Nichols, T. Nichols, A. Nicholson, J. Nicholson, S. Nicholson, W. Nicholson, A. Nickel, D. Nickerson, K. Nickerson, H. Nicklefork, W.
Nicklefork, J. Nicolajsen, T. Nicolas, E. Nicolas-Quintin, J. Nicoll, S. Nidua, J. Nie, C. Nielsen, K. Nielsen, M. Nielsen, T. Nielsen, O. Nieto, M. Nieves, M. Nikic, W. Nikiforuk, C. Nikipelo,
R. Nimco, Y. Ning, T. Ninovska, M. Nippard, R. Nippard, S. Nippard, J. Nipshank, D. Nissen, J. Nistico, T. Nistor, O. Niven, R. Nixdorf, K. Nixon, P. Niziolek, N. Njoku, M. Nkathazo, A.
N’Kesse, C. Nobbs, G. Noble, M. Nobles, C. Noel, D. Noel, A. Noftall, J. Noga, B. Nolan, P. Nolan, R. Nolan, S. Nolan, B. Nolin, G. Nolin, R. Noot, W. Nordin, J. Norgaard, B. Norgard,
A. Nori, A. Noriel, V. Norkin, D. Norman, J. Norman, P. Norman, T. Norman, T. Normand, Y. Normand, C. Normandin, G. Normore, B. Norquay, L. Norrad, N. Northcott, R. Norton, A.
Noskey, K. Notenbomer, J. Novak, S. Novak, O. Novikova, D. Nowicki, A. Nur, K. Nurkowski, R. Nycholat, C. Nyman, K. Nzemba, N. Nzurum, W. Oakes, A. Obad, D. Ober, F. Obiri, P.
Oblozinsky, S. O’Bomsawin-Corriveau, E. Oborowsky, B. O’Brien, D. O’Brien, H. O’Brien, J. Obrigewitsch, J. Obuck, M. Ochran, J. O’Connell, M. O’Connell, A. O’Connor, G.
O’Connor, D. Oczkowski, J. Oddie, M. Odo, P. O’Donnell, T. Oele, H. Offet, I. Offor, E. Ofuya, L. O’Gallagher, J. Oganwu, O. Ogbodo, I. Ogbuke, A. Ogden, A. Ogilvie, D. Ogilvie, S.
O’Grady, D. Ogren, B. Ogurian, J. Oh, T. Oh, T. Oickle, R. Okada, A. Okanovic, C. O’Keefe, E. O’Keefe, J. Okemow, L. Okemow, S. Okonkwo, R. Oksanen, K. Okuszko, F. Oladebo, P.
Olaniyan, S. Olar, B. Olaski, L. Olaveson, C. Oldfield, S. O’Leary, B. Olenik, D. Olesen, B. Olheiser, D. Oliveira, D. Oliver, N. Oliver, A. Oliverio, C. Olivier, T. Ollenberg, D. Ollenberger,
S. Ollerhead, J. Ollikka, V. Olofernes, G. Oloumi, K. Olsen, M. Olsen, R. Olsen, C. Olson, D. Olson, J. Olson, M. Olson, P. Olson, S. Olson, W. Olson, K. Olszewski, O. Oluwole, E.
Omari-Osei, P. Onciul, D. O’Neil, M. Oness, D. Ong, K. Onuoha, P. Onyszko, C. Opper, C. Oragui, M. O’Reilly, N. O’Reilly, C. Orgu, C. Orkusz, J. O’Rourke, L. Orpilla Jr, A. Orr, N. Orr,
S. Orser, 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, L.
Osterhold, A. Ostrzenski, J. O’Sullivan, C. Oswald, D. Oswald, J. Otis, J. O’Toole, W. Otteson, J. Otto, D. Ouattara, L. Ouch, B. Ouellette, D. Ouellette, G. Ouellette, J. Ouellette, S.
Ouellette, Z. Overbye, M. Overwater, N. Owens, A. Owsianicki, A. Oxford, M. Oxford, P. Oza, P. Ozar, A. Paananen, L. Paananen, J. Paarsmarkt, M. Pachan, F. Pacheco, M. Pacheco,
D. Pacholok, S. Pacholok, T. Packard, J. Paddington, R. Padilla, B. Padlewski, T. Padron, M. Pady, F. Paetz, S. Page, G. Pagniello, M. Pagnucco, D. Pahljina, K. Paige, L. Painchaud, 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, B. Panchal, V. Pandey, D. Pandher, S.
Pandya, T. Pangman, J. Panko, L. Pantazi, F. Pantilag, S. Panuganty, A. Papadoulis, R. Papalia, 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, B. Parent, C. Parenteau, J. Parenteau, L. Parillo, R. Parillo, B. Parker, D. Parker, J. Parker, R. Parker,
D. Parlee, K. Parmar, C. Paron, M. Parsons, T. Parsons, W. Parsons, K. Pascoe, J. Pashko, M. Pasichnuk, W. Pasko, J. Pasos, N. Pasowisty, E. Pastor, K. 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, B. Patey, D. Patey, I. Patey, J. Patey, M. Patey, T.
Patey, J. Patience, P. Patil, C. Paton, G. Paton, E. Patricio, W. Patrick, C. Patrie, E. Patten, B. Patterson, C. Patterson, J. Patterson, K. Patterson, Z. Patterson, C. Pattinson, C. Paul, G.
Paul, J. Paul, K. Paul, T. Paul, M. Paulgaard, J. Paulsen, B. Paulson, D. Pavelick, M. Pavlic, K. Pavlick, M. Pavuluri, C. Pawlachuk, A. Pawlowich, E. Pawlowich, M. Pawluk, C. Pay, A.
Payne, B. Payne, C. Payne, D. Payne, G. Payne, J. Payne, M. Payne, P. Payne, S. Payson, P. Pazienza,
B. Peacock, L. Peacock, E. Pearson, T. Peats, J. Pecorari, G. Peddi, E. Peddle, D. Pedersen, J.
Pedersen, K. Pedersen, P. Pedersen, S. Pedersen, B. Pederson, L. Pederson, B. Peebles, J. Peeke,
M. Peeke, R. Peel, D. Peet, E. Pegg, C. Peifer, K. Pelayo, M. Pelkey, G. Pellegrino, D. Pelletier, M.
Pelletier, A. Pelley, K. Pelley, I. Pelly, M. Pelypiw, 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,
K. Pepper, D. Peramanu, S. Peramanu, M. Perehudoff, J. Perepelecta, F. Perez, L. Perez, D. Perkins,
R. Perkins, T. Perkins, J. Pernitsch, J. Peroramas, C. Perran, D. Perreault, M. Perrin, N. Perron, C.
Perry, D. Perry, G. Perry, J. Perry, R. Perry, S. Perry, V. Perry, S. Persaud, T. Persaud, D. Perumal, K.
Pescador, B. Pesowski, P. Peter, D. Peters, G. Peters, J. Peters, K. Peters, L. Peters, M. Peters, R.
Peters, A. Peterson, D. Peterson, E. Peterson, J. Peterson, K. Peterson, M. Peterson, S. Peterson, T.
Peterson, C. Petkau, D. Petkau, B. Petkus, M. Petrie, M. Petrik, L. Petrillo, R. Pettigrew, B. Pettipas,
S. Pettit, K. Peyman, J. Peyton, K. Pfannmuller, R. Pfriem, L. Pham, B. Phan, L. Phan, K. Phibbs, B.
Philibert, B. Phillips, D. Phillips, J. Phillips, L. Phillips, T. Phillips, B. Philpott, Z. Philpott-Belzil, G.
Phinney, M. Phippen, L. Phoenix, C. Phung, W. Picard, J. Picken, K. Pickering, A. Pickersgill, P.
Pickersgill, T. Pickett, A. Picray, 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, A. Pinerua Petit, S. Pinksen, T. Pinksen, K. Pinney, J. Pintaric, B. Pipa, R. Pira, D.
Pirvan, K. Pisio, M. Pitman, J. Pitoulis, M. Pitre, A. Pittman, C. Pittman, D. Pittman, I. Pittman, J.
Pittman, M. Pittman, S. Pittman, W. Pittman, M. Plamondon, R. Plamondon, E. Plante, D. Plepelic, I.
Plesa, J. Plessis, K. Plosz, G. Plouffe, T. Plouffe, J. Plowman, E. Plumb, J. Plummer, I. Pocaterra, J.
Pocock, S. Podhorodeski, D. Pohl, A. Poirier, D. Poirier, K. Poirier, J. Polacik, D. Pole, S. Police, E.
Poliquin, E. Polkowski, A. Pollard, C. Pollard, R. Pollard, T. Pollard, T. Pollett, A. Pollock, J. Pollock, M.
Pollock, C. Polloso, J. Polsfut, G. Pome Franco, L. Pomponio, M. Poncelet, D. Poncsak, B. Pond, D.
Pond, J. Pond, B. Ponjevic, N. Ponkiya, T. Poole, K. Poon, H. Poonjani, G. Pope, T. Pope, L. Popek, C.
Popko, J. Popoff, T. Popovic-Adamsen, J. Popowich, M. Popowich, T. 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, C. Potter, J. Potter, T. Potter, K. Potts, R. Potts, T. Potts, J. Poulin, L. Poulson, R.
Poulter, K. Pounall, C. Povse, C. Powell, D. Powell, J. Powell, L. Powell, P. Powell, R. Powell, B.
Power, C. Power, E. Power, J. Power, K. Power, L. Power, M. Power, S. Power, T. Power, T. Pozniak,
M. Prajapati, D. Prasad, G. Pratch, G. Prather, K. Pratt, R. Pratt, S. Pratt, W. Prawdzik, D. Prediger, M.
Preece, J. Prefontaine, D. Preshyon, D. Presley, A. Preston, J. Preston, R. Preteau, T. Pretty, A. Price,
W. Price, J. Priest, D. Pringle, T. Prins, A. Pritchard, R. Pritchett, S. Pritchett, G. Prochner, K. Proctor,
D. Procyshyn, M. Profiri, N. Proll, M. Pronk, J. Properzi, M. Prosper, D. Prostler, I. Proudfoot, D.
Proulx, G. Provencher, K. Prowse, T. Prudhomme, S. Prud’Homme, C. Przybylski, S. Pshyk, A. Pugh,
J. Puhl, T. Pullen, C. Pumphrey, M. Pumphrey, A. Punko, S. Pupneja, B. Purcell, S. Purchase, C. Purdy,
J. Purdy, T. Purves, D. Pushak, S. Pushak, M. Pye, J. Pyke, R. Pyke, W. Pyne, F. Pynn, J. Pyper, A.
Pyra, M. Qazi, M. Qian, W. Qian, L. Qing, J. Qu, C. Quach, A. Quan, G. Quan, A. Quarin, R.
Quartermain, K. Quayle-Thomson, J. Quehe, J. Quiba, D. Quigley, S. Quigley, C. Quinlan, M. Quintin,
T6
Canadian Natural 2022 Annual Report G. Quinton, B. Quipp, S. Qureshi, J. Raban Mardelli, J. Rabby, B. Rabusic, C. Rabusic, M. Raby,
D. Rach, D. Raciborski, W. Raczynski, L. Radesh, K. Radke, R. Radke, M. Radu, J. Rae, R. Rae,
C. Raed, K. Rafferty, W. Rafiq, I. Rafiyev, G. Raghavan Nair, S. Raghuwanshi, J. Raher, A.
Rahmani, M. Rahmani, P. Rai, S. Rainey, J. Rainnie, M. Raistrick, A. Raivio, K. Raj, M. Raj, S.
Rajan, M. Rajic, J. Rajotte, T. Rakowski, J. Ralph, P. Ralph, S. Raman, J. Ramazani, J. Rambold, J.
Ramirez, M. Ramirez, P. Ramirez Perez, C. Ramos, J. Ramsay, M. Ramsay, S. Ramsay, K.
Ramsbottom, M. Rana, V. Rana, L. Rancourt, K. Randell, L. Randell, W. Randell, J. Rankin, M.
Rankin, D. Ranola, J. Ransom, M. Raoufi, R. Raposo, S. Rasch, T. Rasheed, C. Rasko, C. Raskob,
K. Raskob-Smith, S. Rasmussen, R. Raso, H. Rassi, W. Ratcliffe, D. Rath, A. Rathbone, R.
Rathburn, N. Rathod, S. Ratkovic, M. Rattray, H. Ratzlaff, A. Rau, M. Rausch, P. Ravindran, 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, K. Read,
W. Reashore, R. Reaume, C. Reber, D. Reber, G. Reber, D. Rechenmacher, N. Rector, B. Redlich,
S. Redman, J. Redmann, G. Reed, J. Reed, S. Reed, P. Regan, R. Reginato, C. Regnier, R.
Regnier, P. Regular, H. Rehman, M. Rehman, B. Reid, C. Reid, D. Reid, E. Reid, J. Reid, K. Reid,
M. Reid, R. Reid, T. Reid, B. Reiling, H. Reilly, D. Reimer, I. Reimer, J. Reimer, M. Reinders, T.
Reinders, J. Reiniger, E. Reis, R. Reis, G. Reiter, H. Reithaug, D. Rejman, D. Relkow, P. Rellosa,
W. Remmer, C. Rempel, L. Rempel, P. Rempel, T. Rempel, L. Ren, S. Ren, R. Renaud, T.
Renneberg, A. Rennie, C. Rennie, J. Rennie, L. Rennie, M. Reno, J. Rentar, C. Revereza, M.
Rew, E. Reyes, O. Reyes, J. Reynolds, T. Reynolds, S. Reza, A. Rezai, N. Rhemtulla, C. Rhode, I.
Riach, G. Ricard, S. Ricci, D. Rice, G. Rice, J. Rice, R. Rice, J. Richard, K. Richard, M. Richard, O.
Richard, A. Richards, B. Richards, C. Richards, D. Richards, T. Richards, A. Richards-Dunning, A.
Richardson, K. Richardson, T. Richardson, W. Richardson, B. Riche, P. Richer, W. Ricker, C.
Ricketson, A. Ricketts, M. Ricketts, W. Ricketts, J. Rideout, M. Rideout, R. Rideout, T. Rider, C.
Riegling, C. Ries, M. Rigg, D. Riley, J. Riley, S. Riley, D. Rinas, G. Ringheim, R. Rioux, S. Rioux,
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T7
Canadian Natural 2022 Annual Report Smith, J. Smith, K. Smith, M. Smith, N. Smith, R. Smith, S. Smith, T. Smith, C. Smitham, E. Smolyaninova, A. Smyl, B.
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K. Van Buskirk, A. Van De Reep, C. Van de Reep, M. van den Oever, W. Van den Oever, M. van der Burgh, N. Van Der Merwe, A. Van Donkervoort, H. Van Dyck, B. van Dyke, N. Van
Dyke, J. Van Es, E. van Gellekom, L. Van Genne, L. van Heerden, C. Van Konkelenberg, J. Van Nes, C. van Niekerk, F. Van Overloop, S. Van Rensburg, D. Van Rootselaar, C. Van Schoor,
R. Van Steinburg, C. Van Wyngaarden, B. Vanbeselaere, D. Vanbocquestal, J. Vancoughnett, K. Vandaelle, J. Vandeligt, R. Vandemark, T. Vandemark, G. Vander Veen, N. Vandergriend,
T. Vandermeer, V. Vandersluis, S. Vandervlis, J. Vandervoort, P. Van-Dunem, N. Vangala, E. Vanopian, G. van’t Wout, C. Vare, N. Varey, S. Varey, M. Varga, C. Vargas Suarez, S. Varma,
D. Varty, N. Vaschetto, A. Vashisht, A. Vasquez, C. Vasquez, M. Vasquez-Placid, G. Vassberg, J. Vasseur, R. Vassov, A. Vaters, R. Vaudan, A. Vaughan, N. Vaughan, D. Vazquez Guillen,
O. Vedmedenko, F. Veenbaas, B. Veitch, S. Vekved, T. Vekved, B. Velagapudi, B. Velichka, T. Velichka, M. Velmurugan, R. Veloso, T. Velting, M. Venczel, R. Veneracion, S. Venkatesh, G.
Venkateshvaralu, R. Venn, D. Venning, J. Vera, L. Verbaas, D. Verbeek, D. Verbicky, M. Verburg, A. Verge, M. Verge, B. Verhoeven, S. Veroba, J. Verot, B. Verreau, D. Versnick-Brown,
K. Veysey, J. Vezina, C. Viana, G. Vibert, J. Vicic, N. Vick, T. Viens, K. Vierneza, A. Vijayan, G. Viljoen, J. Villalba Bello, R. Villanueva, B. Villecourt, J. Villemaire, M. Villemaire, C.
Villemere, K. Vincent, R. Vincent, S. Vineham, B. Viney, R. Vinkle, A. Virk, K. Virus, A. Visotto, K. Viswabharathi, R. Vivian, R. Vloet, D. Vo, S. Voight, B. Volkmann, W. Volschenk, L.
Vondermuhll, B. Von-Grat, A. Vosburgh, A. Votta, A. Vredegoor, J. Vrolson, N. Vu, L. Vuong, Q. Vuong, G. Wack, E. Waddell, T. Waddell, K. Waddy, J. Wade, T. Wade, W. Wade, T. Wagil,
D. Wagner, G. Wagner, J. Wagner, K. Wagner, N. Wagner, 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, M. Walker, R. Walker, S. Walker, T. Walker, K. Walko, D. Wall, M. Wall, S. Wall, T. Wall, A. Wallace, C. Wallace, D. Wallace, E.
Wallace, H. Wallace, J. Wallace, K. Wallace, T. Wallace, V. Wallace, K. Wallin, M. Wallis, V. Wallwork, T. Walraven, A. Walsh, B. Walsh, D. Walsh, E. Walsh, M. Walsh, P. Walsh, R. Walsh,
T. Walsh, W. Walsh, L. Walter, A. Walters, C. Walters, D. Walters, I. Walton, N. Wan, S. Wanderingspirit, C. Wang, H. Wang, J. Wang, L. Wang, Q. Wang, R. Wang, S. Wang, T. Wang,
W. Wang, X. Wang, Y. Wang, Z. Wang, L. Wangkhang, D. Wannas, S. Waquan, T. Warburton, E. Ward, I. Ward, K. Ward, B. Warehime, D. Warford, W. Warholik, C. Wark, W. Warman,
F. Warraich, G. Warren, K. Warren, R. Warren, S. Warren, D. Warrington, B. Wartman, K. Warwaruk, J. Washburn, M. Washington, A. Wasikowski, P. Wassell, W. Wasylucha, A.
Watchorn, D. Waterfield, C. Waters, D. Watson, G. Watson, J. Watson, K. Watson, S. Watson, D. Watt, G. Watt, B. Watton, B. Watts, L. Waughtal, T. Wawro, B. Weatherby, D.
Weatherby, C. Weatherhead, A. Webb, D. Webb, G. Webb, P. Webb, B. Webber, J. Webber, V. Webber, W. Weber, O. Websdale, A. Webster, K. Webster, D. Weed, M. Weeks, E.
Weening, E. Weenink, B. Wegenast, A. Wei, B. Wei, Z. Wei, J. Weibrecht, J. Weigl, J. Weik, D. Weimer, C. Weingarten, R. Weir, S. Weir-Murphy, G. Weisbeck, A. Weisbrod, R.
Weisbrot, M. Weishaar, K. Weldon, J. Weller, P. Weller, M. Wellman, E. Wells, J. Wells, L. Wells, N. Wells, R. Wells, A. Welsh, W. Welte, W. Welygan, Z. Wen, G. Weng, P. Wenger, J.
Wenisch, G. Wennberg, P. Wennerstrom, A. Wentworth, K. Wenzel, C. Werner, M. Werner-Fisher, N. Wert, R. Weseen, B. Weslake, E. Wessel, D. West, J. West, R. West, M. Westad,
D. Westbrook, K. Westland, T. Whalen, R. Whalley, D. Wheating, J. Wheaton, S. Wheaton, B. Wheeler, C. Wheeler, K. Wheeler, L. Wheeler, N. Wheeler, K. Whelan, R. Whelan, R.
Whelan-Maloney, K. Whetham, A. White, B. White, C. White, H. White, J. White, M. White, P. White, R. White, S. White, T. White, Z. White, J. Whitehead, T. Whitehead, 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, A. Wickins,
R. Widdifield, G. Wideman, M. Widing, A. Wiebe, D. Wiebe, N. Wiebe, T. Wiebe, D. Wiege, B. Wiens, B. Wiesener, C. Wietzel, S. Wight, T. Wight, D. Wijesingha, C. Wilbee, D. Wilbee,
A. Wilcox, D. Wilcox, J. Wilcox, M. Wilcox, D. Wild, R. Wild, D. Wilde, E. Wildeman, R. Wiles, C. Wilk, T. Wilk, A. Wilkes, C. Wilkes, N. Wilkes, C. Wilkin, L. Wilkin, E. Wilkinson, J.
Wilkinson, K. Wilkinson, P. Will, D. Willard, E. Willard, B. Willburn, A. Willcott, B. Willcott, R. Willey, A. Williams, B. Williams, C. Williams, D. Williams, G. Williams, J. Williams, K.
Williams, L. Williams, M. Williams, N. Williams, R. Williams, T. Williams, W. Williams, C. Williamson, J. Williamson, M. Williamson, M. Willis, 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, R. 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, A. Winterburn, C. Winterhalt, G.
Winters, R. Winters, G. Wirachowsky, J. Wirachowsky, H. Wiseman, 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, D. Wold, S. Wolf, C. Wolfe, J. Wolfe, M. Wolfenden, D. Wollum, C. Woloshyn, J. Wolstenholme, J. Wolter,
R. Wolters, A. Wong, C. Wong, G. Wong, J. Wong, L. Wong, N. Wong, S. Wong, C. Woo, J. Woo, L. Woo, A. Wood, G. Wood, J. Wood, K. Wood, P. Wood, S. Wood, T. Woodburn, R.
Woodburne, J. Woodd, M. Woodfin, S. Woodfine, N. Woodford, S. Woodford, A. Woodger, C. Woodhead, M. Woodhead, D. Woods, H. Woods, J. Woods, T. Woods, M. Woodske, J.
Wooldridge, B. Wooley, S. Woolfitt, T. Woolley, R. Woolner, R. Wootton, M. Woroniuk, B. Worthington, C. Worthman, L. Wotherspoon, J. Wotten, C. Wright, L. Wright, R. Wright, G.
Wrinn, B. Wu, C. Wu, D. Wu, H. Wu, J. Wu, M. Wu, R. Wu, P. Wuorinen, B. Wurzer, A. Wutzke, K. Wutzke, G. Wyman, G. Wyndham, J. Wynne, D. Wyshynski, L. Wysocki, S.
Wytrychowski, B. Xavier, Z. Xavier, Y. Xiao, H. Xie, Y. Xie, H. Xu, J. Xu, Q. Xu, T. Xu, Z. Xu, D. Yackel, A. Yaghoubi, N. Yagolnyk, K. Yakemchuk, K. Yakimowich, J. Yakiwchuk, L. Yakiwchuk,
A. Yang, D. Yang, L. Yang, D. Yanke, G. Yanota, K. Yao, W. Yao, H. Yare, A. Yaremko, E. Yarmuch, R. Yarmuch, J. Yaroslawsky, S. Yasin, S. Yasinski, D. Yates, M. Yaychuk, P. Yazdani, B. Ye,
P. Yeboah, B. Yeboue, G. Yee, K. Yee, R. Yee, C. Yen, C. Yeoman, D. Yep, P. Yepes, J. Yeske, A. Yevtushenko, B. Ying, C. Ying, O. Ying, Y. Ying, J. Yip, K. Yip, F. Yohannes, J. Yong, R. Yong,
S. Yoon, F. York, P. York, A. Yoshikawa, X. You, M. Youell, B. Young, C. Young, D. Young, G. Young, J. Young, L. Young, M. Young, P. Young, S. Young, T. Young, N. Younis, R. Yowney, E. Yu,
G. Yu, J. Yu, N. Yu, Q. Yu, B. Yue, C. Yuen, D. Yuill, J. Yuill, A. Yule, R. Yuristy, R. Zabek, A. Zabloski, T. Zabo , A. Zacaruk, A. Zacharias, T. Zachoda, C. Zackowski, J. Zaderey, B. Zagoruy,
S. Zagozewski, E. Zahacy, V. Zaharia, S. Zahary, A. Zahorszky, A. Zaidi, B. Zaitsoff, K. Zajarny, S. Zakeri, N. Zaman, D. Zambrano Suarez, I. Zami, R. Zamudio Baca, B. Zandstra, N.
Zanet, D. Zanoni, C. Zaparyniuk, M. Zarbock, M. Zarichney, D. Zarowny, G. Zarowny, K. Zarowny, M. Zarowny, Z. Zarowny, S. Zawada, K. Zayac, D. Zazula, R. Zazula, S. Zbrodoff, A.
Zecevic, 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, J. Zhan, B. Zhang, J.
Zhang, M. Zhang, Q. Zhang, W. Zhang, X. Zhang, Y. Zhang, Z. Zhang, B. Zhao, L. Zhao, G. Zheng, W. Zheng, H. Zhou, Q. Zhou, Y. Zhou, J. Zhu, L. Zhu, W. Zhu, E. Zhuromsky, K.
Zielinski, A. Zielke, E. Zimmer, C. Zimmerman, T. Zimmerman, M. Zisi, S. Zitaruk, R. Zoerb, W. Zohoori, J. Zuk, S. Zukanovic, N. Zukiwski, S. Zukowski, S. Zwyer.
T8
Canadian Natural 2022 Annual Report 2022 Year End Reserves
DETERMINATION OF RESERVES
For the year ended December 31, 2022, 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 rate 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 13.587 billion BOE, with reserves additions and revisions of 1.242 billion BOE. Total
proved plus probable reserves increased 6% to 18.046 billion BOE, with reserves additions and revisions of
1.563 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 32 years and a total
proved plus probable BOE reserves life index of approximately 42 years.
– High value, zero decline SCO represents approximately 51% of total proved reserves with a reserve life index of
approximately 44 years.
Proved developed producing reserves additions and revisions are 491 million BOE, replacing 2022 production by 105%. The
proved developed producing BOE reserves life index is approximately 21 years.
Total proved reserves additions and revisions replaced 2022 production by 265%. Total proved plus probable reserves
additions and revisions replaced 2022 production by 334%. This includes negative technical revisions as a result of
accelerating the cessation of production from two platforms in the North Sea.
In 2022, Canadian Natural continued to achieve strong finding and development costs:
◦
◦
FD&A (1) costs, excluding changes in Future Development Cost ("FDC"), are $4.11/BOE for total proved reserves and
$3.26/BOE for total proved plus probable reserves.
FD&A costs, including changes in FDC, are $8.39/BOE for total proved reserves and $7.62/BOE for total proved plus
probable reserves.
The net present value of future net revenues, before income tax, discounted at 10%, is approximately $102.3 billion for
proved developed producing reserves, approximately $150.9 billion for total proved reserves, and approximately
$183.7 billion for total proved plus probable reserves.
(1)
Supplementary financial measure. Refer to the notes of the "2022 Year End Reserves" on page 8.
Canadian Natural 2022 Annual Report
6
Summary of Company Gross Reserves
as of December 31, 2022
Forecast Prices and Costs
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
Total Company
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved plus Probable
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(Bcf)
(MMbbl)
(MMBOE)
122
16
93
231
89
320
96
11
73
179
93
272
207
—
55
262
114
376
540
140
2,604
3,284
1,901
5,186
6,836
4,989
143
8,775
—
37
306
8,332
6,873
13,627
535
8,643
7,408
22,270
6
337
486
285
772
225
4,587
13,587
4,458
18,046
Reconciliation of Company Gross Reserves
as of December 31, 2022
Forecast Prices and Costs
TOTAL PROVED
Total Company
December 31, 2021
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2022
Light and
Medium
Crude Oil
Primary
Heavy
Crude Oil
Pelican Lake
Heavy
Crude Oil
Bitumen
(Thermal
Oil)
Synthetic
Crude Oil
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
169
270
2,631
6,998
300
—
3
7
—
—
—
10
(61)
(28)
231
—
14
5
—
—
—
6
11
(25)
179
—
—
—
—
—
—
4
6
(18)
262
—
262
—
2
431
—
—
50
(92)
—
—
—
37
—
—
—
(6)
(155)
TOTAL PROVED PLUS
PROBABLE
Light and
Medium
Crude Oil
Primary
Heavy
Crude Oil
Pelican Lake
Heavy
Crude Oil
Bitumen
(Thermal
Oil)
Synthetic
Crude Oil
Total Company
December 31, 2021
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
424
249
388
4,337
7,535
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2022
—
4
10
—
—
—
10
(100)
(28)
320
—
26
8
—
—
—
7
8
(25)
272
—
—
—
1
—
—
3
2
(18)
376
—
337
—
2
551
—
—
50
(92)
—
—
—
50
—
—
—
(20)
(155)
Natural
Gas
(Bcf)
12,168
—
290
218
—
249
—
446
1,019
(763)
Natural
Gas
Liquids
Barrels
of Oil
Equivalent
(MMbbl)
418
(MMBOE)
12,813
—
13
19
—
25
—
9
23
(22)
—
339
68
40
498
—
103
194
(468)
Natural
Gas
(Bcf)
20,249
Natural
Gas
Liquids
Barrels
of Oil
Equivalent
(MMbbl)
643
(MMBOE)
16,950
—
829
344
—
588
—
528
495
—
35
26
—
72
—
11
8
—
539
100
52
722
—
120
29
(763)
(22)
(468)
3,284
6,873
13,627
486
13,587
5,186
7,408
22,270
772
18,046
7
Canadian Natural 2022 Annual Report
NOTES TO RESERVES:
1. Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.
2.
Information in the reserves data tables may not add due to rounding. BOE values and oil and gas metrics may not calculate
exactly due to rounding.
3. Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserves estimates are the
3-consultant-average of price forecasts developed by Sproule Associates Limited, GLJ Ltd. and McDaniel & Associates
Consultants Ltd., dated December 31, 2022:
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
2023
2024
2025
2026
2027
80.33
76.54
103.76
104.55
78.50
77.75
97.74
98.50
76.95
77.55
95.27
95.55
77.61
80.07
95.58
96.83
79.16
81.89
97.07
98.13
106.22
101.35
98.94
100.19
101.74
84.67
82.69
81.03
81.39
82.65
4.23
4.08
4.74
4.40
4.28
4.50
4.21
4.11
4.31
4.27
4.16
4.40
4.34
4.23
4.49
All prices increase at a rate of 2% per year after 2027.
A foreign exchange rate of 0.7450 US$/C$ for 2023, 0.7650 US$/C$ for 2024, 0.7683 US$/C$ for 2025, 0.7717 US$/C$ for
2026 and 0.7750 US$/C$ after 2026 was used in the year end 2022 evaluation.
4. A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil
(6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an
energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at
the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl
conversion ratio may be misleading as an indication of value.
5. Oil and gas metrics included herein are commonly used in the crude oil and natural gas industry and are determined by
Canadian Natural as set out in the notes below. These metrics do not have standardized meanings and may not be
comparable to similar measures presented by other companies and may be misleading when making comparisons.
Management uses these metrics to evaluate Canadian Natural’s performance over time. However, such measures are not
reliable indicators of Canadian Natural’s future performance and future performance may vary.
6. Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of
production.
7. Reserves replacement or Production replacement ratio is the Company Gross reserves additions and revisions, for the
relevant reserves category, divided by the Company Gross production in the same period.
8. Reserves Life Index ("RLI") is based on the amount for the relevant reserves category divided by the 2023 proved developed
producing production forecast prepared by the Independent Qualified Reserves Evaluators.
9. Finding, Development and Acquisition ("FD&A") costs excluding changes in Future Development Costs ("FDC") are
calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2022 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 2022 and net changes in FDC from December 31, 2021 to December 31, 2022 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, 2022 and forecast estimates of ADR costs attributable to future development
activity.
Canadian Natural 2022 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
34
37
38
39
40
44
46
47
53
53
9
Canadian Natural 2022 Annual Report
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
Definitions and Abbreviations
Alberta natural gas reference location
Annual Information Form
Athabasca Oil Sands Project
specific gravity measured in degrees on the
American Petroleum Institute scale
asset retirement obligations
IFRS
LIBOR
Mbbl
Mbbl/d
MBOE
International Financial Reporting Standards
London Interbank Offered Rate
thousand barrels
thousand barrels per day
thousand barrels of oil equivalent
MBOE/d
thousand barrels of oil equivalent per day
barrel
barrels per day
billion cubic feet
billion cubic feet per day
a naturally occurring solid or semi-solid
hydrocarbon consisting mainly of heavier
hydrocarbons that are too heavy or thick to
flow at reservoir conditions, and recoverable
at economic rates using thermal
in situ
recovery methods
barrels of oil equivalent
barrels of oil equivalent per day
Dated Brent
Canadian dollars
compound annual growth rate
capital expenditures
carbon dioxide
carbon dioxide equivalents
includes light and medium crude oil, primary
heavy crude oil, Pelican Lake heavy crude oil,
bitumen (thermal oil), and synthetic crude oil
Cyclic Steam Stimulation
Enhanced Oil Recovery
Exploration and Production
Financial Accounting Standards Board
Floating Production, Storage and Offloading
Vessel
greenhouse gas
gigajoules
gigajoules per day
Mcf
Mcfe
Mcf/d
MMbbl
MMBOE
MMBtu
MMcf
thousand cubic feet
thousand cubic feet equivalent
thousand cubic feet per day
million barrels
million barrels of oil equivalent
million British thermal units
million cubic feet
MMcf/d
million cubic feet per day
NGLs
NWRP
natural gas liquids
North West Redwater Partnership
NYMEX
New York Mercantile Exchange
NYSE
OPEC+
PRT
SAGD
SCO
SEC
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
United States dollars
Western Canadian Select
WCS Heavy
Differential
WTI
WCS Heavy Differential from WTI
West Texas
Intermediate
location at Cushing, Oklahoma
reference
Horizon
Horizon Oil Sands
IASB
IBOR
International Accounting Standards Board
Interbank Offered Rate
Canadian Natural 2022 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 impact of the Pathways Alliance ("Pathways")
initiative and activities, 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, the actions of OPEC+ and inflation) 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, 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 the 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 government mandated production curtailments); government regulations and the
expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate
change initiatives on capital expenditures and production expenses); asset retirement obligations; the sufficiency of the
Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long-term; the
strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's
provision for taxes; and other circumstances affecting revenues and expenses.
11
Canadian Natural 2022 Annual Report
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,
2022. It should also be read in conjunction with the Company's MD&A for the three months and year ended December 31,
2022. 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 for information purposes only.
The following discussion and analysis refers primarily to the Company's 2022 financial results compared to 2021 and 2020,
unless otherwise indicated. In addition, this MD&A details the Company's targeted capital program for 2023. The accompanying
tables form an integral part of this MD&A. Additional information relating to the Company, including its quarterly MD&A for the
three months and year ended December 31, 2022, its Annual Information Form for the year ended December 31, 2022, and its
audited consolidated financial statements for the year ended December 31, 2022, 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 1, 2023.
Canadian Natural 2022 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 endeavors 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 2022 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)
2022
49,530 $
43,009 $
5,236 $
10,937 $
9.64 $
9.52 $
2021
32,854 $
29,256 $
2,716 $
7,664 $
6.49 $
6.46 $
12,863 $
7,420 $
11.33 $
11.19 $
19,391 $
19,791 $
17.44 $
17.22 $
4.60 $
76,142 $
29,316 $
4,987 $
5,471 $
90.64 $
6.55 $
117.69 $
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
1,281,434
1,234,906
1,164,136
933,149
2,090
952,404
1,695
917,958
1,477
(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 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share, from $0.75 per common share.
On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share. On March 2, 2022, the Board of Directors approved a
28% increase in the quarterly dividend to $0.75 per common share, from $0.5875 per common share. 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.
(5) Calculated as natural gas sales divided by sales volumes.
(6) Natural gas production volumes approximate sales volumes.
Canadian Natural 2022 Annual Report
14
CONSOLIDATED NET EARNINGS (LOSS) AND ADJUSTED NET EARNINGS (LOSS)
For 2022, the Company reported net earnings of $10,937 million compared with $7,664 million for 2021 (2020 – net loss of
$435 million). Net earnings for 2022 included non-operating items, net of tax, of $1,926 million compared with $244 million for
2021 (2020 – $321 million) related to the effects of share-based compensation, risk management activities, fluctuations in
foreign exchange rates, the impact of realized foreign exchange on the settlement of the cross currency swap and repayment
of US dollar debt securities, the gain on acquisitions, the (gain) loss from investments, a recoverability charge relating to the de-
booking of reserves at the Ninian field in the North Sea, and government grant income under the provincial well-site
rehabilitation programs. Excluding these items, adjusted net earnings from operations for 2022 were $12,863 million compared
with $7,420 million for 2021 (2020 – adjusted net loss from operations of $756 million).
The increase in net earnings and adjusted net earnings from operations for 2022 compared with 2021 primarily reflected:
▪
▪
▪
higher crude oil and NGLs netbacks (1) and crude oil sales volumes in the North America segment;
higher natural gas netbacks and natural gas sales volumes in the Exploration and Production segments; and
higher realized SCO sales price (1) in the Oil Sands Mining and Upgrading segment;
partially offset by:
▪
lower SCO sales volumes in the Oil Sands Mining and Upgrading segment.
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 for
2022 from 2021. These items are discussed in detail in the relevant sections of this MD&A.
Prevailing regulatory and economic conditions in 2022 and the increasingly challenging commercial outlook in the United
Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea
operations. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer
economic, de-booked associated crude oil reserves as at December 31, 2022, and is accelerating abandonment. As a result, the
Company completed a recoverability assessment of its assets in the North Sea, and recognized a non-cash charge of $651
million (after-tax) related to the Ninian field property, plant and equipment, comprised of a recoverability charge of $1,620 million
recognized in depletion, depreciation and amortization, net of deferred tax recoveries of $969 million.
CASH FLOWS FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW
Cash flows from operating activities for 2022 were $19,391 million compared with $14,478 million for 2021 (2020 – $4,714
million). The fluctuations in cash flows from operating activities for 2022 from 2021 were primarily due to the factors previously
noted related to the fluctuations in adjusted net earnings (loss) from operations, together with the impact of net changes in non-
cash working capital.
Adjusted funds flow for 2022 was $19,791 million ($17.44 per common share) compared with $13,733 million ($11.63 per
common share) for 2021 (2020 – $5,200 million; $4.40 per common share). The fluctuations in adjusted funds flow for 2022
from 2021 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, 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.
PRODUCTION VOLUMES
Crude oil and NGLs production before royalties for 2022 of 933,149 bbl/d was comparable with 952,404 bbl/d in 2021 (2020 –
917,958 bbl/d). Natural gas production before royalties for 2022 increased 23% to average 2,090 MMcf/d from 1,695 MMcf/d in
2021 (2020 – 1,477 MMcf/d). Total production before royalties for 2022 of 1,281,434 BOE/d increased 4% from 1,234,906
BOE/d in 2021 (2020 – 1,164,136 BOE/d). Crude oil and NGLs and natural gas production volumes are discussed in detail in the
"Daily Production" section of this MD&A.
PRODUCT PRICES
In the Company’s Exploration and Production segments, the 2022 realized crude oil and NGLs prices (1) increased 42% to
average $90.64 per bbl from $63.71 per bbl in 2021 (2020 – $31.90 per bbl), and the 2022 realized natural gas price increased
61% to average $6.55 per Mcf from $4.07 per Mcf in 2021 (2020 – $2.40 per Mcf). In the Oil Sands Mining and Upgrading
segment, the Company’s 2022 realized SCO sales price increased 51% to average $117.69 per bbl from $77.95 per bbl in 2021
(2020 – $43.98 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.
(1) Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
15
Canadian Natural 2022 Annual Report
PRODUCTION EXPENSE
In the Company’s Exploration and Production segments, the 2022 crude oil and NGLs production expense (1) increased 24% to
average $18.17 per bbl from $14.71 per bbl in 2021 (2020 – $12.42 per bbl), and natural gas production expense (1) averaged
$1.22 per Mcf in 2022, an increase of 3% from $1.18 per Mcf in 2021 (2020 – $1.18 per Mcf). In the Oil Sands Mining and
Upgrading segment, the Company's 2022 production expense (1) averaged $26.04 per bbl, an increase of 25% from $20.91 per
bbl in 2021 (2020 – $20.46 per bbl). Crude oil and NGLs and natural gas production expense is discussed in detail in the
"Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.
SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company’s quarterly financial results for the eight most recently completed quarters:
($ millions, except per common share amounts)
2022
Product sales (1)
$
Crude oil and NGLs
Natural gas
Net earnings
Net earnings per common share
– basic
– diluted
$
$
$
$
$
($ millions, except per common share amounts)
2021
Product sales (1)
$
Crude oil and NGLs
Natural gas
Net earnings
Net earnings per common share
– basic
– diluted
$
$
$
$
$
Total
49,530 $
43,009 $
5,236 $
10,937 $
Dec 31
11,012 $
9,508 $
1,287 $
1,520 $
Sep 30
12,574 $
11,001 $
1,342 $
2,814 $
Jun 30
13,812 $
11,727 $
1,605 $
3,502 $
Mar 31
12,132
10,773
1,002
3,101
9.64 $
9.52 $
1.37 $
1.36 $
2.52 $
2.49 $
3.04 $
3.00 $
2.66
2.63
Sep 30
Jun 30
Mar 31
Total
32,854 $
29,256 $
2,716 $
7,664 $
Dec 31
10,190 $
8,979 $
958 $
2,534 $
8,521 $
7,607 $
694 $
2,202 $
7,124 $
6,382 $
509 $
1,551 $
6.49 $
6.46 $
2.16 $
2.14 $
1.87 $
1.86 $
1.31 $
1.30 $
7,019
6,288
555
1,377
1.16
1.16
(1) Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements.
(1) Calculated as respective production expense divided by respective sales volumes.
Canadian Natural 2022 Annual Report
16
Volatility in the quarterly net earnings 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 and the impact of the Russian invasion of Ukraine, 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;
and the impact of the differential between WTI and Brent benchmark pricing in the International segments.
Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, third-
party pipeline maintenance and outages, the impact of geopolitical and market uncertainties, the impact of seasonal
conditions, 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, natural decline rates, the impact of turnarounds and pitstops in
the Oil Sands Mining and Upgrading segment, 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 drilling program in North America and the
International segments, natural decline rates, the temporary shutdown and subsequent reinstatement of the Pine River Gas
Plant during 2021, and the impact and timing of acquisitions.
Production expense – Fluctuations primarily due to the impacts of the demand and cost for services, fluctuations in
product mix and production volumes, seasonal conditions, increased carbon tax and energy costs, inflationary cost
pressures, cost optimizations across all segments, the impact and timing of acquisitions, turnarounds and pitstops in the Oil
Sands Mining and Upgrading segment, and maintenance activities in the International segments.
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, the impact of
turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and a recoverability charge relating to the de-
booking of reserves at the Ninian field in the North Sea.
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 and accrued interest on the deferred PRT recovery.
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 any cross currency swap hedges outstanding.
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. and Inter Pipeline Ltd. shares, and the
distribution from NWRP in 2021.
17
Canadian Natural 2022 Annual Report
Business Environment
Global benchmark crude oil prices increased significantly in the first half of 2022, primarily in response to the impact of the
Russian invasion of Ukraine and the OPEC+ decision to adhere to previously agreed upon production cut agreements, together
with the improvement of global economic conditions and outlook due to the lessening of COVID-19 restrictions. In the second
half of 2022, global benchmark crude oil prices decreased from levels in the first half of 2022 due to demand concerns related
to the temporary reinstatement of COVID-19 restrictions in China, the impact of rising interest rates and concerns of a global
recession.
Liquidity
As at December 31, 2022, the Company had undrawn revolving bank credit facilities of $5,520 million. Including cash and cash
equivalents and short-term investments, the Company had approximately $6,931 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 November 30, 2022, the Company
announced its 2023 base capital budget (2) targeted at approximately $4,190 million. The budget also includes incremental
strategic growth capital of approximately $1,020 million that targets to add additional production and capacity growth beyond
2023 in the Company's E&P segment, and long life low decline thermal in situ and Oil Sands Mining and Upgrading assets.
Production for 2023 is targeted between 1,330,000 BOE/d and 1,374,000 BOE/d. Annual budgets are developed and scrutinized
throughout the year and can be changed, if necessary, in the context of price volatility, project returns and the balancing of
project risks and time horizons. The 2023 capital budget constitutes forward-looking statements. Refer to the "Advisory" section
of this MD&A for further details on forward-looking statements.
Risks and Uncertainties
COVID-19, including variants of concern, continues to have the potential to further disrupt the Company’s operations, projects,
and financial condition, through the disruption of the local or global supply chain and transportation services, or the loss of
manpower, any of which may require the Company to temporarily reduce or shut down its operations depending on their extent
and severity. The global economy, including Canada, is experiencing higher and more persistent inflation, in part due to the
Russian invasion of Ukraine and ongoing supply constraints due to the impacts of COVID-19. As a result of these conditions, the
Company has experienced and may continue to experience higher than normal fluctuations in commodity prices, and may
experience inflationary pressures on operating and capital expenditures.
BENCHMARK COMMODITY PRICES
(Yearly average)
WTI benchmark price (US$/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$)
2022
94.23 $
99.80 $
18.26 $
98.66 $
93.69 $
0.54 $
6.64 $
5.28 $
2021
67.96 $
70.49 $
13.04 $
66.36 $
68.24 $
(0.28) $
3.85 $
3.38 $
2020
39.40
42.27
12.57
36.26
36.97
2.43
2.08
2.12
0.7686 $
0.7389 $
0.7979 $
0.7901 $
0.7454
0.7840
$
$
$
$
$
$
$
$
$
$
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.
(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 2022 Annual Report
18
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$94.23
per bbl for 2022, an increase of 39% from US$67.96 per bbl for 2021 (2020 – US$39.40 per bbl).
Crude oil sales contracts for the Company’s International segments are typically based on Brent pricing, which is representative
of international markets and overall global supply and demand. Brent averaged US$99.80 per bbl for 2022, an increase of 42%
from US$70.49 per bbl for 2021 (2020 – US$42.27 per bbl).
The increase in WTI and Brent pricing for 2022 from 2021 primarily reflected the impact of the Russian invasion of Ukraine, the
OPEC+ decision to adhere to the previously agreed upon production cut agreements, and an increase in global demand for
crude oil due to improved economic conditions as a result of the lessening of earlier COVID-19 restrictions.
The WCS Heavy Differential averaged US$18.26 per bbl for 2022, compared with US$13.04 per bbl for 2021 (2020 – US$12.57
per bbl). The widening of the WCS Heavy Differential for 2022 from 2021 primarily reflected weakening US Gulf Coast pricing
due to increased sour supply from the US Strategic Petroleum Reserve and lower Russian pricing as a result of the Ukraine
invasion.
The SCO price averaged US$98.66 per bbl for 2022, an increase of 49% from US$66.36 per bbl for 2021 (2020 – US$36.26 per
bbl). The increase in SCO pricing for 2022 from 2021 primarily reflected the increase in WTI benchmark pricing.
NYMEX natural gas prices averaged US$6.64 per MMBtu for 2022, an increase of 72% from US$3.85 per MMBtu for 2021
(2020 – US$2.08 per MMBtu). The increase in NYMEX natural gas prices for 2022 from 2021 primarily reflected increased global
commodity prices due to lower European inventories and the Russian invasion of Ukraine.
AECO natural gas prices averaged $5.28 per GJ for 2022, an increase of 56% from $3.38 per GJ for 2021 (2020 – $2.12 per GJ).
The increase in AECO natural gas prices for 2022 from 2021 primarily reflected lower storage levels and increased NYMEX
benchmark pricing.
19
Canadian Natural 2022 Annual Report
Analysis of Changes in Product Sales
($ millions)
North America
Changes due to
Changes due to
2020 Volumes
Prices
Other
2021 Volumes
Prices
Other
2022
Crude oil and NGLs
$ 7,480 $
82 $ 6,916 $
— $ 14,478 $
286 $ 5,991 $
— $ 20,755
Natural gas
Other (1)
North Sea
Crude oil and NGLs
Natural gas
Other (1)
Offshore Africa
Crude oil and NGLs
Natural gas
Other (1)
Oil Sands Mining
and Upgrading
Crude oil and NGLs
Other (1)
Midstream and
Refining
Midstream activities
Refined product sales
and other (1)
Intersegment
eliminations
and other (2)
Product sales
Other (1)
1,242
41
8,763
193
—
275
1,049
—
7,965
—
78
2,484
119
78
17,081
584
—
870
1,863
—
7,854
—
98
4,931
217
98
25,903
417
12
3
432
318
42
18
378
(72)
(8)
—
262
1
—
(80)
263
(68)
(9)
—
(77)
170
(2)
—
168
—
—
(4)
(4)
—
—
(11)
(11)
607
5
(1)
(183)
199
(2)
—
10
—
611
(185)
209
420
31
7
458
45
2
—
47
229
22
—
251
—
—
1
1
—
—
1
1
623
13
—
636
694
55
8
757
7,389
139
7,528
560
—
560
6,084
—
6,084
—
14,033
(592)
7,363
—
20,804
(66)
73
—
—
76
149
(66) 14,106
(592)
7,363
76
20,953
83
202
285
74
31
105
—
—
—
—
—
—
—
—
—
—
—
—
(5)
78
479
474
681
759
(238)
(164)
(28)
3
(266)
(161)
—
—
—
—
—
—
—
—
—
—
—
—
2
80
225
227
906
986
454
2
456
290
5
295
Total
$ 17,491 $
678 $ 14,480 $
205 $ 32,854 $
140 $ 15,677 $
859 $ 49,530
(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 51% to $49,530 million for 2022 from $32,854 million for 2021 (2020 – $17,491 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 2022, 3% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America
(2021 – 3%; 2020 – 5%). North Sea accounted for 1% of crude oil and NGLs and natural gas product sales for 2022 (2021 – 2%;
2020 – 3%), and Offshore Africa accounted for 2% of crude oil and NGLs and natural gas product sales for 2022 (2021 – 1%;
2020 – 2%).
Canadian Natural 2022 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)
International – Exploration and Production
North Sea
Offshore Africa
Total International (2)
Total Crude oil and NGLs
Natural gas (MMcf/d) (3)
North America
International
North Sea
Offshore Africa
Total International
Total Natural gas
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) (4)
(excluding Midstream and Refining revenue)
Crude oil and NGLs
Natural gas
2022
2021
2020
479,971
425,945
472,621
448,133
460,443
417,351
12,890
14,343
27,233
17,633
14,017
31,650
23,142
17,022
40,164
933,149
952,404
917,958
2,075
1,680
1,450
2
13
15
3
12
15
12
15
27
2,090
1,695
1,477
1,281,434
1,234,906
1,164,136
11%
4%
5%
20%
33%
27%
88%
12%
10%
5%
5%
21%
36%
23%
91%
9%
11%
5%
6%
21%
36%
21%
91%
9%
(1) SCO production before royalties excludes SCO consumed internally as diesel.
(2)
"International" includes North Sea and Offshore Africa Exploration and Production segments in all instances used.
(3) Natural gas production volumes approximate sales volumes.
(4) Net of blending costs and excluding risk management activities.
21
Canadian Natural 2022 Annual Report
DAILY PRODUCTION, NET OF ROYALTIES
Crude oil and NGLs (bbl/d)
North America – Exploration and Production
North America – Oil Sands Mining and Upgrading
International – Exploration and Production
North Sea
Offshore Africa
Total International
Total Crude oil and NGLs
Natural gas (MMcf/d)
North America
International
North Sea
Offshore Africa
Total International
Total Natural gas
Total Barrels of oil equivalent (BOE/d)
2022
2021
2020
374,089
351,740
404,637
410,385
420,906
413,363
12,849
12,972
25,821
17,588
13,354
30,942
23,086
16,306
39,392
751,650
845,964
873,661
1,885
1,593
1,406
2
11
13
3
11
14
12
14
26
1,898
1,607
1,432
1,068,063
1,113,878
1,112,364
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 2022 production before royalties averaged 1,281,434 BOE/d, an increase of 4% from 1,234,906 BOE/d in 2021 (2020 –
1,164,136 BOE/d).
Crude oil and NGLs production before royalties for 2022 averaged 933,149 bbl/d, comparable with 952,404 bbl/d for 2021 (2020
– 917,958 bbl/d).
Annual crude oil and NGLs production for 2022 was slightly below the Company's previously issued production forecast of
943,000 bbl/d. Annual crude oil and NGLs production for 2023 is targeted to average between 969,000 bbl/d and
1,001,000 bbl/d. 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 27% of the Company's total production in 2022 on a BOE basis. Natural
gas production for 2022 of 2,090 MMcf/d increased 23% from 1,695 MMcf/d for 2021 (2020 – 1,477 MMcf/d). The increase in
natural gas production for 2022 from 2021 primarily reflected strong drilling results and the acquisition completed in 2021,
partially offset by natural field declines and the impact of extreme cold weather conditions late in the fourth quarter of 2022.
Annual natural gas production for 2022 was slightly below the Company's previously issued production forecast of
2,112 MMcf/d. Annual natural gas production for 2023 is targeted to average between 2,170 MMcf/d and 2,242 MMcf/d.
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 2022 averaged 479,971 bbl/d, comparable with 472,621 bbl/d
for 2021 (2020 – 460,443 bbl/d).
Thermal oil production before royalties for 2022 averaged 252,018 bbl/d, a decrease of 3% from 259,284 bbl/d for 2021 (2020 –
248,971 bbl/d). The decrease in thermal oil production for 2022 from 2021 primarily reflected natural field declines.
Pelican Lake heavy crude oil production before royalties averaged 50,333 bbl/d for 2022, a decrease of 7% from 54,390 bbl/d for
2021 (2020 – 56,535 bbl/d), primarily reflecting a temporary injection reduction in 2022, together with natural field declines.
Natural gas production before royalties for 2022 averaged 2,075 MMcf/d, an increase of 24% from 1,680 MMcf/d for 2021
(2020 – 1,450 MMcf/d). The increase in natural gas production for 2022 from 2021 primarily reflected strong drilling results and
the acquisition completed in 2021, partially offset by natural field declines and the impact of extreme cold weather conditions
late in the fourth quarter of 2022.
Canadian Natural 2022 Annual Report
22
North America – Oil Sands Mining and Upgrading
SCO production before royalties for 2022 of 425,945 bbl/d decreased 5% from 448,133 bbl/d for 2021 (2020 – 417,351 bbl/d).
The decrease in SCO production for 2022 from 2021 primarily reflected the extended turnaround at the Scotford Upgrader
("Scotford") in the first half of 2022, the unplanned outage at Horizon during October, and the impact of extreme cold weather
conditions late in the fourth quarter of 2022 at both mines.
International – Exploration and Production
International crude oil and NGLs production before royalties for 2022 averaged 27,233 bbl/d, a decrease of 14% from 31,650
bbl/d for 2021 (2020 – 40,164 bbl/d). The decrease in production for 2022 from 2021 primarily reflected natural field declines,
together with the impact of maintenance activities in the North Sea in 2022.
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)
International
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 ($/Mcf) (1)
Realized price (5)
Transportation (6)
Realized price, net of transportation
Royalties (3)
Production expense (4)
Netback
Barrels of oil equivalent ($/BOE) (1)
Realized price (2)
Transportation (2)
Realized price, net of transportation (2)
Royalties (3)
Production expense (4)
Netback (2)
2022
2021
2020
390,959
727,439
972,133
2022
2021
2020
$
90.64 $
63.71 $
$
$
$
$
4.13
86.51
18.91
18.17
3.86
59.85
8.59
14.71
49.43 $
36.55 $
6.55 $
4.07 $
0.51
6.04
0.61
1.22
0.45
3.62
0.22
1.18
4.21 $
2.22 $
70.07 $
49.67 $
3.72
66.35
12.75
13.76
3.44
46.23
5.98
11.98
$
39.84 $
28.27 $
31.90
3.85
28.05
2.59
12.42
13.04
2.40
0.43
1.97
0.08
1.18
0.71
26.15
3.44
22.71
1.89
10.67
10.15
(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 2022 Annual Report
REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION
Crude oil and NGLs ($/bbl) (1)
North America (2)
International average (3)
North Sea (3)
Offshore Africa (3)
Crude oil and NGLs average (2)
Natural gas ($/Mcf) (1) (3)
North America
International average
North Sea
Offshore Africa
Natural gas average
Average ($/BOE) (1) (2)
2022
2021
2020
$
$
$
$
$
$
$
$
$
$
$
88.43 $
128.41 $
129.04 $
127.85 $
90.64 $
6.51 $
12.78 $
15.75 $
12.23 $
6.55 $
70.07 $
62.10 $
87.04 $
87.98 $
85.71 $
63.71 $
4.05 $
6.21 $
2.94 $
7.17 $
4.07 $
30.31
50.46
50.09
50.95
31.90
2.34
5.56
2.74
7.77
2.40
49.67 $
26.15
(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 42% to average $88.43 per bbl for 2022 from $62.10 per bbl for
2021 (2020 – $30.31 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 2022, the Company contributed approximately 179,000 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 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 61% to average $6.51 per Mcf for 2022 from $4.05 per Mcf for 2021 (2020
– $2.34 per Mcf). The increase in realized natural gas prices for 2022 from 2021 primarily reflected increased AECO benchmark
pricing.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
(Yearly average)
Wellhead Price (1)
Light and medium crude oil and NGLs ($/bbl)
Pelican Lake heavy crude oil ($/bbl)
Primary heavy crude oil ($/bbl)
Bitumen (thermal oil) ($/bbl)
Natural gas ($/Mcf)
2022
2021
2020
$
$
$
$
$
88.24 $
96.18 $
93.80 $
85.51 $
6.51 $
61.29 $
68.05 $
65.88 $
60.20 $
4.05 $
33.42
33.57
31.81
28.11
2.34
(1) Amounts expressed on a per unit basis are based on sales volumes of the respective product type.
International
International realized crude oil and NGLs prices increased 48% to average $128.41 per bbl for 2022 from $87.04 per bbl for
2021 (2020 – $50.46 per bbl). Realized crude oil and NGLs prices per barrel in any particular year are dependent on the terms of
the various sales contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign
exchange rates at the time of lifting. The increase in realized crude oil and NGLs prices for 2022 from 2021 reflected prevailing
Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.
Canadian Natural 2022 Annual Report
24
ROYALTIES – EXPLORATION AND PRODUCTION
Crude oil and NGLs ($/bbl) (1)
North America
International average
North Sea
Offshore Africa
Crude oil and NGLs average
Natural gas ($/Mcf) (1)
North America
Offshore Africa
Natural gas average
Average ($/BOE) (1)
2022
2021
2020
$
$
$
$
$
$
$
$
$
19.64 $
6.38 $
0.30 $
11.79 $
18.91 $
0.61 $
1.50 $
0.61 $
12.75 $
9.06 $
1.75 $
0.19 $
3.94 $
8.59 $
0.22 $
0.33 $
0.22 $
5.98 $
2.72
0.99
0.12
2.17
2.59
0.07
0.37
0.08
1.89
(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 2022 and the comparable periods reflected movements in
benchmark commodity prices, fluctuations in the WCS Heavy Differential and the impact of sliding scale royalty rates.
Crude oil and NGLs royalty rates (1) averaged approximately 22% of product sales for 2022 compared with 15% of product sales
for 2021 (2020 – 9%). The increase in royalty rates for 2022 from 2021 was primarily due to higher benchmark prices together
with fluctuations in the WCS Heavy Differential.
Natural gas royalty rates averaged approximately 9% of product sales for 2022, compared with 5% of product sales for 2021
(2020 – 3%). The increase in royalty rates for 2022 from 2021 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 9% for 2022 compared with 5% of product sales for
2021 (2020 – 4%). 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 2022 Annual Report
PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION
Crude oil and NGLs ($/bbl) (1)
North America
International average
North Sea
Offshore Africa
Crude oil and NGLs average
Natural gas ($/Mcf) (1)
North America
International average
North Sea
Offshore Africa
Natural gas average
Average ($/BOE) (1)
2022
2021
2020
16.25 $
51.01 $
88.99 $
17.25 $
18.17 $
1.19 $
5.16 $
9.27 $
4.40 $
1.22 $
13.12 $
37.77 $
54.13 $
14.73 $
14.71 $
1.15 $
5.07 $
7.31 $
4.41 $
1.18 $
11.21
26.60
36.51
13.29
12.42
1.14
3.64
3.72
3.58
1.18
13.76 $
11.98 $
10.67
$
$
$
$
$
$
$
$
$
$
$
(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 2022 averaged $16.25 per bbl, an increase of 24% from $13.12 per
bbl for 2021 (2020 – $11.21 per bbl). The increase in crude oil and NGLs production expense per bbl for 2022 from 2021
primarily reflected higher energy and service costs.
North America natural gas production expense for 2022 averaged $1.19 per Mcf, an increase of 3% from $1.15 per Mcf for
2021 (2020 – $1.14 per Mcf). The increase in natural gas production expense per Mcf for 2022 from 2021 primarily reflected
higher energy costs.
International
International crude oil and NGLs production expense for 2022 averaged $51.01 per bbl, an increase of 35% from $37.77 per bbl
for 2021 (2020 – $26.60 per bbl). The increase in crude oil production expense per bbl for 2022 from 2021 primarily reflected the
timing of liftings from various fields that have different cost structures, the impact of lower production volumes, higher energy
costs, and fluctuations in foreign exchange.
DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Depletion, Depreciation and Amortization
Less: Recoverability charge (1)
Adjusted depletion, depreciation and amortization (2)
$/BOE (3)
$
$
$
$
2022
2021
3,595 $
3,569 $
1,747
173
160
142
5,515 $
3,871 $
1,620
3,895 $
12.45 $
—
3,871 $
13.49 $
2020
3,780
277
190
4,247
—
4,247
15.45
(1) Prevailing regulatory and economic conditions in 2022 and the increasingly challenging commercial outlook in the United Kingdom, including the impact of
higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations. Following a detailed review of its development plans,
the Company determined that the Ninian field is no longer economic, de-booked associated crude oil reserves as at December 31, 2022, and is accelerating
abandonment. As a result, the Company completed a recoverability assessment of its assets in the North Sea, and recognized a recoverability charge of
$1,620 million in depletion, depreciation and amortization.
(2) This is a non-GAAP measure used to calculate depletion, depreciation and amortization, excluding the impact of non-recurring charges that do not reflect the
Company's normal course depletion, depreciation and amortization costs. It 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 financial statements
(depletion, depreciation and amortization expense), as applicable, as an indication of the Company's performance. It is calculated as depletion, depreciation
and amortization expense, less the impact of non-recurring charges.
(3) Non-GAAP ratio calculated as adjusted depletion, depreciation and amortization divided by sales volumes. For sales volumes, refer to the "Non-GAAP and
Other Financial Measures" section of this MD&A.
Canadian Natural 2022 Annual Report
26
Adjusted depletion, depreciation and amortization expense for 2022 of $12.45 per BOE decreased 8% from $13.49 per BOE for
2021 (2020 – $15.45 per BOE). The decrease in adjusted depletion, depreciation and amortization expense per BOE for 2022
from 2021 primarily reflected lower depletion rates due to increases to the Company's North America E&P reserve estimates at
December 31, 2021, including the impact of acquisitions completed during the prior year.
Adjusted depletion, depreciation and amortization expense on an absolute and per BOE basis also reflects the impact of the
timing of liftings from each field in the North Sea and Offshore Africa.
ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION
($ millions, except per BOE amounts)
North America
North Sea
Offshore Africa
Asset Retirement Obligation Accretion
$/BOE (1)
$
$
$
2022
171 $
33
7
211 $
0.67 $
2021
101 $
21
6
128 $
0.44 $
2020
97
30
6
133
0.48
(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 2022 of $0.67 per BOE increased 52% from $0.44 per BOE for 2021 (2020 –
$0.48 per BOE). The increase in asset retirement obligation accretion expense per BOE for 2022 from 2021 primarily reflected
the cost estimate and discount rate revisions made to the asset retirement obligation in 2021 and 2022.
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. SCO production in 2022 averaged 425,945 bbl/d, reflecting the extended turnaround at Scotford in the
first half of 2022, the unplanned outage at Horizon in October, and the impact of extreme cold weather conditions late in the
fourth quarter at both mines.
The Company incurred production expense of $4,076 million for 2022, an increase of 19% from $3,414 million for 2021,
reflecting increased energy and maintenance services costs.
REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND
UPGRADING
($/bbl)
Realized SCO sales price (1)
Bitumen value for royalty purposes (2)
Bitumen royalties (3)
Transportation (1)
2022
117.69 $
83.07 $
20.71 $
1.71 $
$
$
$
$
2021
77.95 $
58.39 $
6.62 $
1.21 $
2020
43.98
25.82
0.51
1.23
(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.
The realized SCO sales price averaged $117.69 per bbl for 2022, an increase of 51% from $77.95 per bbl for 2021 (2020 –
$43.98 per bbl). The increase in the realized SCO sales price for 2022 compared to 2021 primarily reflected the increase in WTI
benchmark pricing.
The increase in bitumen royalties per bbl for 2022 from 2021 primarily reflected the impact of Horizon reaching full payout in
2022, together with higher prevailing bitumen pricing and higher sliding scale royalty rates.
Transportation expense averaged $1.71 per bbl for 2022, an increase of 41% from $1.21 per bbl for 2021 (2020 – $1.23 per bbl).
The increase in transportation expense for 2022 from 2021 primarily reflected the impact of higher pipeline tolls, partially offset
by lower sales volumes.
27
Canadian Natural 2022 Annual Report
PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and Upgrading production expense disclosed in note 22 to the
Company’s audited consolidated financial statements.
($ millions)
Production expense, excluding natural gas costs
Natural gas costs
Production expense
($/bbl)
Production expense, excluding natural gas costs (1)
Natural gas costs (2)
Production expense (3)
Sales volumes (bbl/d)
$
$
$
$
2022
2021
3,743 $
3,176 $
333
238
4,076 $
3,414 $
2022
2021
23.91 $
19.45 $
2.13
1.46
26.04 $
20.91 $
2020
2,968
146
3,114
2020
19.50
0.96
20.46
428,820
447,230
415,741
(1) Calculated as production expense, excluding natural gas costs divided by sales volumes.
(2) Calculated as natural gas costs divided by sales volumes.
(3) Calculated as production expense divided by sales volumes.
Production expense for 2022 of $26.04 per bbl increased 25% from $20.91 per bbl for 2021 (2020 – $20.46 per bbl). The
increase in production expense per bbl for 2022 as compared to 2021 primarily reflected increased energy and maintenance
services costs, together with lower production volumes.
DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING
($ millions, except per bbl amounts)
Depletion, depreciation and amortization
$/bbl (1)
2022
1,822 $
11.64 $
2021
1,838 $
11.26 $
2020
1,784
11.73
$
$
(1) Calculated as depletion, depreciation and amortization divided by sales volumes.
Depletion, depreciation and amortization expense for 2022 of $11.64 per bbl increased 3% from $11.26 per bbl for 2021 (2020 –
$11.73 per bbl), reflecting lower production volumes in 2022.
ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING
($ millions, except per bbl amounts)
Asset retirement obligation accretion
$/bbl (1)
$
$
2022
70 $
0.45 $
2021
57 $
0.35 $
2020
72
0.47
(1) Calculated as asset retirement obligation accretion divided by sales volumes.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation
due to the passage of time.
Asset retirement obligation accretion expense for 2022 of $0.45 per bbl increased 29% from $0.35 per bbl for 2021 (2020 –
$0.47 per bbl). The increase in asset retirement obligation accretion expense on a per barrel basis for 2022 from 2021 primarily
reflected the impact of cost estimate and discount rate revisions made to the asset retirement obligation during 2022.
Canadian Natural 2022 Annual Report
28
Midstream and Refining
($ 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
Segmented earnings (loss)
2022
2021
2020
$
80 $
78 $
906
986
247
24
271
691
16
—
$
8 $
681
759
213
21
234
550
15
(400)
360 $
83
202
285
166
18
184
181
15
—
(95)
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 25% 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 until 2058. 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 2022 averaged 58,351 BOE/d (14,588 BOE/d to the Company), reflecting
turnaround activities during the year (2021 – 69,713 BOE/d; 17,428 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.
During 2022, NWRP extended its $3,000 million syndicated credit facility and increased it to $3,175 million. The revolving
portion of the credit facility was increased to $2,175 million, with $118 million maturing in June 2023, and $2,057 million
maturing in June 2025. The $1,000 million non-revolving portion of the credit facility was extended, with $60 million maturing in
June 2023, and $940 million maturing in June 2025. During 2022, NWRP also entered into a $150 million facility to support
letters of credit. As at December 31, 2022, NWRP had borrowings of $2,318 million under the syndicated credit facility
(December 31, 2021 – $1,981 million).
As at December 31, 2022, the cumulative unrecognized share of the equity loss and partnership distributions from NWRP was
$551 million (2021 – $562 million). The recovery of the unrecognized share of equity losses from NWRP for 2022 was $11
million (2021 – unrecognized equity loss of $9 million and partnership distributions of $400 million; 2020 – unrecognized equity
loss of $94 million).
29
Canadian Natural 2022 Annual Report
Corporate and Other
ADMINISTRATION EXPENSE
Expense ($ millions)
$/BOE (1)
Sales volumes (BOE/d) (2)
(1) Calculated as administration expense divided by sales volumes.
(2) Total Company sales volumes.
$
$
2022
415 $
0.88 $
2021
366 $
0.81 $
2020
391
0.92
1,285,877
1,233,457
1,166,862
Administration expense for 2022 of $0.88 per BOE increased 9% from $0.81 per BOE for 2021 (2020 – $0.92 per BOE).
Administration expense per BOE increased for 2022 from 2021 primarily due to higher personnel costs, partially offset by the
impact of higher overhead recoveries.
SHARE-BASED COMPENSATION
($ millions)
Expense (recovery)
$
2022
804 $
2021
514 $
2020
(82)
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 $804 million of share-based compensation expense for 2022, 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 $101 million related to PSUs granted to certain executive employees was included in
the share-based compensation expense for 2022 (2021 – $79 million expense; 2020 – $21 million expense).
INTEREST AND OTHER FINANCING EXPENSE
($ millions, except effective interest rate)
Interest and other financing expense
Interest income and other (1)
Capitalized interest (1)
Interest on long-term debt and lease liabilities (1)
Average current and long-term debt (2)
Average lease liabilities (2)
Average long-term debt and lease liabilities (2)
Average effective interest rate (3) (4)
Interest and other financing expense per $/BOE (5)
Sales volumes (BOE/d) (6)
(1)
Item is a component of interest and other financing expense.
$
$
$
$
$
2022
549 $
121
—
2021
711 $
32
—
670 $
743 $
13,986 $
18,935 $
1,531
1,619
15,517 $
20,554 $
4.3%
3.5%
2020
756
72
24
852
22,446
1,708
24,154
3.5%
1.17 $
1.58 $
1.77
1,285,877
1,233,457
1,166,862
(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 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.
(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 2022 decreased 26% to $1.17 per BOE from $1.58 per BOE for 2021 (2020 –
$1.77 per BOE). The decrease in interest and other financing expense per BOE for 2022 from 2021 was primarily due to lower
debt levels in 2022 and accrued interest on the deferred PRT recovery.
The Company’s average effective interest rate of 4.3% for 2022 increased from 2021 primarily due to higher prevailing interest
rates on floating rate debt held during 2022.
Canadian Natural 2022 Annual Report
30
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency
exposures. These derivative financial instruments are not intended for trading or speculative purposes.
($ millions)
Foreign currency contracts
Natural gas financial instruments (1)
Crude oil and NGLs financial instruments (1)
Net realized (gain) loss
Foreign currency contracts
Natural gas financial instruments (1)
Crude oil and NGLs financial instruments (1)
Net unrealized (gain) loss
Net (gain) loss
$
2022
(37) $
13
17
(7)
(16)
(10)
(2)
(28)
2021
2020
1 $
17
(1)
17
6
11
2
19
16
16
—
32
(3)
(36)
—
(39)
(7)
$
(35) $
36 $
(1) Commodity financial instruments were assumed in the acquisition of Storm Resources Ltd. ("Storm") and Painted Pony Energy Ltd. ("Painted Pony") in 2021
and 2020, respectively.
During 2022, net realized risk management gains were related to the settlement of foreign currency contracts, partially offset by
losses on natural gas financial instruments, and crude oil and NGLs financial instruments. The Company recorded a net
unrealized gain of $28 million ($25 million after-tax of $3 million) on its risk management activities for 2022 (2021 – $19 million
unrealized loss, $16 million after-tax of $3 million; 2020 – $39 million unrealized gain, $31 million after-tax of $8 million).
Further details related to outstanding derivative financial instruments as at December 31, 2022 are disclosed in note 19 to the
Company's audited consolidated financial statements.
FOREIGN EXCHANGE
($ millions)
Net realized (gain) loss
Net unrealized loss (gain)
Net loss (gain) (1)
$
$
2022
(114) $
852
738 $
2021
78 $
(205)
(127) $
2020
(159)
(116)
(275)
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange gain for 2022 was primarily due to foreign exchange rate fluctuations on settlement of
working capital items denominated in US dollars or UK pounds sterling and the settlement of the US$550 million cross currency
swap during 2022. The net unrealized foreign exchange loss for 2022 was primarily related to the impact of a weaker Canadian
dollar with respect to outstanding US dollar debt and the reclassification of the gain on the US$550 million cross currency swap
to realized foreign exchange due to its settlement in 2022. The US/Canadian dollar exchange rate at December 31, 2022 was
US$0.7389 (December 31, 2021 – US$0.7901, December 31, 2020 – US$0.7840).
31
Canadian Natural 2022 Annual Report
INCOME TAXES
($ 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)
($ millions, except effective tax rates)
Income tax
Tax effect on non-operating items (3)
Current PRT – North Sea
Other taxes
2022
2021
$
2,789 $
1,841 $
69
74
(42)
16
2,906
302
(441)
(139)
2,767 $
13,704 $
20%
2022
7
21
(34)
13
1,848
399
—
399
2,247 $
9,911 $
23%
2021
$
$
$
2,767 $
2,247 $
964
42
(16)
3,757 $
12,863 $
5
34
(13)
2,273 $
7,420 $
2020
(245)
(4)
17
(31)
6
(257)
(181)
—
(181)
(438)
(873)
50%
2020
(438)
29
31
(6)
(384)
(756)
Effective tax on adjusted net earnings (loss)
Adjusted net earnings (loss) from operations (4)
Adjusted net earnings (loss) from operations, before taxes
Effective tax rate on adjusted net earnings (loss) from operations (5) (6)
$
$
$
16,620 $ 9,693 $ (1,140)
23%
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 recoverability charge, the Keystone XL pipeline
provision and legislative changes to tax rates in adjusted net earnings (loss) from operations.
(4) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(5) 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 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.
(6) 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 2022 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 2022 and the prior periods included the impact of carrybacks of
PRT losses, including expenditures related to decommissioning activities at the Company's platforms in the North Sea.
Deferred PRT and income taxes for 2022 also reflected the impact of the recoverability charge recognized in depletion,
depreciation, and amortization.
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 2022, the Company filed Scientific Research and Experimental Development claims of approximately $283 million (2021
– $229 million; 2020 – $246 million) relating to qualifying research and development expenditures for Canadian income tax
purposes.
Canadian Natural 2022 Annual Report
32
Net Capital Expenditures (1) (2)
($ millions)
Exploration and Evaluation
Net expenditures
Net property dispositions
Total Exploration and Evaluation
Property, Plant and Equipment
Net property acquisitions (3) (4)
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
Net property dispositions
Other (5)
Total Oil Sands Mining and Upgrading
Midstream and Refining
Head office
Abandonments expenditures, net (2)
Net capital expenditures
By segment
North America (3) (4)
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream and Refining
Head office
Abandonments expenditures, net (2)
Net capital expenditures
2022
2021
2020
$
36 $
(3)
33
12 $
(11)
1
36
(31)
5
513
1,545
1,233
59
3,350
3,383
294
1,171
287
(40)
7
1,719
9
25
335
1,112
918
802
64
2,896
2,897
236
1,035
145
—
331
1,747
9
23
232
$
$
5,471 $
4,908 $
3,133 $
2,662 $
126
124
1,719
9
25
335
173
62
1,747
9
23
232
$
5,471 $
4,908 $
536
429
580
60
1,605
1,610
258
839
196
—
30
1,323
5
19
249
3,206
1,389
122
99
1,323
5
19
249
3,206
(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)
(4)
(5)
Includes cash consideration of $771 million and the settlement of long-term debt of $183 million assumed in the acquisition of Storm in 2021.
Includes cash consideration of $111 million and the settlement of long-term debt of $397 million assumed in the acquisition of Painted Pony in 2020.
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 2022 were $5,471 million compared with $4,908 million for 2021. Net capital expenditures for 2022
included base capital expenditures (1) of $3,956 million and strategic growth capital expenditures (1) of $1,045 million, in
accordance with the Company's capital budget. The Company also completed strategic acquisitions (1) of $470 million during
2022.
(1)
Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on Net Capital
Expenditures.
33
Canadian Natural 2022 Annual Report
2023 CAPITAL BUDGET
On November 30, 2022, the Company announced its 2023 base capital budget (1) targeted at approximately $4,190 million. The
budget also includes incremental strategic growth capital of approximately $1,020 million that targets to add additional
production and capacity growth beyond 2023 in the Company's E&P segments, and long life low decline thermal in situ and Oil
Sands Mining and Upgrading assets.
The 2023 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further details
on forward-looking statements.
DRILLING ACTIVITY (1) (2)
(number of net wells)
Net successful crude oil wells (3)
Net successful natural gas wells
Dry wells
Total
Success rate
2022
317
72
1
390
99%
2021
149
49
1
199
99%
2020
42
30
—
72
100%
(1)
Includes drilling activity for North America and International segments.
(2) During 2022, on a net basis, the Company drilled 373 stratigraphic and 5 service wells in the Oil Sands Mining and Upgrading segment, 18 stratigraphic and
53 service wells in the Company's thermal oil projects, and 3 service wells in Northwest Alberta.
(3)
Includes bitumen wells.
North America
During 2022, the Company drilled 72 net natural gas wells, 176 net primary heavy crude oil wells, 6 net Pelican Lake heavy
crude oil wells, 104 net bitumen (thermal oil) wells and 32 net light crude oil wells.
Liquidity and Capital Resources
($ millions, except ratios)
Adjusted working capital (1)
Long-term debt, net (2)
Shareholders’ equity
2022
(1,190) $
10,525 $
38,175 $
2021
(480) $
13,950 $
36,945 $
$
$
$
Debt to book capitalization (2)
After-tax return on average capital employed (3)
22%
22%
27%
16%
(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.
2020
626
21,269
32,380
40%
—%
As at December 31, 2022, 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;
(1) 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 2022 Annual Report
34
▪
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 $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 2022, the Company repaid and cancelled the $500 million non-revolving
portion of the $1,000 million term credit facility, reducing the remaining facility to the $500 million revolving facility
maturing February 2023, and extended this facility from February 2023 to February 2024.
◦ 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 2022, the Company repaid and cancelled the $1,150
million non-revolving term credit facility maturing in February 2023.
◦ During 2022, the Company discontinued its £5 million demand credit facility related to its North Sea operations.
◦ 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 outstanding balance of $3,088 million on the non-revolving term credit facility was repaid and the
facility was cancelled.
◦ 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.
◦ 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 2022, the Company repaid through market purchases $498 million of medium-term notes with interest rates
ranging from 1.45% to 3.55%, originally due between 2023 and 2028.
◦ During 2022, the Company repaid $1,000 million of 3.31% 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 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023.
◦ During 2021, the Company repaid US$500 million of 3.45% 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.
As at December 31, 2022, the Company had undrawn revolving bank credit facilities of $5,520 million. Including cash and cash
equivalents and short-term investments, the Company had approximately $6,931 million in liquidity. The Company also has
certain other dedicated credit facilities supporting letters of credit.
During 2022, the Company settled the US$550 million cross currency swap designated as a cash flow hedge of a portion of the
US$1,100 million 6.25% US dollar debt securities due March 2038. The Company realized cash proceeds of $158 million on
settlement. As at December 31, 2022, the Company had no cross currency swap contracts outstanding. As at December 31,
2022, there were no foreign currency contracts designated as cash flow hedges.
35
Canadian Natural 2022 Annual Report
Long-term debt, net was $10,525 million at December 31, 2022, resulting in a debt to book capitalization ratio (1) of 22%
(December 31, 2021 – 27%, December 31, 2020 – 40%); this ratio was below 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, 2022
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, 2022, 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,
2022 are discussed in note 19 to the Company’s audited consolidated financial statements.
As at December 31, 2022, the maturity dates of long-term debt and other long-term liabilities and related interest payments
were as follows:
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
$
$
$
404 $
247 $
584 $
1,009 $
156 $
577 $
3,757 $
416 $
1,410 $
Thereafter
6,344
724
3,790
(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, $244 million; one to less than
two years, $156 million; two to less than five years, $416 million; and thereafter, $724 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, 2022.
SHARE CAPITAL
As at December 31, 2022, there were 1,102,636,000 common shares outstanding (December 31, 2021 – 1,168,369,000
common shares) and 31,150,000 stock options outstanding. As at February 28, 2023, the Company had 1,099,741,000 common
shares outstanding and 31,902,000 stock options outstanding.
On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share,
beginning with the dividend payable on April 5, 2023.
On November 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share,
beginning with the dividend paid on January 5, 2023.
On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share, paid on August 31, 2022.
On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.75 per common share. On
November 3, 2021, the Board of Directors approved a 25% increase in the quarterly dividend to $0.5875 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. The dividend policy undergoes periodic review by the Board of Directors and is subject to change.
On March 8, 2022, 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
101,574,207 common shares, representing 10% of the public float, over a 12-month period commencing March 11, 2022 and
ending March 10, 2023.
During 2022, the Company purchased 77,338,200 common shares at a weighted average price of $72.03 per common share for
a total cost of $5,571 million. Retained earnings were reduced by $4,868 million, representing the excess of the purchase price
of common shares over their average carrying value. Subsequent to December 31, 2022, up to and including February 28, 2023,
the Company purchased 6,000,000 common shares at a weighted average price of $77.72 per common share for a total cost of
$466 million.
On March 1, 2023, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with the
TSX to purchase, by way of Normal Course Issuer Bid, up to 10% of the public float (as determined in accordance with the rules
of the TSX) of its issued and outstanding common shares. Subject to acceptance of the Notice of Intention by the TSX, the
purchases would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE.
(1) Capital management measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
Canadian Natural 2022 Annual Report
36
Commitments and Contingencies
In the normal course of business, the Company has committed to certain payments. The following table summarizes the
Company’s commitments as at December 31, 2022:
($ millions)
Product transportation and processing (1)
North West Redwater Partnership service
toll (2)
Offshore vessels and equipment
Field equipment and power
Other
$
$
$
$
$
2023
2024
2025
2026
2027
Thereafter
1,171 $
1,349 $
1,168 $
1,102 $
1,052 $
11,095
151 $
152 $
151 $
133 $
118 $
4,884
44 $
36 $
23 $
35 $
27 $
24 $
— $
24 $
21 $
— $
23 $
16 $
— $
22 $
— $
—
215
—
(1)
Includes commitments pertaining to a 20-year product transportation agreement on the Trans Mountain Pipeline Expansion.
(2) 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 $2,863 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 2022 Annual Report
Reserves
For the years ended December 31, 2022 and 2021, 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, 2022:
Total Proved
December 31, 2021 (1)
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2022 (1)
Total Proved Plus
Probable
December 31, 2021 (1)
Discoveries
Extensions
Infill Drilling
Improved Recovery
Acquisitions
Dispositions
Economic Factors
Technical Revisions
Production
December 31, 2022 (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)
300
—
3
7
—
—
—
10
(61)
(28)
231
169
270
2,631
6,998
12,168
418
12,813
—
14
5
—
—
—
6
11
—
—
—
—
—
—
4
6
—
262
—
2
431
—
—
50
—
—
—
37
—
—
—
—
290
218
—
249
—
446
(6)
1,019
—
13
19
—
25
—
9
23
—
339
68
40
498
—
103
194
(25)
179
(18)
262
(92)
(155)
(763)
(22)
(468)
3,284
6,873
13,627
486
13,587
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)
424
249
388
4,337
7,535
20,249
643
16,950
—
4
10
—
—
—
10
(100)
(28)
320
—
26
8
—
—
—
7
8
—
—
—
1
—
—
3
2
(25)
272
(18)
376
—
337
—
2
551
—
—
50
(92)
—
—
—
50
—
—
—
(20)
(155)
—
829
344
—
588
—
528
495
—
35
26
—
72
—
11
8
—
539
100
52
722
—
120
29
(763)
(22)
(468)
5,186
7,408
22,270
772
18,046
(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, 2022, the total proved crude oil, bitumen (thermal oil) and NGLs reserves were 11,316 MMbbl, and total
proved plus probable crude oil, bitumen (thermal oil) and NGLs reserves were 14,334 MMbbl. Total proved reserves additions
and revisions replaced 256% of 2022 production. Additions to total proved reserves resulting from exploration and development
activities, acquisitions, dispositions and future offset additions amounted to 818 MMbbl, and additions to total proved plus
probable reserves amounted to 1,120 MMbbl. Net positive revisions amounted to 53 MMbbl for total proved reserves and net
negative revisions amounted to 21 MMbbl for total proved plus probable reserves, primarily due to technical revisions.
At December 31, 2022, the total proved natural gas reserves were 13,627 Bcf, and total proved plus probable natural gas
reserves were 22,270 Bcf. Total proved reserves additions and revisions replaced 291% of 2022 production. Additions to total
proved reserves resulting from exploration and development activities, acquisitions, dispositions and future offset additions
amounted to 757 Bcf, and additions to total proved plus probable reserves amounted to 1,761 Bcf.
Canadian Natural 2022 Annual Report
38
Net positive revisions amounted to 1,465 Bcf for total proved reserves, primarily due to technical revisions and economic
factors. Net positive revisions amounted to 1,023 Bcf for total proved plus probable reserves, primarily due to economic factors
and technical revisions.
The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence
procedures with each of the Company’s Independent Qualified Reserves Evaluators to review the qualifications of and
procedures used by each evaluator in determining the estimate of the Company’s quantities and related net present value of
future net revenue of the remaining reserves. Additional reserves 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;
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;
39
Canadian Natural 2022 Annual Report
▪
▪
▪
▪
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, 2022.
Environment
The Company has a Corporate Statement on Environmental Management which affirms that environmental stewardship is a
fundamental value of the Company. The Company continues to invest in people, proven and new technologies, facilities and
infrastructure to recover and process crude oil and natural gas resources efficiently and in an environmentally sustainable
manner. Environmental, social, economic and health considerations are evaluated in new project designs and in operations to
improve environmental performance. Processes are employed to avoid, mitigate, minimize or compensate for environmental
effects. Working with local communities, the Company considers the interests and values of the people using the land in
proximity to its operations, and where appropriate, adapts projects to recognize those matters.
The crude oil and natural gas industry is experiencing incremental increases in costs related to environmental regulation
compliance, particularly in North America and the North Sea. Existing and expected legislation and regulations may require the
Company to address and mitigate the effect of its activities on the environment. The Company has processes in place to meet
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.
Canadian Natural 2022 Annual Report
40
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"), the innovation arm of Pathways, 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. 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 Ninian North and were advanced at Banff and Kyle;
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;
Supporting regional air shed monitoring for emissions and their deposition; and
An internal environmental management system for compliance audit and inspection programs of operating facilities.
The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60
years and have been discounted using a weighted average discount rate of 5.6% (2021 – 4.0%; 2020 – 3.7%). For 2022, the
Company’s capital expenditures included $449 million for abandonment expenditures ($335 million – abandonment
expenditures, net) (2021 – $307 million; 2020 – $249 million). Refer to the “Non-GAAP and Other Financial Measures” section
of this MD&A for further details on abandonments expenditures, net. The Company’s estimated discounted ARO at
December 31, 2022 was as follows:
($ millions)
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Midstream and Refining
2022
2021
$
4,326 $
1,011
143
1,427
1
$
6,908 $
4,021
821
170
1,793
1
6,806
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 estimates of current
costs in accordance with present legislation, industry operating practice and the expected timing of abandonment.
In 2021, the Alberta Energy Regulator (“AER”) 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. During
2022, the AER increased the mandatory targets. Also during 2022, the government of Saskatchewan introduced the Inactive
Liability Reduction Program and the government of British Columbia updated its Dormancy and Shutdown Regulations, which
provide mandatory targets for decommissioning and restoring inactive wells and facilities in those provinces. 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, 2022 was increased on an inflated and discounted basis due to earlier
forecasted expenditures to settle liabilities associated with the closure of inactive well and facilities.
41
Canadian Natural 2022 Annual Report
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 Pathways, an alliance of oil sands producers working collectively with federal and provincial
governments, to achieve the goal of 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.
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 2023. 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 a comprehensive management system for air pollutants and has released regulations pertaining to certain boilers,
heaters and compressor engines operated by the Company. Additionally, in 2022, the federal government released the Clean
Fuel Regulations, which applies to producers or importers of liquid fuels (including gasoline, diesel, kerosene and light and
heavy fuel oils).
Carbon pricing regulatory systems in all provinces are subject to periodic 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). In December 2022, the Alberta government published
changes to TIER effective January 1, 2023 that reduce the amount of emissions allocations for facilities under the regulation.
Additionally, emissions coverage within TIER was expanded to include flaring from all TIER regulated facilities. The carbon price
in Alberta was $50/tonne for emissions above the TIER-regulated limits in 2022 and is $65/tonne in 2023, in alignment with the
federal carbon pricing schedule. The Alberta government has published a carbon pricing schedule to 2030 that aligns with the
federal carbon pricing schedule for that period. 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 $50/tonne of CO2e on fuel consumed and gas flared and vented in
the province. 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.
The governments of British Columbia and Saskatchewan have announced their intention to follow the federal carbon pricing
schedule and associated regulations are expected in 2023.
In Manitoba, the federal output-based pricing system and carbon pricing schedule 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.
Canadian Natural 2022 Annual Report
42
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. In 2022, the federal government announced a framework for expanding
methane regulations to achieve at least a 75% reduction below 2012 levels, by 2030. Draft regulations are expected in 2023.
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 2022 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 beginning in 2021.
CHANGES IN ACCOUNTING POLICIES
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.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the
application of IFRS that have a significant impact on the financial results of the Company. Actual results may differ from
estimated amounts, and those differences may be material. A comprehensive discussion of the Company's significant
accounting estimates is contained in this MD&A and the audited consolidated financial statements for the year ended
December 31, 2022.
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, income taxes, and the potential impact of climate related
matters and in accordance with related government regulations. 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 a recoverability assessment related to the specific assets at the CGU level.
Canadian Natural 2022 Annual Report
44
B) Crude Oil and Natural Gas Reserves
Reserves estimates are based on 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 5.6%. 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.
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.
45
Canadian Natural 2022 Annual Report
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, 2022, 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, 2022, 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 2022 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 2022 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, net of 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 (gain) loss, net of tax (2)
Unrealized foreign exchange loss (gain), net of tax (3)
Realized foreign exchange (gain) loss, net of tax (4)
Gain on acquisitions, net of tax (5)
(Gain) loss from investments, net of tax (6)
Recoverability charge, net of tax (7)
Other, net of tax (8)
Non-operating items, net of tax
2022
2021
$
10,937 $
7,664 $
780
(25)
852
(62)
—
(182)
651
(88)
1,926
495
16
(205)
118
(478)
(132)
—
(58)
(244)
Adjusted net earnings (loss) from operations
$
12,863 $
7,420 $
2020
(435)
(86)
(31)
(116)
(166)
(217)
185
—
110
(321)
(756)
(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 2022 was an expense of $804 million (2021 – $514 million expense; 2020 – $82 million recovery).
(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 crude oil, natural gas and foreign exchange. Pre-tax
unrealized risk management gain for 2022 was $28 million (2021 – $19 million loss; 2020 – $39 million gain).
(3) Unrealized foreign exchange losses and gains 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 losses and gains are the same.
(4) During 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023, resulting in a realized foreign exchange
loss of $7 million. Also, during 2022, the Company settled the US$550 million cross currency swap designated as a cash flow hedge of a portion of the
US$1,100 million 6.25% US dollar debt securities due March 2038, resulting in a realized foreign exchange gain of $69 million. During 2021, the Company
repaid US$500 million of 3.45% debt securities, resulting in a realized 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, originally due November 2021, resulting
in a realized foreign exchange gain of $166 million. Pre- and after-tax amounts for these realized foreign exchange gains and losses are the same.
(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 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 zero net tax impact on these (gains) losses from investments.
(7) The Company recognized a recoverability charge of $1,620 million in depletion, depreciation and amortization at December 31, 2022 relating to the de-booking
of reserves at the Ninian field in the North Sea. Prevailing regulatory and economic conditions in 2022 and the increasingly challenging commercial outlook in
the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations.
Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked associated crude oil
reserves as at December 31, 2022, and is accelerating abandonment.
(8) During 2022, the Company recognized the impact of government grant income under the provincial well-site rehabilitation programs of $114 million (2021 –
$75 million). During 2020, the Company recognized a provision in transportation, blending and feedstock expense of $143 million relating to the Keystone XL
pipeline project.
47
Canadian Natural 2022 Annual Report
ADJUSTED FUNDS FLOW
Adjusted funds flow is a non-GAAP financial measure that represents cash flows from operating activities as presented in the
Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment
expenditures excluding the impact of government grant income under the provincial well-site rehabilitation programs, and
movements in other long-term assets. The Company considers adjusted funds flow a key measure in evaluating its
performance, as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through
capital investment and to repay debt. A reconciliation for adjusted funds flow, from cash flows from operating activities is
presented below.
($ millions)
2022
2021
Cash flows from operating activities
$
19,391 $
14,478 $
Net change in non-cash working capital
Abandonment expenditures, net (1)
Movements in other long-term assets (2)
(79)
335
144
(964)
232
(13)
2020
4,714
166
249
71
Adjusted funds flow
$
19,791 $
13,733 $
5,200
(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 the deferred PRT recovery, 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 common 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.
These non-GAAP measures, disclosed on a per share basis, enable a comparison to the per share amounts disclosed in the
Company's financial statements prepared in accordance with IFRS.
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
$
$
2022
449 $
(114)
335 $
2021
307 $
(75)
232 $
2020
249
—
249
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 2022 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 $/bbl)
Crude oil and NGLs (bbl/d)
North America
International
North Sea
Offshore Africa
Total International
Total sales volumes
Crude oil and NGLs sales (1) (2)
Less: Blending costs (3)
Realized crude oil and NGLs sales
Realized price ($/bbl)
2022
2021
2020
480,691
471,331
465,073
13,215
14,866
28,081
18,942
13,452
32,394
22,852
17,017
39,869
508,772
503,725
504,942
$
$
$
22,072 $
15,505 $
5,239
3,792
16,833 $
11,713 $
90.64 $
63.71 $
8,215
2,321
5,894
31.90
(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 $/BOE)
Barrels of oil equivalent (BOE/d)
North America
International
North Sea
Offshore Africa
Total International
Total sales volumes
Barrels of oil equivalent sales (1) (2)
Less: Blending costs (3)
Less: Sulphur (income) expense
Realized barrels of oil equivalent sales
Realized price ($/BOE)
2022
2021
2020
826,526
751,330
706,799
13,598
16,933
30,531
19,512
15,385
34,897
24,805
19,517
44,322
857,057
786,227
751,121
$
$
$
27,071 $
18,025 $
5,239
(88)
3,792
(21)
21,920 $
14,254 $
70.07 $
49.67 $
9,511
2,321
4
7,186
26.15
(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 2022 Annual Report
TRANSPORTATION – EXPLORATION AND PRODUCTION
Transportation ($/BOE, $/bbl and $/Mcf) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure) divided
by the respective sales volumes. The Company calculates transportation to demonstrate its cost to deliver products to the
market excluding the impact of blending costs. A reconciliation for Exploration and Production transportation and the
calculations for transportation on a per unit basis are presented below.
($ millions, except $ per unit amounts)
Transportation, blending and feedstock (1)
Less: Blending costs
Less: Other (2)
Transportation
Transportation ($/BOE)
Amounts attributed to crude oil and NGLs
Transportation ($/bbl)
Amounts attributed to natural gas
Transportation ($/Mcf)
2022
2021
6,401 $
4,780 $
5,239
—
1,162 $
3.72 $
767 $
4.13 $
395 $
0.51 $
3,792
—
988 $
3.44 $
710 $
3.86 $
278 $
0.45 $
2020
3,409
2,321
143
945
3.44
711
3.85
234
0.43
$
$
$
$
$
$
$
(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
$
$
$
$
2022
2021
20,755 $
14,478 $
5,239
3,792
15,516 $
10,686 $
88.43 $
62.10 $
3,445 $
1,558 $
22%
15%
2020
7,480
2,321
5,159
30.31
464
9%
(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 2022 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 on a per unit basis are presented below.
($ millions, except for bbl/d and $/bbl)
SCO sales volumes (bbl/d)
Crude oil and NGLs sales (1) (2)
Less: Blending and feedstock costs
Realized SCO sales
Realized SCO sales price ($/bbl)
Transportation, blending and feedstock (3)
Less: Blending and feedstock costs
Transportation
Transportation ($/bbl)
2022
428,820
2021
447,230
2020
415,741
$
$
$
$
$
$
20,804 $
14,033 $
2,384
18,420 $
117.69 $
1,309
12,724 $
77.95 $
2,652 $
1,505 $
2,384
268 $
1.71 $
1,309
196 $
1.21 $
7,389
695
6,694
43.98
881
695
186
1.23
(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 investments, 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
Proceeds from investment
Repayment of NWRP subordinated debt advances
Capital expenditures
Abandonment expenditures, net (1)
Settlement of long-term debt acquired (2)
Net capital expenditures (3)
2022
2021
$
4,987 $
3,703 $
149
—
—
5,136
335
—
107
128
555
4,493
232
183
$
5,471 $
4,908 $
2020
2,819
(383)
—
124
2,560
249
397
3,206
(1) Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the “Abandonment Expenditures, net” section above.
(2) Relates to the settlement of long-term debt assumed in the acquisition of Storm in 2021 and Painted Pony in 2020.
(3) For 2022, includes base capital expenditures of $3,956 million, net property, plant and equipment acquisitions and net exploration and evaluation asset
dispositions of $470 million, and strategic growth capital expenditures of $1,045 million. Strategic growth capital expenditures represent the allocation of the
Company's free cash flow that will be directed to strategic capital growth opportunities that target to increase production volumes in future periods and that
exceed the Company's base capital expenditures for the current fiscal year, as outlined in the Company's capital budget.
51
Canadian Natural 2022 Annual Report
LIQUIDITY
Liquidity is a non-GAAP financial measure that represents the availability of readily available undrawn bank credit facilities, cash
and cash equivalents, and other highly liquid assets to meet short-term funding requirements and to assist in assessing the
Company's financial position. The Company’s calculation of liquidity is presented below.
($ millions)
Undrawn bank credit facilities
Cash and cash equivalents
Investments
Liquidity
LONG-TERM DEBT, NET
2022
2021
5,520 $
6,098 $
920
491
744
309
6,931 $
7,151 $
2020
4,958
184
305
5,447
$
$
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)
12 months average capital employed
2022
2021
2020
$
$
$
$
10,937 $
7,664 $
424
547
11,361 $
8,211 $
1,359 $
1,483 $
11,761
38,218
16,769
34,458
51,338 $
52,710 $
(435)
571
136
1,842
20,162
33,026
55,030
After-tax return on average capital employed
22%
16%
—%
(1) The blended tax rate on interest was 23% for December 31, 2022, 23% for December 31, 2021, and 24% for December 31, 2020.
(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 2022 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.
2023 CAPITAL BUDGET
On November 30, 2022, the Company announced its 2023 base capital budget targeted at approximately $4,190 million. The
budget also includes incremental strategic growth capital of approximately $1,020 million that targets to add additional
production and capacity growth beyond 2023 in the Company's E&P segments, and long life low decline thermal in situ and Oil
Sands Mining and Upgrading assets. The 2023 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
2022, 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
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)
$
$
$
$
$
$
$
300 $
0.26 $
300 $
0.26
36 $
35 $
165 $
11 $
0.03 $
0.03 $
0.15 $
0.01 $
36 $
35 $
140 $
7 $
280 $
4 $
0.25 $
— $
146 $
4 $
0.03
0.03
0.12
0.01
0.13
—
(1) For details of financial instruments in place, refer to note 19 to the Company’s audited consolidated financial statements as at December 31, 2022.
53
Canadian Natural 2022 Annual Report
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
Q1
Q2
Q3
Q4
2022
2021
2020
Crude oil and NGLs (bbl/d)
North America – Exploration and
Production
484,280 477,478 471,632 486,559 479,971 472,621 460,443
North America – Oil Sands Mining and
Upgrading (1)
429,826 356,953 487,553 428,784 425,945 448,133 417,351
International
North Sea
Offshore Africa
Total International
Total Crude oil and NGLs
Natural gas (MMcf/d) (2)
North America
International
North Sea
Offshore Africa
Total International
Total Natural gas
Barrels of oil equivalent (BOE/d)
North America – Exploration and
15,961
10,788
10,855
14,006
12,890
17,633
23,142
15,742
15,119
13,638
12,909
14,343
14,017
17,022
31,703
25,907
24,493
26,915
27,233
31,650
40,164
945,809 860,338 983,678 942,258 933,149 952,404 917,958
1,988
2,089
2,117
2,105
2,075
1,680
1,450
3
15
18
2
14
16
1
14
15
3
7
10
2
13
15
3
12
15
12
15
27
2,006
2,105
2,132
2,115
2,090
1,695
1,477
Production
815,632 825,664 824,358 837,348 825,806 752,620 702,168
North America – Oil Sands Mining and
Upgrading (1)
429,826 356,953 487,553 428,784 425,945 448,133 417,351
International
North Sea
Offshore Africa
Total International
16,435
11,103
11,072
14,526
13,273
18,203
25,095
18,287
17,427
15,957
14,021
16,410
15,950
19,522
34,722
28,530
27,029
28,547
29,683
34,153
44,617
Total Barrels of oil equivalent
1,280,180 1,211,147 1,338,940 1,294,679 1,281,434 1,234,906 1,164,136
(1) SCO production before royalties excludes SCO consumed internally as diesel.
(2) Natural gas production volumes approximate sales volumes.
Canadian Natural 2022 Annual Report
54
PER UNIT RESULTS – EXPLORATION AND PRODUCTION
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
Barrels of oil equivalent ($/BOE) (1)
Realized price (2)
Transportation (2)
Realized price, net of transportation (2)
Royalties (3)
Production expense (4)
Netback (2)
Q1
Q2
Q3
Q4
2022
2021
2020
$
93.54 $ 115.26 $
84.91 $
69.34 $
90.64 $
63.71 $
31.90
4.18
4.13
89.36
111.13
17.80
15.80
25.01
19.58
4.10
80.81
19.48
16.86
4.11
65.23
13.56
20.37
4.13
86.51
18.91
18.17
3.86
59.85
8.59
14.71
$
55.76 $
66.54 $
44.47 $
31.30 $
49.43 $
36.55 $
$
5.26 $
7.93 $
6.57 $
6.39 $
6.55 $
4.07 $
0.50
4.76
0.42
1.31
0.52
7.41
0.89
1.17
0.51
6.06
0.61
1.16
0.55
5.84
0.51
1.25
0.51
6.04
0.61
1.22
0.45
3.62
0.22
1.18
$
3.03 $
5.35 $
4.29 $
4.08 $
4.21 $
2.22 $
3.85
28.05
2.59
12.42
13.04
2.40
0.43
1.97
0.08
1.18
0.71
$
69.66 $
88.07 $
66.04 $
56.83 $
70.07 $
49.67 $
26.15
3.72
65.94
11.88
12.70
3.70
84.37
17.03
14.44
3.64
62.40
12.88
12.68
3.80
53.03
9.31
15.17
3.72
66.35
12.75
13.76
3.44
46.23
5.98
11.98
$
41.36 $
52.90 $
36.84 $
28.55 $
39.84 $
28.27 $
3.44
22.71
1.89
10.67
10.15
(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
Crude oil and NGLs ($/bbl) (1)
Realized SCO sales price (2)
Bitumen royalties (3)
Transportation (2)
Production expense (4)
Netback (2)
Q1
Q2
Q3
Q4
2022
2021
2020
$ 112.05 $ 137.60 $ 120.91 $ 103.79 $ 117.69 $
77.95 $
43.98
13.51
31.63
24.87
14.48
20.71
1.55
2.05
1.55
1.80
1.71
6.62
1.21
24.60
33.76
22.35
25.48
26.04
20.91
$
72.39 $
70.16 $
72.14 $
62.03 $
69.23 $
49.21 $
0.51
1.23
20.46
21.78
(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 2022 Annual Report
TRADING AND SHARE STATISTICS
TSX – C$
Trading volume (thousands)
Share Price ($/share)
High
Low
Close
Market capitalization as at December 31
($ millions)
Shares outstanding
(thousands)
NYSE – US$
Trading volume (thousands)
Share Price ($/share)
High
Low
Close
Q1
Q2
Q3
Q4
2022
2021
408,106 378,433 401,112 346,071 1,533,722 1,568,872
$
$
$
80.13 $
88.18 $
75.95 $
84.25 $
88.18 $
54.20 $
64.20 $
58.75 $
66.42 $
54.20 $
77.41 $
69.17 $
64.30 $
75.19 $
75.19 $
55.59
28.67
53.45
$ 82,907 $ 62,449
1,102,636 1,168,369
243,414 176,133 187,207 148,968 755,722 795,605
$
$
$
64.10 $
70.60 $
58.60 $
62.57 $
70.60 $
42.32 $
49.37 $
44.45 $
48.43 $
42.32 $
61.98 $
53.68 $
46.57 $
55.53 $
55.53 $
44.33
22.40
42.25
Market capitalization as at December 31
($ millions)
Shares outstanding
(thousands)
$ 61,229 $ 49,364
1,102,636 1,168,369
Canadian Natural 2022 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 (Loss)
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
74
74
74
76
76
77
79
80
80
82
84
86
88
90
90
90
91
91
95
95
96
23. Remuneration of Directors and Senior Management
100
57
Canadian Natural 2022 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, 2022; and
the effectiveness of the Company’s internal control over financial reporting as at December 31, 2022.
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 A. STAINTHORPE, CFA
VICTOR C. DAREL, CPA, CA
Chief Financial Officer and
Senior Vice-President, Finance
Vice-President, Finance and Principal
Accounting Officer
Calgary, Alberta, Canada
March 1, 2023
Canadian Natural 2022 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 was
effective as at December 31, 2022. 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, 2022, as stated in their accompanying Report of
Independent Registered Public Accounting Firm.
TIM S. MCKAY
President
MARK A. STAINTHORPE, CFA
Chief Financial Officer and
Senior Vice-President, Finance
Calgary, Alberta, Canada
March 1, 2023
59
Canadian Natural 2022 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, 2022 and 2021, 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,
2022, 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, 2022, 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, 2022 and 2021, and its financial performance and its cash flows for each of the
three years in the period ended December 31, 2022 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, 2022, 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 2022 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 $25.2 billion as of December 31, 2022.
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, 2022. 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 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 1, 2023
We have served as the Company's auditor since 1973.
61
Canadian Natural 2022 Annual Report
Consolidated Balance Sheets
As at December 31,
(millions of Canadian dollars)
ASSETS
Current assets
Cash and cash equivalents
Accounts 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 income (loss)
Commitments and contingencies (note 20).
Approved by the Board of Directors on March 1, 2023.
Note
2022
2021
5
9
10
6
7
8
10
11
8,12
11
8,12
13
14
15
$
920 $
3,555
1,815
215
491
61
7,057
2,226
64,859
1,447
553
$
76,142 $
$
1,341 $
4,209
1,324
404
1,373
8,651
11,041
8,161
10,114
37,967
10,294
27,672
209
38,175
$
76,142 $
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
CATHERINE M. BEST
N. MURRAY EDWARDS
Chair of the Audit Committee
Executive Chairman of the Board
and Director
of Directors and Director
Canadian Natural 2022 Annual Report
62
Consolidated Statements of Earnings (Loss)
For the years ended December 31,
(millions of Canadian dollars, except per common share amounts) Note
Product sales
22
$
Less: royalties
Revenue
Expenses
Production
Transportation, blending and feedstock
Depletion, depreciation and amortization
Administration
Share-based compensation
Asset retirement obligation accretion
Interest and other financing expense
Risk management activities
Foreign exchange loss (gain)
Gain on acquisitions
Income from North West Redwater Partnership
(Gain) loss from investments
Earnings (loss) before taxes
Current income tax expense (recovery)
Deferred income tax (recovery) expense
Net earnings (loss)
Net earnings (loss) per common share
Basic
Diluted
7,8
12
12
18
19
7
10
9,10
13
13
17
17
2022
49,530 $
(7,232)
42,298
2021
32,854 $
(2,797)
30,057
8,712
9,973
7,353
415
804
281
549
(35)
738
—
—
(196)
28,594
13,704
2,906
(139)
7,152
6,604
5,724
366
514
185
711
36
(127)
(478)
(400)
(141)
20,146
9,911
1,848
399
$
$
$
10,937 $
7,664 $
9.64 $
9.52 $
6.49 $
6.46 $
Consolidated Statements of Comprehensive Income (Loss)
2022
2021
$
10,937 $
7,664 $
2020
(435)
For the years ended December 31,
(millions of Canadian dollars)
Net earnings (loss)
Items that may be reclassified subsequently to net earnings (loss)
Net change in derivative financial instruments designated as cash
flow hedges
Unrealized income, net of taxes of $1 million (2021 – $2 million,
2020 – $2 million)
Reclassification to net earnings (loss), net of taxes of $1 million
(2021 – $1 million, 2020 – $2 million)
Foreign currency translation adjustment
Translation of net investment
Other comprehensive income (loss), net of taxes
4
(6)
(2)
212
210
15
(7)
8
(17)
(9)
Comprehensive income (loss)
$
11,147 $
7,655 $
2020
17,491
(598)
16,893
6,280
4,498
6,046
391
(82)
205
756
(7)
(275)
(217)
—
171
17,766
(873)
(257)
(181)
(435)
(0.37)
(0.37)
13
(15)
(2)
(24)
(26)
(461)
63
Canadian Natural 2022 Annual Report
Consolidated Statements of Changes in Equity
For the years ended December 31,
(millions of Canadian dollars)
Share capital
Balance – beginning of year
Issued upon exercise of stock options
Previously recognized liability on stock options exercised for
common shares
Purchase of common shares under Normal Course Issuer Bid
Balance – end of year
Retained earnings
Balance – beginning of year
Net earnings (loss)
Dividends on common shares
Purchase of common shares under Normal Course Issuer Bid
Balance – end of year
Accumulated other comprehensive income (loss)
Balance – beginning of year
Other comprehensive income (loss), net of taxes
Balance – end of year
Shareholders’ equity
Note
14
14
14
15
2022
2021
2020
$
10,168 $
9,606 $
442
387
(703)
10,294
26,778
10,937
(5,175)
(4,868)
27,672
(1)
210
209
707
139
(284)
10,168
22,766
7,664
(2,355)
(1,297)
26,778
8
(9)
(1)
9,533
108
21
(56)
9,606
25,424
(435)
(2,008)
(215)
22,766
34
(26)
8
$
38,175 $
36,945 $
32,380
Canadian Natural 2022 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
Note
2022
2021
2020
$
10,937 $
7,664 $
(435)
Depletion, depreciation and amortization
7
Share-based compensation
Asset retirement obligation accretion
Unrealized risk management (gain) loss
Unrealized foreign exchange loss (gain)
Gain on acquisitions
(Gain) loss from investments
Deferred income tax (recovery) expense
Realized foreign exchange (gain) loss (1)
Proceeds on settlement of cross currency swap
Other
Abandonment expenditures
Net change in non-cash working capital
Cash flows from operating activities
Financing activities
(Repayment) issue of bank credit facilities and commercial
paper, net
Repayment of medium-term notes
(Repayment) issue 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
12
21
11,21
11,21
11,21
7
8
14
Purchase of common shares under Normal Course Issuer Bid
14
7,353
804
281
(28)
852
—
(182)
(139)
(62)
89
(144)
(449)
79
19,391
(1,156)
(1,498)
(1,356)
—
69
(232)
442
(4,926)
(5,571)
Cash flows used in financing activities
Investing activities
Net expenditures on exploration and evaluation assets
Net expenditures on property, plant and equipment
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 paid (received)
(14,228)
(10,215)
(33)
(5,103)
(1)
(4,492)
—
—
149
128
555
107
(4,987)
(3,703)
176
744
920 $
613 $
3,057 $
560
184
744 $
672 $
(62) $
6,22
7,22
9
10
21
$
$
$
(1) Consists of the realized foreign exchange gain on settlement of cross currency swaps in 2022 and 2020, and the realized foreign exchange loss on repayment
of US dollar debt securities in 2022 and 2021.
65
Canadian Natural 2022 Annual Report
5,724
514
185
19
(205)
(478)
(132)
399
118
—
13
(307)
964
6,046
(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)
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)
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 2022 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 2022 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 a recoverability charge is taken 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 recoverability charges 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 recoverability charge been recognized for the asset in prior periods. A reversal of a
recoverability charge is recognized in net earnings. After a reversal, the depletion, depreciation and amortization charge is
adjusted in future periods to allocate the asset’s revised carrying amount over its remaining useful life.
(G) BUSINESS COMBINATIONS
Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed in a business
combination are recognized at their fair value at the date of the acquisition. Any excess of the consideration paid over the fair
value of the net assets acquired is recognized as an asset. Any excess of the fair value of the net assets acquired over the
consideration paid is recognized in net earnings.
(H) OVERBURDEN REMOVAL COSTS
Overburden removal costs incurred during the initial development of a mine at Horizon and AOSP are capitalized to property,
plant and equipment. Overburden removal costs incurred during the production of a mine are included in the cost of inventory,
unless the overburden removal activity has resulted in a probable inflow of future economic benefits to the Company, in which
case the costs are capitalized to property, plant and equipment. Capitalized overburden removal costs are depleted over the life
of the mining reserves that directly benefit from the overburden removal activity.
(I) CAPITALIZED BORROWING COSTS
Borrowing costs attributable to the acquisition, construction or production of qualifying assets are capitalized to the cost of
those assets until such time as the assets are substantially available for their intended use. Qualifying assets are comprised of
those significant assets that require a period greater than one year to be available for their intended use. All other borrowing
costs are recognized in net earnings.
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68
(J) LEASES
At inception of a contract, the Company assesses whether a contract is, or contains a lease. A contract is, or contains a lease if
the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To
assess whether a contract conveys the right to control the use of an identified asset, the Company assesses whether: the
contract involves the use of an identified asset; the Company has the right to obtain substantially all of the economic benefits
from the use of the asset throughout the period of use; and, the Company has the right to direct the use of the asset.
The Company recognizes a lease asset and a lease liability at the commencement date of the lease contract, which is the date
that the lease asset is available to the Company. The lease asset is initially measured at cost. The cost of a lease asset includes
the amount of the initial measurement of the lease liability, lease payments made prior to the commencement date, initial direct
costs and estimates of the asset retirement obligation, if any. Subsequent to initial recognition, the lease asset is depreciated
using the straight-line method over the earlier of the end of the useful life of the lease asset or the lease term.
Lease liabilities are initially measured at the present value of lease payments discounted at the rate implicit in the lease, or if not
readily determinable, the Company's incremental borrowing rate. Lease payments include fixed lease payments, variable lease
payments based on indices or rates, residual value guarantees, and purchase options expected to be exercised. Subsequent to
initial recognition, the lease liability is measured at amortized cost using the effective interest method. Lease liabilities are
remeasured if there are changes in the lease term or if the Company changes its assessment of whether it is reasonably certain
it will exercise a purchase, extension or termination option. Lease liabilities are also remeasured if there are changes in the
estimate of the amounts payable under the lease due to changes in indices or rates, or residual value guarantees.
Lease assets are reported in a separate caption in the consolidated balance sheet. Lease liabilities are reported within other
long-term liabilities in the consolidated balance sheet.
Depreciation on lease assets used in the construction of property, plant and equipment is capitalized to the cost of those assets
over their period of use until such time as the property, plant and equipment is substantially available for its intended use.
Where the Company acts as the operator of a joint operation, the Company recognizes 100% of the related lease asset and
lease liability. As the Company recovers its joint operation partners' share of the costs of the lease contract, these recoveries
are recognized as other income in the consolidated statements of earnings.
(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.
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Canadian Natural 2022 Annual Report
(M) REVENUE RECOGNITION AND COSTS OF GOODS SOLD
Revenue from the sale of crude oil and NGLs and natural gas products is recognized when performance obligations in the sales
contract are satisfied and it is probable that the Company will collect the consideration to which it is entitled. Performance
obligations are generally satisfied at the point in time when the product is delivered to a location specified in a contract and
control passes to the customer. The Company assesses customer creditworthiness, both before entering into contracts and
throughout the revenue recognition process.
Contracts for sale of the Company’s products generally have terms of less than a year, with certain contracts extending beyond
one year. Contracts in North America generally specify delivery of crude oil and NGLs and natural gas throughout the term of
the contract. Contracts in the North Sea and Offshore Africa generally specify delivery of crude oil at a point in time.
Sales of the Company’s crude oil and NGLs and natural gas products to customers are made pursuant to contracts based on
prevailing commodity pricing at or near the time of delivery and volumes of product delivered. Revenues are typically collected
in the month following delivery and accordingly, the Company has elected to apply the practical expedient to not adjust
consideration for the effects of a financing component. Purchases and sales of crude oil and NGLs and natural gas with the
same counterparty, made to facilitate sales to customers or potential customers, that are entered into in contemplation of one
another, are combined and recorded as non-monetary exchanges and measured at the net settlement amount.
Revenue in the consolidated statement of earnings represents the Company’s share of product sales net of royalty payments to
governments and other mineral interest owners. The Company discloses the disaggregation of revenues from sales of crude oil
and NGLs and natural gas in the segmented information in note 22. Related costs of goods sold are comprised of production,
transportation, blending and feedstock, and depletion, depreciation and amortization expenses. These amounts have been
separately presented in the consolidated statements of earnings.
(N) PRODUCTION SHARING CONTRACTS
Production generated from Côte d’Ivoire 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.
Canadian Natural 2022 Annual Report
70
(P) SHARE-BASED COMPENSATION
The Company’s Stock Option Plan (the "Option Plan") provides current employees with the right to elect to receive common
shares or a cash payment in exchange for stock options surrendered. The liability for awards granted to employees is initially
measured based on the grant date fair value of the awards and the number of awards expected to vest. The awards are
remeasured each reporting period for subsequent changes in the fair value of the liability. Fair value is determined using the
Black-Scholes valuation model under a graded vesting method. Expected volatility is estimated based on historic results. When
stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are
exercised for common shares under the Option Plan, consideration paid by the employee and any previously recognized liability
associated with the stock options are recorded as share capital.
The Performance Share Unit ("PSU") plan provides certain executive employees of the Company with the right to receive a cash
payment, the amount of which is determined by individual employee performance and the extent to which certain other
performance measures are met. PSUs vest three years from original grant date. The liability for PSUs is initially measured in
reference to the Company's stock price and the number of awards expected to vest and is remeasured at each reporting period
for changes in the fair value of the liability.
The unamortized costs of employer contributions to the Company’s share bonus program are included in other long-term
assets.
(Q) FINANCIAL INSTRUMENTS
The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost; financial
liabilities at amortized cost; and fair value through profit or loss. All financial instruments are measured at fair value on initial
recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.
Fair value through profit or loss financial instruments are subsequently measured at fair value with changes in fair value
recognized in net earnings. All other categories of financial instruments are measured at amortized cost using the effective
interest method.
Cash and cash equivalents, accounts receivable and certain other long-term assets are classified as financial assets at amortized
cost since it is the Company’s intention to hold these assets to maturity and the related cash flows are solely comprised of
payments of principal and interest. Investments in publicly traded shares are classified as fair value through profit or loss.
Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as financial liabilities at
amortized cost. Risk management assets and liabilities are classified as fair value through profit or loss.
Financial assets and liabilities are also categorized using a three-level hierarchy that reflects the significance of the inputs used
in making fair value measurements for these assets and liabilities. The fair values of financial assets and liabilities included in
Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair values of financial
assets and liabilities in Level 2 are based on inputs other than Level 1 quoted prices that are observable for the asset or liability
either directly (as prices) or indirectly (derived from prices). The fair values of Level 3 financial assets and liabilities are not based
on observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value
approximates fair value due to the liquid nature of the asset or liability.
Transaction costs in respect of financial instruments at fair value through profit or loss are recognized in net earnings.
Transaction costs in respect of other financial instruments are included in the initial measurement of the financial instrument.
Impairment of financial assets
At each reporting date, on a forward looking basis, the Company assesses the expected credit losses associated with its
financial assets carried at amortized cost. Expected credit losses are measured as the difference between the cash flows that
are due to the Company and the cash flows that the Company expects to receive, discounted at the effective interest rate
determined at initial recognition. For trade accounts receivable, the Company applies the simplified approach permitted by IFRS
9, which requires expected lifetime credit losses to be recognized from initial recognition of the receivables. To measure
expected credit losses, accounts receivable are grouped based on the number of days the receivables have been outstanding
and internal credit assessments of the customers. Credit risk for longer-term receivables is assessed based on an external
credit rating of the counterparty. For longer-term receivables with credit risk that has not increased significantly since the date
of recognition, the Company measures the expected credit loss as the 12-month expected credit loss. Changes in the provision
for expected credit loss are recognized in net earnings.
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Canadian Natural 2022 Annual Report
(R) RISK MANAGEMENT ACTIVITIES
The Company periodically uses derivative financial instruments to manage its commodity price, foreign currency and interest
rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative
purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The
estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions, the
Company primarily relied on external, readily-observable market inputs including quoted commodity prices and volatility, interest
rate yield curves, and foreign exchange rates. The carrying amount of a risk management liability is adjusted for the Company’s
own credit risk.
The Company documents all derivative financial instruments that are formally designated as hedging transactions at the
inception of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the
hedging relationship is evaluated, both at inception of the hedge and on an ongoing basis.
The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil and
natural gas in order to protect its cash flow for its capital expenditure programs. The effective portion of changes in the fair
value of derivative commodity price contracts formally designated as cash flow hedges is initially recognized in other
comprehensive income and is reclassified to risk management activities in net earnings in the same period or periods in which
the commodity is sold or purchased. The ineffective portion of changes in the fair value of these designated contracts is
recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural
gas commodity price contracts are recognized in risk management activities in net earnings.
The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on certain
long-term debt instruments. The interest rate swap contracts require the periodic exchange of payments without the exchange
of the notional principal amounts on which the payments are based. Changes in the fair value of interest rate swap contracts
designated as fair value hedges and corresponding changes in the fair value of the hedged long-term debt are recognized in
interest expense in net earnings. Changes in the fair value of non-designated interest rate swap contracts are recognized in risk
management activities in net earnings.
Upon termination of an interest rate swap designated as a fair value hedge, the interest rate swap is derecognized in the
consolidated balance sheets and the related long-term debt hedged is no longer revalued for subsequent changes in fair value
due to interest rates changes. The fair value adjustment due to interest rates on the long-term debt at the date of termination of
the interest rate swap is amortized to interest expense over the remaining term of the long-term debt.
Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt.
The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional
principal amounts on which the payments are based. Changes in the fair value of the foreign exchange component of cross
currency swap contracts designated as cash flow hedges related to the notional principal amounts are recognized in foreign
exchange gains and losses in net earnings. The effective portion of changes in the fair value of the interest rate component of
cross currency swap contracts designated as cash flow hedges is initially recognized in other comprehensive income and is
reclassified to interest expense when the hedged item is recognized in net earnings, with the ineffective portion recognized in
risk management activities in net earnings. Changes in the fair value of non-designated cross currency swap contracts are
recognized in risk management activities in net earnings.
Realized gains or losses on the termination of financial instruments that have been designated as cash flow hedges are
deferred under accumulated other comprehensive income and amortized into net earnings in the periods in which the
underlying hedged items are recognized. In the event a designated hedged item is sold, extinguished or matures prior to the
termination of the related derivative instrument, any unrealized derivative gain or loss is recognized in net earnings. Realized
gains or losses on the termination of financial instruments that have not been designated as hedges are recognized in net
earnings.
Foreign currency forward contracts are periodically used to manage foreign currency cash requirements. The foreign currency
forward contracts involve the purchase or sale of an agreed upon amount of US dollars at a specified future date at forward
exchange rates. Changes in the fair value of foreign currency forward contracts designated as cash flow hedges are initially
recorded in other comprehensive income and are reclassified to foreign exchange gains and losses when the hedged item is
recognized in net earnings. Changes in the fair value of non-designated foreign currency forward contracts are recognized in risk
management activities in net earnings.
Embedded derivatives are derivatives that are included in a non-derivative host contract. Embedded derivatives are recorded at
fair value separately from the host contract when their economic characteristics and risks are not clearly and closely related to
the host contract, except when the host contract is an asset.
Canadian Natural 2022 Annual Report
72
(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 (loss) 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 (loss) per common share by dividing net earnings (loss) 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.
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Canadian Natural 2022 Annual Report
2. Changes in Accounting Policies
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.
3. Accounting Standards Issued But Not Yet Applied
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 will be adopted January 1,
2023 and the Company is assessing the impact on the Company's 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 will be adopted January 1, 2023 and the Company is
assessing the 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. In October 2022, the IASB
issued further amendments to specify that the classification of debt as current or non-current at the reporting date is not
affected by covenants to be complied with after the reporting date, and added disclosure requirements about these covenants.
All amendments are effective January 1, 2024 with early adoption permitted. The amendments are required to be adopted
retrospectively. The Company is assessing the impact of all 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
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.
Canadian Natural 2022 Annual Report
74
(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, 2022, COVID-19 continued to have an impact on the global economy, including the oil and
gas industry. Business conditions in 2022 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.
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Canadian Natural 2022 Annual Report
5. Inventory
Product inventory
Materials, supplies and other
$
$
2022
611 $
1,204
1,815 $
2021
535
1,013
1,548
During 2022, approximately $33 billion of purchased and produced inventory was recorded as expense (2021 - approximately
$22 billion).
6. Exploration and Evaluation Assets
Exploration and Production
North
America
North Sea
Offshore
Africa
Oil Sands
Mining and
Upgrading
Total
Cost
At December 31, 2020
$
2,101 $
— $
83 $
252 $
2,436
Additions/Acquisitions (note 7)
Transfers to property, plant and equipment
Derecognitions and other
At December 31, 2021
Additions/Acquisitions
Transfers to property, plant and equipment
Derecognitions and other
Foreign exchange adjustments
30
(73)
(1)
2,057
41
(71)
(1)
—
—
—
—
—
—
—
—
—
8
—
—
91
5
—
—
2
—
(150)
—
102
—
—
—
—
38
(223)
(1)
2,250
46
(71)
(1)
2
At December 31, 2022
$
2,026 $
— $
98 $
102 $
2,226
Canadian Natural 2022 Annual Report
76
7. Property, Plant and Equipment
Exploration and Production
Oil Sands
Mining and
Upgrading
Midstream
and
Refining
Head
Office
Total
North
America
North Sea
Offshore
Africa
Cost
At December 31, 2020
$
73,997 $
7,283 $
3,963 $
45,710 $
457 $
485 $
131,895
Additions/Acquisitions
4,146
208
48
1,526
Transfers from exploration
and evaluation assets
Derecognitions (1)
Foreign exchange
73
(382)
—
3
—
—
150
(530)
adjustments and other
—
(56)
(31)
—
At December 31, 2021
77,834
7,438
3,980
46,856
Additions/Acquisitions
3,564
304
75
1,380
Transfers from exploration
and evaluation assets
Derecognitions (1)
Disposals
Foreign exchange
71
(394)
—
—
(1)
—
—
—
—
—
(469)
(35)
adjustments and other
—
517
277
—
At December 31, 2022
$
81,075 $
8,258 $
4,332 $
47,732 $
9
—
—
—
466
8
—
—
—
—
474 $
23
5,960
—
—
—
223
(909)
(87)
508
137,082
25
5,356
—
—
—
3
71
(864)
(35)
797
536 $
142,407
Accumulated depletion and depreciation
At December 31, 2020
$
49,641 $
5,853 $
2,822 $
7,289 $
168 $
370 $
66,143
Expense
Derecognitions (1)
Foreign exchange
3,468
(382)
149
3
118
—
adjustments and other
5
(54)
(17)
At December 31, 2021
52,732
5,951
2,923
Expense
Derecognitions (1)
Disposals
Recoverability charge
Foreign exchange
adjustments and other
3,502
(394)
—
—
(5)
117
(1)
—
1,620
148
—
—
—
419
206
1,733
(530)
7
8,499
1,684
(469)
(2)
—
—
At December 31, 2022
$
55,835 $
8,106 $
3,277 $
9,712 $
15
—
—
183
15
—
—
—
25
—
(1)
5,508
(909)
(60)
394
70,682
23
—
—
—
5,489
(864)
(2)
1,620
—
198 $
3
623
420 $
77,548
Net book value
At December 31, 2022
At December 31, 2021
$
$
25,240 $
152 $
1,055 $
38,020 $
25,102 $
1,487 $
1,057 $
38,357 $
276 $
283 $
116 $
64,859
114 $
66,400
(1) An asset is derecognized when no future economic benefits are expected to arise from its continued use or disposal.
Prevailing regulatory and economic conditions in 2022 and the increasingly challenging commercial outlook in the United
Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea
operations. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer
economic, de-booked associated crude oil reserves as at December 31, 2022, and is accelerating abandonment.
77
Canadian Natural 2022 Annual Report
As a result, the Company completed a recoverability assessment of its assets in the North Sea, and recognized a non-cash
charge of $651 million (after-tax) related to the Ninian field property, plant and equipment, comprised of a recoverability charge
of $1,620 million recognized in depletion, depreciation and amortization, net of deferred tax recoveries of $969 million.
As at December 31, 2022, the Company completed its normal course assessment of the recoverability of its other property,
plant and equipment and exploration and evaluation assets, and determined the carrying amounts of all 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 2022, no interest was capitalized to property, plant and equipment (2021 – $nil; 2020 – $24 million at a weighted average
capitalization rate of 3.5%).
As at December 31, 2022, property, plant and equipment included project costs, not subject to depletion and depreciation, of
$162 million in the Oil Sands Mining and Upgrading segment (2021 – $118 million in the Oil Sands Mining and Upgrading
segment).
Acquisitions in the current and comparative years have been accounted for as business combinations using the acquisition
method of accounting. Gains reported on the acquisitions represent the excess of the fair value of the net assets acquired
compared to the total purchase consideration.
ACQUISITIONS IN 2022
During 2022, the Company acquired a number of crude oil and natural gas properties in the North America Exploration and
Production segment for net cash consideration of $513 million and assumed associated asset retirement obligations of $11
million. No net deferred income tax liabilities were recognized and no pre-tax gains were recognized on these transactions.
ACQUISITIONS IN 2021
Acquisition of Storm Resources Ltd. ("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. 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).
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.
ACQUISITION IN 2020
Acquisition of Painted Pony Energy Ltd. ("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 gain on acquisition:
Net assets acquired
Less: cash consideration
Gain on acquisition
$
$
328
111
217
In connection with the acquisition the Company assumed certain product transportation and processing commitments
(note 20).
Canadian Natural 2022 Annual Report
78
8. Leases
LEASE ASSETS
At December 31, 2020
$
1,038 $
379 $
128 $
100 $
Product
transportation
and storage
Field
equipment
and power
Offshore
vessels
and equipment
Office leases
and other
Additions
Depreciation
Foreign exchange and other
At December 31, 2021
Additions
Depreciation
Foreign exchange and other
At December 31, 2022
$
LEASE ASSETS, BY SEGMENT
48
(110)
(2)
974
44
(106)
—
912 $
36
(57)
(4)
354
110
(86)
(1)
377 $
—
(27)
(2)
99
28
(31)
1
97 $
4
(22)
(1)
81
—
(21)
1
61 $
As at December 31, 2022 and 2021, the Company had the following lease assets by segment:
Total
1,645
88
(216)
(9)
1,508
182
(244)
1
1,447
Exploration and Production
North America
North Sea
Offshore Africa
Oil Sands Mining and Upgrading
Head Office
LEASE LIABILITIES
2022
2021
$
277 $
1
98
1,015
56
$
1,447 $
308
1
101
1,027
71
1,508
The Company measures its lease liabilities at the discounted value of its lease payments during the lease term. Lease liabilities
at December 31, 2022 and 2021, were as follows:
Lease liabilities
Less: current portion
2022
1,540 $
244
1,296 $
2021
1,584
185
1,399
$
$
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 2022 and 2021 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)
2022
410 $
60 $
49 $
2021
450
62
65
1,204 $
1,089
$
$
$
$
(1) During 2022, the Company capitalized $453 million (2021 - $303 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 2022 Annual Report
9. Investments
As at December 31, 2022 and 2021, the Company had the following investment:
Investment in PrairieSky Royalty Ltd.
INVESTMENT IN PRAIRIESKY ROYALTY LTD.
$
2022
491 $
2021
309
The Company’s 22.6 million common shares investment in 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, 2022
the market price per common share was $21.70 (December 31, 2021 – $13.63; December 31, 2020 – $10.09).
As at December 31, 2022, 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
$
$
2022
(182) $
(14)
(196) $
2021
(81) $
(7)
(88) $
2020
117
(9)
108
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 shares 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 (gain) loss from the investment in Inter Pipeline was comprised as follows:
2022
2021
2020
(Gain) loss from investment
Dividend income
10. Other Long-Term Assets
Prepaid cost of service toll
Long-term inventory
Risk management (note 19)
Long-term contracts, prepayments and other (1)
Less: current portion
$
$
— $
—
— $
(51) $
(2)
(53) $
$
$
2022
199 $
137
9
269
614
61
553 $
68
(5)
63
2021
157
126
140
177
600
35
565
(1)
Includes physical product sales contracts assumed in the acquisition of Painted Pony in the fourth quarter of 2020, accrued interest on the deferred PRT
recovery, and the unamortized portion of the Company's share bonus program.
INVESTMENT IN NORTH WEST REDWATER PARTNERSHIP
The Company has a 50% equity investment in North West Redwater Partnership ("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 until 2058 (note 20).
Sales of diesel and refined products and associated refining tolls are recognized in the Midstream and Refining segment
(note 22).
Canadian Natural 2022 Annual Report
80
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.
During 2022, NWRP extended and increased its $3,000 million syndicated credit facility to $3,175 million. The revolving portion
of the credit facility was increased to $2,175 million, with $118 million maturing in June 2023, and $2,057 million maturing in
June 2025. The $1,000 million non-revolving portion of the credit facility was extended, with $60 million maturing in June 2023,
and $940 million maturing in June 2025. During 2022, NWRP also entered into a $150 million facility to support letters of credit.
As at December 31, 2022, NWRP had borrowings of $2,318 million under the syndicated credit facility (December 31, 2021 –
$1,981 million).
The assets, liabilities, partners’ equity, product sales and equity income (loss) related to NWRP at December 31, 2022 and 2021
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 income (loss) (3)
2022
257 $
10,729 $
849 $
11,239 $
(1,102) $
(551) $
1,267 $
22 $
2021
280
10,806
798
11,412
(1,124)
(562)
1,168
(18)
$
$
$
$
$
$
$
$
(1)
(2)
(3)
In 2021, NWRP paid partnership distributions at 100% interest of $800 million.
Included in NWRP's revenue for 2022 is $317 million (2021 – $294 million) related to the Company's 25% share of the refining toll.
Included in the net income (loss) for 2022 is the impact of depreciation and amortization expense of $245 million (2021 – $278 million) and interest and other
financing expense of $422 million (2021 – $412 million).
The carrying value of the Company’s interest in NWRP is $nil, and as at December 31, 2022, the cumulative unrecognized share
of the equity loss and partnership distributions from NWRP was $551 million (2021 – $562 million). The Company's recovery of
the unrecognized share of the equity loss from NWRP for 2022 was $11 million (2021 – unrecognized equity loss of $9 million
and partnership distributions were $400 million; 2020 – unrecognized equity loss of $94 million).
81
Canadian Natural 2022 Annual Report
11. Long-Term Debt
Canadian dollar denominated debt, unsecured
Medium-term notes
3.31% debentures due February 11, 2022
1.45% debentures due November 16, 2023
3.55% debentures due June 3, 2024
3.42% debentures due December 1, 2026
2.50% debentures due January 17, 2028
4.85% debentures due May 30, 2047
US dollar denominated debt, unsecured
Bank credit facilities (December 31, 2022 – US$nil;
December 31, 2021 – US$901 million)
US dollar debt securities
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 other long-term debt (1) (2)
2022
2021
$
— $
1,000
404
332
441
225
300
500
500
600
300
300
1,702
3,200
—
—
677
812
812
1,692
677
541
474
474
609
1,488
541
1,015
9,812
11,514
13
56
11,445
404
$
11,041 $
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
13,694
(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.
Canadian Natural 2022 Annual Report
82
BANK CREDIT FACILITIES AND COMMERCIAL PAPER
As at December 31, 2022, the Company had undrawn bank credit facilities of $5,520 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 $500 million revolving credit facility maturing February 2024;
a $2,425 million revolving syndicated credit facility maturing June 2024; and
a $2,495 million revolving syndicated credit facility, with $70 million maturing June 2023, and $2,425 million maturing June
2025.
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 2022, the Company repaid and cancelled the $1,150 million non-
revolving term credit facility maturing February 2023.
During 2022, the Company discontinued its £5 million demand credit facility related to its North Sea operations.
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 mature upon
the original maturity date of June 2022 and June 2023, respectively.
Borrowings under the Company's non-revolving and 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 repaid and amended its $1,000 million non-revolving term credit facility to allow for a re-draw of the
full $1,000 million until March 31, 2022. During 2022, the Company repaid and cancelled $500 million of the non-revolving
portion of the term credit facility, amended the remaining facility to a $500 million revolving credit facility and extended maturity
from February 2023 to February 2024.
During 2021, the Company repaid and cancelled the remaining $3,088 million of its $3,250 million non-revolving term credit
facility with an original maturity of June 2022 used to finance the Company's acquisition of assets from Devon in 2019.
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,
2022 was 4.3% (December 31, 2021 – 0.8%), and on total long-term debt outstanding for the year ended December 31, 2022
was 4.3% (December 31, 2021 – 3.5%).
As at December 31, 2022, letters of credit and guarantees aggregating to $637 million were outstanding (December 31, 2021 –
$513 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 2022, the Company repaid $1,000 million of 3.31% medium-term notes.
During 2022, the Company repaid through market purchases $95 million of 1.45% medium-term notes due November 2023,
$169 million of 3.55% medium-term notes due June 2024, $159 million of 3.42% medium-term notes due December 2026, and
$75 million of 2.50% medium-term notes due January 2028.
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 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023.
During 2021, the Company repaid US$500 million of 3.45% debt securities.
83
Canadian Natural 2022 Annual Report
SCHEDULED DEBT REPAYMENTS
Scheduled debt repayments are as follows:
Year
2023
2024
2025
2026
2027
Thereafter
12. Other Long-Term Liabilities
Asset retirement obligations
Lease liabilities (note 8)
Share-based compensation
Transportation and processing contracts (1)
Risk management (note 19)
Other
Less: current portion
$
$
$
$
$
$
2022
$
6,908 $
1,540
832
159
3
92
9,534
1,373
$
8,161 $
Repayment
404
1,009
1,624
441
1,692
6,344
2021
6,806
1,584
489
241
85
127
9,332
948
8,384
(1) The acquisition of Painted Pony in 2020 included product transportation and processing obligations (note 7).
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 5.6% (2021 – 4.0%; 2020 – 3.7%) and inflation rates of up to
2% (December 31, 2021 – up to 2%). Reconciliations of the discounted asset retirement obligations were as follows:
Balance – beginning of year
Liabilities incurred
Liabilities acquired, net
Liabilities settled
Asset retirement obligation accretion
Revision of cost, inflation and timing estimates (1)
Impact of regulatory changes (2)
Change in discount rates
Foreign exchange adjustments
Balance – end of year
Less: current portion
2022
2021
$
6,806 $
5,861 $
20
11
5
76
(449)
(307)
281
897
982
(1,698)
58
6,908
495
185
508
1,208
(723)
(7)
6,806
249
$
6,413 $
6,557 $
2020
5,771
5
13
(249)
205
(134)
—
253
(3)
5,861
184
5,677
(1)
Includes normal course revisions of cost, inflation and timing estimates, as well as revisions related to the acceleration of the abandonment of Ninian field
assets in the North Sea at December 31, 2022.
(2) Reflects changes to the estimated timing of settlement of the Company's asset retirement obligations due to provincial regulatory changes in Alberta, British
Columbia and Saskatchewan.
Canadian Natural 2022 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
2022
2021
$
4,326 $
1,011
143
1,427
1
$
6,908 $
4,021
821
170
1,793
1
6,806
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
2022
489 $
804
(79)
(387)
5
832
559
2021
160 $
514
(48)
(139)
2
489
329
$
273 $
160 $
2020
297
(82)
(39)
(21)
5
160
119
41
Included within share-based compensation liability as at December 31, 2022 was $127 million (2021 – $90 million; 2020 –
$49 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.
$
$
2022
32.96 $
75.19 $
35.8%
4.5%
3.8%
5.0%
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%
4.2 years
4.2 years
4.3 years
The intrinsic value of vested stock options at December 31, 2022 was $208 million (2021 – $112 million; 2020 – $11 million).
85
Canadian Natural 2022 Annual Report
13. Income Taxes
The provision for income tax was as follows:
Expense (recovery)
2022
2021
Current corporate income tax – North America
$
2,789 $
1,841 $
Current corporate income tax – North Sea
Current corporate income tax – Offshore Africa
Current PRT (1) – North Sea
Other taxes
Current income tax
Deferred corporate income tax
Deferred PRT (1) – North Sea
Deferred income tax
Income tax
(1) Petroleum Revenue Tax.
69
74
(42)
16
2,906
302
(441)
(139)
7
21
(34)
13
1,848
399
—
399
$
2,767 $
2,247 $
2020
(245)
(4)
17
(31)
6
(257)
(181)
—
(181)
(438)
In connection with the Company's de-booking of its crude oil reserves and acceleration of the abandonment at the Ninian field
in the North Sea (note 7), as at December 31, 2022, the Company recognized deferred tax recoveries comprised of a deferred
corporate income tax recovery of $528 million and a deferred PRT recovery of $441 million.
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 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
Non-taxable gain on corporate acquisitions
Revisions arising from prior year tax filings
Change in unrecognized capital loss carryforward asset
Other
Income tax
2022
23.2%
2021
23.2%
$
3,180 $
2,298 $
2020
24.1%
(211)
(467)
190
(203)
65
159
—
(186)
65
(36)
(21)
11
(11)
(26)
98
(110)
16
(26)
18
(25)
11
(52)
(10)
(25)
(52)
(62)
(10)
(2)
$
2,767 $
2,247 $
(438)
Canadian Natural 2022 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
$
11,985 $
12,254
2022
2021
Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows:
Lease assets
Investments
Investment in North West Redwater Partnership
Unrealized risk management activities
Unrealized foreign exchange gain on long-term debt
Taxable PRT for corporate income tax
Other
Deferred income tax assets
Asset retirement obligations
Lease liabilities
Share-based compensation
Loss carryforwards
Unrealized foreign exchange loss on long-term debt
Deferred PRT
Net deferred income tax liability
$
Property, plant and equipment and exploration and evaluation assets
$
(334) $
2022
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
Taxable PRT for corporate income tax
Other
(15)
(81)
(12)
(74)
11
(11)
618
21
53
(441)
176
(50)
(139) $
$
336
56
903
—
—
176
25
349
35
850
12
14
—
78
13,481
13,592
(1,822)
(354)
(33)
(652)
(67)
(439)
(3,367)
10,114 $
2021
184 $
(30)
34
19
(213)
25
(10)
202
21
83
—
—
84
(1,719)
(363)
(22)
(1,268)
—
—
(3,372)
10,220
2020
(158)
(11)
29
(8)
(13)
6
4
(182)
(22)
174
—
—
—
399 $
(181)
The following table summarizes the movements of the net deferred income tax liability during the year:
Balance – beginning of year
Deferred income tax (recovery) expense
Deferred income tax expense included in other comprehensive
income (loss)
Foreign exchange adjustments
Business combinations (note 7)
Balance – end of year
2022
2021
$
10,220 $
10,144 $
(139)
399
—
33
—
1
(2)
(322)
$
10,114 $
10,220 $
2020
10,539
(181)
—
(3)
(211)
10,144
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 2022 Annual Report
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. Deferred PRT assets will be recovered from the UK Government, directly or through
other third parties, as related abandonment expenditures are made. 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 $1,000 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
2022
Number
of shares
(thousands)
Amount
2021
Number
of shares
(thousands)
1,168,369 $
10,168
1,183,866 $
11,605
—
442
387
18,147
—
139
(77,338)
(703)
(33,644)
(284)
1,102,636 $
10,294
1,168,369 $
10,168
Amount
9,606
707
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 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share,
beginning with the dividend payable on April 5, 2023.
On November 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share,
beginning with the dividend paid on January 5, 2023.
On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share, paid on August 31, 2022.
On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.75 per common share. On
November 3, 2021, the Board of Directors approved a 25% increase in the quarterly dividend to $0.5875 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.
Canadian Natural 2022 Annual Report
88
NORMAL COURSE ISSUER BID
On March 8, 2022, the Company's application was approved for a Normal Course Issuer Bid ("NCIB") to purchase through the
facilities of the Toronto Stock Exchange ("TSX"), alternative Canadian trading platforms, and the New York Stock Exchange
("NYSE"), up to 101,574,207 common shares, over a 12-month period commencing March 11, 2022 and ending March 10, 2023.
For the year ended December 31, 2022, the Company purchased 77,338,200 common shares at a weighted average price of
$72.03 per common share for a total cost of $5,571 million. Retained earnings were reduced by $4,868 million, representing the
excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2022, up to
and including February 28, 2023, the Company purchased 6,000,000 common shares at a weighted average price of $77.72 per
common share for a total cost of $466 million.
On March 1, 2023, 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, 2022 and 2021:
Outstanding – beginning of year
Granted
Exercised for common shares
Surrendered for cash settlement
Forfeited
Outstanding – end of year
Exercisable – end of year
2022
2021
Stock options
(thousands)
Weighted
average
exercise price
Stock options
(thousands)
Weighted
average
exercise price
38,327 $
7,547 $
(11,605) $
(441) $
(2,678) $
31,150 $
5,522 $
35.88
68.15
38.06
38.43
41.43
42.37
37.60
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
The range of exercise prices of stock options outstanding and exercisable at December 31, 2022 was as follows:
Range of exercise prices
$20.76
$30.00
$40.00
$50.00
$60.00
$70.00
–
–
–
–
–
–
$29.99
$39.99
$49.99
$59.99
$69.99
$79.71
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
7,821
11,266
4,503
555
4,718
2,287
31,150
2.98 $
1.84 $
2.62 $
4.86 $
4.49 $
4.88 $
2.92 $
27.14
36.60
41.50
54.24
64.84
75.40
42.37
982 $
2,672 $
1,682 $
1 $
1 $
184 $
5,522 $
24.07
36.83
42.73
54.24
64.15
73.83
37.60
89
Canadian Natural 2022 Annual Report
15. Accumulated Other Comprehensive Income (Loss)
The components of accumulated other comprehensive income (loss), net of taxes, were as follows:
Derivative financial instruments designated as cash flow hedges
Foreign currency translation adjustment
$
$
2022
75 $
134
209 $
2021
77
(78)
(1)
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 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, 2022, the ratio was below the target range at 22%.
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
$
$
$
2022
11,445 $
920
10,525 $
38,175 $
22%
2021
14,694
744
13,950
36,945
27%
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, 2022, the Company was in compliance with this covenant.
17. Net Earnings Per Common Share
Weighted average common shares outstanding
– basic (thousands of shares)
2022
2021
2020
1,134,960
1,181,250
1,181,768
Effect of dilutive stock options (thousands of shares)
14,222
5,307
—
Weighted average common shares outstanding
– diluted (thousands of shares)
Net earnings (loss)
Net earnings (loss) per common share
– basic
– diluted
1,149,182
1,186,557
1,181,768
$
$
$
10,937 $
7,664 $
9.64 $
9.52 $
6.49 $
6.46 $
(435)
(0.37)
(0.37)
In 2022, the Company excluded 2,039,000 potentially anti-dilutive stock options from the calculation of diluted earnings per
common share (2021 – 3,496,000; 2020 – 44,117,000).
Canadian Natural 2022 Annual Report
90
18. Interest and Other Financing Expense
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
Net interest and other financing expense
19. Financial Instruments
2022
2021
2020
$
610 $
681 $
60
—
670
(121)
549 $
62
—
743
(32)
711 $
$
785
67
(24)
828
(72)
756
The carrying amounts of the Company’s financial instruments by category were as follows:
Asset (liability)
2022
Financial
assets at
amortized cost
Fair value
through
profit or loss
Derivatives
used for
hedging
Financial
liabilities at
amortized
cost
Cash and cash equivalents
$
920 $
— $
— $
— $
Accounts receivable
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
Long-term debt (2)
3,555
—
—
—
—
—
—
—
491
9
—
—
(3)
—
—
—
—
—
—
—
—
—
—
—
(1,341)
(4,209)
(1,540)
(11,445)
$
4,475 $
497 $
— $
(18,535) $
2021
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
$
744 $
— $
— $
— $
—
309
—
—
—
(64)
—
245 $
—
—
140
—
—
(21)
—
—
—
—
(803)
(3,064)
(1,632)
(14,694)
119 $
(20,193) $
Accounts receivable
Investments
Other long-term assets
Accounts payable
Accrued liabilities
Other long-term liabilities (1)
Long-term debt (2)
3,111
—
—
—
—
—
—
$
3,855 $
Includes $1,540 million of lease liabilities (December 31, 2021 – $1,584 million).
Includes the current portion of long-term debt.
(1)
(2)
91
Canadian Natural 2022 Annual Report
Total
920
3,555
491
9
(1,341)
(4,209)
(1,543)
(11,445)
(13,563)
Total
744
3,111
309
140
(803)
(3,064)
(1,717)
(14,694)
(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 (4) (5)
Asset (liability) (1) (2)
Investments (3)
Other long-term assets
Other long-term liabilities
Fixed rate long-term debt (4) (5)
Carrying amount
Fair value
2022
Level 1
Level 2
Level 3
$
$
$
$
491 $
9 $
(3) $
491 $
— $
— $
(11,445) $
(10,796) $
— $
9 $
(3) $
— $
—
—
—
—
2021
Carrying amount
Fair value
Level 1
Level 2
Level 3
$
$
$
$
309 $
140 $
(133) $
309 $
— $
— $
(13,554) $
(15,420) $
— $
140 $
(85) $
— $
—
—
(48)
—
(1) Excludes financial assets and liabilities where the carrying amount approximates fair value due to the short-term nature of the asset or liability (cash and cash
equivalents, accounts receivable, accounts payable and accrued liabilities).
(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 fixed rate long-term debt has been determined based on quoted market prices.
(5)
Includes the current portion of fixed rate long-term debt.
RISK MANAGEMENT
The Company periodically uses derivative financial instruments to manage its commodity price, interest rate and foreign
currency exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative
purposes.
The following provides a summary of the carrying amounts of derivative financial instruments held and a reconciliation to the
Company’s consolidated balance sheets.
2022
2021
Asset (liability)
Derivatives held for trading
Natural gas (1)
Crude oil and NGLs (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
(1) Commodity financial instruments assumed in the acquisitions of Storm and Painted Pony in 2021 and 2020, respectively (note 7).
Canadian Natural 2022 Annual Report
$
3 $
—
3
—
—
6 $
3 $
(3)
6
—
6 $
$
$
$
(41)
(10)
(13)
(21)
140
55
5
(72)
135
(13)
55
92
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
Balance – end of year
Less: current portion
$
2022
55 $
70
(119)
—
6
—
$
6 $
(1)
Includes the fair value movement of commodity financial instruments included in acquisitions (note 7).
Net (gain) loss from risk management activities for the years ended December 31, were as follows:
Net realized risk management (gain) loss
Net unrealized risk management (gain) loss
FINANCIAL RISK FACTORS
a) Market risk
2022
2021
$
$
(7) $
(28)
(35) $
17 $
19
36 $
2021
(24)
(12)
82
9
55
(67)
122
2020
32
(39)
(7)
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, 2022, 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.
During 2022, the Company settled the US$550 million cross currency swap designated as a cash flow hedge of a portion of the
US$1,100 million 6.25% US dollar debt securities due March 2038. The Company realized cash proceeds of $158 million on
settlement.
As at December 31, 2022, the Company had US$1,017 million of foreign currency forward contracts outstanding, with original
terms of up to 90 days, all of which were designated as derivatives held for trading.
93
Canadian Natural 2022 Annual Report
FINANCIAL INSTRUMENT SENSITIVITIES
The following table summarizes the annualized sensitivities of the Company’s 2022 net earnings and other comprehensive
income to changes in the fair value of financial instruments outstanding as at December 31, 2022, resulting from changes in the
specified variable, with all other variables held constant. These sensitivities are prepared on a different basis than those
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.
2022
2021
Increase
(decrease) to
net earnings
Increase
(decrease)
to other
comprehensive
income
Increase
(decrease) to
net earnings
Increase
(decrease)
to other
comprehensive
income
$
$
$
$
(4) $
4 $
(135) $
131 $
— $
— $
— $
— $
(13) $
13 $
(116) $
114 $
(29)
39
—
—
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
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, 2022, 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, 2021 – 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, 2022, the Company had net risk management assets
of $7 million with specific counterparties related to derivative financial instruments (December 31, 2021 – $140 million). The
carrying amount of financial assets approximates the maximum credit exposure.
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities.
Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources
of capital, consisting primarily of cash flow from operating activities, available credit facilities, commercial paper and access to
debt capital markets, to meet obligations as they become due. The Company believes it has adequate bank credit facilities to
provide liquidity to manage fluctuations in the timing of the receipt and/or disbursement of operating cash flows.
The maturity dates of the Company’s financial liabilities were as follows:
Less than
1 year
1 to less than
2 years
2 to less than
5 years
Thereafter
Accounts payable
Accrued liabilities
Long-term debt (1)
Other long-term liabilities (2)
Interest and other financing expense (3)
$
$
$
$
$
1,341 $
4,209 $
404 $
247 $
584 $
— $
— $
1,009 $
156 $
577 $
— $
— $
3,757 $
416 $
1,410 $
—
—
6,344
724
3,790
(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, $244 million; one to less than
two years, $156 million; two to less than five years, $416 million; and thereafter, $724 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, 2022.
Canadian Natural 2022 Annual Report
94
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, 2022:
Product transportation and processing (1) $
North West Redwater Partnership
service toll (2)
Offshore vessels and equipment
Field equipment and power
Other
2023
2024
2025
2026
2027
Thereafter
1,171 $
1,349 $
1,168 $
1,102 $
1,052 $
11,095
$
$
$
$
151 $
152 $
151 $
133 $
118 $
4,884
44 $
36 $
23 $
35 $
27 $
24 $
— $
24 $
21 $
— $
23 $
16 $
— $
22 $
— $
—
215
—
(1)
Includes commitments pertaining to a 20-year product transportation agreement on the Trans Mountain Pipeline Expansion.
(2) 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 $2,863 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.
21. Supplemental Disclosure of Cash Flow Information
Changes in non-cash working capital:
Accounts receivable
Inventory
Prepaids and other
Other long-term assets
Accounts payable
Accrued liabilities
Current income tax (liabilities) assets
Other long-term liabilities
Net changes in non-cash working capital
Relating to:
Operating activities
Investing activities
2022
2021
2020
$
$
$
$
(441) $
(266)
(20)
—
537
896
(282)
(196)
228 $
79 $
149
228 $
(850) $
(487)
39
—
80
525
1,918
(154)
1,071 $
964 $
107
1,071 $
284
98
(56)
(117)
(147)
(254)
(295)
(62)
(549)
(166)
(383)
(549)
95
Canadian Natural 2022 Annual Report
The following table summarizes movements in the Company's liabilities arising from financing activities for the years' ended
December 31, 2022 and 2021:
At December 31, 2020
$
21,453 $
(28) $
1,690 $
23,115
Long-term
debt
Cash flow
hedges on
US dollar debt
securities Lease liabilities
Liabilities from
financing
activities
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)
At December 31, 2021
Changes from financing cash flows:
Repayment of long-term debt, net (1)
Proceeds on settlement of cross currency swap
Payment of lease liabilities
Non-cash changes:
Lease additions
Changes in foreign exchange and fair value (2)
(6,779)
(183)
—
183
—
20
14,694
(4,010)
—
—
—
761
—
—
—
—
—
(91)
(119)
—
69
—
—
50
—
—
(209)
—
88
15
(6,779)
(183)
(209)
183
88
(56)
1,584
16,159
—
—
(232)
182
6
(4,010)
69
(232)
182
817
At December 31, 2022
$
11,445 $
— $
1,540 $
12,985
(1)
(2)
Includes original issue discounts and premiums, and directly attributable transaction costs.
Includes foreign exchange loss (gain), 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.
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. 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.
Canadian Natural 2022 Annual Report
96
(millions of Canadian dollars)
2022
2021
2020
2022
2021
2020
2022
2021
2020
North America
North Sea
Offshore Africa
$ 20,755 $ 14,478 $ 7,480 $
623 $
607 $
417 $
694 $
420 $
318
Segmented product sales
Crude oil and NGLs (1)
Natural gas
Other income and revenue (2)
Total segmented product sales 25,903 17,081
4,931
2,484
217
119
1,242
41
13
—
5
(1)
12
3
8,763
636
611
432
Less: royalties
(3,918)
(1,694)
(503)
(1)
(1)
(1)
Segmented revenue
21,985 15,387
8,260
635
610
431
55
8
757
(71)
686
31
7
458
(21)
437
42
18
378
(16)
362
Segmented expenses
Production
Transportation, blending and
feedstock (1)
Depletion, depreciation and
amortization (3)
Asset retirement obligation
accretion
Risk management activities
(commodity derivatives)
Gain on acquisitions
Income from NWRP
3,754
2,963
2,510
437
383
321
114
91
103
6,394
4,772
3,393
6
7
15
1
1
1
3,595
3,569
3,780
1,747
160
277
173
142
190
171
101
97
33
21
30
7
6
18
—
—
29
(20)
(478)
(217)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
6
—
—
—
300
62
Total segmented expenses
13,932 10,956
9,543
2,223
571
643
295
240
Segmented earnings (loss)
$ 8,053 $ 4,431 $
(1,283) $ (1,588) $
39 $
(212) $
391 $
197 $
Non–segmented expenses
Administration
Share-based compensation
Interest and other financing
expense
Risk management activities
(other)
Foreign exchange loss (gain)
(Gain) loss from investments
Total non–segmented expenses
Earnings (loss) before taxes
Current income tax
Deferred income tax
Net earnings (loss)
(1)
(2)
Includes blending and feedstock costs associated with the processing of third party bitumen and other purchased feedstock in the Oil Sands Mining and
Upgrading segment.
Includes the sale of diesel and other refined products and other income, including government grants and recoveries associated with the joint operations
partners' share of the costs of lease contracts.
(3)
Includes a $1,620 million recoverability charge in depletion, depreciation and amortization, related to the Ninian field in the North Sea at December 31, 2022.
97
Canadian Natural 2022 Annual Report
Oil Sands Mining
and Upgrading
Midstream and Refining
Inter–segment
elimination and Other
Total
2022
2021
2020
2022
2021
2020
2022
2021
2020
2022
2021
2020
$ 20,804 $ 14,033 $ 7,389 $
80 $
78 $
83 $
53 $
(360) $
(108) $ 43,009 $ 29,256 $ 15,579
—
149
—
73
—
139
20,953 14,106
7,528
(3,242)
(1,081)
(78)
17,711 13,025
7,450
—
906
986
—
986
—
681
759
—
759
—
202
285
—
285
237
196
182
5,236
2,716
1,478
5
3
31
1,285
882
434
295
(161)
105 49,530 32,854 17,491
—
—
—
(7,232)
(2,797)
(598)
295
(161)
105 42,298 30,057 16,893
4,076
3,414
3,114
271
234
184
60
67
48
8,712
7,152
6,280
2,652
1,505
881
691
550
181
229
(231)
27
9,973
6,604
4,498
1,822
1,838
1,784
16
15
15
—
—
—
7,353
5,724
6,046
70
57
72
—
—
—
—
—
—
281
185
205
—
—
—
—
—
—
—
—
—
—
—
—
8,620
6,814
5,851
978
—
—
(400)
399
—
—
—
—
—
—
—
—
—
—
—
—
18
—
—
29
(478)
(400)
(20)
(217)
—
380
289
(164)
75 26,337 18,816 16,792
$ 9,091 $ 6,211 $ 1,599 $
8 $
360 $
(95) $
6 $
3 $
30 $ 15,961 $ 11,241 $
101
415
804
366
514
391
(82)
549
711
756
(53)
738
(196)
7
(127)
(141)
2,257
1,330
13,704
9,911
2,906
1,848
(139)
399
13
(275)
171
974
(873)
(257)
(181)
$ 10,937 $ 7,664 $
(435)
Canadian Natural 2022 Annual Report
98
CAPITAL EXPENDITURES (1)
2022
2021
Net
expenditures
Non-cash
and fair value
changes (2)
Capitalized
costs
Net
expenditures
Non-cash
and fair value
changes (2)
Capitalized
costs
Exploration and
evaluation assets
Exploration and
Production
North America
$
28 $
(59) $
(31) $
(7) $
Offshore Africa
Oil Sands Mining and
Upgrading
Property, plant and
equipment
Exploration and
Production
North America (3)
North Sea
Offshore Africa
Oil Sands Mining and
Upgrading (4)
Midstream and Refining
Head Office
5
—
33
3,105
126
119
3,350
1,719
9
25
5,103
$
5,136 $
—
—
5
—
(59)
(26)
3,241
303
75
3,619
876
8
25
136
177
(44)
269
(843)
(1)
—
(575)
(634) $
8
—
1
2,486
173
54
2,713
1,747
9
23
(36) $
—
(150)
(186)
(43)
8
(150)
(185)
1,351
38
(6)
1,383
3,837
211
48
4,096
(601)
1,146
—
—
782
9
23
5,274
5,089
4,528
4,492
4,502 $
4,493 $
596 $
(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) Net expenditures includes the acquisition of a 5% net carried interest on an existing oil sands lease during 2021.
SEGMENTED ASSETS
Exploration and Production
North America
North Sea
Offshore Africa
Other
Oil Sands Mining and Upgrading
Midstream and Refining
Head Office
2022
2021
$
31,135 $
30,645
378
1,322
54
42,102
979
172
1,561
1,332
40
42,016
886
185
$
76,142 $
76,665
99
Canadian Natural 2022 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
$
$
$
2022
2 $
2021
2 $
2022
2 $
2021
2 $
12
5
18
10
6
19
37 $
37 $
2020
2
2020
2
9
4
14
29
(1) Senior management identified above are consistent with the disclosure on Named Executive Officers provided in the Company’s Information Circular to
shareholders for the respective years.
Canadian Natural 2022 Annual Report
100
Supplementary Oil & Gas Information for the Fiscal
Year Ended December 31, 2022 (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, 2022, 2021, 2020 and 2019 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, 2022,
2021, 2020 and 2019 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 2022 and 2021 reserves for SEC
requirements.
Crude Oil and NGLs
Canadian
Light
Sweet
(C$/bbl)
Cromer
LSB
(C$/bbl)
Brent
(US$/bbl)
WTI
(US$/bbl)
WCS
(C$/bbl)
2022:
2021:
94.13
66.34
99.40
67.68
118.90
77.87
117.76
78.17
97.98
68.92
Edmonton
C5+ Henry Hub
(US$/
MMBtu)
(C$/bbl)
119.93
83.05
Natural Gas
BC
Westcoast
Station 2
(C$/MMBtu)
AECO
(C$/MMBtu)
6.44
3.68
5.59
3.39
4.51
2.90
A foreign exchange rate of US$0.7709/C$1.00 was used in the 2022 evaluation (2021 - US$0.7972/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, 2022, 2021, 2020 and 2019, 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, 2022, 2021, 2020 and 2019, 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.
101
Canadian Natural 2022 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, 2022, 2021, 2020 and 2019:
Crude Oil and NGLs (MMbbl) (1)
Net Proved Reserves
North America
Synthetic
Crude Oil Bitumen (2)
Crude Oil
& NGLs
North
America
Total
North
Sea
Offshore
Africa
Reserves, December 31, 2019
5,554
2,216
598
8,368
105
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
708
—
—
—
(151)
701
36
8
49
—
—
(109)
207
41
10
9
28
—
(45)
(94)
20
726
58
28
—
(305)
814
97
Reserves, December 31, 2020
6,847
2,413
525
9,785
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
—
—
—
—
(150)
(927)
174
101
19
—
—
(103)
(296)
155
Reserves, December 31, 2021
5,944
2,289
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
—
29
—
—
(128)
(455)
—
195
5
267
—
(91)
(263)
144
Reserves, December 31, 2022
5,390
2,546
Net proved developed reserves
December 31, 2019
December 31, 2020
December 31, 2021
December 31, 2022
5,452
6,770
5,929
5,389
661
628
584
582
14
14
52
—
(45)
108
40
708
11
21
21
—
(45)
(73)
54
696
354
285
370
359
115
33
52
—
(297)
(1,115)
369
8,941
205
56
288
—
(265)
(791)
198
8,632
6,466
7,682
6,883
6,330
—
—
—
—
(8)
(12)
3
87
—
—
—
—
(6)
1
(3)
79
—
—
—
—
(5)
1
(64)
11
38
32
39
5
Total
8,544
726
58
28
—
(320)
805
103
70
—
—
—
—
(6)
3
4
71
9,943
—
—
—
—
(5)
(4)
2
115
33
52
—
(309)
(1,118)
368
64
9,083
—
—
—
—
(5)
(2)
—
57
39
37
38
34
205
56
288
—
(274)
(792)
134
8,700
6,543
7,751
6,960
6,369
(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 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.
(4) 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.
(5) Reflects the impact of increased royalties due to higher commodity pricing resulting in higher royalties and lower net reserves.
Canadian Natural 2022 Annual Report
102
2022 total proved Crude Oil and NGLs reserves decreased by 383 MMbbl:
▪
▪
▪
▪
▪
▪
Extensions and discoveries: Increase of 205 MMbbl primarily due to extension drilling/future offset additions at various
Bitumen properties.
Improved recovery: Increase of 56 MMbbl primarily due to improved recovery at Oil Sands Mining and Upgrading (SCO) and
infill drilling/future offset additions at various natural gas (NGLs) and Crude Oil properties.
Purchases of reserves in place: Increase of 288 MMbbl primarily due to a Bitumen acquisition in Alberta.
Production: Decrease of 274 MMbbl.
Economic revisions due to prices: Decrease of 792 MMbbl primarily at Oil Sands Mining and Upgrading (SCO) and various
Bitumen properties due to higher bitumen pricing resulting in higher royalties and lower net reserves.
Revisions of prior estimates: Increase of 134 MMbbl primarily due to improved performance at various Bitumen, North
America Crude Oil and natural gas (NGLs) properties, partially offset by removal of future undeveloped reserves at North
Sea.
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.
103
Canadian Natural 2022 Annual Report
Natural Gas (Bcf) (1)
Net Proved Reserves
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
Extensions and discoveries
Improved recovery
Purchases of reserves in place
Sales of reserves in place
Production
Economic revisions due to prices (2)
Revisions of prior estimates
Reserves, December 31, 2022
Net proved developed reserves
December 31, 2019
December 31, 2020
December 31, 2021
December 31, 2022
North
America
North
Sea
Offshore
Africa
4,728
173
159
2,614
(4)
(515)
97
402
7,655
545
161
1,654
(1)
(581)
712
1,139
11,285
251
192
228
—
(688)
(572)
1,521
12,217
2,342
3,116
4,469
4,956
16
—
—
—
—
(4)
—
—
12
—
—
—
—
(1)
—
(3)
8
—
—
—
—
(1)
—
(3)
4
11
6
3
1
38
—
—
—
—
(5)
4
(3)
34
—
—
—
—
(4)
(4)
—
25
—
—
—
—
(4)
(3)
7
25
28
22
20
19
Total
4,782
173
159
2,615
(4)
(524)
100
399
7,701
545
161
1,654
(1)
(587)
708
1,136
11,318
251
192
228
—
(693)
(575)
1,526
12,246
2,381
3,144
4,492
4,975
(1)
Information in the reserves data tables may not add due to rounding.
(2) Reflects the impact of increased royalties primarily at various North America natural gas properties due to higher natural gas pricing resulting in higher
royalties and lower net reserves.
Canadian Natural 2022 Annual Report
104
2022 total proved Natural Gas reserves increased by 928 Bcf primarily due to the following:
▪
▪
▪
▪
▪
▪
Extensions and discoveries: Increase of 251 Bcf primarily due to extension drilling/future offset additions in the Montney
formation of northwest Alberta and northeast British Columbia.
Improved recovery: Increase of 192 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 228 Bcf primarily due to property acquisitions in North America core areas.
Production: Decrease of 693 Bcf.
Economic revisions due to prices: Decrease of 575 Bcf primarily at various North America natural gas properties due to
higher natural gas pricing resulting in higher royalties and lower net reserves.
Revisions of prior estimates: Increase of 1,526 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.
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.
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.
105
Canadian Natural 2022 Annual Report
Capitalized Costs Related to Crude Oil and Natural Gas Activities
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
Net capitalized costs
(millions of Canadian dollars)
Proved properties
Unproved properties
Less: accumulated depletion and depreciation
Net capitalized costs
(millions of Canadian dollars)
Proved properties
Unproved properties
2022
North
America
North
Sea
Offshore
Africa
Total
$
128,807 $
8,258 $
4,332 $
141,397
2,128
130,935
—
8,258
98
4,430
2,226
143,623
(65,547)
(8,106)
(3,277)
(76,930)
$
65,388 $
152 $
1,153 $
66,693
2021
North
America
North
Sea
Offshore
Africa
Total
$
124,690 $
7,438 $
3,980 $
136,108
2,159
126,849
—
7,438
91
4,071
2,250
138,358
(61,231)
(5,951)
(2,923)
(70,105)
$
65,618 $
1,487 $
1,148 $
68,253
2020
North
America
119,707 $
$
North
Sea
7,283 $
Offshore
Africa
3,963 $
2,353
122,060
—
7,283
83
4,046
Total
130,953
2,436
133,389
Less: accumulated depletion and depreciation
(56,930)
(5,853)
(2,822)
(65,605)
Net capitalized costs
$
65,130 $
1,430 $
1,224 $
67,784
Canadian Natural 2022 Annual Report
106
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
2022
North
America
North
Sea
Offshore
Africa
$
524 $
— $
— $
—
40
4,387
—
—
304
—
5
75
$
4,951 $
304 $
80 $
Total
524
—
45
4,766
5,335
2021
North
America
North
Sea
Offshore
Africa
Total
$
1,371 $
— $
— $
1,371
26
4
4,301
—
—
208
—
8
48
$
5,702 $
208 $
56 $
2020
North
America
North
Sea
Offshore
Africa
$
750 $
— $
— $
15
22
2,338
—
—
104
—
15
94
$
3,125 $
104 $
109 $
26
12
4,557
5,966
Total
750
15
37
2,536
3,338
107
Canadian Natural 2022 Annual Report
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,
2022, 2021 and 2020 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
(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
2022
North
America
North
Sea
Offshore
Africa
Total
$
31,698 $
635 $
687 $
33,020
(7,830)
(1,424)
(5,417)
(241)
—
(3,896)
(437)
(6)
(1,747)
(33)
483
442
(114)
(1)
(173)
(7)
—
(98)
(8,381)
(1,431)
(7,337)
(281)
483
(3,552)
$
12,890 $
(663) $
294 $
12,521
2021
North
America
North
Sea
Offshore
Africa
$
23,111 $
(6,377)
(1,176)
(5,407)
(158)
—
(2,317)
$
7,676 $
438 $
(91)
(1)
(142)
(6)
—
(50)
148 $
611 $
(383)
(7)
(160)
(21)
33
(29)
44 $
2020
North
America
North
Sea
Offshore
Africa
12,520 $
(5,624)
(1,258)
(5,564)
(169)
—
23
432 $
(321)
(15)
(277)
(30)
31
72
354 $
(103)
(1)
(190)
(6)
—
(13)
Total
24,160
(6,851)
(1,184)
(5,709)
(185)
33
(2,396)
7,868
Total
13,306
(6,048)
(1,274)
(6,031)
(205)
31
82
$
(72) $
(108) $
41 $
(139)
Canadian Natural 2022 Annual Report
108
Standardized Measure of Discounted Future Net Cash Flows from Proved Crude
Oil and Natural Gas Reserves and Changes Therein
The following standardized measure of discounted future net cash flows from proved crude oil and natural gas reserves has
been computed using the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-
the-month price for each month within the 12-month period prior to the end of the reporting period, costs as at the balance
sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized
measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted
future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair
value of the crude oil and natural gas properties. Actual net cash flows will differ from the presented estimated future net cash
flows due to several factors including:
▪
▪
▪
▪
▪
Future production will include production not only from proved properties, but may also include production from probable
and possible reserves;
Future production of crude oil and natural gas from proved properties will differ from reserves estimated;
Future production rates will vary from those estimated;
Future prices and costs rather than 12-month average prices and costs as at the balance sheet date will apply;
Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will
change;
Future estimated income taxes do not take into account the effects of future exploration and evaluation expenditures; and
Future development and asset retirement obligations will differ from those estimated.
▪
▪
Future net revenues, development, production and asset retirement obligation costs have been based upon the estimates
referred to above. The following tables summarize the Company's future net cash flows relating to proved crude oil and natural
gas reserves based on the standardized measure as prescribed in FASB Topic 932 - "Extractive Activities - Oil and Gas":
(millions of Canadian dollars)
Future cash inflows
2022
North
America
North
Sea
Offshore
Africa
Total
$
986,672 $
1,506 $
7,304 $
995,482
Future production costs
Future development costs and asset retirement obligations
(303,270)
(691)
(1,998)
(305,959)
(83,803)
(1,416)
(1,439)
(86,658)
Future income taxes
Future net cash flows
10% annual discount for timing of future cash flows
(136,905)
462,694
(327,333)
517
(84)
84
(900)
(137,288)
2,967
465,577
(1,330)
(328,579)
Standardized measure of future net cash flows
$
135,361 $
— $
1,637 $
136,998
(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)
(244,036)
(1,142)
(565)
2,056
(80,374)
(83,144)
284,941
(788)
(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
(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
(1,746)
(208,604)
(1,032)
(217)
1,177
(76,097)
(27,536)
102,001
(373)
(74,490)
$
26,086 $
621 $
804 $
27,511
109
Canadian Natural 2022 Annual Report
The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the
following table:
(millions of Canadian dollars)
Sales of crude oil and natural gas produced, net of production costs
2022
2021
$
(23,242) $
(16,149) $
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
79,291
6,198
(3,640)
5,745
—
(9,956)
10,712
5,463
74,558
2,948
(2,773)
4,010
(1)
(186)
3,460
6,638
(16,357)
(17,232)
54,214
82,784
55,273
27,511
$
136,998 $
82,784 $
2020
(6,127)
(46,055)
626
(153)
947
(1)
5,295
7,718
(4,830)
6,566
(36,014)
63,525
27,511
Canadian Natural 2022 Annual Report
110
Ten Year Review
Years ended December 31
FINANCIAL INFORMATION (C$ millions, except per share amounts)
2022
2021
Net earnings (loss)
10,937
7,664
2020
2019
2018
2017
2016
2015
2014
2013
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
9.64
9.52
6.49
6.46
19,391
14,478
(435)
(0.37)
(0.37)
4,714
4.55
4.54
2.13
2.12
8,829
10,121
19,791
13,733
5,200
10,267
9,088
17.44
17.22
4,987
5,471
(1,190)
2,226
11.63
11.57
3,703
4,908
(480)
2,250
4.40
4.40
2,819
3,206
626
2,436
8.62
8.61
7,255
7,121
241
2,579
5,416
2,591
2,397
3,929
2,270
2.04
2.03
7,262
7,347
6.25
6.21
7.46
7.43
4,814
13,102
4,731
17,129
(601)
2,637
513
2,632
(204)
(0.19)
(0.19)
3,452
4,293
3.90
3.89
3,811
3,794
1,056
2,382
(637)
(0.58)
(0.58)
5,632
5,785
5.29
5.28
3.60
3.58
8,459
9,587
8.78
8.74
5,465
11,177
3,853
11,744
2.08
2.08
7,218
7,477
6.87
6.86
7,006
7,274
1,193
2,586
(673)
3,557
(1,574)
2,609
Property, plant and equipment, net
64,859
66,400
65,752
68,043
64,559
65,170
50,910
51,475
52,480
46,487
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 ($/share) (4)
76,142
76,665
75,276
78,121
71,559
73,867
58,648
59,275
60,200
51,754
11,445
14,694
21,453
20,982
20,623
22,458
16,805
16,794
14,002
9,661
38,175
36,945
32,380
34,991
31,974
31,653
26,267
27,381
28,891
25,772
1,102,636
1,168,369
1,183,866
1,186,857
1,201,886
1,222,769
1,110,952
1,094,668
1,091,837
1,087,322
1,134,960
1,181,250
1,181,768
1,190,977
1,218,798
1,175,094
1,100,471
1,093,862
1,091,754
1,088,682
1,149,182
1,186,557
1,181,768
1,193,106
1,223,758
1,182,823
1,100,471
1,093,862
1,096,822
1,090,541
4.60
2.00
1.70
1.50
1.34
1.10
0.94
0.92
0.90
0.58
Trading statistics
TSX – C$
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)
1,533,722
1,568,872
1,866,414
904,013
806,254
588,422
653,727
728,033
717,580
683,003
88.18
54.20
75.19
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
755,722
795,605
1,058,121
679,697
796,971
608,008
892,220
951,311
812,521
645,403
70.60
42.32
55.53
22 %
22 %
11.6
16.4
44.33
22.40
42.25
27 %
16 %
10.6
14.5
164.55
119.36
32.79
6.71
24.05
40 %
— %
32.56
22.58
32.35
37 %
11 %
9.8
9.3
38.19
21.85
24.13
36.78
27.53
35.72
39 %
41 %
6 %
9.0
6 %
7.9
9.7
35.28
14.60
31.88
39 %
— %
7.3
8.3
34.46
18.94
21.83
38 %
(1) %
7.8
8.3
46.65
26.53
30.88
33 %
10 %
7.2
8.1
33.92
26.98
33.84
27 %
7 %
6.2
7.3
12.0
11.1
13.5
71.62
97.09
101.89
81.41
74.77
73.39
78.99
72.41
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
Long-term debt includes current portion of long-term debt.
On March 1, 2023, the Board of Directors approved a quarterly dividend of $0.90 per common share, an increase from the previous quarterly dividend of $0.85 per common share. The dividend is
payable on April 5, 2023.
Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
Based upon company gross reserves (forecast price and costs, before royalties), using year end common shares outstanding.
111
Canadian Natural 2022 Annual Report
Years ended December 31
COMPANY NET RESERVES (8)
Crude oil and NGLs (MMbbl)
Company net proved reserves (after royalties)
North America
North Sea
Offshore Africa
Company net proved plus probable reserves
(after royalties)
North America
North Sea
Offshore Africa
Natural gas (Bcf)
Company net proved reserves (after royalties)
North America
North Sea
Offshore Africa
Company net proved plus probable reserves
(after royalties)
North America
North Sea
Offshore Africa
Total company net proved reserves
(after royalties) (MMBOE)
Total company net proved plus probable
reserves (after royalties) (MMBOE)
OPERATING INFORMATION
Daily production (before royalties) (10)
Crude oil and NGLs (Mbbl/d)
North America –
Exploration and Production
North America –
Oil Sands Mining and Upgrading
North Sea
Offshore Africa
Natural gas (MMcf/d)
North America
North Sea
Offshore Africa
Total production (before royalties) (MBOE/d)
PRODUCT PRICING (1) (6) (11)
Average crude oil and NGLs price ($/bbl) (12)
Average natural gas price ($/Mcf)
Average SCO price ($/bbl) (13)
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
8,940
11
59
9,010
8,740
79
64
8,883
8,980
96
70
9,147
8,129
109
70
8,307
11,181
15
77
11,273
10,883
117
85
11,085
11,151
160
94
11,405
10,231
175
93
10,499
7,163
119
72
7,354
9,456
186
98
9,740
6,423
120
70
6,613
8,353
180
102
8,635
3,909
134
74
4,117
6,015
252
108
6,375
3,645
158
74
3,877
5,806
284
113
6,203
3,380
204
78
3,662
5,609
308
119
6,036
11,614
4
27
11,645
11,076
8
25
11,109
8,373
12
32
8,417
5,795
16
37
5,849
6,005
27
21
6,053
6,032
21
15
6,068
5,845
41
23
5,909
5,383
39
21
5,443
5,054
83
36
5,173
18,617
7
40
18,664
18,315
11
39
18,364
13,884
17
48
13,949
8,556
21
52
8,630
8,681
38
44
8,763
8,454
32
47
8,533
7,888
85
55
8,028
7,361
96
50
7,507
6,791
114
68
6,973
3,290
224
80
3,594
5,135
325
122
5,582
3,684
91
38
3,813
5,138
125
70
5,333
10,951
10,734
10,549
9,282
8,363
7,625
5,102
4,784
4,524
4,230
14,384
14,146
13,730
11,938
11,202
10,057
7,713
7,454
7,198
6,471
480
473
460
406
351
359
351
400
391
344
426
13
14
933
2,075
2
13
2,090
1,281
90.64
6.55
117.69
448
18
14
952
1,680
3
12
1,695
1,235
63.71
4.07
77.95
417
23
17
918
1,450
12
15
1,477
1,164
31.90
2.40
43.98
395
28
21
850
1,443
24
24
1,491
1,099
55.08
2.34
70.18
426
24
20
821
1,490
32
26
1,548
1,079
46.92
2.61
68.61
282
23
20
685
1,601
39
22
1,662
962
48.57
2.76
63.98
123
24
26
524
1,622
38
31
1,691
806
36.93
2.32
58.59
123
22
19
564
1,663
36
27
1,726
852
111
17
12
531
1,527
7
21
1,555
790
41.13
3.16
61.39
77.04
4.83
100.27
100
18
16
478
1,130
4
24
1,158
671
73.81
3.30
99.18
(8)
(9)
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.
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, 2022) 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
$300/acre ($285/acre from 2021 to 2015, $300/acre from 2014 to 2013), 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)
(12) Average crude oil and NGLs pricing excludes SCO.
(13)
Product prices reflect realized product prices before blending costs, transportation costs and exclude risk management activities.
For years 2017 to 2022, average SCO product price includes AOSP realized product prices net of blending and feedstock costs.
Canadian Natural 2022 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
*Christopher L. Fong (3)(5)
Corporate Director
Calgary, Alberta
*Ambassador Gordon D. Giffin (1)(4)
Partner and Global Vice Chair, emeritus,
Dentons US LLP
Sarasota, Florida
*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 Instrument 58-101 and the New York
Stock Exchange Corporate Governance Listing Standards.
Senior Officers
N. Murray Edwards
Executive Chairman
Tim S. McKay
President
Trevor J. Cassidy
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
Jay E. Froc
Senior Vice-President, Oil Sands Mining and Upgrading
Dwayne F. Giggs
Senior Vice-President, Exploration
Dean W. Halewich
Senior Vice-President, Safety, Risk Management
and Innovation
Ron K. Laing
Senior Vice-President, Corporate Development and Land
Warren P. Raczynski
Senior Vice-President, Thermal
Robin S. Zabek
Senior Vice-President, Exploitation
Victor C. Darel
Vice-President, Finance and Principal Accounting Officer
Erin L. Lunn
Vice-President, Land
Paul M. Mendes
Vice-President, Legal, General Counsel and
Corporate Secretary
Mark A. Overwater
Vice-President, Marketing
Kyle G. Pisio
Vice-President, Drilling, Completions and
Asset Retirement
Roy D. Roth
Vice-President, Facilities and Pipelines
Kara L. Slemko
Vice-President, Corporate Development and
Commercial Operations
113
Canadian Natural 2022 Annual Report
2022 Performance Highlights
Canadian Natural's diverse and balanced asset base along with the Company's flexible capital allocation
strategy and continued focus on effective and efficient operations delivered record operational and
financial results in 2022. These strong results generated substantial free cash flow, significant returns to
shareholders and strong reserves growth 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)
2022
2021
2020
49,530 $
32,854 $
17,491
10,937 $
7,664 $
9.64 $
9.52 $
6.49 $
6.46 $
12,863 $
7,420 $
11.33 $
11.19 $
6.28 $
6.25 $
19,391 $
14,478 $
19,791 $
13,733 $
17.44 $
17.22 $
4,987 $
5,471 $
11.63 $
11.57 $
3,703 $
4,908 $
(435)
(0.37)
(0.37)
(756)
(0.64)
(0.64)
4,714
5,200
4.40
4.40
2,819
3,206
10,525 $
13,950 $
38,175 $
36,945 $
22%
27%
21,269
32,380
40%
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(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, 2022, dated March 1, 2023, 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.
Management's Discussion and Analysis
Supplementary Oil and Gas Information
Consolidated Financial Statements
Management's Report
Ten Year Review
Corporate Information
Managements's Assessment of Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Notes to the Consolidated Financial Statements
59
60
66
101
111
113
TABLE OF CONTENTS
2022 Performance Highlights
Letter to Shareholders
2022 Year End Reserves
01
03
06
09
57
58
1
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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
cubic metres
cubic metres
metres
kilometres
hectares
tons
Multiply by
0.159
28.174
0.305
1.609
0.405
1.102
COMMON SHARE DIVIDEND
The Company paid its first dividend on its common shares
on April 1, 2001. Since then, dividends have been paid
quarterly. The following table shows the aggregate amount of
the cash dividends declared per common share of the
Company and accrued in each of its last three years ended
December 31, 2022.
Cash dividends declared
per common share
2022
2021
2020
$4.60
$2.00
$1.70
NOTICE OF ANNUAL MEETING
Canadian Natural’s Annual Meeting of the Shareholders will be
held on Thursday, May 4, 2023 at 1:00 p.m. Mountain Daylight
Time in Exhibition Hall E of the Telus Convention Centre,
Calgary, Alberta.
CORPORATE GOVERNANCE
Canadian Natural’s corporate governance practices and disclosure of those practices are in compliance with National Policy 58-201 Corporate
Governance Guidelines and National Instrument 58-101 Disclosure of Corporate Governance Practices. Canadian Natural, as a foreign private issuer in
the United States, may rely on home jurisdiction listing standards for compliance with most of the New York Stock Exchange (NYSE) Corporate
Governance Listing Standards but must disclose any significant differences between its corporate governance practices and those required for U.S.
companies listed on the NYSE.
Canadian Natural follows Toronto Stock Exchange (TSX) rules with respect to shareholder approval of equity compensation plans and material revisions
to such plans. TSX rules provide that only the creation of or material amendments to equity compensation plans which provide for new issuance of
securities are subject to shareholder approval. However, the NYSE requires shareholder approval of all equity compensation plans whether they provide
for the delivery of newly issued securities, or rely on securities acquired in the open market by the issuing company for the purposes of redistribution to
plan beneficiaries, and material revisions to such plans. Canadian Natural has a performance share unit plan pursuant to which common shares are
purchased through the TSX. This is not a new issue of securities under the performance share unit plan and under TSX rules the plan is not subject to
shareholder approval.
Canadian Natural has included as exhibits to its Annual Report on Form 40-F for the 2022 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 2022 Annual Report
Canadian Natural 2022 Annual Report
114
2023-03-16 4:23 PM
2023-03-16 4:23 PM
2100, 855 – 2 Street S.W.
Calgary, AB T2P 4J8
T (403) 517-6700
F (403) 517-7350
E ir@cnrl.com
www.cnrl.com
2022 ANNUAL REPORT
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