2024 ANNUAL REPORT
2024 Performance Highlights
Canadian Natural's flexible capital allocation strategy combined with our unique, diverse and balanced
portfolio of assets maximizes value for our shareholders. In 2024, the Company focused on effective and
efficient operations and achieved record production, which delivered strong financial results, significant
returns to shareholders and reserves growth year over year.
2024
2023
2022
FINANCIAL ($ millions, except per common share amounts)
Product sales (1)
$
41,509 $
40,835 $
49,530
Net earnings
$
6,106 $
8,233 $
10,937
Per common share (2) – basic
$
2.87 $
3.77 $
4.82
– diluted
$
2.85 $
3.74 $
4.76
Adjusted net earnings from operations (3)
$
7,414 $
8,533 $
12,863
Per common share (2) – basic (4)
$
3.49 $
3.91 $
5.67
– diluted (4)
$
3.46 $
3.87 $
5.60
Cash flows from operating activities
$
13,386 $
12,353 $
19,391
Adjusted funds flow (3)
$
14,859 $
15,274 $
19,791
Per common share (2) – basic (4)
$
6.99 $
7.00 $
8.72
– diluted (4)
$
6.94 $
6.93 $
8.61
Cash flows used in investing activities
$
14,095 $
4,858 $
4,987
Net capital expenditures (5)
$
14,431 $
4,909 $
5,136
Abandonment expenditures, net (3)
$
646 $
509 $
335
Long-term debt, net (6)
$
18,688 $
9,922 $
10,525
Shareholders' equity
$
39,468 $
39,832 $
38,175
Debt to book capitalization (6)
32%
20%
22%
(1)
Further details related to product sales are disclosed in the "Segmented Information" note to the Company's audited consolidated financial statements.
(2)
Per common share amounts have been updated to reflect the two for one common share split. Further details are disclosed in the Advisory section of the
Company's MD&A and in the audited consolidated financial statements.
(3)
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") included in this annual report.
(4)
Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
(5)
Non-GAAP Financial Measure. The composition of this measure was updated for all periods presented. Refer to the "Non-GAAP and Other Financial
Measures" section of the Company's MD&A.
(6)
Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
Cover: Steam Generators at Jackfish.
TABLE OF CONTENTS
01
03
06
09
55
56
2024 Performance Highlights
Letter to Shareholders
2024 Year End Reserves
Management's Discussion and Analysis
Consolidated Financial Statements
Management's Report
57
58
65
97
107
109
Management's Assessment of Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Notes to the Consolidated Financial Statements
Supplementary Oil and Gas Information
Ten Year Review
Corporate Information
1
Canadian Natural 2024 Annual Report
2024
2023
2022
OPERATING
Daily production, before royalties (1)
Crude oil and NGLs (Mbbl/d)
North America – Exploration and Production
509
496
480
North America – Oil Sands Mining and Upgrading
472
451
426
North Sea
12
13
13
Offshore Africa
13
13
14
1,006
974
933
Natural gas (MMcf/d)
North America
2,136
2,139
2,075
North Sea
2
2
2
Offshore Africa
9
10
13
2,147
2,151
2,090
Barrels of oil equivalent (MBOE/d) (2)
1,363
1,332
1,281
Drilling activity (3)
North America
387
284
390
North Sea
—
—
—
Offshore Africa
—
—
—
387
284
390
(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.
1,005,603
BBL/D
RECORD LIQUIDS PRODUCTION
78%
OF TOTAL LIQUIDS PRODUCTION IS
LONG LIFE LOW DECLINE
Canadian Natural 2024 Annual Report
2
Letter to Shareholders
One of Canadian Natural's strengths is the diversity of our world class assets, which have been strategically
assembled and developed over several decades. Our large, diverse portfolio is supported by long life low
decline assets, which drive top tier operating costs and low maintenance capital relative to the size and
quality of our reserves. This 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 our capital allocation strategy in 2024, through our disciplined and flexible
approach. When combined with our safe, reliable, effective and efficient operations and our culture of
continuous improvement we drove strong operational and financial results in 2024, maximizing value for
our shareholders.
2024 was an excellent year for the Company, as we achieved strong growth and set several new production
records from our base operations, before including acquisitions that closed late in 2024. Additionally,
including acquisitions, we achieved record annual average production of over 1,363 MBOE/d in 2024, which
includes record annual liquids production of over one million barrels per day. At our world class Oil Sands
Mining and Upgrading assets, we achieved record quarterly and annual Synthetic Crude Oil (”SCO”)
production of approximately 535 Mbbl/d in Q4/24 and 472 Mbbl/d in 2024.
This strong operational performance resulted in a high annual utilization rate of 99%, anchored by industry leading SCO
operating costs averaging $22.88/bbl (US$16.70/bbl) in 2024, which drove significant free cash flow(1) in the year. Thermal in
situ production also reached record annual production levels of approximately 271 Mbbl/d combined with strong operating costs
of $11.04/bbl (US$8.06/bbl). Our conventional crude oil and liquids-rich natural gas operations continue to provide significant
free cash flow with further potential for organic growth. When combined with our entire portfolio, we have significant organic
growth opportunities.
In 2024, we delivered strong financial results, with adjusted net earnings of approximately $7.4 billion and adjusted funds flow
of $14.9 billion. We returned approximately $7.1 billion to shareholders in 2024, inclusive of our sustainable and growing
dividend and share repurchases.
The Board of Directors approved two separate increases to our quarterly dividend in 2024, for a combined increase of 13% to
$0.5625 per common share. Subsequent to year end, in March of 2025, the Board of Directors approved an additional 4%
increase to the quarterly dividend to $0.5875 per common share, or $2.35 per common share on an annual basis, 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 25 consecutive years of
dividend increases, with a compound annual growth rate of 21% over that time period.
Canadian Natural's reserves compete on a global scale supporting long-term organic growth opportunities, with total proved
reserves of 15.2 billion BOE and total proved plus probable reserves of 20.1 billion BOE as of year end 2024, both of which
increased 9% from year end 2023 levels. The increase in our reserves reflects acquisitions and the success of our capital
efficient development opportunities across our asset base with reserve replacement ratios of 365% and 422% on a total proved
and total proved plus probable basis respectively. With approximately 74% of the Company's total proved reserves being long
life low decline, the strength and depth of our assets is evident and provides us with a total proved reserves life index ("RLI") of
33 years and a total proved plus probable RLI of 44 years. This includes Oil Sands Mining and Upgrading reserves that have a
total proved RLI of 43 years, providing significant production for decades.
In December 2024, we closed the acquisition of Chevron's Alberta assets, which included a 20% interest in the Athabasca Oil
Sands Project (“AOSP”) and a 70% operated interest in light crude oil and liquids-rich Duvernay assets. Combined, these assets
are targeted to add approximately 122,500 BOE/d of production in 2025, consisting of approximately 62,500 bbl/d of long life no
decline SCO at AOSP and approximately 179 MMcf/d of natural gas and 30,000 bbl/d of liquids from the Duvernay. These
acquisitions provide Canadian Natural with immediate free cash flow generation and further opportunities to drive long-term
shareholder value.
~$7.1 BILLION
RETURNED TO SHAREHOLDERS
IN 2024
1,363,496
BOE/D
RECORD TOTAL PRODUCTION
3
Canadian Natural 2024 Annual Report
Canadian Natural is committed to supplying safe, reliable, responsible energy and to environmental stewardship.
We incorporate environmental, social and governance practices that strengthen our long-term sustainability across all aspects of
our business and are uniquely positioned with diverse, long life low decline assets which are ideal for continued review and
evaluation of new technologies designed to reduce environmental impacts. Canada’s energy sector has an important role in
Canada’s economy, providing jobs, economic growth, and reliable, affordable energy that the world needs. We believe that
Canada has the people, resources, and expertise to be a global leader in oil and natural gas production.
We are committed to creating 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. In 2024, we worked with 212 Indigenous businesses through which approximately
$855 million in contracts were awarded, a 3% increase from 2023 levels. 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.
Our strong execution in 2024 sets us up to continue delivering on our four pillars of capital allocation through our disciplined
2025 operating capital budget(1) of approximately $6.0 billion, along with approximately $787 million of abandonment
expenditures before recoveries, approximately $90 million of carbon capture expenditures and $45 million on a one-time office
move. We have flexibility within our budget to adjust to evolving market conditions, ensuring we are allocating capital
effectively, strengthening our balance sheet and maximizing value for our shareholders. We have a long track record of
consistently delivering strong, industry leading results driven by our safe, reliable operations and relentless focus on continuous
improvement, which maximizes long-term shareholder value.
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 and relentless focus on
continuous improvement by following our mission statement underpins the ongoing success of the business and positions
Canadian Natural very well into the future to drive long-term shareholder value.
N. MURRAY EDWARDS
SCOTT G. STAUTH
MARK A. STAINTHORPE
VICTOR C. DAREL
Executive Chairman
President
Chief Financial Officer
Senior Vice-President,
Finance and Principal
Accounting Officer
(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 2024 Annual Report
4
Advisory
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, as applicable, as an indication of the Company's performance.
Descriptions of the Company’s non-GAAP and other financial measures included in this document, and reconciliations to the
most directly comparable GAAP measure, as applicable, are provided below as well as in the "Non-GAAP and Other Financial
Measures" section of the Company's MD&A.
FREE CASH FLOW ALLOCATION POLICY
Free cash flow is a non-GAAP financial measure. 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 or maintain net debt levels, pursuant to the free cash flow allocation policy.
The Company’s free cash flow is used to determine the targeted amount of shareholder returns after dividends. The amount
allocated to shareholders varies depending on the Company’s net debt position.
Free cash flow is calculated as adjusted funds flow less dividends on common shares, net capital expenditures and
abandonment expenditures. The Company targets to manage the allocation of free cash flow on a forward looking annual basis,
while managing working capital and cash management as required.
Up to October 2024, before the announcement of the Chevron acquisition, the Company was targeting to allocate 100% of its
free cash flow in 2024 to shareholder returns.
In October 2024, with the announcement of the Chevron acquisition, the Board of Directors adjusted the allocation of free cash
flow as follows:
▪
60% of free cash flow to shareholder returns and 40% to the balance sheet until net debt reaches $15 billion.
▪
When net debt is between $12 billion and $15 billion, free cash flow allocation will be 75% to shareholder returns and 25%
to the balance sheet.
▪
When net debt is at or below $12 billion, free cash flow allocation will be 100% to shareholder returns.
The Company's free cash flow for the year ended December 31, 2024 is shown below:
Year Ended
($ millions)
Dec 31
2024
Adjusted funds flow (1)
$
14,859
Less: Dividends on common shares
4,429
Net capital expenditures,(2) excluding net acquisition costs
5,286
Abandonment expenditures
646
Free cash flow (3)
$
4,498
(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, 2024, dated March 5, 2025.
(2)
Net Capital expenditures is a Non-GAAP Financial Measure. 2024 Net capital expenditures, excluding net acquisition costs is equal to net capital expenditures
of $14,431 million less net acquisition costs of $9,145 million in the period. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's
MD&A for the year ended December 31, 2024, dated March 5, 2025.
(3)
The Company's free cash flow in 2023 was $6,917 million (2022 – $10,909 million), calculated as per the Company's free cash flow policy at the time, as
adjusted funds flow of $15,274 million (2022 – $19,791 million), less base capital expenditures of $3,958 million (2022 – $3,621 million), abandonment
expenditures, net of $509 million (2022 – $335 million) and dividends on common shares of $3,891 million (2022 – $4,926 million).
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.
The 2025 capital budget reflects budgeted net capital expenditures, before capital related to the office relocation and
abandonment expenditures related to the execution of the Company's abandonment and reclamation programs in North
America and the North Sea. The Company currently carries an Asset Retirement Obligation ("ARO") liability on its balance sheet
for these budgeted future expenditures. Abandonment expenditures are reported before the impact of current income tax
recoveries. Current tax recoveries are refundable at a rate of approximately 23% in Canada and a combined current income tax
and Petroleum Revenue Tax ("PRT") rate approximating 70% to 75% in the UK portion of the North Sea. The Company is eligible
to recover interest on refunded PRT previously paid.
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. Refer to Note 16 to the Company's 2024 audited consolidated financial statements.
5
Canadian Natural 2024 Annual Report
2024 Year End Reserves
DETERMINATION OF RESERVES
For the year ended December 31, 2024, Canadian Natural retained Independent Qualified Reserves Evaluators ("IQREs") to
evaluate and review all of the Company’s proved and proved plus probable reserves. The Company retained Sproule
International Limited for its North America Conventional, International and Thermal reserves evaluation and review, and GLJ Ltd.
for its Oil Sands Mining and Upgrading reserves evaluation. 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 National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("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 Independent Qualified Reserves Evaluators ("IQRE") 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 its world class, top tier assets. The Company's
total proved reserve life index ("RLI")(1) of 33 years is supported by long life low decline assets that have been strategically
assembled and developed over several decades. The low maintenance capital requirements relative to the size and quality of
the reserves affords the Company significant flexibility when balancing its four pillars of capital allocation to maximize
shareholder value.
The following highlights are based on the Company's reserves using forecast prices and costs at December 31, 2024 (all
reserves values are Company Gross unless stated otherwise).
▪
Total proved reserves increased 9% to 15.231 billion BOE, with reserves additions and revisions of 1.820 billion BOE. Total
proved plus probable reserves increased 9% to 20.110 billion BOE, with reserves additions and revisions of
2.105 billion BOE.
◦
The strength and depth of the Company's assets are evident as approximately 74% of total proved reserves are long
life low decline reserves. This results in a total proved BOE RLI of 33 years and a total proved plus probable BOE RLI of
44 years.
–
Additionally, high value, zero decline SCO represents approximately 50% of total proved reserves with a RLI of
43 years.
▪
In 2024, proved developed producing reserves additions and revisions were 1.322 million BOE, replacing 2024 production
by 265%. The proved developed producing BOE RLI is 21 years.
▪
In 2024, total proved reserves additions and revisions replaced 2024 production by 365%. Total proved plus probable
reserves additions and revisions replaced 2024 production by 422%.
▪
In 2024, Canadian Natural continued to achieve strong finding and development costs:
◦
Finding, development and acquisition ("FD&A")(1) costs, excluding changes in Future Development Cost ("FDC"), were
$7.82/BOE for total proved reserves and $6.76/BOE for total proved plus probable reserves.
◦
FD&A costs, including changes in FDC, were $13.56/BOE for total proved reserves and $12.60/BOE for total proved
plus probable reserves.
▪
At December 31, 2024, the net present value of Future Net Revenues ("FNR"), before income tax, discounted at 10%, was
$118.3 billion for proved developed producing reserves, $170.2 billion for total proved reserves, and $205.7 billion for total
proved plus probable reserves.
◦
The Company's total proved net asset value ("NAV") per share increased to $74.83 per share at December 31, 2024
from $69.53 per share at December 31, 2023 after adjusting for asset retirement obligations and net debt and the
share split that occurred in June 2024. Total proved plus probable NAV per share increased to $91.72 per share at
December 31, 2024 from $84.83 per share at December 31, 2023.
(1)
Supplementary financial measure. Refer to the notes to the "2024 Year End Reserves" on page 8.
Canadian Natural 2024 Annual Report
6
Summary of Company Gross Reserves
as of December 31, 2024
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
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(Bcf)
(MMbbl)
(MMBOE)
Proved
Developed Producing
118
123
202
631
7,567
5,034
172
9,652
Developed Non-Producing
5
7
—
78
—
246
9
140
Undeveloped
129
88
53
2,603
96
11,625
533
5,440
Total Proved
252
219
255
3,312
7,663
16,904
713
15,231
Probable
94
99
105
1,878
593
10,252
403
4,879
Total Proved plus Probable
346
318
360
5,190
8,255
27,156
1,116
20,110
Reconciliation of Company Gross Reserves
as of December 31, 2024
Forecast Prices and Costs
TOTAL PROVED
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
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(Bcf)
(MMbbl)
(MMBOE)
December 31, 2023
218
193
258
3,287
6,910
15,005
543
13,910
Discoveries
—
—
—
—
—
1
—
1
Extensions
15
21
—
57
—
537
22
205
Infill Drilling
2
4
—
3
—
175
13
52
Improved Recovery
—
—
—
1
2
—
—
2
Acquisitions
8
—
—
—
853
1,266
157
1,229
Dispositions
(1)
—
—
—
—
(51)
(2)
(12)
Economic Factors
1
1
—
—
—
(230)
(4)
(41)
Technical Revisions
34
29
13
63
71
987
10
383
Production
(25)
(29)
(16)
(99)
(173)
(786)
(25)
(499)
December 31, 2024
252
219
255
3,312
7,663
16,904
713
15,231
TOTAL PROVED PLUS
PROBABLE
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
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(MMbbl)
(Bcf)
(MMbbl)
(MMBOE)
December 31, 2023
305
288
365
5,191
7,460
24,284
848
18,504
Discoveries
1
—
—
—
—
1
—
1
Extensions
21
31
—
75
—
1,169
55
377
Infill Drilling
3
6
—
4
—
268
18
77
Improved Recovery
—
—
—
1
2
—
—
3
Acquisitions
16
—
—
—
904
1,874
233
1,466
Dispositions
(1)
—
—
—
—
(66)
(3)
(15)
Economic Factors
1
1
1
—
—
(269)
(4)
(46)
Technical Revisions
26
20
10
18
62
681
(6)
243
Production
(25)
(29)
(16)
(99)
(173)
(786)
(25)
(499)
December 31, 2024
346
318
360
5,190
8,255
27,156
1,116
20,110
7
Canadian Natural 2024 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 natural gas metrics may not
calculate exactly due to rounding.
3. Forecast pricing assumptions utilized by the IQREs in the reserves estimates are the 3-Consultant-Average of price
forecasts developed by Sproule International Limited, GLJ Ltd. and McDaniel & Associates Consultants Ltd., dated
December 31, 2024:
2025
2026
2027
2028
2029
Crude Oil and NGLs
WTI
US$/bbl
71.58
74.48
75.81
77.66
79.22
WCS
C$/bbl
82.69
84.27
83.81
85.70
87.45
Canadian Light Sweet
C$/bbl
94.79
97.04
97.37
99.80
101.79
Cromer LSB
C$/bbl
93.30
96.05
95.92
98.55
100.51
Edmonton C5+
C$/bbl
100.14
100.72
100.24
102.73
104.79
Brent
US$/bbl
75.58
78.51
79.89
81.82
83.46
Natural Gas
AECO
C$/MMBtu
2.36
3.33
3.48
3.69
3.76
BC Westcoast Station 2
C$/MMBtu
2.15
3.14
3.29
3.50
3.57
Henry Hub
US$/MMBtu
3.31
3.73
3.85
3.93
4.01
All prices increase at a rate of 2% per year after 2029.
A US$/C$ foreign exchange rate of 0.7117 was used for 2025, 0.7283 for 2026, and 0.7433 for 2027 and thereafter in the
year end 2024 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 natural 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 2025 proved developed
producing production forecast prepared by the IQREs.
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 2024 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 2024 and net changes in FDC from December 31, 2023 to December 31, 2024 by the sum of total
additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and
reclamation ("ADR") costs.
11. ADR costs included in the calculation of the FNR consist of both the Company's total Asset Retirement Obligation ("ARO"),
before inflation and discounting, for development existing as at December 31, 2024 and forecast estimates of ADR costs
attributable to future development activity.
Canadian Natural 2024 Annual Report
8
Management's Discussion and Analysis
Table of Contents
Definitions and Abbreviations
10
Advisory
11
Objectives and Strategy
14
Financial and Operational Highlights
15
Business Environment and Outlook
18
Analysis of Changes in Product Sales
20
Daily Production
21
Exploration and Production
23
Oil Sands Mining and Upgrading
27
Midstream and Refining
28
Corporate and Other
29
Net Capital Expenditures
32
Liquidity and Capital Resources
33
Commitments and Contingencies
36
Subsequent Events
36
Reserves
37
Risks and Uncertainties
38
Environment
39
Accounting Policies and Standards
42
Control Environment
44
Non-GAAP and Other Financial Measures
45
Other
51
9
Canadian Natural 2024 Annual Report
Definitions and Abbreviations
AECO
Alberta natural gas reference location
AIF
Annual Information Form
AOSP
Athabasca Oil Sands Project
API
specific gravity measured in degrees on the
American Petroleum Institute scale
ARO
asset retirement obligations
bbl
barrel
bbl/d
barrels per day
Bcf
billion cubic feet
Bcf/d
billion cubic feet per day
Bitumen
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
BOE
barrels of oil equivalent
BOE/d
barrels of oil equivalent per day
Brent
Dated Brent
C$
Canadian dollars
CO2
carbon dioxide
CO2e
carbon dioxide equivalents
CORRA
Canadian Overnight Repo Rate Average
Crude oil
includes light and medium crude oil, primary
heavy crude oil, Pelican Lake heavy crude oil,
bitumen (thermal oil), and synthetic crude oil
E&P
Exploration and Production
FASB
Financial Accounting Standards Board
FPSO
Floating Production, Storage and Offloading
Vessel
GHG
greenhouse gas
GJ
gigajoules
GJ/d
gigajoules per day
Horizon
Horizon Oil Sands
IASB
International Accounting Standards Board
IFRS
International Financial Reporting Standards
Mbbl
thousand barrels
Mbbl/d
thousand barrels per day
MBOE
thousand barrels of oil equivalent
MBOE/d
thousand barrels of oil equivalent per day
Mcf
thousand cubic feet
Mcfe
thousand cubic feet equivalent
Mcf/d
thousand cubic feet per day
MMbbl
million barrels
MMBOE
million barrels of oil equivalent
MMBtu
million British thermal units
MMBtu/d
million British thermal units per day
MMcf
million cubic feet
MMcf/d
million cubic feet per day
NGLs
natural gas liquids
NWRP
North West Redwater Partnership
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
OPEC+
Organization of the Petroleum Exporting
Countries Plus
PRT
Petroleum Revenue Tax
SCO
synthetic crude oil
SEC
United States Securities and Exchange
Commission
SOFR
Secured Overnight Financing Rate
TMX
Trans Mountain Expansion pipeline
TSX
Toronto Stock Exchange
UK
United Kingdom
US
United States
US$
United States dollars
WCS
Western Canadian Select
WCS Heavy
Differential
WCS Heavy Differential from WTI
WTI
West Texas Intermediate reference
location at Cushing, Oklahoma
Canadian Natural 2024 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", "focus", "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 the Company's strategy or strategic focus, capital budget, expected future commodity pricing, forecast or
anticipated production volumes, royalties, production expenses, capital expenditures, abandonment 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, including the strength of the Company's balance sheet, the sources and
adequacy of the Company's liquidity, and the flexibility of the Company's capital structure, 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 ("Primrose"), the
Pelican Lake water and polymer flood projects ("Pelican Lake"), the Kirby thermal oil sands project ("Kirby"), the Jackfish thermal
oil sands project ("Jackfish") 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 abandonment and decommissioning of certain assets
and the timing thereof; 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 materiality of the
impact of litigation and tax interpretations on the Company's results, 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 the actions of OPEC+, the impact of conflicts
in the Middle East and in Ukraine, increased inflation, and the risk of decreased economic activity resulting from a global
recession) 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; 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; changes and uncertainty
in the international trade environment, including with respect to tariffs, export restrictions, embargoes and key trade
agreements (including the tariffs on certain goods announced by the US government and Canadian countermeasures
subsequently announced, both of which are anticipated to evolve); uncertainty in the regulatory framework governing
greenhouse gas emissions, including among other things, financial and other support from various levels of government for
climate related initiatives and potential emissions or production caps, political uncertainty, including changes in government,
actions of or against terrorists, insurgent groups or other conflict including conflict between states; the ability of the Company
to prevent and recover from a cyberattack, other cyber-related crime and other cyber-related incidents; industry capacity; ability
of the Company to implement its business strategy, including exploration and development activities; the impact of
competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the
Company to complete capital programs; the Company's 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 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,
including the acquired working interests in AOSP and Duvernay assets from Chevron Canada Limited ("Chevron") in December
11
Canadian Natural 2024 Annual Report
2024; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and
NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures
required to comply with them (especially safety, competition, environmental laws and regulations, and the impact of climate
change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and
regulations; 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; the impact of legal proceedings to which the
Company is party; and other circumstances affecting revenues and expenses.
The Company's operations have been, and in the future may be, affected by political developments and by national, federal,
provincial, state and local laws and regulations such as restrictions on production, the imposition of tariffs, embargoes or export
restrictions on the Company's products (including the tariffs on certain goods announced by the US government and Canadian
countermeasures subsequently announced, both of which are anticipated to evolve), 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 COMMON SHARE SPLIT AND COMPARATIVE FIGURES
At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a Special Resolution approving a two
for one common share split effective for shareholders of record as of market close on June 3, 2024. On June 10, 2024,
shareholders of record received one additional share for every one common share held, with common shares trading on a split-
adjusted basis beginning June 11, 2024. Common share, per common share, dividend, and stock option amounts for periods
prior to the two for one common share split have been updated to reflect the common share split.
SPECIAL NOTE REGARDING AMENDMENTS TO THE COMPETITION ACT (CANADA)
On June 20, 2024, amendments to the Competition Act (Canada) came into force with the adoption of Bill C-59, An Act to
Implement Certain Provisions of the Fall Economic Statement, which impacted environmental and climate disclosures by
businesses. As a result of these amendments, certain public representations by a business regarding the benefits of the work it
is doing to protect or restore the environment or mitigate the environmental and ecological causes or effects of climate change
may violate the Competition Act's deceptive marketing practices provisions. These amendments include substantial financial
penalties and, effective June 20, 2025, a private right of action which will permit private parties to seek an order from the
Competition Tribunal under the deceptive marketing practices provisions. Uncertainty surrounding the interpretation and
enforcement of this legislation may expose the Company to increased litigation and financial penalties, the outcome and
impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business,
reputation, financial condition, and results.
SPECIAL NOTE REGARDING CURRENCY, FINANCIAL INFORMATION, PRODUCTION AND RESERVES
This MD&A should be read in conjunction with the Company's audited consolidated financial statements for the year ended
December 31, 2024. It should also be read in conjunction with the Company's MD&A for the three months and year ended
December 31, 2024. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The
Company's audited consolidated financial statements for the year ended December 31, 2024 and this MD&A have been
prepared in accordance with IFRS as issued by the IASB.
Canadian Natural 2024 Annual Report
12
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 2024 financial results compared to 2023 and 2022,
unless otherwise indicated. In addition, this MD&A details the Company's targeted capital program for 2025. 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, 2024, its Annual Information Form for the year ended December 31, 2024, and its
audited consolidated financial statements for the year ended December 31, 2024, is available on SEDAR+ at
www.sedarplus.ca, 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 5, 2025.
13
Canadian Natural 2024 Annual Report
Objectives and Strategy
The Company's objectives are to increase crude oil and natural gas production, reserves, cash flow and net asset value 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 and its commitments
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, including through its dividend and share buyback programs, in accordance with its capital allocation
policy. 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(1), 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;
▪
Expanding market access for crude oil and natural gas by supporting and participating in pipeline and infrastructure projects
that add incremental transportation capacity to existing and new markets; 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 develop its reserves, execute on growth projects and take advantage of favourable
acquisition opportunities. Additionally, the Company periodically utilizes its risk management hedging program to reduce the risk
of volatility in commodity prices and foreign exchange rates, and corresponding cash flows.
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 provide the means to responsibly and sustainably grow in the long term.
(1)
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.
Canadian Natural 2024 Annual Report
14
Financial and Operational Highlights(1)
($ millions, except per common share amounts)
2024
2023
2022
Product sales (1)
$
41,509
$
40,835 $
49,530
Crude oil and NGLs
$
39,084
$
37,300 $
43,009
Natural gas
$
1,568
$
2,575 $
5,236
Net earnings
$
6,106
$
8,233 $
10,937
Per common share
– basic
$
2.87
$
3.77 $
4.82
– diluted
$
2.85
$
3.74 $
4.76
Adjusted net earnings from operations (2)
$
7,414
$
8,533 $
12,863
Per common share
– basic (3)
$
3.49
$
3.91 $
5.67
– diluted (3)
$
3.46
$
3.87 $
5.60
Cash flows from operating activities
$
13,386
$
12,353 $
19,391
Adjusted funds flow (2)
$
14,859
$
15,274 $
19,791
Per common share
– basic (3)
$
6.99
$
7.00 $
8.72
– diluted (3)
$
6.94
$
6.93 $
8.61
Dividends declared per common share (4)
$
2.14
$
1.85 $
2.30
Total assets
$
85,359
$
75,955 $
76,142
Long-term debt, net (5)
$
18,688
$
9,922 $
10,525
Cash flows used in investing activities
$
14,095
$
4,858 $
4,987
Net capital expenditures (6)
$
14,431
$
4,909 $
5,136
Abandonment expenditures, net (2)
$
646
$
509 $
335
Average realized price
Crude oil and NGLs – Exploration and Production ($/bbl) (3)
$
77.76
$
72.36 $
90.64
Natural gas – Exploration and Production ($/Mcf) (7)
$
1.86
$
3.10 $
6.55
SCO – Oil Sands Mining and Upgrading ($/bbl) (3)
$
98.03
$
100.06 $
117.69
Daily production, before royalties (BOE/d)
1,363,496
1,332,105
1,281,434
Crude oil and NGLs (bbl/d)
1,005,603
973,530
933,149
Natural gas (MMcf/d) (8)
2,147
2,151
2,090
(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 March 5, 2025, the Board of Directors approved a 4% increase in the quarterly dividend to $0.5875 per common share, beginning with the dividend
payable on April 4, 2025. On October 7, 2024, the Board of Directors approved a 7% increase in the quarterly dividend to $0.5625 per common share,
beginning with the dividend paid on January 3, 2025. On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to
$0.525 per common share. On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $0.50 per common share.
On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.45 per common share. On November 2, 2022, the Board of
Directors approved a 13% increase in the quarterly dividend to $0.425 per common share. On August 3, 2022, the Board of Directors approved a special
dividend of $0.75 per common share. On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.375 per common
share.
(5)
Capital management measure. Refer to note 16 to the Company's audited consolidated financial statements.
(6)
Non-GAAP Financial Measure. The composition of this measure was updated for all periods presented. Refer to the "Non-GAAP and Other Financial
Measures" section of this MD&A.
(7)
Calculated as natural gas sales divided by sales volumes.
(8)
Natural gas production volumes approximate sales volumes.
(1)
Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are
disclosed in the Advisory section of this MD&A and in note 1 to the Company's audited consolidated financial statements.
15
Canadian Natural 2024 Annual Report
CONSOLIDATED NET EARNINGS AND ADJUSTED NET EARNINGS FROM OPERATIONS
For 2024, the Company reported net earnings of $6,106 million compared with $8,233 million for 2023 (2022 – $10,937 million).
Net earnings for 2024 included non-operating losses, net of tax, of $1,308 million compared with non-operating losses of
$300 million for 2023 (2022 – non-operating losses of $1,926 million) related to the effects of share-based compensation, risk
management activities, fluctuations in foreign exchange rates, realized foreign exchange on the repayment of US dollar debt
securities, the gain from investments, a recoverability charge related to the notice to withdraw from Block 11B/12B in South
Africa in 2024, and a recoverability charge related to the increase in estimate of the future abandonment costs for the Ninian
field in the North Sea in 2024 and 2023. Excluding these items, adjusted net earnings from operations for 2024 were
$7,414 million compared with $8,533 million for 2023 (2022 – $12,863 million).
The decrease in net earnings and adjusted net earnings from operations for 2024 compared with 2023 primarily reflected:
▪
lower realized natural gas pricing in the North America Exploration and Production segment; and
▪
lower netbacks(1) in the Oil Sands Mining and Upgrading segment;
partially offset by:
▪
higher realized crude oil and NGLs pricing(1) in the North America Exploration and Production segment; and
▪
higher 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 depletion, depreciation and amortization, share-based compensation, risk management activities, fluctuations in
foreign exchange rates, and the gain from investments also contributed to the decrease in net earnings for 2024 from 2023.
These items are discussed in detail in the relevant sections of this MD&A.
CASH FLOWS FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW
Cash flows from operating activities for 2024 were $13,386 million compared with $12,353 million for 2023 (2022 –
$19,391 million). The increase in cash flows from operating activities for 2024 from 2023 were primarily due to the factors
previously noted related to the fluctuations in adjusted net earnings from operations, together with the impact of net changes in
non-cash working capital.
Adjusted funds flow for 2024 was $14,859 million ($6.99 per common share(2)) compared with $15,274 million ($7.00 per
common share(2)) for 2023 (2022 – $19,791 million; $8.72 per common share(2)). The decrease in adjusted funds flow for 2024
from 2023 was primarily due to the factors noted above related to the increase in cash flows from operating activities, excluding
the impact of the net change in non-cash working capital, abandonment expenditures, and movements in other long-term
assets, including the unamortized cost of contributions to the Company's employee bonus program, accrued interest on PRT
recoveries, and prepaid cost of service tolls.
PRODUCTION VOLUMES
Record crude oil and NGLs production before royalties for 2024 of 1,005,603 bbl/d increased 3% from 973,530 bbl/d in 2023
(2022 – 933,149 bbl/d). Natural gas production before royalties for 2024 averaged 2,147 MMcf/d, comparable with
2,151 MMcf/d in 2023 (2022 – 2,090 MMcf/d). Total production before royalties for 2024 of 1,363,496 BOE/d was comparable
with 1,332,105 BOE/d in 2023 (2022 – 1,281,434 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 2024 realized crude oil and NGLs prices increased 7% to average
$77.76 per bbl from $72.36 per bbl in 2023 (2022 – $90.64 per bbl), and the 2024 realized natural gas price decreased 40% to
average $1.86 per Mcf from $3.10 per Mcf in 2023 (2022 – $6.55 per Mcf). In the Oil Sands Mining and Upgrading segment, the
Company's 2024 realized SCO sales price averaged $98.03 per bbl, comparable with $100.06 per bbl in 2023 (2022 –
$117.69 per bbl). The Company's realized pricing reflected prevailing benchmark pricing. Crude oil and NGLs and natural gas
prices are discussed in detail in the "Business Environment and Outlook", "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.
(2)
Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are
disclosed in the Advisory section of this MD&A and in note 1 to the Company's audited consolidated financial statements.
Canadian Natural 2024 Annual Report
16
PRODUCTION EXPENSE
In the Company’s Exploration and Production segments, the 2024 crude oil and NGLs production expense(1) decreased 9% to
average $14.72 per bbl from $16.12 per bbl in 2023 (2022 – $18.17 per bbl), and natural gas production expense(1) averaged
$1.22 per Mcf in 2024, a decrease of 6% from $1.30 per Mcf in 2023 (2022 – $1.22 per Mcf). In the Oil Sands Mining and
Upgrading segment, the 2024 production expense(1) averaged $22.88 per bbl, a decrease of 6% from $24.32 per bbl in 2023
(2022 – $26.04 per bbl). Crude oil and NGLs and natural gas production expense is discussed in detail in the "Production
Expense – Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.
SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company’s quarterly financial results for the eight most recently completed quarters:
($ millions, except per common share amounts)
2024
Total
Dec 31
Sep 30
Jun 30
Mar 31
Product sales (1)
$
41,509
$
11,064
$
10,401
$
10,622
$
9,422
Crude oil and NGLs
$
39,084
$
10,381
$
9,943
$
10,084
$
8,676
Natural gas
$
1,568
$
451
$
257
$
331
$
529
Net earnings
$
6,106
$
1,138
$
2,266
$
1,715
$
987
Net earnings per common share (2)
– basic
$
2.87
$
0.54
$
1.07
$
0.80
$
0.46
– diluted
$
2.85
$
0.54
$
1.06
$
0.80
$
0.46
2023
Total
Dec 31
Sep 30
Jun 30
Mar 31
Product sales (1)
$
40,835
$
10,679
$
11,762
$
8,846
$
9,548
Crude oil and NGLs
$
37,300
$
9,829
$
10,944
$
8,115
$
8,412
Natural gas
$
2,575
$
603
$
599
$
522
$
851
Net earnings
$
8,233
$
2,627
$
2,344
$
1,463
$
1,799
Net earnings per common share (2)
– basic
$
3.77
$
1.22
$
1.08
$
0.67
$
0.82
– diluted
$
3.74
$
1.21
$
1.06
$
0.66
$
0.81
(1)
Further details related to product sales are disclosed in note 22 to the Company's audited consolidated financial statements.
(2)
Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are
disclosed in the Advisory section of this MD&A and in note 1 to the Company's audited consolidated financial statements.
Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to:
▪
Crude oil pricing – Fluctuations in 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 the conflicts in the Middle East
and in Ukraine) on worldwide benchmark pricing, the impact of shale oil production in North America, the impact of the
start-up of the TMX pipeline, 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 – Fluctuations in both the demand for natural gas and inventory storage levels, the impact of 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 Kirby and Jackfish, fluctuations in production due to
the cyclic nature of Primrose, fluctuations in the Company’s drilling program in the North America Exploration and
Production segment, natural field decline rates, the impact of turnarounds and pitstops in the Oil Sands Mining and
Upgrading segment, the impact and timing of acquisitions, including the acquisition of working interests in AOSP and
Duvernay assets from Chevron in the fourth quarter of 2024, wildfires, and a third-party pipeline outage in 2023 in the North
America Exploration and Production segment. 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 the North America
Exploration and Production segment, the impact and timing of acquisitions, including the acquisition of a working interest in
the Duvernay assets from Chevron in the fourth quarter of 2024, natural field decline rates, the impact of seasonal
conditions, wildfires, and a third-party pipeline outage in 2023 in the North America Exploration and Production segment.
(1)
Calculated as respective production expense divided by respective sales volumes.
17
Canadian Natural 2024 Annual Report
▪
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, fluctuating energy costs, inflationary cost
pressures, cost optimizations across all segments, 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, timing of
acquisitions, 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, a recoverability charge at December 31, 2024 and December 31, 2023 relating to the
increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the
North Sea, and a recoverability charge at June 30, 2024 relating to the notice to withdraw from Block 11B/12B in South
Africa.
▪
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 PRT recoveries.
▪
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. Realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar
denominated debt.
▪
Loss (gain) from investments – Fluctuations due to the loss (gain) from the Company's investment in PrairieSky Royalty
Ltd. shares.
Business Environment and Outlook
Global crude oil benchmark pricing declined in the fourth quarter of 2024 as a result of weaker global demand growth and
concerns of higher non-OPEC+ supply, partially offset by continued supply quota management by OPEC+ and geopolitical
tensions in the Middle East. The start-up of the TMX pipeline in the second quarter of 2024 contributed to a narrowing of the
WCS differential with benefit to the Company's realized product pricing in 2024. Natural gas prices remained low as a result of
higher storage levels in 2024 but recovered slightly during the fourth quarter due to seasonal demand factors and increased
exports.
Subsequent to December 31, 2024, the US government announced tariffs on certain Canadian goods imported into the United
States, with countermeasures subsequently announced by the Canadian government. The effect of these actions may have an
impact on the market and pricing received for the Company's products, increase the cost or reduce the availability of products
in the Company's supply chain, and introduce additional foreign currency volatility. The timing, duration and impact of these
trade actions remain uncertain. The Company will continue to assess the impacts of the tariffs on its business, financial
condition and results.
Liquidity
As at December 31, 2024, the Company had undrawn revolving bank credit facilities of $4,562 million. Including cash and cash
equivalents, the Company had approximately $4,693 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
On January 9, 2025, the Company announced its 2025 operating capital budget(2) targeted at approximately $6,015 million,
which includes capital related to a number of acquisitions for which agreements between parties have been reached, with
closings targeted in the first half of 2025, and subject to regulatory approvals and other customary closing conditions. With this
capital, the Company is targeting near-term production growth in 2025 and mid- and long-term production and capacity growth
in 2026 and beyond. In addition, the Company has approved approximately $135 million of capital, consisting of $90 million
related to carbon capture and $45 million related to a one-time office move scheduled to take place through 2026. The
Company targets $787 million in abandonment expenditures for 2025. Production for 2025 is targeted between 1,510 MBOE/d
and 1,555 MBOE/d.
(1)
Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2)
Forward-looking non-GAAP Financial Measure. The operating capital budget is based on net capital expenditures (Non-GAAP Financial Measure). Refer to the
"Non-GAAP and Other Financial Measures" section of this MD&A for more details on Net Capital Expenditures.
Canadian Natural 2024 Annual Report
18
Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price
volatility, project returns and the balancing of project risks and time horizons. The 2025 capital budget constitutes forward-
looking statements and is based on net capital expenditures (Non-GAAP Financial Measure). Refer to the "Advisory" section of
this MD&A for further details on forward-looking statements.
BENCHMARK COMMODITY PRICES
(Yearly average)
2024
2023
2022
WTI benchmark price (US$/bbl)
$
75.72
$
77.61 $
94.23
Dated Brent benchmark price (US$/bbl)
$
80.75
$
82.61 $
99.80
WCS Heavy Differential from WTI (US$/bbl)
$
14.73
$
18.62 $
18.26
SCO price (US$/bbl)
$
75.09
$
79.64 $
98.66
Condensate benchmark price (US$/bbl)
$
72.94
$
76.55 $
93.69
NYMEX benchmark price (US$/MMBtu)
$
2.27
$
2.74 $
6.64
AECO benchmark price (C$/GJ)
$
1.36
$
2.77 $
5.28
US/Canadian dollar average exchange rate (US$)
$
0.7300
$
0.7409 $
0.7686
US/Canadian dollar year end exchange rate (US$)
$
0.6942
$
0.7573 $
0.7389
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 resulting in product revenues
being impacted by changes in Canadian dollar sales prices relative to the US dollar benchmark prices.
Crude oil sales contracts in North America are typically based on WTI benchmark pricing. WTI averaged US$75.72 per bbl for
2024, comparable with US$77.61 per bbl for 2023 (2022 – US$94.23 per bbl).
Crude oil sales contracts for the Company’s International segments are typically based on Brent benchmark pricing, which is
representative of international markets and overall global supply and demand. Brent averaged US$80.75 per bbl for 2024,
comparable with US$82.61 per bbl for 2023 (2022 – US$99.80 per bbl).
The decrease in WTI and Brent benchmark pricing for 2024 from 2023 primarily reflected weaker global demand growth and
concerns of higher non-OPEC+ supply, partially offset by continued supply quota management by OPEC+, and geopolitical
tensions in the Middle East.
The WCS Heavy Differential averaged US$14.73 per bbl for 2024 compared with US$18.62 per bbl for 2023 (2022 –
US$18.26 per bbl). The narrowing of the WCS Heavy Differential for 2024 from 2023 primarily reflected the start-up of the TMX
pipeline in the second quarter of 2024, combined with stronger US Gulf Coast heavy oil pricing.
The SCO price averaged US$75.09 per bbl for 2024, a decrease of 6% from US$79.64 per bbl for 2023 (2022 – US$98.66 per
bbl). The decrease in SCO pricing for 2024 from 2023 primarily reflected weaker diesel pricing, together with increased
production in the Western Canadian Sedimentary Basin ("WCSB") in 2024.
NYMEX natural gas prices averaged US$2.27 per MMBtu for 2024, a decrease of 17% from US$2.74 per MMBtu for 2023
(2022 – US$6.64 per MMBtu). The decrease in NYMEX natural gas prices for 2024 from 2023 primarily reflected high North
American and European inventory levels resulting from weaker demand following mild winter weather in 2024.
AECO natural gas prices averaged $1.36 per GJ for 2024, a decrease of 51% from $2.77 per GJ for 2023 (2022 – $5.28 per GJ).
The decrease in AECO natural gas prices for 2024 from 2023 reflected high storage inventories resulting from weaker demand
and increased production levels in the WCSB, combined with weaker NYMEX benchmark pricing.
19
Canadian Natural 2024 Annual Report
Analysis of Changes in Product Sales
Changes due to
Changes due to
($ millions)
2022
Volumes
Prices
Other
2023
Volumes
Prices
Other
2024
North America
Crude oil and NGLs
$ 20,755 $
730 $ (4,110) $
— $ 17,375 $
283
$ 1,082
$
—
$ 18,740
Natural gas
4,931
153
(2,709)
—
2,375
3
(963)
—
1,415
Other (1)
217
—
—
(207)
10
—
—
(4)
6
25,903
883
(6,819)
(207)
19,760
286
119
(4) 20,161
North Sea
Crude oil and NGLs
623
(117)
(71)
—
435
30
2
—
467
Natural gas
13
(3)
(3)
—
7
1
(1)
—
7
Other (1)
—
—
—
—
—
—
—
4
4
636
(120)
(74)
—
442
31
1
4
478
Offshore Africa
Crude oil and NGLs
694
1
(118)
—
577
(142)
(1)
—
434
Natural gas
55
(8)
4
—
51
(7)
(2)
—
42
Other (1)
8
—
—
1
9
—
—
(5)
4
757
(7)
(114)
1
637
(149)
(3)
(5)
480
Oil Sands Mining
and Upgrading
Crude oil and NGLs
20,804
1,012
(3,155)
—
18,661
823
(221)
—
19,263
Other (1)
149
—
—
(144)
5
—
—
11
16
20,953
1,012
(3,155)
(144)
18,666
823
(221)
11
19,279
Midstream and
Refining
Midstream activities
80
—
—
(4)
76
—
—
6
82
Refined product sales
and other (1)
906
—
—
20
926
—
—
(113)
813
986
—
—
16
1,002
—
—
(107)
895
Inter-segment
Elimination and
Other (2)
Product sales
290
—
—
28
318
—
—
(116)
202
Other (1)
5
—
—
5
10
—
—
4
14
295
—
—
33
328
—
—
(112)
216
Total
$ 49,530 $
1,768 $ (10,162) $
(301) $ 40,835 $
991
$
(104) $
(213) $ 41,509
(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 2% to $41,509 million for 2024 from $40,835 million for 2023 (2022 – $49,530 million). The increase in
product sales was primarily due to higher realized crude oil and NGLs pricing and sales volumes in North America, together with
higher SCO sales volumes in the Oil Sands Mining and Upgrading segment, partially offset by lower realized natural gas pricing,
and lower realized SCO pricing. Crude oil and NGLs and natural gas pricing are discussed in detail in the "Business Environment
and Outlook", "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 2024, 2% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America
(2023 – 3%; 2022 – 3%). North Sea accounted for 1% of crude oil and NGLs and natural gas product sales for 2024 (2023 – 1%;
2022 – 1%), and Offshore Africa accounted for 1% of crude oil and NGLs and natural gas product sales for 2024 (2023 – 2%;
2022 – 2%).
Canadian Natural 2024 Annual Report
20
Daily Production
DAILY PRODUCTION, BEFORE ROYALTIES
2024
2023
2022
Crude oil and NGLs (bbl/d)
North America – Exploration and Production
509,288
496,100
479,971
North America – Oil Sands Mining and Upgrading (1)
472,245
451,339
425,945
International – Exploration and Production
North Sea
11,536
12,639
12,890
Offshore Africa
12,534
13,452
14,343
Total International (2)
24,070
26,091
27,233
Total Crude oil and NGLs
1,005,603
973,530
933,149
Natural gas (MMcf/d) (3)
North America
2,136
2,139
2,075
International
North Sea
2
2
2
Offshore Africa
9
10
13
Total International
11
12
15
Total Natural gas
2,147
2,151
2,090
Total Barrels of oil equivalent (BOE/d)
1,363,496
1,332,105
1,281,434
Product mix
Light and medium crude oil and NGLs
10%
10%
11%
Pelican Lake heavy crude oil
3%
3%
4%
Primary heavy crude oil
6%
6%
5%
Bitumen (thermal oil)
20%
20%
20%
Synthetic crude oil (1)
35%
34%
33%
Natural gas
26%
27%
27%
Percentage of product sales (1) (4) (5)
Crude oil and NGLs
96%
93%
88%
Natural gas
4%
7%
12%
(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 in this MD&A.
(3)
Natural gas production volumes approximate sales volumes.
(4)
Net of blending and feedstock costs and excluding risk management activities.
(5)
Excluding Midstream and Refining revenue.
21
Canadian Natural 2024 Annual Report
DAILY PRODUCTION, NET OF ROYALTIES
2024
2023
2022
Crude oil and NGLs (bbl/d)
North America – Exploration and Production
408,237
406,534
374,089
North America – Oil Sands Mining and Upgrading (1)
386,171
385,996
351,740
International – Exploration and Production
North Sea
11,509
12,609
12,849
Offshore Africa
11,918
12,183
12,972
Total International
23,427
24,792
25,821
Total Crude oil and NGLs
817,835
817,322
751,650
Natural gas (MMcf/d)
North America
2,091
2,055
1,885
International
North Sea
2
2
2
Offshore Africa
9
10
11
Total International
11
12
13
Total Natural gas
2,102
2,067
1,898
Total Barrels of oil equivalent (BOE/d)
1,168,209
1,161,852
1,068,063
(1)
SCO production net of royalties excludes SCO consumed internally as diesel.
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 2024 production before royalties averaged 1,363,496 BOE/d, comparable with 1,332,105 BOE/d in 2023 (2022 –
1,281,434 BOE/d).
Record crude oil and NGLs production before royalties for 2024 averaged 1,005,603 bbl/d, an increase of 3% from 973,530 bbl/d
for 2023 (2022 – 933,149 bbl/d). The increase in crude oil and NGLs production before royalties for 2024 from 2023 primarily
reflected high utilization in the Oil Sands Mining and Upgrading segment, combined with strong drilling results in the North
America Exploration and Production segment.
Annual crude oil and NGLs production for 2024 was within the Company's previously issued production target of 977,000 bbl/d
and 1,008,000 bbl/d. Annual crude oil and NGLs production for 2025 is targeted to average between 1,106,000 bbl/d and
1,142,000 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 26% of the Company's total production in 2024 on a BOE basis. Natural
gas production before royalties for 2024 averaged 2,147 MMcf/d, comparable with 2,151 MMcf/d for 2023 (2022 –
2,090 MMcf/d).
Annual natural gas production for 2024 was within the Company's previously issued production target of 2,120 MMcf/d and
2,230 MMcf/d. Annual natural gas production for 2025 is targeted to average between 2,425 MMcf/d and 2,480 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
Record North America crude oil and NGLs production before royalties for 2024 averaged 509,288 bbl/d, an increase of 3% from
496,100 bbl/d for 2023 (2022 – 479,971 bbl/d). The increase in North America crude oil and NGLs production for 2024 from 2023
primarily reflected increased production from thermal oil pad additions, and strong drilling results for liquids-rich natural gas and
heavy oil, partially offset by natural field declines.
Thermal oil production before royalties for 2024 averaged 271,011 bbl/d, an increase of 3% from 262,000 bbl/d for 2023 (2022 –
252,018 bbl/d). The increase in thermal oil production for 2024 from 2023 primarily reflected pad additions at Kirby and Jackfish,
partially offset by the cyclical nature of Primrose and natural field declines.
Pelican Lake heavy crude oil production before royalties averaged 44,779 bbl/d for 2024, a decrease of 5% from 47,078 bbl/d for
2023 (2022 – 50,333 bbl/d) reflecting Pelican Lake's long life low decline production.
North America natural gas production before royalties for 2024 averaged 2,136 MMcf/d, comparable with 2,139 MMcf/d for
2023 (2022 – 2,075 MMcf/d).
Canadian Natural 2024 Annual Report
22
North America – Oil Sands Mining and Upgrading
Record SCO production before royalties for 2024 averaged 472,245 bbl/d, an increase of 5% from 451,339 bbl/d for 2023
(2022 – 425,945 bbl/d). The increase in SCO production for 2024 from 2023 primarily reflected strong performance and
utilization at Horizon following the completion of the reliability enhancement project, and the acquisition of Chevron's assets in
December 2024 at AOSP.
International – Exploration and Production
International crude oil and NGLs production before royalties for 2024 averaged 24,070 bbl/d, a decrease of 8% from
26,091 bbl/d for 2023 (2022 – 27,233 bbl/d). The decrease in crude oil and NGLs production for 2024 from 2023 reflected natural
field declines.
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 production held in various storage
facilities or FPSOs, as follows:
(bbl)
2024
2023
2022
International
1,051,540
515,543
390,959
Exploration and Production
OPERATING HIGHLIGHTS
2024
2023
2022
Crude oil and NGLs ($/bbl) (1)
Realized price (2)
$
77.76
$
72.36 $
90.64
Transportation (2)
5.50
4.23
4.13
Realized price, net of transportation (2)
72.26
68.13
86.51
Royalties (3)
14.85
12.55
18.91
Production expense (4)
14.72
16.12
18.17
Netback (2)
$
42.69
$
39.46 $
49.43
Natural gas ($/Mcf) (1)
Realized price (5)
$
1.86
$
3.10 $
6.55
Transportation (6)
0.62
0.56
0.51
Realized price, net of transportation
1.24
2.54
6.04
Royalties (3)
0.05
0.13
0.61
Production expense (4)
1.22
1.30
1.22
Netback (7)
$
(0.03) $
1.11 $
4.21
Barrels of oil equivalent ($/BOE) (1)
Realized price (2)
$
50.82
$
50.54 $
70.07
Transportation (2)
4.78
3.88
3.72
Realized price, net of transportation (2)
46.04
46.66
66.35
Royalties (3)
8.96
7.77
12.75
Production expense (4)
11.73
12.74
13.76
Netback (2)
$
25.35
$
26.15 $
39.84
(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.
(7)
Natural gas netbacks exclude NGLs netbacks derived from the Company's liquids-rich natural gas plays.
23
Canadian Natural 2024 Annual Report
REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION
2024
2023
2022
Crude oil and NGLs ($/bbl) (1)
North America (2)
$
76.37
$
70.51 $
88.43
International average (3)
$
108.80
$
107.46 $
128.41
North Sea (3)
$
111.53
$
110.99 $
129.04
Offshore Africa (3)
$
106.00
$
106.25 $
127.85
Crude oil and NGLs average (2)
$
77.76
$
72.36 $
90.64
Natural gas ($/Mcf) (1) (3)
North America
$
1.81
$
3.04 $
6.51
International average
$
12.01
$
12.81 $
12.78
North Sea
$
9.93
$
10.45 $
15.75
Offshore Africa
$
12.46
$
13.19 $
12.23
Natural gas average
$
1.86
$
3.10 $
6.55
Average ($/BOE) (1) (2)
$
50.82
$
50.54 $
70.07
(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 8% to average $76.37 per bbl for 2024 from $70.51 per bbl for 2023
(2022 – $88.43 per bbl), primarily reflecting the narrowing of the WCS Heavy Differential.
The Company remains focused on its crude oil blending and marketing strategy, which includes expanding market access
within existing pipeline infrastructure, supporting pipeline projects that increase transportation capacity to new markets, and
collaborating with refiners to enhance heavy conversion capacity. During 2024, the Company contributed approximately
212,000 bbl/d of heavy crude oil blends to the WCS stream.
The Company has 20-year transportation agreements to ship 169,000 bbl/d of crude oil on the Trans Mountain Pipeline
Expansion that provides waterborne access to international markets.
North America realized natural gas prices decreased 40% to average $1.81 per Mcf for 2024 from $3.04 per Mcf for 2023
(2022 – $6.51 per Mcf). The decrease in realized natural gas prices per Mcf for 2024 from 2023 reflected lower AECO
benchmark pricing.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
(Yearly average)
2024
2023
2022
Wellhead Price (1)
Light and medium crude oil and NGLs ($/bbl)
$
69.42
$
70.72 $
88.24
Pelican Lake heavy crude oil ($/bbl)
$
82.83
$
77.69 $
96.18
Primary heavy crude oil ($/bbl)
$
81.97
$
75.67 $
93.80
Bitumen (thermal oil) ($/bbl)
$
76.57
$
67.62 $
85.51
Natural gas ($/Mcf)
$
1.81
$
3.04 $
6.51
(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 averaged $108.80 per bbl for 2024, comparable with $107.46 per bbl for 2023
(2022 – $128.41 per bbl). Realized crude oil and NGLs prices per bbl in any particular year are dependent on the terms of the
various sales contracts, the frequency and timing of liftings from each field, and prevailing Brent benchmark prices and foreign
exchange rates at the time of lifting.
Canadian Natural 2024 Annual Report
24
ROYALTIES – EXPLORATION AND PRODUCTION
2024
2023
2022
Crude oil and NGLs ($/bbl) (1)
North America
$
15.40
$
12.89 $
19.64
International average
$
2.75
$
5.99 $
6.38
North Sea
$
0.26
$
0.33 $
0.30
Offshore Africa
$
5.30
$
10.08 $
11.79
Crude oil and NGLs average
$
14.85
$
12.55 $
18.91
Natural gas ($/Mcf) (1)
North America
$
0.04
$
0.13 $
0.61
Offshore Africa
$
0.57
$
0.62 $
1.50
Natural gas average
$
0.05
$
0.13 $
0.61
Average ($/BOE) (1)
$
8.96
$
7.77 $
12.75
(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 production, capital and
abandonment costs incurred.
North America crude oil and NGLs and natural gas royalties for 2024 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 20% of product sales for 2024, compared with 18% of product sales
for 2023 (2022 – 22%). The increase in royalty rates for 2024 from 2023 primarily reflected increased realized heavy oil and
bitumen pricing in 2024.
Natural gas royalty rates averaged approximately 2% of product sales for 2024, compared with 4% of product sales for 2023
(2022 – 9%). The decrease in royalty rates for 2024 from 2023 primarily reflected lower benchmark pricing.
Offshore Africa
Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing,
capital expenditures and production expenses, the status of payouts, and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 5% for 2024 compared with 9% of product sales for
2023 (2022 – 9%). Royalty rates as a percentage of product sales reflected the timing of liftings and the status of payout in the
various fields.
PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION
2024
2023
2022
Crude oil and NGLs ($/bbl) (1)
North America
$
12.55
$
14.46 $
16.25
International average
$
62.99
$
48.16 $
51.01
North Sea
$
103.28
$
85.57 $
88.99
Offshore Africa
$
21.77
$
21.14 $
17.25
Crude oil and NGLs average
$
14.72
$
16.12 $
18.17
Natural gas ($/Mcf) (1)
North America
$
1.19
$
1.27 $
1.19
International average
$
6.51
$
7.26 $
5.16
North Sea
$
8.95
$
9.85 $
9.27
Offshore Africa
$
5.98
$
6.83 $
4.40
Natural gas average
$
1.22
$
1.30 $
1.22
Average ($/BOE) (1)
$
11.73
$
12.74 $
13.76
(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.
(1)
Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
25
Canadian Natural 2024 Annual Report
North America
North America crude oil and NGLs production expense for 2024 averaged $12.55 per bbl, a decrease of 13% from
$14.46 per bbl for 2023 (2022 – $16.25 per bbl). The decrease in crude oil and NGLs production expense per bbl for 2024 from
2023 primarily reflected lower energy costs.
North America natural gas production expense for 2024 averaged $1.19 per Mcf, a decrease of 6% from $1.27 per Mcf for 2023
(2022 – $1.19 per Mcf). The decrease in natural gas production expense per Mcf for 2024 from 2023 primarily reflected lower
energy costs and maintenance activities.
International
International crude oil and NGLs production expense for 2024 averaged $62.99 per bbl, an increase of 31% from $48.16 per bbl
for 2023 (2022 – $51.01 per bbl). The increase in crude oil and NGLs production expense per bbl for 2024 from 2023 reflected
the timing of liftings from various fields that have different cost structures and the impact of foreign exchange.
ADJUSTED DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION
($ millions, except per BOE amounts)
2024
2023
2022
North America
$
3,831
$
3,679 $
3,595
North Sea
279
494
1,747
Offshore Africa
297
213
173
Depletion, Depreciation and Amortization
$
4,407
$
4,386 $
5,515
Less: Recoverability charge (1) (2)
222
436
1,620
Adjusted depletion, depreciation and amortization (3)
$
4,185
$
3,950 $
3,895
$/BOE (4)
$
12.92
$
12.27 $
12.45
(1)
As at December 31, 2024, as a result of refined project scope and cost estimates associated with abandonment activities, the Company recognized a
recoverability charge of $160 million (December 31, 2023 – $436 million; December 31, 2022 – $1,620 million) in depletion, depreciation and amortization
expense related to an increase in its estimate of future abandonment costs for the Ninian field in the North Sea.
(2)
In connection with the Company’s notice of withdrawal from Block 11B/12B in South Africa in the second quarter of 2024, the Company derecognized
$62 million of exploration and evaluation assets through depletion, depreciation and amortization expense.
(3)
This is a non-GAAP financial measure used to calculate depletion, depreciation and amortization, less the impact of charges that are not related to current
period normal course depletion, depreciation and amortization expense such as asset recoverability charges that are not related to current period production.
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 an indication of the
Company's performance.
(4)
This is a non-GAAP ratio calculated as adjusted depletion, depreciation and amortization expense divided by sales volumes. For sales volumes, refer to the
"Non-GAAP and Other Financial Measures" section of this MD&A.
Adjusted depletion, depreciation and amortization expense for 2024 of $12.92 per BOE increased 5% from $12.27 per BOE for
2023 (2022 – $12.45 per BOE). The increase in adjusted depletion, depreciation and amortization expense per BOE for 2024
from 2023 primarily reflected the impact of changes in North America depletion rates due to changes in reserve estimates at
December 31, 2023.
Adjusted depletion, depreciation and amortization expense on an absolute and per BOE basis also reflects the impact of the
timing of liftings from each field in the North Sea and Offshore Africa.
ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION
($ millions, except per BOE amounts)
2024
2023
2022
North America
$
231
$
234 $
171
North Sea
65
46
33
Offshore Africa
9
8
7
Asset Retirement Obligation Accretion
$
305
$
288 $
211
$/BOE (1)
$
0.94
$
0.89 $
0.67
(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 2024 of $0.94 per BOE increased 6% from
$0.89 per BOE for 2023 (2022 – $0.67 per BOE). The increase in asset retirement obligation accretion expense per BOE for
2024 from 2023 primarily reflected the impact of the Company's estimate for future abandonment costs for the Ninian field in
the North Sea at December 31, 2023.
Canadian Natural 2024 Annual Report
26
Oil Sands Mining and Upgrading
OPERATING HIGHLIGHTS
The Company continues to focus on safe, reliable and efficient operations, leveraging its technical expertise across the Horizon
and AOSP sites, resulting in record SCO production averaging 472,245 bbl/d in 2024.
REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING
($/bbl)
2024
2023
2022
Realized SCO sales price (1)
$
98.03
$
100.06 $
117.69
Bitumen value for royalty purposes (2)
$
72.68
$
65.43 $
83.07
Bitumen royalties (3)
$
17.23
$
14.43 $
20.71
Transportation (1)
$
2.91
$
1.89 $
1.71
(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 $98.03 per bbl for 2024, comparable with $100.06 per bbl for 2023 (2022 –
$117.69 per bbl).
Bitumen royalties averaged $17.23 per bbl for 2024, an increase from $14.43 per bbl for 2023 (2022 – $20.71 per bbl) primarily
reflecting an increase in average bitumen pricing for royalty purposes in 2024.
Transportation expense averaged $2.91 per bbl for 2024, an increase of 54% from $1.89 per bbl for 2023 (2022 – $1.71 per bbl).
The increase in transportation expense per bbl for 2024 from 2023 primarily reflected volumes being shipped on the TMX
pipeline beginning in 2024.
PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and Upgrading production expense disclosed in note 22 to the
Company’s audited consolidated financial statements.
($ millions)
2024
2023
2022
Production expense, excluding natural gas costs
$
3,801
$
3,794 $
3,743
Natural gas costs
120
195
333
Production expense
$
3,921
$
3,989 $
4,076
($/bbl)
2024
2023
2022
Production expense, excluding natural gas costs (1)
$
22.18
$
23.13 $
23.91
Natural gas costs (2)
0.70
1.19
2.13
Production expense (3)
$
22.88
$
24.32 $
26.04
Sales volumes (bbl/d)
468,280
449,282
428,820
(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.
The Company incurred production expense of $3,921 million for 2024, comparable with $3,989 million for 2023 (2022 –
$4,076 million), reflecting the Company's continued focus on cost control and driving efficiencies across the Oil Sands Mining
and Upgrading segment.
Production expense for 2024 of $22.88 per bbl decreased 6% from $24.32 per bbl for 2023 (2022 – $26.04 per bbl). The
decrease in production expense per bbl for 2024 as compared to 2023 reflected higher production volumes from strong
utilization, combined with lower energy costs.
27
Canadian Natural 2024 Annual Report
DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING
($ millions, except per bbl amounts)
2024
2023
2022
Depletion, depreciation and amortization
$
2,258
$
2,011 $
1,822
$/bbl (1)
$
13.17
$
12.26 $
11.64
(1)
Calculated as depletion, depreciation and amortization divided by sales volumes.
Depletion, depreciation and amortization expense for 2024 of $13.17 per bbl increased 7% from $12.26 per bbl for 2023 (2022 –
$11.64 per bbl), primarily reflecting derecognitions related to the Horizon turnaround in the second quarter of 2024, partially
offset by higher sales volumes in 2024.
ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING
($ millions, except per bbl amounts)
2024
2023
2022
Asset retirement obligation accretion
$
84
$
78 $
70
$/bbl (1)
$
0.49
$
0.48 $
0.45
(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 2024 of $0.49 per bbl was comparable with $0.48 per bbl for 2023 (2022 –
$0.45 per bbl).
Midstream and Refining
($ millions)
2024
2023
2022
Product sales
Midstream activities
$
82
$
76 $
80
NWRP, refined product sales and other
813
926
906
Segmented revenue
895
1,002
986
Less:
NWRP, refining toll
295
303
247
Midstream activities
20
29
24
Production expense
315
332
271
NWRP, transportation and feedstock costs
685
664
691
Depreciation
16
16
16
Segmented (loss) earnings
$
(121) $
(10) $
8
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 crude oil production is transported through its fully owned and operated Pelican Lake and ECHO pipelines to
Edmonton and Hardisty, Alberta, providing access to international export pipelines. Ownership of these midstream pipeline
assets enables the Company to control transportation costs and generate third-party revenue.
NWRP operates a 50,000 bbl/d bitumen upgrader and refinery that processes approximately 12,500 bbl/d of bitumen feedstock
for the Company (25% toll payer) and 37,500 bbl/d of bitumen feedstock for the Alberta Petroleum Marketing Commission
("APMC") (75% toll payer), 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 2024 averaged 76,664 BOE/d (19,166 BOE/d to the Company) (2023 –
81,525 BOE/d; 20,381 BOE/d to the Company; 2022 – 58,351 BOE/d; 14,588 BOE/d to the Company), reflecting the 25% toll
payer commitment.
During 2024, NWRP repaid $500 million of 3.20% series A bonds. Additionally, in 2024 NWRP issued $700 million of 4.85%
series P bonds due June 2034 and $600 million of 5.08% series Q bonds due June 2054.
During 2024, NWRP entered into a $2,000 million unsecured commercial paper program and reserves capacity under its
revolving credit facility for these amounts.
Canadian Natural 2024 Annual Report
28
NWRP's credit facilities consist of a $2,150 million syndicated credit facility (December 31, 2023 – $3,115 million) comprised of
a $1,900 million revolving portion maturing June 2027 (December 31, 2023 – $2,175 million), and a $250 million non-revolving
portion maturing June 2025 (December 31, 2023 – $940 million). The syndicated credit facility reserves capacity for a debt
service reserve equal to six months of anticipated facility interest and fees, and for amounts outstanding under its commercial
paper program.
During 2024, NWRP amended its syndicated credit facility to extend the revolving portion originally maturing June 2025 to June
2027, and reduce the authorized limit on the revolving portion by $275 million to $1,900 million. In 2024, NWRP repaid
$657 million on its non-revolving facility, and reduced the authorized limit to $250 million.
NWRP also has dedicated short-term borrowings under a $300 million syndicated credit facility ("demand operating facility")
(December 31, 2023 – $300 million), and $300 million uncommitted demand revolving letter of credit facilities ("bilateral
facilities") (December 31, 2023 – $150 million).
During 2024, NWRP increased its availability on its bilateral facilities, supporting letters of credit, to $300 million (December 31,
2023 – $150 million).
As at December 31, 2024, NWRP had borrowings of $251 million under the syndicated credit facility (December 31, 2023 –
$2,559 million), $1,459 million under its commercial paper program (December 31, 2023 – $nil), and $103 million under its
demand operating facility (December 31, 2023 – $77 million).
As at December 31, 2024, NWRP had $8,750 million in long-term notes outstanding (December 31, 2023 – $7,950 million).
As at December 31, 2024, the cumulative unrecognized share of the equity loss and partnership distributions from NWRP was
$509 million (2023 – $555 million). The recovery of unrecognized equity losses from NWRP for 2024 was $46 million (2023 –
unrecognized equity loss of $4 million; 2022 – recovery of unrecognized equity losses of $11 million).
Corporate and Other
ADMINISTRATION EXPENSE
($ millions, except per BOE amounts)
2024
2023
2022
Expense
$
503
$
452 $
415
$/BOE (1)
$
1.02
$
0.93 $
0.88
Sales volumes (BOE/d) (2)
1,353,166
1,331,092
1,285,877
(1)
Calculated as administration expense divided by sales volumes.
(2)
Total Company sales volumes.
Administration expense for 2024 of $1.02 per BOE increased 10% from $0.93 per BOE for 2023 (2022 – $0.88 per BOE).
Administration expense per BOE increased from 2023 primarily reflecting higher personnel costs, partially offset by higher
overhead recoveries.
SHARE-BASED COMPENSATION
($ millions)
2024
2023
2022
Share-based compensation expense
$
279
$
491 $
804
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 with reference to the value of the Company's
shares, and by individual employee performance and the extent to which certain other performance measures are met.
The Company recognized $279 million of share-based compensation expense for 2024, 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 $77 million related to PSUs granted to certain executive employees was included in
the share-based compensation expense for 2024 (2023 – $70 million expense; 2022 – $101 million expense).
29
Canadian Natural 2024 Annual Report
INTEREST AND OTHER FINANCING EXPENSE
($ millions, except effective interest rate)
2024
2023
2022
Interest and other financing expense
$
592
$
636 $
549
Less: Interest (income) and other expense (1)
(81)
(55)
(121)
Interest expense on long-term debt and lease liabilities (1)
$
673
$
691 $
670
Average current and long-term debt (2)
$
11,895
$
12,749 $
13,986
Average lease liabilities (2)
1,509
1,500
1,531
Average long-term debt and lease liabilities (2)
$
13,404
$
14,249 $
15,517
Average effective interest rate (3) (4)
4.9%
4.8%
4.3%
Interest and other financing expense ($/BOE) (5)
$
1.20
$
1.31 $
1.17
Sales volumes (BOE/d) (6)
1,353,166
1,331,092
1,285,877
(1)
Item is a component of interest and other financing expense.
(2)
The average of current and long-term debt and lease liabilities outstanding during the respective year.
(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 average interest expense on long-term debt and lease liabilities divided by the average long-term debt and lease liabilities balance for the
respective year. 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 for 2024 decreased 8% to $1.20 per BOE from $1.31 per BOE for 2023 (2022 – $1.17 per
BOE). The decrease in interest and other financing expense per BOE for 2024 from 2023 primarily reflected lower average debt
levels.
The Company’s average effective interest rate of 4.9% for 2024 increased from 4.8% for 2023 primarily reflecting higher
prevailing interest rates on long-term debt held during 2024.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency
exposures. These derivative financial instruments are not intended for trading or speculative purposes.
($ millions)
2024
2023
2022
Foreign currency contracts
$
155
$
(17) $
(37)
Natural gas financial instruments (1) (2) (3)
13
3
13
Crude oil and NGLs financial instruments (1)
—
—
17
Net realized loss (gain)
168
(14)
(7)
Foreign currency contracts
15
(9)
(16)
Natural gas financial instruments (1) (2) (3)
(6)
21
(10)
Crude oil and NGLs financial instruments (1)
—
—
(2)
Net unrealized loss (gain)
9
12
(28)
Net loss (gain)
$
177
$
(2) $
(35)
(1)
Certain commodity financial instruments were assumed in the acquisition of Storm Resources Ltd. ("Storm") in 2021, and Painted Pony Energy Ltd. ("Painted
Pony") in 2020.
(2)
In the fourth quarter of 2024, the Company entered into fixed price financial contracts to buy 12,500 MMBtu/d of natural gas at US$1.47 AECO, and 25,000
MMBtu/d of natural gas at US$1.82 AECO for the period of January to December 2025.
(3)
In the fourth quarter of 2023, the Company entered into fixed price financial contracts to buy 50,000 MMBtu/d of natural gas at US$1.82 AECO for the period
of January to December 2024.
During 2024, net realized risk management losses were related to the settlement of foreign currency contracts and natural gas
financial instruments. The Company recorded a net unrealized loss of $9 million ($10 million after-tax of $1 million) on its risk
management activities for 2024 (2023 – $12 million unrealized loss, $7 million after-tax of $5 million; 2022 – $28 million
unrealized gain, $25 million after-tax of $3 million).
Further details related to outstanding derivative financial instruments as at December 31, 2024 are disclosed in note 19 to the
Company's audited consolidated financial statements.
Canadian Natural 2024 Annual Report
30
FOREIGN EXCHANGE
($ millions)
2024
2023
2022
Net realized loss (gain)
$
67
$
(19) $
(114)
Net unrealized loss (gain)
888
(260)
852
Net loss (gain) (1)
$
955
$
(279) $
738
(1)
Amounts are reported net of the hedging effect of any cross currency swaps.
The net realized foreign exchange loss for 2024 was primarily related to the repayment of US dollar debt, partially offset by
foreign exchange rate fluctuations on the settlement of working capital items denominated in US dollars. The net unrealized
foreign exchange loss for 2024 was primarily related to the translation of outstanding US dollar debt, partially offset by the
repayment of the US dollar debt during the second quarter of 2024. The US/Canadian dollar exchange rate at December 31,
2024 was US$0.6942 (December 31, 2023 – US$0.7573, December 31, 2022 – US$0.7389).
INCOME TAXES
($ millions, except effective tax rates)
2024
2023
2022
North America (1)
$
1,654
$
1,853 $
2,789
North Sea
(41)
(6)
69
Offshore Africa
57
73
74
Current PRT – North Sea
(134)
(58)
(42)
Other taxes
(5)
17
16
Current income tax
1,531
1,879
2,906
Deferred corporate income tax
520
267
302
Deferred PRT – North Sea
(98)
(214)
(441)
Deferred income tax
422
53
(139)
Income tax
$
1,953
$
1,932 $
2,767
Earnings before taxes
$
8,059
$
10,165 $
13,704
Effective tax rate on net earnings (2)
24%
19%
20%
($ millions, except effective tax rates)
2024
2023
2022
Income tax
$
1,953
$
1,932 $
2,767
Tax effect on non-operating items (3)
175
345
964
Current PRT – North Sea
134
58
42
Deferred PRT – North Sea
9
9
—
Other taxes
5
(17)
(16)
Effective tax on adjusted net earnings
$
2,276
$
2,327 $
3,757
Adjusted net earnings from operations (4)
$
7,414
$
8,533 $
12,863
Adjusted net earnings from operations, before taxes
$
9,690
$
10,860 $
16,620
Effective tax rate on adjusted net earnings from operations (5) (6)
23%
21%
23%
(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 before taxes.
(3)
Includes the net income tax effect on PSUs, certain stock options, unrealized risk management, government grant income related to abandonment
expenditures in 2022, and recoverability charges related to the increase in future abandonment costs for Ninian field in the North Sea, and the notice to
withdraw from Block 11B/12B in South Africa.
(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 financial statements, as applicable, as an indication of the Company's
performance.
(6)
Calculated as effective tax on adjusted net earnings divided by adjusted net earnings from operations, before taxes. The Company presents its effective tax
rate on adjusted net earnings 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 and adjusted net earnings from operations for 2024 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.
The current and deferred corporate income tax and the current and deferred PRT in the North Sea included the impact of
carrybacks of abandonment expenditures related to the decommissioning activities at the Company's platforms in the North
31
Canadian Natural 2024 Annual Report
Sea. Deferred PRT and income taxes also reflected the impact of the recoverability charges recognized in depletion,
depreciation, and amortization expense.
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 2024, the Company filed Scientific Research and Experimental Development claims of approximately $273 million
(2023 – $380 million; 2022 – $283 million) relating to qualifying research and development expenditures for Canadian income tax
purposes.
Net Capital Expenditures (1) (2)
($ millions)
2024
2023
2022
EXPLORATION AND PRODUCTION
Exploration and Evaluation Assets
Net expenditures
$
82
$
47 $
36
Net property acquisitions (dispositions) (3)
330
(3)
(3)
Total Exploration and Evaluation Assets
412
44
33
Property, Plant and Equipment
Net property acquisitions (3)
2,642
24
513
Well drilling, completion and equipping
1,832
1,579
1,545
Production and related facilities
1,336
1,267
1,233
Other
53
61
59
Total Property, Plant and Equipment
5,863
2,931
3,350
Total Exploration and Production
6,275
2,975
3,383
OIL SANDS MINING AND UPGRADING
Project costs
306
348
294
Sustaining capital
1,466
1,347
1,171
Turnaround costs
153
189
287
Net property acquisitions (dispositions) (3)
6,173
5
(40)
Other
6
5
7
Total Oil Sands Mining and Upgrading
8,104
1,894
1,719
Midstream and Refining
11
10
9
Head office
41
30
25
Net capital expenditures
$
14,431
$
4,909 $
5,136
Abandonment expenditures, net (4)
$
646
$
509 $
335
By Segment
North America
$
6,033
$
2,770 $
3,133
North Sea
39
33
126
Offshore Africa
203
172
124
Oil Sands Mining and Upgrading
8,104
1,894
1,719
Midstream and Refining
11
10
9
Head office
41
30
25
Net capital expenditures
$
14,431
$
4,909 $
5,136
(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. The composition of this measure was updated for all periods presented. Refer to the "Non-GAAP and Other Financial
Measures" section of this MD&A.
(3)
Includes cash consideration paid of $320 million for exploration and evaluation assets and $2,553 million for property, plant and equipment within the North
America Exploration and Production segment, and $6,175 million for property, plant and equipment within the Oil Sands Mining and Upgrading segment
acquired from Chevron in 2024.
(4)
Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
Canadian Natural 2024 Annual Report
32
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 2024 were $14,431 million compared with $4,909 million for 2023. In addition, the Company
reported abandonment expenditures of $646 million for the year ended December 31, 2024 compared with $509 million for the
year ended December 31, 2023.
ACQUISITION OF CHEVRON'S ASSETS
In December 2024, the Company completed the acquisition of Chevron's assets for total cash consideration of $9,163 million,
subject to final closing adjustments. The acquisition includes a 70% operated working interest in the light crude oil and liquids-
rich Duvernay asset play in Alberta and a 20% interest in AOSP. As a result of the acquisition, the Company now has a 90%
direct and indirect working interest in AOSP, which includes the Muskeg River and Jackpine mines, the Scotford Upgrader, and
the Quest Carbon Capture and Storage facility. The acquisition also includes various working interests in a number of other non-
producing oil sands leases. The Company consolidates its interests in the assets, liabilities, revenue, and expenses of both the
AOSP and Duvernay joint operations. Further details are disclosed in note 7 to the Company's audited consolidated financial
statements.
DRILLING ACTIVITY (1) (2)
(number of net wells)
2024
2023
2022
Net successful crude oil wells (3)
307
221
317
Net successful natural gas wells
78
61
72
Dry wells
2
2
1
Total
387
284
390
Success rate
99%
99%
99%
(1)
Includes drilling activity for North America and International segments.
(2)
Excludes stratigraphic and service wells.
(3)
Includes bitumen wells.
North America
During 2024, the Company drilled 79 net natural gas wells, 161 net primary heavy crude oil wells, 10 net Pelican Lake heavy
crude oil wells, 94 net bitumen (thermal oil) wells and 43 net light crude oil wells.
Liquidity and Capital Resources
($ millions, except ratios)
2024
2023
2022
Adjusted working capital (1)
$
174
$
712 $
(1,190)
Long-term debt, net (2)
$
18,688
$
9,922 $
10,525
Shareholders’ equity
$
39,468
$
39,832 $
38,175
Debt to book capitalization (2)
32%
20%
22%
After-tax return on average capital employed (3)
13%
17%
22%
(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.
As at December 31, 2024, 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 are dependent on factors discussed in the "Business Environment and
Outlook" 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
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.
33
Canadian Natural 2024 Annual Report
On an ongoing basis the Company continues to focus on its balance sheet strength and available liquidity by:
▪
Monitoring cash flows from operating activities, which is the primary source of funds;
▪
Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when
appropriate, ensuring parental guarantees or letters of credit are in place, and as applicable, taking other mitigating actions
to minimize the impact in the event of a default;
▪
Actively managing the allocation of 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 2024, the Company extended its $2,425 million revolving syndicated credit facility originally maturing June 2025
to June 2028.
◦
During 2024 and in connection with the acquisition of Chevron's assets, the Company entered into a $4,000 million non-
revolving term credit facility maturing December 2027.
◦
During 2023, the Company extended its $500 million revolving credit facility from February 2024 to
February 2025. During 2024, the Company extended its $500 million revolving credit facility from February 2025 to
February 2026.
◦
During 2023, the Company extended its $2,425 million revolving syndicated credit facility originally maturing June 2024
to June 2027.
◦
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 credit facilities may be made by way of pricing referenced to CORRA, SOFR, US base
rate or Canadian prime rate.
◦
The Company's borrowings under its US commercial paper program are authorized up to a maximum of
US$2,500 million.
◦
During 2024, the Company issued, by private placement, $500 million of 4.15% medium-term notes due
December 2031.
◦
During 2024, the Company repaid $320 million of 3.55% medium-term notes.
◦
During 2023, the Company repaid $405 million of 1.45% medium-term notes.
◦
During 2023, 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 2025. 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 2024, no medium-term notes were issued in Canada under the base shelf prospectus.
◦
During 2024, the Company issued, by private placement, US$750 million of 5.00% notes due December 2029 and
US$750 million of 5.40% notes due December 2034.
◦
During 2024, the Company repaid US$500 million of 3.80% US dollar debt securities.
◦
Subsequent to December 31, 2024, the Company repaid US$600 million of 3.90% US dollar debt securities.
◦
During 2023, 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 2025. 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 2024, no US dollar debt securities were issued in the United States under the base shelf prospectus.
As at December 31, 2024, the Company had undrawn revolving bank credit facilities of $4,562 million. Additionally, the
Company had in place a fully drawn term credit facility of $4,000 million. Including cash and cash equivalents, the Company had
approximately $4,693 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of
credit. As at December 31, 2024, the Company had $672 million drawn under its commercial paper program, and reserves
capacity under its revolving bank credit facilities for amounts outstanding under this program.
As at December 31, 2024, the Company had no cross currency swap contracts outstanding.
Canadian Natural 2024 Annual Report
34
Long-term debt, net was $18,688 million as at December 31, 2024, resulting in a debt to book capitalization ratio of 32%
(December 31, 2023 – 20%, December 31, 2022 – 22%); this ratio was within the 25% to 45% internal range utilized by
management. The ratio may fall below or exceed the targeted range depending on the execution of the Company's capital
program, commodity price and foreign currency volatility, and the timing of acquisitions. 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, 2024, the Company was in compliance with this covenant.
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 as at December 31, 2024 are discussed in note 11 to the
Company’s audited consolidated financial statements.
During 2024, the Company sold its 22.6 million common share investment in PrairieSky Royalty Ltd. for $25.65 per common
share with net proceeds at close, after fees and expenses, of $575 million.
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 as at
December 31, 2024 are discussed in note 19 to the Company’s audited consolidated financial statements.
As at December 31, 2024, the maturity dates of certain financial liabilities, including long-term debt and other long-term
liabilities and related interest payments, were as follows:
Less than
1 year
1 to less than
2 years
2 to less than
5 years
Thereafter
Long-term debt (1)
$
2,400 $
941 $
7,494 $
8,074
Other long-term liabilities (2)
$
263 $
187 $
405 $
617
Interest and other financing expense (3)
$
1,024 $
951 $
1,978 $
3,574
(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, $255 million; one to less than
two years, $187 million; two to less than five years, $405 million; and thereafter, $617 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, 2024.
SHARE CAPITAL(1)
As at December 31, 2024, there were 2,102,996,000 common shares outstanding (December 31, 2023 – 2,144,815,000
common shares) and 50,806,000 stock options outstanding (December 31, 2023 – 52,410,000 stock options). As at March 4,
2025, the Company had 2,100,007,000 common shares outstanding and 57,117,000 stock options outstanding.
On March 5, 2025, the Board of Directors approved a 4% increase in the quarterly dividend to $0.5875 per common share,
beginning with the dividend payable on April 4, 2025.
On October 7, 2024, the Board of Directors approved a 7% increase in the quarterly dividend to $0.5625 per common share,
beginning with the dividend paid on January 3, 2025. On February 28, 2024, the Board of Directors approved a 5% increase in
the quarterly dividend to $0.525 per common share.
On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $0.50 per common share.
On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.45 per common share.
The dividend policy undergoes periodic review by the Board of Directors and is subject to change.
On March 8, 2024, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of
the TSX, alternative Canadian trading platforms, and the NYSE, up to 180,462,858 common shares, representing 10% of the
public float, over a 12-month period commencing March 13, 2024 and ending March 12, 2025.
For the year ended December 31, 2024, the Company purchased 55,350,000 common shares at a weighted average price of
$48.07 per common share for a total cost, including tax, of $2,700 million. Retained earnings were reduced by $2,414 million,
representing the excess of the purchase price of common shares over their average carrying value. Subsequent to
December 31, 2024, up to and including March 4, 2025, the Company purchased 7,740,000 common shares at a weighted
average price of $44.11 per common share for a total cost, including tax, of $344 million.
On March 5, 2025, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with the
TSX to purchase, by way of Normal Course Issuer Bid, up to 10% of the public float (as determined in accordance with the rules
of the TSX) of its issued and outstanding common shares. Subject to acceptance of the Notice of Intention by the TSX, the
purchases will be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE.
(1)
Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are
disclosed in the Advisory section of this MD&A and in note 1 to the Company's audited consolidated financial statements.
35
Canadian Natural 2024 Annual Report
Commitments and Contingencies
In the normal course of business, the Company has committed to certain payments. The following table summarizes the
Company’s commitments as at December 31, 2024:
($ millions)
2025
2026
2027
2028
2029
Thereafter
Product transportation, purchases, and
processing (1) (2) (3)
$
2,249 $
2,245 $
2,097 $
1,983 $
1,882 $
19,310
North West Redwater Partnership
service toll (4)
$
141 $
121 $
103 $
104 $
104 $
4,203
Offshore vessels and equipment
$
88 $
— $
— $
— $
— $
—
Field equipment and power
$
43 $
29 $
29 $
28 $
27 $
216
Other
$
124 $
111 $
21 $
22 $
21 $
247
(1)
The Company's commitment for the 20-year product transportation agreement on the TMX pipeline reflects interim tolls approved by the Canada Energy
Regulator in 2023, and is subject to change pending the approval of final tolls.
(2)
During 2024, the Company increased its total committed capacity on the TMX pipeline to 169,000 bbl/d, an incremental 75,000 bbl/d over the 20-year term.
(3)
During 2024, the acquisition of Chevron's assets included approximately $1,292 million of product transportation and processing commitments and
approximately $75 million of field equipment and power commitments.
(4)
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 $2,161 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.
Subsequent Events
On January 29, 2025, the Company announced that pursuant to an agreement with Shell Canada Limited and affiliates ("Shell")
and as a result of certain conditions being met, the Company will acquire a 10% working interest in the AOSP mines,
associated reserves and additional working interests in a number of other non-producing oil sands leases in exchange for a 10%
working interest in the Scotford Upgrader and Quest. Following the close of the transaction, the Company will have a 100%
direct working interest in the AOSP mines and an 80% interest in the Scotford Upgrader and Quest, where Shell will remain
operator. The transaction does not include an exchange of cash, except for regular closing adjustments for working capital. The
acquisition is targeted to close in the first half of 2025, subject to obtaining the necessary regulatory approvals.
Canadian Natural 2024 Annual Report
36
Reserves
For the years ended December 31, 2024 and 2023, 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, 2024:
Total Proved
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)
December 31, 2023 (1)
218
193
258
3,287
6,910
15,005
543
13,910
Discoveries
—
—
—
—
—
1
—
1
Extensions
15
21
—
57
—
537
22
205
Infill Drilling
2
4
—
3
—
175
13
52
Improved Recovery
—
—
—
1
2
—
—
2
Acquisitions
8
—
—
—
853
1,266
157
1,229
Dispositions
(1)
—
—
—
—
(51)
(2)
(12)
Economic Factors
1
1
—
—
—
(230)
(4)
(41)
Technical Revisions
34
29
13
63
71
987
10
383
Production
(25)
(29)
(16)
(99)
(173)
(786)
(25)
(499)
December 31, 2024 (1)
252
219
255
3,312
7,663
16,904
713
15,231
Total Proved Plus
Probable
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)
December 31, 2023 (1)
305
288
365
5,191
7,460
24,284
848
18,504
Discoveries
1
—
—
—
—
1
—
1
Extensions
21
31
—
75
—
1,169
55
377
Infill Drilling
3
6
—
4
—
268
18
77
Improved Recovery
—
—
—
1
2
—
—
3
Acquisitions
16
—
—
—
904
1,874
233
1,466
Dispositions
(1)
—
—
—
—
(66)
(3)
(15)
Economic Factors
1
1
1
—
—
(269)
(4)
(46)
Technical Revisions
26
20
10
18
62
681
(6)
243
Production
(25)
(29)
(16)
(99)
(173)
(786)
(25)
(499)
December 31, 2024 (1)
346
318
360
5,190
8,255
27,156
1,116
20,110
(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, 2024, the total proved crude oil, bitumen (thermal oil) and NGLs reserves were 12,414 MMbbl, and total
proved plus probable crude oil, bitumen (thermal oil) and NGLs reserves were 15,584 MMbbl. Total proved reserves additions
and revisions replaced 373% of 2024 production. Additions to total proved reserves resulting from exploration and development
activities, acquisitions, dispositions and future offset additions amounted to 1,156 MMbbl, and additions to total proved plus
probable reserves amounted to 1,368 MMbbl. Net positive revisions amounted to 216 MMbbl for total proved reserves and
128 MMbbl for total proved plus probable reserves, primarily due to technical revisions.
At December 31, 2024, the total proved natural gas reserves were 16,904 Bcf, and total proved plus probable natural gas
reserves were 27,156 Bcf. Total proved reserves additions and revisions replaced 342% of 2024 production. Additions to total
proved reserves resulting from exploration and development activities, acquisitions, dispositions and future offset additions
amounted to 1,928 Bcf, and additions to total proved plus probable reserves amounted to 3,247 Bcf.
37
Canadian Natural 2024 Annual Report
Net positive revisions amounted to 757 Bcf for total proved reserves, primarily due to technical revisions. Net positive revisions
amounted to 411 Bcf for total proved plus probable reserves, primarily due to 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 associated with project or facility expansions, or 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 risk associated with exploration and development activities, including associated GHG emissions;
▪
Future legislative and regulatory developments related to environmental regulation, including but not limited to GHG
compliance costs and reduction targets, and emissions caps;
▪
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 approval 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;
▪
International trade risk with key trading partners, including the imposition of tariffs or other trade measures on the
Company's products or goods and services used by the Company in its supply chain, including the imposition of
countermeasures by the government of Canada, the duration and extent of which may be uncertain;
▪
Changing royalty regimes;
▪
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 data security, intellectual property and
operations, and/or result in a material privacy breach;
Canadian Natural 2024 Annual Report
38
▪
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, droughts, 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 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 (as was the case with the COVID-19 pandemic). 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;
▪
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 and NGLs. 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, asset integrity and environmental management systems to recover and process crude oil and natural
gas resources safely and efficiently while being committed to environmental stewardship.
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, 2024.
Environment
The Company has a Corporate Statement on Environmental Management which affirms that environmental stewardship is a
fundamental value of the Company. As part of the Company's commitment to environmental stewardship, the Company
includes and evaluates environmental, social, economic, and health considerations in new project designs and in operations,
where appropriate. The Company invests in people, proven and new technologies (including technologies designed to improve
environmental performance), facilities and infrastructure to recover and process crude oil and natural gas resources efficiently
while supporting its commitment to environmental stewardship. When 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 or accommodate these concerns.
The Company has processes in place and is committed to complying with all existing environmental standards and regulations
and has included appropriate amounts in its capital budget to continue to meet current environmental protection requirements;
however there are no assurances that the effect of future environmental laws and regulations will not be significant to the
Company's business, financial condition and results of operations. 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 take steps to mitigate the effect of
its activities on the environment. To address some of these concerns, the Company’s environmental risk management strategy
includes working constructively with legislators and regulators on any new or revised policies, legislation or regulations to
39
Canadian Natural 2024 Annual Report
reflect a balanced approach to sustainable development. However, increasingly stringent laws and regulations may have an
adverse effect on the Company’s future net earnings.
The environmental risk management strategies employed by the Company are based upon an Environmental Management Plan
(the "Plan") that incorporates targets and measurements against which the Company’s environmental performance is measured,
all of which is presented to, and reviewed by, the Board of Directors quarterly.
As part of the Company’s environmental stewardship and risk management, the Company engages in research (often through
collaborative efforts with industry partners, governments and research institutions) designed to develop, assess and implement
new or improved technologies and innovative practices that are intended to improve environmental performance.
The Plan, in conjunction with the Company's operating practices and guidelines, has been adopted with the intention of
reducing the impact of operations while meeting: regulatory requirements; regional management frameworks for biodiversity,
air quality and emissions, and ground and surface water; industry operating standards and guidelines, and internal corporate
standards. Training and due diligence for operators and contractors is a key component of the effectiveness of the Company’s
environmental management programs and supports efforts to reduce the Company’s environmental footprint. The Company, as
part of this Plan, has implemented proactive programs that include:
▪
Environmental planning to assess potential impacts by the Company's operations and implement avoidance strategies and
mitigation programs that seek to maintain biodiversity for terrestrial and aquatic systems and high value ecosystems;
▪
Continued evaluation of new technologies designed to reduce environmental impacts from operations, including support for
Canada’s Oil Sands Innovation Alliance ("COSIA"), the innovation arm of Pathways, Petroleum Technology Alliance Canada
("PTAC") and other research institutions;
▪
Implementation of various GHG emissions and methane reduction programs; and optimization programs that seek to
improve efficiencies at the Company's facilities;
▪
Water management programs that are designed to improve recycle rates and reduce fresh water use;
▪
Groundwater monitoring for all thermal in situ and mine operations;
▪
Reclamation and decommissioning programs across the Company’s operations. In North America, well abandonment and
progressive reclamation of large contiguous areas of land supports biodiversity and functional wildlife habitats. In the
Company's International operations, decommissioning activities continued for the Banff and Kyle fields and preparations
advanced for decommissioning of the Ninian Hub Area;
▪
Tailings management in Oil Sands Mining intended to reduce fine tailings and promote progressive reclamation;
▪
Monitoring programs to assess changes to biodiversity, wildlife and fisheries in order to manage construction and
operations impacts 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;
▪
Support for regional air shed monitoring for emissions and their deposition; and
▪
An internal environmental management system for conformance 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 4.8% (2023 – 5.2%; 2022 – 5.6%). For 2024, the
Company’s capital expenditures included $646 million for abandonment expenditures (2023 – $509 million; 2022 – $449 million).
Refer to the “Non-GAAP and Other Financial Measures” section of this MD&A for further details on abandonment
expenditures, net. The Company’s estimated discounted ARO at December 31, 2024 was as follows:
($ millions)
2024
2023
Exploration and Production
North America
$
4,783
$
4,471
North Sea
1,724
1,441
Offshore Africa
197
165
Oil Sands Mining and Upgrading
1,902
1,612
Midstream and Refining
1
1
$
8,607
$
7,690
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 as well as the expected work scope and the timing of abandonment.
Canadian Natural 2024 Annual Report
40
In 2021, the Alberta Energy Regulator (“AER”) announced a new Liability Management Framework, as part of its life-cycle
management of oil and gas wells, facilities and pipelines, which imposes annual mandatory spending targets for companies for
the closure of inactive wells and related infrastructure. Under the framework, the AER assigns licensees a mandatory annual
spend target for their abandonment and reclamation activities, which is determined based on a licensee's proportionate share of
the provincial inventory of inactive wells and related infrastructure, among other factors. Alberta's mandatory spend targets
became effective January 1, 2022 at 4% of inactive liability spend, increasing to 6.7% for the 2023 performance year, and
subsequently reduced for 2024 and 2025 to 6.6% and 6.2%, respectively. In 2022, the government of Saskatchewan also
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. In addition to spending requirements, the provincial regulators have the ability to require the posting of security to
secure the completion of abandonment and reclamation requirements. 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.
GREENHOUSE GAS AND OTHER EMISSIONS
The Company, through industry associations, is working with Canadian legislators and regulators as they develop and
implement new laws and regulations to properly reflect a balanced approach to sustainable development, such as programs to
support industry investments for environmental performance improvement and emissions reduction. 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
provincial, federal 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
published draft regulations on November 3, 2024 that propose to cap emissions from the oil and gas sector through a national
cap-and-trade system. The draft regulations currently propose to cap 2030 emissions at 27% below 2026 levels while providing
some compliance flexibility to emit up to 20% above the cap level. In December 2020, the federal government announced its
intention to increase the carbon price to $170/tonne by 2030 in annual increments of $15/tonne after 2022. In 2022, the federal
government released the Clean Fuel Regulations that were effective July 1, 2023, which apply to producers or importers of
gasoline and diesel and require reductions in the carbon intensity associated with gasoline and diesel fuels produced and
supplied in Canada. In December 2024, the federal government finalized its Clean Electricity Regulations, which may increase
the cost of electricity generated or purchased by the Company. Additionally, the federal government released draft regulations
in 2024 for the control of volatile organic compounds (VOCs) from certain upstream oil and gas facilities.
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.
The Technology Innovation and Emissions Reduction Regulation ("TIER") applies to 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 that took effect
January 1, 2023 that reduce the amount of emissions allocations for facilities under the regulation. Emissions coverage within
TIER also includes flaring from all TIER regulated facilities. The carbon price in Alberta was $80/tonne, which is for emissions
above the TIER-regulated limits in 2024 and increases annually in $15/tonne increments to $170/tonne in 2030, which aligns
with the federal carbon pricing schedule. The non-operated Scotford Upgrader and the North West Redwater bitumen upgrader
and refinery are also subject to compliance under TIER.
In British Columbia, the carbon tax on fuel consumed and gas flared and vented in the province was assessed at $65/tonne for
the first quarter of 2024. Effective April 1, 2024, the carbon tax for the industrial sector was replaced with an output-based
pricing system, with a carbon price of $80/tonne, which is expected to continue to increase by $15/tonne CO2e annually until
reaching $170/tonne of CO2e in 2030, aligning with the federal carbon pricing schedule. In March 2023, British Columbia
announced its intention to implement an emissions cap for the oil and gas industry to ensure that the province meets its 2030
emissions reduction target for the sector. This target aims to reduce oil and gas industry emissions by 33-38% below 2007
levels by 2030. The British Columbia government also announced its intention to implement a Net-Zero New Industry policy. In
March 2024, British Columbia announced that it would be introducing regulatory measures in 2025, that come into effect in
2026 to backstop the federal carbon cap, which will apply in the event of gaps between federal and provincial targets and in the
event that the federal cap is not implemented or cancelled.
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 effective 2020. This regulation also enables facilities below the threshold to aggregate and
41
Canadian Natural 2024 Annual Report
opt into the Saskatchewan regulatory system as an alternative to the federal fuel charge. This regulation also adopts the federal
carbon pricing schedule to 2030.
In Manitoba, the federal output-based pricing system and carbon pricing schedule applies for facilities with emissions greater
than or equal to 50 kilotonnes of CO2e annually. Facilities with emissions equal to or greater than 10 kilotonnes of CO2e annually
can voluntarily opt-in to the system.
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 equivalency agreements with the federal government in place. 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 with the draft regulatory framework
released in November 2022 and amendments published in December 2023. Feedback on the draft regulations were ongoing
during 2024 and are anticipated to continue through 2025.
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, as determined in accordance with UK regulations. In Phase 2 (2008 – 2012) the
Company’s CO2 allocation was decreased below the Company’s operations emissions, as determined in accordance with UK
regulations. In Phase 3 (2013 – 2020) the Company’s CO2 allocation was further reduced, as determined in accordance with UK
regulations. 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.
Accounting Policies and Standards
CHANGE IN ACCOUNTING POLICIES
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. The amendments were adopted on January 1, 2024 and had
no 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, 2024.
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.
Canadian Natural 2024 Annual Report
42
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.
B) Crude Oil and Natural Gas Reserves
Reserves estimates, evaluated by the Company's Independent Qualified Reserves Evaluators, 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, including property,
plant and equipment for which underlying reserves have been de-booked, and the carrying value of the asset has been fully
depleted. An ARO liability associated with the retirement of a tangible long-lived asset is recognized to the extent of a legal
obligation resulting from an existing or enacted law, statute, ordinance or written or oral contract, or by legal construction of a
contract under the doctrine of promissory estoppel. The ARO is based on estimated costs, taking into account the anticipated
method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site.
Since these estimates are specific to the sites involved, there are many individual assumptions underlying the Company’s total
ARO amount, including the potential impact of climate related matters and in accordance with related government regulations.
These individual assumptions may be subject to change.
The estimated present values of ARO related to long-term assets are recognized as a liability in the period in which they are
incurred. The provision for the ARO is estimated by discounting the expected future cash flows to settle the ARO at the
Company’s weighted average credit-adjusted risk-free interest rate, which is currently 4.8%. 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
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
43
Canadian Natural 2024 Annual Report
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, derived
from the present value of estimated future cash flows from the assets, together with deferred income tax effects. As a result,
the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on
future depletion, depreciation and amortization expense and impairment tests.
The Company has made various assumptions in determining the fair values of acquired assets and liabilities. The most
significant assumptions and judgements relate to the estimation of the fair value of crude oil and natural gas properties. To
determine the fair value of these properties, the Company estimates crude oil and natural gas reserves. Reserves estimates are
based on the work performed by the Company’s internal engineers and outside consultants. The judgements associated with
these estimated reserves are described above in "Crude Oil and Natural Gas Reserves". Estimates of future prices are based on
prices derived from price forecasts among industry analysts and internal assessments. The Company applies estimated future
prices to the estimated reserves quantities acquired, and estimates future production 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. 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, the Chief Financial Officer, and the Senior Vice-President, Finance and
Principal Accounting Officer, evaluated the effectiveness of disclosure controls and procedures as at December 31, 2024, 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, the Chief Financial Officer, and the Senior Vice-President, Finance and
Principal Accounting Officer, also evaluated the effectiveness of internal control over financial reporting as at December 31,
2024, 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 2024 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 2024 Annual Report
44
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, and 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 FROM OPERATIONS
Adjusted net earnings from operations is a non-GAAP financial measure that adjusts net earnings as presented in the
Company's consolidated Statements of Earnings, for non-operating items, net of tax impacts. The Company considers adjusted
net earnings 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 from operations is presented
below.
($ millions)
2024
2023
2022
Net earnings
$
6,106
$
8,233 $
10,937
Share-based compensation, net of tax (1)
257
474
780
Unrealized risk management loss (gain), net of tax (2)
10
7
(25)
Unrealized foreign exchange loss (gain), net of tax (3)
888
(260)
852
Realized foreign exchange loss (gain), net of tax (4)
135
—
(62)
Gain from investments, net of tax (5)
(50)
(34)
(182)
Recoverability charge, net of tax (6) (7) (8)
68
113
651
Other, net of tax (9)
—
—
(88)
Non-operating items, net of tax
1,308
300
1,926
Adjusted net earnings from operations
$
7,414
$
8,533 $
12,863
(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. Pre-tax share-based
compensation for 2024 was an expense of $279 million (2023 – $491 million expense; 2022 – $804 million expense).
(2)
Derivative financial instruments are recognized at fair value on the Company’s balance sheets, with changes in the fair value of non-designated hedges
recognized in net earnings. 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 loss for 2024 was $9 million (2023 – $12 million loss; 2022 – $28 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 in 2022, and are recognized in net earnings. Pre- and after-tax amounts for these unrealized foreign
exchange losses and gains are the same.
(4)
During 2024, the Company repaid US$500 million of 3.80% debt securities due April 2024, resulting in a pre- and after-tax foreign exchange loss of
$135 million. 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.
(5)
The Company’s investments have been accounted for at fair value through profit and loss and are measured each period with gains and losses recognized in
net earnings. During 2024, the Company sold its 22.6 million common share investment in PrairieSky Royalty Ltd. for $25.65 per common share with net
proceeds at close, after fees and expenses, of $575 million. There is a $nil net tax impact on the sale as the Company has sufficient capital losses to offset
the capital gain on the sale.
(6)
In connection with the Company's notice of withdrawal from Block 11B/12B in South Africa in 2024, the Company derecognized $62 million ($47 million after-
tax) of exploration and evaluation assets through depletion, depreciation and amortization expense.
(7)
The Company recognized a pre-tax recoverability charge of $160 million ($21 million after-tax) (2023 – $436 million ($113 million after-tax)) in depletion,
depreciation and amortization expense related to refined project scope and cost estimates for planned decommissioning and abandonment activities at the
Ninian field in the North Sea. The costs are considered to be capital in nature, consistent with the treatment of all abandonment related expenditures for the
purpose of the Company's non-GAAP measures.
(8)
The Company recognized a pre-tax recoverability charge of $1,620 million ($651 million after-tax) in depletion, depreciation and amortization expense at
December 31, 2022 relating to the de-booking of reserves and acceleration of abandonment at the Ninian field in the North Sea.
(9)
During 2022, the Company recognized the impact of government grant income under the provincial well-site rehabilitation programs of $114 million.
45
Canadian Natural 2024 Annual Report
ADJUSTED FUNDS FLOW
Adjusted funds flow is a non-GAAP financial measure that represents cash flows from operating activities as presented in the
Company's consolidated Statements of Cash Flows adjusted for the net change in non-cash working capital, abandonment
expenditures excluding the impact of government grant income under the provincial well-site rehabilitation programs, and
movements in other long-term assets. The Company considers adjusted funds flow a key measure in evaluating its
performance, as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through
capital investment, repay debt, and provide returns to shareholders through dividends and share buybacks. A reconciliation for
adjusted funds flow from cash flows from operating activities is presented below.
($ millions)
2024
2023
2022
Cash flows from operating activities
$
13,386
$
12,353 $
19,391
Net change in non-cash working capital
743
2,417
(79)
Abandonment expenditures, net (1)
646
509
335
Movements in other long-term assets (2)
84
(5)
144
Adjusted funds flow
$
14,859
$
15,274 $
19,791
(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 contributions to the Company's employee bonus program, accrued interest on PRT recoveries, and prepaid cost of service
tolls.
ADJUSTED NET EARNINGS FROM OPERATIONS AND ADJUSTED FUNDS FLOW, PER SHARE (BASIC
AND DILUTED)
Adjusted net earnings 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 historical annual capital budgets. 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)
2024
2023
2022
Abandonment expenditures
$
646
$
509 $
449
Government grants for abandonment expenditures
—
—
(114)
Abandonment expenditures, net
$
646
$
509 $
335
NETBACK
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 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 2024 Annual Report
46
REALIZED PRICE ($/BBL AND $/BOE) – EXPLORATION AND PRODUCTION
Realized price ($/bbl and $/BOE) is a non-GAAP ratio calculated as realized crude oil and NGLs sales and total realized BOE sales
(non-GAAP financial measures) divided by respective sales volumes. Realized crude oil and NGLs sales and total realized BOE
sales exclude the impact of blending and feedstock costs and other by-product sales. The Company considers realized price a
key measure in evaluating its performance, as it demonstrates the realized pricing per unit the Company obtained on the market
for its crude oil and NGLs sales volumes and BOE sales volumes.
Reconciliations for Exploration and Production realized crude oil and NGLs sales and BOE sales and the calculations for realized
price are presented below.
($ millions, except bbl/d and $/bbl)
2024
2023
2022
Crude oil and NGLs (bbl/d)
North America
504,339
497,604
480,691
International
North Sea
11,455
10,749
13,215
Offshore Africa
11,198
14,882
14,866
Total International
22,653
25,631
28,081
Total sales volumes
526,992
523,235
508,772
Crude oil and NGLs sales (1)
$
19,641
$
18,387 $
22,072
Less: Blending and feedstock costs (2)
4,643
4,568
5,239
Realized crude oil and NGLs sales
$
14,998
$
13,819 $
16,833
Realized price ($/bbl)
$
77.76
$
72.36 $
90.64
(1)
Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements.
(2)
Blending and feedstock 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)
2024
2023
2022
Barrels of oil equivalent (BOE/d)
North America
860,367
854,138
826,526
International
North Sea
11,791
11,034
13,598
Offshore Africa
12,728
16,638
16,933
Total International
24,519
27,672
30,531
Total sales volumes
884,886
881,810
857,057
Barrels of oil equivalent sales (1)
$
21,105
$
20,820 $
27,071
Less: Blending and feedstock costs (2)
4,643
4,568
5,239
Less: Sulphur expense (income)
3
(14)
(88)
Realized barrels of oil equivalent sales
$
16,459
$
16,266 $
21,920
Realized price ($/BOE)
$
50.82
$
50.54 $
70.07
(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)
Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration
and Production" section.
47
Canadian Natural 2024 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)
2024
2023
2022
Transportation, blending and feedstock (1)
$
6,195
$
5,816 $
6,401
Less: Blending and feedstock costs
4,643
4,568
5,239
Transportation
$
1,552
$
1,248 $
1,162
Transportation ($/BOE)
$
4.78
$
3.88 $
3.72
Amounts attributed to crude oil and NGLs
$
1,061
$
807 $
767
Transportation ($/bbl)
$
5.50
$
4.23 $
4.13
Amounts attributed to natural gas
$
491
$
441 $
395
Transportation ($/Mcf)
$
0.62
$
0.56 $
0.51
(1)
Transportation, blending and feedstock in note 22 to the Company's audited consolidated financial statements.
NORTH AMERICA – REALIZED PRODUCT PRICES AND ROYALTIES
Realized crude oil and NGLs price ($/bbl) is a non-GAAP ratio calculated as realized crude oil and NGLs sales (non-GAAP financial
measure) divided by sales volumes. Realized crude oil and NGLs sales exclude the impact of blending costs. The Company
considers the realized crude oil and NGLs price a key measure in evaluating its performance, as it demonstrates the realized
pricing per unit that the Company obtained on the market for its crude oil and NGLs sales volumes.
Crude oil and NGLs royalty rate is a non-GAAP ratio that is calculated as crude oil and NGLs royalties divided by realized crude
oil and NGLs sales. The Company considers crude oil and NGLs royalty rate a key measure in evaluating its performance, as it
describes the Company’s royalties for crude oil and NGLs sales volumes on a per unit basis.
A reconciliation for North America realized crude oil and NGLs sales and the calculations for realized crude oil and NGLs prices
and the royalty rates are presented below.
($ millions, except $/bbl and royalty rates)
2024
2023
2022
Crude oil and NGLs sales (1)
$
18,740
$
17,375 $
20,755
Less: Blending and feedstock costs (2)
4,643
4,568
5,239
Realized crude oil and NGLs sales
$
14,097
$
12,807 $
15,516
Realized crude oil and NGLs prices ($/bbl)
$
76.37
$
70.51 $
88.43
Crude oil and NGLs royalties (3)
$
2,842
$
2,340 $
3,445
Crude oil and NGLs royalty rates
20%
18%
22%
(1)
Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements.
(2)
Blending and feedstock 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 2024 Annual Report
48
REALIZED PRODUCT PRICES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING
Realized SCO sales price ($/bbl) is a non-GAAP ratio calculated as realized SCO sales (non-GAAP financial measure), excluding
the impact of blending and feedstock costs, divided by SCO sales volumes. The Company considers realized SCO sales price a
key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the
market for its SCO sales volumes.
Transportation ($/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)
2024
2023
2022
SCO sales volumes (bbl/d)
468,280
449,282
428,820
Crude oil and NGLs sales (1)
$
19,263
$
18,661 $
20,804
Less: Blending and feedstock costs
2,462
2,253
2,384
Realized SCO sales
$
16,801
$
16,408 $
18,420
Realized SCO sales price ($/bbl)
$
98.03
$
100.06 $
117.69
Transportation, blending and feedstock (2)
$
2,959
$
2,563 $
2,652
Less: Blending and feedstock costs
2,462
2,253
2,384
Transportation
$
497
$
310 $
268
Transportation ($/bbl)
$
2.91
$
1.89 $
1.71
(1)
Crude oil and NGLs sales in note 22 to the Company's audited consolidated financial statements.
(2)
Transportation, blending and feedstock in note 22 to the Company's audited consolidated financial statements.
CHANGE IN COMPOSITION OF NON-GAAP FINANCIAL MEASURE
During the fourth quarter of 2023, the Company revised the composition of its net capital expenditures non-GAAP financial
measure to exclude expenditures related to the Company's abandonment program. The revision was made during
Management's assessment of its annual capital budgeting process, and will provide users a better representation of the
Company's performance and the composition of its capital budget. The composition of this measure has been updated for all
periods presented.
Additionally, the Company revised the composition of its net capital expenditures non-GAAP financial measure to include
acquisition capital related to a number of acquisitions for which agreements between parties have been reached, with closings
targeted in 2025. Although subject to regulatory approvals and other customary closing conditions, the inclusion of these
acquisitions reflects the Company's estimate of its net capital expenditures at the time the 2025 budget was released. The
composition of this measure has been updated to reflect the 2025 capital budget, but did not impact net capital expenditures in
2024, 2023 or 2022.
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, net
proceeds from investments, and cash flows from investing activities not included in the Company's capital budget. The
Company includes acquisition and disposition capital for property, plant and equipment and exploration and evaluation assets in
net capital expenditures at close of the transactions. 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)
2024
2023
2022
Cash flows used in investing activities
$
14,095
$
4,858
$
4,987
Net proceeds from investments
575
—
—
Working capital acquired from Chevron
(115)
—
—
Net change in non-cash working capital
(124)
51
149
Net capital expenditures
14,431
4,909
5,136
Abandonment expenditures, net (1)
646
509
335
Capital and abandonment expenditures
$
15,077
$
5,418
$
5,471
(1)
Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the “Abandonment Expenditures, net” section above.
49
Canadian Natural 2024 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)
2024
2023
2022
Undrawn bank credit facilities
$
4,562
$
5,450 $
5,520
Cash and cash equivalents
131
877
920
Investments (1)
—
525
491
Liquidity
$
4,693
$
6,852 $
6,931
(1)
During 2024, the Company sold its 22.6 million common share investment in PrairieSky Royalty Ltd. for $25.65 per common share with net proceeds at close,
after fees and expenses, of $575 million.
LONG-TERM DEBT, NET
Long-term debt, net, is a capital management measure that represents long-term debt, including the current portion of long-
term debt, less cash and cash equivalents, as disclosed in note 16 to the Company's audited consolidated financial statements.
A reconciliation of the Company's long-term debt, net is presented below.
($ millions)
2024
2023
2022
Long-term debt
$
18,819
$
10,799 $
11,445
Less: cash and cash equivalents
131
877
920
Long-term debt, net
$
18,688
$
9,922 $
10,525
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 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)
2024
2023
2022
Interest adjusted after-tax return:
Net earnings, 12 months trailing
$
6,106 $
8,233 $
10,937
Interest and other financing expense, net of tax, 12 months trailing (1)
454
490
424
Interest adjusted after-tax return
$
6,560 $
8,723 $
11,361
12 months average current portion long-term debt (2)
$
1,525 $
1,259 $
1,359
12 months average long-term debt (2)
10,642
10,354
11,761
12 months average common shareholders' equity (2)
39,635
38,974
38,218
12 months average capital employed
$
51,802 $
50,587 $
51,338
After-tax return on average capital employed
13%
17%
22%
(1)
The blended tax rate on interest was 23% for each of the periods presented.
(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 2024 Annual Report
50
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
2024, excluding mark-to-market gains (losses) on risk management activities and is not necessarily indicative of future results.
Each separate line item in the sensitivity analysis shows the effect of a change in that variable only with all other variables being
held constant.
Cash flows
from Operating
Activities
($ millions)
Cash flows
from Operating
Activities
(per common
share, basic)
Net
earnings
($ millions)
Net
earnings
(per common
share, basic)
Price changes
Crude oil – WTI US$1.00/bbl
Excluding financial derivatives
$
378 $
0.18 $
378 $
0.18
Natural gas – AECO C$0.10/Mcf (1)
Excluding financial derivatives
$
47 $
0.02 $
47 $
0.02
Including financial derivatives
$
45 $
0.02 $
45 $
0.02
Volume changes
Crude oil – 10,000 bbl/d
$
165 $
0.08 $
139 $
0.07
Natural gas – 10 MMcf/d
$
1 $
— $
(4) $
—
Foreign currency rate change
$0.01 change in US$ (1)
Including financial derivatives
$
299 $
0.14 $
43 $
0.02
Interest rate change – 1%
$
46 $
0.02 $
46 $
0.02
(1)
For details of financial instruments in place, refer to note 19 to the Company’s audited consolidated financial statements as at December 31, 2024.
51
Canadian Natural 2024 Annual Report
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
Q1
Q2
Q3
Q4
2024
2023
2022
Crude oil and NGLs (bbl/d)
North America – Exploration and
Production
505,636
499,636
499,772
531,960
509,288
496,100
479,971
North America – Oil Sands Mining and
Upgrading (1)
445,209
410,518
497,656
534,631
472,245
451,339
425,945
International
North Sea
12,433
11,295
10,958
11,467
11,536
12,639
12,890
Offshore Africa
12,390
12,617
13,186
11,944
12,534
13,452
14,343
Total International
24,823
23,912
24,144
23,411
24,070
26,091
27,233
Total Crude oil and NGLs
975,668
934,066 1,021,572 1,090,002 1,005,603
973,530
933,149
Natural gas (MMcf/d) (2)
North America
2,135
2,099
2,039
2,273
2,136
2,139
2,075
International
North Sea
1
2
1
4
2
2
2
Offshore Africa
11
9
9
6
9
10
13
Total International
12
11
10
10
11
12
15
Total Natural gas
2,147
2,110
2,049
2,283
2,147
2,151
2,090
Barrels of oil equivalent (BOE/d)
North America – Exploration and
Production
861,352
849,498
839,490
910,703
865,314
852,633
825,806
North America – Oil Sands Mining and
Upgrading (1)
445,209
410,518
497,656
534,631
472,245
451,339
425,945
International
North Sea
12,673
11,572
11,184
12,066
11,873
12,925
13,273
Offshore Africa
14,268
14,210
14,756
13,028
14,064
15,208
16,410
Total International
26,941
25,782
25,940
25,094
25,937
28,133
29,683
Total Barrels of oil equivalent
1,333,502 1,285,798 1,363,086 1,470,428 1,363,496 1,332,105 1,281,434
(1)
SCO production before royalties excludes SCO consumed internally as diesel.
(2)
Natural gas production volumes approximate sales volumes.
Canadian Natural 2024 Annual Report
52
PER UNIT RESULTS – EXPLORATION AND PRODUCTION
Q1
Q2
Q3
Q4
2024
2023
2022
Crude oil and NGLs ($/bbl) (1)
Realized price (2)
$
70.01 $
86.64 $
79.15 $
75.22 $
77.76 $
72.36 $
90.64
Transportation (2)
4.63
5.98
5.26
6.08
5.50
4.23
4.13
Realized price, net of transportation (2)
65.38
80.66
73.89
69.14
72.26
68.13
86.51
Royalties (3)
12.09
17.45
15.05
14.77
14.85
12.55
18.91
Production expense (4)
16.66
14.54
14.65
13.15
14.72
16.12
18.17
Netback (2)
$
36.63 $
48.67 $
44.19 $
41.22 $
42.69 $
39.46 $
49.43
Natural gas ($/Mcf) (1)
Realized price (5)
$
2.55 $
1.59 $
1.25 $
2.02 $
1.86 $
3.10 $
6.55
Transportation (6)
0.64
0.63
0.63
0.59
0.62
0.56
0.51
Realized price, net of transportation
1.91
0.96
0.62
1.43
1.24
2.54
6.04
Royalties (3)
0.10
0.02
0.02
0.04
0.05
0.13
0.61
Production expense (4)
1.30
1.21
1.26
1.12
1.22
1.30
1.22
Netback (7)
$
0.51 $
(0.27) $
(0.66) $
0.27 $
(0.03) $
1.11 $
4.21
Barrels of oil equivalent ($/BOE) (1)
Realized price (2)
$
47.60 $
55.84 $
50.36 $
49.54 $
50.82 $
50.54 $
70.07
Transportation (2)
4.31
5.09
4.67
5.06
4.78
3.88
3.72
Realized price, net of transportation (2)
43.29
50.75
45.69
44.48
46.04
46.66
66.35
Royalties (3)
7.39
10.53
9.05
8.85
8.96
7.77
12.75
Production expense (4)
13.03
11.64
11.81
10.53
11.73
12.74
13.76
Netback (2)
$
22.87 $
28.58 $
24.83 $
25.10 $
25.35 $
26.15 $
39.84
(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.
(7)
Natural gas netbacks exclude NGLs netbacks derived from the Company's liquids-rich natural gas plays.
PER UNIT RESULTS – OIL SANDS MINING AND UPGRADING
Q1
Q2
Q3
Q4
2024
2023
2022
Crude oil and NGLs ($/bbl) (1)
Realized SCO sales price (2)
$
88.84 $
108.81 $
100.93 $
95.08 $
98.03 $
100.06 $
117.69
Bitumen royalties (3)
14.28
20.01
17.71
17.20
17.23
14.43
20.71
Transportation (2)
1.67
2.81
3.34
3.60
2.91
1.89
1.71
Production expense (4)
24.85
25.95
20.67
20.97
22.88
24.32
26.04
Netback (2)
$
48.04 $
60.04 $
59.21 $
53.31 $
55.01 $
59.42 $
69.23
(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 expense divided by sales volumes.
53
Canadian Natural 2024 Annual Report
TRADING AND SHARE STATISTICS (1)
Q1
Q2
Q3
Q4
2024
2023
TSX – C$
Trading volume (thousands)
798,934
741,418
805,899
679,568 3,025,819 3,394,111
Share Price ($/share)
High
$
51.81 $
56.50 $
50.87 $
52.15 $
56.50 $
46.72
Low
$
40.02 $
45.44 $
43.04 $
42.04 $
40.02 $
33.57
Close
$
51.67 $
48.73 $
44.91 $
44.38 $
44.38 $
43.41
Market capitalization as at December 31,
($ millions)
$
93,331 $
93,096
Shares outstanding
(thousands)
2,102,996 2,144,815
NYSE – US$
Trading volume (thousands)
364,890
353,501
326,599
265,304 1,310,294 1,205,733
Share Price ($/share)
High
$
38.28 $
41.29 $
37.63 $
37.90 $
41.29 $
34.37
Low
$
29.46 $
33.04 $
31.66 $
29.23 $
29.23 $
24.41
Close
$
38.16 $
35.60 $
33.21 $
30.87 $
30.87 $
32.76
Market capitalization as at December 31,
($ millions)
$
64,919 $
70,264
Shares outstanding
(thousands)
2,102,996 2,144,815
(1)
Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are
disclosed in the Advisory section of this MD&A and in note 1 to the Company's audited consolidated financial statements.
Canadian Natural 2024 Annual Report
54
Consolidated Financial Statements
Table of Contents
Management's Report
56
Management’s Assessment of Internal Control over Financial Reporting
57
Report of Independent Registered Public Accounting Firm
58
Consolidated Balance Sheets
61
Consolidated Statements of Earnings
62
Consolidated Statements of Comprehensive Income
62
Consolidated Statements of Changes in Equity
63
Consolidated Statements of Cash Flows
64
Notes to the Consolidated Financial Statements
65
1. Accounting Policies
65
2. Change in Accounting Policies
71
3. Accounting Standards Issued But Not Yet Applied
71
4. Critical Accounting Estimates and Judgements
71
5. Inventory
73
6. Exploration and Evaluation Assets
73
7. Property, Plant and Equipment
74
8. Leases
76
9. Investments
77
10. Other Long-Term Assets
77
11. Long-Term Debt
79
12. Other Long-Term Liabilities
81
13. Income Taxes
83
14. Share Capital
85
15. Accumulated Other Comprehensive Income
87
16. Capital Disclosures
87
17. Net Earnings Per Common Share
87
18. Interest and Other Financing Expense
88
19. Financial Instruments
88
20. Commitments and Contingencies
91
21. Supplemental Disclosure of Cash Flow Information
91
22. Segmented Information
93
23. Remuneration of Directors and Senior Management
96
24. Subsequent Events
96
55
Canadian Natural 2024 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, 2024; and
▪
the effectiveness of the Company’s internal control over financial reporting as at December 31, 2024.
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.
SCOTT G. STAUTH
MARK A. STAINTHORPE, CFA
VICTOR C. DAREL, CPA, CA
President
Chief Financial Officer
Senior Vice-President, Finance and
Principal Accounting Officer
Calgary, Alberta, Canada
March 5, 2025
Canadian Natural 2024 Annual Report
56
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, 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, 2024. 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, 2024, as stated in their accompanying Report of
Independent Registered Public Accounting Firm.
SCOTT G. STAUTH
MARK A. STAINTHORPE, CFA
President
Chief Financial Officer
Calgary, Alberta, Canada
March 5, 2025
57
Canadian Natural 2024 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, 2024 and 2023, and the related consolidated statements of earnings, of
comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31,
2024, 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, 2024, 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, 2024 and 2023, and its financial performance and its cash flows for each of the
three years in the period ended December 31, 2024 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, 2024, 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 2024 Annual Report
58
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial
statements that were communicated or required to be communicated to the Audit Committee and that (i) relate 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 matters below, providing separate
opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Acquisition of Chevron’s Assets - Valuation of Acquired Property, Plant and Equipment
As described in Notes 1, 4, and 7 to the Company’s consolidated financial statements, in December 2024, the Company
completed the acquisition of Chevron Canada Limited’s (“Chevron”) assets for total cash consideration of $9.2 billion, subject to
final closing adjustments. The acquisition has been accounted for as a business combination using the acquisition method of
accounting. The allocation of the purchase price was based on management's best estimates of the fair value of the assets and
liabilities acquired as at the acquisition date. $8.9 billion of the purchase price was allocated to the fair value of the acquired
property, plant and equipment (the “Acquired PP&E”) derived from the present value of estimated future cash flows. The fair
value assessment required the use of estimates and judgments by management including key assumptions related to future
commodity prices, expected production volumes, quantity of crude oil and natural gas reserves, future development and
production costs, and discount rates. Management utilizes third party specialists, specifically independent qualified reserves
evaluators (“Management’s Specialists”) to evaluate its estimated quantity of crude oil and natural gas reserves.
The principal considerations for our determination that performing procedures relating to the Acquisition of Chevron’s Assets -
Valuation of Acquired PP&E is a critical audit matter are the significant judgment by management, including the use of
Management's Specialists, when developing the fair value of the Acquired PP&E. This led to a high degree of auditor judgment,
effort and subjectivity in performing procedures and evaluating evidence obtained related to the key assumptions used in
developing the fair value of the Acquired PP&E, including future commodity prices, expected production volumes, quantity of
reserves, future development and production costs, and discount rates. The audit effort also involved the use of professionals
with specialized skill and knowledge.
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 controls relating to
management’s determination of the fair value of the Acquired PP&E. These procedures also included, among others, testing
management’s process for determining the fair value of the Acquired PP&E which included (i) evaluating the appropriateness of
the method used by management in making the estimate, (ii) testing the completeness and accuracy of underlying data used in
management’s determination of the fair value and (iii) evaluating the reasonableness of key assumptions used by management
related to future commodity prices, expected production volumes, quantity of crude oil and natural gas reserves, future
development and production costs, and discount rates. Evaluating the key assumptions involved assessing whether the key
assumptions used were reasonable considering the past performance of similar properties owned by the Company, external
market and industry data and whether they were consistent with evidence obtained in other areas of the audit, as applicable.
The work of Management’s Specialists was used in performing procedures to evaluate the reasonableness of the estimated
quantity of crude oil and natural gas reserves. As a basis for using this work, Management’s Specialists’ qualifications were
understood and the Company’s relationship with Management’s Specialists was assessed. The procedures performed also
included evaluating the methods and assumptions used by Management’s Specialists, testing the completeness and accuracy
of the data used by Management’s Specialists, and evaluating Management’s Specialists’ findings. Professionals with
specialized skill and knowledge were used to assist in evaluating the appropriateness of the present value of estimated future
cash flows from the Acquired PP&E and the reasonableness of the discount rates.
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 $27.0 billion as of December 31, 2024.
Depletion, depreciation and amortization (“DD&A”) expense for the North America Exploration and Production segment was
$3.7 billion for the year ended December 31, 2024. 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 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 the significant
judgment by management, including the use of Management’s 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
59
Canadian Natural 2024 Annual Report
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, Management’s Specialists’
qualifications were understood, and the Company’s relationship with Management’s Specialists was assessed. The procedures
performed also included evaluation of the methods and assumptions used by Management’s Specialists, tests of data used by
Management’s Specialists and an evaluation of Management’s Specialists’ findings. The procedures performed also included,
among others, 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.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Canada
March 5, 2025
We have served as the Company's auditor since 1973.
Canadian Natural 2024 Annual Report
60
Consolidated Balance Sheets
As at December 31,
Note
2024
2023
(millions of Canadian dollars)
ASSETS
Current assets
Cash and cash equivalents
$
131
$
877
Accounts receivable
4,126
3,189
Inventory
5
2,793
2,034
Prepaids and other
279
471
Investments
9
—
525
Current portion of other long-term assets
10
76
71
7,405
7,167
Exploration and evaluation assets
6
2,526
2,208
Property, plant and equipment
7
73,414
64,581
Lease assets
8
1,394
1,458
Other long-term assets
10
620
541
$
85,359
$
75,955
LIABILITIES
Current liabilities
Accounts payable
$
1,079
$
1,418
Accrued liabilities
4,525
3,534
Current income taxes payable
92
—
Current portion of long-term debt
11
2,400
980
Current portion of other long-term liabilities
12
1,535
1,503
9,631
7,435
Long-term debt
11
16,419
9,819
Other long-term liabilities
12
9,302
8,686
Deferred income taxes
13
10,539
10,183
45,891
36,123
SHAREHOLDERS’ EQUITY
Share capital
14
11,064
10,712
Retained earnings
28,103
28,948
Accumulated other comprehensive income
15
301
172
39,468
39,832
$
85,359
$
75,955
Commitments and contingencies (note 20).
Approved by the Board of Directors on March 5, 2025.
CATHERINE M. BEST
N. MURRAY EDWARDS
Chair of the Audit Committee
and Director
Executive Chairman of the
Board of Directors and Director
61
Canadian Natural 2024 Annual Report
Consolidated Statements of Earnings
For the years ended December 31,
(millions of Canadian dollars, except per common share amounts)
Note
2024
2023
2022
Product sales
22
$
41,509
$
40,835 $
49,530
Less: royalties
(5,853)
(4,867)
(7,232)
Revenue
35,656
35,968
42,298
Expenses
Production
8,093
8,480
8,712
Transportation, blending and feedstock
9,984
9,302
9,973
Depletion, depreciation and amortization
6,7,8
6,681
6,413
7,353
Administration
503
452
415
Share-based compensation
12
279
491
804
Asset retirement obligation accretion
12
389
366
281
Interest and other financing expense
18
592
636
549
Risk management loss (gain)
19
177
(2)
(35)
Foreign exchange loss (gain)
955
(279)
738
Gain from investments
9
(56)
(56)
(196)
27,597
25,803
28,594
Earnings before taxes
8,059
10,165
13,704
Current income tax expense
13
1,531
1,879
2,906
Deferred income tax expense (recovery)
13
422
53
(139)
Net earnings
$
6,106
$
8,233 $
10,937
Net earnings per common share (1)
Basic
17
$
2.87
$
3.77 $
4.82
Diluted
17
$
2.85
$
3.74 $
4.76
(1)
Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split (note 1).
Consolidated Statements of Comprehensive Income
For the years ended December 31,
(millions of Canadian dollars)
2024
2023
2022
Net earnings
$
6,106
$
8,233 $
10,937
Items that may be reclassified subsequently to net earnings
Net change in derivative financial instruments designated as cash
flow hedges
Unrealized income, net of taxes of $nil (2023 – $nil,
2022 – $1 million)
2
2
4
Reclassification to net earnings, net of taxes of $nil (2023 – $nil,
2022 – $1 million)
(4)
(5)
(6)
(2)
(3)
(2)
Foreign currency translation adjustment
Translation of net investment
131
(34)
212
Other comprehensive income (loss), net of taxes
129
(37)
210
Comprehensive income
$
6,235
$
8,196 $
11,147
Canadian Natural 2024 Annual Report
62
Consolidated Statements of Changes in Equity
For the years ended December 31,
(millions of Canadian dollars)
Note
2024
2023
2022
Share capital
14
Balance – beginning of year
$
10,712
$
10,294 $
10,168
Issued upon exercise of stock options
280
372
442
Previously recognized liability on stock options exercised for
common shares
358
435
387
Purchase of common shares under Normal Course Issuer Bid
(286)
(389)
(703)
Balance – end of year
11,064
10,712
10,294
Retained earnings
Balance – beginning of year
28,948
27,672
26,778
Net earnings
6,106
8,233
10,937
Dividends on common shares
14
(4,537)
(4,028)
(5,175)
Purchase of common shares under Normal Course Issuer Bid,
including tax
14
(2,414)
(2,929)
(4,868)
Balance – end of year
28,103
28,948
27,672
Accumulated other comprehensive income (loss)
15
Balance – beginning of year
172
209
(1)
Other comprehensive income (loss), net of taxes
129
(37)
210
Balance – end of year
301
172
209
Shareholders’ equity
$
39,468
$
39,832 $
38,175
63
Canadian Natural 2024 Annual Report
Consolidated Statements of Cash Flows
For the years ended December 31,
(millions of Canadian dollars)
Note
2024
2023
2022
Operating activities
Net earnings
$
6,106
$
8,233 $
10,937
Non-cash items
Depletion, depreciation and amortization
6,7,8
6,681
6,413
7,353
Share-based compensation
279
491
804
Asset retirement obligation accretion
389
366
281
Unrealized risk management loss (gain)
9
12
(28)
Unrealized foreign exchange loss (gain)
888
(260)
852
Gain from investments
9
(50)
(34)
(182)
Deferred income tax expense (recovery)
422
53
(139)
Realized foreign exchange loss (gain) (1)
135
—
(62)
Proceeds on settlement of cross currency swap
—
—
89
Abandonment expenditures
12
(646)
(509)
(449)
Other
(84)
5
(144)
Net change in non-cash working capital
21
(743)
(2,417)
79
Cash flows from operating activities
13,386
12,353
19,391
Financing activities
Issuance (repayment) of bank credit facilities and commercial
paper, net
11,21
5,466
—
(1,156)
Issuance of other long-term debt
11,21
2,639
—
—
Repayment of other long-term debt
11,21
(1,008)
(416)
(2,854)
Proceeds on settlement of cross currency swaps
—
—
69
Payment of lease liabilities
8,21
(325)
(285)
(232)
Issue of common shares on exercise of stock options
14
280
372
442
Dividends on common shares
(4,429)
(3,891)
(4,926)
Purchase of common shares under Normal Course Issuer Bid
14
(2,660)
(3,318)
(5,571)
Cash flows used in financing activities
(37)
(7,538)
(14,228)
Investing activities
Net expenditures on exploration and evaluation assets
6,22
(92)
(44)
(33)
Net expenditures on property, plant and equipment
7,22
(5,291)
(4,865)
(5,103)
Acquisition of Chevron's assets
6,7,22
(9,163)
—
—
Net proceeds from investments
9
575
—
—
Net change in non-cash working capital
21
(124)
51
149
Cash flows used in investing activities
(14,095)
(4,858)
(4,987)
(Decrease) increase in cash and cash equivalents
(746)
(43)
176
Cash and cash equivalents – beginning of year
877
920
744
Cash and cash equivalents – end of year
$
131
$
877 $
920
Interest paid on long-term debt
$
586
$
602 $
613
Income taxes paid, net
$
1,144
$
3,317 $
3,057
(1)
Consists of the realized foreign exchange loss on repayment of US dollar debt securities in 2024 and 2022, and the realized foreign exchange gain on
settlement of cross currency swaps in 2022.
Canadian Natural 2024 Annual Report
64
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 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) 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, including emissions credits, is determined by reference to
current market prices and regulated compliance rates. Emissions credit inventory generated in the normal course of business is
initially measured in accordance with the Company's accounting policy for government grants.
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Canadian Natural 2024 Annual Report
(C) 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.
(D) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is measured at cost less accumulated depletion and depreciation and recoverability charges.
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,
overburden removal costs incurred during the initial development of a mine at Horizon and AOSP, 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. Capitalized overburden removal
costs are depleted over the life of the mining reserves that directly benefit from overburden removal activity. 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.
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.
Canadian Natural 2024 Annual Report
66
Major maintenance expenditures
Inspection costs associated with major turnarounds are capitalized and depreciated over the period to the next major
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.
(E) 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.
(F) LEASES
The Company recognizes a lease asset and a lease liability at the commencement date of the lease contract. 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 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.
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.
(G) 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 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.
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Canadian Natural 2024 Annual Report
(H) 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").
When the Company disposes of its entire interest in a foreign operation, the foreign currency gains or losses accumulated in
other comprehensive income related to the foreign operation are recognized in net earnings.
(I) REVENUE RECOGNITION AND COSTS OF GOODS SOLD
Revenue from the sale of crude oil and natural gas liquids ("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.
(J) 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 company
(the "Government"). Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a
portion has been allocated to the Government. The Government’s 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.
(K) 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 or a transaction that, on initial
recognition, gives rise to equal taxable and deductible temporary differences) 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.
Canadian Natural 2024 Annual Report
68
(L) 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 share 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.
(M) 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 2024 Annual Report
(N) 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.
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.
(O) GOVERNMENT GRANTS
The Company receives or is eligible for government grants, including emissions credits. 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.
(P) PER COMMON SHARE AMOUNTS
The Company calculates basic earnings per common share by dividing net earnings by the weighted average number of
common shares outstanding during the period. As the Company’s Option Plan allows for the settlement of stock options in
either cash or shares at the option of the holder, diluted earnings per common share is calculated using the more dilutive of
cash settlement or share settlement under the treasury stock method.
(Q) 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, including tax,
is recognized as a reduction of retained earnings. Shares are cancelled upon purchase.
Canadian Natural 2024 Annual Report
70
(R) COMMON SHARE SPLIT AND COMPARATIVE FIGURES
At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a Special Resolution approving a two
for one common share split effective for shareholders of record as of market close on June 3, 2024. On June 10, 2024,
shareholders of record received one additional share for every one common share held, with common shares trading on a split-
adjusted basis beginning June 11, 2024. Common share, per common share, dividend, and stock option amounts for periods
prior to the two for one common share split have been updated to reflect the common share split.
2. Change in Accounting Policies
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. The amendments were adopted on January 1, 2024 and had
no impact on the Company's consolidated financial statements.
3. Accounting Standards Issued But Not Yet Applied
In April 2024, the IASB issued IFRS 18 "Presentation and Disclosure in Financial Statements", which provides presentation and
disclosure requirements for the primary financial statements and related notes, replacing IAS 1 “Presentation of Financial
Statements". IFRS 18 introduces defined categories for income and expenses and requires disclosure of new defined subtotals,
including operating profit. The new standard also requires additional notes for management-defined performance measures and
disclosure of certain expenses by nature. There are some associated changes to the statement of cash flows, including the
starting point for the calculation of cash flows from operating activities and the categorization of interest and dividends. IFRS 18
is effective January 1, 2027, with early adoption permitted. The new standard is required to be adopted retrospectively. The
Company is assessing the impact of IFRS 18 on the Company’s consolidated financial statements.
In May 2024, the IASB issued amendments to IFRS 9 "Financial Instruments" and IFRS 7 "Financial Instruments: Disclosures" to
clarify the date of recognition and derecognition of some financial assets and liabilities, with a new exception for some financial
liabilities settled using an electronic payment system. The amendments also clarify the requirements for assessing whether a
financial asset meets the solely payments of principal and interest criterion, and adds disclosure requirements for financial
instruments with certain contingent features and for equity investments designated at fair value through other comprehensive
income. The amendments are effective January 1, 2026, with early adoption permitted. The amendments are required to be
adopted retrospectively by adjusting the opening balance of financial assets, financial liabilities and retained earnings at the date
of adoption. The Company is assessing the impact of the amendments on the Company’s 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, evaluated by the
Company's Independent Qualified Reserves Evaluators, 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, technological advances, and
estimates of future inflation 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, revisions to work
scope, 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.
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Canadian Natural 2024 Annual Report
(C) INCOME TAXES
The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the Company to
interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with
respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of
tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company
recognizes a liability for a tax filing position based on its assessment of the probability that additional taxes may ultimately be
due.
(D) FAIR VALUE OF DERIVATIVES AND OTHER FINANCIAL INSTRUMENTS
The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The
Company uses its judgement to select a variety of methods and make assumptions that are primarily based on market
conditions existing at the end of each reporting period. The Company uses directly and indirectly observable inputs in measuring
the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility,
interest rate yield curves and foreign exchange rates.
(E) PURCHASE PRICE ALLOCATIONS
Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their
estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates,
assumptions, and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts
assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties, derived
from the present value of estimated future cash flows from the assets, 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 production 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.
Canadian Natural 2024 Annual Report
72
5. Inventory
2024
2023
Product inventory
$
986
$
546
Materials, supplies and other
1,807
1,488
$
2,793
$
2,034
During 2024, approximately $30 billion of purchased and produced inventory was recorded as expense (2023 – approximately
$29 billion).
6. Exploration and Evaluation Assets
Exploration and Production
Oil Sands
Mining and
Upgrading
Total
North
America
North Sea
Offshore
Africa
Cost
At December 31, 2022
$
2,026 $
— $
98 $
102 $
2,226
Additions/Acquisitions
45
—
3
—
48
Transfers to property, plant and equipment
(38)
—
—
(25)
(63)
Derecognitions and other
(2)
—
—
—
(2)
Foreign exchange adjustments
—
—
(1)
—
(1)
At December 31, 2023
2,031
—
100
77
2,208
Additions, net
102
—
6
—
108
Acquisition of Chevron's assets (note 7)
320
—
—
—
320
Transfers to property, plant and equipment
(45)
—
—
(7)
(52)
Derecognitions and other (1)
—
—
(62)
—
(62)
Foreign exchange adjustments
—
—
4
—
4
At December 31, 2024
$
2,408 $
— $
48 $
70 $
2,526
(1)
In connection with the Company's notice of withdrawal from Block 11B/12B in South Africa in 2024, the Company derecognized $62 million of exploration
and evaluation assets through depletion, depreciation and amortization expense.
In December 2024, the Company completed the acquisition of Chevron Canada Limited's ("Chevron") assets in the North
America Exploration and Production and Oil Sands Mining and Upgrading segments, including exploration and evaluation assets
of $320 million. Refer to note 7 for further details on the acquisition.
73
Canadian Natural 2024 Annual Report
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, 2022
$
81,075 $
8,258 $
4,332 $
47,732 $
474 $
536 $
142,407
Additions/Acquisitions
2,951
558
187
2,088
10
30
5,824
Transfers from exploration
and evaluation assets
38
—
—
25
—
—
63
Derecognitions (1)
(581)
—
—
(470)
—
—
(1,051)
Foreign exchange
adjustments and other
—
(210)
(110)
—
—
—
(320)
At December 31, 2023
83,483
8,606
4,409
49,375
484
566
146,923
Additions
3,440
352
205
2,103
11
41
6,152
Acquisition of Chevron's
assets
2,585
—
—
6,316
—
—
8,901
Transfers from exploration
and evaluation assets
45
—
—
7
—
—
52
Derecognitions (1)
(589)
(18)
—
(456)
—
—
(1,063)
Foreign exchange
adjustments and other
—
791
409
—
—
—
1,200
At December 31, 2024
$
88,964 $
9,731 $
5,023 $
57,345 $
495 $
607 $
162,165
Accumulated depletion and depreciation
At December 31, 2022
$
55,835 $
8,106 $
3,277 $
9,712 $
198 $
420 $
77,548
Expense
3,592
40
177
1,856
15
24
5,704
Derecognitions (1)
(581)
—
—
(470)
—
—
(1,051)
Recoverability charge (2)
—
436
—
—
—
—
436
Foreign exchange
adjustments and other
(6)
(200)
(96)
7
—
—
(295)
At December 31, 2023
58,840
8,382
3,358
11,105
213
444
82,342
Expense
3,741
96
192
2,086
16
26
6,157
Derecognitions (1)
(589)
(18)
—
(456)
—
—
(1,063)
Recoverability charge (2)
—
160
—
—
—
—
160
Foreign exchange
adjustments and other
18
772
335
30
—
—
1,155
At December 31, 2024
$
62,010 $
9,392 $
3,885 $
12,765 $
229 $
470 $
88,751
Net book value
At December 31, 2024
$
26,954 $
339 $
1,138 $
44,580 $
266 $
137 $
73,414
At December 31, 2023
$
24,643 $
224 $
1,051 $
38,270 $
271 $
122 $
64,581
(1)
An asset is derecognized when no future economic benefits are expected to arise from its continued use or disposal.
(2)
The Company continues to refine its project scope and cost estimates related to its long-term abandonment activities at the Ninian field in the North Sea. At
December 31, 2024, the Company recognized a non-cash charge of $21 million comprised of a recoverability charge recognized in depletion, depreciation and
amortization expense of $160 million net of deferred tax recoveries of $139 million (2023 – $113 million comprised of a recoverability charge of $436 million
net of deferred tax recoveries of $323 million; 2022 – $651 million comprised of a recoverability charge of $1,620 million net of deferred tax recoveries of
$969 million). The Company's estimate of its asset retirement obligation liability, including the Ninian field recoverability charges and associated tax
recoveries, is subject to revision in future periods as abandonment efforts progress.
Canadian Natural 2024 Annual Report
74
ACQUISITION OF CHEVRON'S ASSETS
In December 2024, the Company completed the acquisition of Chevron's assets for total cash consideration of $9,163 million,
subject to final closing adjustments. The acquisition includes a 70% operated working interest in the light crude oil and liquids-
rich Duvernay asset play in Alberta and a 20% working interest in AOSP. As a result of the acquisition, the Company now has a
90% direct and indirect working interest in AOSP, which includes the Muskeg River and Jackpine mines, the Scotford
Upgrader, and the Quest Carbon Capture and Storage facility ("Quest"). The acquisition also includes various working interests in
a number of other non-producing oil sands leases. The Company consolidates its interests in the assets, liabilities, revenue, and
expenses of both the AOSP and Duvernay joint operations.
In connection with the acquisition, the Company arranged a fully committed $4,000 million non-revolving term credit facility
maturing December 2027 (note 11), and assumed certain product transportation and processing commitments (note 20).
The acquisition has been accounted for as a business combination using the acquisition method of accounting. The allocation of
the purchase price was based on management's best estimates of the fair value of the assets and liabilities acquired as at the
acquisition date. Key assumptions used in the determination of estimated fair value were future commodity prices, expected
production volumes, quantity of reserves, asset retirement obligations, future development and production costs, discount
rates, and income taxes. The fair value of working capital approximates its carrying value. The below amounts are estimates,
and may be subject to change based on the receipt of new information.
The following provides a summary of the net assets acquired relating to the acquisition:
Property, plant and equipment
$
8,901
Exploration and evaluation assets
320
Working capital
115
Asset retirement obligations
(173)
Net assets acquired
$
9,163
As a result of the acquisition, revenue increased by approximately $222 million to $35,656 million and net operating income
(comprised of revenue less production, and transportation, blending and feedstock expenses) increased by approximately
$109 million to $17,579 million for the year ended December 31, 2024. Including the impact of interest expense and depletion,
depreciation and amortization, earnings before tax increased by approximately $23 million for the year ended December 31,
2024.
If the acquisition had been completed on January 1, 2024, the Company estimates that pro forma revenue would have
increased by approximately $2,700 million and pro forma net operating income would have increased by approximately
$1,475 million for the year ended December 31, 2024. Including the impact of interest expense and depletion, depreciation and
amortization, the Company estimates earnings before tax would have increased by approximately $570 million for the year
ended December 31, 2024. Readers are cautioned that pro forma estimates are not necessarily indicative of the results of
operations that would have resulted had the acquisition actually occurred on January 1, 2024, or of future results. Pro forma
results are based on historical information and reflect actual production in the period available for the assets as provided to the
Company and do not include any synergies that have or may arise subsequent to the acquisition date.
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 have been accounted for as business combinations using the acquisition method of accounting.
OTHER MATTERS
As at December 31, 2024, the Company determined that there were no indicators of impairment with respect to its property,
plant and equipment. Although there were no indicators of impairment, the Company completed its normal course assessment
of the recoverability of its property, plant and equipment and exploration and evaluation assets, and determined the carrying
amounts of all its cash generating units to be recoverable, except for certain North Sea property, plant and equipment where
recoverability charges have been recognized related to ongoing abandonment activities at the Ninian field.
As at December 31, 2024, property, plant and equipment included project costs, not subject to depletion and depreciation, of
$272 million in the Oil Sands Mining and Upgrading segment (2023 – $191 million in the Oil Sands Mining and Upgrading
segment).
75
Canadian Natural 2024 Annual Report
8. Leases
LEASE ASSETS
Product
transportation
and storage
Field
equipment and
power
Offshore
vessels and
equipment
Office leases
and other
Total
At December 31, 2022
$
912
$
377
$
97
$
61
$
1,447
Additions
27
218
49
23
317
Depreciation
(98)
(111)
(45)
(19)
(273)
Foreign exchange adjustments
and other
(1)
(2)
(30)
—
(33)
At December 31, 2023
840
482
71
65
1,458
Additions
5
118
40
68
231
Depreciation
(96)
(135)
(51)
(20)
(302)
Foreign exchange adjustments
and other
3
3
4
(3)
7
At December 31, 2024
$
752
$
468
$
64
$
110
$
1,394
LEASE ASSETS, BY SEGMENT
As at December 31, 2024 and 2023, the Company had the following lease assets by segment:
2024
2023
Exploration and Production
North America
$
257 $
280
North Sea
25
18
Offshore Africa
93
119
Oil Sands Mining and Upgrading
932
1,001
Head Office
87
40
$
1,394 $
1,458
LEASE LIABILITIES
The Company measures its lease liabilities at the discounted value of its lease payments during the lease term. Lease liabilities
at December 31, 2024 and 2023, were as follows:
2024
2023
Lease liabilities
$
1,464 $
1,555
Less: current portion
255
298
$
1,209 $
1,257
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 2024 and 2023 are provided below:
2024
2023
Expenses relating to short-term leases (1)
$
337 $
403
Interest expense on lease liabilities
$
69 $
64
Variable lease payments not included in the measurement of lease liabilities
$
59 $
59
Total cash outflows for leases (2)
$
1,333 $
1,325
(1)
During 2024, the Company capitalized $543 million (2023 – $514 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.
Canadian Natural 2024 Annual Report
76
9. Investments
For the years ended December 31, 2024 and 2023, the Company had the following investment:
2024
2023
Investment in PrairieSky Royalty Ltd.
$
—
$
525
INVESTMENT IN PRAIRIESKY ROYALTY LTD.
During 2024, the Company sold its 22.6 million common share investment in PrairieSky Royalty Ltd. ("PrairieSky") for $25.65 per
common share with net proceeds at close, after fees and expenses, of $575 million. 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 from the investment in PrairieSky was comprised as follows:
2024
2023
2022
Gain from investment
$
(50) $
(34) $
(182)
Dividend income
(6)
(22)
(14)
$
(56) $
(56) $
(196)
10. Other Long-Term Assets
2024
2023
Long-term prepayments, contracts and other (1)
$
313
$
279
Prepaid cost of service tolls
166
179
Long-term inventory
204
141
Risk management (note 19)
13
13
696
612
Less: current portion
76
71
$
620
$
541
(1)
Includes physical product sales contracts, accrued interest on PRT recoveries, and the unamortized cost of contributions to the Company's employee bonus
program.
INVESTMENT IN NORTH WEST REDWATER PARTNERSHIP
The Company has a 50% equity investment in NWRP. NWRP operates a 50,000 barrels per day bitumen upgrader and refinery
that processes approximately 12,500 barrels per day of bitumen feedstock for the Company (25% toll payer) and 37,500 barrels
per day of bitumen feedstock for the Alberta Petroleum Marketing Commission ("APMC") (75% toll payer), 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).
During 2024, NWRP repaid $500 million of 3.20% series A bonds. Additionally, in 2024 NWRP issued $700 million of 4.85%
series P bonds due June 2034 and $600 million of 5.08% series Q bonds due June 2054.
During 2024, NWRP entered into a $2,000 million unsecured commercial paper program and reserves capacity under its
revolving credit facility for these amounts.
NWRP's credit facilities consist of a $2,150 million syndicated credit facility (December 31, 2023 – $3,115 million) comprised of
a $1,900 million revolving portion maturing June 2027 (December 31, 2023 – $2,175 million), and a $250 million non-revolving
portion maturing June 2025 (December 31, 2023 – $940 million). The syndicated credit facility reserves capacity for a debt
service reserve equal to six months of anticipated facility interest and fees, and for amounts outstanding under its commercial
paper program.
During 2024, NWRP amended its syndicated credit facility to extend the revolving portion originally maturing June 2025 to June
2027, and reduce the authorized limit on the revolving portion by $275 million to $1,900 million. In 2024, NWRP repaid
$657 million on its non-revolving facility, and reduced the authorized limit to $250 million.
NWRP also has dedicated short-term borrowings under a $300 million syndicated credit facility ("demand operating facility")
(December 31, 2023 – $300 million), and $300 million uncommitted demand revolving letter of credit facilities ("bilateral
facilities") (December 31, 2023 – $150 million).
During 2024, NWRP increased its availability on its bilateral facilities, supporting letters of credit, to $300 million
(December 31, 2023 – $150 million).
77
Canadian Natural 2024 Annual Report
As at December 31, 2024, NWRP had borrowings of $251 million under the syndicated credit facility (December 31, 2023 –
$2,559 million), $1,459 million under its commercial paper program (December 31, 2023 – $nil), and $103 million under its
demand operating facility (December 31, 2023 – $77 million).
As at December 31, 2024, NWRP had $8,750 million in long-term notes outstanding (December 31, 2023 – $7,950 million).
The assets, liabilities, partners’ equity, product sales, and equity income (loss) related to NWRP at December 31, 2024 and
2023 were comprised as follows:
2024
2023
Current assets
$
535
$
349
Non-current assets
$
10,286
$
10,508
Current liabilities
$
2,082
$
1,054
Non-current liabilities
$
9,757
$
10,913
Partners’ equity
$
(1,018) $
(1,110)
Partners’ equity at Company's 50% interest
$
(509) $
(555)
Revenue (1)
$
1,490
$
1,527
Net income (loss) (2)
$
92
$
(8)
(1)
Included in NWRP's revenue for 2024 is $325 million (2023 – $335 million) related to the Company's 25% share of the refining toll.
(2)
Included in the net income (loss) for 2024 is the impact of depreciation and amortization expense of $346 million (2023 – $387 million) and interest and other
financing expense of $502 million (2023 – $500 million).
The carrying value of the Company’s interest in NWRP is $nil, and as at December 31, 2024, the cumulative unrecognized share
of the equity loss and partnership distributions from NWRP was $509 million (2023 – $555 million). The Company's recovery of
unrecognized equity losses from NWRP for 2024 was $46 million (2023 – unrecognized equity loss of $4 million; 2022 –
recovery of the unrecognized share of the equity loss of $11 million).
Canadian Natural 2024 Annual Report
78
11. Long-Term Debt
2024
2023
Canadian dollar denominated debt, unsecured
Medium-term notes
3.55% debentures due June 3, 2024
$
—
$
320
3.42% debentures due December 1, 2026
441
441
2.50% debentures due January 17, 2028
225
225
4.15% debentures due December 15, 2031
500
—
4.85% debentures due May 30, 2047
300
300
1,466
1,286
US dollar denominated debt, unsecured
Bank credit facilities (December 31, 2024 – US$3,393 million;
December 31, 2023 – US$nil)
4,888
—
Commercial paper (December 31, 2024 – US$467 million;
December 31, 2023 – US$nil)
672
—
US dollar debt securities
3.80% due April 15, 2024 (US$500 million)
—
660
3.90% due February 1, 2025 (US$600 million)
864
792
2.05% due July 15, 2025 (US$600 million)
864
792
3.85% due June 1, 2027 (US$1,250 million)
1,801
1,651
5.00% due December 15, 2029 (US$750 million)
1,080
—
2.95% due July 15, 2030 (US$500 million)
720
660
7.20% due January 15, 2032 (US$400 million)
576
528
6.45% due June 30, 2033 (US$350 million)
504
462
5.40% due December 15, 2034 (US$750 million)
1,080
—
5.85% due February 1, 2035 (US$350 million)
504
462
6.50% due February 15, 2037 (US$450 million)
649
594
6.25% due March 15, 2038 (US$1,100 million)
1,585
1,453
6.75% due February 1, 2039 (US$400 million)
576
528
4.95% due June 1, 2047 (US$750 million)
1,080
991
17,443
9,573
Long-term debt before transaction costs and original issue discounts, net
18,909
10,859
Less: original issue discounts, net (1)
12
11
transaction costs (1) (2)
78
49
18,819
10,799
Less: current portion of commercial paper
672
—
current portion of long-term debt (1) (2)
1,728
980
$
16,419
$
9,819
(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.
79
Canadian Natural 2024 Annual Report
BANK CREDIT FACILITIES AND COMMERCIAL PAPER
As at December 31, 2024, the Company had undrawn revolving bank credit facilities of $4,562 million. Additionally, the
Company had in place a fully drawn term credit facility of $4,000 million. Details of these facilities are described below. The
Company also has certain other dedicated credit facilities supporting letters of credit. As at December 31, 2024, the Company
had $672 million drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for
amounts outstanding under this program.
▪
a $100 million demand credit facility;
▪
a $500 million revolving credit facility, maturing February 2026;
▪
a $2,425 million revolving syndicated credit facility, maturing June 2027;
▪
a $4,000 million non-revolving term credit facility, maturing December 2027; and
▪
a $2,425 million revolving syndicated credit facility, maturing June 2028.
During 2024, the Company extended its $2,425 million revolving syndicated credit facility originally maturing June 2025 to June
2028.
During 2024 and in connection with the acquisition of Chevron's assets, the Company entered into a $4,000 million non-
revolving term credit facility maturing December 2027.
During 2023, the Company extended its $500 million revolving credit facility from February 2024 to February 2025. During 2024,
the Company extended its $500 million revolving credit facility from February 2025 to February 2026.
During 2023, the Company extended its $2,425 million revolving syndicated credit facility, originally maturing June 2024 to June
2027.
Borrowings under the Company's credit facilities may be made by way of pricing referenced to CORRA, SOFR, US base rate or
Canadian prime rate.
The Company’s borrowings under its US commercial paper program are authorized up to a maximum US$2,500 million.
The Company’s weighted average interest rate on bank credit facilities and commercial paper outstanding for the year ended
December 31, 2024 was 5.4% (December 31, 2023 – N/A), and on total long-term debt outstanding for the year ended
December 31, 2024 was 4.9% (December 31, 2023 – 4.8%).
As at December 31, 2024, letters of credit and guarantees aggregating to $1,542 million were outstanding (December 31,
2023 – $446 million).
MEDIUM-TERM NOTES
During 2024, the Company issued, by private placement, $500 million of 4.15% medium-term notes due December 2031.
During 2024, the Company repaid $320 million of 3.55% medium-term notes.
During 2023, the Company repaid $405 million of 1.45% medium-term notes.
During 2023, 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 2025. 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
2024, no medium-term notes were issued in Canada under the base shelf prospectus.
US DOLLAR DEBT SECURITIES
During 2024, the Company issued, by private placement, US$750 million of 5.00% notes due December 2029 and
US$750 million of 5.40% notes due December 2034.
During 2024, the Company repaid US$500 million of 3.80% US dollar debt securities.
Subsequent to December 31, 2024, the Company repaid US$600 million of 3.90% US dollar debt securities due February 2025.
During 2023, 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 2025. 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 2024, no US dollar debt securities were issued in the United States under the base shelf prospectus.
Canadian Natural 2024 Annual Report
80
SCHEDULED DEBT REPAYMENTS
Scheduled debt repayments are as follows:
Year
Repayment
2025
$
2,400
2026
$
941
2027
$
5,905
2028
$
509
2029
$
1,080
Thereafter
$
8,074
12. Other Long-Term Liabilities
2024
2023
Asset retirement obligations
$
8,607
$
7,690
Lease liabilities (note 8)
1,464
1,555
Share-based compensation
620
780
Transportation and processing contracts
58
87
Risk management (note 19)
8
4
Other
80
73
10,837
10,189
Less: current portion
1,535
1,503
$
9,302
$
8,686
ASSET RETIREMENT OBLIGATIONS
The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately
60 years and discounted using a weighted average discount rate of 4.8% (2023 – 5.2%; 2022 – 5.6%) and inflation rates of up
to 2% (2023 – up to 2%; 2022 – up to 2%). Reconciliations of the discounted asset retirement obligations were as follows:
2024
2023
2022
Balance – beginning of year
$
7,690
$
6,908 $
6,806
Liabilities incurred
28
25
20
Liabilities acquired, net
171
—
11
Liabilities settled
(646)
(509)
(449)
Asset retirement obligation accretion
389
366
281
Revision of cost, inflation and timing estimates (1)
417
621
897
Impact of regulatory changes (2)
—
—
982
Change in discount rates
419
314
(1,698)
Foreign exchange adjustments
139
(35)
58
Balance – end of year
8,607
7,690
6,908
Less: current portion
787
634
495
$
7,820
$
7,056 $
6,413
(1)
Includes normal course revisions of cost, inflation and timing estimates, as well as revisions related to cost estimate increases on future abandonment of the
Ninian field assets in the North Sea.
(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 in 2022.
81
Canadian Natural 2024 Annual Report
Segmented Asset Retirement Obligations
2024
2023
Exploration and Production
North America
$
4,783
$
4,471
North Sea
1,724
1,441
Offshore Africa
197
165
Oil Sands Mining and Upgrading
1,902
1,612
Midstream and Refining
1
1
$
8,607
$
7,690
SHARE-BASED COMPENSATION
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 with reference to the value of the Company's shares, and 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.
2024
2023
2022
Balance – beginning of year
$
780
$
832 $
489
Share-based compensation expense
279
491
804
Cash payment for stock options surrendered and PSUs vested
(84)
(110)
(79)
Transferred to common shares
(358)
(435)
(387)
Other
3
2
5
Balance – end of year
620
780
832
Less: current portion
463
538
559
$
157
$
242 $
273
Included within share-based compensation liability as at December 31, 2024 was $99 million (2023 – $96 million; 2022 –
$127 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:
2024
2023
2022
Fair value (1)
$
13.15
$
17.96 $
16.48
Share price (1)
$
44.38
$
43.41 $
37.60
Expected volatility
26.4%
30.9%
35.8%
Expected dividend yield
5.1%
4.6%
4.5%
Risk free interest rate
2.9%
3.6%
3.8%
Expected forfeiture rate
5.2%
5.4%
5.0%
Expected stock option life (2)
4.1 years
4.2 years
4.2 years
(1)
Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split (note 1).
(2)
At original time of grant.
The intrinsic value of vested stock options at December 31, 2024 was $181 million (2023 – $164 million; 2022 – $208 million).
Canadian Natural 2024 Annual Report
82
13. Income Taxes
The provision for income tax was as follows:
Expense (recovery)
2024
2023
2022
Current corporate income tax – North America (1)
$
1,654
$
1,853 $
2,789
Current corporate income tax – North Sea
(41)
(6)
69
Current corporate income tax – Offshore Africa
57
73
74
Current PRT (2) – North Sea
(134)
(58)
(42)
Other taxes
(5)
17
16
Current income tax
1,531
1,879
2,906
Deferred corporate income tax
520
267
302
Deferred PRT (2) – North Sea
(98)
(214)
(441)
Deferred income tax
422
53
(139)
Income tax
$
1,953
$
1,932 $
2,767
(1)
Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments.
(2)
Petroleum Revenue Tax.
As at December 31, 2024, the Company recognized deferred tax recoveries comprised of a deferred corporate income tax
recovery of $50 million (2023 – $118 million, 2022 – $528 million) and a deferred PRT recovery of $89 million (2023 –
$205 million, 2022 – $441 million) in connection with the increase in the Company's estimate of future abandonment costs for
the planned decommissioning activities at the Ninian field in the North Sea.
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:
2024
2023
2022
Canadian statutory income tax rate
23.2%
23.3%
23.2%
Income tax provision at statutory rate
$
1,870
$
2,364 $
3,180
Effect on income taxes of:
UK PRT and other taxes
(237)
(255)
(467)
Impact of UK PRT and other taxes on corporate income tax
95
105
190
Foreign and domestic tax rate differentials
(112)
(104)
(203)
Non-taxable portion of capital loss (gains)
114
(35)
65
Stock options exercised for common shares
41
91
159
Revisions arising from prior year tax filings
43
(174)
(186)
Change in unrecognized capital loss carryforward asset
114
(35)
65
Other
25
(25)
(36)
Income tax
$
1,953
$
1,932 $
2,767
83
Canadian Natural 2024 Annual Report
The following table summarizes the temporary differences that give rise to the net deferred income tax liability:
2024
2023
Deferred income tax liabilities
Property, plant and equipment and exploration and evaluation assets
$
12,647
$
12,172
Lease assets
316
336
Investments
—
54
Investment in North West Redwater Partnership
908
904
Taxable PRT for corporate income tax
336
256
Other
92
41
14,299
13,763
Deferred income tax assets
Asset retirement obligations
(2,437)
(2,098)
Lease liabilities
(332)
(356)
Share-based compensation
(35)
(31)
Loss carryforwards
(36)
(417)
Unrealized foreign exchange loss on long-term debt
(125)
(39)
Deferred PRT
(795)
(639)
(3,760)
(3,580)
Net deferred income tax liability
$
10,539
$
10,183
Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows:
2024
2023
2022
Property, plant and equipment and exploration and evaluation assets
$
443
$
196 $
(334)
Lease assets
(22)
1
(15)
Unrealized foreign exchange on long-term debt
(86)
28
(81)
Unrealized risk management activities
(1)
—
(12)
Asset retirement obligations
(279)
(292)
(74)
Lease liabilities
26
(3)
11
Share-based compensation
(4)
2
(11)
Loss carryforwards
381
235
618
Investments
(54)
(2)
21
Investment in North West Redwater Partnership
4
1
53
Deferred PRT
58
86
(441)
Taxable PRT for corporate income tax
(98)
(214)
176
Other
54
15
(50)
$
422
$
53 $
(139)
The following table summarizes the movements of the net deferred income tax liability during the year:
2024
2023
2022
Balance – beginning of year
$
10,183
$
10,114 $
10,220
Deferred income tax expense (recovery)
422
53
(139)
Foreign exchange adjustments
(66)
16
33
Balance – end of year
$
10,539
$
10,183 $
10,114
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.
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.
Canadian Natural 2024 Annual Report
84
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.
The Company has reviewed the Organization for Economic Co-operation and Development's Pillar Two model rules and has
concluded it does not have a significant impact.
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 $950 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.
2024
2023
ISSUED COMMON SHARES(1)
Number
of shares
(thousands)
Amount
Number
of shares
(thousands)
Amount
Balance – beginning of year
2,144,815
$
10,712
2,205,272 $
10,294
Issued upon exercise of stock options
13,531
280
19,643
372
Previously recognized liability on stock options
exercised for common shares
—
358
—
435
Purchase of common shares under Normal Course
Issuer Bid
(55,350)
(286)
(80,100)
(389)
Balance – end of year
2,102,996
$
11,064
2,144,815 $
10,712
PREFERRED SHARES
Preferred shares are issuable in a series. If issued, the number of shares in each series, and the designation, rights, privileges,
restrictions, and conditions attached to the shares will be determined by the Board of Directors of the Company.
DIVIDENDS(1)
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 5, 2025, the Board of Directors approved a 4% increase in the quarterly dividend to $0.5875 per common share,
beginning with the dividend payable on April 4, 2025.
On October 7, 2024, the Board of Directors approved a 7% increase in the quarterly dividend to $0.5625 per common share,
beginning with the dividend paid on January 3, 2025. On February 28, 2024, the Board of Directors approved a 5% increase in
the quarterly dividend to $0.525 per common share.
On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $0.50 per common share.
On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.45 per common share.
NORMAL COURSE ISSUER BID(1)
On March 8, 2024, 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 180,462,858 common shares, representing 10% of the public float, over a 12-month period commencing March
13, 2024 and ending March 12, 2025.
(1)
Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split (note 1).
85
Canadian Natural 2024 Annual Report
For the year ended December 31, 2024, the Company purchased 55,350,000 common shares at a weighted average price of
$48.07 per common share for a total cost, including tax, of $2,700 million. Retained earnings were reduced by $2,414 million,
representing the excess of the purchase price of common shares over their average carrying value. Subsequent to
December 31, 2024, up to and including March 4, 2025, the Company purchased 7,740,000 common shares at a weighted
average price of $44.11 per common share for a total cost, including tax, of $344 million.
On March 5, 2025, 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 will be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE.
SHARE-BASED COMPENSATION – STOCK OPTIONS(1)
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, 2024 and 2023:
2024
2023
Stock options
(thousands)
Weighted
average
exercise price
Stock options
(thousands)
Weighted
average
exercise price
Outstanding – beginning of year
52,410
$
26.80
62,300 $
21.19
Granted
15,906
$
44.82
14,047 $
40.09
Exercised for common shares
(13,531) $
20.69
(19,643) $
18.92
Surrendered for cash settlement
(384) $
22.19
(435) $
19.39
Forfeited
(3,595) $
29.69
(3,859) $
25.43
Outstanding – end of year
50,806
$
33.90
52,410 $
26.80
Exercisable – end of year
10,033
$
26.67
7,344 $
21.07
The range of exercise prices of stock options outstanding and exercisable at December 31, 2024 was as follows:
Stock options outstanding
Stock options exercisable
Range of exercise prices
Stock options
outstanding
(thousands)
Weighted
average
remaining
term (years)
Weighted
average
exercise price
Stock options
exercisable
(thousands)
Weighted
average
exercise price
$10.38
– $14.99
6,890
1.07
$
13.98
2,203
$
12.91
$15.00
– $19.99
3,848
0.31
$
18.65
1,684
$
17.94
$20.00
– $24.99
3,203
1.48
$
20.24
1,474
$
20.15
$25.00
– $29.99
686
2.86
$
27.12
169
$
27.12
$30.00
– $34.99
5,923
2.50
$
32.47
1,150
$
32.39
$35.00
– $39.99
13,146
3.18
$
39.24
2,612
$
38.86
$40.00
– $44.99
11,134
4.36
$
42.57
13
$
42.20
$45.00
– $49.99
5,651
4.50
$
48.04
728
$
48.53
$50.00
– $52.98
325
5.30
$
52.98
—
$
—
50,806
2.90
$
33.90
10,033
$
26.67
(1)
Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split (note 1).
Canadian Natural 2024 Annual Report
86
15. Accumulated Other Comprehensive Income
The components of accumulated other comprehensive income, net of taxes, were as follows:
2024
2023
Derivative financial instruments designated as cash flow hedges
$
70
$
72
Foreign currency translation adjustment
231
100
$
301
$
172
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 ratio of current and long-term debt less cash and cash equivalents divided by the sum of the carrying value of
shareholders' equity plus current 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%. The ratio may fall below or exceed the targeted range depending on the
execution of the Company's capital program, commodity price and foreign currency volatility, and the timing of acquisitions. As
at December 31, 2024, the ratio was within the target range at 32%.
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.
2024
2023
Long-term debt
$
18,819
$
10,799
Less: cash and cash equivalents
131
877
Long-term debt, net
$
18,688
$
9,922
Total shareholders’ equity
$
39,468
$
39,832
Debt to book capitalization
32%
20%
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, 2024, the Company was in compliance with this covenant.
17. Net Earnings Per Common Share(1)
2024
2023
2022
Weighted average common shares outstanding
– basic (thousands of shares)
2,125,804
2,182,623
2,269,919
Effect of dilutive stock options (thousands of shares)
14,625
21,625
28,444
Weighted average common shares outstanding
– diluted (thousands of shares)
2,140,429
2,204,248
2,298,363
Net earnings
$
6,106
$
8,233 $
10,937
Net earnings per common share
– basic
$
2.87
$
3.77 $
4.82
– diluted
$
2.85
$
3.74 $
4.76
In 2024, the Company excluded 12,144,000 potentially anti-dilutive stock options from the calculation of diluted earnings per
common share (2023 – 6,461,000; 2022 – 4,078,000).
(1)
Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split (note 1).
87
Canadian Natural 2024 Annual Report
18. Interest and Other Financing Expense
2024
2023
2022
Interest expense on long-term debt
$
604
$
627 $
610
Interest expense on lease liabilities
69
64
60
Interest expense on long-term debt and lease liabilities
673
691
670
Interest (income) and other expense
(81)
(55)
(121)
Interest and other financing expense
$
592
$
636 $
549
19. Financial Instruments
The Company's financial instruments are comprised of cash and cash equivalents, accounts receivable, investments, risk
management assets and liabilities, accounts payable, accrued liabilities, lease liabilities, and long-term debt. These financial
instruments, with the exception of investments and risk management assets and liabilities, are classified as financial assets and
liabilities at amortized cost. Investments are classified as financial assets at fair value through profit or loss and are based on
quoted market prices. Risk management assets and liabilities are classified as derivatives held for trading or as cash flow
hedges.
At each measurement date, the estimated fair values of derivative financial instruments in Level 2 have been determined based
on appropriate internal valuation methodologies and/or third party indications, including quoted forward prices for commodities,
foreign exchange rates, interest yield curves and other volatility factors.
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)
2024
2023
Balance – beginning of year
$
9
$
6
Net change in fair value of outstanding derivative financial instruments recognized in:
Risk management activities (1)
(6)
3
Foreign exchange
1
—
Other comprehensive income
1
—
Balance – end of year
5
9
Less: current portion
5
8
$
—
$
1
(1)
Risk management assets and liabilities are disclosed in note 10 and note 12, respectively.
Net loss (gain) from risk management activities for the years ended December 31, were as follows:
2024
2023
2022
Net realized risk management loss (gain)
$
168
$
(14) $
(7)
Net unrealized risk management loss (gain)
9
12
(28)
$
177
$
(2) $
(35)
The carrying amounts of the Company’s financial instruments approximated their fair value, except for fixed rate long-term debt.
The Company's financial instruments are categorized as Level 1 with the exception of risk management assets and liabilities
which are categorized as Level 2. There were no transfers between Level 1, 2 and 3 financial instruments. The fair value of the
Company’s fixed rate long-term debt is outlined below:
2024
2023
Carrying amount
Level 1
Fair Value
Carrying amount
Level 1
Fair Value
Fixed rate long-term debt (1) (2)
$
13,259
$
13,186
$
10,799 $
10,795
(1)
The fair value of fixed rate long-term debt has been determined based on quoted market prices.
(2)
Includes the current portion of fixed rate long-term debt.
Canadian Natural 2024 Annual Report
88
RISK MANAGEMENT
The Company periodically uses derivative financial instruments to manage its commodity price, interest rate, and foreign
currency exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative
purposes.
The following provides a summary of the carrying amounts of derivative financial instruments held and a reconciliation to the
Company’s consolidated balance sheets.
Asset (liability)
2024
2023
Derivatives held for trading
Natural gas (1) (2)
$
7
$
(3)
Foreign currency forward contracts
(2)
12
$
5
$
9
Included within:
Current portion of other long-term assets
$
13
$
12
Current portion of other long-term liabilities
(8)
(4)
Other long-term assets
—
1
$
5
$
9
(1)
In 2024, the Company entered into fixed price financial contracts to buy 12,500 MMBtu/d of natural gas at US$1.47 AECO, and 25,000 MMBtu/d of natural
gas at US$1.82 AECO for the period of January to December 2025.
(2)
In 2023, the Company entered into fixed price financial contracts to buy 50,000 MMBtu/d of natural gas at US$1.82 AECO for the period of January to
December 2024.
FINANCIAL RISK FACTORS
The Company's financial risks are consistent with those disclosed in notes 1 and 4.
a) Market risk
Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in
market prices. The Company’s market risk is comprised of commodity price risk, interest rate risk, and foreign currency
exchange risk.
COMMODITY PRICE RISK MANAGEMENT
The Company periodically uses commodity derivative financial instruments to manage its exposure to commodity price risk
associated with the sale of its future crude oil and natural gas production and with natural gas purchases.
The Company's outstanding commodity derivative financial instruments are expected to be settled monthly based on the
applicable index pricing for the respective contract month.
INTEREST RATE RISK MANAGEMENT
The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company periodically enters into interest rate swap contracts to manage its fixed to floating
interest rate mix on long-term debt. Interest rate swap contracts require the periodic exchange of payments without the
exchange of the notional principal amounts on which the payments are based. As at December 31, 2024, the Company had no
interest rate swap contracts outstanding.
FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long-
term debt, commercial paper and working capital. The Company is also exposed to foreign currency exchange rate risk on
transactions conducted in other currencies and in the carrying value of its foreign subsidiaries. The Company periodically enters
into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on US dollar
denominated long-term debt, commercial paper, and working capital. The cross currency swap contracts require the periodic
exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based.
As at December 31, 2024, the Company had US$2,187 million of foreign currency forward contracts outstanding (December 31,
2023 – US$1,003 million), with original terms of up to 90 days, of which US$1,521 million were designated as derivatives held
for trading (December 31, 2023 – US$1,003 million) and US$666 million were designated as cash flow hedges (December 31,
2023 – US$nil).
89
Canadian Natural 2024 Annual Report
FINANCIAL INSTRUMENT SENSITIVITIES
The following table summarizes the annualized sensitivities of the Company’s 2024 net earnings and other comprehensive
income to changes in the fair value of financial instruments outstanding as at December 31, 2024, 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.
2024
2023
Increase
(decrease) to
net earnings
Increase
(decrease) to
other
comprehensive
income
Increase
(decrease) to
net earnings
Increase
(decrease) to
other
comprehensive
income
Interest rate risk
Increase interest rate 1%
$
(46) $
— $
(5) $
—
Decrease interest rate 1%
$
46 $
— $
5 $
—
Foreign currency exchange rate risk
Weakening of the Canadian dollar by US$0.01
$
(255) $
— $
(128) $
—
Strengthening of the Canadian dollar by US$0.01
$
248 $
— $
125 $
—
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, ensuring that parental guarantees or letters of credit are in place to minimize the impact in the
event of default. As at December 31, 2024, substantially all of the Company’s accounts receivable were due within normal trade
terms and the average expected credit loss was approximately 2% of the Company's accounts receivable balance
(December 31, 2023 – 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. As at December 31, 2024, the Company had net risk of $11 million with
specific counterparties related to derivative financial instruments (December 31, 2023 – $11 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
$
1,079 $
— $
— $
—
Accrued liabilities
$
4,525 $
— $
— $
—
Long-term debt (1)
$
2,400 $
941 $
7,494 $
8,074
Other long-term liabilities (2)
$
263 $
187 $
405 $
617
Interest and other financing expense (3)
$
1,024 $
951 $
1,978 $
3,574
(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, $255 million; one to less than
two years, $187 million; two to less than five years, $405 million; and thereafter, $617 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, 2024.
Canadian Natural 2024 Annual Report
90
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, 2024:
2025
2026
2027
2028
2029
Thereafter
Product transportation, purchases and
processing (1) (2) (3)
$
2,249 $
2,245 $
2,097 $
1,983 $
1,882 $
19,310
North West Redwater Partnership
service toll (4)
$
141 $
121 $
103 $
104 $
104 $
4,203
Offshore vessels and equipment
$
88 $
— $
— $
— $
— $
—
Field equipment and power (3)
$
43 $
29 $
29 $
28 $
27 $
216
Other
$
124 $
111 $
21 $
22 $
21 $
247
(1)
The Company's commitment for the 20-year product transportation agreement on the Trans Mountain Expansion ("TMX") pipeline reflects interim tolls
approved by the Canada Energy Regulator in 2023, and is subject to change pending the approval of final tolls.
(2)
During 2024, the Company increased its total committed capacity on the TMX pipeline to 169,000 bbl/d, an incremental 75,000 bbl/d over the 20-year term.
(3)
During 2024, the acquisition of Chevron's assets included approximately $1,292 million of product transportation and processing commitments and
approximately $75 million of field equipment and power commitments (note 7).
(4)
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 $2,161 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
2024
2023
2022
Changes in non-cash working capital:
Accounts receivable
$
(940) $
368 $
(441)
Inventory
(616)
(219)
(266)
Prepaids and other
(42)
(23)
(20)
Accounts payable
(340)
78
537
Accrued liabilities
851
(812)
896
Current income tax (liabilities) assets
326
(1,558)
(282)
Other long-term liabilities
(106)
(200)
(196)
Net changes in non-cash working capital
$
(867) $
(2,366) $
228
Relating to:
Operating activities
$
(743) $
(2,417) $
79
Investing activities
(124)
51
149
$
(867) $
(2,366) $
228
91
Canadian Natural 2024 Annual Report
The following table summarizes movements in the Company's liabilities arising from financing activities for the years ended
December 31, 2024 and 2023:
Long-term
debt
Lease
liabilities
Liabilities from
financing
activities
At December 31, 2022
$
11,445
$
1,540
$
12,985
Changes from financing cash flows:
Repayment of other long-term debt (1)
(416)
—
(416)
Payment of lease liabilities
—
(285)
(285)
Non-cash changes:
Lease additions
—
317
317
Changes in foreign exchange and fair value (2)
(230)
(17)
(247)
At December 31, 2023
$
10,799
$
1,555
$
12,354
Changes from financing cash flows:
Issuance of bank credit facilities and commercial paper, net (1)
5,466
—
5,466
Issuance of other long-term debt (1)
2,639
—
2,639
Repayment of other long-term debt (1)
(1,008)
—
(1,008)
Payment of lease liabilities
—
(325)
(325)
Non-cash changes:
Lease additions
—
231
231
Changes in foreign exchange and fair value (2)
923
3
926
At December 31, 2024
$
18,819
$
1,464
$
20,283
(1)
Includes original issue discounts and premiums, and directly attributable transaction costs.
(2)
Includes foreign exchange loss (gain), the amortization of original issue discounts and premiums and directly attributable transaction costs, and derecognition
of lease liabilities.
Canadian Natural 2024 Annual Report
92
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.
North America
North Sea
Offshore Africa
(millions of Canadian dollars)
2024
2023
2022
2024
2023
2022
2024
2023
2022
Segmented product sales
Crude oil and NGLs (1)
$ 18,740 $ 17,375 $ 20,755 $
467 $
435 $
623 $
434 $
577 $
694
Natural gas
1,415
2,375
4,931
7
7
13
42
51
55
Other income and revenue (2)
6
10
217
4
—
—
4
9
8
Total segmented product sales
20,161
19,760
25,903
478
442
636
480
637
757
Less: royalties
(2,876)
(2,443)
(3,918)
(1)
(1)
(1)
(24)
(57)
(71)
Segmented revenue
17,285
17,317
21,985
477
441
635
456
580
686
Segmented expenses
Production
3,249
3,617
3,754
440
342
437
109
141
114
Transportation, blending and
feedstock (1)
6,184
5,808
6,394
10
7
6
1
1
1
Depletion, depreciation and
amortization (3)
3,831
3,679
3,595
279
494
1,747
297
213
173
Asset retirement obligation
accretion
231
234
171
65
46
33
9
8
7
Risk management loss
(commodity derivatives)
7
24
18
—
—
—
—
—
—
Total segmented expenses
13,502
13,362
13,932
794
889
2,223
416
363
295
Segmented earnings (loss)
$
3,783 $
3,955 $
8,053 $
(317) $
(448) $ (1,588) $
40 $
217 $
391
Non-segmented expenses
Administration
Share-based compensation
Interest and other financing
expense
Risk management loss (gain)
(other)
Foreign exchange loss (gain)
Gain from investments
Total non-segmented expenses
Earnings before taxes
Current income tax
Deferred income tax
Net earnings
(1)
Includes blending and feedstock costs associated with the processing of third party bitumen and other purchased feedstock in the Oil Sands Mining and
Upgrading segment.
(2)
Includes the sale of diesel and other refined products and other income, including government grants and recoveries associated with the joint operations
partners' share of the costs of lease contracts.
(3)
Includes a recoverability charge in depletion, depreciation and amortization, related to the Ninian field in the North Sea at December 31, 2024 for $160 million
(2023 – $436 million; 2022 – $1,620 million) (note 7).
93
Canadian Natural 2024 Annual Report
Inter-segment Elimination and Other includes internal and corporate transportation and electricity charges. Production,
processing, and other purchasing and selling activities, that are not included in the preceding segments are also reported in the
segmented information as Inter-segment Elimination and Other.
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.
Oil Sands Mining
and Upgrading
Midstream and Refining
Inter-segment
Elimination and Other
Total
2024
2023
2022
2024
2023
2022
2024
2023
2022
2024
2023
2022
$ 19,263 $ 18,661 $ 20,804 $
82 $
76 $
80 $
98 $
176 $
53 $ 39,084 $ 37,300 $ 43,009
—
—
—
—
—
—
104
142
237
1,568
2,575
5,236
16
5
149
813
926
906
14
10
5
857
960
1,285
19,279
18,666
20,953
895
1,002
986
216
328
295
41,509
40,835
49,530
(2,952)
(2,366)
(3,242)
—
—
—
—
—
—
(5,853)
(4,867)
(7,232)
16,327
16,300
17,711
895
1,002
986
216
328
295
35,656
35,968
42,298
3,921
3,989
4,076
315
332
271
59
59
60
8,093
8,480
8,712
2,959
2,563
2,652
685
664
691
145
259
229
9,984
9,302
9,973
2,258
2,011
1,822
16
16
16
—
—
—
6,681
6,413
7,353
84
78
70
—
—
—
—
—
—
389
366
281
—
—
—
—
—
—
—
—
—
7
24
18
9,222
8,641
8,620
1,016
1,012
978
204
318
289
25,154
24,585
26,337
$
7,105 $
7,659 $
9,091 $
(121) $
(10) $
8 $
12 $
10 $
6 $ 10,502 $ 11,383 $ 15,961
503
452
415
279
491
804
592
636
549
170
(26)
(53)
955
(279)
738
(56)
(56)
(196)
2,443
1,218
2,257
8,059
10,165
13,704
1,531
1,879
2,906
422
53
(139)
$
6,106 $
8,233 $ 10,937
Canadian Natural 2024 Annual Report
94
CAPITAL EXPENDITURES (1)
2024
2023
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 (3)
$
406
$
(29) $
377
$
41 $
(36) $
5
Offshore Africa
6
(62)
(56)
3
—
3
Oil Sands Mining and
Upgrading (3)
—
(7)
(7)
—
(25)
(25)
412
(98)
314
44
(61)
(17)
Property, plant and
equipment
Exploration and
Production
North America (3)
5,627
(146)
5,481
2,729
(321)
2,408
North Sea
39
295
334
33
525
558
Offshore Africa
197
8
205
169
18
187
5,863
157
6,020
2,931
222
3,153
Oil Sands Mining and
Upgrading (3)
8,104
(134)
7,970
1,894
(251)
1,643
Midstream and Refining
11
—
11
10
—
10
Head Office
41
—
41
30
—
30
14,019
23
14,042
4,865
(29)
4,836
$
14,431
$
(75) $
14,356
$
4,909 $
(90) $
4,819
(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 $320 million for exploration and evaluation assets and $2,553 million for property, plant and equipment within the North
America Exploration and Production segment, and $6,175 million for property, plant and equipment within the Oil Sands Mining and Upgrading segment
acquired from Chevron in 2024.
SEGMENTED ASSETS
2024
2023
Exploration and Production
North America
$
32,670
$
30,058
North Sea
702
602
Offshore Africa
1,412
1,380
Other
31
32
Oil Sands Mining and Upgrading
49,221
42,865
Midstream and Refining
1,099
856
Head Office
224
162
$
85,359
$
75,955
95
Canadian Natural 2024 Annual Report
23. Remuneration of Directors and Senior Management
REMUNERATION OF NON-MANAGEMENT DIRECTORS
2024
2023
2022
Fees earned
$
3
$
3 $
2
REMUNERATION OF SENIOR MANAGEMENT (1)
2024
2023
2022
Salary
$
2
$
2 $
2
Common stock option based awards
11
13
12
Annual incentive plans
6
5
5
Long-term incentive plans
20
19
18
$
39
$
39 $
37
(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.
24. Subsequent Events
On January 29, 2025, the Company announced that pursuant to an agreement with Shell Canada Limited and affiliates ("Shell")
and as a result of certain conditions being met, the Company will acquire a 10% working interest in the AOSP mines,
associated reserves and additional working interests in a number of other non-producing oil sands leases in exchange for a 10%
working interest in the Scotford Upgrader and Quest. Following the close of the transaction, the Company will have a 100%
direct working interest in the AOSP mines and an 80% interest in the Scotford Upgrader and Quest, where Shell will remain
operator. The transaction does not include an exchange of cash, except for regular closing adjustments for working capital. The
acquisition is targeted to close in the first half of 2025, subject to obtaining the necessary regulatory approvals.
Canadian Natural 2024 Annual Report
96
Supplementary Oil & Gas Information for the Fiscal
Year Ended December 31, 2024 (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, 2024, 2023, 2022, and 2021 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, 2024,
2023, 2022, and 2021 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 2024 and 2023 reserves for SEC
requirements.
Crude Oil and NGLs
Natural Gas
WTI
WCS
Canadian
Light
Sweet
Cromer
LSB
Brent
Edmonton
C5+
Henry Hub
AECO
BC
Westcoast
Station 2
(US$/bbl)
(C$/bbl)
(C$/bbl)
(C$/bbl)
(US$/bbl)
(C$/bbl)
(US$/MMBtu)
(C$/MMBtu)
(C$/MMBtu)
2024
74.88
80.78
96.35
93.44
78.81
98.90
2.37
1.28
0.91
2023
78.10
79.95
100.93
99.48
82.51
103.43
2.75
2.79
2.10
A foreign exchange rate of US$0.7325/C$1.00 was used in the 2024 evaluation (2023 - US$0.7407/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, 2024, 2023, 2022, and 2021, 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 year ended December 31, 2024 the reports by Sproule International Limited, and for the years ended December 31,
2023, 2022, and 2021 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.
97
Canadian Natural 2024 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, 2024, 2023, 2022 and 2021:
North America
Crude Oil and NGLs (MMbbl) (1)
Synthetic
Crude Oil
Bitumen (2)
Crude Oil
& NGLs
North
America
Total
North
Sea
Offshore
Africa
Total
Net Proved Reserves
Reserves, December 31, 2021
5,944
2,289
708
8,941
79
64
9,083
Extensions and discoveries
—
195
11
205
—
—
205
Improved recovery
29
5
21
56
—
—
56
Purchases of reserves in place
—
267
21
288
—
—
288
Sales of reserves in place
—
—
—
—
—
—
—
Production
(128)
(91)
(45)
(265)
(5)
(5)
(274)
Economic revisions due to prices (3)
(455)
(263)
(73)
(791)
1
(2)
(792)
Revisions of prior estimates
—
144
54
198
(64)
—
134
Reserves, December 31, 2022
5,390
2,546
696
8,632
11
57
8,700
Extensions and discoveries
162
67
51
280
—
—
280
Improved recovery
28
9
37
75
—
—
75
Purchases of reserves in place
—
—
—
—
—
—
—
Sales of reserves in place
—
—
(1)
(1)
—
—
(1)
Production
(141)
(102)
(47)
(289)
(5)
(4)
(298)
Economic revisions due to prices (3)
333
123
29
484
—
1
485
Revisions of prior estimates
68
26
1
94
3
1
98
Reserves, December 31, 2023
5,840
2,669
767
9,276
9
54
9,339
Extensions and discoveries
—
62
31
93
—
—
93
Improved recovery
1
7
13
21
—
—
21
Purchases of reserves in place
701
1
137
839
—
—
839
Sales of reserves in place
—
—
(2)
(2)
—
—
(2)
Production
(141)
(101)
(49)
(291)
(4)
(4)
(299)
Economic revisions due to prices (3)
(106)
(38)
(35)
(180)
—
—
(179)
Revisions of prior estimates
18
77
42
136
1
(2)
136
Reserves, December 31, 2024
6,313
2,676
903
9,892
6
48
9,947
Net Proved Developed Reserves
December 31, 2021
5,929
584
370
6,883
39
38
6,960
December 31, 2022
5,389
582
359
6,330
5
34
6,369
December 31, 2023
5,804
610
337
6,752
6
30
6,787
December 31, 2024
6,268
629
359
7,256
6
25
7,288
(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) Includes changes due to commodity price and resulting royalty volumes.
Canadian Natural 2024 Annual Report
98
2024 total proved Crude Oil and NGLs reserves increased by 607 MMbbl:
▪
Extensions and discoveries: Increase of 93 MMbbl primarily due to extension drilling/future offset additions at various
Bitumen, natural gas (NGLs) and Crude Oil properties.
▪
Improved recovery: Increase of 21 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs)
and Crude Oil and Bitumen properties as well as improved recovery at Oil Sands Mining and Upgrading (SCO) properties.
▪
Purchases of reserves in place: Increase of 839 MMbbl primarily due to acquisitions at Oil Sands Mining and Upgrading
(SCO) and various natural gas (NGLs) and Crude Oil properties in Alberta.
▪
Sales of reserves in place: Decrease of 2 MMbbl primarily due to dispositions from various natural gas (NGLs) properties in
Alberta.
▪
Production: Decrease of 299 MMbbl.
▪
Economic revisions due to prices: Decrease of 179 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 136 MMbbl primarily due to improved performance at various Bitumen, natural gas
(NGLs) and Crude Oil properties as well as transfers from beyond the 50-year reserves life cutoff at Oil Sands Mining and
Upgrading (SCO).
2023 total proved Crude Oil and NGLs reserves increased by 639 MMbbl:
▪
Extensions and discoveries: Increase of 280 MMbbl primarily due to pit extensions at Oil Sands Mining and Upgrading
(SCO) and infill drilling/future offset additions at various Bitumen, natural gas (NGLs) and Crude Oil properties.
▪
Improved recovery: Increase of 75 MMbbl primarily due to infill drilling/future offset additions at various natural gas (NGLs)
and Crude Oil properties as well as improved recovery at Oil Sands Mining and Upgrading (SCO) and Bitumen properties.
▪
Sales of reserves in place: Decrease of 1 MMbbl primarily due to dispositions from various natural gas (NGLs) properties in
Alberta.
▪
Production: Decrease of 298 MMbbl.
▪
Economic revisions due to prices: Increase of 485 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 98 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 Bitumen properties.
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 increased 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.
99
Canadian Natural 2024 Annual Report
Natural Gas (Bcf) (1)
North
America
North
Sea
Offshore
Africa
Total
Net Proved Reserves
Reserves, December 31, 2021
11,285
8
25
11,318
Extensions and discoveries
251
—
—
251
Improved recovery
192
—
—
192
Purchases of reserves in place
228
—
—
228
Sales of reserves in place
—
—
—
—
Production
(688)
(1)
(4)
(693)
Economic revisions due to prices (2)
(572)
—
(3)
(575)
Revisions of prior estimates
1,521
(3)
7
1,526
Reserves, December 31, 2022
12,217
4
25
12,246
Extensions and discoveries
1,185
—
—
1,185
Improved recovery
603
—
—
603
Purchases of reserves in place
—
—
—
—
Sales of reserves in place
(6)
—
—
(6)
Production
(750)
(1)
(4)
(755)
Economic revisions due to prices (2)
87
—
1
88
Revisions of prior estimates
57
(1)
1
58
Reserves, December 31, 2023
13,393
3
23
13,419
Extensions and discoveries
202
—
—
202
Improved recovery
152
—
—
152
Purchases of reserves in place
1,090
—
—
1,090
Sales of reserves in place
(44)
—
—
(44)
Production
(765)
(1)
(3)
(769)
Economic revisions due to prices (2)
(3,860)
—
—
(3,860)
Revisions of prior estimates
988
1
(2)
987
Reserves, December 31, 2024
11,155
3
18
11,177
Net Proved Developed Reserves
December 31, 2021
4,469
3
20
4,492
December 31, 2022
4,956
1
19
4,975
December 31, 2023
4,029
1
10
4,040
December 31, 2024
3,347
3
7
3,357
(1) Information in the reserves data tables may not add due to rounding.
(2) Includes changes due to commodity price and resulting royalty volumes.
Canadian Natural 2024 Annual Report
100
2024 total proved Natural Gas reserves decreased by 2,242 Bcf primarily due to the following:
▪
Extensions and discoveries: Increase of 202 Bcf primarily due to extension drilling/future offset additions in the Montney
formation of northwest Alberta and northeast British Columbia.
▪
Improved recovery: Increase of 152 Bcf primarily due to infill drilling/future offset additions in the Montney formation of
northwest Alberta and northeast British Columbia.
▪
Purchases of reserves in place: Increase of 1,090 Bcf primarily due to acquisitions at various Natural Gas properties in
Alberta.
▪
Sales of reserves in place: Decrease of 44 Bcf primarily due to dispositions from various Natural Gas properties in Alberta.
▪
Production: Decrease of 769 Bcf.
▪
Economic revisions due to prices: Decrease of 3,860 Bcf primarily due to lower natural gas pricing.
▪
Revisions of prior estimates: Increase of 987 Bcf primarily due to improved performance at various Natural Gas properties
as well as category transfers from probable to proved.
2023 total proved Natural Gas reserves increased by 1,173 Bcf primarily due to the following:
▪
Extensions and discoveries: Increase of 1,185 Bcf primarily due to extension drilling/future offset additions in the Montney
formation of northwest Alberta and northeast British Columbia.
▪
Improved recovery: Increase of 603 Bcf primarily due to infill drilling/future offsets additions in the Montney formation of
northwest Alberta and northeast British Columbia.
▪
Sales of reserves in place: Decrease of 6 Bcf primarily due to dispositions from various Natural Gas properties in Alberta.
▪
Production: Decrease of 755 Bcf.
▪
Economic revisions due to prices: Increase of 88 Bcf primarily at various North America Natural Gas properties due to lower
natural gas pricing resulting in lower royalties and higher net reserves.
▪
Revisions of prior estimates: Increase of 58 Bcf primarily due to category transfers from probable to proved partially offset
by negative revisions in various North American core areas as a result of decreased performance.
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 offsets 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.
101
Canadian Natural 2024 Annual Report
Capitalized Costs Related to Crude Oil and Natural Gas Activities
2024
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Proved properties
$
146,309
$
9,731
$
5,023
$
161,063
Unproved properties
2,478
—
48
2,526
148,787
9,731
5,071
163,589
Less: accumulated depletion and depreciation
(74,775)
(9,392)
(3,885)
(88,052)
Net capitalized costs
$
74,012
$
339
$
1,186
$
75,537
2023
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Proved properties
$
132,858 $
8,606 $
4,409 $
145,873
Unproved properties
2,108
—
100
2,208
134,966
8,606
4,509
148,081
Less: accumulated depletion and depreciation
(69,945)
(8,382)
(3,358)
(81,685)
Net capitalized costs
$
65,021 $
224 $
1,151 $
66,396
2022
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Proved properties
$
128,807 $
8,258 $
4,332 $
141,397
Unproved properties
2,128
—
98
2,226
130,935
8,258
4,430
143,623
Less: accumulated depletion and depreciation
(65,547)
(8,106)
(3,277)
(76,930)
Net capitalized costs
$
65,388 $
152 $
1,153 $
66,693
Canadian Natural 2024 Annual Report
102
Costs Incurred in Crude Oil and Natural Gas Activities
2024
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Property acquisitions
Proved
$
8,901
$
—
$
—
$
8,901
Unproved
320
—
—
320
Exploration
102
—
(56)
46
Development
5,543
352
205
6,100
Costs incurred
$
14,866
$
352
$
149
$
15,367
2023
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Property acquisitions
Proved
$
— $
— $
— $
—
Unproved
—
—
—
—
Exploration
43
—
3
46
Development
5,039
558
187
5,784
Costs incurred
$
5,082 $
558 $
190 $
5,830
2022
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Property acquisitions
Proved
$
524 $
— $
— $
524
Unproved
—
—
—
—
Exploration
40
—
5
45
Development
4,387
304
75
4,766
Costs incurred
$
4,951 $
304 $
80 $
5,335
103
Canadian Natural 2024 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,
2024, 2023, and 2022 are summarized in the following tables:
2024
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
$
26,501
$
478
$
458
$
27,437
Production
(7,170)
(440)
(109)
(7,719)
Transportation
(2,038)
(10)
(1)
(2,049)
Depletion, depreciation and amortization
(6,089)
(279)
(297)
(6,665)
Asset retirement obligation accretion
(315)
(65)
(9)
(389)
Petroleum revenue tax recovery
—
232
—
232
Income tax
(2,526)
34
(12)
(2,504)
Results of operations
$
8,363
$
(50) $
30
$
8,343
2023
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
$
26,773 $
442 $
581 $
27,796
Production
(7,606)
(342)
(141)
(8,089)
Transportation
(1,550)
(7)
(1)
(1,558)
Depletion, depreciation and amortization
(5,690)
(494)
(213)
(6,397)
Asset retirement obligation accretion
(312)
(46)
(8)
(366)
Petroleum revenue tax recovery
—
273
—
273
Income tax
(2,700)
70
(54)
(2,684)
Results of operations
$
8,915 $
(104) $
164 $
8,975
2022
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Crude oil and natural gas revenue, net of royalties,
blending and feedstock costs
$
31,698 $
635 $
687 $
33,020
Production
(7,830)
(437)
(114)
(8,381)
Transportation
(1,424)
(6)
(1)
(1,431)
Depletion, depreciation and amortization
(5,417)
(1,747)
(173)
(7,337)
Asset retirement obligation accretion
(241)
(33)
(7)
(281)
Petroleum revenue tax recovery
—
483
—
483
Income tax
(3,896)
442
(98)
(3,552)
Results of operations
$
12,890 $
(663) $
294 $
12,521
Canadian Natural 2024 Annual Report
104
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":
2024
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Future cash inflows
$
876,917
$
722
$
5,329
$
882,968
Future production costs
(286,440)
(414)
(1,661)
(288,515)
Future development costs and asset retirement obligations
(92,455)
(1,970)
(1,804)
(96,229)
Future income taxes
(111,073)
1,144
(413)
(110,342)
Future net cash flows
386,949
(518)
1,451
387,882
10% annual discount for timing of future cash flows
(275,139)
136
(721)
(275,724)
Standardized measure of future net cash flows (1)
$
111,810
$
(382) $
730
$
112,158
(1) Includes abandonment cost estimates for the Ninian field.
2023
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Future cash inflows
$
863,544 $
1,067 $
6,144 $
870,755
Future production costs
(276,498)
(636)
(1,880)
(279,014)
Future development costs and asset retirement obligations
(86,615)
(1,873)
(1,927)
(90,415)
Future income taxes
(113,516)
967
(508)
(113,057)
Future net cash flows
386,915
(475)
1,829
388,269
10% annual discount for timing of future cash flows
(278,814)
168
(887)
(279,533)
Standardized measure of future net cash flows (1)
$
108,101 $
(307) $
942 $
108,736
(1) Includes abandonment cost estimates for the Ninian field.
105
Canadian Natural 2024 Annual Report
2022
(millions of Canadian dollars)
North
America
North
Sea
Offshore
Africa
Total
Future cash inflows
$
986,672 $
1,506 $
7,304 $
995,482
Future production costs
(303,270)
(691)
(1,998)
(305,959)
Future development costs and asset retirement obligations
(83,803)
(1,416)
(1,439)
(86,658)
Future income taxes
(136,905)
517
(900)
(137,288)
Future net cash flows
462,694
(84)
2,967
465,577
10% annual discount for timing of future cash flows
(327,333)
84
(1,330)
(328,579)
Standardized measure of future net cash flows (1)
$
135,361 $
— $
1,637 $
136,998
(1) Includes abandonment cost estimates for the Ninian field.
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)
2024
2023
2022
Sales of crude oil and natural gas produced, net of production costs
$
(17,672) $
(18,174) $
(23,242)
Net changes in sales prices and production costs
(11,189)
(47,145)
79,291
Extensions, discoveries and improved recovery
2,576
8,196
6,198
Changes in estimated future development costs
(2,101)
(1,511)
(3,640)
Purchases of proved reserves in place
15,463
—
5,745
Sales of proved reserves in place
(63)
(47)
—
Revisions of previous reserve estimates
(485)
6,647
(9,956)
Accretion of discount
14,059
17,769
10,712
Changes in production timing and other
2,507
(2,831)
5,463
Net change in income taxes
327
8,834
(16,357)
Net change
3,422
(28,262)
54,214
Balance - beginning of year
108,736
136,998
82,784
Balance - end of year
$
112,158
$
108,736 $
136,998
Canadian Natural 2024 Annual Report
106
Ten Year Review
Years ended December 31
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
FINANCIAL INFORMATION (C$ millions, except per share amounts)
Net earnings (loss)
6,106
8,233
10,937
7,664
(435)
5,416
2,591
2,397
(204)
(637)
Per share – basic ($/share) (1)
2.87
3.77
4.82
3.24
(0.18)
2.27
1.06
1.02
(0.09)
(0.29)
Per share – diluted ($/share) (1)
2.85
3.74
4.76
3.23
(0.18)
2.27
1.06
1.01
(0.09)
(0.29)
Cash flows from operating activities
13,386
12,353
19,391
14,478
4,714
8,829
10,121
7,262
3,452
5,632
Adjusted funds flow (2)
14,859
15,274
19,791
13,733
5,200
10,267
9,088
7,347
4,293
5,785
Per share – basic ($/share) (1)(6)
6.99
7.00
8.72
5.81
2.20
4.31
3.73
3.13
1.95
2.64
Per share – diluted ($/share) (1)(6)
6.94
6.93
8.61
5.79
2.20
4.30
3.71
3.11
1.94
2.64
Cash flows used in investing activities
14,095
4,858
4,987
3,703
2,819
7,255
4,814
13,102
3,811
5,465
Net capital expenditures (2)
14,431
4,909
5,136
4,676
2,957
6,825
4,441
16,855
3,527
3,483
Abandonment expenditures, net (2)
646
509
335
232
249
296
290
274
267
370
Balance sheet information (C$ millions)
Adjusted working capital (3)
174
712
(1,190)
(480)
626
241
(601)
513
1,056
1,193
Exploration and evaluation assets
2,526
2,208
2,226
2,250
2,436
2,579
2,637
2,632
2,382
2,586
Property, plant and equipment, net
73,414
64,581
64,859
66,400
65,752
68,043
64,559
65,170
50,910
51,475
Total assets
85,359
75,955
76,142
76,665
75,276
78,121
71,559
73,867
58,648
59,275
Long-term debt, net (5)
18,688
9,922
10,525
13,950
21,269
20,843
20,522
22,321
16,788
16,725
Shareholders' equity
39,468
39,832
38,175
36,945
32,380
34,991
31,974
31,653
26,267
27,381
SHARE INFORMATION (1)
Common shares outstanding (thousands)
2,102,996 2,144,815 2,205,272 2,336,738 2,367,733 2,373,714 2,403,771 2,445,538 2,221,905 2,189,336
Weighted average shares outstanding
– basic (thousands)
2,125,804 2,182,623 2,269,919 2,362,500 2,363,536 2,381,954 2,437,597 2,350,188 2,200,943 2,187,725
Weighted average shares outstanding
– diluted (thousands)
2,140,429 2,204,248 2,298,363 2,373,114 2,363,536 2,386,211 2,447,517 2,365,645 2,200,943 2,187,725
Dividends declared ($/share) (4)
2.14
1.85
2.30
1.00
0.85
0.75
0.67
0.55
0.47
0.46
Trading statistics (1)
TSX – C$
Trading volume (thousands)
3,025,819 3,394,111 3,067,445 3,137,743 3,732,827 1,808,025 1,612,508 1,176,845 1,307,454 1,456,066
Share Price (C$/share)
High
56.50
46.72
44.09
27.80
21.29
21.28
24.54
23.50
23.37
21.23
Low
40.02
33.57
27.10
14.34
4.90
15.01
15.06
17.95
10.64
12.51
Close
44.38
43.41
37.60
26.73
15.30
21.00
16.47
22.46
21.40
15.11
NYSE – US$
Trading volume (thousands)
1,310,294 1,205,733 1,511,444 1,591,210 2,116,244 1,359,393 1,593,943 1,216,016 1,784,439 1,902,622
Share Price (US$/share)
High
41.29
34.37
35.30
22.17
16.40
16.28
19.10
18.39
17.64
17.23
Low
29.23
24.41
21.16
11.20
3.36
11.29
10.93
13.77
7.30
9.47
Close
30.87
32.76
27.77
21.13
12.03
16.18
12.07
17.86
15.94
10.92
RATIOS
Debt to book capitalization (5)
32 %
20 %
22 %
27 %
40 %
37 %
39 %
41 %
39 %
38 %
After-tax return on average capital
employed (6)
13 %
17 %
22 %
16 %
— %
11 %
6 %
6 %
— %
(1) %
Daily production before royalties per ten
thousand common shares (BOE/d)
6.5
6.2
5.8
5.3
4.9
4.6
4.5
3.9
3.6
3.9
Total proved plus probable reserves per
common share (BOE) (7)
9.6
8.6
8.2
7.3
6.7
6.0
5.6
4.9
4.2
4.1
Net asset value ($/share) (1)(9)
94.53
87.40
82.28
59.68
35.81
48.55
50.95
40.70
37.38
36.70
(1)
Updated to reflect the two for one common share split in June 2024.
(2)
Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
(3)
Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
(4)
On March 5, 2025, the Board of Directors approved a quarterly dividend of $0.5875 per common share, an increase from the previous quarterly dividend of $0.5625 per common share.
The dividend is payable on April 4, 2025. In 2022, the Company paid a special dividend of $0.75 per common share.
(5)
Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
(6)
Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A.
(7)
Based upon company gross reserves (forecast price and costs, before royalties), using year end common shares outstanding.
107
Canadian Natural 2024 Annual Report
Years ended December 31
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
COMPANY NET RESERVES (8)(10)
Crude oil and NGLs (MMbbl)
Company net proved reserves (after royalties)
North America
9,665
8,977
8,940
8,740
8,980
8,129
7,163
6,423
3,909
3,645
North Sea
6
8
11
79
96
109
119
120
134
158
Offshore Africa
48
53
59
64
70
70
72
70
74
74
9,720
9,038
9,010
8,883
9,147
8,307
7,354
6,613
4,117
3,877
Company net proved plus probable reserves (after royalties)
North America
11,990
11,240
11,181
10,883
11,151
10,231
9,456
8,353
6,015
5,806
North Sea
7
12
15
117
160
175
186
180
252
284
Offshore Africa
61
69
77
85
94
93
98
102
108
113
12,058
11,322
11,273
11,085
11,405
10,499
9,740
8,635
6,375
6,203
Natural gas (Bcf)
Company net proved reserves (after royalties)
North America
14,849
12,952
11,614
11,076
8,373
5,795
6,005
6,032
5,845
5,383
North Sea
3
3
4
8
12
16
27
21
41
39
Offshore Africa
18
22
27
25
32
37
21
15
23
21
14,871
12,977
11,645
11,109
8,417
5,849
6,053
6,068
5,909
5,443
Company net proved plus probable reserves (after royalties)
North America
23,475
20,596
18,617
18,315
13,884
8,556
8,681
8,454
7,888
7,361
North Sea
5
5
7
11
17
21
38
32
85
96
Offshore Africa
30
36
40
39
48
52
44
47
55
50
23,510
20,637
18,664
18,364
13,949
8,630
8,763
8,533
8,028
7,507
Total company net proved
reserves (after royalties) (MMBOE)
12,198
11,201
10,951
10,734
10,549
9,282
8,363
7,625
5,102
4,784
Total company net proved plus probable
reserves (after royalties) (MMBOE)
15,976
14,761
14,384
14,146
13,730
11,938
11,202
10,057
7,713
7,454
OPERATING INFORMATION
Daily production (before royalties) (10)
Crude oil and NGLs (Mbbl/d)
North America
Exploration and Production
509
496
480
473
460
406
351
359
351
400
North America
Oil Sands Mining and Upgrading
472
451
426
448
417
395
426
282
123
123
North Sea
12
13
13
18
23
28
24
23
24
22
Offshore Africa
13
13
14
14
17
21
20
20
26
19
1,006
974
933
952
918
850
821
685
524
564
Natural gas (MMcf/d)
North America
2,136
2,139
2,075
1,680
1,450
1,443
1,490
1,601
1,622
1,663
North Sea
2
2
2
3
12
24
32
39
38
36
Offshore Africa
9
10
13
12
15
24
26
22
31
27
2,147
2,151
2,090
1,695
1,477
1,491
1,548
1,662
1,691
1,726
Total production (before royalties) (MBOE/d)
1,363
1,332
1,281
1,235
1,164
1,099
1,079
962
806
852
PRODUCT PRICING (11)
Average crude oil & NGLs price ($/bbl) (6)(12)
77.76
72.36
90.64
63.71
31.90
55.08
46.92
48.57
36.93
41.13
Average natural gas price ($/Mcf)
1.86
3.10
6.55
4.07
2.40
2.34
2.61
2.76
2.32
3.16
Average SCO price ($/bbl) (6)(13)
98.03
100.06
117.69
77.95
43.98
70.18
68.61
63.98
58.59
61.39
(8)
Company net reserves are company gross reserves after royalties in accordance with NI 51-101. Reserves data may not add and BOE values may not calculate exactly due to rounding.
(9)
Net present value, discounted at 10%, of the future net revenue (before income tax and excluding the ARO for existing development as at December 31, 2024) 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 for 2024 to 2022 ($285/acre from 2021 to 2015), less debt divided by common shares outstanding. Debt for the purpose of this calculation is defined as long-term debt plus/minus the
working capital deficit/surplus. Future development costs and abandonment and reclamation costs attributable to future development activity have been applied against the future net revenue.
(10) Numbers may not add due to rounding.
(11) Product prices reflect realized product prices before blending costs, transportation costs and exclude risk management activities.
(12) Average crude oil and NGLs pricing excludes SCO.
(13) For years 2017 to 2024, average SCO product price includes AOSP realized product prices net of blending and feedstock costs.
Canadian Natural 2024 Annual Report
108
Corporate Information
Board of Directors
*Catherine M. Best, FCA, ICD.D (1)(2)
Corporate Director
Calgary, Alberta
*M. Elizabeth Cannon, Ph.D, O.C. (3)(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)(6)
Partner and Global Vice Chair, emeritus, Dentons US LLP
Sarasota, Florida
*Wilfred A. Gobert (1)(2)(4)
Corporate Director
Calgary, Alberta
*Christine M. Healy (1)(4)
President and CEO of Northland Power Inc.
Toronto, Ontario
*Steve W. Laut (3)(5)
Corporate Director
Calgary, Alberta
*Honourable Frank J. McKenna, P.C., O.C., O.N.B., K.C.(2)(4)
Deputy Chair, TD Bank Group
Cap Pelé, New Brunswick
Scott G. Stauth (3)(7)
President, Canadian Natural Resources Limited
Calgary, Alberta
*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
(6)
Lead Independent Director
(7)
Mr. Scott G. Stauth was appointed President of the Company effective
February 28, 2024.
(8)
Mr. Stainthorpe is stepping down as Chief Financial Officer effective
April 30, 2025. Mr. Darel has been appointed Chief Financial Officer
effective April 30, 2025.
*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
Scott G. Stauth
President
Mark A. Stainthorpe (8)
Chief Financial Officer
Jay E. Froc
Chief Operating Officer, Oil Sands
Robin S. Zabek
Chief Operating Officer, Exploration and Production
Ron K. Laing
Chief Commercial and Corporate Development Officer
Troy J.P. Andersen
Senior Vice-President, Canadian Conventional
Field Operations
Calvin J. Bast
Senior Vice-President, Production
Victor C. Darel (8)
Senior Vice-President, Finance and
Principal Accounting Officer
Dwayne F. Giggs
Senior Vice-President, Exploration
Dean W. Halewich
Senior Vice-President, Safety, Risk Management
and Innovation
Devin C. Lowe
Senior Vice-President, Exploitation
Warren P. Raczynski
Senior Vice-President, Thermal
Kara L. Slemko
Senior Vice-President, Commercial Operations and
Corporate Development
Trevor T. Wagil
Senior Vice-President, Oil Sands Mining and Upgrading
Brenda G. Balog
Vice-President, Legal and General Counsel
Erin L. Lunn
Vice-President, Land
Mark A. Overwater
Vice-President, Marketing
Kyle G. Pisio
Vice-President, Drilling, Completions and
Asset Retirement
Stephanie A. Graham
Corporate Secretary and Associate General Counsel,
Canada
109
Canadian Natural 2024 Annual Report
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 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
To
Multiply by
barrels
cubic metres
0.159
thousand cubic feet
cubic metres
28.174
feet
metres
0.305
miles
kilometres
1.609
acres
hectares
0.405
tonnes
tons
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,
2024 and is restated for the two for one subdivision of the
common shares which occurred in June 2024.
2024
2023
2022
Cash dividends declared
per common share
$2.14
$1.85
$2.30(1)
(1)
2022 includes a special dividend of $0.75 per common share.
NOTICE OF ANNUAL MEETING
Canadian Natural’s 2025 Annual and Special Meeting of the
Shareholders will be held on Thursday, May 8, 2025 at
11:00 a.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 2024 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 2024 Annual Report
110
T (403) 517-6700 F (403) 517-7350 E ir@cnrl.com
2100, 855 – 2 Street S.W. Calgary, AB T2P 4J8
www.cnrl.com