EX-99.2 3 a09302025q3mda.htm EX-99.2
CANADIAN NATURAL RESOURCES LIMITED

MANAGEMENT'S DISCUSSION & ANALYSIS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2025
NOVEMBER 5, 2025

MANAGEMENT'S DISCUSSION AND ANALYSIS
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 Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("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, natural gas liquids ("NGLs"), or synthetic crude oil ("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 the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of conflicts in the Middle East and in Ukraine, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; changes and 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 greenhouse gas emissions including, among other things, financial and other support from various levels of government for climate related initiatives and potential emissions or production caps; 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; 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.

Canadian Natural Resources Limited | 1 | Three and nine months ended September 30, 2025

The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state, and local laws and regulations such as restrictions on production, the imposition of tariffs, embargoes, or export restrictions on the Company's products (including 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. 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. These amendments include substantial financial penalties and, effective June 20, 2025, a private right of action which permits private parties to seek an order from the Competition Tribunal under the deceptive marketing practices provisions. Uncertainty surrounding the interpretation and enforcement of this legislation may expose the Company to increased litigation and financial penalties, the outcome and impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business, reputation, financial condition, and results.
Special Note Regarding Currency, Financial Information and Production
This MD&A should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") for the three and nine months ended September 30, 2025, and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2024. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements for the three and nine months ended September 30, 2025 and this MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").
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, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.
The following discussion and analysis refers primarily to the Company's financial results for the three and nine months ended September 30, 2025 in relation to the comparable periods in 2024 and the second quarter of 2025. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2024, is available on SEDAR+ at www.sedarplus.ca, and on EDGAR at www.sec.gov. Information in such Annual Information Form and 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 November 5, 2025.

Canadian Natural Resources Limited | 2 | Three and nine months ended September 30, 2025

FINANCIAL HIGHLIGHT S

|  | Three Months Ended |  |  | Nine Months Ended
($ millions, except per common share amounts) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Product sales (1) |  | $ | 11,070 |  |  | $ | 9,675 |  |  | $ | 10,401 |  |  |  | $ | 33,457 |  |  | $ | 30,445 |
Crude oil and NGLs |  | $ | 10,468 |  |  | $ | 8,874 |  |  | $ | 9,943 |  |  |  | $ | 31,074 |  |  | $ | 28,703 |
Natural gas |  |  | $ | 399 |  |  | $ | 600 |  |  | $ | 257 |  |  |  | $ | 1,715 |  |  | $ | 1,117 |
Net earnings |  | $ | 600 |  |  | $ | 2,459 |  |  | $ | 2,266 |  |  |  | $ | 5,517 |  |  | $ | 4,968 |
Per common share | – basic |  | $ | 0.29 |  |  | $ | 1.17 |  |  | $ | 1.07 |  |  |  | $ | 2.64 |  |  | $ | 2.33 |
| – diluted |  | $ | 0.29 |  |  | $ | 1.17 |  |  | $ | 1.06 |  |  |  | $ | 2.63 |  |  | $ | 2.31 |
Adjusted net earnings from operations (2) |  | $ | 1,801 |  |  | $ | 1,496 |  |  | $ | 2,071 |  |  |  | $ | 5,733 |  |  | $ | 5,437 |
Per common share | – basic (3) |  | $ | 0.86 |  |  | $ | 0.71 |  |  | $ | 0.98 |  |  |  | $ | 2.74 |  |  | $ | 2.55 |
| – diluted (3) |  | $ | 0.86 |  |  | $ | 0.71 |  |  | $ | 0.97 |  |  |  | $ | 2.73 |  |  | $ | 2.53 |
Cash flows from operating activities |  | $ | 3,940 |  |  | $ | 3,114 |  |  | $ | 3,002 |  |  |  | $ | 11,338 |  |  | $ | 9,954 |
Adjusted funds flow (2) |  | $ | 3,920 |  |  | $ | 3,262 |  |  | $ | 3,921 |  |  |  | $ | 11,712 |  |  | $ | 10,673 |
Per common share | – basic (3) |  | $ | 1.88 |  |  | $ | 1.56 |  |  | $ | 1.85 |  |  |  | $ | 5.59 |  |  | $ | 5.01 |
| – diluted (3) |  | $ | 1.87 |  |  | $ | 1.55 |  |  | $ | 1.84 |  |  |  | $ | 5.57 |  |  | $ | 4.97 |
Cash flows used in investing activities |  | $ | 2,234 |  |  | $ | 1,941 |  |  | $ | 1,274 |  |  |  | $ | 5,487 |  |  | $ | 3,681 |
Net capital expenditures (4) |  | $ | 2,124 |  |  | $ | 1,915 |  |  | $ | 1,349 |  |  |  | $ | 5,342 |  |  | $ | 4,083 |
Abandonment expenditures |  | $ | 189 |  |  | $ | 193 |  |  | $ | 204 |  |  |  | $ | 570 |  |  | $ | 495 |

(1)Further details related to product sales are disclosed in note 15 to the financial statements.
(2)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(4)Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2024. R efer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
SUMMARY OF FINANCIAL HIGHLIGHTS
Consolidated Net Earnings and Adjusted Net Earnings from Operations
N et earnings for the nine months ended September 30, 2025 were $5,517 million compared with $4,968 million for the nine months ended September 30, 2024. Net earnings for the nine months ended September 30, 2025 included non‑operating losses, net of tax, of $216 million compared with non-operating losses of $469 million for the nine months ended September 30, 2024 related to the effects of share-based compensation, risk management activities, fluctuations in foreign e xchange rates, realized foreign exchange on financing activities, the gain from investments, the gain on acquisition, a recoverability charge related to the increase in estimate of the future abandonment costs for the Ninian field and T‑Block assets in the North Sea in the third quarter of 2025, and a recoverability charge related to the notice to withdraw from Block 11B/12B in South Africa in the second quarter of 2024. Excluding these items, adjusted net earnings from operations for the nine months ended September 30, 2025 were $5,733 million compared with $5,437 million for the nine months ended September 30, 2024.
Net earnings for the third quarter of 2025 were $600 million compared with $2,266 million for the third quarter of 2024 and $2,459 million for the second quarter of 2025. Net earnings for the third quarter of 2025 included non-operating losses, net of tax, of $1,201 million compared with non-operating income of $195 million for the third quarter of 2024 and non‑operating income of $963 million for the second quarter of 2025 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on financing activities, the gain on acquisition, and a recoverability charge related to the increase in estimate of the future abandonment costs for the Ninian field and T‑Block assets in the North Sea in the third quarter of 2025. Ex cluding these items, adjusted net earnings from operations for the third quarter of 2025 were $1,801 million compared with $2,071 million for the third quarter of 2024 and $1,496 million for the second quarter of 2025.

Canadian Natural Resources Limited | 3 | Three and nine months ended September 30, 2025

T he increase in net earnings and adjusted net earnings from operati ons for the nine months ended September 30, 2025 from the nine months ended September 30, 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.
T he decrease in net earnings and adjusted net earnings from operati ons for the third quarter of 2025 from the third quarter of 2024 primarily reflected:
▪lower realized SCO pricing in the Oil Sands Mining and Upgrading segment; and
▪lower realized crude oil and NGLs pricing in the North America Exploration and Production segment;
partially offset by:
▪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.
The movements in net earnings and adjusted net earnings from operations for the third quarter of 2025 from the second quarter of 2025 primarily reflected:
▪higher sales volumes in the Oil Sands Mining and Upgrading segment;
▪higher crude oil and NGLs, and natural gas sales volumes in the North America Exploration and Production segment; and
▪higher realized crude oil and NGLs pricing in the North America Exploration and Production segment;
part ially offset by:
▪lower realized natural gas pricing in the North America Exploration and Production segment.
The impacts of depletion, depreciation and amortization, share-based compensation, risk management activities, foreign exchang e loss (gain), gain on acquisition, a nd the gain from investments also contributed to fluctuations in net earnings from the comparable periods. These items are discussed in detail in the relevant sections of this MD&A.
The Company is progressing its abandonment and decommissioning activities in the North Sea, including the tendering and awarding of contracts for the Ninian South Platform. Following a competitive bidding process in 2025, cost estimates have come in higher than originally budgeted. As a result, the Company has reviewed and updated estimates for abandonment and decommissioning costs for its North Sea assets, including the Ninian Central and South Platforms and T‑Block (comprising the Tiffany, Toni, and Thelma fields). In addition, based on current and forecasted economic conditions, including commodity pricing and market egress for T‑Block volumes, the Company has determined that the T-Block assets are no longer economically viable. The Company is assessing alternatives for the potential acceleration of the T‑Block decommissioning plan. As a result, at September 30, 2025, the Company recognized a non-cash charge of $695 million, comprised of additional abandonment costs for the Ninian field of $734 million, net of deferred tax recoveries of $359 million, and an additional charge of $524 million for T‑Block, net of deferred tax recoveries of $204 million, relating to current and forecasted economic conditions. The Company's estimate of its asset retirement obligations, including its long-term abandonment projects in the North Sea and associated tax recoveries, are subject to revision in future periods as abandonment activities progress.
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited | 4 | Three and nine months ended September 30, 2025

Cash Flows from Operating Activities and Adjusted Funds Flow
Cash flows from operating activities for the nine months ended September 30, 2025 were $11,338 million compared with $9,954 million for the nine months ended September 30, 2024. Cash flows from operating activities for the third quarter of 2025 were $3,940 million compared with $3,002 million for the third quarter of 2024 and $3,114 million for the second quarter of 2025. The fluctuations in cash flows from operating activities from the comparable periods 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 the nine months ended September 30, 2025 was $11,712 million compared with $10,673 million for the nine months ended September 30, 2024. Adjusted funds flow for the third quarter of 2025 was $3,920 million compared with $3,921 million for the third quarter of 2024 and $3,262 million for the second quarter of 2025. The fluctuations in adjusted funds flow from the comparable periods were primarily due to the factors noted above related to the fluctuations in cash flows from operating activities, excluding the impact of the net change in non-cash working capital, abandonment expenditures, and movements in other long-term assets, including the unamortized cost of contributions to the Company's employee bonus program, interest on Petroleum Revenue Tax ("PRT") and corporate tax recoveries, and prepaid cost of service tolls.
Production Volumes
Crude oil and NGLs production before royalties for the third quarter of 2025 of 1,175,604 bbl/d increased 15% from 1,021,572 bbl/d for the third quarter of 2024 and increased 15% from 1,019,149 bbl/d for the second quarter of 2025. Natural gas production before royalties for the third quarter of 2025 of 2,668 MMcf/d increased 30% from 2,049 MMcf/d for the third quarter of 2024 and increased 11% from 2,407 MMcf/d for the second quarter of 2025. Total production before royalties for the third quarter of 2025 of 1,620,261 BOE/d increased 19% from 1,363,086 BOE/d for the third quarter of 2024 and increased 14% from 1,420,358 BOE/d for the second quarter of 2025. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production, before royalties" section of this MD&A.
Product Prices
In the Company's Exploration and Production segments, realized crude oil and NGLs prices averag ed $72.57 per bbl for the third quarter of 2025, a decrease of 8% from $79.15 per bbl for the third quarter of 2024 and an increase of 4% from $69.58 per bbl for the second quarter of 2025. The realized natural gas pri ce increased 19% to average $1.49 per Mcf for the third quarter of 2025 from $1.25 per Mcf for the third quarter of 2024 and decreased 42% from $2.58 per Mcf for the second quarter of 2025. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales pri ce decreased 13% to average $87.85 per bbl for the third quarter of 2025 from $100.93 per bbl for the third quarter of 2024 and was comparable with $87.22 per bbl for the second quarter of 2025. 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", "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, crude oil and NGLs production expense(1) averag ed $13.18 per bbl for the third quarter of 2025, a decrease of 10% from $14.65 per bbl for the third quarter of 2024 and a decrease of 6% from $14.03 per bbl for the second quarter of 2025. Natural gas production expense(1) averaged $1.16 per Mcf for the third quarter of 2025, a decrease of 8% from $1.26 per Mcf for the third quarter of 2024 and an increase of 5% from $1.11 per Mcf for the second quarter of 2025. In the Oil Sands Mining and Upgrading segment, production expense(1) averaged $21.29 per bbl for the third quarter of 2025, comparable with $20.67 per bbl for the third quarter of 2024 and a decrease of 20% from $26.53 per bbl for the second quarter of 2025. 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 thi s MD&A.
(1)Calculated as respective production expense divided by respective sales volumes.

Canadian Natural Resources Limited | 5 | Three and nine months ended September 30, 2025

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) |  | Sep 30 2025 |  | Jun 30 2025 |  | Mar 31 2025 |  | Dec 31 2024
Product sales (1) |  | $ | 11,070 |  |  | $ | 9,675 |  |  | $ | 12,712 |  |  | $ | 11,064 |
Crude oil and NGLs |  | $ | 10,468 |  |  | $ | 8,874 |  |  | $ | 11,732 |  |  | $ | 10,381 |
Natural gas |  | $ | 399 |  |  | $ | 600 |  |  | $ | 716 |  |  | $ | 451 |
Net earnings |  | $ | 600 |  |  | $ | 2,459 |  |  | $ | 2,458 |  |  | $ | 1,138 |
Net earnings per common share |  |  |  |  |  |  |  |
– basic |  | $ | 0.29 |  |  | $ | 1.17 |  |  | $ | 1.17 |  |  | $ | 0.54 |
– diluted |  | $ | 0.29 |  |  | $ | 1.17 |  |  | $ | 1.17 |  |  | $ | 0.54 |
($ millions, except per common share amounts) |  | Sep 30 2024 |  | Jun 30 2024 |  | Mar 31 2024 |  | Dec 31 2023
Product sales (1) |  | $ | 10,401 |  |  | $ | 10,622 |  |  | $ | 9,422 |  |  | $ | 10,679 |
Crude oil and NGLs |  | $ | 9,943 |  |  | $ | 10,084 |  |  | $ | 8,676 |  |  | $ | 9,829 |
Natural gas |  | $ | 257 |  |  | $ | 331 |  |  | $ | 529 |  |  | $ | 603 |
Net earnings |  | $ | 2,266 |  |  | $ | 1,715 |  |  | $ | 987 |  |  | $ | 2,627 |
Net earnings per common share (2) |  |  |  |  |  |  |  |
– basic |  | $ | 1.07 |  |  | $ | 0.80 |  |  | $ | 0.46 |  |  | $ | 1.22 |
– diluted |  | $ | 1.06 |  |  | $ | 0.80 |  |  | $ | 0.46 |  |  | $ | 1.21 |

(1)Further details related to product s ales for the three months ended September 30, 2025 and 2024 are disclosed in note 15 to the financial statements.
(2)Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are disclosed in the Advisory section of this MD&A.
Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to:
▪Crude oil pricing – Fluctuations in global supply/demand including crude oil production levels from OPEC+ and its impact on world supply, the impact of geopolitical and market uncertainties (including those due to the conflicts in the Middle East and in Ukraine, and 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 the second quarter of 2024, the impact of the Western Canadian Select ("WCS") Heavy Differential from the West Texas Intermediate reference location at Cushing, Oklahoma ("WTI") in North America, and the impact of the differential between WTI and Dated Brent ("Brent") benchmark pricing in the International segments.
▪Natural gas pricing – Fluctuations in both the demand for natural gas and inventory storage levels, the impact of third‑party pipeline maintenance and outages, the impact of geopolitical and market uncertainties, the impact of seasonal conditions, and the impact of shale gas production in the US.
▪Crude oil and NGLs sales volumes – Fluctuations in production from Kirby and Jackfish, fluctuations in production due to the cyclic nature of Primrose, fluctuations in the Company's drilling program in the North America Exploration and Production segment, natural field decline rates, the impact of turnarounds in the Oil Sands Mining and Upgrading segment, the impact and timing of acquisition s, including the acquisition of working interests in AOSP and Duvernay assets in the fourth quarter of 2024, the acquisition of assets in the Palliser Block in the second quarter of 2025, and the acquisition of assets in the Grande Prairie area in the third quarter of 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 floating production storage and offloading vessel ("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 the fourth quarter of 2024, the acquisition of assets in the Palliser Block in the second quarter of 2025, and the acquisition of assets in the Grande Prairie area in the third quarter of 2025, n atural field decline rates, the impact of seasonal conditions, and wildfires in the North America Exploration and Production segment.

Canadian Natural Resources Limited | 6 | Three and nine months ended September 30, 2025

▪Production expense – Fluctuations primarily due to the impacts of the demand and cost f or services, fluctuations in product mix and production volumes, seasonal conditions, carbon tax, fluctuating energy costs, inflationary cost pressure s, 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 segmen t, a recoverability charge at September 30, 2025 relating to an increase in estimate of future abandonment costs for the Ninian field and T‑Block assets in the North Sea, recoverability charges at D ecember 31, 2024 and December 31, 2023 relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea, and a recoverability charge at June 30, 2024 relating to the notice to withdraw from Block 11B/12B in South Africa.
▪Share-based compensation – Fluctuations due to the measurement of fair market value of the Company's share-based compensation liability.
▪Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company's risk management activities.
▪Interest expense – Fluctuations due to changing long-term debt levels, 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.
BUSINESS ENVIRONMENT
Global crude oil benchmark pricing remained relatively stable through the third quarter of 2025, though continued to experience downward pressure from weaker demand outlooks amid ongoing tariff and trade uncertainty, and the impact of the unwinding of OPEC+ supply cuts. Additionally, near record non-OPEC+ production during the quarter reduced the impact of geopolitical supply uncertainty. Natural gas benchmark pricing declined in the third quarter of 2025, driven by increasing inventory levels primarily as a result of weaker US demand. In Canada, AECO benchmark pricing declined due to strong production in the Western Canadian Sedimentary Basin ("WCSB"), combined with third-party pipeline outages reducing export egress, and lower processing capacity than expected at LNG Canada.
In the first quarter of 2025, the US government announced tariffs on certain Canadian goods with countermeasures subsequently announced by the Canadian government. These trade measures have created market volatility which may continue to affect pricing received for the Company's products, increase the cost or reduce the availability of products in the Company's supply chain, and introduce additional foreign currency volatility. As of the date of this MD&A, the duration and impact of these trade actions remains uncertain, and any tariffs imposed or announced continue to evolve. The Company will continue to assess the impacts of any proposed or implemented tariffs on its business, financial condition, and results.
Liquidity
As at September 30, 2025, the Company had undrawn revolving bank credit facili ties of $4,201 million. Including cash and cash equivalents, the Company had approximately $4,314 million in liquidity(1). The Company also has certa in other dedicated credit facilities supporting letters of credit. The Company remains committed to maintaining a strong balance sheet, adequate available liquidity, and a flexible capital structure. Refer to the "Liquidity and Capital Resources" section of this MD&A for further details.
(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited | 7 | Three and nine months ended September 30, 2025

Benchmark Commodity Prices

| Three Months Ended |  |  | Nine Months Ended
(Average for the period) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
WTI benchmark price (US$/bbl) |  | $ | 64.95 |  |  | $ | 63.71 |  |  | $ | 75.16 |  |  |  | $ | 66.67 |  |  | $ | 77.55 |
Dated Brent benchmark price (US$/bbl) |  | $ | 69.08 |  |  | $ | 67.78 |  |  | $ | 80.25 |  |  |  | $ | 70.82 |  |  | $ | 82.78 |
WCS Heavy Differential from WTI (US$/bbl) |  | $ | 10.36 |  |  | $ | 10.19 |  |  | $ | 13.51 |  |  |  | $ | 11.07 |  |  | $ | 15.46 |
SCO price (US$/bbl) |  | $ | 66.26 |  |  | $ | 64.69 |  |  | $ | 76.51 |  |  |  | $ | 66.66 |  |  | $ | 76.42 |
Condensate benchmark price (US$/bbl) |  | $ | 63.12 |  |  | $ | 63.42 |  |  | $ | 71.24 |  |  |  | $ | 65.45 |  |  | $ | 73.71 |
NYMEX benchmark price (US$/MMBtu) |  | $ | 3.07 |  |  | $ | 3.44 |  |  | $ | 2.16 |  |  |  | $ | 3.39 |  |  | $ | 2.10 |
AECO benchmark price (C$/GJ) |  | $ | 0.94 |  |  | $ | 1.97 |  |  | $ | 0.77 |  |  |  | $ | 1.61 |  |  | $ | 1.35 |
US/Canadian dollar average exchange rate (US$) |  | $ | 0.7262 |  |  | $ | 0.7225 |  |  | $ | 0.7332 |  |  |  | $ | 0.7150 |  |  | $ | 0.7351 |

Substantially all of the Company's production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based on WTI and Brent indices. Canadian natural gas pricing is primarily based on AECO reference pricing, which is derived from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at Henry Hub. The Company’s realized prices are directly impacted by fluctuations in foreign exchange rates resulting in product revenues being impacted by changes in Canadian dollar sales prices relative to the US dollar benchmark prices.
Crude oil sales contracts in North America are typically based on WTI benchmark pricing. WTI averaged US$66.67 per bbl for the nine months ended September 30, 2025, a decrease of 14% from US$77.55 per bbl for the nine months ended September 30, 2024. WTI averaged US$64.95 per bbl for the third quarter of 2025, a decrease of 14% from US$75.16 per bbl for the third quarter of 2024 and comparable with US$63.71 per bbl for the second quarter of 2025.
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$70.82 p er bbl for the nine months ended September 30, 2025, a decrease of 14% from US$82.78 per bbl for the nine months ended September 30, 2024. Brent averaged U S$69.08 p er bbl for the third quarter of 2025, a decrease of 14% from US$80.25 per bbl for the third quarter of 2024 and comparable with US$67.78 per bbl for the second quarter of 2025.
The decrease in WTI and Brent benchmark pricing for the three and nine months ended September 30, 2025 from the comparable periods in 2024 reflected weaker global demand outlooks amid ongoing tariff and trade uncertainty, combined with increased OPEC+ supply and near record non-OPEC+ production.
The WCS Heavy Differential averaged U S$11.07 per bbl for the nine months ended September 30, 2025, compared with US$15.46 per bbl for the nine months ended September 30, 2024. The WCS Heavy Differential averaged US$10.36 per bbl for the third quarter of 2025, compared with US$13.51 per bbl for the third quarter of 2024 and US$10.19 per bbl f or the second quarter of 2025. The narrowing of the WCS Heavy Differential for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflected the start-up of the TMX pipeline in the second quarter of 2024, and strong US Gulf Coast heavy oil pricing. The narrowing of the WCS Heavy Differential for the third quarter of 2025 from the third quarter of 2024 primarily reflected higher refinery utilization further supported by strong US Gulf Coast heavy oil pricing.
The SCO price averaged US$66.66 per bbl for the nine months ended September 30, 2025, a decrease of 13% from US$76.42 per bbl for the nine months ended September 30, 2024. The SCO price averaged US$66.26 per bbl for the third quarter of 2025, a decrease of 13% from US$76.51 per bbl for the third quarter of 2024 and comparable wit h US$64.69 per bbl for the second quarter of 2025. The decrease in SCO pricing for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected weaker WTI benchmark pricing.
NYMEX benchmark pricing averaged U S$3.39 per MMBtu for the nine months ended September 30, 2025, an increase of 61% from US$2.10 per MMBtu for the nine months ended September 30, 2024. NYMEX benchmark pricing averaged US$3.07 per MMBtu for the third quarter of 2025, an increase of 42% from US$2.16 per MMBtu for t he third quarter of 2024 a nd a decrease of 11% from US$3.44 per M MBtu for the second quarter of 2025. The increase in NYMEX natural gas prices for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected lower US inventory levels in the first half of 2025, combined with higher LNG exports out of the US Gulf Coast. The decrease in NYMEX natural gas pricing for the third quarter of 2025 from the second quarter of 2025 primarily reflected increased inventory levels from strong US production and lower electricity demand, partially offset by increased LNG exports out of the US Gulf Coast.

Canadian Natural Resources Limited | 8 | Three and nine months ended September 30, 2025

AECO benchmark pricing averaged $1.61 per GJ for the nine months ended September 30, 2025, an increase of 19% from $1.35 per GJ for the nine months ended September 30, 2024. AECO benchmark pricing average d $0.94 pe r GJ for the third quarter of 2025, an increase o f 22% from $0.77 per GJ for the third quarter of 2024 and a decrease of 52% from $1.97 per GJ for the second quarter of 2025. The increase in AECO natural gas prices for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected higher NYMEX benchmark pricing, combined with increased exports out of the WCSB. The decrease in AECO natural gas pricing for the third quarter of 2025 from the second quarter of 2025 reflected increased inventory levels from strong production in the WCSB, lower processing capacity than expected at LNG Canada, and third-party pipeline outages reducing export egress.
DAILY PRODUCTION, before royalties

| Three Months Ended | Nine Months Ended
| Sep 30 2025 | Jun 30 2025 | Sep 30 2024 | Sep 30 2025 | Sep 30 2024
Crude oil and NGLs (bbl/d) |  |  |  |  |
North America – Exploration and Production | 584,625 |  | 545,811 |  | 499,772 |  | 563,977 |  | 501,674 |
North America – Oil Sands Mining and Upgrading (1) | 581,136 |  | 463,808 |  | 497,656 |  | 546,635 |  | 451,298 |
International – Exploration and Production |  |  |  |  |
North Sea | 7,045 |  | 7,761 |  | 10,958 |  | 8,755 |  | 11,560 |
Offshore Africa | 2,798 |  | 1,769 |  | 13,186 |  | 3,492 |  | 12,733 |
Total International (2) | 9,843 |  | 9,530 |  | 24,144 |  | 12,247 |  | 24,293 |
Total Crude oil and NGLs | 1,175,604 |  | 1,019,149 |  | 1,021,572 |  | 1,122,859 |  | 977,265 |
Natural gas (MMcf/d) (3) |  |  |  |  |
North America | 2,658 |  | 2,398 |  | 2,039 |  | 2,498 |  | 2,091 |
International |  |  |  |  |
North Sea | 2 |  | 3 |  | 1 |  | 3 |  | 1 |
Offshore Africa | 8 |  | 6 |  | 9 |  | 9 |  | 10 |
Total International | 10 |  | 9 |  | 10 |  | 12 |  | 11 |
Total Natural gas | 2,668 |  | 2,407 |  | 2,049 |  | 2,510 |  | 2,102 |
Total Barrels of oil equivalent (BOE/d) | 1,620,261 |  | 1,420,358 |  | 1,363,086 |  | 1,541,127 |  | 1,327,593 |
Product mix |  |  |  |  |
Light and medium crude oil and NGLs | 12% | 11% | 9% | 11% | 10%
Pelican Lake heavy crude oil | 3% | 3% | 3% | 3% | 3%
Primary heavy crude oil | 5% | 6% | 6% | 6% | 6%
Bitumen (thermal oil) | 17% | 19% | 20% | 18% | 20%
Synthetic crude oil (1) | 36% | 33% | 37% | 35% | 34%
Natural gas | 27% | 28% | 25% | 27% | 27%
Percentage of product sales (1) (4) (5) |  |  |  |  |
Crude oil and NGLs | 96% | 93% | 97% | 94% | 96%
Natural gas | 4% | 7% | 3% | 6% | 4%

(1)SCO production before royalties excludes SCO consumed internally as diesel.
(2)"International" includes North Sea and Offshore Africa Exploration and Production segments in all instances used in this MD&A.
(3)Natural gas production volumes approximate sales volumes.
(4)Net of blending and feedstock costs and excluding risk management activities.
(5)Excluding Midstream and Refining revenue.

Canadian Natural Resources Limited | 9 | Three and nine months ended September 30, 2025

DAILY PRODUCTION, net of royalties

| Three Months Ended | Nine Months Ended
| Sep 30 2025 | Jun 30 2025 | Sep 30 2024 | Sep 30 2025 | Sep 30 2024
Crude oil and NGLs (bbl/d) |  |  |  |  |
North America – Exploration and Production | 479,660 |  | 472,329 |  | 399,397 |  | 469,188 |  | 402,381 |
North America – Oil Sands Mining and Upgrading (1) | 473,188 |  | 397,052 |  | 408,120 |  | 450,130 |  | 370,547 |
International – Exploration and Production |  |  |  |  |
North Sea | 7,017 |  | 7,746 |  | 10,925 |  | 8,735 |  | 11,531 |
Offshore Africa | 2,669 |  | 1,692 |  | 12,496 |  | 3,338 |  | 12,104 |
Total International | 9,686 |  | 9,438 |  | 23,421 |  | 12,073 |  | 23,635 |
Total Crude oil and NGLs | 962,534 |  | 878,819 |  | 830,938 |  | 931,391 |  | 796,563 |
Natural gas (MMcf/d) |  |  |  |  |
North America | 2,615 |  | 2,325 |  | 2,016 |  | 2,430 |  | 2,047 |
International |  |  |  |  |
North Sea | 2 |  | 3 |  | 1 |  | 3 |  | 1 |
Offshore Africa | 8 |  | 6 |  | 9 |  | 8 |  | 10 |
Total International | 10 |  | 9 |  | 10 |  | 11 |  | 11 |
Total Natural gas | 2,625 |  | 2,334 |  | 2,026 |  | 2,441 |  | 2,058 |
Total Barrels of oil equivalent (BOE/d) | 1,399,968 |  | 1,267,787 |  | 1,168,599 |  | 1,338,293 |  | 1,139,622 |

(1)SCO production net of royalties excludes SCO consumed internally as diesel.
The Company's business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO, and natural gas.
Crude oil and NGLs production before royalties for the nine months ended September 30, 2025 averaged 1,122,859 bbl/d, an increase of 15% from 977,265 bbl/d for the nine months ended September 30, 2024. Crude oil and NGLs production before royalties for the third quarter of 2025 averaged 1,175,604 bbl/d, an increase of 15% from 1,021,572 bbl/d for the third quarter of 2024 and an increase of 15% from 1,019,149 bbl/d for the second quarter of 2025. The increase in crude oil and NGLs production before royalties for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition completed in December 2024, strong utilization in the Oil Sands Mining and Upgrading segment, and strong drilling results in the North America Exploration and Production segment. The increase in crude oil and NGLs production before royalties for the third quarter of 2025 from the second quarter of 2025 primarily reflected strong utilization in the Oil Sands Mining and Upgrading segment following the completion of the planned turnaround at the non-operated Scotford Upgrader ("Scotford") in the second quarter, combined with the acquisitions completed in the second and third quarters of 2025 in the North America Exploration and Production segment.
Annual crude oil and NGLs production for 2025 is now targeted to average between 1,137,000 bbl/d and 1,151,000 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 for the nine months ended September 30, 2025 average d 2,510 MMcf/d, an increase of 19% from 2,102 MMcf/d for the nine months ended September 30, 2024. Natural gas production before royalties for the third quarter of 2025 averaged 2,668 MMcf/d, an increase of 30% from 2,049 MMcf/d for the third quarter of 2024 and an increase of 11% from 2,407 MMcf/d for the second quarter of 2025. The increase in natural gas produ ction before royalties for the three and nine months ended September 30, 2025 from the comparable periods primarily reflected the acquisitions completed in December 2024 and during the second and third quarters of 2025, combined with strong drilling results in the Company's liquids-rich natural gas assets, partially offset by natural field declines.
Annual natural gas production for 2025 is now targeted to average between 2,535 MMcf/d and 2,575 MMcf/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward‑looking statements.

Canadian Natural Resources Limited | 10 | Three and nine months ended September 30, 2025

North America – Exploration and Production
North America crude oil and NGLs production before royalties for the nine months ended September 30, 2025 averaged 563,977 bbl/d, an increase of 12% from 501,674 bbl/d for the nine months ended September 30, 2024. North America crude oil and NGLs production before royalties for the third quarter of 2025 of 584,625 bbl/d increased 17% from 499,772 bbl/d for the third quarter of 2024 and increased 7% from 545,811 bbl/d for the second quarter of 2025. The increase in North America crude oil and NGLs production before royalties for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition completed in December 2024, and strong drilling results from heavy oil multilaterals, liquids-rich natural gas, and light oil, partially offset by natural field declines. The increase in North America crude oil and NGLs production for the third quarter of 2025 from the second quarter of 2025 primarily reflected the acquisitions completed in the second and third quarters of 2025, partially offset by natural field declines.
The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 274,752 bbl/d for the third quarter of 2025, comparable with 271,551 bbl/d for the third quarter of 2024 and 274,789 bbl/d for the second quarter of 2025.
Pelican Lake heavy crude oil production before royalties for the third quarter of 2025 averaged 42,070 bbl/d, a decrease of 7% from 45,101 bbl/d for the third quarter of 2024 reflecting Pelican Lake's long life low decline production and planned maintenance activities. Pelican Lake heavy crude oil production before royalties for the third quarter of 2025 was comparable with 43,078 bbl/d for the second quarter of 2025.
North America natural gas production before royalties for the nine months ended September 30, 2025 averaged 2,498 MMcf/d, an increase of 19% from 2,091 MMcf/d for the nine months ended September 30, 2024. Natural gas production before royalties averaged 2,658 MMcf/d for the third quarter of 2025, an increase of 30% from 2,039 MMcf/d for the third quarter of 2024 and an increase of 11% from 2,398 MMcf/d for the second quarter of 2025. The increase in natural gas production before royalties for the three and nine months ended September 30, 2025 from the comparable periods primarily reflected the acquisitions completed in December 2024 and during the second and third quarters of 2025, and strong drilling results in the Company's liquids-rich natural gas assets, partially offset by natural field declines.
North America – Oil Sands Mining and Upgrading
SCO production before royalties for the nine months ended September 30, 2025 ave raged 546,635 bbl/d, an increase of 21% from 451,298 bbl/d for the nine months ended September 30, 2024. SCO production before royalties for the third quarter of 2025 averaged 581,136 bbl/d, an increase of 17% from 497,656 bbl/d for the third quarter of 2024 and an increase of 25% from 463,808 bbl/d for the second quarter of 2025. The increase in SCO production before royalties for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition completed in December 2024, combined with high utilization. The increase in SCO production for the third quarter of 2025 from the second quarter of 2025 primarily reflected strong utilization following the completion of the planned turnaround at Scotford in the second quarter.
International – Exploration and Production
In ternational crude oil and NGLs production before royalties for the nine months ended September 30, 2025 averaged 12,247 bbl/d, a decrease of 50% from 24,293 bbl/d for the nine months ended September 30, 2024. International crude oil and NGLs production before royalties for the third quarter of 2025 averaged 9,843 bbl/d, a decrease of 59% from 24,144 bbl/d for the third quarter of 2024 and comparable with 9,530 bbl/d for the second quarter of 2025. T he decrease in International crude oil and NGLs production before royalties for the three and nine months ended September 30, 2025 from the comparable periods in 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.

Canadian Natural Resources Limited | 11 | Three and nine months ended September 30, 2025

OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION

| Three Months Ended |  |  | Nine Months Ended
|  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Crude oil and NGLs ($/bbl) (1) |  |  |  |  |  |  |  |  |  |  |
Realized price (2) |  | $ | 72.57 |  |  | $ | 69.58 |  |  | $ | 79.15 |  |  |  | $ | 74.06 |  |  | $ | 78.67 |
Transportation (3) |  | 6.93 |  |  | 7.65 |  |  | 5.26 |  |  |  | 6.99 |  |  | 5.30 |
Realized price, net of transportation (2) |  | 65.64 |  |  | 61.93 |  |  | 73.89 |  |  |  | 67.07 |  |  | 73.37 |
Royalties (4) |  | 13.10 |  |  | 9.20 |  |  | 15.05 |  |  |  | 12.26 |  |  | 14.88 |
Production expense (5) |  | 13.18 |  |  | 14.03 |  |  | 14.65 |  |  |  | 14.32 |  |  | 15.28 |
Netback (2) |  | $ | 39.36 |  |  | $ | 38.70 |  |  | $ | 44.19 |  |  |  | $ | 40.49 |  |  | $ | 43.21 |
Natural gas ($/Mcf) (1) |  |  |  |  |  |  |  |  |  |  |
Realized price (6) |  | $ | 1.49 |  |  | $ | 2.58 |  |  | $ | 1.25 |  |  |  | $ | 2.37 |  |  | $ | 1.80 |
Transportation (3) |  | 0.57 |  |  | 0.59 |  |  | 0.63 |  |  |  | 0.60 |  |  | 0.62 |
Realized price, net of transportation |  | 0.92 |  |  | 1.99 |  |  | 0.62 |  |  |  | 1.77 |  |  | 1.18 |
Royalties (4) |  | 0.02 |  |  | 0.08 |  |  | 0.02 |  |  |  | 0.07 |  |  | 0.05 |
Production expense (5) |  | 1.16 |  |  | 1.11 |  |  | 1.26 |  |  |  | 1.16 |  |  | 1.26 |
Netback (7) |  | $ | (0.26) |  |  | $ | 0.80 |  |  | $ | (0.66) |  |  |  | $ | 0.54 |  |  | $ | (0.13) |
Barrels of oil equivalent ($/BOE) (1) |  |  |  |  |  |  |  |  |  |  |
Realized price (2) |  | $ | 45.31 |  |  | $ | 47.17 |  |  | $ | 50.36 |  |  |  | $ | 49.09 |  |  | $ | 51.29 |
Transportation (3) |  | 5.38 |  |  | 5.94 |  |  | 4.67 |  |  |  | 5.54 |  |  | 4.70 |
Realized price, net of transportation (2) |  | 39.93 |  |  | 41.23 |  |  | 45.69 |  |  |  | 43.55 |  |  | 46.59 |
Royalties (4) |  | 7.53 |  |  | 5.58 |  |  | 9.05 |  |  |  | 7.31 |  |  | 8.99 |
Production expense (5) |  | 10.50 |  |  | 10.95 |  |  | 11.81 |  |  |  | 11.22 |  |  | 12.16 |
Netback (2) |  | $ | 21.90 |  |  | $ | 24.70 |  |  | $ | 24.83 |  |  |  | $ | 25.02 |  |  | $ | 25.44 |

(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Calculated as transportation expense divided by respective sales volumes.
(4)Calculated as royalties divided by respective sales volumes.
(5)Calculated as production expense divided by respective sales volumes.
(6)Calculated as natural gas sales divided by natural gas sales volumes.
(7)Natural gas netbacks exclude NGLs netbacks derived from the Company's liquids-rich natural gas plays.

Canadian Natural Resources Limited | 12 | Three and nine months ended September 30, 2025

REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION

| Three Months Ended |  |  | Nine Months Ended
|  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Crude oil and NGLs ($/bbl) (1) |  |  |  |  |  |  |  |  |  |  |
North America (2) |  | $ | 72.35 |  |  | $ | 69.30 |  |  | $ | 77.29 |  |  |  | $ | 73.40 |  |  | $ | 77.06 |
International average (3) |  | $ | 94.08 |  |  | $ | 91.00 |  |  | $ | 109.41 |  |  |  | $ | 102.18 |  |  | $ | 112.14 |
North Sea (3) |  | $ | 90.19 |  |  | $ | 90.63 |  |  | $ | 112.54 |  |  |  | $ | 100.76 |  |  | $ | 113.90 |
Offshore Africa (3) |  | $ | 99.90 |  |  | $ | 95.92 |  |  | $ | 108.04 |  |  |  | $ | 104.83 |  |  | $ | 110.45 |
Crude oil and NGLs average (2) |  | $ | 72.57 |  |  | $ | 69.58 |  |  | $ | 79.15 |  |  |  | $ | 74.06 |  |  | $ | 78.67 |
Natural gas ($/Mcf) (1) (3) |  |  |  |  |  |  |  |  |  |  |
North America |  | $ | 1.45 |  |  | $ | 2.54 |  |  | $ | 1.19 |  |  |  | $ | 2.32 |  |  | $ | 1.75 |
International average |  | $ | 11.22 |  |  | $ | 11.71 |  |  | $ | 12.67 |  |  |  | $ | 12.76 |  |  | $ | 12.22 |
North Sea |  | $ | 8.57 |  |  | $ | 10.00 |  |  | $ | 11.28 |  |  |  | $ | 12.70 |  |  | $ | 10.79 |
Offshore Africa |  | $ | 11.87 |  |  | $ | 12.47 |  |  | $ | 12.87 |  |  |  | $ | 12.77 |  |  | $ | 12.43 |
Natural gas average |  | $ | 1.49 |  |  | $ | 2.58 |  |  | $ | 1.25 |  |  |  | $ | 2.37 |  |  | $ | 1.80 |
Average ($/BOE) (1) (2) |  | $ | 45.31 |  |  | $ | 47.17 |  |  | $ | 50.36 |  |  |  | $ | 49.09 |  |  | $ | 51.29 |

(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Calculated as crude oil and NGLs sales, and natural gas sales divided by respective sales volumes.
North America
North America realized crude oil and NGLs pric es decreased 5% to average $73.40 per bbl for the nine months ended September 30, 2025 from $77.06 per bbl for the nine months ended September 30, 2024. North America realized crude oil and NGLs prices averaged $72.35 per bbl for the third quarter of 2025, a decrease of 6% from $77.29 per bbl for the third quarter of 2024 and an increase of 4% from $69.30 per bbl for the second quarter of 2025. Th e decrease in N orth America realized crude oil and NGLs prices per bbl for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primari ly reflected lower WTI benchmark pricing, partially offset by a narrowing of the WCS Heavy Differential. The increase in North America realized crude oil and NGLs prices per bbl for the third quarter of 2025 from the second quarter of 2025 reflected prevailing benchmark pricing, and product sales mix. Realized crude oil and NGLs pricing is also directly impacted by fluctuations in foreign exchange rates as sales prices are primarily denominated with reference to US dollar benchmarks. The Company continues to focus on its crude oil blending marketing strategy and in the third quarter of 2025 contributed approximately 228,000 bbl/d of heavy crude oil blends to the WCS stream.
North America realized natural gas pric es increased 33% to average $2.32 per Mcf for the nine months ended September 30, 2025 from $1.75 per Mcf for the nine months ended September 30, 2024. North America realized natural gas prices increased 22% to average $1.45 per Mcf for the third quarter of 2025 from $1.19 per Mcf for the third quarter of 2024 and decreased 43% from $2.54 per Mcf for the second quarter of 2025. The increase in North America realized natural gas prices per Mcf for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected higher benchmark pricing. The decrease for the third quarter of 2025 from the second quarter of 2025 reflected lower benchmark and export pricing.

Canadian Natural Resources Limited | 13 | Three and nine months ended September 30, 2025

Comparisons of the prices received in North America Exploration and Production by product type were as follows:

| Three Months Ended
(Quarterly average) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024
Wellhead Price (1) |  |  |  |  |  |
Light and medium crude oil and NGLs ($/bbl) |  | $ | 66.29 |  |  | $ | 63.96 |  |  | $ | 67.58 |
Pelican Lake heavy crude oil ($/bbl) |  | $ | 75.94 |  |  | $ | 73.94 |  |  | $ | 84.02 |
Primary heavy crude oil ($/bbl) |  | $ | 75.55 |  |  | $ | 72.88 |  |  | $ | 83.56 |
Bitumen (thermal oil) ($/bbl) |  | $ | 74.83 |  |  | $ | 70.13 |  |  | $ | 78.26 |
Natural gas ($/Mcf) |  | $ | 1.45 |  |  | $ | 2.54 |  |  | $ | 1.19 |

(1)Amounts expressed on a per unit basis are based on sales volumes of the respective product type.
International
International realized crude oil an d NGLs prices decreased 9% to average $102.18 per bbl for the nine months ended September 30, 2025 from $112.14 per bbl for the nine months ended September 30, 2024. International realized crude oil and NGLs prices decreased 14% to average $94.08 per bbl for the third quarter of 2025 from $109.41 per bbl for the third quarter of 2024 and increased 3% from $91.00 per bbl for the second quarter of 2025. Realized crude oil and NGLs prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and tim ing of liftings from each field, prevailing Brent benchmark prices and foreign exchange rates at the time of lifting.
ROYALTIES – EXPLORATION AND PRODUCTION

| Three Months Ended |  |  | Nine Months Ended
|  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Crude oil and NGLs ($/bbl) (1) |  |  |  |  |  |  |  |  |  |  |
North America |  | $ | 13.21 |  |  | $ | 9.31 |  |  | $ | 15.72 |  |  |  | $ | 12.51 |  |  | $ | 15.46 |
International average |  | $ | 2.05 |  |  | $ | 0.45 |  |  | $ | 4.02 |  |  |  | $ | 1.71 |  |  | $ | 2.96 |
North Sea |  | $ | 0.35 |  |  | $ | 0.17 |  |  | $ | 0.33 |  |  |  | $ | 0.17 |  |  | $ | 0.27 |
Offshore Africa |  | $ | 4.60 |  |  | $ | 4.19 |  |  | $ | 5.65 |  |  |  | $ | 4.59 |  |  | $ | 5.56 |
Crude oil and NGLs average |  | $ | 13.10 |  |  | $ | 9.20 |  |  | $ | 15.05 |  |  |  | $ | 12.26 |  |  | $ | 14.88 |
Natural gas ($/Mcf) (1) |  |  |  |  |  |  |  |  |  |  |
North America |  | $ | 0.02 |  |  | $ | 0.08 |  |  | $ | 0.01 |  |  |  | $ | 0.07 |  |  | $ | 0.04 |
Offshore Africa |  | $ | 0.55 |  |  | $ | 0.57 |  |  | $ | 0.59 |  |  |  | $ | 0.59 |  |  | $ | 0.57 |
Natural gas average |  | $ | 0.02 |  |  | $ | 0.08 |  |  | $ | 0.02 |  |  |  | $ | 0.07 |  |  | $ | 0.05 |
Average ($/BOE) (1) |  | $ | 7.53 |  |  | $ | 5.58 |  |  | $ | 9.05 |  |  |  | $ | 7.31 |  |  | $ | 8.99 |

(1)Calculated as royalties divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
North America crude oil and NGLs and natural gas royalties for the three and nine months ended September 30, 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 approx imately 17% of product sales for the nine months ended September 30, 2025 compared with 20% of product sales for the nine months ended September 30, 2024. Crude oil and NGLs royalty rates averaged approximately 18% of product sales for the third quarter of 2025 compared with 20% for the third quarter of 2024 and 13% for the second quarter of 2025. The decrease in royalty rates for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected prevailing benchmark pricing and the impact of sliding scale royalty rates. The increase in royalty rates for third quarter of 2025 from the second quarter of 2025 primarily reflected higher bitumen pricing and the impact of sliding scale royalty rates.
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited | 14 | Three and nine months ended September 30, 2025

Natural gas royalty rates averaged approximate ly 3% of product sales for the nine months ended September 30, 2025 compared with 2% of product sales for the nine months ended September 30, 2024. Natural gas royalty rates averaged approximately 2% of product sales for the third quarter of 2025 compared with 1% for the third quarter of 2024 and 3% for the second quarter of 2025. The fluctuations in royalty rates for the three and nine months ended September 30, 2025 from the comparable periods primarily reflected 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 approximat ely 4% for the nine months ended September 30, 2025 compared with 5% of product sales for the nine months ended September 30, 2024. Royalty rates as a percentage of product sales averaged approximately 5% for the third quarter of 2025 compared with 5% of product sales for the third quarter of 2024 and 5% for the second quarter of 2025. 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

| Three Months Ended |  |  | Nine Months Ended
|  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Crude oil and NGLs ($/bbl) (1) |  |  |  |  |  |  |  |  |  |  |
North America |  | $ | 11.97 |  |  | $ | 11.89 |  |  | $ | 12.36 |  |  |  | $ | 12.17 |  |  | $ | 13.17 |
International average |  | $ | 134.12 |  |  | $ | 175.70 |  |  | $ | 52.04 |  |  |  | $ | 106.02 |  |  | $ | 59.04 |
North Sea |  | $ | 188.98 |  |  | $ | 186.50 |  |  | $ | 120.92 |  |  |  | $ | 145.38 |  |  | $ | 98.49 |
Offshore Africa |  | $ | 52.17 |  |  | $ | 29.38 |  |  | $ | 21.67 |  |  |  | $ | 32.36 |  |  | $ | 20.94 |
Crude oil and NGLs average |  | $ | 13.18 |  |  | $ | 14.03 |  |  | $ | 14.65 |  |  |  | $ | 14.32 |  |  | $ | 15.28 |
Natural gas ($/Mcf) (1) |  |  |  |  |  |  |  |  |  |  |
North America |  | $ | 1.14 |  |  | $ | 1.07 |  |  | $ | 1.23 |  |  |  | $ | 1.12 |  |  | $ | 1.23 |
International average |  | $ | 8.18 |  |  | $ | 12.20 |  |  | $ | 6.24 |  |  |  | $ | 9.02 |  |  | $ | 6.13 |
North Sea |  | $ | 15.64 |  |  | $ | 12.78 |  |  | $ | 9.61 |  |  |  | $ | 12.34 |  |  | $ | 8.60 |
Offshore Africa |  | $ | 6.32 |  |  | $ | 11.94 |  |  | $ | 5.75 |  |  |  | $ | 7.80 |  |  | $ | 5.77 |
Natural gas average |  | $ | 1.16 |  |  | $ | 1.11 |  |  | $ | 1.26 |  |  |  | $ | 1.16 |  |  | $ | 1.26 |
Average ($/BOE) (1) |  | $ | 10.50 |  |  | $ | 10.95 |  |  | $ | 11.81 |  |  |  | $ | 11.22 |  |  | $ | 12.16 |

(1)Calculated as production expense divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
North America crude oil and NGLs production expense for the nine months ended September 30, 2025 averaged $12.17 per bbl, a decrease of 8% from $13.17 per bbl for the nine months ended September 30, 2024. North America crude oil and NGLs production expense for the third quarter of 2025 of $11.97 per bbl decreased 3% from $12.36 per bbl for the third quarter of 2024 and was comparable with $11.89 per bbl for the second quarter of 2025. The decrease in crude oil and NG Ls production expense per bbl for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected lower fuel costs.
North America natural gas production expense for the nine months ended September 30, 2025 averaged $1.12 per Mcf, a decrease of 9% from $1.23 per Mcf for the nine months ended September 30, 2024. North America natural gas production expense for the third quarter of 2025 of $1.14 per Mcf decreased 7% from $1.23 per Mcf for the third quarter of 2024 and increased 7% from $1.07 per Mc f for the second quarter of 2025. The decrease in natural gas production expense per Mcf for the three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected higher production volumes. The increase in natural gas production expense per Mcf for the third quarter of 2025 from the second quarter of 2025 primarily reflected higher energy and service costs.

Canadian Natural Resources Limited | 15 | Three and nine months ended September 30, 2025

International
International crude oil and NGLs production expense for the nine months ended September 30, 2025 aver aged $106.02 per bbl, an increase of 80% from $59.04 per bbl for the nine months ended September 30, 2024. International crude oil and NGLs production expense for the third quarter of 2025 of $134.12 per bbl increased 158% from $52.04 per bbl for the third quarter of 2024 and decreased 24% from $175.70 per bbl for the second quarter of 2025. The increase in crude oil and NGLs production expense per bbl for the three and nine months ended September 30, 2025 from the comparable periods i n 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. The decrease in crude oil and NGLs production expense per bbl for the third quarter of 2025 from the second quarter of 2025 primarily reflected the timing of liftings from various fields that have different cost structures.
ADJUSTED DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION

| Three Months Ended |  |  | Nine Months Ended
($ millions, except per BOE amounts) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
North America |  | $ | 1,188 |  |  | $ | 1,085 |  |  | $ | 924 |  |  |  | $ | 3,365 |  |  | $ | 2,821 |
North Sea |  | 1,285 |  |  | 33 |  |  | 17 |  |  |  | 1,358 |  |  | 58 |
Offshore Africa |  | 20 |  |  | 13 |  |  | 96 |  |  |  | 92 |  |  | 251 |
Depletion, depreciation and amortization |  | $ | 2,493 |  |  | $ | 1,131 |  |  | $ | 1,037 |  |  |  | $ | 4,815 |  |  | $ | 3,130 |
Less: Recoverability charge(1) (2) |  | 1,258 |  |  | — |  |  | — |  |  |  | 1,258 |  |  | 62 |
Adjusted depletion, depreciation and amortization (3) |  | $ | 1,235 |  |  | $ | 1,131 |  |  | $ | 1,037 |  |  |  | $ | 3,557 |  |  | $ | 3,068 |
$/BOE (4) |  | $ | 13.08 |  |  | $ | 12.94 |  |  | $ | 13.27 |  |  |  | $ | 13.10 |  |  | $ | 12.89 |

(1)The Company is progressing its abandonment and decommissioning activities in the North Sea, including the tendering and awarding of contracts for the Ninian South Platform. Following a competitive bidding process in 2025, cost estimates have come in higher than originally budgeted. As a result, the Company has reviewed and updated estimates for abandonment and decommissioning costs for its North Sea assets, including the Ninian Central and South Platforms and T‑Block (comprising the Tiffany, Toni, and Thelma fields). In addition, based on current and forecasted economic conditions, including commodity pricing and market egress for T‑Block volumes, the Company has determined that the T-Block assets are no longer economically viable. During the third quarter of 2025, the Company recognized a recoverability charge of $1,258 million in depletion, depreciation and amortization expense related to its North Sea assets.
(2)In connection with the Company's notice of withdrawal from Block 11B/12B in South Africa in the second quarter of 2024, the Company derecognized $62 million of exploration and evaluation assets through depletion, depreciation and amortization expense.
(3)This is a non-GAAP financial measure used to calculate depletion, depreciation and amortization, less the impact of charges that are not related to current period normal course depletion, depreciation and amortization expense such as asset recoverability charges that are not related to current period production. It may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements (depletion, depreciation and amortization expense), as an indication of the Company's performance.
(4)This is a non-GAAP ratio calculated as adjusted depletion, depreciation and amortization expense divided by sales volumes. For sales volumes, refer to the "Non‑GAAP and Other Financial Measures" section of this MD&A.
Adjusted depletion, depreciation and amortization expense for the nine months ended September 30, 2025 averaged $13.10 per BOE, comparable with $12.89 per BOE for the nine months ended September 30, 2024. Adjusted depletion, depreciation and amortization expense for the third quarter of 2025 averaged $13.08 per BOE, comparable with $13.27 per BOE for the third quarter of 2024 and $12.94 per BOE for the second quarter of 2025.

Canadian Natural Resources Limited | 16 | Three and nine months ended September 30, 2025

ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION

| Three Months Ended |  |  | Nine Months Ended
($ millions, except per BOE amounts) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
North America |  | $ | 57 |  |  | $ | 53 |  |  | $ | 58 |  |  |  | $ | 163 |  |  | $ | 173 |
North Sea |  | 13 |  |  | 14 |  |  | 16 |  |  |  | 41 |  |  | 48 |
Offshore Africa |  | 3 |  |  | 2 |  |  | 2 |  |  |  | 7 |  |  | 6 |
Asset retirement obligation accretion |  | $ | 73 |  |  | $ | 69 |  |  | $ | 76 |  |  |  | $ | 211 |  |  | $ | 227 |
$/BOE (1) |  | $ | 0.77 |  |  | $ | 0.79 |  |  | $ | 0.97 |  |  |  | $ | 0.78 |  |  | $ | 0.96 |

(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 the nine months ended September 30, 2025 averag ed $0.78 per BOE, a decrease of 19% from $0.96 per BOE for the nine months ended September 30, 2024. Asset retirement obligation accretion expense for the third quarter of 2025 averaged $0.77 per BOE, a decrease of 21% from $0.97 per BOE for the third quarter of 2024 and a decrease of 3% from $0.79 per BOE for the second quarter of 2025. The decrease in asset retirement obligation accretion expense per BOE for the three and nine months ended September 30, 2025 from the comparable periods in 2024 reflected the impact of changes in discount rate estimate revisions at December 31, 2024, combined with higher sales volumes in 2025, partially offset by revisions in cost and timing estimates at December 31, 2024. The decrease in asset retirement obligation accretion expense per BOE for the third quarter of 2025 from the second quarter of 2025 primarily reflected higher sales volumes.
OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING
The Company continues to focus on safe, reliable, and efficient operations, leveraging its technical expertise acros s the Horizon and AOSP sites. SCO production averaged 581,136 bbl/d in the third quarter of 2025 primarily reflecting strong utilization in the Oil Sands Mining and Upgrading segment.
REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING

| Three Months Ended |  |  | Nine Months Ended
($/bbl) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Realized SCO sales price (1) |  | $ | 87.85 |  |  | $ | 87.22 |  |  | $ | 100.93 |  |  |  | $ | 90.45 |  |  | $ | 99.19 |
Bitumen value for royalty purposes (2) |  | $ | 68.06 |  |  | $ | 64.57 |  |  | $ | 76.16 |  |  |  | $ | 69.06 |  |  | $ | 73.93 |
Bitumen royalties (3) |  | $ | 15.80 |  |  | $ | 11.59 |  |  | $ | 17.71 |  |  |  | $ | 15.49 |  |  | $ | 17.24 |
Transportation (4) |  | $ | 3.86 |  |  | $ | 3.73 |  |  | $ | 3.34 |  |  |  | $ | 3.59 |  |  | $ | 2.62 |

(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2)Calculated as the quarterly average of the bitumen methodology price.
(3)Calculated as royalties divided by sales volumes.
(4)Calculated as transportation expense divided by sales volumes.
The realized SCO sales price avera ged $90.45 per bbl for the nine months ended September 30, 2025, a decrease of 9% from $99.19 per bbl for the nine months ended September 30, 2024. The realized SCO sales price averaged $87.85 per bbl for the third quarter of 2025, a decrease of 13% from $100.93 per bbl for the third quarter of 2024 and comparable with $87.22 per bbl for the second quarter of 2025. The decrease in realized SCO sales price per bbl for t he three and nine months ended September 30, 2025 from the comparable periods in 2024 primarily reflected lower WTI benchmark pricing.
The fluctuations in bitumen royalties p er bbl in any particular period reflect prevailing bitumen value for royalty purposes, and the impact of sliding scale royalty rates. The fluctuations in bitumen royalties per bbl for the three and nine months ended September 30, 2025 from the comparable periods primarily reflected the changes in average bitumen value for royalty purposes.

Canadian Natural Resources Limited | 17 | Three and nine months ended September 30, 2025

Transportation expense averag ed $3.59 per bbl for the nine months ended September 30, 2025, an increase of 37% from $2.62 per bbl for the nine months ended September 30, 2024. Transportation expense averaged $3.86 per bbl for the third quarter of 2025, an increase of 16% from $3.34 per bbl for the third quarter of 2024 and an increase of 3% from $3.73 per bbl for the second quarter of 2025. The increase in tran sportation expense per bbl for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflecte d higher volumes shipped on the TMX pipeline in 2025. The increase in transportation expense per bbl for the third quarter of 2025 from the third quarter of 2024 and the second quarter of 2025 reflected the Company's commitments on egress pipelines, combined with higher volumes shipped on the TMX pipeline and to the US Gulf Coast.
PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING

| Three Months Ended |  |  | Nine Months Ended
($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Production expense, excluding natural gas costs |  | $ | 1,116 |  |  | $ | 1,085 |  |  | $ | 917 |  |  |  | $ | 3,336 |  |  | $ | 2,810 |
Natural gas costs |  | 19 |  |  | 35 |  |  | 18 |  |  |  | 104 |  |  | 92 |
Production expense |  | $ | 1,135 |  |  | $ | 1,120 |  |  | $ | 935 |  |  |  | $ | 3,440 |  |  | $ | 2,902 |

| Three Months Ended |  |  | Nine Months Ended
($/bbl) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Production expense, excluding natural gas costs(1) |  | $ | 20.93 |  |  | $ | 25.71 |  |  | $ | 20.27 |  |  |  | $ | 22.28 |  |  | $ | 22.89 |
Natural gas costs (2) |  | 0.36 |  |  | 0.82 |  |  | 0.40 |  |  |  | 0.70 |  |  | 0.75 |
Production expense (3) |  | $ | 21.29 |  |  | $ | 26.53 |  |  | $ | 20.67 |  |  |  | $ | 22.98 |  |  | $ | 23.64 |
Sales volumes (bbl/d) |  | 579,209 |  |  | 463,586 |  |  | 491,635 |  |  |  | 548,197 |  |  | 448,145 |

(1)Calculated as production expense, excluding natural gas costs, divided by sales volumes.
(2)Calculated as natural gas costs divided by sales volumes.
(3)Calculated as production expense divided by sales volumes.
Production expen se for the nine months ended September 30, 2025 averaged $22.98 per bbl, a decrease of 3% from $23.64 per bbl for the nine months ended September 30, 2024. Production expense for the third quarter of 2025 averaged $21.29 per bbl, comparable with $20.67 per bbl for the third quarter of 2024 and a decrease of 20% from $26.53 per bbl for the second quarter of 2025. The decrease in production expense per bbl for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflected higher production volumes from the acquisition of the additional 20% working interest in AOSP in December 2024. The decrease in productio n expense per bbl for the third quarter of 2025 from the second quarter of 2025 primarily reflected higher production volumes from strong utilization and lower fuel costs.
DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING

| Three Months Ended |  |  | Nine Months Ended
($ millions, except per bbl amounts) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Depletion, depreciation and amortization |  | $ | 713 |  |  | $ | 630 |  |  | $ | 556 |  |  |  | $ | 2,018 |  |  | $ | 1,637 |
$/bbl (1) |  | $ | 13.38 |  |  | $ | 14.96 |  |  | $ | 12.27 |  |  |  | $ | 13.49 |  |  | $ | 13.33 |

(1)Calculated as depletion, depreciation and amortization divided by sales volumes.
Depletion, depreciation and amortization expense for the nine months ended September 30, 2025 averaged $13.49 per bbl, comparable with $13.33 per bbl for the nine months ended September 30, 2024. Depletion, depreciation and amortization expense for the third quarter of 2025 of $13.38 per bbl increased 9% from $12.27 per bbl for the third quarter of 2024 and decreased 11% from $14.96 per bbl for the second quarter of 2025. The increase in depletion, depreciation and amortization expense per bbl for the third quarter of 2025 from the third quarter of 2024 primarily reflected a higher depletable base due to asset additions, partially offset by higher sales volumes. The decrease in depletion, depreciation and amortization expense per bbl for the third quarter of 2025 from the second quarter of 2025 primarily reflected higher sales volumes in the third quarter.

Canadian Natural Resources Limited | 18 | Three and nine months ended September 30, 2025

ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING

| Three Months Ended |  |  | Nine Months Ended
($ millions, except per bbl amounts) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Asset retirement obligation accretion |  | $ | 22 |  |  | $ | 21 |  |  | $ | 21 |  |  |  | $ | 65 |  |  | $ | 64 |
$/bbl (1) |  | $ | 0.40 |  |  | $ | 0.51 |  |  | $ | 0.46 |  |  |  | $ | 0.43 |  |  | $ | 0.51 |

(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 du e to the passage of time. Asset retirement obligation accretion expense for the nine months ended September 30, 2025 of $0.43 per bbl decreased 16% from $0.51 per bbl for the nine months ended September 30, 2024. Asset retirement obligation accretion expense for the third quarter of 2025 of $0.40 per bbl decreased 13% from $0.46 per bbl for the third quarter of 2024 and decreased 22% from $0.51 per bbl for the second quarter of 2025. The decrease in asset retirement obligation accretion expense per bbl for the three and nine months ended September 30, 2025 from the comparable periods primarily reflected the impact of higher sales volumes.
MIDSTREAM AND REFINING

| Three Months Ended |  |  | Nine Months Ended
($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Product sales |  |  |  |  |  |  |  |  |  |  |
Midstream activities |  | $ | 24 |  |  | $ | 22 |  |  | $ | 20 |  |  |  | $ | 68 |  |  | $ | 61 |
NWRP, refined product sales and other |  | 106 |  |  | 137 |  |  | 191 |  |  |  | 464 |  |  | 620 |
Segmented revenue |  | 130 |  |  | 159 |  |  | 211 |  |  |  | 532 |  |  | 681 |
Less: |  |  |  |  |  |  |  |  |  |  |
NWRP, refining toll |  | 70 |  |  | 61 |  |  | 75 |  |  |  | 199 |  |  | 230 |
Midstream activities |  | 7 |  |  | 5 |  |  | 3 |  |  |  | 17 |  |  | 15 |
Production expense |  | 77 |  |  | 66 |  |  | 78 |  |  |  | 216 |  |  | 245 |
NWRP, feedstock costs |  | 82 |  |  | 105 |  |  | 166 |  |  |  | 359 |  |  | 509 |
Transportation expenses |  | 3 |  |  | 31 |  |  | 3 |  |  |  | 38 |  |  | 12 |
Depreciation |  | 5 |  |  | 4 |  |  | 5 |  |  |  | 13 |  |  | 13 |
Segmented loss |  | $ | (37) |  |  | $ | (47) |  |  | $ | (41) |  |  |  | $ | (94) |  |  | $ | (98) |

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 North West Redwater Partnership ("NWRP").
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 refined products and associated refining tolls are recognized in the Midstream and Refining segment. For the third quarter of 2025, production of ultra-low sulphur diesel and other refined products average d 38,434 BOE/d (9,608 BOE/d to the Company) (three months ended June 30, 2025 – 60,549 BOE/d; 15,137 BOE/d to the Company; three months ended September 30, 2024 – 72,109 BOE/d; 18,027 BOE/d to the Company), reflecting the successful completion of the planned turnaround in the third quarter, and the Company's 25% toll payer commitment.
As at September 30, 2025, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP w as $483 million (December 31, 2024 – $509 million). For the three months ended September 30, 2025, the Company's recovery of its share of unrecognized equity losses was $21 million (three months ended June 30, 2025 – recovery of unrecognized equity losses of $24 million; nine months ended September 30, 2025 – recovery of unrecognized equity losses of $26 million; three months ended September 30, 2024 – recovery of unrecognized equity losses o f $6 million; nine months ended September 30, 2024 – recovery of unrecognized equity losses of $45 million).

Canadian Natural Resources Limited | 19 | Three and nine months ended September 30, 2025

ADMINISTRATION EXPENSE

| Three Months Ended |  |  | Nine Months Ended
($ millions, except per BOE amounts) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Administration expense |  | $ | 152 |  |  | $ | 151 |  |  | $ | 126 |  |  |  | $ | 455 |  |  | $ | 376 |
$/BOE (1) |  | $ | 1.03 |  |  | $ | 1.17 |  |  | $ | 1.02 |  |  |  | $ | 1.08 |  |  | $ | 1.04 |
Sales volumes (BOE/d) (2) |  | 1,606,723 |  |  | 1,423,321 |  |  | 1,342,508 |  |  |  | 1,543,203 |  |  | 1,316,989 |

(1)Calculated as administration expense divided by sales volumes.
(2)Total Company sales volumes.
Administration expense for the nine months ended September 30, 2025 of $1.08 pe r BOE increased 4% from $1.04 per BOE for the nine months ended September 30, 2024. Administration expense for the third quarter of 2025 of $1.03 per BOE was comparable with $1.02 per BOE for the third quarter of 2024 and decreased 12% from $1.17 per BOE for the second quarter of 2025. The increase in administration expense per BOE for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflected higher personnel costs, partially offset by higher overhead recoveries and higher sales volumes. The decrease in administration expense per BOE for the third quarter of 2025 from the second quarter of 2025 primarily reflected higher sales volumes.
SHARE-BASED COMPENSATION

| Three Months Ended |  |  | Nine Months Ended
($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Share-based compensation expense (recovery) |  | $ | 63 |  |  | $ | 8 |  |  | $ | (46) |  |  |  | $ | 97 |  |  | $ | 235 |

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 $97 million of share-based compensation expense for the nine months ended September 30, 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.

Canadian Natural Resources Limited | 20 | Three and nine months ended September 30, 2025

INTEREST AND OTHER FINANCING EXPENSE

| Three Months Ended |  |  | Nine Months Ended
($ millions, except effective interest rate) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Interest and other financing expense |  | $ | 93 |  |  | $ | 238 |  |  | $ | 154 |  |  |  | $ | 589 |  |  | $ | 450 |
Less: Interest (income) and other expense (1) |  | (174) |  |  | (7) |  |  | (5) |  |  |  | (187) |  |  | (34) |
Interest expense on long-term debt and lease liabilities (1) |  | $ | 267 |  |  | $ | 245 |  |  | $ | 159 |  |  |  | $ | 776 |  |  | $ | 484 |
Average current and long-term debt (2) |  | $ | 18,802 |  |  | $ | 17,552 |  |  | $ | 11,130 |  |  |  | $ | 18,500 |  |  | $ | 11,431 |
Average lease liabilities (2) |  | 1,469 |  |  | 1,382 |  |  | 1,511 |  |  |  | 1,424 |  |  | 1,526 |
Average long-term debt and lease liabilities (2) |  | $ | 20,271 |  |  | $ | 18,934 |  |  | $ | 12,641 |  |  |  | $ | 19,924 |  |  | $ | 12,957 |
Average effective interest rate (3) (4) |  | 5.2% |  | 5.1% |  | 4.9% |  |  | 5.1% |  | 4.9%
Interest and other financing expense ($/BOE) (5) |  | $ | 0.62 |  |  | $ | 1.84 |  |  | $ | 1.24 |  |  |  | $ | 1.40 |  |  | $ | 1.25 |
Sales volumes (BOE/d) (6) |  | 1,606,723 |  |  | 1,423,321 |  |  | 1,342,508 |  |  |  | 1,543,203 |  |  | 1,316,989 |

(1)Item is a component of interest and other financing expense.
(2)The average of current and long-term debt and lease liabilities outstanding during the respective period.
(3)This is a non-GAAP ratio and may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements, as applicable, as an indication of the Company's performance.
(4)Calculated as the average interest expense on long-term debt and lease liabilities divided by the average long-term debt and lease liabilities balance. The Company presents its average effective interest rate for financial statement users to evaluate the Company’s average cost of debt borrowings.
(5)Calculated as interest and other financing expense divided by sales volumes.
(6)Total Company sales volumes.
Interest and other financing expense for the nine months ended September 30, 2025 increased 12% to $1.40 per BOE from $1.25 per BOE for the nine months ended September 30, 2024. Interest and other financing expense for the third quarter of 2025 decreased 50% to $0.62 per BOE from $1.24 per BOE for the third quarter of 2024 and decreased 66% from $1.84 per BOE for the second quarter of 2025. The increase in interest and other financing expense per BOE for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 primarily reflected higher average debt levels, including higher floating rate debt levels, partially offset by higher sales volumes. The decrease in interest and other financing expense per BOE for the third quarter of 2025 from the third quarter of 2024 and second quarter of 2025 primarily reflected interest on the deferred PRT and corporate tax recoveries in the North Sea.
The Company's average effective interest rate for the three and nine months ended September 30, 2025 averaged 5.2% and 5.1%, respectively, an increase from the comparable periods in 2024, reflecting higher floating rate long-term debt held during 2025.

Canadian Natural Resources Limited | 21 | Three and nine months ended September 30, 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.

| Three Months Ended |  |  | Nine Months Ended
($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Foreign currency forward contracts |  | $ | 52 |  |  | $ | (115) |  |  | $ | (27) |  |  |  | $ | (83) |  |  | $ | 11 |
Foreign currency put options (1) |  | — |  |  | 27 |  |  | — |  |  |  | 23 |  |  | — |
Natural gas financial instruments (2) (3) (4) (5) |  | 2 |  |  | (1) |  |  | 6 |  |  |  | (2) |  |  | 11 |
Net realized loss (gain) |  | 54 |  |  | (89) |  |  | (21) |  |  |  | (62) |  |  | 22 |
Foreign currency forward contracts |  | — |  |  | (19) |  |  | 5 |  |  |  | (5) |  |  | 17 |
Foreign currency put options (1) |  | — |  |  | 2 |  |  | — |  |  |  | — |  |  | — |
Natural gas embedded derivative (6) |  | 156 |  |  | (11) |  |  | — |  |  |  | 145 |  |  | — |
Natural gas financial instruments (2) (3) (4) (5) |  | 4 |  |  | 13 |  |  | (5) |  |  |  | 8 |  |  | (4) |
Net unrealized loss (gain) |  | 160 |  |  | (15) |  |  | — |  |  |  | 148 |  |  | 13 |
Net loss (gain) |  | $ | 214 |  |  | $ | (104) |  |  | $ | (21) |  |  |  | $ | 86 |  |  | $ | 35 |

(1)During 2025, the Company entered into foreign currency put options contracts. Further details are disclosed in note 13 to the financial statements.
(2)Certain commodity financial instruments were assumed in the acquisition of Painted Pony Energy Ltd. in the fourth quarter of 2020.
(3)In the third quarter of 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.
(4)In the fourth quarter of 2024, the Company entered into fixed price financial contracts to buy 12,500 MMBtu/d of natural gas at US$1.47 AECO, and 25,000 MMBtu/d of natural gas at US$1.82 AECO for the period of January to December 2025.
(5)In the fourth quarter of 2023, the Company entered into fixed price financial contracts to buy 50,000 MMBtu/d of natural gas at US$1.82 AECO for the period of January to December 2024.
(6)In the second quarter of 2025, the Company entered into a long-term natural gas supply agreement containing an embedded derivative. Further details are disclosed in note 13 to the financial statements.
During the nine months ended September 30, 2025, the Company recorded a net realized risk management gain of $62 million and a net realized risk management loss of $54 million for the third quarter of 2025.
The Company recorded a net unrealized loss of $148 million ($114 million after tax of $34 million) on its risk management activities for the nine months ended September 30, 2025, and a net unrealized loss of $160 million ($124 million after tax of $36 million) for the third quarter of 2025 (three months ended June 30, 2025 – unrealized gain of $15 million ($12 million after tax of $3 million); three months ended September 30, 2024 – $nil; nine months ended September 30, 2024 – unrealized loss of $13 million ($13 million after tax of $nil)).
Further details related to outstanding derivative financial instruments as at September 30, 2025 are disclosed in note 13 to the financial statements.
FOREIGN EXCHANGE

| Three Months Ended |  |  | Nine Months Ended
($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Net realized loss (gain) |  | $ | 21 |  |  | $ | (142) |  |  | $ | 30 |  |  |  | $ | 121 |  |  | $ | 129 |
Net unrealized loss (gain) |  | 269 |  |  | (661) |  |  | (148) |  |  |  | (677) |  |  | 106 |
Net loss (gain) (1) |  | $ | 290 |  |  | $ | (803) |  |  | $ | (118) |  |  |  | $ | (556) |  |  | $ | 235 |

(1)Amounts are reported net of derivative financial instruments designated as cash flow hedges.
The net realized foreign exchange loss for the nine months ended September 30, 2025 was primarily related to the 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 the nine months ended September 30, 2025 was primarily related to the translation of outstanding US dollar debt. The US/Canadian dollar exchange rate as at September 30, 2025 was US$0.7191 (June 30, 2025 – US$0.7341, September 30, 2024 – US$0.7405).

Canadian Natural Resources Limited | 22 | Three and nine months ended September 30, 2025

INCOME TAXES

| Three Months Ended |  |  | Nine Months Ended
($ millions, except effective tax rates) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
North America (1) |  | $ | 499 |  |  | $ | 529 |  |  | $ | 433 |  |  |  | $ | 1,597 |  |  | $ | 1,393 |
North Sea |  | (37) |  |  | (45) |  |  | (12) |  |  |  | (108) |  |  | (30) |
Offshore Africa |  | — |  |  | — |  |  | 12 |  |  |  | 5 |  |  | 22 |
Current PRT – North Sea |  | (45) |  |  | (49) |  |  | (47) |  |  |  | (133) |  |  | (67) |
Other taxes |  | 2 |  |  | 3 |  |  | 3 |  |  |  | 7 |  |  | (8) |
Current income tax |  | 419 |  |  | 438 |  |  | 389 |  |  |  | 1,368 |  |  | 1,310 |
Deferred corporate income tax |  | (143) |  |  | (106) |  |  | 120 |  |  |  | (130) |  |  | 148 |
Deferred PRT – North Sea |  | (389) |  |  | 18 |  |  | 34 |  |  |  | (362) |  |  | 47 |
Deferred income tax |  | (532) |  |  | (88) |  |  | 154 |  |  |  | (492) |  |  | 195 |
Income tax |  | $ | (113) |  |  | $ | 350 |  |  | $ | 543 |  |  |  | $ | 876 |  |  | $ | 1,505 |
Earnings before taxes |  | $ | 487 |  |  | $ | 2,809 |  |  | $ | 2,809 |  |  |  | $ | 6,393 |  |  | $ | 6,473 |
Effective tax rate on net earnings (2) |  | (23)% |  | 12% |  | 19% |  |  | 14% |  | 23%
| Three Months Ended |  |  | Nine Months Ended
($ millions, except effective tax rates) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Income tax |  | $ | (113) |  |  | $ | 350 |  |  | $ | 543 |  |  |  | $ | 876 |  |  | $ | 1,505 |
Tax effect on non-operating items (3) |  | 603 |  |  | (1) |  |  | 1 |  |  |  | 607 |  |  | 32 |
Current PRT – North Sea |  | 45 |  |  | 49 |  |  | 47 |  |  |  | 133 |  |  | 67 |
Deferred PRT – North Sea |  | (31) |  |  | (18) |  |  | (34) |  |  |  | (58) |  |  | (47) |
Other taxes |  | (2) |  |  | (3) |  |  | (3) |  |  |  | (7) |  |  | 8 |
Effective tax on adjusted net earnings |  | $ | 502 |  |  | $ | 377 |  |  | $ | 554 |  |  |  | $ | 1,551 |  |  | $ | 1,565 |
Adjusted net earnings from operations (4) |  | $ | 1,801 |  |  | $ | 1,496 |  |  | $ | 2,071 |  |  |  | $ | 5,733 |  |  | $ | 5,437 |
Adjusted net earnings from operations, before taxes |  | $ | 2,303 |  |  | $ | 1,873 |  |  | $ | 2,625 |  |  |  | $ | 7,284 |  |  | $ | 7,002 |
Effective tax rate on adjusted net earnings from operations (5) (6) |  | 22% |  | 20% |  | 21% |  |  | 21% |  | 22%

(1)Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments.
(2)Calculated as total of current and deferred income tax divided by earnings before taxes.
(3)Includes the net income tax effect on PSUs, certain stock options, unrealized risk management, a recoverability charge related to the increase in estimate of the future abandonment costs for the Ninian field and T‑Block assets in the North Sea in the third quarter of 2025, and a re coverability charge related to the notice to withdraw from Block 11B/12B in South Africa in the second quarter of 2024.
(4)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(5)This is a non-GAAP ratio and may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements, as applicable, as an indication of the Company's performance.
(6)Calculated as effective tax on adjusted net earnings divided by adjusted net earnings from operations, before taxes. The Company presents its effective tax rate on adjusted net earnings from operations for financial statement users to evaluate the Company's effective tax rate on its core business activities.
The effective tax rate on net earnings and adjusted net earnings from operations for the three and nine months ended September 30, 2025 and the comparable periods included the impact of non-taxable items in North America and the North Sea and the impact of differences in jurisdictional income and tax rates in the countries in which the Company operates, in relation to net earnings.
The current and deferred corporate income tax and the current and deferred PRT in the North Sea for the three and nine months ended September 30, 2025 and the comparable periods included the impact of carrybacks of abandonment expenditures related to the decommissioning activities in the North Sea.

Canadian Natural Resources Limited | 23 | Three and nine months ended September 30, 2025

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.
NET CAPITAL EXPENDITURES (1) (2)

| Three Months Ended |  |  | Nine Months Ended
($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Exploration and Production |  |  |  |  |  |  |  |  |  |  |
Exploration and Evaluation Assets |  |  |  |  |  |  |  |  |  |  |
Net expenditures |  | $ | 18 |  |  | $ | 5 |  |  | $ | 8 |  |  |  | $ | 42 |  |  | $ | 73 |
Net property acquisitions |  | 45 |  |  | 46 |  |  | — |  |  |  | 78 |  |  | — |
Total Exploration and Evaluation Assets |  | 63 |  |  | 51 |  |  | 8 |  |  |  | 120 |  |  | 73 |
Property, Plant and Equipment |  |  |  |  |  |  |  |  |  |  |
Net property acquisitions |  | 761 |  |  | 178 |  |  | 88 |  |  |  | 970 |  |  | 89 |
Well drilling, completion and equipping |  | 499 |  |  | 558 |  |  | 469 |  |  |  | 1,593 |  |  | 1,360 |
Production and related facilities |  | 365 |  |  | 407 |  |  | 387 |  |  |  | 1,162 |  |  | 995 |
Other |  | 13 |  |  | 16 |  |  | 14 |  |  |  | 32 |  |  | 39 |
Total Property, Plant and Equipment |  | 1,638 |  |  | 1,159 |  |  | 958 |  |  |  | 3,757 |  |  | 2,483 |
Total Exploration and Production |  | 1,701 |  |  | 1,210 |  |  | 966 |  |  |  | 3,877 |  |  | 2,556 |
Oil Sands Mining and Upgrading |  |  |  |  |  |  |  |  |  |  |
Project costs |  | 76 |  |  | 96 |  |  | 55 |  |  |  | 227 |  |  | 240 |
Sustaining capital |  | 312 |  |  | 406 |  |  | 302 |  |  |  | 934 |  |  | 1,109 |
Turnaround costs |  | 13 |  |  | 174 |  |  | 12 |  |  |  | 233 |  |  | 137 |
Net property dispositions |  | — |  |  | — |  |  | — |  |  |  | — |  |  | (2) |
Other |  | 2 |  |  | 2 |  |  | 3 |  |  |  | 6 |  |  | 5 |
Total Oil Sands Mining and Upgrading |  | 403 |  |  | 678 |  |  | 372 |  |  |  | 1,400 |  |  | 1,489 |
Midstream and Refining |  | 2 |  |  | 2 |  |  | 3 |  |  |  | 6 |  |  | 10 |
Head Office |  | 18 |  |  | 25 |  |  | 8 |  |  |  | 59 |  |  | 28 |
Net capital expenditures |  | $ | 2,124 |  |  | $ | 1,915 |  |  | $ | 1,349 |  |  |  | $ | 5,342 |  |  | $ | 4,083 |
Abandonment expenditures |  | $ | 189 |  |  | $ | 193 |  |  | $ | 204 |  |  |  | $ | 570 |  |  | $ | 495 |
By Segment |  |  |  |  |  |  |  |  |  |  |
North America |  | $ | 1,606 |  |  | $ | 1,110 |  |  | $ | 896 |  |  |  | $ | 3,552 |  |  | $ | 2,401 |
North Sea |  | 5 |  |  | 8 |  |  | 29 |  |  |  | 16 |  |  | 36 |
Offshore Africa |  | 90 |  |  | 92 |  |  | 41 |  |  |  | 309 |  |  | 119 |
Oil Sands Mining and Upgrading |  | 403 |  |  | 678 |  |  | 372 |  |  |  | 1,400 |  |  | 1,489 |
Midstream and Refining |  | 2 |  |  | 2 |  |  | 3 |  |  |  | 6 |  |  | 10 |
Head Office |  | 18 |  |  | 25 |  |  | 8 |  |  |  | 59 |  |  | 28 |
Net capital expenditures |  | $ | 2,124 |  |  | $ | 1,915 |  |  | $ | 1,349 |  |  |  | $ | 5,342 |  |  | $ | 4,083 |

(1)Net capital expenditures exclude the impact of lease assets, fair value and revaluation adjustments.
(2)Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2024. R efer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited | 24 | Three and nine months ended September 30, 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 were $5,342 million for the nine months ended September 30, 2025 compared with $4,083 million for the nine months ended September 30, 2024. Net capital expenditures were $2,124 million for the third quarter of 2025 compared with $1,349 million for the third quarter of 2024 and $1,915 million for the second quarter of 2025.
In addition, the Company reported abandonment expenditures of $570 million for the nine months ended September 30, 2025 compared with $495 million for the nine months ended September 30, 2024. Abandonment expenditures were $189 million for the third quarter of 2025 compared with $204 million for the third quarter of 2024 and $193 million for the second quarter of 2025.
2025 Capital Budget
On January 9, 2025, the Company announced its 2025 operating capital budget(1) targeted at approximately $6,015 million, which comprises capital related to a number of acquisitions, including the acquisitions completed in the second quarter of 2025. With this capital, the Company is targeting near-term production growth in 2025 and mid- and long-term production and capacity growth in 2026 and beyond. In addition, the Company has approved approximately $135 million of capital, consisting of $90 million related to carbon capture and $45 million related to a one-time office move scheduled to take place through 2026. The Company targets $787 million in abandonment expenditures for 2025. On May 7, 2025, the 2025 total capital budget was reduced by $100 million to $6,050 million, excluding abandonment expenditures. On November 3, 2025, the Company revised its 2025 production guidance to between 1,560 MBOE/d and 1,580 MBOE/d.
In July 2025, the Company acquired certain producing and non-producing NGLs and natural gas assets in the Grande Prairie area in the North America Exploration and Production segment for cash consideration of $752 million, subject to final closing adjustments. The 2025 capital budget did not include capital related to the Grande Prairie, and other small acquisitions completed in the third quarter of 2025.
Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns, and the balancing of project risks and time horizons. The 2025 capita l budget constitutes forward‑looking statements and is based on net capital expenditures. Refer to the "Advisory" section of this MD&A for further details on forward‑looking statements.
Drilling Activity (1) (2)

| Three Months Ended |  |  | Nine Months Ended
(number of net wells) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Net successful crude oil wells (3) |  | 89 |  |  | 81 |  |  | 83 |  |  |  | 244 |  |  | 207 |
Net successful natural gas wells |  | 17 |  |  | 22 |  |  | 24 |  |  |  | 58 |  |  | 64 |
Dry wells |  | — |  |  | — |  |  | 1 |  |  |  | 1 |  |  | 2 |
Total |  | 106 |  |  | 103 |  |  | 108 |  |  |  | 303 |  |  | 273 |
Success rate |  | 100% |  | 100% |  | 99% |  |  | 99% |  | 99%

(1)Includes drilling activity for North America and International segments.
(2)Excludes stratigraphic and service wells.
(3)Includes bitumen wells.
North America
During the third quarter of 2025, the Company drilled 17 net natural gas wells, 58 net primary heavy crude oil wells, 4 net Pelican Lake heavy crude oil wells, 11 net bitumen (thermal oil) wells and 16 net light crud e oil wells.
(1)Forward-looking non-GAAP Financial Measure. Th e operating capit al budget is based on net capital expenditures (Non-GAAP Financial Measure). Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on net capital expenditures.

Canadian Natural Resources Limited | 25 | Three and nine months ended September 30, 2025

LIQUIDITY AND CAPITAL RESOURCES

($ millions, except ratios) |  | Sep 30 2025 |  | Jun 30 2025 |  | Dec 31 2024 |  | Sep 30 2024 |  |
Adjusted working capital (1) |  | $ | (303) |  |  | $ | 102 |  |  | $ | 174 |  |  | $ | 365 |  |  |
Long-term debt, net (2) |  | $ | 17,155 |  |  | $ | 16,979 |  |  | $ | 18,688 |  |  | $ | 9,308 |  |  |
Shareholders' equity |  | $ | 40,461 |  |  | $ | 41,298 |  |  | $ | 39,468 |  |  | $ | 39,897 |  |  |
Debt to book capitalization (2) |  | 29.8% |  | 29.1% |  | 32.1% |  | 18.9% |  |
After-tax return on average capital employed (3) |  | 12.8% |  | 16.3% |  | 12.7% |  | 15.9% |  |

(1)Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
(2)Capital Management Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
As at September 30, 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" section of this MD&A and in the "Risks and Uncertainties" section of the Company's annual MD&A for the year ended December 31, 2024. 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.
On an ongoing basis the Company continues to focus on its balance sheet strength and available liquidity by:
▪Monitoring cash flows from operating activities, which is the primary source of funds;
▪Monitoring exposure to individual customers, contractors, suppliers, and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place, and as applicable, taking other mitigating actions to minimize the impact in the event of a default;
▪Actively managing the allocation of capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. The Company continues to exercise its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments, and long-term debt;
▪Monitoring the Company's ability to fulfill financial obligations as they become due or the ability to monetize assets in a timely manner at a reasonable price;
▪Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages; and
▪Reviewing the Company's borrowing capacity:
•During the first quarter of 2025, the Company extended its $500 million revolving credit facility originally maturing February 2026 to June 2027.
•Borrowings under the Company's credit facilities may be made by way of pricing referenced to CORRA, SOFR, US base rate or Canadian prime rate.
•The Company's borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million.
•In July 2023, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada, which expired in August 2025. In August 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 the third quarter of 2025, the Company repaid US$600 million of 2.05% US dollar debt securities due July 2025.
•During the first quarter of 2025, the Company repaid US$600 million of 3.90% US dollar debt securities due February 2025.

Canadian Natural Resources Limited | 26 | Three and nine months ended September 30, 2025

•In July 2023, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to US$3,000 million of debt securities in the United States, which expired in August 2025. In August 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.
•In October 2025, the Company filed a prospectus supplement to the base shelf prospectus. Under the prospectus supplement, up to US$1,500 million of the registered debt securities may be issued in exchange for up to US$1,500 million of the Company's outstanding restricted 5.00% US dollar debt securities due December 2029 and 5.40% US dollar debt securities due December 2034. Any notes issued under such exchange will not be subject to transfer restrictions and will not result in a change in the current level of indebtedness.
As at September 30, 2025, the Company had undrawn revolving bank credit facilities of $4,201 million, and a fully drawn non-revolving term credit facility of $4,000 million. Including cash and cash equivalents, the Company had approximately $4,314 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit. As at September 30, 2025, the Company had $829 million drawn under its commercial paper program and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
Long-term debt, net was $17,155 million as at September 30, 2025 (December 31, 2024 – $18,688 million), resulting in a debt to book capitalization ratio of 29.8% (December 31, 2024 – 32.1%); 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 September 30, 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 September 30, 2025 are discussed in note 6 to the financial statements.
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.
As at September 30, 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) | $ | 829 |  |  | $ | 3,047 |  |  | $ | 6,345 |  |  | $ | 7,127 |
Other long-term liabilities (2) | $ | 227 |  |  | $ | 175 |  |  | $ | 417 |  |  | $ | 779 |
Interest and other financing expense (3) | $ | 966 |  |  | $ | 938 |  |  | $ | 1,634 |  |  | $ | 3,114 |

(1)Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
(2)Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $224 million; one to less than two years, $175 million; two to less than five years, $417 million; and thereafter, $634 million.
(3)Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates as at September 30, 2025.
Share Capital
As at September 30, 2025, there were 2,085,082,000 common shares outstanding (December 31, 2024 – 2,102,996,000 common shares) and 57,326,000 stock options outstanding (December 31, 2024 – 50,806,000 stock options). As at November 4, 2025, the Company had 2,083,107,000 common shares outstanding and 56,671,000 stock options outstanding.
On March 5, 2025, the Board of Directors approved a 4% increase in the quarterly dividend to $0.5875 per common share, beginning with the dividend paid on April 4, 2025.
On October 7, 2024, the Board of Directors approved a 7% increase in the quarterly dividend to $0.5625 per common share. On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to $0.525 per common share.
The dividend policy undergoes periodic review by the Board of Directors and is subject to change.

Canadian Natural Resources Limited | 27 | Three and nine months ended September 30, 2025

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 nine months ended September 30, 2025, the Company purchased 26,980,000 common shares at a weighted average price of $42.81 per common share for a total cost, including tax, of $1,170 million. Retained earnings were reduced by $1,025 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to September 30, 2025, up to and including November 4, 2025, the Company purchased 2,500,000 common shares at a weighted average price of $44.03 per common share for a total cost, including tax, of $112 million.
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 September 30, 2025:

($ millions) |  | Remaining 2025 |  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | Thereafter
Product transportation, purchases, and processing (1) |  | $ | 602 |  |  | $ | 2,380 |  |  | $ | 2,253 |  |  | $ | 2,107 |  |  | $ | 2,004 |  |  | $ | 19,595 |
North West Redwater Partnership service toll (2) |  | $ | 35 |  |  | $ | 117 |  |  | $ | 97 |  |  | $ | 98 |  |  | $ | 97 |  |  | $ | 4,018 |
Offshore vessels and equipment |  | $ | 94 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Field equipment and power |  | $ | 29 |  |  | $ | 32 |  |  | $ | 29 |  |  | $ | 28 |  |  | $ | 27 |  |  | $ | 216 |
Other |  | $ | 31 |  |  | $ | 119 |  |  | $ | 19 |  |  | $ | 19 |  |  | $ | 18 |  |  | $ | 195 |

(1)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 the fourth quarter of 2023, and is subject to change pending the approval of final tolls.
(2)Pursuant to the processing agreements, the Company pays its 25% pro rata share of the debt component of the monthly fee-for-service toll. Included in the toll is $1,882 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.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the application of IFRS that have a significant impact on the financial results of the Company. Actual results may differ from estimated amounts, and those differences may be material. A comprehensive discussion of the Company's significant accounting estimates is contained in the Company's annual MD&A and audited consolidated financial statements for the year ended December 31, 2024.
CONTROL ENVIRONMENT
There have been no changes to internal control over financial reporting ("ICFR") during the nine months ended September 30, 2025 that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting. Due to inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Canadian Natural Resources Limited | 28 | Three and nine months ended September 30, 2025

NON-GAAP AND OTHER FINANCIAL MEASURES
This MD&A includes references to non-GAAP and other financial measures as defined in NI 52-112. These financial measures are used by the Company to evaluate its financial performance, financial position, and cash flow and include non‑GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non‑GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies and should not be considered an alternative to, or more meaningful than, the most directly comparable financial measure presented in the financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company's non-GAAP and other financial measures included in this MD&A and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below.
Adjusted Net Earnings from Operations
Adjusted net earnings from operations is a non-GAAP financial measure that adjusts net earnings as presented in the Company's consolidated statements of earnings, for non-operating items, net of tax impacts. The Company considers adjusted net earnings from operations a key measure in evaluating its performance, as it demonstrates the Company's ability to generate after-tax operating earnings from its core business areas. A reconciliation for adjusted net earnings from operations is presented below.

| Three Months Ended |  |  | Nine Months Ended
($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Net earnings |  | $ | 600 |  |  | $ | 2,459 |  |  | $ | 2,266 |  |  |  | $ | 5,517 |  |  | $ | 4,968 |
Share-based compensation, net of tax (1) |  | 59 |  |  | 6 |  |  | (48) |  |  |  | 87 |  |  | 218 |
Unrealized risk management loss (gain), net of tax (2) |  | 124 |  |  | (12) |  |  | 1 |  |  |  | 114 |  |  | 13 |
Unrealized foreign exchange loss (gain), net of tax (3) |  | 269 |  |  | (661) |  |  | (148) |  |  |  | (677) |  |  | 106 |
Realized foreign exchange loss (gain) on financing activities, net of tax (4) |  | 54 |  |  | (216) |  |  | — |  |  |  | 77 |  |  | 135 |
Gain fr om investments, net of tax |  | — |  |  | — |  |  | — |  |  |  | — |  |  | (50) |
Gain on acquisition, net of tax (5) |  | — |  |  | (80) |  |  | — |  |  |  | (80) |  |  | — |
Recoverability charge, net of tax (6) (7) |  | 695 |  |  | — |  |  | — |  |  |  | 695 |  |  | 47 |
Non-operating items, net of tax |  | 1,201 |  |  | (963) |  |  | (195) |  |  |  | 216 |  |  | 469 |
Adjusted net earnings from operations |  | $ | 1,801 |  |  | $ | 1,496 |  |  | $ | 2,071 |  |  |  | $ | 5,733 |  |  | $ | 5,437 |

(1)Share-based compensation includes costs incurred under the Company's Stock Option Plan and PSU Plan. The fair value of the share-based compensation is recognized as a liability on the Company's balance sheets, and periodic changes in the fair value are recognized in net earnings. Pre-tax share-based compensation for the three months ended September 30, 2025 w as an expense of $63 million (three months ended June 30, 2025 – $8 million expense, three months ended September 30, 2024 – $46 million recovery; nine months ended September 30, 2025 – $97 million expense; nine months ended September 30, 2024 – $235 million expense).
(2)Derivative financial instruments are recognized at fair value on the Company's balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than those amounts reflected in the financial statements due to changes in prices of the underlying items hedged, primarily natural gas and foreign exchange. The pre-tax unrealized risk management loss for the three months ended September 30, 2025 was $160 million (three months ended June 30, 2025 – $15 million gain, three months ended September 30, 2024 – $nil; nine months ended September 30, 2025 – $148 million loss; nine months ended September 30, 2024 – $13 million loss).
(3)Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates and are recognized in net earnings. Pre- and after-tax amounts for these unrealized foreign exchange gains and losses are the same.
(4)Realized foreign exchange gains and losses associated with financing activities primarily result from the repayment of US dollar denominated debt and are recognized in net earnings. Pre- and after-tax amounts for these realized foreign exchange gains and losses are the same.
(5)During the second quarter of 2025, the Company acquired an interest in certain producing and non-producing crude oil and NGLs, a nd natural gas assets in the North America Exploration and Production segment, resulting in a pre- and after-tax gain on acquisition of $80 million representing the excess of the fair value of the net assets acquired compared to the total purchase consideration.
(6)During the third quarter of 2025, the Company recognized a pre-tax recoverability charge of $1,258 million ($695 million after-tax) in depletion, depreciation and amortization relating to the increase in estimate of the future abandonment costs for the Ninian field and T‑Block assets in the North Sea. The costs are included in capital and abandonment expenditures, consistent with the treatment of all abandonment related expenditures for the purpose of the Company's non-GAAP measures.
(7)In connection with the Company's notice of withdrawal from Block 11B/12B in South Africa in the second quarter of 2024, the Company derecogni zed $62 million ($47 million after-tax) of exploration and evaluation assets through depletion, depreciation and amortization expense.

Canadian Natural Resources Limited | 29 | Three and nine months ended September 30, 2025

Adjusted Funds Flow
Adjusted funds flow is a non-GAAP financial measure that represents cash flows from operating activities as presented in the Company's consolidated statements of cash flows adjusted for the net change in non-cash working capital, abandonment expenditures, and movements in other long-term assets. The Company considers adjusted funds flow a key measure in evaluating its performance, as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment, repay debt, and provide returns to shareholders through dividends and share buybacks. A reconciliation for adjusted funds flow from cash flows from operating activities is presented below.

| Three Months Ended |  |  | Nine Months Ended
($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Cash flows from operating activities |  | $ | 3,940 |  |  | $ | 3,114 |  |  | $ | 3,002 |  |  |  | $ | 11,338 |  |  | $ | 9,954 |
Net change in non-cash working capital |  | (432) |  |  | (24) |  |  | 680 |  |  |  | (538) |  |  | 180 |
Abandonment expenditures |  | 189 |  |  | 193 |  |  | 204 |  |  |  | 570 |  |  | 495 |
Movements in other long-term assets (1) |  | 223 |  |  | (21) |  |  | 35 |  |  |  | 342 |  |  | 44 |
Adjusted funds flow |  | $ | 3,920 |  |  | $ | 3,262 |  |  | $ | 3,921 |  |  |  | $ | 11,712 |  |  | $ | 10,673 |

(1)Includes the unamortized cost of contributions to the Company's employee bonus program, interest on PRT and corporate tax recoveries in the North Sea, and prepaid cost of service tolls.
Adjusted Net Earnings from Operations and Adjusted Funds Flow, Per Common Share (Basic and Diluted)
Adjusted net earnings from operations and adjusted funds flow, per common share (basic and diluted) are non-GAAP ratios that represent those non-GAAP measures divided by the weighted average number of basic and diluted common shares outstanding for the period, respectively, as presented in note 12 to the financial statements. These non-GAAP measures, disclosed on a per share basis, enable a comparison to the per share amounts disclosed in the Company's financial statements prepared in accordance with IFRS.
Netback
Netback is a non-GAAP ratio that represents net cash flows provided from core activities after the impact of all costs associated with bringing a product to market, on a per unit basis. The Company considers netback a key measure in evaluating its performance, as it demonstrates the efficiency and profitability of the Company's activities. Refer to the "Operating Highlights – Exploration and Production" section of this MD&A for the netback calculations on a per unit basis for crude oil and NGLs and on a total barrels of oil equivalent basis.
The netback calculations include the realized price non-GAAP financial measure which is reconciled below to its respective line item in note 15 to the financial statements.
During the first quarter of 2025, the Company revised its presentation of transportation expense and blending and feedstock costs, showing the expenses on a disaggregated basis in the consolidated statements of earnings. Previously the Company aggregated transportation, blending and feedstock. The revision provides users with more information to evaluate the Company’s performance. The financial statements and this MD&A have been updated for all periods presented. As a result, Transportation ($/BOE, $/bbl and $/Mcf) is no longer considered a non-GAAP ratio.

Canadian Natural Resources Limited | 30 | Three and nine months ended September 30, 2025

Realized Price ($/bbl and $/BOE) – Exploration and Production
Realized price ($/bbl and $/BOE) is a non-GAAP ratio calculated as realized crude oil and NGLs sales and total realized BOE sales (non-GAAP financial measures) divided by respective sales volumes. Realized crude oil and NGLs sales and total realized BOE sales is comprised of crude oil and NGLs sales and natural gas sales less blending and feedstock costs and other by-product sales, as disclosed in note 15 to the financial statements. The Company considers realized price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit the Company obtained on the market for its crude oil and NGLs sales volumes and BOE sales volumes.
Reconciliations for Exploration and Production realized crude oil and NGLs sales and BOE sales and the calculations for realized price are presented below.

| Three Months Ended |  |  | Nine Months Ended
($ millions, except bbl/d and $/bbl) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Crude oil and NGLs (bbl/d) |  |  |  |  |  |  |  |  |  |  |
North America |  | 577,089 |  |  | 551,248 |  |  | 479,889 |  |  |  | 563,561 |  |  | 494,674 |
International |  |  |  |  |  |  |  |  |  |  |
North Sea |  | 3,455 |  |  | 6,778 |  |  | 9,020 |  |  |  | 8,588 |  |  | 11,713 |
Offshore Africa |  | 2,313 |  |  | 500 |  |  | 20,450 |  |  |  | 4,588 |  |  | 12,129 |
Total International |  | 5,768 |  |  | 7,278 |  |  | 29,470 |  |  |  | 13,176 |  |  | 23,842 |
Total sales volumes |  | 582,857 |  |  | 558,526 |  |  | 509,359 |  |  |  | 576,737 |  |  | 518,516 |
Crude oil and NGLs sales (1) |  | $ | 4,773 |  |  | $ | 4,655 |  |  | $ | 4,653 |  |  |  | $ | 15,052 |  |  | $ | 14,642 |
Less: Blending and feedstock costs (2) |  | 883 |  |  | 1,119 |  |  | 946 |  |  |  | 3,393 |  |  | 3,466 |
Realized crude oil and NGLs sales |  | $ | 3,890 |  |  | $ | 3,536 |  |  | $ | 3,707 |  |  |  | $ | 11,659 |  |  | $ | 11,176 |
Realized price ($/bbl) |  | $ | 72.57 |  |  | $ | 69.58 |  |  | $ | 79.15 |  |  |  | $ | 74.06 |  |  | $ | 78.67 |

(1)Crude oil and NGLs sales in note 15 to the financial statements.
(2)Blending and feedstock costs in note 15 to the financial statements.

| Three Months Ended |  |  | Nine Months Ended
($ millions, except BOE/d and $/BOE) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Barrels of oil equivalent (BOE/d) |  |  |  |  |  |  |  |  |  |  |
North America |  | 1,020,062 |  |  | 950,888 |  |  | 819,606 |  |  |  | 979,903 |  |  | 843,074 |
International |  |  |  |  |  |  |  |  |  |  |
North Sea |  | 3,791 |  |  | 7,262 |  |  | 9,246 |  |  |  | 9,104 |  |  | 11,961 |
Offshore Africa |  | 3,661 |  |  | 1,585 |  |  | 22,021 |  |  |  | 5,999 |  |  | 13,809 |
Total International |  | 7,452 |  |  | 8,847 |  |  | 31,267 |  |  |  | 15,103 |  |  | 25,770 |
Total sales volumes |  | 1,027,514 |  |  | 959,735 |  |  | 850,873 |  |  |  | 995,006 |  |  | 868,844 |
Barrels of oil equivalent sales (1) |  | $ | 5,139 |  |  | $ | 5,221 |  |  | $ | 4,889 |  |  |  | $ | 16,674 |  |  | $ | 15,681 |
Less: Blending and feedstock costs (2) |  | 883 |  |  | 1,119 |  |  | 946 |  |  |  | 3,393 |  |  | 3,466 |
Less: Sulphur (income) expense |  | (28) |  |  | (18) |  |  | 2 |  |  |  | (55) |  |  | 6 |
Realized barrels of oil equivalent sales |  | $ | 4,284 |  |  | $ | 4,120 |  |  | $ | 3,941 |  |  |  | $ | 13,336 |  |  | $ | 12,209 |
Realized price ($/BOE) |  | $ | 45.31 |  |  | $ | 47.17 |  |  | $ | 50.36 |  |  |  | $ | 49.09 |  |  | $ | 51.29 |

(1)Barrels of oil equivalent sales includes crude oil and NGLs sales and natural gas sales in note 15 to the financial statements.
(2)Blending and feedstock costs in note 15 to the financial statements.

Canadian Natural Resources Limited | 31 | Three and nine months ended September 30, 2025

North America – Realized Product Prices and Royalties
Realized crude oil and NGLs price ($/bbl) is a non-GAAP ratio calculated as realized crude oil and NGLs sales (non-GAAP financial measure) divided by sales volumes. Realized crude oil and NGLs sales is comprised of crude oil and NGLs sales less blending and feedstock costs, as disclosed in note 15 to the financial statements. The Company considers the realized crude oil and NGLs price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its crude oil and NGLs sales volumes.
Crude oil and NGLs royalty rate is a non-GAAP ratio that is calculated as crude oil and NGLs royalties divided by realized crude oil and NGLs sales. The Company considers crude oil and NGLs royalty rate a key measure in evaluating its performance, as it describes the Company's royalties for crude oil and NGLs sales volumes on a per unit basis.
A reconciliation for North America realized crude oil and NGLs sales and the calculations for realized crude oil and NGLs prices and the royalty rates are presented below.

| Three Months Ended |  |  | Nine Months Ended
($ millions, except $/bbl and royalty rates) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Crude oil and NGLs sales (1) |  | $ | 4,724 |  |  | $ | 4,595 |  |  | $ | 4,357 |  |  |  | $ | 14,685 |  |  | $ | 13,910 |
Less: Blending and feedstock costs (2) |  | 883 |  |  | 1,119 |  |  | 946 |  |  |  | 3,393 |  |  | 3,466 |
Realized crude oil and NGLs sales |  | $ | 3,841 |  |  | $ | 3,476 |  |  | $ | 3,411 |  |  |  | $ | 11,292 |  |  | $ | 10,444 |
Realized crude oil and NGLs prices ($/bbl) |  | $ | 72.35 |  |  | $ | 69.30 |  |  | $ | 77.29 |  |  |  | $ | 73.40 |  |  | $ | 77.06 |
Crude oil and NGLs royalties (3) |  | $ | 702 |  |  | $ | 467 |  |  | $ | 694 |  |  |  | $ | 1,925 |  |  | $ | 2,095 |
Crude oil and NGLs royalty rates |  | 18% |  | 13% |  | 20% |  |  | 17% |  | 20%

(1)Crude oil and NGLs sales in note 15 to the financial statements.
(2)Blending and feedstock costs in note 15 to the financial statements.
(3)Item is a component of royalties in note 15 to the financial statements.
Realized Product Prices – Oil Sands Mining and Upgrading
Realized SCO sales price ($/bbl) is a non-GAAP ratio calculated as realized SCO sales (non-GAAP financial measure) divided by SCO sales volumes. Realized SCO sales is comprised of crude oil and NGLs sales less blending and feedstock costs, as disclosed in note 15 to the financial statements. The Company considers realized SCO sales price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its SCO sales volumes.
Reconciliations for Oil Sands Mining and Upgrading realized SCO sales and the calculation for realized SCO sales price on a per unit basis are presented below.

| Three Months Ended |  |  | Nine Months Ended
($ millions, except for bbl/d and $/bbl) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
SCO sales volumes (bbl/d) |  | 579,209 |  |  | 463,586 |  |  | 491,635 |  |  |  | 548,197 |  |  | 448,145 |
Crude oil and NGLs sales (1) |  | $ | 5,255 |  |  | $ | 4,023 |  |  | $ | 5,208 |  |  |  | $ | 15,157 |  |  | $ | 13,901 |
Less: Blending and feedstock costs (2) |  | 573 |  |  | 345 |  |  | 643 |  |  |  | 1,621 |  |  | 1,721 |
Realized SCO sales |  | $ | 4,682 |  |  | $ | 3,678 |  |  | $ | 4,565 |  |  |  | $ | 13,536 |  |  | $ | 12,180 |
Realized SCO sales price ($/bbl) |  | $ | 87.85 |  |  | $ | 87.22 |  |  | $ | 100.93 |  |  |  | $ | 90.45 |  |  | $ | 99.19 |

(1)Crude oil and NGLs sales in note 15 to the financial statements.
(2)Blending and feedstock costs in note 15 to the financial statements.

Canadian Natural Resources Limited | 32 | Three and nine months ended September 30, 2025

Change in Composition of Non-GAAP Financial Measure
During the fourth quarter of 2024, the Company revised the composition of its net capital expenditures non-GAAP financial measure to include acquisition capital related to a number of acquisitions for which agreements between parties have been reached. The inclusion of these acquisitions reflects the Company's estimate of its net capital expenditures at the time the 2025 budget was released. The composition of this measure has been updated to reflect the 2025 capital budget, but did not impact net capital expenditures in 2024.
Net Capital Expenditures
Net capital expenditures is a non-GAAP financial measure that represents cash flows used in investing activities as presented in the Company's consolidated statements of cash flows, adjusted for the net change in non-cash working capita l, net proceeds from investments, and cash flows from investing activities not included in the Company's capital budget. The Company includes acquisition and disposition capital for property, plant and equipment and exploration and evaluation assets in net capital expenditures at close of the transactions. The Company considers net capital expenditures a key measure in evaluating its performance, as it provides an understanding of the Company's capital spending activities in comparison to the Company's annual capital budget. A reconciliation of net capital expenditures is presented below.

| Three Months Ended |  |  | Nine Months Ended
($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Sep 30 2024 |  |  | Sep 30 2025 |  | Sep 30 2024
Cash flows used in investing activities |  | $ | 2,234 |  |  | $ | 1,941 |  |  | $ | 1,274 |  |  |  | $ | 5,487 |  |  | $ | 3,681 |
Net proceeds from investments |  | — |  |  | — |  |  | — |  |  |  | — |  |  | 575 |
Net change in non-cash working capital |  | (110) |  |  | (26) |  |  | 75 |  |  |  | (145) |  |  | (173) |
Net capital expenditures |  | 2,124 |  |  | 1,915 |  |  | 1,349 |  |  |  | 5,342 |  |  | 4,083 |
Abandonment expenditures |  | 189 |  |  | 193 |  |  | 204 |  |  |  | 570 |  |  | 495 |
Capital and abandonment expenditures |  | $ | 2,313 |  |  | $ | 2,108 |  |  | $ | 1,553 |  |  |  | $ | 5,912 |  |  | $ | 4,578 |

Liquidity
Liquidity is a non-GAAP financial measure that represents the availability of readily available undrawn bank credit facilities, cash and cash equivalents, and other highly liquid assets to meet short-term funding requirements and to assist in assessing the Company's financial position. The Company's calculation of liquidity is presented below.

($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Dec 31 2024 |  | Sep 30 2024
Undrawn bank credit facilities |  | $ | 4,201 |  |  | $ | 4,723 |  |  | $ | 4,562 |  |  | $ | 5,450 |
Cash and cash equivalents |  | 113 |  |  | 102 |  |  | 131 |  |  | 721 |
Liquidity |  | $ | 4,314 |  |  | $ | 4,825 |  |  | $ | 4,693 |  |  | $ | 6,171 |

Long-term Debt, net
Long‑term debt, net, is a capital management measure that represents long-term debt, including the current portion of long‑term debt, less cash and cash equivalents, as disclosed in note 11 to the financial statements. A reconciliation of long‑term debt, net is presented below.

($ millions) |  | Sep 30 2025 |  | Jun 30 2025 |  | Dec 31 2024 |  | Sep 30 2024 |  |  |  |  |
Long-term debt |  | $ | 17,268 |  |  | $ | 17,081 |  |  | $ | 18,819 |  |  | $ | 10,029 |  |  |  |  |  |
Less: cash and cash equivalents |  | 113 |  |  | 102 |  |  | 131 |  |  | 721 |  |  |  |  |  |
Long-term debt, net |  | $ | 17,155 |  |  | $ | 16,979 |  |  | $ | 18,688 |  |  | $ | 9,308 |  |  |  |  |  |

Canadian Natural Resources Limited | 33 | Three and nine months ended September 30, 2025

Debt to Book Capitalization
Debt to book capitalization is a capital management measure intended to enable financial statement users to evaluate the Company's capital structure, as disclosed in note 11 to the financial statements.
After-Tax Return on Average Capital Employed
After-tax return on average capital employed as defined by the Company is a non-GAAP ratio. The ratio is calculated as net earnings plus after-tax interest and other financing expense for the twelve month trailing period as a percentage of average capital employed (defined as current and long-term debt plus shareholders' equity) for the twelve month trailing period. The Company considers this ratio a key measure in evaluating the Company's ability to generate profit and the efficiency with which it employs capital. A reconciliation of the Company's after-tax return on average capital employed is presented below.

($ millions, except ratios) |  | Sep 30 2025 |  | Jun 30 2025 |  | Dec 31 2024 |  | Sep 30 2024 |  |  |
Interest adjusted after-tax return: |  |  |  |  |  |  |  |  |  |  |
Net earnings, 12 months trailing |  | $ | 6,655 |  |  | $ | 8,321 |  |  | $ | 6,106 |  |  | $ | 7,595 |  |  |  |
Interest and other financing expense, net of tax, 12 months trailing (1) |  | 561 |  |  | 608 |  |  | 454 |  |  | 435 |  |  |  |
Interest adjusted after-tax return |  | $ | 7,216 |  |  | $ | 8,929 |  |  | $ | 6,560 |  |  | $ | 8,030 |  |  |  |
12 months average current portion long-term debt (2) |  | $ | 1,529 |  |  | $ | 1,528 |  |  | $ | 1,525 |  |  | $ | 1,366 |  |  |  |
12 months average long-term debt (2) |  | 14,596 |  |  | 13,174 |  |  | 10,642 |  |  | 9,366 |  |  |  |
12 months average common shareholders' equity (2) |  | 40,314 |  |  | 40,115 |  |  | 39,635 |  |  | 39,668 |  |  |  |
12 months average capital employed |  | $ | 56,439 |  |  | $ | 54,817 |  |  | $ | 51,802 |  |  | $ | 50,400 |  |  |  |
After-tax return on average capital employed |  | 12.8% |  | 16.3% |  | 12.7% |  | 15.9% |  |  |

(1)The blended tax rate on interest was 23% for each of the periods presented.
(2)For the purpose of this non-GAAP ratio, the measurement of average current and long-term debt and common shareholders' equity are determined on a consistent basis, as an average of the opening and quarterly period end values for the 12 month trailing period for each of the periods presented.

Canadian Natural Resources Limited | 34 | Three and nine months ended September 30, 2025