CANADIAN NATURAL RESOURCES LIMITED

MANAGEMENT'S DISCUSSION & ANALYSIS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2025

AUGUST 6, 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, 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 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 uncertainty in the international trade environment, including with respect to tariffs, export restrictions, embargoes, and key trade agreements (including tariffs imposed or announced by the US government on certain goods and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded to additional goods); 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; 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

Canadian Natural Resources Limited 1 Three and six months ended June 30, 2025

structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.

The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state, and local laws and regulations such as restrictions on production, the imposition of tariffs, embargoes, or export restrictions on the Company's products (including tariffs imposed or announced by the US government on certain goods and actual or potential Canadian countermeasures, both of which continue to evolve and may be continued, suspended, increased, decreased, or expanded to additional goods), 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 six months ended June 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 six months ended June 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 six months ended June 30, 2025 in relation to the comparable periods in 2024 and the first 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 August 6, 2025.

Canadian Natural Resources Limited 2 Three and six months ended June 30, 2025

FINANCIAL HIGHLIGHTS

		Three Months Ended							Six Months Ended
($ millions, except per common share amounts)			Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Product sales (1)			$	9,675	$	12,712	$	10,622	$	22,387	$	20,044
Crude oil and NGLs			$	8,874	$	11,732	$	10,084	$	20,606	$	18,760
Natural gas			$	600	$	716	$	331	$	1,316	$	860
Net earnings			$	2,459	$	2,458	$	1,715	$	4,917	$	2,702
Per common share	– basic		$	1.17	$	1.17	$	0.80	$	2.34	$	1.26
	– diluted		$	1.17	$	1.17	$	0.80	$	2.34	$	1.25
Adjusted net earnings from operations (2)			$	1,496	$	2,436	$	1,892	$	3,932	$	3,366
Per common share	– basic (3)		$	0.71	$	1.16	$	0.89	$	1.88	$	1.57
	– diluted (3)		$	0.71	$	1.16	$	0.88	$	1.87	$	1.56
Cash flows from operating activities			$	3,114	$	4,284	$	4,084	$	7,398	$	6,952
Adjusted funds flow (2)			$	3,262	$	4,530	$	3,614	$	7,792	$	6,752
Per common share	– basic (3)		$	1.56	$	2.16	$	1.69	$	3.72	$	3.16
	– diluted (3)		$	1.55	$	2.15	$	1.68	$	3.70	$	3.13
Cash flows used in investing activities			$	1,941	$	1,312	$	1,015	$	3,253	$	2,407
Net capital expenditures (4)			$	1,915	$	1,303	$	1,621	$	3,218	$	2,734
Abandonment expenditures			$	193	$	188	$	129	$	381	$	291

(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. Refer 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

Net earnings for the six months ended June 30, 2025 were $4,917 million compared with $2,702 million for the six months ended June 30, 2024. Net earnings for the six months ended June 30, 2025 included non-operating income, net of tax, of $985 million compared with non-operating losses of $664 million for the six months ended June 30, 2024 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on financing activities, the gain from investments, the gain on acquisition, 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 six months ended June 30, 2025 were $3,932 million compared with $3,366 million for the six months ended June 30, 2024.

Net earnings for the second quarter of 2025 were $2,459 million compared with $1,715 million for the second quarter of 2024 and $2,458 million for the first quarter of 2025. Net earnings for the second quarter of 2025 included non-operating income, net of tax, of $963 million compared with non-operating losses of $177 million for the second quarter of 2024 and non-operating income of $22 million for the first 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 loss from investments, the gain on acquisition, 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 second quarter of 2025 were $1,496 million compared with $1,892 million for the second quarter of 2024 and $2,436 million for the first quarter of 2025.

Canadian Natural Resources Limited 3 Three and six months ended June 30, 2025

The movements in net earnings and adjusted net earnings from operations for the three and six months ended June 30, 2025 from the three and six months ended June 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 crude oil and NGLs realized pricing(1) in the North America Exploration and Production segment.

The movements in net earnings and adjusted net earnings from operations for the second quarter of 2025 from the first quarter of 2025 primarily reflected:

▪lower realized SCO pricing and sales volumes in the Oil Sands Mining and Upgrading segment, and

▪lower realized crude oil and NGLs pricing and 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 exchange (gain) loss, gain on acquisition, and the loss (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.

Cash Flows from Operating Activities and Adjusted Funds Flow

Cash flows from operating activities for the six months ended June 30, 2025 were $7,398 million compared with $6,952 million for the six months ended June 30, 2024. Cash flows from operating activities for the second quarter of 2025 were $3,114 million compared with $4,084 million for the second quarter of 2024 and $4,284 million for the first 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 six months ended June 30, 2025 was $7,792 million compared with $6,752 million for the six months ended June 30, 2024. Adjusted funds flow for the second quarter of 2025 was $3,262 million compared with $3,614 million for the second quarter of 2024 and $4,530 million for the first 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, accrued interest on Petroleum Revenue Tax ("PRT") recoveries, and prepaid cost of service tolls.

Production Volumes

Crude oil and NGLs production before royalties for the second quarter of 2025 of 1,019,149 bbl/d increased 9% from 934,066 bbl/d for the second quarter of 2024 and decreased 13% from 1,173,804 bbl/d for the first quarter of 2025. Natural gas production before royalties for the second quarter of 2025 of 2,407 MMcf/d increased 14% from 2,110 MMcf/d for the second quarter of 2024 and was comparable with 2,451 MMcf/d for the first quarter of 2025. Total production before royalties for the second quarter of 2025 of 1,420,358 BOE/d increased 10% from 1,285,798 BOE/d for the second quarter of 2024 and decreased 10% from 1,582,348 BOE/d for the first 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 averaged $69.58 per bbl for the second quarter of 2025, a decrease of 20% from $86.64 per bbl for the second quarter of 2024 and a decrease of 13% from $79.85 per bbl for the first quarter of 2025. The realized natural gas price increased 62% to average $2.58 per Mcf for the second quarter of 2025 from $1.59 per Mcf for the second quarter of 2024 and decreased 18% from $3.13 per Mcf for the first quarter of 2025. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price decreased 20% to average $87.22 per bbl for the second quarter of 2025 from $108.81 per bbl for the second quarter of 2024 and decreased 9% from $95.52 per bbl for the first 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 "Oil Sands Mining and Upgrading" sections of this MD&A.

(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited 4 Three and six months ended June 30, 2025

Production Expense

In the Company's Exploration and Production segments, crude oil and NGLs production expense(1) averaged $14.03 per bbl for the second quarter of 2025, a decrease of 4% from $14.54 per bbl for the second quarter of 2024 and a decrease of 11% from $15.74 per bbl for the first quarter of 2025. Natural gas production expense(1) averaged $1.11 per Mcf for the second quarter of 2025, a decrease of 8% from $1.21 per Mcf for the second quarter of 2024 and a decrease of 8% from $1.20 per Mcf for the first quarter of 2025. In the Oil Sands Mining and Upgrading segment, production expense(1)averaged $26.53 per bbl for the second quarter of 2025, comparable with $25.95 per bbl for the second quarter of 2024 and an increase of 21% from $21.88 per bbl for the first 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 "Oil Sands Mining and Upgrading" sections of this MD&A.

SUMMARY OF QUARTERLY FINANCIAL RESULTS

The following is a summary of the Company's quarterly financial results for the eight most recently completed quarters:

($ millions, except per common share amounts)	Jun 30 2025		Mar 31 2025		Dec 31 2024		Sep 30 2024
Product sales (1)	$	9,675	$	12,712	$	11,064	$	10,401
Crude oil and NGLs	$	8,874	$	11,732	$	10,381	$	9,943
Natural gas	$	600	$	716	$	451	$	257
Net earnings	$	2,459	$	2,458	$	1,138	$	2,266
Net earnings per common share
– basic	$	1.17	$	1.17	$	0.54	$	1.07
– diluted	$	1.17	$	1.17	$	0.54	$	1.06
($ millions, except per common share amounts)	Jun 30 2024		Mar 31 2024		Dec 31 2023		Sep 30 2023
Product sales (1)	$	10,622	$	9,422	$	10,679	$	11,762
Crude oil and NGLs	$	10,084	$	8,676	$	9,829	$	10,944
Natural gas	$	331	$	529	$	603	$	599
Net earnings	$	1,715	$	987	$	2,627	$	2,344
Net earnings per common share (2)
– basic	$	0.80	$	0.46	$	1.22	$	1.08
– diluted	$	0.80	$	0.46	$	1.21	$	1.06

(1)Further details related to product sales for the three months ended June 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.

(1)Calculated as respective production expense divided by respective sales volumes.

Canadian Natural Resources Limited 5 Three and six months ended June 30, 2025

▪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 acquisitions, including the acquisition of working interests in AOSP and Duvernay assets in the fourth quarter of 2024, 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, natural field decline rates, the impact of seasonal conditions, and wildfires in the North America Exploration and Production segment.

▪Production expense – Fluctuations primarily due to the impacts of the demand and cost for services, fluctuations in product mix and production volumes, seasonal conditions, increased carbon tax, fluctuating energy costs, inflationary cost pressures, cost optimizations across all segments, turnarounds in the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments.

▪Depletion, depreciation and amortization expense – Fluctuations due to changes in sales volumes, timing of acquisitions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, fluctuations in International sales volumes subject to higher depletion rates, the impact of turnarounds in the Oil Sands Mining and Upgrading segment, a recoverability charge at December 31, 2024 and December 31, 2023 relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea, and a recoverability charge at June 30, 2024 relating to the notice to withdraw from Block 11B/12B in South Africa.

▪Share-based compensation – Fluctuations due to the measurement of fair market value of the Company's share-based compensation liability.

▪Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company's risk management activities.

▪Interest expense – Fluctuations due to changing long-term debt levels, the impact of movements in benchmark interest rates on outstanding floating rate long-term debt, and accrued interest on PRT recoveries.

▪Foreign exchange – Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company receives for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar denominated debt and working capital.

BUSINESS ENVIRONMENT

Global crude oil benchmark pricing declined through the second quarter of 2025, driven by demand outlook concerns due to ongoing tariff and trade uncertainty and the impact of larger than expected OPEC+ output hikes. Crude oil benchmark price volatility provided pricing support in the latter half of the quarter as escalating tensions in the Middle East led to concerns of supply disruptions. Natural gas benchmark pricing remained stable in the second quarter of 2025. In Canada, the start-up of LNG Canada, which began exporting cargoes at the outset of the third quarter of 2025, will provide additional market egress and is expected to support AECO benchmark pricing.

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 June 30, 2025, the Company had undrawn revolving bank credit facilities of $4,723 million. Including cash and cash equivalents, the Company had approximately $4,825 million in liquidity(1). The Company also has certain other dedicated credit facilities supporting letters of credit. The Company remains committed to maintaining a strong balance sheet, adequate available liquidity, and a flexible capital structure. Refer to the "Liquidity and Capital Resources" section of this MD&A for further details.

(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited 6 Three and six months ended June 30, 2025

Benchmark Commodity Prices

	Three Months Ended							Six Months Ended
(Average for the period)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
WTI benchmark price (US$/bbl)		$	63.71	$	71.42	$	80.55	$	67.55	$	78.76
Dated Brent benchmark price (US$/bbl)		$	67.78	$	75.68	$	84.90	$	71.71	$	84.07
WCS Heavy Differential from WTI (US$/bbl)		$	10.19	$	12.66	$	13.54	$	11.42	$	16.44
SCO price (US$/bbl)		$	64.69	$	69.07	$	83.33	$	66.87	$	76.38
Condensate benchmark price (US$/bbl)		$	63.42	$	69.89	$	77.11	$	66.64	$	74.95
NYMEX benchmark price (US$/MMBtu)		$	3.44	$	3.66	$	1.89	$	3.55	$	2.06
AECO benchmark price (C$/GJ)		$	1.97	$	1.92	$	1.36	$	1.94	$	1.65
US/Canadian dollar average exchange rate (US$)		$	0.7225	$	0.6969	$	0.7308	$	0.7096	$	0.7360

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$67.55 per bbl for the six months ended June 30, 2025, a decrease of 14% from US$78.76 per bbl for the six months ended June 30, 2024. WTI averaged US$63.71 per bbl for the second quarter of 2025, a decrease of 21% from US$80.55 per bbl for the second quarter of 2024 and a decrease of 11% from US$71.42 per bbl for the first 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$71.71 per bbl for the six months ended June 30, 2025, a decrease of 15% from US$84.07 per bbl for the six months ended June 30, 2024. Brent averaged US$67.78 per bbl for the second quarter of 2025, a decrease of 20% from US$84.90 per bbl for the second quarter of 2024 and a decrease of 10% from US$75.68 per bbl for the first quarter of 2025.

The decrease in WTI and Brent benchmark pricing for the three and six months ended June 30, 2025 from the comparable periods reflected weaker global demand outlooks amid ongoing tariff and trade uncertainty, combined with larger than expected OPEC+ output hikes in the second quarter of 2025.

The WCS Heavy Differential averaged US$11.42 per bbl for the six months ended June 30, 2025, compared with US$16.44 per bbl for the six months ended June 30, 2024. The WCS Heavy Differential averaged US$10.19 per bbl for the second quarter of 2025, compared with US$13.54 per bbl for the second quarter of 2024 and US$12.66 per bbl for the first quarter of 2025. The narrowing of the WCS Heavy Differential for the six months ended June 30, 2025 from the six months ended June 30, 2024 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 second quarter of 2025 from the comparable periods primarily reflected production impacts in the Western Canadian Sedimentary Basin ("WCSB") as a result of maintenance activities and shut-in production from wildfires that occurred in the second quarter of 2025.

The SCO price averaged US$66.87 per bbl for the six months ended June 30, 2025, a decrease of 12% from US$76.38 per bbl for the six months ended June 30, 2024. The SCO price averaged US$64.69 per bbl for the second quarter of 2025, a decrease of 22% from US$83.33 per bbl for the second quarter of 2024 and a decrease of 6% from US$69.07 per bbl for the first quarter of 2025. The decrease in SCO pricing for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected weaker WTI benchmark pricing. The decrease in SCO pricing for the second quarter of 2025 from the first quarter of 2025 primarily reflected weaker WTI benchmark pricing, partially offset by the SCO differential strengthening due to lower production levels in the WCSB as a result of maintenance activities that took place in the second quarter of 2025.

Canadian Natural Resources Limited 7 Three and six months ended June 30, 2025

NYMEX benchmark pricing averaged US$3.55 per MMBtu for the six months ended June 30, 2025, an increase of 72% from US$2.06 per MMBtu for the six months ended June 30, 2024. NYMEX benchmark pricing averaged US$3.44 per MMBtu for the second quarter of 2025, an increase of 82% from US$1.89 per MMBtu for the second quarter of 2024 and a decrease of 6% from US$3.66 per MMBtu for the first quarter of 2025. The increase in NYMEX natural gas prices for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected lower US inventory levels following cold weather conditions in the first quarter of 2025, combined with higher LNG exports out of the US Gulf Coast in 2025. The decrease in NYMEX natural gas pricing for the second quarter of 2025 from the first quarter of 2025 primarily reflected reduced LNG exports from the US Gulf Coast due to maintenance activities, as well as seasonal demand factors.

AECO benchmark pricing averaged $1.94 per GJ for the six months ended June 30, 2025, an increase of 18% from $1.65 per GJ for the six months ended June 30, 2024. AECO benchmark pricing averaged $1.97 per GJ for the second quarter of 2025, an increase of 45% from $1.36 per GJ for the second quarter of 2024 and comparable with $1.92 per GJ for the first quarter of 2025. The increase in AECO natural gas prices for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected stronger NYMEX benchmark pricing, combined with increased exports out of the WCSB.

DAILY PRODUCTION, before royalties

	Three Months Ended			Six Months Ended
	Jun 30 2025	Mar 31 2025	Jun 30 2024	Jun 30 2025	Jun 30 2024
Crude oil and NGLs (bbl/d)
North America – Exploration and Production	545,811	561,238	499,636	553,482	502,636
North America – Oil Sands Mining and Upgrading (1)	463,808	595,116	410,518	529,099	427,863
International – Exploration and Production
North Sea	7,761	11,507	11,295	9,623	11,864
Offshore Africa	1,769	5,943	12,617	3,845	12,503
Total International (2)	9,530	17,450	23,912	13,468	24,367
Total Crude oil and NGLs	1,019,149	1,173,804	934,066	1,096,049	954,866
Natural gas (MMcf/d) (3)
North America	2,398	2,436	2,099	2,417	2,117
International
North Sea	3	4	2	4	2
Offshore Africa	6	11	9	8	10
Total International	9	15	11	12	12
Total Natural gas	2,407	2,451	2,110	2,429	2,129
Total Barrels of oil equivalent (BOE/d)	1,420,358	1,582,348	1,285,798	1,500,905	1,309,649
Product mix
Light and medium crude oil and NGLs	11%	10%	10%	10%	10%
Pelican Lake heavy crude oil	3%	3%	4%	3%	3%
Primary heavy crude oil	6%	5%	6%	6%	6%
Bitumen (thermal oil)	19%	18%	21%	19%	21%
Synthetic crude oil (1)	33%	38%	32%	35%	33%
Natural gas	28%	26%	27%	27%	27%
Percentage of product sales(1) (4) (5)
Crude oil and NGLs	93%	94%	97%	93%	95%
Natural gas	7%	6%	3%	7%	5%

(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 8 Three and six months ended June 30, 2025

DAILY PRODUCTION, net of royalties

	Three Months Ended			Six Months Ended
	Jun 30 2025	Mar 31 2025	Jun 30 2024	Jun 30 2025	Jun 30 2024
Crude oil and NGLs (bbl/d)
North America – Exploration and Production	472,329	455,307	394,025	463,865	403,888
North America – Oil Sands Mining and Upgrading (1)	397,052	480,227	332,272	438,410	351,554
International – Exploration and Production
North Sea	7,746	11,493	11,270	9,609	11,838
Offshore Africa	1,692	5,685	12,057	3,678	11,906
Total International	9,438	17,178	23,327	13,287	23,744
Total Crude oil and NGLs	878,819	952,712	749,624	915,562	779,186
Natural gas (MMcf/d)
North America	2,325	2,348	2,077	2,336	2,063
International
North Sea	3	4	2	4	2
Offshore Africa	6	11	9	8	10
Total International	9	15	11	12	12
Total Natural gas	2,334	2,363	2,088	2,348	2,075
Total Barrels of oil equivalent (BOE/d)	1,267,787	1,346,536	1,097,693	1,306,945	1,124,974

(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 six months ended June 30, 2025 averaged 1,096,049 bbl/d, an increase of 15% from 954,866 bbl/d for the six months ended June 30, 2024. Crude oil and NGLs production before royalties for the second quarter of 2025 averaged 1,019,149 bbl/d, an increase of 9% from 934,066 bbl/d for the second quarter of 2024 and a decrease of 13% from 1,173,804 bbl/d for the first quarter of 2025. The increase in crude oil and NGLs production before royalties for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024, strong utilization in the Oil Sands Mining and Upgrading segment, and thermal oil pad additions and strong drilling results in the North America Exploration and Production segment. The decrease in crude oil and NGLs production before royalties for the second quarter of 2025 from the first quarter of 2025 primarily reflected the planned turnaround at the non-operated Scotford Upgrader ("Scotford") successfully completed in the second quarter of 2025.

Annual crude oil and NGLs production for 2025 is targeted to average between 1,106,000 bbl/d and 1,142,000 bbl/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Natural gas production before royalties for the six months ended June 30, 2025 averaged 2,429 MMcf/d, an increase of 14% from 2,129 MMcf/d for the six months ended June 30, 2024. Natural gas production before royalties for the second quarter of 2025 averaged 2,407 MMcf/d, an increase of 14% from 2,110 MMcf/d for the second quarter of 2024 and comparable with 2,451 MMcf/d for the first quarter of 2025. The increase in natural gas production before royalties for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024 and strong drilling results, partially offset by natural field declines.

Annual natural gas production for 2025 is targeted to average between 2,425 MMcf/d and 2,480 MMcf/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Canadian Natural Resources Limited 9 Three and six months ended June 30, 2025

North America – Exploration and Production

North America crude oil and NGLs production before royalties for the six months ended June 30, 2025 averaged 553,482 bbl/d, an increase of 10% from 502,636 bbl/d for the six months ended June 30, 2024. North America crude oil and NGLs production before royalties for the second quarter of 2025 of 545,811 bbl/d increased 9% from 499,636 bbl/d for the second quarter of 2024 and decreased 3% from 561,238 bbl/d for the first quarter of 2025. The increase in North America crude oil and NGLs production for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024, thermal pad additions at Primrose, and strong drilling results from heavy oil multilaterals, liquids-rich natural gas, and light oil, partially offset by natural field declines. The decrease in North America crude oil and NGLs production for the second quarter of 2025 from the first quarter of 2025 primarily reflected maintenance activities, the impact of wildfires, and natural field declines.

The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 274,789 bbl/d for the second quarter of 2025, an increase of 3% from 268,044 bbl/d for the second quarter of 2024 and a decrease of 3% from 284,706 bbl/d for the first quarter of 2025. The increase in thermal in situ production in the second quarter of 2025 from the second quarter of 2024 primarily reflected pad additions at Primrose, partially offset by natural field declines. The decrease in thermal in situ production in the second quarter of 2025 from the first quarter of 2025 primarily reflected natural field declines and the impact of wildfires.

Pelican Lake heavy crude oil production before royalties for the second quarter of 2025 averaged 43,078 bbl/d, a decrease of 4% from 44,839 bbl/d for the second quarter of 2024 reflecting Pelican Lake's long life low decline production, and comparable with 43,175 bbl/d for the first quarter of 2025.

North America natural gas production before royalties for the six months ended June 30, 2025 averaged 2,417 MMcf/d, an increase of 14% from 2,117 MMcf/d for the six months ended June 30, 2024. Natural gas production before royalties averaged 2,398 MMcf/d for the second quarter of 2025, an increase of 14% from 2,099 MMcf/d for the second quarter of 2024 and comparable with 2,436 MMcf/d for the first quarter of 2025. The increase in natural gas production for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024 and strong drilling results, partially offset by natural field declines.

North America – Oil Sands Mining and Upgrading

SCO production before royalties for the six months ended June 30, 2025 averaged 529,099 bbl/d, an increase of 24% from 427,863 bbl/d for the six months ended June 30, 2024. SCO production before royalties for the second quarter of 2025 averaged 463,808 bbl/d, an increase of 13% from 410,518 bbl/d for the second quarter of 2024 and a decrease of 22% from 595,116 bbl/d for the first quarter of 2025. The increase in SCO production for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the acquisition in December 2024, combined with strong performance and utilization at both Horizon and AOSP. The increase in SCO production for the second quarter of 2025 from the second quarter of 2024 also reflected the turnaround at Horizon in the second quarter of 2024, partially offset by the planned turnaround at Scotford completed in the second quarter of 2025. The decrease for the second quarter of 2025 from the first quarter of 2025 primarily reflected the turnaround at Scotford.

International – Exploration and Production

International crude oil and NGLs production before royalties for the six months ended June 30, 2025 averaged 13,468 bbl/d, a decrease of 45% from 24,367 bbl/d for the six months ended June 30, 2024. International crude oil and NGLs production before royalties for the second quarter of 2025 averaged 9,530 bbl/d, a decrease of 60% from 23,912 bbl/d for the second quarter of 2024 and a decrease of 45% from 17,450 bbl/d for the first quarter of 2025. The decrease in International crude oil and NGLs production for the three and six months ended June 30, 2025 from the comparable periods primarily reflected 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, maintenance activities in the North Sea in the second quarter of 2025, planned North Sea abandonments conducted as part of the previously announced decommissioning plans, and natural field declines.

Canadian Natural Resources Limited 10 Three and six months ended June 30, 2025

OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION

	Three Months Ended							Six Months Ended
		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Crude oil and NGLs ($/bbl) (1)
Realized price (2)		$	69.58	$	79.85	$	86.64	$	74.82	$	78.43
Transportation (3)		7.65		6.40		5.98		7.01		5.31
Realized price, net of transportation (2)		61.93		73.45		80.66		67.81		73.12
Royalties (4)		9.20		14.36		17.45		11.83		14.80
Production expense (5)		14.03		15.74		14.54		14.90		15.59
Netback (2)		$	38.70	$	43.35	$	48.67	$	41.08	$	42.73
Natural gas ($/Mcf) (1)
Realized price (6)		$	2.58	$	3.13	$	1.59	$	2.86	$	2.07
Transportation (3)		0.59		0.63		0.63		0.61		0.63
Realized price, net of transportation		1.99		2.50		0.96		2.25		1.44
Royalties (4)		0.08		0.11		0.02		0.10		0.06
Production expense (5)		1.11		1.20		1.21		1.15		1.26
Netback (7)		$	0.80	$	1.19	$	(0.27)	$	1.00	$	0.12
Barrels of oil equivalent ($/BOE) (1)
Realized price (2)		$	47.17	$	54.95	$	55.84	$	51.11	$	51.74
Transportation (3)		5.94		5.34		5.09		5.63		4.71
Realized price, net of transportation (2)		41.23		49.61		50.75		45.48		47.03
Royalties (4)		5.58		8.76		10.53		7.19		8.97
Production expense (5)		10.95		12.23		11.64		11.60		12.33
Netback (2)		$	24.70	$	28.62	$	28.58	$	26.69	$	25.73

(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 11 Three and six months ended June 30, 2025

REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION

	Three Months Ended							Six Months Ended
		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Crude oil and NGLs ($/bbl) (1)
North America (2)		$	69.30	$	78.56	$	85.49	$	73.95	$	76.94
International average (3)		$	91.00	$	107.04	$	115.27	$	103.58	$	114.08
North Sea (3)		$	90.63	$	107.57	$	115.02	$	102.41	$	114.37
Offshore Africa (3)		$	95.92	$	106.30	$	115.67	$	105.85	$	113.59
Crude oil and NGLs average (2)		$	69.58	$	79.85	$	86.64	$	74.82	$	78.43
Natural gas ($/Mcf) (1) (3)
North America		$	2.54	$	3.06	$	1.53	$	2.80	$	2.02
International average		$	11.71	$	14.46	$	11.87	$	13.40	$	12.01
North Sea		$	10.00	$	16.43	$	9.79	$	13.86	$	10.58
Offshore Africa		$	12.47	$	13.65	$	12.24	$	13.20	$	12.23
Natural gas average		$	2.58	$	3.13	$	1.59	$	2.86	$	2.07
Average ($/BOE)(1) (2)		$	47.17	$	54.95	$	55.84	$	51.11	$	51.74

(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.

(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

(3)Calculated as crude oil and NGLs sales, and natural gas sales divided by respective sales volumes.

North America

North America realized crude oil and NGLs prices decreased 4% to average $73.95 per bbl for the six months ended June 30, 2025 from $76.94 per bbl for the six months ended June 30, 2024. North America realized crude oil and NGLs prices averaged $69.30 per bbl for the second quarter of 2025, a decrease of 19% from $85.49 per bbl for the second quarter of 2024 and a decrease of 12% from $78.56 per bbl for the first quarter of 2025. The decrease in North America realized crude oil and NGLs prices per bbl for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected lower WTI benchmark pricing, partially offset by a narrowing of the WCS Heavy Differential. The decrease in North America realized crude oil and NGLs prices per bbl for the second quarter of 2025 from the first quarter of 2025primarily reflected lower WTI benchmark pricing. 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 second quarter of 2025 contributed approximately 210,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices increased 39% to average $2.80 per Mcf for the six months ended June 30, 2025 from $2.02 per Mcf for the six months ended June 30, 2024. North America realized natural gas prices increased 66% to average $2.54 per Mcf for the second quarter of 2025 from $1.53 per Mcf for the second quarter of 2024 and decreased 17% from $3.06 per Mcf for the first quarter of 2025. The increase in North America realized natural gas prices per Mcf for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher benchmark pricing. The decrease for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower export pricing.

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

	Three Months Ended
(Quarterly average)		Jun 30 2025		Mar 31 2025		Jun 30 2024
Wellhead Price (1)
Light and medium crude oil and NGLs ($/bbl)		$	63.96	$	76.47	$	74.90
Pelican Lake heavy crude oil ($/bbl)		$	73.94	$	83.57	$	92.42
Primary heavy crude oil ($/bbl)		$	72.88	$	81.76	$	91.27
Bitumen (thermal oil) ($/bbl)		$	70.13	$	77.96	$	86.84
Natural gas ($/Mcf)		$	2.54	$	3.06	$	1.53

(1)Amounts expressed on a per unit basis are based on sales volumes of the respective product type.

Canadian Natural Resources Limited 12 Three and six months ended June 30, 2025

International

International realized crude oil and NGLs prices decreased 9% to average $103.58 per bbl for the six months ended June 30, 2025 from $114.08 per bbl for the six months ended June 30, 2024. International realized crude oil and NGLs prices decreased 21% to average $91.00 per bbl for the second quarter of 2025 from $115.27 per bbl for the second quarter of 2024 and decreased 15% from $107.04 per bbl for the first 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 timing of liftings from each field, and prevailing Brent benchmark prices and foreign exchange rates at the time of lifting.

ROYALTIES – EXPLORATION AND PRODUCTION

	Three Months Ended							Six Months Ended
		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Crude oil and NGLs ($/bbl) (1)
North America		$	9.31	$	14.94	$	18.06	$	12.14	$	15.33
International average		$	0.45	$	1.99	$	2.11	$	1.65	$	2.20
North Sea		$	0.17	$	0.14	$	0.24	$	0.15	$	0.24
Offshore Africa		$	4.19	$	4.61	$	5.14	$	4.59	$	5.43
Crude oil and NGLs average		$	9.20	$	14.36	$	17.45	$	11.83	$	14.80
Natural gas ($/Mcf) (1)
North America		$	0.08	$	0.11	$	0.02	$	0.09	$	0.06
Offshore Africa		$	0.57	$	0.63	$	0.56	$	0.61	$	0.56
Natural gas average		$	0.08	$	0.11	$	0.02	$	0.10	$	0.06
Average ($/BOE) (1)		$	5.58	$	8.76	$	10.53	$	7.19	$	8.97

(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 six months ended June 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 approximately 16% of product sales for the six months ended June 30, 2025 compared with 20% of product sales for the six months ended June 30, 2024. Crude oil and NGLs royalty rates averaged approximately 13% of product sales for the second quarter of 2025 compared with 21% for the second quarter of 2024 and 19% for the first quarter of 2025. The decrease in royalty rates for the three and six months ended June 30, 2025 from the comparable periods primarily reflected prevailing benchmark pricing and the impact of sliding scale royalty rates.

Natural gas royalty rates averaged approximately 3% of product sales for the six months ended June 30, 2025 compared with 3% of product sales for the six months ended June 30, 2024. Natural gas royalty rates averaged approximately 3% of product sales for the second quarter of 2025 compared with 1% for the second quarter of 2024 and 4% for the first quarter of 2025. The fluctuations in royalty rates for the second quarter of 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 approximately 4% for the six months ended June 30, 2025 compared with 5% of product sales for the six months ended June 30, 2024. Royalty rates as a percentage of product sales averaged approximately 5% for the second quarter of 2025 compared with 4% of product sales for the second quarter of 2024 and 4% for the first 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.

(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited 13 Three and six months ended June 30, 2025

PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION

	Three Months Ended							Six Months Ended
		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Crude oil and NGLs ($/bbl) (1)
North America		$	11.89	$	12.65	$	12.44	$	12.28	$	13.56
International average		$	175.70	$	80.63	$	66.83	$	101.16	$	64.00
North Sea		$	186.50	$	117.56	$	96.07	$	138.54	$	90.67
Offshore Africa		$	29.38	$	28.26	$	19.28	$	28.31	$	20.00
Crude oil and NGLs average		$	14.03	$	15.74	$	14.54	$	14.90	$	15.59
Natural gas ($/Mcf) (1)
North America		$	1.07	$	1.16	$	1.19	$	1.11	$	1.23
International average		$	12.20	$	7.60	$	6.51	$	9.37	$	6.08
North Sea		$	12.78	$	10.52	$	7.72	$	11.42	$	8.16
Offshore Africa		$	11.94	$	6.42	$	6.30	$	8.51	$	5.77
Natural gas average		$	1.11	$	1.20	$	1.21	$	1.15	$	1.26
Average ($/BOE) (1)		$	10.95	$	12.23	$	11.64	$	11.60	$	12.33

(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 six months ended June 30, 2025 averaged $12.28 per bbl, a decrease of 9% from $13.56 per bbl for the six months ended June 30, 2024. North America crude oil and NGLs production expense for the second quarter of 2025 of $11.89 per bbl decreased 4% from $12.44 per bbl for the second quarter of 2024 and decreased 6% from $12.65 per bbl for the first quarter of 2025. The decrease in crude oil and NGLs production expense per bbl for the six months ended June 30, 2025 from the six months ended June 30, 2024 primarily reflected higher production volumes. The decrease in crude oil and NGLs production expense per bbl for the second quarter of 2025 from the second quarter of 2024 primarily reflected higher production volumes, partially offset by higher energy costs. The decrease in crude oil and NGLs production expense per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower energy costs.

North America natural gas production expense for the six months ended June 30, 2025 averaged $1.11 per Mcf, a decrease of 10% from $1.23 per Mcf for the six months ended June 30, 2024. North America natural gas production expense for the second quarter of 2025 of $1.07 per Mcf decreased 10% from $1.19 per Mcf for the second quarter of 2024 and decreased 8% from $1.16 per Mcf for the first quarter of 2025. The decrease in natural gas production expense per Mcf for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher production volumes. The decrease in natural gas production expense per Mcf for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower energy costs.

International

International crude oil and NGLs production expense for the six months ended June 30, 2025 averaged $101.16 per bbl, an increase of 58% from $64.00 per bbl for the six months ended June 30, 2024. International crude oil and NGLs production expense for the second quarter of 2025 of $175.70 per bbl increased 163% from $66.83 per bbl for the second quarter of 2024 and increased 118% from $80.63 per bbl for the first quarter of 2025. The increase in crude oil and NGLs production expense per bbl for the three and six months ended June 30, 2025 from the comparable periods 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.

Canadian Natural Resources Limited 14 Three and six months ended June 30, 2025

ADJUSTED DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION

	Three Months Ended							Six Months Ended
($ millions, except per BOE amounts)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
North America		$	1,085	$	1,092	$	956	$	2,177	$	1,897
North Sea		33		40		24		73		41
Offshore Africa		13		59		108		72		155
Depletion, depreciation and amortization		$	1,131	$	1,191	$	1,088	$	2,322	$	2,093
Less: Recoverability charge (1)		—		—		62		—		62
Adjusted depletion, depreciation and amortization (2)		$	1,131	$	1,191	$	1,026	$	2,322	$	2,031
$/BOE (3)		$	12.94	$	13.27	$	12.77	$	13.11	$	12.71

(1)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.

(2)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.

(3)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 six months ended June 30, 2025 averaged $13.11 per BOE, an increase of 3% from $12.71 per BOE for the six months ended June 30, 2024. Adjusted depletion, depreciation and amortization expense for the second quarter of 2025 averaged $12.94 per BOE, comparable with $12.77 per BOE for the second quarter of 2024 and $13.27 per BOE for the first quarter of 2025. The increase in adjusted depletion, depreciation and amortization expense per BOE for the six months ended June 30, 2025 from the six months ended June 30, 2024 primarily reflected the impact of changes in North America depletion rates due to changes in reserve estimates at December 31, 2024, combined with a higher depletable base due to asset additions, partially offset by higher sales volumes.

Adjusted depletion, depreciation and amortization expense on an absolute and per BOE basis also reflects the impact of the timing of liftings from each field in the North Sea and Offshore Africa.

ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION

	Three Months Ended							Six Months Ended
($ millions, except per BOE amounts)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
North America		$	53	$	53	$	57	$	106	$	115
North Sea		14		14		16		28		32
Offshore Africa		2		2		2		4		4
Asset retirement obligation accretion		$	69	$	69	$	75	$	138	$	151
$/BOE (1)		$	0.79	$	0.77	$	0.95	$	0.78	$	0.95

(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 six months ended June 30, 2025 averaged $0.78 per BOE, a decrease of 18% from $0.95 per BOE for the six months ended June 30, 2024. Asset retirement obligation accretion expense for the second quarter of 2025 averaged $0.79 per BOE, a decrease of 17% from $0.95 per BOE for the second quarter of 2024 and comparable with $0.77 per BOE for the first quarter of 2025. The decrease in asset retirement obligation accretion expense per BOE for the three and six months ended June 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.

Canadian Natural Resources Limited 15 Three and six months ended June 30, 2025

OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING

The Company continues to focus on safe, reliable, and efficient operations, leveraging its technical expertise across the Horizon and AOSP sites. SCO production averaged 463,808 bbl/d in the second quarter of 2025 primarily reflecting the planned turnaround at Scotford completed during the quarter.

REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING

	Three Months Ended							Six Months Ended
($/bbl)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Realized SCO sales price (1)		$	87.22	$	95.52	$	108.81	$	91.88	$	98.18
Bitumen value for royalty purposes (2)		$	64.57	$	73.72	$	82.08	$	69.61	$	72.66
Bitumen royalties (3)		$	11.59	$	18.22	$	20.01	$	15.32	$	16.96
Transportation (4)		$	3.73	$	3.21	$	2.81	$	3.44	$	2.21

(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 averaged $91.88 per bbl for the six months ended June 30, 2025, a decrease of 6% from $98.18 per bbl for the six months ended June 30, 2024. The realized SCO sales price averaged $87.22 per bbl for the second quarter of 2025, a decrease of 20% from $108.81 per bbl for the second quarter of 2024 and a decrease of 9% from $95.52 per bbl for the first quarter of 2025. The decrease in realized SCO sales price per bbl for the three and six months ended June 30, 2025 from the comparable periods primarily reflected lower WTI benchmark pricing.

The fluctuations in bitumen royalties per bbl in any particular period reflect prevailing bitumen pricing for royalty purposes, and the impact of sliding scale royalty rates. The decrease in bitumen royalties per bbl for the three and six months ended June 30, 2025 from the comparable periods primarily reflected the decrease in average bitumen pricing for royalty purposes.

Transportation expense averaged $3.44 per bbl for the six months ended June 30, 2025, an increase of 56% from $2.21 per bbl for the six months ended June 30, 2024. Transportation expense averaged $3.73 per bbl for the second quarter of 2025, an increase of 33% from $2.81 per bbl for the second quarter of 2024 and an increase of 16% from $3.21 per bbl for the first quarter of 2025. The increase in transportation expense per bbl for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher volumes shipped on the TMX pipeline in 2025. The increase in transportation expense per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected the Company's commitments on egress pipelines and lower sales volumes due to the turnaround at Scotford in the second quarter of 2025.

PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING

	Three Months Ended							Six Months Ended
($ millions)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Production expense, excluding natural gas costs		$	1,085	$	1,135	$	917	$	2,220	$	1,893
Natural gas costs		35		50		24		85		74
Production expense		$	1,120	$	1,185	$	941	$	2,305	$	1,967

Canadian Natural Resources Limited 16 Three and six months ended June 30, 2025

	Three Months Ended							Six Months Ended
($/bbl)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Production expense, excluding natural gas costs (1)		$	25.71	$	20.95	$	25.29	$	23.03	$	24.41
Natural gas costs (2)		0.82		0.93		0.66		0.88		0.95
Production expense (3)		$	26.53	$	21.88	$	25.95	$	23.91	$	25.36
Sales volumes (bbl/d)		463,586		602,048		398,528		532,434		426,161

(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.

Oil Sands Mining and Upgrading production expense was $1,120 million for the second quarter of 2025, an increase of 19% from $941 million for the second quarter of 2024, primarily reflecting the acquisition of the additional working interest in AOSP in December 2024. Production expense decreased 5% in the second quarter of 2025 from $1,185 million for the first quarter of 2025 primarily reflecting lower energy costs.

Production expense for the six months ended June 30, 2025 averaged $23.91 per bbl, a decrease of 6% from $25.36 per bbl for the six months ended June 30, 2024. Production expense for the second quarter of 2025 averaged $26.53 per bbl, comparable with $25.95 per bbl for the second quarter of 2024 and an increase of 21% from $21.88 per bbl for the first quarter of 2025. The decrease in production expense per bbl for the six months ended June 30, 2025 from the six months ended June 30, 2024 primarily reflected higher production volumes.The increase in production expense per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower production volumes. SCO production volumes are discussed in detail in the "Daily Production, before royalties" section of this MD&A.

DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING

	Three Months Ended							Six Months Ended
($ millions, except per bbl amounts)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Depletion, depreciation and amortization		$	630	$	675	$	557	$	1,305	$	1,081
$/bbl (1)		$	14.96	$	12.45	$	15.37	$	13.55	$	13.95

(1)Calculated as depletion, depreciation and amortization divided by sales volumes.

Depletion, depreciation and amortization expense for the six months ended June 30, 2025 averaged $13.55 per bbl, a decrease of 3% from $13.95 per bbl for the six months ended June 30, 2024. Depletion, depreciation and amortization expense for the second quarter of 2025 of $14.96 per bbl decreased 3% from $15.37 per bbl for the second quarter of 2024 and increased 20% from $12.45 per bbl for the first quarter of 2025. The decrease in depletion, depreciation and amortization expense per bbl for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher sales volumes, partially offset by a higher depletable base due to asset additions. The increase in depletion, depreciation and amortization expense per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected lower sales volumes in the second quarter.

ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING

	Three Months Ended							Six Months Ended
($ millions, except per bbl amounts)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Asset retirement obligation accretion		$	21	$	22	$	22	$	43	$	43
$/bbl (1)		$	0.51	$	0.40	$	0.58	$	0.45	$	0.54

(1)Calculated as asset retirement obligation accretion divided by sales volumes.

Canadian Natural Resources Limited 17 Three and six months ended June 30, 2025

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 six months ended June 30, 2025 of $0.45 per bbl decreased 17% from $0.54 per bbl for the six months ended June 30, 2024. Asset retirement obligation accretion expense for the second quarter of 2025 of $0.51 per bbl decreased 12% from $0.58 per bbl for the second quarter of 2024 and increased 28% from $0.40 per bbl for the first quarter of 2025. The decrease in asset retirement obligation accretion expense per bbl for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected the impact of higher sales volumes in 2025. The increase in asset retirement obligation accretion expense per bbl for the second quarter of 2025 from the first quarter of 2025 primarily reflected the impact of lower sales volumes in the second quarter.

MIDSTREAM AND REFINING

	Three Months Ended							Six Months Ended
($ millions)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Product sales
Midstream activities		$	22	$	22	$	21	$	44	$	41
NWRP, refined product sales and other		137		221		215		358		429
Segmented revenue		159		243		236		402		470
Less:
NWRP, refining toll		61		68		81		129		155
Midstream activities		5		5		7		10		12
Production expense		66		73		88		139		167
NWRP, feedstock costs		105		172		190		277		343
Transportation expenses		31		4		4		35		9
Depreciation		4		4		4		8		8
Segmented loss		$	(47)	$	(10)	$	(50)	$	(57)	$	(57)

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 second quarter of 2025, production of ultra-low sulphur diesel and other refined products averaged 60,549 BOE/d (15,137 BOE/d to the Company) (three months ended March 31, 2025 – 83,863 BOE/d; 20,966 BOE/d to the Company; three months ended June 30, 2024 – 78,272 BOE/d; 19,568 BOE/d to the Company), reflecting the 25% toll payer commitment.

As at June 30, 2025, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $504 million (December 31, 2024 – $509 million). For the three months ended June 30, 2025, the Company's recovery of its share of unrecognized equity losses was $24 million (three months ended March 31, 2025 – unrecognized equity losses of $19 million; six months ended June 30, 2025 – recovery of unrecognized equity losses of $5 million; three months ended June 30, 2024 – recovery of unrecognized equity losses of $35 million; six months ended June 30, 2024 – recovery of unrecognized equity losses of $39 million).

Canadian Natural Resources Limited 18 Three and six months ended June 30, 2025

ADMINISTRATION EXPENSE

	Three Months Ended							Six Months Ended
($ millions, except per BOE amounts)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Administration expense		$	151	$	152	$	124	$	303	$	250
$/BOE (1)		$	1.17	$	1.06	$	1.06	$	1.11	$	1.05
Sales volumes (BOE/d) (2)		1,423,321		1,599,487		1,280,416		1,510,917		1,304,089

(1)Calculated as administration expense divided by sales volumes.

(2)Total Company sales volumes.

Administration expense for the six months ended June 30, 2025 of $1.11 per BOE increased 6% from $1.05 per BOE for the six months ended June 30, 2024. Administration expense for the second quarter of 2025 of $1.17 per BOE increased 10% from $1.06 per BOE for the second quarter of 2024 and the first quarter of 2025. The increase in administration expense per BOE for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher personnel costs, partially offset by higher overhead recoveries and higher sales volumes. The increase in administration expense per BOE for the second quarter of 2025 from the first quarter of 2025 reflected the impact of lower sales volumes in the second quarter.

SHARE-BASED COMPENSATION

	Three Months Ended							Six Months Ended
($ millions)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Share-based compensation expense (recovery)		$	8	$	26	$	(13)	$	34	$	281

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 $34 million of share-based compensation expense for the six months ended June 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 19 Three and six months ended June 30, 2025

INTEREST AND OTHER FINANCING EXPENSE

	Three Months Ended							Six Months Ended
($ millions, except effective interest rate)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Interest and other financing expense		$	238	$	258	$	158	$	496	$	296
Less: Interest (income) and other expense (1)		(7)		(6)		(7)		(13)		(29)
Interest expense on long-term debt and lease liabilities (1)		$	245	$	264	$	165	$	509	$	325
Average current and long-term debt (2)		$	17,552	$	19,147	$	11,568	$	18,349	$	11,582
Average lease liabilities (2)		1,382		1,422		1,525		1,402		1,533
Average long-term debt and lease liabilities (2)		$	18,934	$	20,569	$	13,093	$	19,751	$	13,115
Average effective interest rate (3) (4)		5.1%		5.0%		4.9%		5.1%		4.9%
Interest and other financing expense ($/BOE) (5)		$	1.84	$	1.79	$	1.35	$	1.81	$	1.25
Sales volumes (BOE/d) (6)		1,423,321		1,599,487		1,280,416		1,510,917		1,304,089

(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 six months ended June 30, 2025 increased 45% to $1.81 per BOE from $1.25 per BOE for the six months ended June 30, 2024. Interest and other financing expense for the second quarter of 2025 increased 36% to $1.84 per BOE from $1.35 per BOE for the second quarter of 2024 and increased 3% from $1.79 per BOE for the first quarter of 2025. The increase in interest and other financing expense per BOE for the three and six months ended June 30, 2025 from the comparable periods in 2024 primarily reflected higher average debt levels, including higher floating rate debt, partially offset by higher sales volumes. The increase in interest and other financing expense per BOE for the second quarter of 2025 from the first quarter of 2025 primarily reflected the impact of lower sales volumes in the second quarter of 2025, partially offset by lower average debt levels driven by movements in the US/Canadian dollar exchange rate.

The Company's average effective interest rate for the three and six months ended June 30, 2025 of 5.1% increased from the comparable periods in 2024, reflecting higher floating rate long-term debt held during 2025.

Canadian Natural Resources Limited 20 Three and six months ended June 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							Six Months Ended
($ millions)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Foreign currency forward contracts		$	(115)	$	(20)	$	12	$	(135)	$	38
Foreign currency put options (1)		27		(4)		—		23		—
Natural gas financial instruments (2) (3) (4)		(1)		(3)		6		(4)		5
Net realized (gain) loss		(89)		(27)		18		(116)		43
Foreign currency forward contracts		(19)		14		3		(5)		12
Foreign currency put options (1)		2		(2)		—		—		—
Natural gas embedded derivative (5)		(11)		—		—		(11)		—
Natural gas financial instruments (2) (3) (4)		13		(9)		(3)		4		1
Net unrealized (gain) loss		(15)		3		—		(12)		13
Net (gain) loss		$	(104)	$	(24)	$	18	$	(128)	$	56

(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 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.

(4)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.

(5)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 six months ended June 30, 2025, the net realized risk management gain was primarily related to the settlement of foreign currency forward contracts. The Company recorded a net unrealized gain of $12 million ($10 million after tax of $2 million) on its risk management activities for the six months ended June 30, 2025, and a net unrealized gain of $15 million ($12 million after tax of $3 million) for the second quarter of 2025 (three months ended March 31, 2025 – unrealized loss of $3 million ($2 million after tax of $1 million); three months ended June 30, 2024 – $nil; six months ended June 30, 2024 – unrealized loss of $13 million ($12 million after tax of $1 million)).

Further details related to outstanding derivative financial instruments as at June 30, 2025 are disclosed in note 13 to the financial statements.

FOREIGN EXCHANGE

	Three Months Ended							Six Months Ended
($ millions)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Net realized (gain) loss		$	(142)	$	242	$	118	$	100	$	99
Net unrealized (gain) loss		(661)		(285)		(15)		(946)		254
Net (gain) loss (1)		$	(803)	$	(43)	$	103	$	(846)	$	353

(1)Amounts are reported net of derivative financial instruments designated as cash flow hedges.

The net realized foreign exchange loss for the six months ended June 30, 2025 was primarily related to the foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars. The net unrealized foreign exchange gain for the six months ended June 30, 2025 was primarily related to the translation of outstanding US dollar debt. The US/Canadian dollar exchange rate as at June 30, 2025 was US$0.7341 (March 31, 2025 – US$0.6955, June 30, 2024 – US$0.7306).

Canadian Natural Resources Limited 21 Three and six months ended June 30, 2025

INCOME TAXES

	Three Months Ended							Six Months Ended
($ millions, except effective tax rates)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
North America (1)		$	529	$	569	$	548	$	1,098	$	960
North Sea		(45)		(26)		(13)		(71)		(18)
Offshore Africa		—		5		5		5		10
Current PRT – North Sea		(49)		(39)		(6)		(88)		(20)
Other taxes		3		2		(14)		5		(11)
Current income tax		438		511		520		949		921
Deferred corporate income tax		(106)		119		14		13		28
Deferred PRT – North Sea		18		9		7		27		13
Deferred income tax		(88)		128		21		40		41
Income tax		$	350	$	639	$	541	$	989	$	962
Earnings before taxes		$	2,809	$	3,097	$	2,256	$	5,906	$	3,664
Effective tax rate on net earnings (2)		12%		21%		24%		17%		26%
	Three Months Ended							Six Months Ended
($ millions, except effective tax rates)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Income tax		$	350	$	639	$	541	$	989	$	962
Tax effect on non-operating items (3)		(1)		5		17		4		31
Current PRT – North Sea		49		39		6		88		20
Deferred PRT – North Sea		(18)		(9)		(7)		(27)		(13)
Other taxes		(3)		(2)		14		(5)		11
Effective tax on adjusted net earnings		$	377	$	672	$	571	$	1,049	$	1,011
Adjusted net earnings from operations (4)		$	1,496	$	2,436	$	1,892	$	3,932	$	3,366
Adjusted net earnings from operations, before taxes		$	1,873	$	3,108	$	2,463	$	4,981	$	4,377
Effective tax rate on adjusted net earnings from operations (5) (6)		20%		22%		23%		21%		23%

(1)Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments.

(2)Calculated as total of current and deferred income tax divided by earnings before taxes.

(3)Includes the net income tax effect on PSUs, certain stock options, unrealized risk management, and a recoverability 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 six months ended June 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 six months ended June 30, 2025 and the comparable periods included the impact of carrybacks of abandonment expenditures related to the decommissioning activities at the Company's platforms in the North Sea.

Canadian Natural Resources Limited 22 Three and six months ended June 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							Six Months Ended
($ millions)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Exploration and Production
Exploration and Evaluation Assets
Net expenditures		$	5	$	19	$	(4)	$	24	$	65
Net property acquisitions (dispositions)		46		(13)		—		33		—
Total Exploration and Evaluation Assets		51		6		(4)		57		65
Property, Plant and Equipment
Net property acquisitions		178		31		4		209		1
Well drilling, completion and equipping		558		536		478		1,094		891
Production and related facilities		407		390		353		797		608
Other		16		3		13		19		25
Total Property, Plant and Equipment		1,159		960		848		2,119		1,525
Total Exploration and Production		1,210		966		844		2,176		1,590
Oil Sands Mining and Upgrading
Project costs		96		55		123		151		185
Sustaining capital		406		216		526		622		807
Turnaround costs		174		46		114		220		125
Net property dispositions		—		—		—		—		(2)
Other		2		2		1		4		2
Total Oil Sands Mining and Upgrading		678		319		764		997		1,117
Midstream and Refining		2		2		3		4		7
Head Office		25		16		10		41		20
Net capital expenditures		$	1,915	$	1,303	$	1,621	$	3,218	$	2,734
Abandonment expenditures		$	193	$	188	$	129	$	381	$	291
By Segment
North America		$	1,110	$	836	$	804	$	1,946	$	1,505
North Sea		8		3		3		11		7
Offshore Africa		92		127		37		219		78
Oil Sands Mining and Upgrading		678		319		764		997		1,117
Midstream and Refining		2		2		3		4		7
Head Office		25		16		10		41		20
Net capital expenditures		$	1,915	$	1,303	$	1,621	$	3,218	$	2,734

(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. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited 23 Three and six months ended June 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 $3,218 million for the six months ended June 30, 2025 compared with $2,734 million for the six months ended June 30, 2024. Net capital expenditures were $1,915 million for the second quarter of 2025 compared with $1,621 million for the second quarter of 2024 and $1,303 million for the first quarter of 2025.

In addition, the Company reported abandonment expenditures of $381 million for the six months ended June 30, 2025 compared with $291 million for the six months ended June 30, 2024. Abandonment expenditures were $193 million for the second quarter of 2025 compared with $129 million for the second quarter of 2024 and $188 million for the first 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. Production for 2025 is targeted between 1,510 MBOE/d and 1,555 MBOE/d. On May 7, 2025, the 2025 total capital budget was reduced by $100 million to $6,050 million, excluding abandonment expenditures.

In July 2025, subsequent to quarter end, the Company acquired certain producing and non-producing assets in the North America Exploration and Production segment for consideration of approximately $750 million, subject to final closing adjustments. The 2025 capital budget did not include capital related to this acquisition.

Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns, and the balancing of project risks and time horizons. The 2025 capital budget constitutes forward-looking statements and is based on net capital expenditures. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Drilling Activity (1) (2)

	Three Months Ended				Six Months Ended
(number of net wells)		Jun 30 2025	Mar 31 2025	Jun 30 2024	Jun 30 2025	Jun 30 2024
Net successful crude oil wells (3)		81	74	63	155	124
Net successful natural gas wells		22	19	24	41	40
Dry wells		—	1	1	1	1
Total		103	94	88	197	165
Success rate		100%	99%	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 second quarter of 2025, the Company drilled22 net natural gas wells, 41 net primary heavy crude oil wells, 4 net Pelican Lake heavy crude oil wells, 24 net bitumen (thermal oil) wells and 12 net light crude oil wells.

(1)Forward-looking non-GAAP Financial Measure. The operating capital budget is based on net capital expenditures (Non-GAAP Financial Measure). Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on net capital expenditures.

Canadian Natural Resources Limited 24 Three and six months ended June 30, 2025

LIQUIDITY AND CAPITAL RESOURCES

($ millions, except ratios)	Jun 30 2025		Mar 31 2025		Dec 31 2024		Jun 30 2024
Adjusted working capital (1)	$	102	$	20	$	174	$	(194)
Long-term debt, net (2)	$	16,979	$	17,335	$	18,688	$	9,234
Shareholders' equity	$	41,298	$	40,445	$	39,468	$	39,469
Debt to book capitalization (2)	29.1%		30.0%		32.1%		19.0%
After-tax return on average capital employed (3)	16.3%		15.3%		12.7%		16.1%

(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 June 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 expires in August 2025. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.

•Subsequent to June 30, 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 25 Three and six months ended June 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 expires in August 2025. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.

As at June 30, 2025, the Company had undrawn revolving bank credit facilities of $4,723 million, and a fully drawn non-revolving term credit facility of $4,000 million. Including cash and cash equivalents, the Company had approximately $4,825 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit. As at June 30, 2025, the Company had $553 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 $16,979 million as at June 30, 2025 (December 31, 2024 – $18,688 million), resulting in a debt to book capitalization ratio of 29.1% (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 June 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 June 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 June 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)	$	1,370	$	2,774	$	5,343	$	7,679
Other long-term liabilities (2)	$	242	$	151	$	370	$	621
Interest and other financing expense (3)	$	922	$	899	$	1,654	$	3,189

(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, $238 million; one to less than two years, $151 million; two to less than five years, $370 million; and thereafter, $621 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 June 30, 2025.

Share Capital

As at June 30, 2025, there were 2,090,620,000 common shares outstanding (December 31, 2024 – 2,102,996,000 common shares) and 58,657,000 stock options outstanding (December 31, 2024 – 50,806,000 stock options). As at August 5, 2025, the Company had 2,088,737,000 common shares outstanding and 57,234,000 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.

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 six months ended June 30, 2025, the Company purchased 19,800,000 common shares at a weighted average price of $42.70 per common share for a total cost, including tax, of $856 million. Retained earnings were reduced by $750 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to June 30, 2025, up to and including August 5, 2025, the Company purchased 2,600,000 common shares at a weighted average price of $43.19 per common share for a total cost, including tax, of $114 million.

Canadian Natural Resources Limited 26 Three and six months ended June 30, 2025

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 June 30, 2025:

($ millions)	Remaining 2025		2026		2027		2028		2029		Thereafter
Product transportation, purchases, and processing (1)	$	1,144	$	2,247	$	2,117	$	1,972	$	1,869	$	19,032
North West Redwater Partnership service toll (2)	$	69	$	119	$	99	$	100	$	99	$	4,080
Offshore vessels and equipment	$	100	$	—	$	—	$	—	$	—	$	—
Field equipment and power	$	28	$	32	$	29	$	28	$	27	$	216
Other	$	63	$	119	$	18	$	19	$	18	$	194

(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 $1,967 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 six months ended June 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 27 Three and six months ended June 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							Six Months Ended
($ millions)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Net earnings		$	2,459	$	2,458	$	1,715	$	4,917	$	2,702
Share-based compensation, net of tax (1)		6		22		(15)		28		266
Unrealized risk management (gain) loss, net of tax (2)		(12)		2		—		(10)		12
Unrealized foreign exchange (gain) loss, net of tax (3)		(661)		(285)		(15)		(946)		254
Realized foreign exchange (gain) loss on financing activities, net of tax (4)		(216)		239		135		23		135
Loss (gain) from investments, net of tax		—		—		25		—		(50)
Gain on acquisition, net of tax (5)		(80)		—		—		(80)		—
Recoverability charge, net of tax (6)		—		—		47		—		47
Non-operating items, net of tax		(963)		(22)		177		(985)		664
Adjusted net earnings from operations		$	1,496	$	2,436	$	1,892	$	3,932	$	3,366

(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 June 30, 2025 was an expense of $8 million (three months ended March 31, 2025 – $26 million expense, three months ended June 30, 2024 – $13 million recovery; six months ended June 30, 2025 – $34 million expense; six months ended June 30, 2024 – $281 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. Pre-tax unrealized risk management gain for the three months ended June 30, 2025 was $15 million (three months ended March 31, 2025 – $3 million loss, three months ended June 30, 2024 – $nil; six months ended June 30, 2025 – $12 million gain; six months ended June 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 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)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 ($47 million after-tax) of exploration and evaluation assets through depletion, depreciation and amortization expense.

Canadian Natural Resources Limited 28 Three and six months ended June 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							Six Months Ended
($ millions)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Cash flows from operating activities		$	3,114	$	4,284	$	4,084	$	7,398	$	6,952
Net change in non-cash working capital		(24)		(82)		(515)		(106)		(500)
Abandonment expenditures		193		188		129		381		291
Movements in other long-term assets (1)		(21)		140		(84)		119		9
Adjusted funds flow		$	3,262	$	4,530	$	3,614	$	7,792	$	6,752

(1)Includes the unamortized cost of contributions to the Company's employee bonus program, the accrued interest on PRT recoveries, 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 29 Three and six months ended June 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							Six Months Ended
($ millions, except bbl/d and $/bbl)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Crude oil and NGLs (bbl/d)
North America		551,248		562,183		509,674		556,685		502,148
International
North Sea		6,778		15,665		12,682		11,197		13,075
Offshore Africa		500		11,048		7,800		5,745		7,923
Total International		7,278		26,713		20,482		16,942		20,998
Total sales volumes		558,526		588,896		530,156		573,627		523,146
Crude oil and NGLs sales (1)		$	4,655	$	5,624	$	5,484	$	10,279	$	9,989
Less: Blending and feedstock costs (2)		1,119		1,391		1,303		2,510		2,520
Realized crude oil and NGLs sales		$	3,536	$	4,233	$	4,181	$	7,769	$	7,469
Realized price ($/bbl)		$	69.58	$	79.85	$	86.64	$	74.82	$	78.43

(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							Six Months Ended
($ millions, except BOE/d and $/BOE)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Barrels of oil equivalent (BOE/d)
North America		950,888		968,189		859,536		959,491		854,936
International
North Sea		7,262		16,399		12,959		11,805		13,334
Offshore Africa		1,585		12,851		9,393		7,187		9,658
Total International		8,847		29,250		22,352		18,992		22,992
Total sales volumes		959,735		997,439		881,888		978,483		877,928
Barrels of oil equivalent sales (1)		$	5,221	$	6,314	$	5,788	$	11,535	$	10,792
Less: Blending and feedstock costs (2)		1,119		1,391		1,303		2,510		2,520
Less: Sulphur (income) expense		(18)		(9)		3		(27)		4
Realized barrels of oil equivalent sales		$	4,120	$	4,932	$	4,482	$	9,052	$	8,268
Realized price ($/BOE)		$	47.17	$	54.95	$	55.84	$	51.11	$	51.74

(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 30 Three and six months ended June 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							Six Months Ended
($ millions, except $/bbl and royalty rates)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Crude oil and NGLs sales (1)		$	4,595	$	5,366	$	5,269	$	9,961	$	9,553
Less: Blending and feedstock costs (2)		1,119		1,391		1,303		2,510		2,520
Realized crude oil and NGLs sales		$	3,476	$	3,975	$	3,966	$	7,451	$	7,033
Realized crude oil and NGLs prices ($/bbl)		$	69.30	$	78.56	$	85.49	$	73.95	$	76.94
Crude oil and NGLs royalties (3)		$	467	$	756	$	838	$	1,223	$	1,401
Crude oil and NGLs royalty rates		13%		19%		21%		16%		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 (a 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							Six Months Ended
($ millions, except for bbl/d and $/bbl)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
SCO sales volumes (bbl/d)		463,586		602,048		398,528		532,434		426,161
Crude oil and NGLs sales (1)		$	4,023	$	5,879	$	4,525	$	9,902	$	8,693
Less: Blending and feedstock costs (2)		345		703		579		1,048		1,078
Realized SCO sales		$	3,678	$	5,176	$	3,946	$	8,854	$	7,615
Realized SCO sales price ($/bbl)		$	87.22	$	95.52	$	108.81	$	91.88	$	98.18

(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 31 Three and six months ended June 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 capital, net proceeds from investments, and cash flows from investing activities not included in the Company's capital budget. The Company includes acquisition and disposition capital for property, plant and equipment and exploration and evaluation assets in net capital expenditures at close of the transactions. The Company considers net capital expenditures a key measure in evaluating its performance, as it provides an understanding of the Company's capital spending activities in comparison to the Company's annual capital budget. A reconciliation of net capital expenditures is presented below.

	Three Months Ended							Six Months Ended
($ millions)		Jun 30 2025		Mar 31 2025		Jun 30 2024		Jun 30 2025		Jun 30 2024
Cash flows used in investing activities		$	1,941	$	1,312	$	1,015	$	3,253	$	2,407
Net proceeds from investments		—		—		575		—		575
Net change in non-cash working capital		(26)		(9)		31		(35)		(248)
Net capital expenditures		1,915		1,303		1,621		3,218		2,734
Abandonment expenditures		193		188		129		381		291
Capital and abandonment expenditures		$	2,108	$	1,491	$	1,750	$	3,599	$	3,025

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)	Jun 30 2025		Mar 31 2025		Dec 31 2024		Jun 30 2024
Undrawn bank credit facilities	$	4,723	$	4,965	$	4,562	$	5,450
Cash and cash equivalents	102		93		131		915
Liquidity	$	4,825	$	5,058	$	4,693	$	6,365

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)	Jun 30 2025		Mar 31 2025		Dec 31 2024		Jun 30 2024
Long-term debt	$	17,081	$	17,428	$	18,819	$	10,149
Less: cash and cash equivalents	102		93		131		915
Long-term debt, net	$	16,979	$	17,335	$	18,688	$	9,234

Canadian Natural Resources Limited 32 Three and six months ended June 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)	Jun 30 2025		Mar 31 2025		Dec 31 2024		Jun 30 2024
Interest adjusted after-tax return:
Net earnings, 12 months trailing	$	8,321	$	7,577	$	6,106	$	7,673
Interest and other financing expense, net of tax, 12 months trailing (1)	608		546		454		461
Interest adjusted after-tax return	$	8,929	$	8,123	$	6,560	$	8,134
12 months average current portion long-term debt (2)	$	1,528	$	1,615	$	1,525	$	1,506
12 months average long-term debt (2)	13,174		11,878		10,642		9,651
12 months average common shareholders' equity (2)	40,115		39,757		39,635		39,418
12 months average capital employed	$	54,817	$	53,250	$	51,802	$	50,575
After-tax return on average capital employed	16.3%		15.3%		12.7%		16.1%

(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 33 Three and six months ended June 30, 2025