2025 ANNUAL REPORT
2025 Performance Highlights
The Company continues to maximize value for shareholders, with another successful year in 2025. We set several new production records, lowered operating costs and capital expenditures came in under our forecast. We grew organically and completed several accretive acquisitions, including the Palliser Block assets in southern Alberta and liquids-rich Montney assets in the Grande Prairie area, along with increasing our ownership in the Albian mines to 100% through an asset swap. We strengthened our financial position in 2025 by reducing net debt and ended the year with strong financial metrics.
2025 | 2024 | 2023 | |
FINANCIAL ($ millions, except per common share amounts) | |||
Product sales (1) | $ 44,167 | $ 41,509 | $ 40,835 |
Net earnings | $ 10,820 | $ 6,106 | $ 8,233 |
Per common share (2) - basic | $ 5.17 | $ 2.87 | $ 3.77 |
- diluted | $ 5.16 | $ 2.85 | $ 3.74 |
Adjusted net earnings from operations (3) | $ 7,444 | $ 7,414 | $ 8,533 |
Per common share (2) - basic (4) | $ 3.56 | $ 3.49 | $ 3.91 |
- diluted (4) | $ 3.55 | $ 3.46 | $ 3.87 |
Cash flows from operating activities | $ 15,106 | $ 13,386 | $ 12,353 |
Adjusted funds flow (3) | $ 15,460 | $ 14,859 | $ 15,274 |
Per common share (2) - basic (4) | $ 7.39 | $ 6.99 | $ 7.00 |
- diluted (4) | $ 7.37 | $ 6.94 | $ 6.93 |
Cash flows used in investing activities | $ 6,687 | $ 14,095 | $ 4,858 |
Net capital expenditures (3) | $ 6,579 | $ 14,431 | $ 4,909 |
Abandonment expenditures | $ 771 | $ 646 | $ 509 |
Long-term debt, net (5) | $ 15,944 | $ 18,688 | $ 9,922 |
Shareholders' equity | $ 44,366 | $ 39,468 | $ 39,832 |
Debt to book capitalization (5) | 26% | 32% | 20% |
Further details related to product sales are disclosed in note 21 to the Company's audited consolidated financial statements.
Per common share amounts have been updated to reflect the two for one common share split in June 2024. Further details are disclosed in the 'Advisory' section of the Company's Management's Discussion and Analysis ("MD&A") and in note 1 to the Company's audited consolidated financial statements.
Non-GAAP Financial Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's annual MD&A included in this annual report.
Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A.
Capital Management Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's MD&A and note 15 to the Company's audited consolidated financial statements.
Cover: Jackpine Mine Extraction building.
TABLE OF CONTENTS
1 2025 Performance Highlights
3 Letter to Shareholders
7 2025 Year End Reserves
10 Management's Discussion and Analysis
Consolidated Financial Statements
Management's Report
59 Management's Assessment of Internal Control over Financial Reporting
60 Report of Independent Registered Public Accounting Firm
67 Notes to the Consolidated Financial Statements
103 Supplementary Oil and Gas Information
113 Ten Year Review
115 Corporate Information
2025
2024
2023
OPERATING
Daily production, before royalties (1)
Crude oil and NGLs (Mbbl/d)
North America - Exploration and Production
569
509
496
North America - Oil Sands Mining and Upgrading
565
472
451
North Sea
8
12
13
Offshore Africa
3
13
13
1,146
1,006
974
Natural gas (MMcf/d)
North America
2,538
2,136
2,139
North Sea
3
2
2
Offshore Africa
6
9
10
2,547
2,147
2,151
Barrels of oil equivalent (MBOE/d) (2)
1,571
1,363
1,332
Drilling activity (3)
North America
438
387
284
North Sea
-
-
-
Offshore Africa
-
-
-
438
387
284
Numbers may not add due to rounding.
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.
Net wells. Excludes net stratigraphic test and service wells.
Canadian Natural holds one of the largest, most diversified and highest-quality portfolios in the oil and natural gas industry. Our long life low decline production base provides reliable, sustainable output, while our extensive infrastructure ownership in core areas gives us strong control over operations, costs, and market access. 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. Our operational excellence delivers industry-leading performance through safety, reliability and cost efficiency and our low maintenance capital and low break-even costs support sustainable free cash flow generation. This, combined with our strong balance sheet and financial strength, drive strong and sustainable returns to shareholders.
2025 was the best operational year in the Company's long history of maximizing value for our shareholders. We set several production records, lowered our operating costs and capital expenditures came in under our forecast. We grew organically and completed several accretive acquisitions, and as a result, we achieved record annual production of 1,571 MBOE/d in 2025, resulting in year-over-year production growth of 15% or approximately 207 MBOE/d from 2024 levels. We also achieved record annual liquids production of 1,146 Mbbl/d, of which 65% was comprised of Synthetic Crude Oil ("SCO"), light crude oil and NGLs.
Strong execution across our large, diverse asset base continues to provide significant opportunities to create shareholder value in 2026 and beyond. This is evidenced by our increased production, strong free cash flow and growth in reserves achieved in 2025, through both organic growth and accretive acquisitions. These successes provided the Board of Directors with the confidence to approve a dividend increase and an enhancement to our direct shareholder returns, by adjusting our net debt targets as a part of our free cash flow allocation policy. Additionally, as of March 5, 2026, we decreased our 2026 operating capital forecast by approximately $310 million, following the completion of a strategic acquisition early in 2026, and increased our 2026 production guidance range to 1,615 MBOE/d and 1,665 MBOE/d from the previous guidance range of 1,590 MBOE/d and 1,650 MBOE/d.
In 2025, we generated adjusted net earnings from operations of $7.4 billion or $3.56 per share, and adjusted funds flow of
$15.5 billion or $7.39 per share. Throughout the year, we completed several accretive acquisitions, increasing production and cash flow, while reducing net debt by approximately $2.7 billion to just under $16 billion at year end 2025. In total we returned approximately $9.0 billion to our shareholders in 2025, including $4.9 billion in dividends, $1.4 billion in share repurchases and
$2.7 billion in net debt reduction.
Subsequent to year end, the Board of Directors approved a 6.4% increase to our quarterly dividend, bringing the annualized dividend up to $2.50 per common share. This marks 2026 as the 26th consecutive year of dividend increases by Canadian Natural, with a compound annual growth rate ("CAGR") of 20% over that time, demonstrating the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base.
Additionally, the Board of Directors have, effective January 1, 2026, adjusted the net debt target levels in our free cash flow allocation policy which results in an acceleration of the next increase to direct shareholder returns. Now, when net debt falls below $16 billion, compared to our previous target of $15 billion, we will increase direct shareholder returns in the form of share repurchases to 75% of free cash flow generated, managed on a forward-looking basis.
Our financial flexibility and long life low decline asset base provide a strong foundation and a competitive advantage with low maintenance capital requirements. Our US$ WTI breakeven remains top tier in the low to mid-$40 per barrel range. Our balance sheet is strong with significant liquidity of approximately $6.3 billion at year end 2025. Our excellent results highlight the cash flow generating capability of our top tier asset base with strong year end metrics, including Debt to Book Capitalization at 26%.
~$9.0 BILLION RETURNED TO SHAREHOLDERS IN 2025 ~1,571,000 BOE/D RECORD TOTAL PRODUCTIONCanadian Natural's reserves are significant when compared to other major oil companies, which support long-term organic growth opportunities. Year end 2025 total proved reserves of 15.91 billion BOE and total proved plus probable reserves of
20.75 billion BOE represent increases of approximately 4% and 3%, respectively, from year end 2024 levels. With approximately 73% of the Company's total proved reserves being long life low decline, the strength and depth of our assets is evident and provide us with a total proved reserves life index ("RLI") of 31 years and a total proved plus probable RLI of 40 years. We continue to deliver strong total proved Finding, Development and Acquisition ("FD&A") costs, including changes in Future Development Cost ("FDC"), achieving an industry leading FD&A in 2025 of $3.64/BOE for total proved reserves and $2.42/BOE for total proved plus probable reserves.
Canada's energy sector plays 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.
Canadian Natural remains focused on supporting Canada in supplying safe, reliable and responsibly produced energy. We continue to incorporate environmental, social and governance practices that enhance our long-term sustainability across all aspects of our business. Our diverse, long life low decline assets are ideal for continued review and evaluation of new technologies designed to improve productivity and reduce environmental impacts.
We continue to create shared value in the communities where we operate in Canada, the United Kingdom and Africa. This 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 is committed to working together with these diverse communities to identify opportunities for education and training, employment, business development, and community investment. At the end of 2025, our work with Indigenous businesses led to approximately
$1.1 billion in contracts being awarded during the year, a 33% increase from 2024 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.
In 2026, we look to continue to deliver on our four pillars of capital allocation through our updated 2026 forecasted operating capital expenditures of approximately $6.0 billion, along with $993 million of abandonment expenditures and $125 million of carbon capture expenditures. We have capital flexibility 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.
Our team is world class and we would like to thank our employees and contractors for their hard work and focus on delivering 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 our ongoing success and positions Canadian Natural very well to drive long-term shareholder value into the future.
N. MURRAY EDWARDS | SCOTT G. STAUTH | VICTOR C. DAREL |
Executive Chairman | President | Chief Financial Officer |
Advisory
SPECIAL NOTE REGARDING NON-GAAP AND OTHER FINANCIAL MEASURES
This document includes references to Non-GAAP and Other Financial Measures as defined in National Instrument 52-112 -Non-GAAP and Other Financial Measures Disclosure ("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 Accounting Standards 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 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 the Company's MD&A 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 requirements as needed.
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 $12 billion, free cash flow allocation will be 100% to shareholder returns.
The Company's free cash flow for the year ended December 31, 2025 and comparable period is shown below:
Year Ended
($ millions) | Dec 31 2025 | Dec 31 2024 |
Adjusted funds flow (1) | $ 15,460 | $ 14,859 |
Less: Dividends on common shares | 4,871 | 4,429 |
Net capital expenditures (2) | 6,579 | 5,286 |
Abandonment expenditures | 771 | 646 |
Free cash flow | $ 3,239 | $ 4,498 |
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 annual MD&A.
Non-GAAP Financial Measure. In 2024, for the purpose of the free cash flow calculated above, net capital expenditures of $5,286 million excludes net acquisitions of $9,145 million. Refer to the 'Non-GAAP and Other Financial Measures' section of the Company's annual MD&A.
In March 2026, the Board of Directors adjusted the allocation of free cash flow, effective January 1, 2026, as follows:
When net debt is at or above $16 billion, 60% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases and 40% to the balance sheet.
When net debt is between $13 billion and $16 billion, 75% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases and 25% to the balance sheet.
When net debt is at or below $13 billion, 100% of free cash flow will be allocated to direct shareholder returns in the form of share repurchases.
CAPITAL BUDGET
Capital budget (or capital forecast) is a forward-looking non-GAAP financial measure. 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 capital budget (or capital forecast) excludes 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 forecasted future expenditures. Abandonment expenditures are reported before the impact of current income tax recoveries in Canada and the UK portion of the North Sea. The Company is eligible to recover interest related to tax recoveries in the North Sea.
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 15 to the Company's 2025 audited consolidated financial statements.
2025 Year End ReservesDETERMINATION OF RESERVES
For the year ended December 31, 2025, 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, Thermal and International 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 IQREs as to the Company's reserves.
Additional reserves information is disclosed in the Company's Annual Information Form.
RESERVES INFORMATION HIGHLIGHTS
A key differentiator for Canadian Natural is the strength, diversity and balance of its world class, top tier assets. The Company's total proved RLI(1) of 31 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, 2025 (all reserves values are Company Gross unless stated otherwise).
Total proved reserves increased 4% to 15.910 billion BOE, with reserves additions and revisions of 1.253 billion BOE. Total proved plus probable reserves increased 3% to 20.750 billion BOE, with reserves additions and revisions of
1.213 billion BOE.
The strength and depth of the Company's assets are evident as approximately 73% of total proved reserves are long life low decline reserves. This results in a total proved BOE RLI of 31 years and a total proved plus probable BOE RLI of 40 years.
- Additionally, high value, zero decline SCO and bitumen from the Horizon and Albian mines represent approximately 50% of total proved reserves with a RLI of 39 years.
Proved developed producing reserves additions and revisions for 2025 were 1.129 billion BOE, replacing 2025 production by 197%. The proved developed producing BOE RLI is 20 years.
Total proved reserves additions and revisions for 2025 replaced 2025 production by 218%. Total proved plus probable reserves additions and revisions for 2025 replaced 2025 production by 212%.
In 2025, Canadian Natural continued to achieve strong FD&A costs:
FD&A costs, including changes in FDC, are $3.64/BOE for total proved reserves and $2.42/BOE for total proved plus probable reserves.
At December 31, 2025, the net present value of Future Net Revenues ("FNR"), before income tax, discounted at 10%, was
$110.1 billion for proved developed producing reserves, $157.8 billion for total proved reserves, and $191.0 billion for total proved plus probable reserves.
(1) Supplementary financial measure. Refer to the notes to the '2025 Year End Reserves' on page 9.
Summary of Company Gross Reserves
as of December 31, 2025 Forecast Prices and Costs
Light and Medium Crude Oil | Primary Heavy Crude Oil | Pelican Lake Heavy Crude Oil | Thermal Bitumen | Mining Bitumen | Synthetic Crude Oil | Natural Gas | Natural Gas Liquids | Barrels of Oil Equivalent | |
Total Company | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (Bcf) | (MMbbl) | (MMBOE) |
Proved Developed Producing | 121 | 130 | 188 | 684 | 835 | 7,043 | 5,861 | 229 | 10,207 |
Developed Non-Producing | 28 | 6 | - | 42 | - | - | 272 | 13 | 135 |
Undeveloped | 160 | 92 | 55 | 2,603 | 14 | 91 | 11,873 | 575 | 5,568 |
Total Proved | 309 | 228 | 243 | 3,330 | 849 | 7,134 | 18,006 | 817 | 15,910 |
Probable | 118 | 105 | 107 | 1,845 | 46 | 554 | 9,969 | 404 | 4,840 |
Total Proved plus Probable | 427 | 333 | 349 | 5,175 | 895 | 7,688 | 27,974 | 1,221 | 20,750 |
Reconciliation of Company Gross Reserves
as of December 31, 2025 Forecast Prices and Costs
TOTAL PROVED | Light and Medium Crude Oil | Primary Heavy Crude Oil | Pelican Lake Heavy Crude Oil | Thermal Bitumen | Mining Bitumen | Synthetic Crude Oil | Natural Gas | Natural Gas Liquids | Barrels of Oil Equivalent |
Total Company | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (Bcf) | (MMbbl) | (MMBOE) |
December 31, 2024 | 252 | 219 | 255 | 3,312 | - | 7,663 | 16,904 | 713 | 15,231 |
Discoveries | - | - | - | - | - | - | - | - | - |
Extensions | 16 | 12 | - | 66 | - | - | 113 | 8 | 121 |
Infill Drilling | 2 | 17 | 1 | 9 | - | - | 191 | 36 | 97 |
Improved Recovery | - | 1 | 3 | - | - | 2 | - | - | 6 |
Acquisitions | 68 | - | - | - | 427 | - | 1,153 | 74 | 760 |
Dispositions | - | - | - | - | - | - | - | - | - |
Economic Factors | (4) | (4) | (3) | - | - | - | (99) | (4) | (32) |
Technical Revisions | 1 | 15 | 2 | 43 | 426 | (328) | 674 | 28 | 300 |
Production | (26) | (32) | (16) | (100) | (4) | (202) | (930) | (38) | (573) |
December 31, 2025 | 309 | 228 | 243 | 3,330 | 849 | 7,134 | 18,006 | 817 | 15,910 |
TOTAL PROVED PLUS | Light and | Primary | Pelican Lake | Natural | Barrels | ||||
PROBABLE | Medium | Heavy | Heavy | Thermal | Mining | Synthetic | Natural | Gas | of Oil |
Crude Oil | Crude Oil | Crude Oil | Bitumen | Bitumen | Crude Oil | Gas | Liquids | Equivalent | |
Total Company | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (Bcf) | (MMbbl) | (MMBOE) |
December 31, 2024 | 346 | 318 | 360 | 5,190 | - | 8,255 | 27,156 | 1,116 | 20,110 |
Discoveries | - | - | - | - | - | - | - | - | - |
Extensions | 22 | 20 | - | 89 | - | - | 167 | 12 | 171 |
Infill Drilling | 2 | 26 | 3 | 11 | - | - | 325 | 54 | 149 |
Improved Recovery | - | 1 | 4 | - | - | 2 | - | - | 7 |
Acquisitions | 99 | - | - | - | 450 | - | 1,469 | 95 | 888 |
Dispositions | - | - | - | - | - | - | - | - | - |
Economic Factors | (5) | (5) | (2) | - | - | - | (99) | (4) | (32) |
Technical Revisions | (11) | 5 | - | (15) | 449 | (367) | (114) | (14) | 29 |
Production | (26) | (32) | (16) | (100) | (4) | (202) | (930) | (38) | (573) |
December 31, 2025 | 427 | 333 | 349 | 5,175 | 895 | 7,688 | 27,974 | 1,221 | 20,750 |
NOTES TO RESERVES:
Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.
Information in the reserves data tables may not add due to rounding. BOE values and oil and natural gas metrics may not calculate exactly due to rounding.
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, 2025:
2026
2027
2028
2029
2030
Crude Oil and NGLs
WTI
US$/bbl
59.92
65.10
70.28
71.93
73.37
WCS
C$/bbl
65.13
70.43
76.90
78.71
80.29
Canadian Light Sweet
C$/bbl
77.54
83.60
90.17
92.32
94.17
Cromer LSB
C$/bbl
75.09
81.56
86.95
89.19
90.98
Edmonton C5+
C$/bbl
80.01
86.19
92.83
95.04
96.94
Brent
US$/bbl
63.92
69.13
74.36
76.10
77.62
Natural Gas
AECO
C$/MMBtu
3.00
3.30
3.49
3.58
3.65
BC Westcoast Station 2
C$/MMBtu
2.66
3.07
3.25
3.34
3.41
Henry Hub
US$/MMBtu
3.74
3.78
3.85
3.93
4.01
All prices increase at a rate of 2% per year after 2030.
A US$/C$ foreign exchange rate of 0.7277 was used for 2026, 0.7367 for 2027, and 0.7400 for 2028 and thereafter in the year end 2025 evaluation.
A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
Oil and 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.
Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production.
Reserves replacement or Production replacement ratio is the Company Gross reserves additions and revisions, for the relevant reserves category, divided by the Company Gross production in the same period.
Reserves Life Index ("RLI") is based on the amount for the relevant reserves category divided by the 2026 proved developed producing production forecast prepared by the IQREs.
Finding, Development and Acquisition ("FD&A") costs including changes in Future Development Costs ("FDC") are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2025 and net changes in FDC from December 31, 2024 to December 31, 2025 by the sum of total additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and reclamation ("ADR") costs.
ADR costs included in the calculation of the Future Net Revenue ("FNR") consist of both the Company's Asset Retirement Obligation ("ARO") for North America and Offshore Africa, before inflation and discounting, for development existing as at December 31, 2025 and forecast estimates of ADR costs attributable to future development activity.
Table of Contents
Definitions and Abbreviations 11
Advisory 12
Objectives and Strategy 15
Financial and Operational Highlights 16
Business Environment and Outlook 19
Analysis of Changes in Product Sales 21
Daily Production 22
Exploration and Production 24
Oil Sands Mining and Upgrading 28
Midstream and Refining 30
Corporate and Other 31
Net Capital Expenditures 34
Liquidity and Capital Resources 35
Commitments and Contingencies 38
Reserves 39
Risks and Uncertainties 40
Environment 41
Accounting Policies and Standards 45
Control Environment 47
Non-GAAP and Other Financial Measures 48
Other 53
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, thermal bitumen, 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
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
MOU Memorandum of Understanding between the Government of Canada and the Government of Alberta.
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. Includes all crude oil blends (including mining bitumen) produced from Horizon, AOSP mines and Scotford Upgrader.
SEC United States Securities and Exchange Commission
SOFR Secured Overnight Financing Rate
TSX Toronto Stock Exchange
UK United Kingdom
US United States
US$ United States dollars
WCS Western Canadian Select
IFRS
Accounting Standards
International Financial Reporting Standards as issued by the International Accounting Standards Board
WCS Heavy Differential
WCS Heavy Differential from WTI
Mbbl thousand barrels
WCSB Western Canadian Sedimentary Basin
WTI West Texas Intermediate reference location at Cushing, Oklahoma
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, forecast and anticipated 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 maintenance of the Company's facilities and any expected return to service dates; the construction, expansion, or maintenance of third-party facilities that process the Company's products; 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 tax interpretations and litigation 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, in Ukraine and in Venezuela, the restriction or disruption of global trade routes, the impact of changes to US economic policy, 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; the impact of the ramp-up of LNG Canada on commodity 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 uncertainties in the international trade environment, including with respect to tariffs, export restrictions, embargoes, and key trade agreements (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded); uncertainty in the regulatory framework governing GHG emissions including, among other things, financial and other support from various levels of government for climate related initiatives and potential emissions or production caps, and the implementation of the MOU in November 2025; civil unrest and 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 acquisition of the remaining interest in the AOSP mines and other acquisitions that occurred in 2025; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; changes to future abandonment and decommissioning costs; 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 or emissions, the imposition of tariffs, embargoes, or export restrictions on the Company's products (including uncertainties around US imposed tariffs, and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded), changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations (including the implementation of the MOU). 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 impact 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. Subsequently, on November 4, 2025, the federal government tabled the 2025 Budget, which proposed further amendments to the Competition Act, namely removing the requirement that businesses substantiate their environmental representations about a business or business activity based on an internationally recognized methodology, and eliminating private rights of action under the revised business-activity greenwashing provision. Uncertainty surrounding the interpretation and enforcement of this legislation, which includes the status of any proposed or future amendments, 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, 2025. It should also be read in conjunction with the Company's MD&A for the three months and year ended December 31, 2025. 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, 2025 and this MD&A have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (the "IFRS Accounting Standards").
Production volumes and per unit statistics 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, thermal bitumen, and SCO (including mining bitumen). 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 2025 financial results compared to 2024 and 2023, unless otherwise indicated. In addition, this MD&A details the Company's targeted capital program for 2026. 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, 2025, its Annual Information Form for the year ended December 31, 2025, and its audited consolidated financial statements for the year ended December 31, 2025, is available on SEDAR+ at https://www.sedarplus.ca, and on EDGAR at https://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 4, 2026.
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 longterm 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), thermal bitumen, 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 thermal bitumen.
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.
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.
Financial and Operational Highlights
($ millions, except per common share amounts)
2025
2024
2023 (1)
Product sales (2)
$ 44,167
$ 41,509
$ 40,835
Crude oil and NGLs
$ 40,740
$ 39,084
$ 37,300
Natural gas
$ 2,450
$ 1,568
$ 2,575
Net earnings
$ 10,820
$ 6,106
$ 8,233
Per common share - basic
$ 5.17
$ 2.87
$ 3.77
- diluted
$ 5.16
$ 2.85
$ 3.74
Adjusted net earnings from operations (3)
$ 7,444
$ 7,414
$ 8,533
Per common share - basic (4)
$ 3.56
$ 3.49
$ 3.91
- diluted (4)
$ 3.55
$ 3.46
$ 3.87
Cash flows from operating activities
$ 15,106
$ 13,386
$ 12,353
Adjusted funds flow (3)
$ 15,460
$ 14,859
$ 15,274
Per common share - basic (4)
$ 7.39
$ 6.99
$ 7.00
- diluted (4)
$ 7.37
$ 6.94
$ 6.93
Dividends declared per common share (5)
$ 2.35
$ 2.14
$ 1.85
Total assets
$ 91,830
$ 85,359
$ 75,955
Long-term debt, net (6)
$ 15,944
$ 18,688
$ 9,922
Cash flows used in investing activities
$ 6,687
$ 14,095
$ 4,858
Net capital expenditures (3)
$ 6,579
$ 14,431
$ 4,909
Abandonment expenditures
$ 771
$ 646
$ 509
Average realized price
Crude oil and NGLs - Exploration and Production ($/bbl) (4)
$ 71.54
$ 77.76
$ 72.36
Natural gas - Exploration and Production ($/Mcf) (7)
$ 2.51
$ 1.86
$ 3.10
SCO - Oil Sands Mining and Upgrading ($/bbl) (4)
$ 86.41
$ 98.03
$ 100.06
Daily production, before royalties (BOE/d)
1,570,757
1,363,496
1,332,105
Crude oil and NGLs (bbl/d)
1,146,175
1,005,603
973,530
Natural gas (MMcf/d) (8)
2,547
2,147
2,151
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.
Further details related to product sales are disclosed in note 21 to the Company's audited consolidated financial statements.
Non-GAAP Financial Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
On March 4, 2026, the Board of Directors approved a 6% increase in the quarterly dividend to $0.625 per common share, beginning with the dividend payable on April 7, 2026. On March 5, 2025, the Board of Directors approved a 4% increase in the quarterly dividend to $0.5875 per common share. On October 7, 2024, the Board of Directors approved a 7% increase in the quarterly dividend to $0.5625 per common share. 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.
Capital management measure. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
Calculated as natural gas sales divided by sales volumes.
Natural gas production volumes approximate sales volumes.
CONSOLIDATED NET EARNINGS AND ADJUSTED NET EARNINGS FROM OPERATIONS
For 2025, the Company reported net earnings of $10,820 million compared with $6,106 million for 2024 (2023 - $8,233 million). Net earnings for 2025 included non-operating income, net of tax, of $3,376 million compared with non-operating losses of
$1,308 million for 2024 (2023 - non-operating losses of $300 million) related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on financing activities, the gain from investment, the gain on acquisitions, disposition, and remeasurement, and recoverability charges related to the North Sea and Offshore Africa. Excluding these items, adjusted net earnings from operations for 2025 were $7,444 million compared with
$7,414 million for 2024 (2023 - $8,533 million).
The increase in net earnings and adjusted net earnings from operations for 2025 compared with 2024 primarily reflected:
higher sales volumes in the Oil Sands Mining and Upgrading segment;
higher crude oil and NGLs sales volumes in the North America Exploration and Production segment; and
higher realized natural gas pricing and sales volumes in the North America Exploration and Production segment; partially offset by:
lower realized SCO pricing(1) in the Oil Sands Mining and Upgrading segment; and
lower realized crude oil and NGLs pricing(1) in the North America Exploration and Production 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, foreign exchange (gain) loss, the gain on acquisitions, disposition, and remeasurement, the gain from investment, and recoverability charges related to the North Sea and Offshore Africa also contributed to the increase in net earnings for 2025 from 2024. These items are discussed in detail in the relevant sections of this MD&A. The AOSP asset swap is discussed below, and the recoverability charges related to the North Sea and Offshore Africa are discussed in detail in the 'Adjusted Depletion, Depreciation and Amortization - Exploration and Production' section of this MD&A.
AOSP ASSET SWAP TRANSACTION
On November 1, 2025, the Company completed the AOSP asset swap with Shell Canada Limited and affiliates ("Shell"). As a result of the transaction, the Company acquired from Shell, the remaining 10% interest in the AOSP mines, associated reserves, and additional working interests in a number of other non-producing oil sands leases, and in exchange to Shell, a 10% non-operated working interest in the Scotford Upgrader ("Scotford") and Quest Carbon Capture and Storage ("Quest") facilities. As a result, the Company owns and operates 100% of the AOSP mines and retains an 80% non-operated working interest in Scotford and Quest. The transaction had an effective date of March 1, 2025.
The Company recognized a $4,989 million gain related to the transaction, comprised of a $17 million gain on acquisition representing the excess of the fair value of the net assets acquired compared to the total purchase consideration and previously held interests, a non-cash gain of $4,508 million ($3,471 million after-tax) related to the remeasurement of the previously held interest in the AOSP mines to fair value, and a non-cash gain on disposition of $464 million ($357 million after-tax) related to the disposition of the 10% interest in Scotford and Quest. Further details are disclosed in note 6 to the Company's audited consolidated financial statements.
CASH FLOWS FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW
Cash flows from operating activities for 2025 were $15,106 million compared with $13,386 million for 2024 (2023 -
$12,353 million). The increase in cash flows from operating activities for 2025 from 2024 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 2025 was $15,460 million ($7.39 per common share) compared with $14,859 million ($6.99 per common share) for 2024 (2023 - $15,274 million; $7.00 per common share(2)). The increase in adjusted funds flow for 2025 from 2024 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, interest on PRT and corporate tax recoveries, and prepaid cost of service tolls.
PRODUCTION VOLUMES
Record crude oil and NGLs production before royalties for 2025 of 1,146,175 bbl/d increased 14% from 1,005,603 bbl/d in 2024 (2023 - 973,530 bbl/d). Natural gas production before royalties for 2025 averaged 2,547 MMcf/d, an increase of 19% from 2,147 MMcf/d in 2024 (2023 - 2,151 MMcf/d). Total production before royalties for 2025 of 1,570,757 BOE/d increased 15% from 1,363,496 BOE/d in 2024 (2023 - 1,332,105 BOE/d). Crude oil and NGLs and natural gas production volumes are discussed in detail in the 'Daily Production' section of this MD&A.
Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
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.
PRODUCT PRICES
In the Company's Exploration and Production segments, the 2025 realized crude oil and NGLs prices decreased 8% to average
$71.54 per bbl from $77.76 per bbl in 2024 (2023 - $72.36 per bbl), and the 2025 realized natural gas price increased 35% to average $2.51 per Mcf from $1.86 per Mcf in 2024 (2023 - $3.10 per Mcf). In the Oil Sands Mining and Upgrading segment, the Company's 2025 realized SCO sales price averaged $86.41 per bbl, a decrease of 12% from $98.03 per bbl in 2024 (2023 -
$100.06 per bbl). The Company's realized product pricing is reflective of the 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 'Realized Product Prices, Royalties and Transportation - Oil Sands Mining and Upgrading' sections of this MD&A.
PRODUCTION EXPENSE
In the Company's Exploration and Production segments, the 2025 crude oil and NGLs production expense(1) averaged $14.33 per bbl, comparable with $14.72 per bbl in 2024 (2023 - $16.12 per bbl), and natural gas production expense(1) averaged $1.14 per Mcf in 2025, a decrease of 7% from $1.22 per Mcf in 2024 (2023 - $1.30 per Mcf). In the Oil Sands Mining and Upgrading segment, the 2025 production expense(1) averaged $22.66 per bbl, comparable with $22.88 per bbl in 2024 (2023 - $24.32 per bbl). Crude oil and NGLs and natural gas production expense is discussed in detail in the 'Production Expense - Exploration and Production' and the 'Production Expense - Oil Sands Mining and Upgrading' sections of this MD&A.
SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company's quarterly financial results for the eight most recently completed quarters:
($ millions, except per common share amounts)
2025
Total
Dec 31
Sep 30
Jun 30
Mar 31
Product sales (1)
$
44,167
$ 10,710
$ 11,070
$ 9,675
$ 12,712
Crude oil and NGLs
$
40,740
$ 9,666
$ 10,468
$ 8,874
$ 11,732
Natural gas
$
2,450
$ 735
$ 399
$ 600
$ 716
Net earnings
Net earnings per common share
$
10,820
$ 5,303
$ 600
$ 2,459
$ 2,458
- basic
$
5.17
$ 2.55
$ 0.29
$ 1.17
$ 1.17
- diluted
$
5.16
$ 2.54
$ 0.29
$ 1.17
$ 1.17
2024
Total
Dec 31
Sep 30
Jun 30
Mar 31(2)
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
- basic
$
2.87
$ 0.54
$ 1.07
$ 0.80
$ 0.46
- diluted
$
2.85
$ 0.54
$ 1.06
$ 0.80
$ 0.46
Further details related to product sales are disclosed in note 21 to the Company's audited consolidated financial statements.
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, Ukraine and Venezuela, and the impacts of ongoing tariff and trade uncertainty) on worldwide benchmark pricing, the impact of shale oil production in North America, the impact of the start-up of the Trans Mountain Expansion ("TMX") pipeline in 2024, 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, the impact of liquefied natural gas ("LNG") demand and exports, and the impact of shale gas production in the US.
(1) Calculated as respective production expense divided by respective sales volumes.
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 declines, the impact of turnarounds 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 in 2024, the acquisition of assets in the Palliser block and the Grande Prairie area in 2025, and the AOSP asset swap in 2025), wildfires, and maintenance activities in the North America Exploration and Production segment. Sales volumes in the International segments also reflected fluctuations due to the timing of liftings, planned abandonment activities in the North Sea, and temporary suspension of production at Baobab in Offshore Africa for planned FPSO maintenance.
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 in 2024, and the acquisition of assets in the Palliser block and the Grande Prairie area in 2025), natural field declines, the impact of seasonal conditions, and wildfires in the North America Exploration and Production segment.
Production expense - Fluctuations primarily due to the impacts of the demand and cost for services, fluctuations in product mix and production volumes, seasonal conditions, carbon tax, fluctuating energy costs, inflationary cost pressures, cost optimizations across all segments, turnarounds 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 in the Oil Sands Mining and Upgrading segment, and recoverability charges related to the North Sea and Offshore 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 lease liabilities, the impact of movements in benchmark interest rates on outstanding floating rate long-term debt, and interest on PRT and corporate tax 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 and working capital.
Gain on acquisitions, disposition, and remeasurement - A gain on acquisitions representing the excess of the fair value of the net assets acquired compared to total purchase consideration and previously held interests, a gain on remeasurement to fair value of the Company's pre-existing 90% interest in the AOSP mines as part of the AOSP asset swap, and a gain on disposition of the 10% interest in Scotford and Quest disposed of as part of the AOSP asset swap.
Business Environment and Outlook
Global crude oil benchmark pricing declined through the fourth quarter of 2025 as increasing global supply outpaced relatively modest demand growth, which remained subdued amid ongoing tariff and trade uncertainty. Late in the fourth quarter of 2025, escalating geopolitical tensions contributed to heightened concerns regarding potential crude oil supply disruptions entering into 2026. Natural gas benchmark pricing increased during the fourth quarter of 2025, driven by seasonal demand factors and continued strength in LNG export activity out of the US Gulf Coast. In Canada, AECO benchmark pricing improved due to robust export volumes out of the WCSB. The ongoing ramp-up of LNG Canada is expected to further increase LNG demand and support AECO pricing in 2026.
During 2025, the US government announced tariffs on certain Canadian goods. While these actions have contributed to market volatility, including commodity price and foreign currency volatility, these tariffs have not had a material impact on the Company's financial results as of the date of this MD&A. The duration of these trade actions remains uncertain, and broader changes to US economic policy may have a material effect on the Company's business, financial conditions, or results in future periods. The Company will continue to monitor and assess the implications of any current or emerging US economic policies.
BENCHMARK COMMODITY PRICES | |||
(Yearly average) | 2025 | 2024 | 2023 |
WTI benchmark price (US$/bbl) | $ 64.77 | $ 75.72 | $ 77.61 |
Dated Brent benchmark price (US$/bbl) | $ 69.02 | $ 80.75 | $ 82.61 |
WCS Heavy Differential from WTI (US$/bbl) | $ 11.10 | $ 14.73 | $ 18.62 |
SCO price (US$/bbl) | $ 64.42 | $ 75.09 | $ 79.64 |
Condensate benchmark price (US$/bbl) | $ 63.32 | $ 72.94 | $ 76.55 |
NYMEX benchmark price (US$/MMBtu) | $ 3.43 | $ 2.27 | $ 2.74 |
AECO benchmark price (C$/GJ) | $ 1.76 | $ 1.36 | $ 2.77 |
US/Canadian dollar average exchange rate (US$) | $ 0.7155 | $ 0.7300 | $ 0.7409 |
US/Canadian dollar year end exchange rate (US$) | $ 0.7292 | $ 0.6942 | $ 0.7573 |
Substantially all of the Company's production is sold based on US dollar benchmark pricing, with crude oil marketed based on WTI and Brent indices, and natural gas marketed using a diversified mix of AECO- and NYMEX-based pricing. 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$64.77 per bbl for 2025, a decrease of 14% from US$75.72 per bbl for 2024 (2023 - US$77.61 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$69.02 per bbl for 2025, a decrease of 15% from US$80.75 per bbl for 2024 (2023 - US$82.61 per bbl).
The decrease in WTI and Brent benchmark pricing for 2025 from 2024 primarily reflected increased global supply and inventory builds driven by near-record production from non-OPEC+ producers and higher OPEC+ output. Supply gains exceeded global demand growth, which remained muted amid ongoing tariff and trade uncertainty.
The WCS Heavy Differential averaged US$11.10 per bbl for 2025 compared with US$14.73 per bbl for 2024 (2023 -US$18.62 per bbl). The narrowing of the WCS Heavy Differential for 2025 from 2024 primarily reflected full year takeaway capacity on the TMX pipeline and strong US Gulf Coast heavy oil pricing.
The SCO price averaged US$64.42 per bbl for 2025, a decrease of 14% from US$75.09 per bbl for 2024 (2023 - US$79.64 per bbl). The decrease in SCO pricing for 2025 from 2024 primarily reflected weaker WTI benchmark pricing.
NYMEX benchmark pricing averaged US$3.43 per MMBtu for 2025, an increase of 51% from US$2.27 per MMBtu for 2024 (2023 - US$2.74 per MMBtu). The increase in NYMEX natural gas pricing for 2025 from 2024 primarily reflected lower US inventory levels in the first half of 2025, combined with record LNG exports out of the US Gulf Coast.
AECO benchmark pricing averaged $1.76 per GJ for 2025, an increase of 29% from $1.36 per GJ for 2024 (2023 -
$2.77 per GJ). The increase in AECO natural gas pricing for 2025 from 2024 primarily reflected higher NYMEX benchmark pricing and increased exports out of the WCSB.
Analysis of Changes in Product Sales
Changes due to Changes due to
($ millions) 2023 North America | Volumes | Prices | Other | 2024 | Volumes | Prices | Other | 2025 |
Crude oil and NGLs $ 17,375 | $ 283 | $ 1,082 | $ - | $ 18,740 | $ 2,392 | $ (2,030) | $ - | $ 19,102 |
Natural gas 2,375 | 3 | (963) | - | 1,415 | 261 | 611 | - | 2,287 |
Other (1) 10 | - | - | (4) | 6 | - | - | 86 | 92 |
19,760 | 286 | 119 | (4) | 20,161 | 2,653 | (1,419) | 86 | 21,481 |
North Sea Crude oil and NGLs 435 | 30 | 2 | - | 467 | (95) | (47) | - | 325 |
Natural gas 7 | 1 | (1) | - | 7 | 4 | 2 | - | 13 |
Other (1) - | - | - | 4 | 4 | - | - | (4) | - |
442 | 31 | 1 | 4 | 478 | (91) | (45) | (4) | 338 |
Offshore Africa Crude oil and NGLs 577 | (142) | (1) | - | 434 | (260) | (10) | - | 164 |
Natural gas 51 | (7) | (2) | - | 42 | (13) | 1 | - | 30 |
Other (1) 9 | - | - | (5) | 4 | - | - | (3) | 1 |
637 | (149) | (3) | (5) | 480 | (273) | (9) | (3) | 195 |
Oil Sands Mining and Upgrading Crude oil and NGLs 18,661 | 823 | (221) | - | 19,263 | 4,138 | (3,289) | - | 20,112 |
Other (1) 5 | - | - | 11 | 16 | - | - | 188 | 204 |
18,666 | 823 | (221) | 11 | 19,279 | 4,138 | (3,289) | 188 | 20,316 |
Midstream and Refining Midstream activities 76 | - | - | 6 | 82 | - | - | 9 | 91 |
Refined product sales and other (1) 926 | - | - | (113) | 813 | - | - | (143) | 670 |
1,002 | - | - | (107) | 895 | - | - | (134) | 761 |
Inter-segment Elimination and Other (2) | ||||||||
Product sales 318 | - | - | (116) | 202 | - | - | 864 | 1,066 |
Other (1) 10 | - | - | 4 | 14 | - | - | (4) | 10 |
328 | - | - | (112) | 216 | - | - | 860 | 1,076 |
Total $ 40,835 | $ 991 | $ (104) | $ (213) | $ 41,509 | $ 6,427 | $ (4,762) | $ 993 | $ 44,167 |
Includes the sale of diesel and other refined products, and other income.
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 6% to $44,167 million for 2025 from $41,509 million for 2024 (2023 - $40,835 million). The increase in total product sales was primarily due to higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; and higher crude oil and NGLs sales volumes, together with higher realized natural gas pricing and sales volumes in the North America Exploration and Production segment; partially offset by lower realized SCO pricing and lower realized crude oil and NGLs pricing in the Oil Sands Mining and Upgrading and North America Exploration and Production segments, respectively. Crude oil and NGLs and natural gas pricing are discussed in detail in the 'Business Environment and Outlook', 'Exploration and Production' and '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 2025, 1% of the Company's crude oil and NGLs and natural gas product sales were generated outside of North America (2024 - 2%; 2023 - 3%). North Sea accounted for 1% of crude oil and NGLs and natural gas product sales for 2025 (2024 - 1%; 2023 - 1%), and Offshore Africa accounted for less than 1% of crude oil and NGLs and natural gas product sales for 2025 (2024 - 1%; 2023 - 2%).
Daily Production
DAILY PRODUCTION, BEFORE ROYALTIES
2025
2024
2023
Crude oil and NGLs (bbl/d)
North America - Exploration and Production
569,401
509,288
496,100
North America - Oil Sands Mining and Upgrading (1)
International - Exploration and Production
565,102
472,245
451,339
North Sea
8,468
11,536
12,639
Offshore Africa
3,204
12,534
13,452
Total International (2)
11,672
24,070
26,091
Total Crude oil and NGLs
1,146,175
1,005,603
973,530
Natural gas (MMcf/d) (3)
North America
2,538
2,136
2,139
International
North Sea
3
2
2
Offshore Africa
6
9
10
Total International
9
11
12
Total Natural gas
2,547
2,147
2,151
Total Barrels of oil equivalent (BOE/d)
1,570,757
1,363,496
1,332,105
Product mix
Light and medium crude oil and NGLs
11%
10%
10%
Pelican Lake heavy crude oil
3%
3%
3%
Primary heavy crude oil
6%
6%
6%
Thermal bitumen
17%
20%
20%
Synthetic crude oil (1)
36%
35%
34%
Natural gas
27%
26%
27%
Percentage of product sales (1) (4) (5)
Crude oil and NGLs
94%
96%
93%
Natural gas
6%
4%
7%
SCO production before royalties excludes SCO consumed internally as diesel.
"International" includes North Sea and Offshore Africa Exploration and Production segments in all instances used in this MD&A.
Natural gas production volumes approximate sales volumes.
Net of blending and feedstock costs and excluding risk management activities.
Excluding Midstream and Refining revenue.
DAILY PRODUCTION, NET OF ROYALTIES | |||
2025 | 2024 | 2023 | |
Crude oil and NGLs (bbl/d) North America - Exploration and Production | 476,850 | 408,237 | 406,534 |
North America - Oil Sands Mining and Upgrading (1) International - Exploration and Production | 467,415 | 386,171 | 385,996 |
North Sea | 8,451 | 11,509 | 12,609 |
Offshore Africa | 3,061 | 11,918 | 12,183 |
Total International | 11,512 | 23,427 | 24,792 |
Total Crude oil and NGLs | 955,777 | 817,835 | 817,322 |
Natural gas (MMcf/d) North America | 2,466 | 2,091 | 2,055 |
International | |||
North Sea | 3 | 2 | 2 |
Offshore Africa | 6 | 9 | 10 |
Total International | 9 | 11 | 12 |
Total Natural gas | 2,475 | 2,102 | 2,067 |
Total Barrels of oil equivalent (BOE/d) | 1,368,198 | 1,168,209 | 1,161,852 |
(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, thermal bitumen, SCO, and natural gas.
Total 2025 production before royalties averaged 1,570,757 BOE/d, an increase of 15% from 1,363,496 BOE/d in 2024 (2023 -
1,332,105 BOE/d).
Record crude oil and NGLs production before royalties for 2025 averaged 1,146,175 bbl/d, an increase of 14% from 1,005,603 bbl/d for 2024 (2023 - 973,530 bbl/d). The increase in crude oil and NGLs production before royalties for 2025 from 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, strong utilization in the Oil Sands Mining and Upgrading segment, and strong drilling results in the North America Exploration and Production segment.
Annual crude oil and NGLs production before royalties for 2025 was within the Company's previously issued production target of 1,137,000 bbl/d and 1,151,000 bbl/d. Annual crude oil and NGLs production before royalties for 2026 is now targeted to average between 1,188,000 bbl/d and 1,229,000 bbl/d. Production targets constitute forward-looking statements. Refer to the 'Advisory' section of this MD&A for further details on forward-looking statements.
Natural gas production before royalties accounted for 27% of the Company's total production in 2025 on a BOE basis. Record natural gas production before royalties for 2025 averaged 2,547 MMcf/d, an increase of 19% from 2,147 MMcf/d for 2024 (2023 - 2,151 MMcf/d). The increase in natural gas production before royalties for 2025 from 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, combined with strong drilling results in the Company's liquids-rich natural gas assets.
Annual natural gas production before royalties for 2025 was within the Company's previously issued production target of 2,535 MMcf/d and 2,575 MMcf/d. Annual natural gas production before royalties for 2026 is now targeted to average between 2,560 MMcf/d and 2,615 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 2025 averaged 569,401 bbl/d, an increase of 12% from 509,288 bbl/d for 2024 (2023 - 496,100 bbl/d). The increase in North America crude oil and NGLs production before royalties for 2025 from 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, combined with strong drilling results.
Thermal oil production before royalties for 2025 averaged 275,086 bbl/d, comparable with 271,011 bbl/d for 2024 (2023 -262,000 bbl/d).
Pelican Lake heavy crude oil production before royalties averaged 42,470 bbl/d for 2025, a decrease of 5% from 44,779 bbl/d for 2024 (2023 - 47,078 bbl/d) reflecting Pelican Lake's long life low decline production.
Record North America natural gas production before royalties for 2025 averaged 2,538 MMcf/d, an increase of 19% from 2,136 MMcf/d for 2024 (2023 - 2,139 MMcf/d). The increase in natural gas production before royalties for 2025 from 2024 primarily reflected the acquisitions completed in December 2024 and in the second and third quarters of 2025, combined with strong drilling results in the Company's liquids-rich natural gas assets.
North America - Oil Sands Mining and Upgrading
Record SCO production before royalties for 2025 averaged 565,102 bbl/d, an increase of 20% from 472,245 bbl/d for 2024 (2023 - 451,339 bbl/d). The increase in SCO production before royalties for 2025 from 2024 primarily reflected the acquisition completed in December 2024, combined with strong utilization.
International - Exploration and Production
International crude oil and NGLs production before royalties for 2025 averaged 11,672 bbl/d, a decrease of 52% from 24,070 bbl/d for 2024 (2023 - 26,091 bbl/d). The decrease in International crude oil and NGLs production before royalties for 2025 from 2024 primarily reflected the temporary suspension of production at Baobab in Offshore Africa due to planned maintenance on its FPSO, which is expected to return to service in the second quarter of 2026, planned North Sea abandonments conducted as part of the previously announced decommissioning plans, and natural field declines.
Exploration and Production | |||
OPERATING HIGHLIGHTS | |||
2025 | 2024 | 2023 | |
Crude oil and NGLs ($/bbl) (1) Realized price (2) | $ 71.54 | $ 77.76 | $ 72.36 |
Transportation (3) | 7.02 | 5.50 | 4.23 |
Realized price, net of transportation (2) | 64.52 | 72.26 | 68.13 |
Royalties (4) | 11.53 | 14.85 | 12.55 |
Production expense (5) | 14.33 | 14.72 | 16.12 |
Netback (2) | $ 38.66 | $ 42.69 | $ 39.46 |
Natural gas ($/Mcf) (1) Realized price (6) | $ 2.51 | $ 1.86 | $ 3.10 |
Transportation (3) | 0.59 | 0.62 | 0.56 |
Realized price, net of transportation | 1.92 | 1.24 | 2.54 |
Royalties (4) | 0.08 | 0.05 | 0.13 |
Production expense (5) | 1.14 | 1.22 | 1.30 |
Netback (7) | $ 0.70 | $ (0.03) | $ 1.11 |
Barrels of oil equivalent ($/BOE) (1) Realized price (2) | $ 47.98 | $ 50.82 | $ 50.54 |
Transportation (3) | 5.54 | 4.78 | 3.88 |
Realized price, net of transportation (2) | 42.44 | 46.04 | 46.66 |
Royalties (4) | 6.90 | 8.96 | 7.77 |
Production expense (5) | 11.18 | 11.73 | 12.74 |
Netback (2) | $ 24.36 | $ 25.35 | $ 26.15 |
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.
Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
Calculated as transportation expense divided by respective sales volumes.
Calculated as royalties divided by respective sales volumes.
Calculated as production expense divided by respective sales volumes.
Calculated as natural gas sales divided by natural gas sales volumes.
Natural gas netbacks exclude NGLs netbacks derived from the Company's liquids-rich natural gas plays.
REALIZED PRODUCT PRICES - EXPLORATION AND PRODUCTION
2025 | 2024 | 2023 | |
Crude oil and NGLs ($/bbl) (1) North America (2) | $ 70.90 | $ 76.37 | $ 70.51 |
International average (3) | $ 98.07 | $ 108.80 | $ 107.46 |
North Sea (3) | $ 97.26 | $ 111.53 | $ 110.99 |
Offshore Africa (3) | $ 99.71 | $ 106.00 | $ 106.25 |
Crude oil and NGLs average (2) | $ 71.54 | $ 77.76 | $ 72.36 |
Natural gas ($/Mcf) (1) (3) North America | $ 2.47 | $ 1.81 | $ 3.04 |
International average | $ 12.45 | $ 12.01 | $ 12.81 |
North Sea | $ 11.77 | $ 9.93 | $ 10.45 |
Offshore Africa | $ 12.77 | $ 12.46 | $ 13.19 |
Natural gas average | $ 2.51 | $ 1.86 | $ 3.10 |
Average ($/BOE) (1) (2) | $ 47.98 | $ 50.82 | $ 50.54 |
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.
Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
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 decreased 7% to average $70.90 per bbl for 2025 from $76.37 per bbl for 2024 (2023 - $70.51 per bbl), primarily reflecting lower WTI benchmark pricing, partially offset by a 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 2025, the Company contributed approximately 223,000 bbl/d of heavy crude oil blends to the WCS stream.
North America realized natural gas prices increased 36% to average $2.47 per Mcf for 2025 from $1.81 per Mcf for 2024 (2023 - $3.04 per Mcf). The increase in realized natural gas prices per Mcf for 2025 from 2024 primarily reflected higher AECO benchmark and export pricing.
The prices received in the North America Exploration and Production segment by product type were as follows:
(Yearly average) | 2025 | 2024 | 2023 |
Wellhead Price (1) | |||
Light and medium crude oil and NGLs ($/bbl) | $ 65.77 | $ 69.42 | $ 70.72 |
Pelican Lake heavy crude oil ($/bbl) | $ 75.07 | $ 82.83 | $ 77.69 |
Primary heavy crude oil ($/bbl) | $ 73.74 | $ 81.97 | $ 75.67 |
Thermal bitumen ($/bbl) | $ 72.42 | $ 76.57 | $ 67.62 |
Natural gas ($/Mcf) | $ 2.47 | $ 1.81 | $ 3.04 |
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 $98.07 per bbl for 2025, a decrease of 10% from $108.80 per bbl for 2024 (2023 - $107.46 per bbl). Realized crude oil and NGLs prices per bbl in any particular year are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, prevailing Brent benchmark prices and foreign exchange rates at the time of lifting.
ROYALTIES - EXPLORATION AND PRODUCTION
2025
2024
2023
Crude oil and NGLs ($/bbl) (1)
North America
$ 11.77
$ 15.40
$ 12.89
International average
$ 1.56
$ 2.75
$ 5.99
North Sea
$ 0.15
$ 0.26
$ 0.33
Offshore Africa
$ 4.41
$ 5.30
$ 10.08
Crude oil and NGLs average
$ 11.53
$ 14.85
$ 12.55
Natural gas ($/Mcf) (1)
North America
$ 0.08
$ 0.04
$ 0.13
Offshore Africa
$ 0.59
$ 0.57
$ 0.62
Natural gas average
$ 0.08
$ 0.05
$ 0.13
Average ($/BOE) (1)
$ 6.90
$ 8.96
$ 7.77
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 2025 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 17% of product sales for 2025 compared with 20% of product sales for 2024 (2023 - 18%). The decrease in royalty rates for 2025 from 2024 primarily reflected lower benchmark pricing and the impact of sliding scale royalty rates.
Natural gas royalty rates averaged approximately 3% of product sales for 2025 compared with 2% of product sales for 2024 (2023 - 4%). The increase in royalty rates for 2025 from 2024 primarily reflected higher prevailing 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 4% for 2025 compared with 5% of product sales for 2024 (2023 - 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
2025 | 2024 | 2023 | |
Crude oil and NGLs ($/bbl) (1) North America | $ 12.19 | $ 12.55 | $ 14.46 |
International average | $ 103.48 | $ 62.99 | $ 48.16 |
North Sea | $ 136.47 | $ 103.28 | $ 85.57 |
Offshore Africa | $ 36.73 | $ 21.77 | $ 21.14 |
Crude oil and NGLs average | $ 14.33 | $ 14.72 | $ 16.12 |
Natural gas ($/Mcf) (1) North America | $ 1.11 | $ 1.19 | $ 1.27 |
International average | $ 9.23 | $ 6.51 | $ 7.26 |
North Sea | $ 12.18 | $ 8.95 | $ 9.85 |
Offshore Africa | $ 7.80 | $ 5.98 | $ 6.83 |
Natural gas average | $ 1.14 | $ 1.22 | $ 1.30 |
Average ($/BOE) (1) | $ 11.18 | $ 11.73 | $ 12.74 |
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.
Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
North America
North America crude oil and NGLs production expense for 2025 averaged $12.19 per bbl, comparable with $12.55 per bbl for 2024 (2023 - $14.46 per bbl).
North America natural gas production expense for 2025 averaged $1.11 per Mcf, a decrease of 7% from $1.19 per Mcf for 2024 (2023 - $1.27 per Mcf). The decrease in natural gas production expense per Mcf for 2025 from 2024 primarily reflected higher production volumes.
International
International crude oil and NGLs production expense for 2025 averaged $103.48 per bbl, an increase of 64% from $62.99 per bbl for 2024 (2023 - $48.16 per bbl). The increase in crude oil and NGLs production expense per bbl for 2025 from 2024 primarily reflected activities at Ninian in the pre-cessation period, the timing of liftings from various fields that have different cost structures, and the impact of foreign exchange.
ADJUSTED DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND PRODUCTION
($ millions, except per BOE amounts) | 2025 | 2024 | 2023 |
North America | $ 4,582 | $ 3,831 | $ 3,679 |
North Sea | 1,573 | 279 | 494 |
Offshore Africa | 432 | 297 | 213 |
Depletion, depreciation and amortization | $ 6,587 | $ 4,407 | $ 4,386 |
Less: Recoverability charges (1) | 1,777 | 222 | 436 |
Adjusted depletion, depreciation and amortization (2) | $ 4,810 | $ 4,185 | $ 3,950 |
$/BOE (3) | $ 13.07 | $ 12.92 | $ 12.27 |
During 2024, in connection with the Company's notice of withdrawal from Block 11B/12B in South Africa, the Company derecognized $62 million of exploration and evaluation assets through depletion, depreciation and amortization expense.
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.
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 2025 of $13.07 per BOE was comparable with $12.92 per BOE for 2024 (2023 - $12.27 per BOE).
International Matters - North Sea and Offshore Africa
Pre-tax recoverability charges of $1,777 million in 2025 reflect the acceleration of the Company's abandonment and decommissioning activities and revisions to cost estimates in the North Sea, together with strategic decisions to not pursue an extension of its Production Sharing Contract ("PSC") for the Espoir Field, Block CI-26, in Offshore Africa and to not pursue development of Kossipo in Offshore Africa.
In the North Sea, following a competitive tender for the Ninian South Platform, estimated abandonment costs were higher than originally budgeted. Accordingly, the Company updated its abandonment and decommissioning cost estimates for the Ninian Central and South Platforms and T-Block (Tiffany, Toni and Thelma fields). Additionally, based on current and forecasted economic conditions, including commodity prices and market egress, the Company determined that the T-Block assets were no longer economically viable. Cessation of production has been accelerated to the first quarter of 2027 and associated crude oil reserves were de-booked. As a result, the Company recognized a non-cash charge of $836 million (2024 - $21 million; 2023 -
$113 million), comprised of a recoverability charge recognized in depletion, depreciation and amortization expense of
$1,462 million (2024 - $160 million; 2023 - $436 million), net of deferred tax recoveries of $626 million (2024 - $139 million; 2023 - $323 million).
In Offshore Africa, the Company determined that it would not pursue an extension of its PSC for the Espoir Field, Block CI-26, and de-booked associated crude oil reserves. The Company is working with the Government of Côte d'Ivoire to facilitate the transition of operatorship in the second half of 2026. As a result, the Company recognized a non-cash recoverability charge of
$269 million as at December 31, 2025. Additionally, the Company decided not to pursue development of Kossipo, and recognized a recoverability charge of $46 million related to the derecognition of its exploration and evaluation assets.
Estimates of asset retirement obligations and related tax recoveries remain subject to revision as abandonment activities progress. Recoverability charges are recognized in depletion, depreciation and amortization expense.
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND PRODUCTION
($ millions, except per BOE amounts) | 2025 | 2024 | 2023 |
North America | $ 221 | $ 231 | $ 234 |
North Sea | 64 | 65 | 46 |
Offshore Africa | 9 | 9 | 8 |
Asset retirement obligation accretion | $ 294 | $ 305 | $ 288 |
$/BOE (1) | $ 0.80 | $ 0.94 | $ 0.89 |
(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 2025 of $0.80 per BOE decreased 15% from
$0.94 per BOE for 2024 (2023 - $0.89 per BOE). The decrease in asset retirement obligation accretion expense per BOE for 2025 from 2024 reflected the impact of changes in discount rates at December 31, 2024, combined with higher sales volumes in 2025, partially offset by revisions in cost and timing estimates at December 31, 2024, North America acquisitions completed during 2025, and North Sea cost and timing estimate revisions during 2025.
Oil Sands Mining and Upgrading
OPERATING HIGHLIGHTS
The Company continues to focus on safe, reliable, and efficient operations, leveraging its technical expertise across the Horizon and AOSP sites. Record SCO production averaged 565,102 bbl/d in 2025, reflecting the acquisition completed in December 2024, combined with strong utilization. Additionally, the Company successfully completed the AOSP asset swap with Shell during the fourth quarter of 2025.
REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION - OIL SANDS MINING AND UPGRADING
($/bbl) | 2025 | 2024 | 2023 |
Realized SCO sales price (1) | $ 86.41 | $ 98.03 | $ 100.06 |
Bitumen value for royalty purposes (2) | $ 66.23 | $ 72.68 | $ 65.43 |
Bitumen royalties (3) | $ 13.84 | $ 17.23 | $ 14.43 |
Transportation (4) | $ 3.31 | $ 2.91 | $ 1.89 |
Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
Calculated as the annual average of the bitumen methodology price.
Calculated as royalties divided by sales volumes.
Calculated as transportation expense divided by sales volumes.
The realized SCO sales price averaged $86.41 per bbl for 2025, a decrease of 12% from $98.03 per bbl for 2024 (2023 -
$100.06 per bbl). The decrease in realized SCO sales price per bbl for 2025 from 2024 primarily reflected lower WTI benchmark pricing.
Bitumen royalties averaged $13.84 per bbl for 2025, a decrease from $17.23 per bbl for 2024 (2023 - $14.43 per bbl) primarily reflecting the decrease in average bitumen value for royalty purposes and the impact of royalty true-ups.
Transportation expense averaged $3.31 per bbl for 2025, an increase of 14% from $2.91 per bbl for 2024 (2023 - $1.89 per bbl). The increase in transportation expense per bbl for 2025 from 2024 primarily reflected higher volumes shipped on the TMX pipeline in 2025.
PRODUCTION EXPENSE - OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and Upgrading production expense disclosed in note 21 to the Company's audited consolidated financial statements.
($ millions) | 2025 | 2024 | 2023 |
Production expense, excluding natural gas costs | $ 4,543 | $ 3,801 | $ 3,794 |
Natural gas costs | 150 | 120 | 195 |
Production expense | $ 4,693 | $ 3,921 | $ 3,989 |
($/bbl) | 2025 | 2024 | 2023 |
Production expense, excluding natural gas costs (1) | $ 21.94 | $ 22.18 | $ 23.13 |
Natural gas costs (2) | 0.72 | 0.70 | 1.19 |
Production expense (3) | $ 22.66 | $ 22.88 | $ 24.32 |
Sales volumes (bbl/d) | 567,335 | 468,280 | 449,282 |
|
Production expense for 2025 of $22.66 per bbl was comparable with $22.88 per bbl for 2024 (2023 - $24.32 per bbl).
DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND UPGRADING
($ millions, except per bbl amounts) | 2025 | 2024 | 2023 |
Depletion, depreciation and amortization | $ 2,780 $ | 2,258 | $ 2,011 |
$/bbl (1) | $ 13.42 $ | 13.17 | $ 12.26 |
(1) Calculated as depletion, depreciation and amortization divided by sales volumes.
Depletion, depreciation and amortization expense for 2025 of $13.42 per bbl was comparable with $13.17 per bbl for 2024 (2023 - $12.26 per bbl).
ASSET RETIREMENT OBLIGATION ACCRETION - OIL SANDS MINING AND UPGRADING
($ millions, except per bbl amounts) | 2025 | 2024 | 2023 |
Asset retirement obligation accretion | $ 86 $ | 84 | $ 78 |
$/bbl (1) | $ 0.42 $ | 0.49 | $ 0.48 |
(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 2025 of $0.42 per bbl decreased 14% from
$0.49 per bbl for 2024 (2023 - $0.48 per bbl). The decrease in asset retirement obligation accretion expense per bbl for 2025 from 2024 primarily reflected the impact of higher sales volumes.
Midstream and Refining | |||
($ millions) | 2025 | 2024 | 2023 |
Product sales | |||
Midstream activities | $ 91 | $ 82 | $ 76 |
NWRP, refined product sales and other | 670 | 813 | 926 |
Segmented revenue Less: | 761 | 895 | 1,002 |
NWRP, refining toll | 262 | 295 | 303 |
Midstream activities | 22 | 20 | 29 |
Production expense | 284 | 315 | 332 |
NWRP, feedstock costs | 503 | 669 | 646 |
Transportation expenses | 42 | 16 | 18 |
Depreciation | 17 | 16 | 16 |
Segmented loss | $ (85) | $ (121) | $ (10) |
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 bitumen upgrader and refinery with an output capacity of approximately 80,000 bbl/d. The refinery processes approximately 50,000 bbl/d of bitumen feedstock, including 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 other 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 2025 averaged 68,139 BOE/d (17,035 BOE/d to the Company) (2024 - 76,664 BOE/d; 19,166 BOE/d to the Company; 2023 - 81,525 BOE/d; 20,381 BOE/d to the Company), reflecting the 25% toll payer commitment.
As at December 31, 2025, NWRP had $1,583 million (December 31, 2024 - $1,459 million) outstanding under its unsecured commercial paper program. NWRP has a $1,900 million syndicated credit facility that reserves capacity for amounts outstanding under its commercial paper program and for a debt service reserve equal to six months of anticipated facility interest and fees. As at December 31, 2025, the facility was undrawn.
During 2025, NWRP repaid and cancelled $250 million of the non-revolving portion of the syndicated credit facility.
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.
As at December 31, 2025, NWRP had $8,750 million in long-term notes outstanding (December 31, 2024 - $8,750 million).
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.
NWRP also has short-term borrowings under a $300 million syndicated credit facility ("demand operating facility") (December 31, 2024 - $300 million). As at December 31, 2025, NWRP had borrowings of $50 million under the demand operating facility (December 31, 2024 - $103 million).
As at December 31, 2025, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $496 million (2024 - $509 million). The Company's recovery of unrecognized equity losses from NWRP for 2025 was $13 million (2024 - recovery of unrecognized equity losses of $46 million; 2023 - unrecognized equity loss of $4 million).
Corporate and Other | |||
ADMINISTRATION EXPENSE | |||
($ millions, except per BOE amounts) | 2025 | 2024 | 2023 |
Administration expense | $ 615 | $ 503 | $ 452 |
$/BOE (1) | $ 1.07 | $ 1.02 | $ 0.93 |
Sales volumes (BOE/d) (2) | 1,575,845 | 1,353,166 | 1,331,092 |
Calculated as administration expense divided by sales volumes.
Total Company sales volumes.
Administration expense for 2025 of $1.07 per BOE increased 5% from $1.02 per BOE for 2024 (2023 - $0.93 per BOE). Administration expense per BOE increased from 2024 primarily reflecting higher personnel costs, including incremental costs from recent acquisitions.
SHARE-BASED COMPENSATION | |||
($ millions) | 2025 | 2024 | 2023 |
Share-based compensation expense | $ 180 $ | 279 $ | 491 |
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, by individual employee performance, and the extent to which certain other performance measures are met.
The Company recognized $180 million of share-based compensation expense for 2025 primarily as a result of changes in the Company's share price, 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, and the impact of vested stock options exercised or surrendered during the period. An expense of $30 million related to PSUs granted to certain executive employees was included in the share-based compensation expense for 2025 (2024 - $77 million expense; 2023 - $70 million expense).
INTEREST AND OTHER FINANCING EXPENSE | |||
($ millions, except effective interest rate) | 2025 | 2024 | 2023 |
Interest and other financing expense | $ 834 | $ 592 | $ 636 |
Less: Interest (income) and other expense (1) | (205) | (81) | (55) |
Interest expense on long-term debt and lease liabilities (1) | $ 1,039 | $ 673 | $ 691 |
Average current and long-term debt (2) | $ 18,401 | $ 11,895 | $ 12,749 |
Average lease liabilities (2) | 1,570 | 1,509 | 1,500 |
Average long-term debt and lease liabilities (2) | $ 19,971 | $ 13,404 | $ 14,249 |
Average effective interest rate (3) (4) | 5.1% | 4.9% | 4.8% |
Interest and other financing expense ($/BOE) (5) | $ 1.45 | $ 1.20 | $ 1.31 |
Sales volumes (BOE/d) (6) | 1,575,845 | 1,353,166 | 1,331,092 |
Item is a component of interest and other financing expense.
The average of current and long-term debt and lease liabilities outstanding during the respective year.
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.
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.
Calculated as interest and other financing expense divided by sales volumes.
Total Company sales volumes.
Interest and other financing expense for 2025 increased 21% to $1.45 per BOE from $1.20 per BOE for 2024 (2023 -
$1.31 per BOE). The increase in interest and other financing expense per BOE for 2025 from 2024 primarily reflected higher average debt levels, partially offset by higher sales volumes.
The Company's average effective interest rate of 5.1% for 2025 increased from 4.9% for 2024 primarily reflecting higher average long-term debt levels held in 2025.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, interest rate, and foreign currency exposures. These derivative financial instruments are not intended for trading or speculative purposes.
($ millions)
2025
2024
2023
Foreign currency forward contracts
$ (107)
$ 155
$ (17)
Foreign currency put options (1)
23
-
-
Natural gas financial instruments (2) (3) (4) (5)
(5)
13
3
Net realized (gain) loss
(89)
168
(14)
Foreign currency forward contracts
-
15
(9)
Natural gas financial instruments (2) (3) (4) (5)
14
(6)
21
Natural gas embedded derivative (6)
57
-
-
Net unrealized loss
71
9
12
Net (gain) loss
$ (18)
$ 177
$ (2)
During 2025, the Company periodically entered into foreign currency put options contracts. Further details are disclosed in note 18 to the Company's audited consolidated financial statements.
In 2025, the Company entered into fixed price financial contracts to buy 12,500 MMBtu/d of natural gas at US$1.30 AECO for the period of August to December 2025, and 25,000 MMBtu/d of natural gas at US$2.16 AECO for the period of January to December 2026.
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.
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.
Certain commodity financial instruments were assumed in the acquisition of Painted Pony Energy Ltd. in 2020.
In 2025, the Company entered into a long-term natural gas supply agreement containing an embedded derivative. Further details are disclosed in note 18 to the Company's audited consolidated financial statements.
During 2025, the Company recorded a net realized risk management gain of $89 million primarily related to the settlement of foreign currency forward contracts.
The Company recorded a net unrealized loss of $71 million ($55 million after tax of $16 million) on its risk management activities for 2025 (2024 - $9 million unrealized loss ($10 million after tax of $1 million); 2023 - $12 million unrealized loss ($7 million after tax of $5 million)).
Further details related to outstanding derivative financial instruments as at December 31, 2025 are disclosed in note 18 to the Company's audited consolidated financial statements.
FOREIGN EXCHANGE | |||
($ millions) | 2025 | 2024 | 2023 |
Net realized loss (gain) | $ 108 | $ 67 | $ (19) |
Net unrealized (gain) loss | (870) | 888 | (260) |
Net (gain) loss (1) | $ (762) | $ 955 | $ (279) |
Amounts are reported net of derivative financial instruments designated as cash flow hedges.
The net realized foreign exchange loss for 2025 was primarily related to exchange rate fluctuations on the settlement of US dollar debt, and on the settlement of working capital items denominated in US dollars. The net unrealized foreign exchange gain for 2025 was primarily related to the translation of outstanding US dollar debt. The US/Canadian dollar exchange rate as at December 31, 2025 was US$0.7292 (December 31, 2024 - US$0.6942; December 31, 2023 - US$0.7573).
INCOME TAXES | |||
($ millions, except effective tax rates) | 2025 | 2024 | 2023 |
North America (1) | $ 2,193 | $ 1,654 | $ 1,853 |
North Sea | (124) | (41) | (6) |
Offshore Africa | 16 | 57 | 73 |
Current PRT - North Sea | (184) | (134) | (58) |
Other taxes | 10 | (5) | 17 |
Current income tax | 1,911 | 1,531 | 1,879 |
Deferred corporate income tax | 887 | 520 | 267 |
Deferred PRT - North Sea | (377) | (98) | (214) |
Deferred income tax | 510 | 422 | 53 |
Income tax | $ 2,421 | $ 1,953 | $ 1,932 |
Earnings before taxes | $ 13,241 | $ 8,059 | $ 10,165 |
Effective tax rate on net earnings (2) | 18% | 24% | 19% |
($ millions, except effective tax rates) | 2025 | 2024 | 2023 |
Income tax | $ 2,421 | $ 1,953 | $ 1,932 |
Tax effect on non-operating items (3) | (481) | 175 | 345 |
Current PRT - North Sea | 184 | 134 | 58 |
Deferred PRT - North Sea | (84) | 9 | 9 |
Other taxes | (10) | 5 | (17) |
Effective tax on adjusted net earnings | $ 2,030 | $ 2,276 | $ 2,327 |
Adjusted net earnings from operations (4) | $ 7,444 | $ 7,414 | $ 8,533 |
Adjusted net earnings from operations, before taxes | $ 9,474 | $ 9,690 | $ 10,860 |
Effective tax rate on adjusted net earnings from operations (5) (6) | 21% | 23% | 21% |
Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments.
Calculated as total of current and deferred income tax divided by earnings before taxes.
Includes the net income tax effect on PSUs, certain stock options, unrealized risk management, gain on disposition and remeasurement, and recoverability charges related to the North Sea and Offshore Africa.
Non-GAAP Financial Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
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.
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 2025 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.
Deferred corporate income tax in North America for 2025 included the deferred tax impacts of the gain on disposition and remeasurement associated with the AOSP asset swap.
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 in the North 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 2025, the Company filed Scientific Research and Experimental Development claims of approximately $240 million (2024 - $273 million; 2023 - $380 million) relating to qualifying research and development expenditures for Canadian income tax purposes.
Net Capital Expenditures (1) (2)
($ millions)
2025
2024
2023
EXPLORATION AND PRODUCTION
Exploration and Evaluation Assets
Net expenditures
$ 46
$ 82
$ 47
Net property acquisitions (dispositions) (3)
69
330
(3)
Total Exploration and Evaluation Assets
115
412
44
Property, Plant and Equipment
Net property acquisitions (3)
1,015
2,642
24
Well drilling, completion and equipping
2,107
1,832
1,579
Production and related facilities
1,560
1,336
1,267
Other
50
53
61
Total Property, Plant and Equipment
4,732
5,863
2,931
Total Exploration and Production
4,847
6,275
2,975
OIL SANDS MINING AND UPGRADING
Project costs
319
306
348
Sustaining capital
1,274
1,466
1,347
Turnaround costs
241
153
189
Net property acquisitions (3)
(212)
6,173
5
Other
10
6
5
Total Oil Sands Mining and Upgrading
1,632
8,104
1,894
Midstream and Refining
8
11
10
Head office
92
41
30
Net capital expenditures
$ 6,579
$ 14,431
$ 4,909
Abandonment expenditures
$ 771
$ 646
$ 509
By Segment
North America
$ 4,364
$ 6,033
$ 2,770
North Sea
16
39
33
Offshore Africa
467
203
172
Oil Sands Mining and Upgrading
1,632
8,104
1,894
Midstream and Refining
8
11
10
Head office
92
41
30
Net capital expenditures
$ 6,579
$ 14,431
$ 4,909
Net capital expenditures exclude the impact of lease assets and fair value adjustments.
Non-GAAP Financial Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
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. Includes cash acquired and received as net consideration of $212 million related to the AOSP asset swap within the Oil Sands Mining and Upgrading segment in 2025.
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 2025 were $6,579 million compared with $14,431 million for 2024. In addition, the Company reported abandonment expenditures of $771 million for the year ended December 31, 2025 compared with $646 million for the year ended December 31, 2024.
CAPITAL SPENDING
On December 16, 2025, the Company announced its 2026 operating capital budget(1) targeted at approximately $6,300 million. With this capital, the Company is targeting production growth in 2026 of approximately 3% from 2025, as it invests in short and medium-term production, while commencing front-end engineering and design on potential additional medium and long-term value creation opportunities. In addition, the Company targets approximately $125 million of capital related to carbon capture projects. The Company targets $993 million in abandonment expenditures for 2026. Subsequent to December 31, 2025, the Company revised its operating capital forecast to $5,990 million and increased its production guidance to between 1,615,000 BOE/d and 1,665,000 BOE/d.
Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns, and the balancing of project risks and time horizons. The 2026 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.
In February 2026, subsequent to year end, the Company acquired certain producing and non-producing crude oil and NGLs, and natural gas assets in the Peace River area in the North America Exploration and Production segment for cash consideration of approximately $765 million, subject to final closing adjustments. Net assets acquired primarily include exploration and evaluation assets and property, plant and equipment. The Company also assumed associated asset retirement obligations. The 2026 capital budget did not include capital related to this acquisition.
DRILLING ACTIVITY (1) (2)
(number of net wells) | 2025 | 2024 | 2023 |
Net successful crude oil wells (3) | 358 | 307 | 221 |
Net successful natural gas wells | 78 | 78 | 61 |
Dry wells | 2 | 2 | 2 |
Total | 438 | 387 | 284 |
Success rate | 99% | 99% | 99% |
Includes drilling activity for North America and International segments.
Excludes stratigraphic and service wells.
Includes bitumen wells.
North America
During 2025, the Company drilled 78 net natural gas wells, 198 net primary heavy crude oil wells, 16 net Pelican Lake heavy crude oil wells, 78 net thermal bitumen wells, and 68 net light crude oil wells.
Liquidity and Capital Resources | |||
($ millions, except ratios) | 2025 | 2024 | 2023 |
Adjusted working capital (1) | $ 42 | $ 174 | $ 712 |
Long-term debt, net (2) | $ 15,944 | $ 18,688 | $ 9,922 |
Shareholders' equity | $ 44,366 | $ 39,468 | $ 39,832 |
Debt to book capitalization (2) | 26% | 32% | 20% |
After-tax return on average capital employed (3) | 20% | 13% | 17% |
Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
Capital Management Measure. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
Non-GAAP Ratio. Refer to the 'Non-GAAP and Other Financial Measures' section of this MD&A.
As at December 31, 2025, 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.
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.
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, where 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 2025, the Company extended its $500 million revolving credit facility originally maturing February 2026 to June 2027. During 2024, the Company extended its $500 million revolving credit facility from February 2025 to February 2026. During 2023, the Company extended its $500 million revolving credit facility from February 2024 to February 2025.
During 2025, the Company increased its $2,425 million revolving syndicated facility to $2,565 million, and extended
$2,425 million originally due June 2027 to June 2029. The remaining $140 million outstanding under this facility will mature in June 2027. Each of the revolving credit facilities are extendible annually at the mutual agreement of the Company and lenders. If the facilities are not extended, the full amount of the outstanding principal would be repayable on the maturity date.
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.
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. The Company reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
During 2025, 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 September 2027. 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 2025, the Company issued $550 million of 3.30% medium-term notes due December 2028, $550 million of 3.75% medium-term notes due February 2031, and $550 million of 4.55% medium-term notes due February 2036. After issuing these securities, the Company had $1,350 million remaining on its base shelf prospectus.
During 2024, the Company repaid $320 million of 3.55% medium-term notes.
During 2024, the Company issued $500 million of 4.15% medium-term notes due December 2031.
During 2025, the Company repaid US$600 million of 3.90% US dollar debt securities due February 2025, and US$600 million of 2.05% US dollar debt securities due July 2025.
During 2024, the Company repaid US$500 million of 3.80% US dollar debt securities.
During 2024, the Company issued US$750 million of 5.00% notes due December 2029 and US$750 million of 5.40% notes due December 2034.
During 2025, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to US$4,500 million of debt securities in the United States, which expires in September 2027. 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 2025, the Company filed a prospectus supplement to the base shelf prospectus. Under the base shelf prospectus, the Company completed the exchange of US$747 million of the outstanding restricted 5.00% US dollar debt securities due December 2029 and US$750 million of the outstanding restricted 5.40% US dollar debt securities due December 2034. The exchanged notes were not subject to transfer restrictions and did not impact the Company's level of indebtedness. After the exchange of these securities, the Company had US$3,003 million remaining on its base shelf prospectus.
As at December 31, 2025, the Company had undrawn bank credit facilities of $5,668 million, and a fully drawn non-revolving term credit facility of $4,000 million. Including cash and cash equivalents, the Company had approximately $6,341 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit.
Long-term debt, net was $15,944 million as at December 31, 2025, resulting in a debt to book capitalization ratio of 26% (December 31, 2024 - 32%; December 31, 2023 - 20%); 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, 2025, 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, 2025 are discussed in note 10 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 commodity 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, 2025 are discussed in note 18 to the Company's audited consolidated financial statements.
As at December 31, 2025, 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) | $ 441 | $ 5,637 | $ 2,489 | $ 8,140 |
Other long-term liabilities (2) | $ 381 | $ 268 | $ 659 | $ 1,863 |
Interest and other financing expense (3) | $ 971 | $ 910 | $ 1,860 | $ 3,678 |
Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $373 million; one to less than two years, $268 million; two to less than five years, $654 million; and thereafter, $1,811 million.
Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates as at December 31, 2025.
SHARE CAPITAL
As at December 31, 2025, there were 2,081,578,000 common shares outstanding (December 31, 2024 - 2,102,996,000 common shares) and 54,734,000 stock options outstanding (December 31, 2024 - 50,806,000 stock options). As at March 3, 2026, the Company had 2,085,972,000 common shares outstanding and 57,252,000 stock options outstanding.
On March 4, 2026, the Board of Directors approved a 6% increase in the quarterly dividend to $0.625 per common share, beginning with the dividend payable on April 7, 2026.
On March 5, 2025, the Board of Directors approved a 4% increase in the quarterly dividend to $0.5875 per common share.
On October 7, 2024, the Board of Directors approved a 7% increase in the quarterly dividend to $0.5625 per common share. On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to $0.525(1) per common share.
On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $0.50(1) per common share. On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.45(1) per common share.
The dividend policy undergoes periodic review by the Board of Directors and is subject to change.
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.
On March 10, 2025, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock Exchange ("TSX"), alternative Canadian trading platforms, and the New York Stock Exchange ("NYSE"), up to 178,738,237 common shares, representing 10% of the public float, over a 12-month period commencing March 13, 2025 and ending March 12, 2026.
For the year ended December 31, 2025, the Company purchased 33,480,000 common shares at a weighted average price of
$43.28 per common share for a total cost, including tax, of $1,467 million. Retained earnings were reduced by $1,287 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2025, up to and including March 3, 2026, the Company purchased 3,300,000 common shares at a weighted average price of $51.12 per common share for a total cost, including tax, of $169 million.
On March 4, 2026, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with the TSX to purchase, by way of Normal Course Issuer Bid, up to 10% of the public float (as determined in accordance with the rules of the TSX) of its issued and outstanding common shares. Subject to acceptance of the Notice of Intention by the TSX, and applicable securities law, the purchases would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE.
Commitments and Contingencies
In the normal course of business, the Company has committed to certain payments. The following table summarizes the Company's commitments as at December 31, 2025:
($ millions)
2026
2027
2028
2029
2030
Thereafter
Product transportation, purchases, and processing (1) (2) (3) (4)
$ 2,241
$ 2,223
$ 2,065
$ 1,912
$ 1,758
$ 18,025
North West Redwater Partnership
service toll (5)
$ 116
$ 95
$ 96
$ 95
$ 95
$ 3,878
Offshore vessels and equipment
$ 99
$ -
$ -
$ -
$ -
$ -
Field equipment and power (4)
$ 50
$ 26
$ 26
$ 24
$ 24
$ 170
Other
$ 122
$ 50
$ 19
$ 18
$ 18
$ 177
The Company's commitment for its 20-year product transportation agreement ending in 2044 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.
In 2025, in connection with the AOSP asset swap, the Company became the sole contracted shipper on the Corridor pipeline. Previously, the Company recognized a commitment associated with the pipeline, however, following the completion of the AOSP asset swap the contract has been recorded as a lease. Further details on the AOSP asset swap are disclosed in note 6 to the Company's audited consolidated financial statements.
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.
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.
Pursuant to the processing agreements, the Company pays its 25% pro rata share of the debt component of the monthly fee-for-service toll. Included in the toll is $1,792 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.
Reserves
For the years ended December 31, 2025 and 2024, 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, 2025:
Total Proved | Light and Medium Crude Oil | Primary Heavy Crude Oil | Pelican Lake Heavy Crude Oil | Thermal Bitumen | Mining Bitumen(2) | Synthetic Crude Oil(2) | Natural Gas | Natural Gas Liquids | Barrels of Oil Equivalent |
(MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (Bcf) | (MMbbl) | (MMBOE) | |
December 31, 2024 (1) | 252 | 219 | 255 | 3,312 | - | 7,663 | 16,904 | 713 | 15,231 |
Discoveries | - | - | - | - | - | - | - | - | - |
Extensions | 16 | 12 | - | 66 | - | - | 113 | 8 | 121 |
Infill Drilling | 2 | 17 | 1 | 9 | - | - | 191 | 36 | 97 |
Improved Recovery | - | 1 | 3 | - | - | 2 | - | - | 6 |
Acquisitions | 68 | - | - | - | 427 | - | 1,153 | 74 | 760 |
Dispositions | - | - | - | - | - | - | - | - | - |
Economic Factors | (4) | (4) | (3) | - | - | - | (99) | (4) | (32) |
Technical Revisions | 1 | 15 | 2 | 43 | 426 | (328) | 674 | 28 | 300 |
Production | (26) | (32) | (16) | (100) | (4) | (202) | (930) | (38) | (573) |
December 31, 2025 (1) | 309 | 228 | 243 | 3,330 | 849 | 7,134 | 18,006 | 817 | 15,910 |
Pelican | |||||||||
Total Proved Plus | Light and Medium | Primary Heavy | Lake Heavy | Thermal | Mining | Synthetic | Natural | Natural Gas | Barrels of Oil |
Probable | Crude Oil | Crude Oil | Crude Oil | Bitumen | Bitumen(2) | Crude Oil(2) | Gas | Liquids | Equivalent |
(MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (MMbbl) | (Bcf) | (MMbbl) | (MMBOE) | |
December 31, 2024 (1) | 346 | 318 | 360 | 5,190 | - | 8,255 | 27,156 | 1,116 | 20,110 |
Discoveries | - | - | - | - | - | - | - | - | - |
Extensions | 22 | 20 | - | 89 | - | - | 167 | 12 | 171 |
Infill Drilling | 2 | 26 | 3 | 11 | - | - | 325 | 54 | 149 |
Improved Recovery | - | 1 | 4 | - | - | 2 | - | - | 7 |
Acquisitions | 99 | - | - | - | 450 | - | 1,469 | 95 | 888 |
Dispositions | - | - | - | - | - | - | - | - | - |
Economic Factors | (5) | (5) | (2) | - | - | - | (99) | (4) | (32) |
Technical Revisions | (11) | 5 | - | (15) | 449 | (367) | (114) | (14) | 29 |
Production | (26) | (32) | (16) | (100) | (4) | (202) | (930) | (38) | (573) |
December 31, 2025 (1) | 427 | 333 | 349 | 5,175 | 895 | 7,688 | 27,974 | 1,221 | 20,750 |
Information in the reserves data tables may not add due to rounding. BOE values as presented may not calculate due to rounding.
Except as disaggregated in the 'Reserves' section of this MD&A, all references to Synthetic Crude Oil also include Mining Bitumen within the product streams produced by Horizon, AOSP mines, and the Scotford Upgrader in this MD&A.
At December 31, 2025, the Company's total proved crude oil, thermal bitumen, mining bitumen, SCO, and NGLs reserves were 12,909 MMbbl, and total proved plus probable crude oil, thermal bitumen, mining bitumen, SCO, and NGLs reserves were 16,088 MMbbl. Total proved reserves additions and revisions replaced 218% of 2025 production. Additions to total proved reserves resulting from exploration and development activities, acquisitions, dispositions, and future offset additions amounted to 741 MMbbl, and additions to total proved plus probable reserves amounted to 889 MMbbl. Net positive revisions amounted to 173 MMbbl for total proved reserves and 33 MMbbl for total proved plus probable reserves, primarily due to technical revisions.
At December 31, 2025, the total proved natural gas reserves were 18,006 Bcf, and total proved plus probable natural gas reserves were 27,974 Bcf. Total proved reserves additions and revisions replaced 218% of 2025 production. Additions to total proved reserves resulting from exploration and development activities, acquisitions, dispositions, and future offset additions
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CNRL - Canadian Natural Resources Ltd. published this content on March 27, 2026, and is solely responsible for the information contained herein. Distributed via Public Technologies (PUBT), unedited and unaltered, on March 27, 2026 at 16:11 UTC.
