CANADIAN NATURAL RESOURCES LIMITED

 MANAGEMENT'S DISCUSSION & ANALYSIS

FOR THE THREE MONTHS AND YEAR ENDED DECEMBER 31, 2023

FEBRUARY 28, 2024

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", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses, and other targets provided throughout this Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby thermal oil sands project, the Jackfish thermal oil sands project and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market; the abandonment 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 impact of the Pathways Alliance ("Pathways") initiative and activities, government support for Pathways and the ability to achieve net zero emissions from oil production, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.

The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of armed conflicts in the Middle East, the impact of the Russian invasion of 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; political uncertainty, including 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 Company's ability to implement strategies and leverage technologies to meet climate change initiatives and emissions targets on the expected timelines; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company's and its subsidiaries' ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's and its subsidiaries' success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long-term; the strength of the Company's balance sheet;

Canadian Natural Resources Limited 1 Three months and year ended December 31, 2023

the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; 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, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.

Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company's estimates or opinions change.

Special Note Regarding Non-GAAP and Other Financial Measures

This MD&A includes references to non-GAAP measures, which include non-GAAP and other financial measures as defined in National Instrument 52-112 – Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). Non-GAAP measures are used by the Company to evaluate its financial performance, financial position or cash flow. Descriptions of the Company's non-GAAP and other financial measures included in this MD&A, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided in the "Non-GAAP and Other Financial Measures" section of this MD&A.

Special Note Regarding Currency, Financial Information 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 months and year ended December 31, 2023, and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2022. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements for the three months and year ended December 31, 2023 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 months and year ended December 31, 2023 in relation to the comparable periods in 2022 and the third quarter of 2023. 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, 2022, is available on SEDAR+ at www.sedarplus.ca, and on EDGAR at www.sec.gov. Information on the Company's website does not form part of and is not incorporated by reference in this MD&A. This MD&A is dated February 28, 2024.

Canadian Natural Resources Limited 2 Three months and year ended December 31, 2023

FINANCIAL HIGHLIGHTS

		Three Months Ended						Year Ended
($ millions, except per common share amounts)		Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Product sales (1)		$	10,679	$	11,762	$	11,012	$	40,835	$	49,530
Crude oil and NGLs		$	9,829	$	10,944	$	9,508	$	37,300	$	43,009
Natural gas		$	603	$	599	$	1,287	$	2,575	$	5,236
Net earnings		$	2,627	$	2,344	$	1,520	$	8,233	$	10,937
Per common share	– basic	$	2.43	$	2.15	$	1.37	$	7.54	$	9.64
	– diluted	$	2.41	$	2.13	$	1.36	$	7.47	$	9.52
Adjusted net earnings from operations (2)		$	2,546	$	2,850	$	2,194	$	8,533	$	12,863
Per common share	– basic (3)	$	2.36	$	2.61	$	1.98	$	7.82	$	11.33
	– diluted (3)	$	2.34	$	2.59	$	1.96	$	7.74	$	11.19
Cash flows from operating activities		$	4,815	$	3,498	$	4,544	$	12,353	$	19,391
Adjusted funds flow (2)		$	4,419	$	4,684	$	4,176	$	15,274	$	19,791
Per common share	– basic (3)	$	4.09	$	4.30	$	3.78	$	14.00	$	17.44
	– diluted (3)	$	4.05	$	4.26	$	3.73	$	13.86	$	17.22
Cash flows used in investing activities		$	946	$	1,199	$	1,262	$	4,858	$	4,987
Net capital expenditures (4)		$	975	$	1,108	$	1,233	$	4,909	$	5,136
Abandonment expenditures, net (2)		$	149	$	123	$	84	$	509	$	335

(1)Further details related to product sales are disclosed in note 17 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 has been updated for all periods presented. 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 year ended December 31, 2023 were $8,233 million compared with $10,937 million for the year ended December 31, 2022. Net earnings for the year ended December 31, 2023 included non-operating losses, net of tax, of $300 million compared with non-operating losses of $1,926 million for the year ended December 31, 2022 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on the settlement of the cross currency swap and repayment of US dollar debt securities, the gain from investments, a recoverability charge relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea in 2023, a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea in 2022, and government grant income under the provincial well-site rehabilitation programs in 2022. Excluding these items, adjusted net earnings from operations for the year ended December 31, 2023 were $8,533 million compared with $12,863 million for the year ended December 31, 2022.

Net earnings for the fourth quarter of 2023 were $2,627 million compared with $1,520 million for the fourth quarter of 2022 and $2,344 million for the third quarter of 2023. Net earnings for the fourth quarter of 2023 included non-operating income, net of tax, of $81 million compared with non-operating losses of $674 million for the fourth quarter of 2022 and non-operating losses of $506 million for the third quarter of 2023 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the impact of realized foreign exchange on the repayment of US dollar debt securities, the loss (gain) from investments, a recoverability charge relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea in 2023, a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea in 2022, and government grant income under the provincial well-site rehabilitation programs in 2022. Excluding these items, adjusted net earnings from operations for the fourth quarter of 2023 were $2,546 million compared with $2,194 million for the fourth quarter of 2022 and $2,850 million for the third quarter of 2023.

Canadian Natural Resources Limited 3 Three months and year ended December 31, 2023

The decrease in net earnings and adjusted net earnings from operations for the year ended December 31, 2023 from the year ended December 31, 2022 primarily reflected:

▪lower realized crude oil and NGLs pricing (1) in the North America Exploration and Production segment;

▪lower realized SCO sales pricing (1) in the Oil Sands Mining and Upgrading segment; and

▪lower realized natural gas pricing in the Exploration and Production segments;

partially offset by:

▪higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; and

▪higher crude oil and NGLs sales volumes in the North America Exploration and Production segment.

The increase in net earnings and adjusted net earnings from operations for the fourth quarter of 2023 from the fourth quarter of 2022 primarily reflected:

▪higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; and

▪higher crude oil and NGLs sales volumes in the North America Exploration and Production segment;

partially offset by:

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

▪lower realized natural gas pricing in the North America Exploration and Production segment.

The movements in net earnings and adjusted net earnings from operations for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected:

▪higher crude oil and NGLs sales volumes in the Exploration and Production segments; and

▪higher natural gas sales volumes and netbacks in the North America Exploration and Production segment;

partially offset by:

▪lower realized crude oil and NGLs pricing in the North America Exploration and Production segment; and

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

The impacts of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the loss (gain) from investment also contributed to the movements in net earnings. These items are discussed in detail in the relevant sections of this MD&A.

Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked crude oil reserves as at December 31, 2022 and is accelerating abandonment. As a result, the Company completed a recoverability assessment of its assets in the North Sea, and recognized a non-cash charge of $651 million (after-tax) related to the Ninian field property, plant and equipment, comprised of a recoverability charge of $1,620 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $969 million.

As at December 31, 2023, as a result of revised project scope and the current cost environment, the Company recognized a non-cash charge of $113 million (after-tax) related to an increase in its estimate of the future abandonment costs for the Ninian field in the North Sea. The non-cash charge is comprised of a recoverability charge of $436 million recognized in depletion, depreciation and amortization expense, net of deferred tax recoveries of $323 million. The Company’s estimate of its asset retirement obligation liability, including the Ninian field recoverability charge and associated tax recoveries, is subject to revision in future periods as abandonment efforts progress.

Cash Flows from Operating Activities and Adjusted Funds Flow

Cash flows from operating activities for the year ended December 31, 2023 were $12,353 million compared with $19,391 million for the year ended December 31, 2022. Cash flows from operating activities for the fourth quarter of 2023 were $4,815 million compared with $4,544 million for the fourth quarter of 2022 and $3,498 million for the third quarter of 2023. 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.

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

Canadian Natural Resources Limited 4 Three months and year ended December 31, 2023

Adjusted funds flow for the year ended December 31, 2023 was $15,274 million compared with $19,791 million for the year ended December 31, 2022. Adjusted funds flow for the fourth quarter of 2023 was $4,419 million compared with $4,176 million for the fourth quarter of 2022 and $4,684 million for the third quarter of 2023. 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, government grant income under the provincial well-site rehabilitation programs, and movements in other long-term assets, including the unamortized cost of the share bonus program, accrued interest on the deferred PRT recovery, and prepaid cost of service tolls.

Production Volumes

Record crude oil and NGLs production before royalties for the fourth quarter of 2023 of 1,047,541 bbl/d increased 11% from 942,258 bbl/d for the fourth quarter of 2022, and was comparable with 1,035,153 bbl/d for the third quarter of 2023. Record natural gas production before royalties for the fourth quarter of 2023 of 2,231 MMcf/d increased 5% from 2,115 MMcf/d for the fourth quarter of 2022, and increased 4% from 2,151 MMcf/d for the third quarter of 2023. Total production before royalties for the fourth quarter of 2023 of 1,419,313 BOE/d increased 10% from 1,294,679 BOE/d for the fourth quarter of 2022, and was comparable with 1,393,614 BOE/d for the third quarter of 2023. 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 $69.39 per bbl for the fourth quarter of 2023, comparable with $69.34 per bbl for the fourth quarter of 2022, and a decrease of 21% from $87.83 per bbl for the third quarter of 2023. The realized natural gas price decreased 56% to average $2.80 per Mcf for the fourth quarter of 2023 from $6.39 per Mcf for the fourth quarter of 2022, and was comparable with $2.81 per Mcf for the third quarter of 2023. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price decreased 5% to average $98.73 per bbl for the fourth quarter of 2023 from $103.79 per bbl for the fourth quarter of 2022, and decreased 9% from $108.55 per bbl for the third quarter of 2023. The Company's realized pricing reflected prevailing benchmark pricing. Crude oil and NGLs and natural gas prices are discussed in detail in the "Business Environment", "Realized Product Prices – Exploration and Production", and the "Oil Sands Mining and Upgrading" sections of this MD&A.

Production Expense

In the Company's Exploration and Production segments, crude oil and NGLs production expense (1) averaged $15.05 per bbl for the fourth quarter of 2023, a decrease of 26% from $20.37 per bbl for the fourth quarter of 2022, and an increase of 5% from $14.40 per bbl for the third quarter of 2023. Natural gas production expense (1) averaged $1.13 per Mcf for the fourth quarter of 2023, a decrease of 10% from $1.25 per Mcf for the fourth quarter of 2022 and the third quarter of 2023. In the Oil Sands Mining and Upgrading segment, production expense (1) averaged $20.96 per bbl for the fourth quarter of 2023, a decrease of 18% from $25.48 per bbl for the fourth quarter of 2022, and a decrease of 5% from $22.12 per bbl for the third quarter of 2023. 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.

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

Canadian Natural Resources Limited 5 Three months and year ended December 31, 2023

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)	Dec 31 2023		Sep 30 2023		Jun 30 2023		Mar 31 2023
Product sales (1)	$	10,679	$	11,762	$	8,846	$	9,548
Crude oil and NGLs	$	9,829	$	10,944	$	8,115	$	8,412
Natural gas	$	603	$	599	$	522	$	851
Net earnings	$	2,627	$	2,344	$	1,463	$	1,799
Net earnings per common share
– basic	$	2.43	$	2.15	$	1.34	$	1.63
– diluted	$	2.41	$	2.13	$	1.32	$	1.62
($ millions, except per common share amounts)	Dec 31 2022		Sep 30 2022		Jun 30 2022		Mar 31 2022
Product sales (1)	$	11,012	$	12,574	$	13,812	$	12,132
Crude oil and NGLs	$	9,508	$	11,001	$	11,727	$	10,773
Natural gas	$	1,287	$	1,342	$	1,605	$	1,002
Net earnings	$	1,520	$	2,814	$	3,502	$	3,101
Net earnings per common share
– basic	$	1.37	$	2.52	$	3.04	$	2.66
– diluted	$	1.36	$	2.49	$	3.00	$	2.63

(1)Further details related to product sales for the three months ended December 31, 2023 and 2022 are disclosed in note 17 to the financial statements.

Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to:

▪Crude oil pricing – Fluctuations in global supply/demand including crude oil production levels from OPEC+ and its impact on world supply, the impact of geopolitical and market uncertainties including those due to the Russian invasion of Ukraine on worldwide benchmark pricing, the impact of shale oil production in North America, 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, third-party pipeline maintenance and outages, the impact of geopolitical and market uncertainties, the impact of seasonal conditions, and the impact of shale gas production in the US.

▪Crude oil and NGLs sales volumes – Fluctuations in production from the Kirby and Jackfish thermal oil sands projects, fluctuations in production due to the cyclic nature of the Primrosethermal oil projects, fluctuations in the Company's drilling program in the North America Exploration and Production segment, natural decline rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and wildfires and a third-party pipeline outage in 2023 in the North America Exploration and Production segment. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the International segments.

▪Natural gas sales volumes – Fluctuations in production due to the Company's drilling program in the North America Exploration and Production segment, natural decline rates, the impact and timing of acquisitions, and wildfires and a third-party pipeline outage in 2023 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 and pitstops in the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments.

Canadian Natural Resources Limited 6 Three months and year ended December 31, 2023

▪Depletion, depreciation and amortization expense – Fluctuations due to changes in sales volumes, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, fluctuations in International sales volumes subject to higher depletion rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, a recoverability charge relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea in 2023, and a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea at December 31, 2022.

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

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

▪Interest expense – Fluctuations due to changing long-term debt levels, and the impact of movements in benchmark interest rates on outstanding floating rate long-term debt and accrued interest on the deferred Petroleum Revenue Tax ("PRT") recovery.

▪Foreign exchange – Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company receives for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar denominated debt, partially offset by the impact of any cross currency swap hedges outstanding.

▪Loss (gain) from investment – Fluctuations due to the loss (gain) from the investment in PrairieSky Royalty Ltd. shares.

BUSINESS ENVIRONMENT

Risks and Uncertainties

Rising interest rates in response to persistent inflation and concerns of a global recession put downward pressure on global crude oil benchmark pricing in 2023 and heightened geopolitical tensions led to pricing volatility throughout 2023. Higher non-OPEC supply and record US production in the fourth quarter of 2023 reduced the impact of previously announced OPEC+ production cuts. Although inflationary pressures are easing, the Company has experienced and may continue to experience inflationary pressures on its operating and capital expenditures in addition to higher than normal fluctuations in commodity prices and interest rates.

Liquidity

As at December 31, 2023, the Company had undrawn revolving bank credit facilities of $5,450 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,852 million in liquidity (1). The Company also has certain other dedicated credit facilities supporting letters of credit.

The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital structure. Refer to the "Liquidity and Capital Resources" section of this MD&A for further details.

Capital Spending

On December 14, 2023, the Company announced its 2024 capital budget (2) targeted at approximately $5,420 million, and targets to provide near-term production growth in 2024 and mid- and long-term production and capacity growth in 2025 and beyond. Production for 2024 is targeted between 1,330,000 BOE/d and 1,380,000 BOE/d. In addition, the Company targets $635 million in abandonment expenditures for 2024. 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 2024 capital budget and targeted abandonment expenditures constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

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

(2)Forward-looking non-GAAP Financial Measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on Net Capital Expenditures.

Canadian Natural Resources Limited 7 Three months and year ended December 31, 2023

Benchmark Commodity Prices

	Three Months Ended						Year Ended
(Average for the period)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
WTI benchmark price (US$/bbl)	$	78.33	$	82.18	$	82.62	$	77.61	$	94.23
Dated Brent benchmark price (US$/bbl)	$	84.06	$	86.68	$	88.15	$	82.61	$	99.80
WCS Heavy Differential from WTI (US$/bbl)	$	21.90	$	12.86	$	25.65	$	18.62	$	18.26
SCO benchmark price (US$/bbl)	$	78.64	$	84.99	$	86.78	$	79.64	$	98.66
Condensate benchmark price (US$/bbl)	$	76.22	$	77.91	$	83.33	$	76.55	$	93.69
Condensate Differential from WTI (US$/bbl)	$	2.11	$	4.27	$	(0.71)	$	1.06	$	0.54
NYMEX benchmark price (US$/MMBtu)	$	2.87	$	2.55	$	6.27	$	2.74	$	6.64
AECO benchmark price (C$/GJ)	$	2.52	$	2.26	$	5.29	$	2.77	$	5.28
US/Canadian dollar average exchange rate (US$)	$	0.7341	$	0.7456	$	0.7366	$	0.7409	$	0.7686

Substantially all of the Company's production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based on WTI and Brent indices. Canadian natural gas pricing is primarily based on AECO reference pricing, which is derived from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at Henry Hub. The Company’s realized prices are directly impacted by fluctuations in foreign exchange rates. Product revenue continued to be impacted by changes in the Canadian dollar as the Canadian dollar sales price the Company received for its crude oil and natural gas sales is based on US dollar denominated benchmarks.

Crude oil sales contracts in North America are typically based on WTI benchmark pricing. WTI averaged US$77.61 per bbl for the year ended December 31, 2023, a decrease of 18% from US$94.23 per bbl for the year ended December 31, 2022. WTI averaged US$78.33 per bbl for the fourth quarter of 2023, a decrease of 5% from US$82.62 per bbl for the fourth quarter of 2022, and a decrease of 5% from US$82.18 per bbl for the third quarter of 2023.

Crude oil sales contracts for the Company's International segments are typically based on Brent pricing, which is representative of international markets and overall global supply and demand. Brent averaged US$82.61 per bbl for the year ended December 31, 2023, a decrease of 17% from US$99.80 per bbl for the year ended December 31, 2022. Brent averaged US$84.06 per bbl for the fourth quarter of 2023, a decrease of 5% from US$88.15 per bbl for the fourth quarter of 2022, and a decrease of 3% from US$86.68 per bbl for the third quarter of 2023.

The decrease in WTI and Brent pricing for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected concerns of higher non-OPEC supply and lower than anticipated global crude oil demand, as a result of persistent inflation and the resulting increase in interest rates. The decrease in WTI and Brent pricing for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected demand concerns and growing global supply.

The WCS Heavy Differential averaged US$18.62 per bbl for the year ended December 31, 2023, compared with US$18.26 per bbl for the year ended December 31, 2022. The WCS Heavy Differential averaged US$21.90 per bbl for the fourth quarter of 2023, compared with US$25.65 per bbl for the fourth quarter of 2022, and US$12.86 per bbl for the third quarter of 2023. The narrowing of the WCS Heavy Differential for the fourth quarter of 2023 from the fourth quarter of 2022 primarily reflected strengthening of US Gulf Coast heavy oil pricing in 2023 and a decrease in supply from the US Strategic Petroleum Reserve following releases in 2022. The widening of the WCS Heavy Differential for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected reduced refining capacity due to maintenance activities in the US, together with increased supply and egress constraints following fall production turnarounds.

The SCO benchmark price averaged US$79.64 per bbl for the year ended December 31, 2023, a decrease of 19% from US$98.66 per bbl for the year ended December 31, 2022. The SCO benchmark price averaged US$78.64 per bbl for the fourth quarter of 2023, a decrease of 9% from US$86.78 per bbl for the fourth quarter of 2022, and a decrease of 7% from US$84.99 per bbl for the third quarter of 2023. The decrease in SCO benchmark pricing for the three months and year ended December 31, 2023 from the comparable periods primarily reflected the decrease in WTI benchmark pricing, together with increased production and egress constraints in the Western Canadian Sedimentary Basin ("WCSB").

Canadian Natural Resources Limited 8 Three months and year ended December 31, 2023

NYMEX natural gas prices averaged US$2.74 per MMBtu for the year ended December 31, 2023, a decrease of 59% from US$6.64 per MMBtu for the year ended December 31, 2022. NYMEX natural gas prices averaged US$2.87 per MMBtu for the fourth quarter of 2023, a decrease of 54% from US$6.27 per MMBtu for the fourth quarter of 2022, and an increase of 13% from US$2.55 per MMBtu for the third quarter of 2023. The decrease in NYMEX natural gas prices for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected increased production and lower storage draws due to mild winter weather in 2023. Additionally, lower global Liquefied Natural Gas ("LNG") prices amid ample supply put downward pressure on NYMEX benchmark prices. The increase in NYMEX natural gas prices for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected seasonal demand factors as well as record LNG exports out of the US Gulf Coast.

AECO natural gas prices averaged $2.77 per GJ for the year ended December 31, 2023, a decrease of 48% from $5.28 per GJ for the year ended December 31, 2022. AECO natural gas prices averaged $2.52 per GJ for the fourth quarter of 2023, a decrease of 52% from $5.29 per GJ for the fourth quarter of 2022, and an increase of 12% from $2.26 per GJ for the third quarter of 2023. The decrease in AECO natural gas prices for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected NYMEX benchmark pricing, increased production in the WCSB, and lower storage draws due to decreased demand resulting from mild winter weather in 2023. The increase in AECO natural gas prices for the fourth quarter of 2023 to the third quarter of 2023 reflected NYMEX benchmark pricing, seasonal demand factors and increased exports out of the WCSB.

DAILY PRODUCTION, before royalties

	Three Months Ended			Year Ended
	Dec 31 2023	Sep 30 2023	Dec 31 2022	Dec 31 2023	Dec 31 2022
Crude oil and NGLs (bbl/d)
North America – Exploration and Production	521,579	519,581	486,559	496,100	479,971
North America – Oil Sands Mining and Upgrading (1)	500,133	490,853	428,784	451,339	425,945
International – Exploration and Production
North Sea	12,616	12,016	14,006	12,639	12,890
Offshore Africa	13,213	12,703	12,909	13,452	14,343
Total International (2)	25,829	24,719	26,915	26,091	27,233
Total Crude oil and NGLs	1,047,541	1,035,153	942,258	973,530	933,149
Natural gas (MMcf/d) (3)
North America	2,218	2,139	2,105	2,139	2,075
International
North Sea	2	1	3	2	2
Offshore Africa	11	11	7	10	13
Total International	13	12	10	12	15
Total Natural gas	2,231	2,151	2,115	2,151	2,090
Total Barrels of oil equivalent (BOE/d)	1,419,313	1,393,614	1,294,679	1,332,105	1,281,434
Product mix
Light and medium crude oil and NGLs	10%	10%	11%	10%	11%
Pelican Lake heavy crude oil	3%	3%	4%	3%	4%
Primary heavy crude oil	6%	5%	5%	6%	5%
Bitumen (thermal oil)	20%	21%	20%	20%	20%
Synthetic crude oil (1)	35%	35%	33%	34%	33%
Natural gas	26%	26%	27%	27%	27%
Percentage of product sales (1) (4) (5)
Crude oil and NGLs	94%	95%	87%	93%	88%
Natural gas	6%	5%	13%	7%	12%

(1)SCO production before royalties excludes SCO consumed internally as diesel.

(2)"International" includes North Sea and Offshore Africa Exploration and Production segments in all instances used.

(3)Natural gas production volumes approximate sales volumes.

(4)Net of blending and feedstock costs and excluding risk management activities.

(5)Excluding Midstream and Refining revenue.

Canadian Natural Resources Limited 9 Three months and year ended December 31, 2023

DAILY PRODUCTION, net of royalties

	Three Months Ended			Year Ended
	Dec 31 2023	Sep 30 2023	Dec 31 2022	Dec 31 2023	Dec 31 2022
Crude oil and NGLs (bbl/d)
North America – Exploration and Production	431,091	409,479	381,546	406,534	374,089
North America – Oil Sands Mining and Upgrading	443,535	387,407	372,894	385,996	351,740
International – Exploration and Production
North Sea	12,590	11,968	13,985	12,609	12,849
Offshore Africa	11,917	11,746	11,153	12,183	12,972
Total International	24,507	23,714	25,138	24,792	25,821
Total Crude oil and NGLs	899,133	820,600	779,578	817,322	751,650
Natural gas (MMcf/d)
North America	2,148	2,068	1,937	2,055	1,885
International
North Sea	2	1	3	2	2
Offshore Africa	11	10	6	10	11
Total International	13	11	9	12	13
Total Natural gas	2,161	2,079	1,946	2,067	1,898
Total Barrels of oil equivalent (BOE/d)	1,259,297	1,167,139	1,103,833	1,161,852	1,068,063

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.

Record crude oil and NGLs production before royalties for the year ended December 31, 2023 averaged 973,530 bbl/d, an increase of 4% from 933,149 bbl/d for the year ended December 31, 2022. Record crude oil and NGLs production for the fourth quarter of 2023 averaged 1,047,541 bbl/d, an increase of 11% from 942,258 bbl/d for the fourth quarter of 2022, and comparable with 1,035,153 bbl/d for the third quarter of 2023. The increase in crude oil and NGLs production before royalties for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected stronger production in the Oil Sands Mining and Upgrading, and North America Exploration and Production segments in 2023 due to pad additions in thermal oil, drilling activity, and the impact of extreme cold weather conditions in the fourth quarter of 2022.

Annual crude oil and NGLs production for 2023 was within the Company's previously issued production target of 969,000 bbl/d to 1,001,000 bbl/d. Annual crude oil and NGLs production for 2024 is targeted to average between 977,000 bbl/d and 1,008,000 bbl/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Record natural gas production before royalties for the year ended December 31, 2023 averaged 2,151 MMcf/d, an increase of 3% from 2,090 MMcf/d for the year ended December 31, 2022. Record natural gas production for the fourth quarter of 2023 averaged 2,231 MMcf/d, an increase of 5% from 2,115 MMcf/d for the fourth quarter of 2022, and an increase of 4% from 2,151 MMcf/d for the third quarter of 2023. The increase in natural gas production before royalties for the year ended December 31, 2023 from the year ended December 31, 2022 primarily reflected 2023 drilling activity, partially offset by the impact of wildfires and a third party pipeline outage in 2023, together with natural field declines. The increase in natural gas production for the fourth quarter of 2023 from the comparable periods primarily reflected drilling activity, partially offset by natural field declines. The increase for the fourth quarter of 2023 from the fourth quarter of 2022 also reflected the impact of extreme cold weather conditions in the fourth quarter of 2022.

Annual natural gas production for 2023 was slightly below the Company's previously issued production target of 2,170 MMcf/d to 2,242 MMcf/d. Annual natural gas production for 2024 is targeted to average between 2,120 MMcf/d and 2,230 MMcf/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Canadian Natural Resources Limited 10 Three months and year ended December 31, 2023

North America – Exploration and Production

North America crude oil and NGLs production before royalties for the year ended December 31, 2023 averaged 496,100 bbl/d, an increase of 3% from 479,971 bbl/d for the year ended December 31, 2022. North America crude oil and NGLs production for the fourth quarter of 2023 of 521,579 bbl/d increased 7% from 486,559 bbl/d for the fourth quarter of 2022, and was comparable with 519,581 bbl/d for the third quarter of 2023. The increase in North America crude oil and NGLs production for the year ended December 31, 2023 from the year ended December 31, 2022 primarily reflected pad additions in thermal oil and conventional drilling activity in 2023, partially offset by the impacts of wildfires and a third party pipeline outage in 2023, and natural field declines. The increase for the fourth quarter of 2023 from the fourth quarter of 2022 primarily reflected pad additions in thermal oil, conventional drilling activity in 2023, and the impact of extreme cold weather conditions in the fourth quarter of 2022, partially offset by natural field declines.

The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 278,422 bbl/d for the fourth quarter of 2023, an increase of 10% from 253,188 bbl/d for the fourth quarter of 2022, and a decrease of 3% from 287,085 bbl/d for the third quarter of 2023. The increase in thermal oil production in the fourth quarter of 2023 from the fourth quarter of 2022 primarily reflected pad additions at Primrose and Kirby in 2023, partially offset by natural field declines. The decrease in thermal oil production in the fourth quarter of 2023 from the third quarter of 2023 primarily reflected the cyclical nature of steaming at Primrose and natural field declines.

Pelican Lake heavy crude oil production before royalties for the fourth quarter of 2023 averaged 46,046 bbl/d, a decrease of 5% from 48,221 bbl/d for the fourth quarter of 2022, and comparable with 46,897 bbl/d for the third quarter of 2023, demonstrating Pelican Lake's long life low decline production.

Natural gas production before royalties for the year ended December 31, 2023 averaged 2,139 MMcf/d, an increase of 3% from 2,075 MMcf/d for the year ended December 31, 2022. Natural gas production for the fourth quarter of 2023 averaged 2,218 MMcf/d, an increase of 5% from 2,105 MMcf/d for the fourth quarter of 2022, and an increase of 4% from 2,139 MMcf/d for the third quarter of 2023. The increase in natural gas production for the year ended December 31, 2023 from the year ended December 31, 2022 primarily reflected 2023 drilling activity, partially offset by the impact of wildfires and a third party pipeline outage in 2023, together with natural field declines. The increase in natural gas production for the fourth quarter of 2023 from the comparable periods primarily reflected drilling activity, partially offset by natural field declines. The increase for the fourth quarter of 2023 from the fourth quarter of 2022 also reflected the impact of extreme cold weather conditions in the fourth quarter of 2022.

North America – Oil Sands Mining and Upgrading

Record SCO production before royalties for the year ended December 31, 2023 averaged 451,339 bbl/d, an increase of 6% from 425,945 bbl/d for the year ended December 31, 2022. Record SCO production for the fourth quarter of 2023 averaged 500,133 bbl/d, an increase of 17% from 428,784 bbl/d for the fourth quarter of 2022, and comparable with 490,853 bbl/d for the third quarter of 2023. The increase in SCO production for the year ended December 31, 2023 from the year ended December 31, 2022 primarily reflected stronger production in 2023 following the impact of an extended turnaround at the non-operated Scotford Upgrader in the first half of 2022, an unplanned outage at Horizon and extreme cold weather conditions impacting mining operations in the fourth quarter of 2022. The increase for the fourth quarter of 2023 compared to the fourth quarter of 2022 primarily reflected stronger production in the fourth quarter of 2023 following an unplanned outage at Horizon and extreme cold weather conditions impacting mining operations in the fourth quarter of 2022.

International – Exploration and Production

International crude oil and NGLs production before royalties for the year ended December 31, 2023 averaged 26,091 bbl/d, a decrease of 4% from 27,233 bbl/d for the year ended December 31, 2022. International crude oil and NGLs production for the fourth quarter of 2023 averaged 25,829 bbl/d, a decrease of 4% from 26,915 bbl/d for the fourth quarter of 2022, and an increase of 4% from 24,719 bbl/d for the third quarter of 2023. The decrease in crude oil and NGLs production for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected natural field declines. The increase in crude oil and NGLs production for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected planned maintenance activities in the third quarter, partially offset by natural field declines.

Canadian Natural Resources Limited 11 Three months and year ended December 31, 2023

International Crude Oil Inventory Volumes

The Company recognizes revenue on its crude oil production when control of the product passes to the customer and delivery has taken place. Revenue has not been recognized in the International segments on crude oil volumes held in various storage facilities or FPSOs, as follows:

(bbl)	Dec 31 2023	Sep 30 2023	Dec 31 2022
International	515,543	1,167,250	390,959

OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION

	Three Months Ended						Year Ended
	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Crude oil and NGLs ($/bbl)(1)
Realized price (2)	$	69.39	$	87.83	$	69.34	$	72.36	$	90.64
Transportation (2)	3.83		4.07		4.11		4.23		4.13
Realized price, net of transportation (2)	65.56		83.76		65.23		68.13		86.51
Royalties (3)	11.38		17.32		13.56		12.55		18.91
Production expense (4)	15.05		14.40		20.37		16.12		18.17
Netback (2)	$	39.13	$	52.04	$	31.30	$	39.46	$	49.43
Natural gas ($/Mcf) (1)
Realized price (5)	$	2.80	$	2.81	$	6.39	$	3.10	$	6.55
Transportation (6)	0.54		0.56		0.55		0.56		0.51
Realized price, net of transportation	2.26		2.25		5.84		2.54		6.04
Royalties (3)	0.09		0.09		0.51		0.13		0.61
Production expense (4)	1.13		1.25		1.25		1.30		1.22
Netback	$	1.04	$	0.91	$	4.08	$	1.11	$	4.21
Barrels of oil equivalent ($/BOE) (1)
Realized price (2)	$	48.41	$	59.40	$	56.83	$	50.54	$	70.07
Transportation (2)	3.61		3.78		3.80		3.88		3.72
Realized price, net of transportation (2)	44.80		55.62		53.03		46.66		66.35
Royalties (3)	7.05		10.61		9.31		7.77		12.75
Production expense (4)	11.75		11.64		15.17		12.74		13.76
Netback (2)	$	26.00	$	33.37	$	28.55	$	26.15	$	39.84

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

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

(3)Calculated as royalties divided by respective sales volumes.

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

(5)Calculated as natural gas sales divided by natural gas sales volumes.

(6)Calculated as natural gas transportation expense divided by natural gas sales volumes.

Canadian Natural Resources Limited 12 Three months and year ended December 31, 2023

REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION

	Three Months Ended						Year Ended
	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Crude oil and NGLs ($/bbl) (1)
North America (2)	$	66.69	$	86.77	$	65.79	$	70.51	$	88.43
International average (3)	$	112.22	$	113.59	$	118.44	$	107.46	$	128.41
North Sea (3)	$	118.50	$	108.22	$	118.91	$	110.99	$	129.04
Offshore Africa (3)	$	107.88	$	118.09	$	117.74	$	106.25	$	127.85
Crude oil and NGLs average (2)	$	69.39	$	87.83	$	69.34	$	72.36	$	90.64
Natural gas ($/Mcf) (1) (3)
North America	$	2.75	$	2.76	$	6.36	$	3.04	$	6.51
International average	$	12.15	$	12.21	$	13.70	$	12.81	$	12.78
North Sea	$	9.66	$	9.99	$	13.51	$	10.45	$	15.75
Offshore Africa	$	12.51	$	12.44	$	13.80	$	13.19	$	12.23
Natural gas average	$	2.80	$	2.81	$	6.39	$	3.10	$	6.55
Average ($/BOE) (1) (2)	$	48.41	$	59.40	$	56.83	$	50.54	$	70.07

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

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

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

North America

North America realized crude oil and NGLs prices decreased 20% to average $70.51 per bbl for the year ended December 31, 2023 from $88.43 per bbl for the year ended December 31, 2022. North America realized crude oil and NGLs prices averaged $66.69 per bbl for the fourth quarter of 2023, comparable with $65.79 per bbl for the fourth quarter of 2022, and decreased 23% from $86.77 per bbl for the third quarter of 2023. The decrease for the year ended December 31, 2023 from year ended December 31, 2022 primarily reflected lower WTI benchmark pricing. The decrease for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected lower WTI benchmark pricing, combined with the widening of the WCS Heavy Differential. The Company continues to focus on its crude oil blending marketing strategy and in the fourth quarter of 2023 contributed approximately 228,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices decreased 53% to average $3.04 per Mcf for the year ended December 31, 2023 from $6.51 per Mcf for the year ended December 31, 2022. North America realized natural gas prices decreased 57% to average $2.75 per Mcf for the fourth quarter of 2023 from $6.36 per Mcf for the fourth quarter of 2022, and was comparable with $2.76 per Mcf for the third quarter of 2023. The decrease in North America realized natural gas prices for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected lower AECO benchmark and export pricing.

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

	Three Months Ended
(Quarterly average)	Dec 31 2023		Sep 30 2023		Dec 31 2022
Wellhead Price(1)
Light and medium crude oil and NGLs ($/bbl)	$	69.42	$	72.07	$	77.08
Pelican Lake heavy crude oil ($/bbl)	$	73.47	$	93.19	$	73.25
Primary heavy crude oil ($/bbl)	$	72.90	$	93.80	$	69.20
Bitumen (thermal oil) ($/bbl)	$	62.64	$	89.50	$	58.13
Natural gas ($/Mcf)	$	2.75	$	2.76	$	6.36

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

Canadian Natural Resources Limited 13 Three months and year ended December 31, 2023

International

International realized crude oil and NGLs prices decreased 16% to average $107.46 per bbl for the year ended December 31, 2023 from $128.41 per bbl for the year ended December 31, 2022. International realized crude oil and NGLs prices decreased 5% to average $112.22 per bbl for the fourth quarter of 2023 from $118.44 per bbl for the fourth quarter of 2022, and was comparable with $113.59 per bbl for the third quarter of 2023. 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 crude oil prices and foreign exchange rates at the time of lifting. The fluctuations in realized crude oil and NGLs prices for the three months and year ended December 31, 2023 from the comparable periods reflected prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.

ROYALTIES – EXPLORATION AND PRODUCTION

	Three Months Ended						Year Ended
	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Crude oil and NGLs ($/bbl) (1)
North America	$	11.72	$	17.79	$	14.07	$	12.89	$	19.64
International average	$	5.83	$	5.67	$	6.56	$	5.99	$	6.38
North Sea	$	0.24	$	0.42	$	0.18	$	0.33	$	0.30
Offshore Africa	$	10.58	$	8.90	$	16.02	$	10.08	$	11.79
Crude oil and NGLs average	$	11.38	$	17.32	$	13.56	$	12.55	$	18.91
Natural gas ($/Mcf) (1)
North America	$	0.09	$	0.09	$	0.51	$	0.13	$	0.61
Offshore Africa	$	0.59	$	0.59	$	0.71	$	0.62	$	1.50
Natural gas average	$	0.09	$	0.09	$	0.51	$	0.13	$	0.61
Average($/BOE) (1)	$	7.05	$	10.61	$	9.31	$	7.77	$	12.75

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

North America

North America crude oil and NGLs and natural gas royalties for the three months and year ended December 31, 2023 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 18% of product sales for the year ended December 31, 2023 compared with 22% of product sales for the year ended December 31, 2022. Crude oil and NGLs royalty rates averaged approximately 18% of product sales for the fourth quarter of 2023 compared with 21% for the fourth quarter of 2022 and 21% for the third quarter of 2023. The decrease in royalty rates for the three months and year ended December 31, 2023 from the comparable periods was primarily due to lower benchmark prices and fluctuations in the WCS Heavy Differential.

Natural gas royalty rates averaged approximately 4% of product sales for the year ended December 31, 2023 compared with 9% of product sales for the year ended December 31, 2022. Natural gas royalty rates averaged approximately 3% of product sales for the fourth quarter of 2023 compared with 8% for the fourth quarter of 2022, and 3% for the third quarter of 2023. The decrease in royalty rates for the three months and year ended December 31, 2023 from the comparable periods in 2022 was primarily due to lower benchmark prices.

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

Canadian Natural Resources Limited 14 Three months and year ended December 31, 2023

Offshore Africa

Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital expenditures and production expenses, the status of payouts, and the timing of liftings from each field.

Royalty rates as a percentage of product sales averaged approximately 9% for the year ended December 31, 2023, comparable with 9% of product sales for the year ended December 31, 2022. Royalty rates as a percentage of product sales averaged approximately 9% for the fourth quarter of 2023 compared with 13% of product sales for the fourth quarter of 2022, and 7% for the third quarter of 2023. Royalty rates as a percentage of product sales reflected the timing of liftings and the status of payout in the various fields.

PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION

	Three Months Ended						Year Ended
	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Crude oil and NGLs ($/bbl) (1)
North America	$	12.56	$	13.21	$	16.80	$	14.46	$	16.25
International average	$	54.95	$	44.16	$	69.70	$	48.16	$	51.01
North Sea	$	92.28	$	83.44	$	100.30	$	85.57	$	88.99
Offshore Africa	$	23.25	$	20.04	$	24.30	$	21.14	$	17.25
Crude oil and NGLs average	$	15.05	$	14.40	$	20.37	$	16.12	$	18.17
Natural gas ($/Mcf) (1)
North America	$	1.09	$	1.22	$	1.22	$	1.27	$	1.19
International average	$	8.76	$	7.40	$	8.07	$	7.26	$	5.16
North Sea	$	9.52	$	9.19	$	10.38	$	9.85	$	9.27
Offshore Africa	$	8.65	$	7.21	$	6.98	$	6.83	$	4.40
Natural gas average	$	1.13	$	1.25	$	1.25	$	1.30	$	1.22
Average($/BOE) (1)	$	11.75	$	11.64	$	15.17	$	12.74	$	13.76

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

North America

North America crude oil and NGLs production expense for the year ended December 31, 2023 averaged $14.46 per bbl, a decrease of 11% from $16.25 per bbl for the year ended December 31, 2022. North America crude oil and NGLs production expense for the fourth quarter of 2023 of $12.56 per bbl decreased 25% from $16.80 per bbl for the fourth quarter of 2022, and decreased 5% from $13.21 per bbl for the third quarter of 2023. The decrease in crude oil and NGLs production expense per bbl for the year ended December 31, 2023 from year ended December 31, 2022 primarily reflected lower energy costs, partially offset by higher service costs. The decrease in crude oil and NGLs production expense per bbl for the fourth quarter of 2023 to the fourth quarter of 2022 primarily reflected lower energy costs and higher production volumes. The decrease in crude oil and NGLs production expense per bbl for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected lower energy costs.

North America natural gas production expense averaged $1.27 per Mcf for the year ended December 31, 2023, an increase of 7% from $1.19 per Mcf for the year ended December 31, 2022. North America natural gas production expense for the fourth quarter of 2023 averaged $1.09 per Mcf, a decrease of 11% from $1.22 per Mcf for the fourth quarter of 2022 and for the third quarter of 2023. The increase in natural gas production expense per Mcf for the year ended December 31, 2023 from the year ended December 31, 2022 primarily reflected higher service costs. The decrease in natural gas production expense per Mcf for the fourth quarter of 2023 from the fourth quarter of 2022 was primarily due to lower power costs and higher production volumes, together with the impact of extreme cold weather conditions in the fourth quarter of 2022. The decrease from the third quarter of 2023 primarily reflected higher production volumes and lower energy costs.

Canadian Natural Resources Limited 15 Three months and year ended December 31, 2023

International

International crude oil and NGLs production expense for the year ended December 31, 2023 averaged $48.16 per bbl, a decrease of 6% from $51.01 per bbl for the year ended December 31, 2022. International crude oil and NGLs production expense for the fourth quarter of 2023 of $54.95 per bbl decreased 21% from $69.70 per bbl for the fourth quarter of 2022, and increased 24% from $44.16 per bbl for the third quarter of 2023. The decrease in crude oil and NGLs production expense per bbl for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected lower energy costs and the timing of liftings from various fields that have different cost structures. The increase in crude oil and NGLs production expense per bbl for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected the timing of liftings from various fields. Fluctuations in production expense per bbl also included the impact of foreign exchange.

ADJUSTED DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION

	Three Months Ended						Year Ended
($ millions, except per BOE amounts)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
North America	$	971	$	947	$	949	$	3,679	$	3,595
North Sea	466		12		1,653		494		1,747
Offshore Africa	66		47		41		213		173
Depletion, depreciation and amortization	$	1,503	$	1,006	$	2,643	$	4,386	$	5,515
Less: Recoverability charge (1) (2)	436		—		1,620		436		1,620
Adjusted depletion, depreciation and amortization (3)	$	1,067	$	1,006	$	1,023	$	3,950	$	3,895
$/BOE (4)	$	12.46	$	12.22	$	12.78	$	12.27	$	12.45

(1)As at December 31, 2023, as a result of revised project scope and the current cost environment, the Company recognized a recoverability charge of $436 million in depletion, depreciation and amortization expense related to an increase in its estimate of future abandonment costs for the Ninian field in the North Sea.

(2)Prevailing regulatory and economic conditions and the increasingly challenging commercial outlook in the United Kingdom, including the impact of higher natural gas and carbon costs, led the Company to assess the viability of its North Sea operations in 2022. As at December 31, 2022 the Company completed a recoverability assessment of its assets in the North Sea, and recognized a recoverability charge of $1,620 million in depletion, depreciation, and amortization expense following a detailed assessment which determined that the Ninian field was no longer economic.

(3)This is a non-GAAP 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 applicable, as an indication of the Company's performance.

(4)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 year ended December 31, 2023 averaged $12.27 per BOE, comparable with $12.45 per BOE for the year ended December 31, 2022. Adjusted depletion, depreciation and amortization expense for the fourth quarter of 2023 averaged $12.46 per BOE, comparable with $12.78 per BOE for the fourth quarter of 2022, and $12.22 per BOE for the third quarter of 2023.

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

Canadian Natural Resources Limited 16 Three months and year ended December 31, 2023

ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION

	Three Months Ended						Year Ended
($ millions, except per BOE amounts)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
North America	$	58	$	59	$	51	$	234	$	171
North Sea	12		11		10		46		33
Offshore Africa	2		2		2		8		7
Asset retirement obligation accretion	$	72	$	72	$	63	$	288	$	211
$/BOE (1)	$	0.84	$	0.87	$	0.78	$	0.89	$	0.67

(1)Calculated as asset retirement obligation accretion divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time.

Asset retirement obligation accretion expense for the year ended December 31, 2023 of $0.89 per BOE increased 33% from $0.67 per BOE for the year ended December 31, 2022. Asset retirement obligation accretion expense for the fourth quarter of 2023 of $0.84 per BOE increased 8% from $0.78 per BOE for the fourth quarter of 2022, and decreased 3% from $0.87 per BOE for the third quarter of 2023. The increase in asset retirement obligation accretion expense per BOE for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected the impact of cost, inflation and timing estimates, regulatory changes, and discount rate revisions made to the asset retirement obligation during 2022, partially offset by higher sales volumes in 2023. The decrease in asset retirement obligation accretion expense per BOE for the fourth quarter of 2023 from the third quarter of 2023 reflected higher sales volumes.

OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING

The Company continues to focus on safe, reliable, and efficient operations leveraging its technical expertise across the Horizon and AOSP sites with record SCO production averaging 500,133 bbl/d in the fourth quarter of 2023.

The Company incurred production expense of $947 million for the fourth quarter of 2023, a decrease of 7% from $1,017 million for the fourth quarter of 2022, and a decrease of 6% from $1,003 million for the third quarter of 2023, reflecting the Company's continued focus on cost control and efficiencies across the entire asset base.

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

	Three Months Ended						Year Ended
($/bbl)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Realized SCO sales price (1)	$	98.73	$	108.55	$	103.79	$	100.06	$	117.69
Bitumen value for royalty purposes (2)	$	61.73	$	84.66	$	58.24	$	65.43	$	83.07
Bitumen royalties (3)	$	11.57	$	21.90	$	14.48	$	14.43	$	20.71
Transportation (1)	$	1.85	$	2.18	$	1.80	$	1.89	$	1.71

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

(2)Calculated as the quarterly average of the bitumen methodology price.

(3)Calculated as royalties divided by sales volumes.

The realized SCO sales price averaged $100.06 per bbl for the year ended December 31, 2023, a decrease of 15% from $117.69 per bbl for the year ended December 31, 2022. The realized SCO sales price averaged $98.73 per bbl for the fourth quarter of 2023, a decrease of 5% from $103.79 per bbl for the fourth quarter of 2022, and a decrease of 9% from $108.55 per bbl for the third quarter of 2023. The decrease in the realized SCO sales price for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected the decrease in WTI benchmark pricing. The decrease in realized SCO sales price for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected WTI benchmark pricing, together with increased production and egress constraints in the WCSB.

Canadian Natural Resources Limited 17 Three months and year ended December 31, 2023

The decrease in bitumen royalties per bbl for the year ended December 31, 2023 from the year ended December 31, 2022 primarily reflected the impact of lower prevailing bitumen pricing and the impact of sliding scale royalty rates. The decrease in bitumen royalties per bbl for the fourth quarter of 2023 from the fourth quarter of 2022 primarily reflected sliding scale royalty rates. The decrease for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected lower prevailing bitumen pricing and the impact of sliding scale royalty rates.

Transportation expense averaged $1.89 per bbl for the year ended December 31, 2023, an increase of 11% from $1.71 per bbl for the year ended December 31, 2022. Transportation expense averaged $1.85 per bbl for the fourth quarter of 2023, an increase of 3% from $1.80 per bbl for the fourth quarter of 2022, and a decrease of 15% from $2.18 per bbl for the third quarter of 2023. The increase in transportation expense per bbl for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected higher sales to the US Gulf Coast in 2023. The decrease for fourth quarter of 2023 from the third quarter of 2023 primarily reflected lower sales to the US Gulf Coast.

PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING

The following tables are reconciled to the Oil Sands Mining and Upgrading production expense disclosed in note 17 to the financial statements.

	Three Months Ended						Year Ended
($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Production expense, excluding natural gas costs	$	904	$	962	$	933	$	3,794	$	3,743
Natural gas costs	43		41		84		195		333
Production expense	$	947	$	1,003	$	1,017	$	3,989	$	4,076

	Three Months Ended						Year Ended
($/bbl)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Production expense, excluding natural gas costs (1)	$	20.00	$	21.22	$	23.37	$	23.13	$	23.91
Natural gas costs (2)	0.96		0.90		2.11		1.19		2.13
Production expense (3)	$	20.96	$	22.12	$	25.48	$	24.32	$	26.04
Sales volumes (bbl/d)	491,339		492,926		433,731		449,282		428,820

(1)Calculated as production expense, excluding natural gas costs divided by sales volumes.

(2)Calculated as natural gas costs divided by sales volumes.

(3)Calculated as production expense divided by sales volumes.

Production expense for the year ended December 31, 2023 averaged $24.32 per bbl, a decrease of 7% from $26.04 per bbl for the year ended December 31, 2022. Production expense for the fourth quarter of 2023 averaged $20.96 per bbl, a decrease of 18% from $25.48 per bbl for the fourth quarter of 2022, and a decrease of 5% from $22.12 per bbl for the third quarter of 2023. The decrease in production expense per bbl for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected higher production volumes and lower energy costs. The decrease in production expense per bbl for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected lower energy costs.

DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING

	Three Months Ended						Year Ended
($ millions, except per bbl amounts)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Depletion, depreciation and amortization	$	554	$	527	$	481	$	2,011	$	1,822
$/bbl (1)	$	12.25	$	11.62	$	12.07	$	12.26	$	11.64

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

Canadian Natural Resources Limited 18 Three months and year ended December 31, 2023

Depletion, depreciation and amortization expense for the year ended December 31, 2023 of $12.26 per bbl increased 5% from $11.64 per bbl for the year ended December 31, 2022. Depletion, depreciation and amortization expense for the fourth quarter of 2023 of $12.25 per bbl was comparable with $12.07 per bbl for the fourth quarter of 2022, and increased 5% from $11.62 per bbl for the third quarter of 2023. The increase in depletion, depreciation and amortization expense on a per bbl basis for the year ended December 31, 2023 from the comparable period in 2022 primarily reflected the impact of a higher depletable base due to asset additions, partially offset by higher sales volumes in 2023. The increase in depletion, depreciation and amortization expense on a per bbl basis for the fourth quarter of 2023 from the third quarter of 2023 primarily reflected a higher depletable base due to asset additions.

ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING

	Three Months Ended						Year Ended
($ millions, except per bbl amounts)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Asset retirement obligation accretion	$	19	$	20	$	19	$	78	$	70
$/bbl (1)	$	0.43	$	0.43	$	0.49	$	0.48	$	0.45

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

Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time.

Asset retirement obligation accretion expense for the year ended December 31, 2023 of $0.48 per bbl increased 7% from $0.45 per bbl for the year ended December 31, 2022. Asset retirement obligation accretion expense for the fourth quarter of 2023 of $0.43 per bbl decreased 12% from $0.49 per bbl for the fourth quarter of 2022, and was comparable with $0.43 per bbl for the third quarter of 2023. The increase in asset retirement obligation accretion expense on a per bbl basis for the year ended December 31, 2023 from the comparable period in 2022 primarily reflected the impact of cost, inflation and timing estimates, and discount rate revisions made to the asset retirement obligation during 2022, partially offset by higher sales volumes in 2023. The decrease in asset retirement obligation accretion expense on a per bbl basis for the fourth quarter of 2023 from the fourth quarter of 2022 primarily reflected the impact of higher sales volumes in the fourth quarter of 2023.

MIDSTREAM AND REFINING

	Three Months Ended						Year Ended
($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Product sales
Midstream activities	$	20	$	20	$	21	$	76	$	80
NWRP, refined product sales and other	236		237		205		926		906
Segmented revenue	256		257		226		1,002		986
Less:
NWRP, refining toll	82		66		57		303		247
Midstream activities	7		8		6		29		24
Production expense	89		74		63		332		271
NWRP, transportation and feedstock costs	166		183		155		664		691
Depreciation	4		4		5		16		16
Segmented (loss) earnings	$	(3)	$	(4)	$	3	$	(10)	$	8

The Company's Midstream and Refining assets consist of two crude oil pipeline systems, a 50% working interest in an 84-megawatt cogeneration plant at Primrose and the Company's 50% equity investment in North West Redwater Partnership ("NWRP").

Canadian Natural Resources Limited 19 Three months and year ended December 31, 2023

NWRP operates a 50,000 bbl/d bitumen upgrader and refinery that processes approximately 12,500 bbl/d (25% toll payer) of bitumen feedstock for the Company and 37,500 bbl/d (75% toll payer) of bitumen feedstock for the Alberta Petroleum Marketing Commission ("APMC"), an agent of the Government of Alberta. The Company is unconditionally obligated to pay its 25% pro rata share of the debt component of the monthly fee-for-service toll over the 40-year tolling period until 2058. Sales of diesel and refined products and associated refining tolls are recognized in the Midstream and Refining segment. For the fourth quarter of 2023, production of ultra-low sulphur diesel and other refined products averaged 83,294 BOE/d (20,824 BOE/d to the Company), (three months ended September 30, 2023 – 78,376 BOE/d; 19,594 BOE/d to the Company; three months ended December 31, 2022 – 54,593 BOE/d; 13,648 BOE/d to the Company), reflecting the 25% toll payer commitment.

As at December 31, 2023, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $555 million (December 31, 2022 – $551 million). For the three months ended December 31, 2023, the Company's unrecognized share of the equity loss was $5 million (year ended December 31, 2023 – unrecognized equity loss of $4 million; three months ended December 31, 2022 – recovery of unrecognized equity losses of $37 million; year ended December 31, 2022 – recovery of unrecognized equity losses of $11 million).

ADMINISTRATION EXPENSE

	Three Months Ended						Year Ended
($ millions, except per BOE amounts)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Administration expense	$	119	$	108	$	108	$	452	$	415
$/BOE (1)	$	0.91	$	0.84	$	0.90	$	0.93	$	0.88
Sales volumes (BOE/d) (2)	1,422,198		1,388,033		1,303,996		1,331,092		1,285,877

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

(2)Total Company sales volumes.

Administration expense for the year ended December 31, 2023 of $0.93 per BOE increased 6% from $0.88 per BOE for the year ended December 31, 2022. Administration expense for the fourth quarter of 2023 of $0.91 per BOE was comparable with $0.90 per BOE for the fourth quarter of 2022, and increased 8% from $0.84 per BOE for the third quarter of 2023. The increase in administration expense per BOE for the three months and year ended December 31, 2023 from the comparable periods primarily reflected higher personnel and corporate costs, partially offset by higher sales volumes and higher overhead recoveries.

SHARE-BASED COMPENSATION

	Three Months Ended						Year Ended
($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Stock-based compensation expense	$	57	$	298	$	319	$	491	$	804

The Company's Stock Option Plan provides employees with the right to receive common shares or a cash payment in exchange for stock options surrendered. The Performance Share Unit ("PSU") plan provides certain executive employees of the Company with the right to receive a cash payment, the amount of which is determined with reference to the value of the Company's shares, and by individual employee performance and the extent to which certain other performance measures are met.

The Company recognized $491 million of share-based compensation expense for the year ended December 31, 2023, primarily as a result of the measurement of the fair value of outstanding stock options related to the impact of normal course graded vesting of stock options granted in prior periods, the impact of vested stock options exercised or surrendered during the period, and changes in the Company's share price.

Canadian Natural Resources Limited 20 Three months and year ended December 31, 2023

INTEREST AND OTHER FINANCING EXPENSE

	Three Months Ended						Year Ended
($ millions, except effective interest rate)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Interest and other financing expense	$	117	$	187	$	76	$	636	$	549
Less: Interest income and other (1)	(53)		4		(93)		(55)		(121)
Interest expense on long-term debt and lease liabilities (1)	$	170	$	183	$	169	$	691	$	670
Average current and long-term debt (2)	$	12,350	$	13,393	$	13,174	$	12,749	$	13,986
Average lease liabilities (2)	1,484		1,490		1,508		1,500		1,531
Average long-term debt and lease liabilities (2)	$	13,834	$	14,883	$	14,682	$	14,249	$	15,517
Average effective interest rate (3) (4)	4.8%		4.8%		4.5%		4.8%		4.3%
Interest and other financing expense per $/BOE (5)	$	0.90	$	1.46	$	0.63	$	1.31	$	1.17
Sales volumes (BOE/d) (6)	1,422,198		1,388,033		1,303,996		1,331,092		1,285,877

(1)Item is a component of interest and other financing expense.

(2)The average of current and long-term debt and lease liabilities outstanding during the respective 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 per BOE for the year ended December 31, 2023 of $1.31 per BOE increased 12% from $1.17 per BOE for the year ended December 31, 2022. Interest and other financing expense per BOE for the fourth quarter of 2023 increased 43% to $0.90 per BOE from $0.63 per BOE for the fourth quarter of 2022, and decreased 38% from $1.46 per BOE for the third quarter of 2023. The increase in interest and other financing expense per BOE for the three months and year ended December 31, 2023 from the comparable periods in 2022 primarily reflected the impact of higher interest rates on floating rate long-term debt, together with the impact of higher accrued interest income on the deferred PRT recovery in 2022, partially offset by lower average debt levels in 2023. The decrease for the fourth quarter of 2023 from the third quarter of 2023 reflected accrued interest on deferred PRT, combined with lower average debt levels and higher sales volumes in the fourth quarter.

The Company's average effective interest rate for the three months and year ended December 31, 2023 increased from the comparable periods in 2022 primarily due to higher prevailing interest rates on floating rate long-term debt held during 2023.

Canadian Natural Resources Limited 21 Three months and year ended December 31, 2023

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						Year Ended
($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Foreign currency contracts	$	(15)	$	30	$	3	$	(17)	$	(37)
Natural gas financial instruments (1) (2)	(2)		(1)		(6)		3		13
Crude oil and NGLs financial instruments (1)	—		—		1		—		17
Net realized (gain) loss	(17)		29		(2)		(14)		(7)
Foreign currency contracts	(16)		2		(2)		(9)		(16)
Natural gas financial instruments (1) (2)	9		1		18		21		(10)
Crude oil and NGLs financial instruments (1)	—		—		(1)		—		(2)
Net unrealized (gain) loss	(7)		3		15		12		(28)
Net (gain) loss	$	(24)	$	32	$	13	$	(2)	$	(35)

(1)Certain commodity financial instruments were assumed in the acquisition of Storm Resources Ltd., and Painted Pony Energy Ltd in the fourth quarter of 2021 and 2020, respectively.

(2)In the fourth quarter of 2023, the Company entered into 50,000 MMBtu/d of US$1.82 AECO fixed price financial hedge contracts for the period of January to December 2024.

During the year ended December 31, 2023, net realized risk management gains were related to the settlement of foreign currency contracts, partially offset by realized losses on the settlement of natural gas financial instruments. The Company recorded a net unrealized loss of $12 million ($7 million after-tax of $5 million) on its risk management activities for the year ended December 31, 2023, including a net unrealized gain of $7 million ($9 million after-tax of $2 million) for the fourth quarter of 2023 (three months ended September 30, 2023 – unrealized loss of $3 million, $2 million after-tax of $1 million; three months ended December 31, 2022 – unrealized loss of $15 million, $11 million after-tax of $4 million; year ended December 31, 2022 – unrealized gain of $28 million, $25 million after-tax of $3 million).

Further details related to outstanding derivative financial instruments as at December 31, 2023 are disclosed in note 15 to the financial statements.

FOREIGN EXCHANGE

	Three Months Ended						Year Ended
($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Net realized loss (gain)	$	11	$	(48)	$	18	$	(19)	$	(114)
Net unrealized (gain) loss	(276)		250		(203)		(260)		852
Net (gain) loss (1)	$	(265)	$	202	$	(185)	$	(279)	$	738

(1)Amounts are reported net of the hedging effect of cross currency swaps.

The net realized foreign exchange gain for the year ended December 31, 2023 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling. The net unrealized foreign exchange gain for the year ended December 31, 2023 was primarily related to the translation of outstanding US dollar debt. The US/Canadian dollar exchange rate as at December 31, 2023 was US$0.7573 (September 30, 2023 – US$0.7387, December 31, 2022 – US$0.7389).

Canadian Natural Resources Limited 22 Three months and year ended December 31, 2023

INCOME TAXES

	Three Months Ended						Year Ended
($ millions, except effective tax rates)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
North America (1)	$	487	$	587	$	345	$	1,853	$	2,789
North Sea	3		(11)		33		(6)		69
Offshore Africa	20		23		23		73		74
Current PRT– North Sea	(13)		—		(5)		(58)		(42)
Other taxes	8		3		3		17		16
Current income tax	505		602		399		1,879		2,906
Deferred corporate income tax	64		195		(148)		267		302
Deferred PRT– North Sea	(238)		6		(441)		(214)		(441)
Deferred income tax	(174)		201		(589)		53		(139)
Income tax	$	331	$	803	$	(190)	$	1,932	$	2,767
Earnings before taxes	$	2,958	$	3,147	$	1,330	$	10,165	$	13,704
Effective tax rate on net earnings (2)	11%		26%		(14)%		19%		20%
	Three Months Ended						Year Ended
($ millions, except effective tax rates)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Income tax	$	331	$	803	$	(190)	$	1,932	$	2,767
Tax effect on non-operating items (3)	331		4		980		345		964
Current PRT – North Sea	13		—		5		58		42
Deferred PRT – North Sea	33		(6)		—		9		—
Other taxes	(8)		(3)		(3)		(17)		(16)
Effective tax on adjusted net earnings	$	700	$	798	$	792	$	2,327	$	3,757
Adjusted net earnings from operations (4)	$	2,546	$	2,850	$	2,194	$	8,533	$	12,863
Adjusted net earnings from operations, before taxes	$	3,246	$	3,648	$	2,986	$	10,860	$	16,620
Effective tax rate on adjusted net earnings from operations (5) (6)	22%		22%		27%		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, unrealized risk management, and government grant income related to abandonment expenditures in 2022, as well as deferred PRT and income tax recoveries related to the recoverability charges recognized in 2023 and 2022.

(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 months and year ended December 31, 2023 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 months and year ended December 31, 2023 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 23 Three months and year ended December 31, 2023

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						Year Ended
($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Exploration and Production
Exploration and Evaluation Assets
Net expenditures	$	12	$	(2)	$	11	$	47	$	36
Net property dispositions	—		(1)		(2)		(3)		(3)
Total Exploration and Evaluation Assets	12		(3)		9		44		33
Property, Plant and Equipment
Net property (dispositions) acquisitions	(1)		8		—		24		513
Well drilling, completion and equipping	274		352		407		1,579		1,545
Production and related facilities	251		301		351		1,267		1,233
Other	13		18		15		61		59
Total Property, Plant and Equipment	537		679		773		2,931		3,350
Total Exploration and Production	549		676		782		2,975		3,383
Oil Sands Mining and Upgrading
Project costs	78		112		98		348		294
Sustaining capital	320		286		367		1,347		1,171
Turnaround costs	17		18		16		189		287
Net property (dispositions) acquisitions	(1)		6		(40)		5		(40)
Other	1		2		1		5		7
Total Oil Sands Mining and Upgrading	415		424		442		1,894		1,719
Midstream and Refining	4		1		2		10		9
Head office	7		7		7		30		25
Net capital expenditures	$	975	$	1,108	$	1,233	$	4,909	$	5,136
Abandonment expenditures, net (3)	$	149	$	123	$	84	$	509	$	335
By Segment
North America	$	479	$	629	$	677	$	2,770	$	3,133
North Sea	11		14		48		33		126
Offshore Africa	59		33		57		172		124
Oil Sands Mining and Upgrading	415		424		442		1,894		1,719
Midstream and Refining	4		1		2		10		9
Head office	7		7		7		30		25
Net capital expenditures	$	975	$	1,108	$	1,233	$	4,909	$	5,136

(1)Net capital expenditures exclude the impact of lease assets and fair value and revaluation adjustments, and include non-cash transfers of property, plant and equipment to inventory due to change in use.

(2)Non-GAAP Financial Measure. The composition of this measure has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

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

Canadian Natural Resources Limited 24 Three months and year ended December 31, 2023

The Company's strategy is focused on building a diversified asset base that is balanced among various products. In order to facilitate efficient operations, the Company concentrates its activities in core areas. The Company focuses on maintaining its land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning associated infrastructure the Company is able to maximize utilization of its production facilities, thereby increasing control over production expenses.

Net capital expenditures for the year ended December 31, 2023 were $4,909 million compared with $5,136 million for the year ended December 31, 2022. Net capital expenditures for the year ended December 31, 2023 included base capital expenditures (1) of $3,958 million and strategic growth capital expenditures (1) of $925 million, in accordance with the Company's 2023 capital budget. Net capital expenditures were $975 million for the fourth quarter of 2023 compared with $1,233 million for the fourth quarter of 2022 and $1,108 million for the third quarter of 2023.

In addition, the Company reported abandonment expenditures (2) of $509 million for the year ended December 31, 2023 compared with $335 million for the year ended December 31, 2022. Abandonment expenditures were $149 million for the fourth quarter of 2023 compared with $84 million for the fourth quarter of 2022 and $123 million for the third quarter of 2023.

2024 Capital Budget

On December 14, 2023, the Company announced its 2024 capital budget targeted at approximately $5,420 million, and targeting to provide near-term production growth in 2024 and mid- and long-term production and capacity growth in 2025 and beyond. Production for 2024 is targeted between 1,330,000 BOE/d and 1,380,000 BOE/d. In addition, the Company targets $635 million in abandonment expenditures for 2024.

The 2024 capital budget constitutes forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Drilling Activity(1) (2)

	Three Months Ended			Year Ended
(number of net wells)	Dec 31 2023	Sep 30 2023	Dec 31 2022	Dec 31 2023	Dec 31 2022
Net successful crude oil wells (3)	42	44	80	221	317
Net successful natural gas wells	9	10	15	61	72
Dry wells	—	—	—	2	1
Total	51	54	95	284	390
Success rate	100%	100%	100%	99%	99%

(1)Includes drilling activity for North America and International segments.

(2)In addition, during the fourth quarter of 2023, on a net basis, the Company drilled 5 service wells in the Company's thermal oil projects. During the year ended December 31, 2023, on a net basis, the Company drilled 334 stratigraphic and 11 service wells in the Oil Sands Mining and Upgrading segment, 24 stratigraphic and 48 service wells in the Company's thermal oil projects, and 2 service wells in the Northern Plains region.

(3)Includes bitumen wells.

North America

During the fourth quarter of 2023, the Company drilled 9 net natural gas wells, 32 net primary heavy crude oil wells, and 10 net light crude oil wells.

(1)Item is a component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A for more details on net capital expenditures.

(2)A reconciliation of abandonment expenditures and abandonment expenditures, net is presented in the "Non-GAAP and Other Financial Measures" section of this MD&A.

Canadian Natural Resources Limited 25 Three months and year ended December 31, 2023

LIQUIDITY AND CAPITAL RESOURCES

($ millions, except ratios)	Dec 31 2023		Sep 30 2023		Dec 31 2022
Adjusted working capital (1)	$	712	$	866	$	(1,190)
Long-term debt, net (2)	$	9,922	$	11,519	$	10,525
Shareholders' equity	$	39,832	$	39,634	$	38,175
Debt to book capitalization (2)	19.9%		22.5%		21.6%
After-tax return on average capital employed (3)	17.2%		15.0%		22.1%

(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 December 31, 2023, 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, 2022. 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 maintenance and growth capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. The Company continues to exercise its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments and long-term debt;

▪Monitoring the Company's ability to fulfill financial obligations as they become due or the ability to monetize assets in a timely manner at a reasonable price;

▪Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages; and

▪Reviewing the Company's borrowing capacity:

◦During the third quarter of 2023, the Company extended its $500 million revolving credit facility, originally maturing February 2024, to February 2025.

◦During the second quarter of 2023, the Company extended its $2,425 million revolving syndicated credit facility, originally maturing June 2024, to June 2027.

◦Borrowings under the Company's revolving credit facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers' acceptances, SOFR, US base rate or Canadian prime rate.

◦The Company's borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million.

◦During the fourth quarter of 2023, the Company repaid $405 million of 1.45% medium-term notes.

Canadian Natural Resources Limited 26 Three months and year ended December 31, 2023

◦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, replacing the Company's previous base shelf prospectus which would have expired in August 2023. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.

◦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, replacing the Company's previous base shelf prospectus which would have expired in August 2023. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.

As at December 31, 2023, the Company had undrawn revolving bank credit facilities of $5,450 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,852 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit. At December 31, 2023, the Company had no commercial paper 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 $9,922 million as at December 31, 2023, resulting in a debt to book capitalization ratio (1) of 19.9% (December 31, 2022 – 21.6%); this ratio was below the 25% to 45% internal range utilized by management. The ratio may fall below or exceed the targeted range depending on the timing of acquisitions, the execution of the Company's capital program, and commodity price and foreign currency volatility. The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital structure. Further details related to the Company's long-term debt as at December 31, 2023 are discussed in note 8 to the financial statements.

The Company is subject to a financial covenant that requires debt to book capitalization as defined in its credit facility agreements to not exceed 65%. As at December 31, 2023, the Company was in compliance with this covenant.

The Company periodically utilizes commodity derivative financial instruments under its commodity hedge policy to reduce the risk of volatility in commodity prices and to support the Company's cash flow for its capital expenditure programs. This policy currently allows for the hedging of up to 60% of the near 12 months budgeted production and up to 40% of the following 13 to 24 months estimated production. For the purpose of this policy, the purchase of put options is in addition to the above parameters.

As at December 31, 2023, 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)	$	980	$	1,584	$	2,317	$	5,978
Other long-term liabilities (2)	$	302	$	184	$	428	$	645
Interest and other financing expense (3)	$	582	$	518	$	1,257	$	3,362

(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, $298 million; one to less than two years, $184 million; two to less than five years, $428 million; and thereafter, $645 million.

(3)Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates as at December 31, 2023.

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

Canadian Natural Resources Limited 27 Three months and year ended December 31, 2023

Share Capital

As at December 31, 2023, there were 1,072,408,000 common shares outstanding (December 31, 2022 – 1,102,636,000 common shares) and 26,205,000 stock options outstanding (December 31, 2022 – 31,150,000). As at February 27, 2024, the Company had 1,070,845,000 common shares outstanding and 28,296,000 stock options outstanding.

On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to $1.05 per common share, beginning with the dividend payable on April 5, 2024.

On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $1.00 per common share. On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share. On November 2, 2022, the Board of Directors approved a 13% increase in the quarterly dividend to $0.85 per common share. On August 3, 2022, the Board of Directors approved a special dividend of $1.50 per common share. On March 2, 2022, the Board of Directors approved a 28% increase in the quarterly dividend to $0.75 per common share, from $0.5875 per common share. The dividend policy undergoes periodic review by the Board of Directors and is subject to change.

On March 8, 2023, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock Exchange, alternative Canadian trading platforms, and the New York Stock Exchange, up to 92,296,006 common shares, representing 10% of the public float, over a 12-month period commencing March 13, 2023 and ending March 12, 2024.

For the year ended December 31, 2023, the Company purchased 40,050,000 common shares at a weighted average price of $82.86 per common share for a total cost of $3,318 million. Retained earnings were reduced by $2,929 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to December 31, 2023, up to and including February 27, 2024, the Company purchased 4,000,000 common shares at a weighted average price of $85.54 per common share for a total cost of $342 million.

On February 28, 2024, the Board of Directors approved a resolution authorizing the Company to file a Notice of Intention with the TSX to purchase, by way of Normal Course Issuer Bid, up to 10% of the public float (as determined in accordance with the rules of the TSX) of its issued and outstanding common shares. Subject to acceptance of the Notice of Intention by the TSX, the purchases would be made through facilities of the TSX, alternative Canadian trading platforms, and the NYSE.

Share Split

On February 28, 2024, the Company's Board of Directors approved a resolution to subdivide the Company's common shares on a two for one basis, subject to shareholder approval and the Company having obtained all regulatory approvals, including TSX approval. The proposal will be voted on at the Company's Annual and Special Meeting of Shareholders to be held on May 2, 2024.

COMMITMENTS AND CONTINGENCIES

In the normal course of business, the Company has committed to certain payments. The following table summarizes the Company's commitments as at December 31, 2023:

($ millions)	2024		2025		2026		2027		2028		Thereafter
Product transportation and processing (1)	$	1,572	$	1,595	$	1,408	$	1,358	$	1,242	$	13,380
North West Redwater Partnership service toll (2)	$	158	$	157	$	139	$	126	$	130	$	4,985
Offshore vessels and equipment	$	36	$	—	$	—	$	—	$	—	$	—
Field equipment and power	$	38	$	25	$	23	$	22	$	22	$	193
Other	$	145	$	111	$	112	$	25	$	26	$	355

(1)The Company's commitment for the 20-year product transportation agreement on the Trans Mountain Pipeline Expansion 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 $3,011 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.

Canadian Natural Resources Limited 28 Three months and year ended December 31, 2023

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, 2022.

CONTROL ENVIRONMENT

There have been no changes to internal control over financial reporting ("ICFR") during the year ended December 31, 2023 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 29 Three months and year ended December 31, 2023

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						Year Ended
($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Net earnings	$	2,627	$	2,344	$	1,520	$	8,233	$	10,937
Share-based compensation, net of tax (1)	51		295		309		474		780
Unrealized risk management (gain) loss, net of tax (2)	(9)		2		11		7		(25)
Unrealized foreign exchange (gain) loss, net of tax (3)	(276)		250		(203)		(260)		852
Realized foreign exchange loss (gain), net of tax (4)	—		—		7		—		(62)
Loss (gain) from investments, net of tax (5)	40		(41)		(88)		(34)		(182)
Recoverability charge, net of tax (6) (7)	113		—		651		113		651
Other, net of tax (8)	—		—		(13)		—		(88)
Non-operating items, net of tax	(81)		506		674		300		1,926
Adjusted net earnings from operations	$	2,546	$	2,850	$	2,194	$	8,533	$	12,863

(1)Share-based compensation includes costs incurred under the Company's Stock Option Plan and PSU plan. The fair value of the share-based compensation is recognized as a liability on the Company's balance sheets and periodic changes in the fair value are recognized in net earnings. Pre-tax share-based compensation for the three months ended December 31, 2023 was an expense of $57 million (three months ended September 30, 2023 – $298 million expense, three months ended December 31, 2022 – $319 million expense; year ended December 31, 2023 – $491 million expense, year ended December 31, 2022 – $804 million expense).

(2)Derivative financial instruments are recognized at fair value on the Company's balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than those amounts reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil, natural gas and foreign exchange. Pre-tax unrealized risk management gain for the three months ended December 31, 2023 was $7 million (three months ended September 30, 2023 – $3 million loss, three months ended December 31, 2022 – $15 million loss; year ended December 31, 2023 – $12 million loss, year ended December 31, 2022 – $28 million gain).

(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)During the fourth quarter of 2022, the Company early repaid US$1,000 million of 2.95% debt securities, originally due January 15, 2023, resulting in a realized foreign exchange loss of $7 million. During the second quarter of 2022, the Company settled the US$550 million cross currency swap designated as a cash flow hedge of a portion of the US$1,100 million 6.25% US dollar debt securities due March 2038, resulting in a realized foreign exchange gain of $69 million. Pre- and after-tax amounts for the realized foreign exchange gain on settlement of the swap are the same.

(5)The Company's investments have been accounted for at fair value through profit and loss and are measured each period with gains and losses recognized in net earnings. There is zero net tax impact on these gains and losses from investments.

(6)The Company recognized a pre-tax recoverability charge of $436 million in depletion, depreciation and amortization expense related to revised project scope and the current cost environment for planned decommissioning and abandonment activities at the Ninian field in the North Sea in 2023. The costs are considered to be capital in nature, consistent with the treatment of all abandonment related expenditures for the purpose of the Company's non-GAAP measures.

(7)The Company recognized a pre-tax recoverability charge of $1,620 million in depletion, depreciation and amortization expense at December 31, 2022 relating to the de-booking of reserves at the Ninian field in the North Sea in 2022.

(8)Other relates to the impact of government grant income under the provincial well-site rehabilitation programs. Pre-tax other for the three months ended December 31, 2023 was $nil (three months ended September 30, 2023 – $nil, three months ended December 31, 2022 – $16 million; year ended December 31, 2023 – $nil, year ended December 31, 2022 – $114 million).

Canadian Natural Resources Limited 30 Three months and year ended December 31, 2023

Adjusted Funds Flow

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

	Three Months Ended						Year Ended
($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Cash flows from operating activities	$	4,815	$	3,498	$	4,544	$	12,353	$	19,391
Net change in non-cash working capital	(562)		1,088		(517)		2,417		(79)
Abandonment expenditures, net (1)	149		123		84		509		335
Movements in other long-term assets (2)	17		(25)		65		(5)		144
Adjusted funds flow	$	4,419	$	4,684	$	4,176	$	15,274	$	19,791

(1)Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the "Abandonment Expenditures, net" section below.

(2)Includes the unamortized cost of the share bonus program, the accrued interest on the deferred PRT recovery, 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 14 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.

Abandonment Expenditures, net

Abandonment expenditures, net, is a non-GAAP financial measure that represents the abandonment expenditures to settle asset retirement obligations as reflected in the Company's historical annual capital budgets. Abandonment expenditures, net is calculated as abandonment expenditures, as presented in the Company's consolidated Statements of Cash Flows, adjusted for the impact of government grant income under the provincial well-site rehabilitation programs. A reconciliation of abandonment expenditures, net is presented below.

	Three Months Ended						Year Ended
($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Abandonment expenditures	$	149	$	123	$	100	$	509	$	449
Government grants for abandonment expenditures	—		—		(16)		—		(114)
Abandonment expenditures, net	$	149	$	123	$	84	$	509	$	335

Netback

Netback is a non-GAAP ratio that represents net cash flows provided from core activities after the impact of all costs associated with bringing a product to market, on a per unit basis. The Company considers netback a key measure in evaluating its performance, as it demonstrates the efficiency and profitability of the Company's activities. Refer to the "Operating Highlights – Exploration and Production" 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 non-GAAP financial measures: realized price and transportation, reconciled below to their respective line item in note 17 to the financial statements.

Canadian Natural Resources Limited 31 Three months and year ended December 31, 2023

Realized Price ($/bbl and $/BOE) – Exploration and Production

Realized price ($/bbl and $/BOE) is a non-GAAP ratio calculated as realized crude oil and NGLs sales and total realized BOE sales (non-GAAP financial measures) divided by respective sales volumes. Realized crude oil and NGLs sales and total realized BOE sales include the impact of blending and feedstock costs and other by-product sales. The Company considers realized price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit the Company obtained on the market for its crude oil and NGLs sales volumes and BOE sales volumes.

Reconciliations for Exploration and Production realized crude oil and NGLs sales and BOE sales and the calculations for realized price are presented below.

	Three Months Ended						Year Ended
($ millions, except bbl/d and $/bbl)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Crude oil and NGLs (bbl/d)
North America	526,350		516,038		482,931		497,604		480,691
International
North Sea	15,032		7,839		20,854		10,749		13,215
Offshore Africa	17,705		12,769		14,059		14,882		14,866
Total International	32,737		20,608		34,913		25,631		28,081
Total sales volumes	559,087		536,646		517,844		523,235		508,772
Crude oil and NGLs sales (1)	$	4,790	$	5,351	$	4,505	$	18,387	$	22,072
Less: Blending and feedstock costs (2)	1,222		1,014		1,202		4,568		5,239
Realized crude oil and NGLs sales	$	3,568	$	4,337	$	3,303	$	13,819	$	16,833
Realized price ($/bbl)	$	69.39	$	87.83	$	69.34	$	72.36	$	90.64

(1)Crude oil and NGLs sales in note 17 to the financial statements.

(2)Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration and Production" section.

	Three Months Ended						Year Ended
($ millions, except BOE/d and $/BOE)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Barrels of oil equivalent (BOE/d)
North America	895,996		872,555		833,719		854,138		826,526
International
North Sea	15,296		8,022		21,375		11,034		13,598
Offshore Africa	19,567		14,530		15,171		16,638		16,933
Total International	34,863		22,552		36,546		27,672		30,531
Total sales volumes	930,859		895,107		870,265		881,810		857,057
Barrels of oil equivalent sales (1)	$	5,365	$	5,908	$	5,751	$	20,820	$	27,071
Less: Blending and feedstock costs (2)	1,222		1,014		1,202		4,568		5,239
Less: Sulphur (income) expense	(2)		1		(3)		(14)		(88)
Realized barrels of oil equivalent sales	$	4,145	$	4,893	$	4,552	$	16,266	$	21,920
Realized price ($/BOE)	$	48.41	$	59.40	$	56.83	$	50.54	$	70.07

(1)Barrels of oil equivalent sales includes crude oil and NGLs sales and natural gas sales in note 17 to the financial statements.

(2)Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration and Production" section.

Canadian Natural Resources Limited 32 Three months and year ended December 31, 2023

Transportation – Exploration and Production

Transportation ($/BOE, $/bbl and $/Mcf) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure) divided by the respective sales volumes. The Company calculates transportation to demonstrate its cost to deliver products to the market excluding the impact of blending costs. A reconciliation for Exploration and Production transportation and the calculations for transportation on a per unit basis are presented below.

	Three Months Ended						Year Ended
($ millions, except $ per unit amounts)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Transportation, blending and feedstock (1)	$	1,531	$	1,326	$	1,506	$	5,816	$	6,401
Less: Blending and feedstock costs	1,222		1,014		1,202		4,568		5,239
Transportation	$	309	$	312	$	304	$	1,248	$	1,162
Transportation ($/BOE)	$	3.61	$	3.78	$	3.80	$	3.88	$	3.72
Amounts attributed to crude oil and NGLs	$	197	$	200	$	196	$	807	$	767
Transportation ($/bbl)	$	3.83	$	4.07	$	4.11	$	4.23	$	4.13
Amounts attributed to natural gas	$	112	$	112	$	108	$	441	$	395
Transportation ($/Mcf)	$	0.54	$	0.56	$	0.55	$	0.56	$	0.51

(1)Transportation, blending and feedstock in note 17 to the financial statements.

North America – Realized Product Prices and Royalties

Realized crude oil and NGLs price ($/bbl) is a non-GAAP ratio calculated as realized crude oil and NGLs sales (non-GAAP financial measure) divided by sales volumes. Realized crude oil and NGLs sales include the impact of blending costs. The Company considers the realized crude oil and NGLs price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its crude oil and NGLs sales volumes.

Crude oil and NGLs royalty rate is a non-GAAP ratio that is calculated as crude oil and NGLs royalties divided by realized crude oil and NGLs sales. The Company considers crude oil and NGLs royalty rate a key measure in evaluating its performance, as it describes the Company's royalties for crude oil and NGLs sales volumes on a per unit basis.

A reconciliation for North America realized crude oil and NGLs sales and the calculations for realized crude oil and NGLs prices and the royalty rates are presented below.

	Three Months Ended						Year Ended
($ millions, except $/bbl and royalty rates)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Crude oil and NGLs sales (1)	$	4,451	$	5,135	$	4,124	$	17,375	$	20,755
Less: Blending and feedstock costs (2)	1,222		1,014		1,202		4,568		5,239
Realized crude oil and NGLs sales	$	3,229	$	4,121	$	2,922	$	12,807	$	15,516
Realized crude oil and NGLs prices ($/bbl)	$	66.69	$	86.77	$	65.79	$	70.51	$	88.43
Crude oil and NGLs royalties (3)	$	567	$	845	$	625	$	2,340	$	3,445
Crude oil and NGLs royalty rates	18%		21%		21%		18%		22%

(1)Crude oil and NGLs sales in note 17 to the financial statements.

(2)Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled above in the "Transportation – Exploration and Production" section.

(3)Item is a component of royalties in note 17 to the financial statements.

Realized Product Prices and Transportation – Oil Sands Mining and Upgrading

Realized SCO sales price ($/bbl) is a non-GAAP ratio calculated as realized SCO sales (non-GAAP financial measure) including the impact of blending and feedstock costs, divided by SCO sales volumes. The Company considers realized SCO sales price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its SCO sales volumes.

Canadian Natural Resources Limited 33 Three months and year ended December 31, 2023

Transportation ($/bbl) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure) divided by SCO sales volumes. The Company calculates transportation to demonstrate its cost to deliver product to the market excluding the impact of blending and feedstock costs.

Reconciliations for Oil Sands Mining and Upgrading realized SCO sales and transportation and the calculations for realized SCO sales price and transportation on a per unit basis are presented below.

	Three Months Ended						Year Ended
($ millions, except for bbl/d and $/bbl)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
SCO sales volumes (bbl/d)	491,339		492,926		433,731		449,282		428,820
Crude oil and NGLs sales (1)	$	5,042	$	5,591	$	4,935	$	18,661	$	20,804
Less: Blending and feedstock costs	579		670		795		2,253		2,384
Realized SCO sales	$	4,463	$	4,921	$	4,140	$	16,408	$	18,420
Realized SCO sales price ($/bbl)	$	98.73	$	108.55	$	103.79	$	100.06	$	117.69
Transportation, blending and feedstock (2)	$	663	$	768	$	867	$	2,563	$	2,652
Less: Blending and feedstock costs	579		670		795		2,253		2,384
Transportation	$	84	$	98	$	72	$	310	$	268
Transportation ($/bbl)	$	1.85	$	2.18	$	1.80	$	1.89	$	1.71

(1)Crude oil and NGLs sales in note 17 to the financial statements.

(2)Transportation, blending and feedstock in note 17 to the financial statements.

Change in Composition of Non-GAAP Financial Measure

During the fourth quarter of 2023, the Company revised the composition of its Net Capital Expenditures non-GAAP financial measure to exclude expenditures related to the Company's abandonment program. The revision was made during Management's assessment of its annual capital budgeting process, and will provide users a better representation of the composition of the Company's capital budget, and in evaluating performance. The composition of this measure has been updated for all periods presented.

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, and cash flows from investing activities not included in the Company's capital budget. The Company includes acquisition and disposition capital in net capital expenditures. 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						Year Ended
($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Cash flows used in investing activities	$	946	$	1,199	$	1,262	$	4,858	$	4,987
Net change in non-cash working capital	29		(91)		(29)		51		149
Net capital expenditures (1)	975		1,108		1,233		4,909		5,136
Abandonment expenditures, net (2)	149		123		84		509		335
Capital and abandonment expenditures	$	1,124	$	1,231	$	1,317	$	5,418	$	5,471

(1)For the year ended December 31, 2023 includes base capital expenditures of $3,958 million, and strategic growth capital expenditures of $925 million. Strategic growth capital expenditures represent the allocation of the Company's free cash flow that will be directed to strategic capital growth opportunities that target to increase production volumes in future periods and that exceed the Company's base capital expenditures for the current fiscal year, as outlined in the Company's capital budget.

(2)Non-GAAP Financial Measure. A reconciliation of abandonment expenditures, net is presented in the "Abandonment Expenditures, net" section above.

Canadian Natural Resources Limited 34 Three months and year ended December 31, 2023

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)	Dec 31 2023		Sep 30 2023		Dec 31 2022
Undrawn bank credit facilities	$	5,450	$	5,450	$	5,520
Cash and cash equivalents	877		125		920
Investments	525		565		491
Liquidity	$	6,852	$	6,140	$	6,931

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 13 to the financial statements. A reconciliation of long-term debt, net is presented below.

($ millions)	Dec 31 2023		Sep 30 2023		Dec 31 2022
Long-term debt	$	10,799	$	11,644	$	11,445
Less: cash and cash equivalents	877		125		920
Long-term debt, net	$	9,922	$	11,519	$	10,525

Debt to Book Capitalization

Debt to book capitalization is a capital management measure intended to enable financial statement users to evaluate the Company's capital structure, as disclosed in note 13 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)	Dec 31 2023		Sep 30 2023		Dec 31 2022
Interest adjusted after-tax return:
Net earnings, 12 months trailing	$	8,233	$	7,126	$	10,937
Interest and other financing expense, net of tax, 12 months trailing (1)	490		459		424
Interest adjusted after-tax return	$	8,723	$	7,585	$	11,361
12 months average current portion long-term debt (2)	$	1,259	$	1,337	$	1,359
12 months average long-term debt (2)	10,354		10,706		11,761
12 months average common shareholders' equity (2)	38,974		38,635		38,218
12 months average capital employed	$	50,587	$	50,678	$	51,338
After-tax return on average capital employed	17.2%		15.0%		22.1%

(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 35 Three months and year ended December 31, 2023