CANADIAN NATURAL RESOURCES LIMITED

 MANAGEMENT'S DISCUSSION & ANALYSIS

FOR THE THREE MONTHS ENDED MARCH 31, 2023

MAY 3, 2023

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 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 the Russian invasion of Ukraine, continuing effects of the novel coronavirus ("COVID-19") pandemic, 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, 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; 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; 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 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; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; and other circumstances affecting revenues and expenses.

Canadian Natural Resources Limited           1 Three months ended March 31, 2023

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 ended March 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 ended March 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 ended March 31, 2023 in relation to the first quarter of 2022 and the fourth quarter of 2022. 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.sedar.com, 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 May 3, 2023.

Canadian Natural Resources Limited           2 Three months ended March 31, 2023

FINANCIAL HIGHLIGHTS

		Three Months Ended
($ millions, except per common share amounts)		Mar 31 2023		Dec 31 2022		Mar 31 2022
Product sales (1)		$	9,548	$	11,012	$	12,132
Crude oil and NGLs		$	8,412	$	9,508	$	10,773
Natural gas		$	851	$	1,287	$	1,002
Net earnings		$	1,799	$	1,520	$	3,101
Per common share	– basic	$	1.63	$	1.37	$	2.66
	– diluted	$	1.62	$	1.36	$	2.63
Adjusted net earnings from operations (2)		$	1,881	$	2,194	$	3,376
Per common share	– basic (3)	$	1.71	$	1.98	$	2.90
	– diluted (3)	$	1.69	$	1.96	$	2.86
Cash flows from operating activities		$	1,295	$	4,544	$	2,853
Adjusted funds flow (2)		$	3,429	$	4,176	$	4,975
Per common share	– basic (3)	$	3.12	$	3.78	$	4.27
	– diluted (3)	$	3.08	$	3.73	$	4.21
Cash flows used in investing activities		$	1,153	$	1,262	$	1,251
Net capital expenditures (2)		$	1,394	$	1,317	$	1,455

(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.

SUMMARY OF FINANCIAL HIGHLIGHTS

Consolidated Net Earnings and Adjusted Net Earnings from Operations

Net earnings for the first quarter of 2023 were $1,799 million compared with $3,101 million for the first quarter of 2022, and $1,520 million for the fourth quarter of 2022. Net earnings for the first quarter of 2023 included non-operating items, net of tax, of $82 million compared with $275 million for the first quarter of 2022 and $674 million for the fourth quarter of 2022 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the loss (gain) from investments, a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea in the fourth quarter of 2022, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the first quarter of 2023 were $1,881 million compared with $3,376 million for the first quarter of 2022 and $2,194 million for the fourth quarter of 2022.

The decrease in adjusted net earnings from operations for the first quarter of 2023 from the comparable periods primarily reflected:

▪lower crude oil and NGLs netbacks (1) and crude oil and NGLs sales volumes in the Exploration and Production segments; and

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

partially offset by:

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

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

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

Canadian Natural Resources Limited           3 Three months ended March 31, 2023

Cash Flows from Operating Activities and Adjusted Funds Flow

Cash flows from operating activities for the first quarter of 2023 were $1,295 million compared with $2,853 million for the first quarter of 2022 and $4,544 million for the fourth quarter of 2022. 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 changes in non-cash working capital.

Adjusted funds flow for the first quarter of 2023 was $3,429 million compared with $4,975 million for the first quarter of 2022 and $4,176 million for the fourth quarter of 2022. 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 excluding the impact of 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.

Production Volumes

Crude oil and NGLs production before royalties for the first quarter of 2023 increased 2% to 962,908 bbl/d from 945,809 bbl/d for the first quarter of 2022, and increased 2% from 942,258 bbl/d for the fourth quarter of 2022. Natural gas production before royalties for the first quarter of 2023 increased 7% to 2,139 MMcf/d from 2,006 MMcf/d for the first quarter of 2022 and was comparable with 2,115 MMcf/d for the fourth quarter of 2022. Total production before royalties for the first quarter of 2023 of 1,319,391 BOE/d increased 3% from 1,280,180 BOE/d for the first quarter of 2022, and was comparable with 1,294,679 BOE/d for the fourth quarter of 2022. 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 (1) averaged $58.85 per bbl for the first quarter of 2023, a decrease of 37% from $93.54 per bbl for the first quarter of 2022, and a decrease of 15% from $69.34 per bbl for the fourth quarter of 2022. The realized natural gas price decreased 19% to average $4.27 per Mcf for the first quarter of 2023 from $5.26 per Mcf for the first quarter of 2022, and decreased 33% from $6.39 per Mcf for the fourth quarter of 2022. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price decreased 14% to average $96.07 per bbl for the first quarter of 2023 from $112.05 per bbl for the first quarter of 2022, and decreased 7% from $103.79 per bbl for the fourth quarter of 2022. The Company's realized pricing reflects 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 (2) averaged $16.93 per bbl for the first quarter of 2023, an increase of 7% from $15.80 per bbl for the first quarter of 2022, and a decrease of 17% from $20.37 per bbl for the fourth quarter of 2022. Natural gas production expense (2) averaged $1.47 per Mcf for the first quarter of 2023, an increase of 12% from $1.31 per Mcf for the first quarter of 2022 and an increase of 18% from $1.25 per Mcf for the fourth quarter of 2022. In the Oil Sands Mining and Upgrading segment, production expense (2) averaged $25.06 per bbl for the first quarter of 2023, comparable to $24.60 per bbl for the first quarter of 2022, and $25.48 per bbl for the fourth quarter of 2022. 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)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.

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

Canadian Natural Resources Limited           4 Three months ended March 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)	Mar 31 2023		Dec 31 2022		Sep 30 2022		Jun 30 2022
Product sales (1)	$	9,548	$	11,012	$	12,574	$	13,812
Crude oil and NGLs	$	8,412	$	9,508	$	11,001	$	11,727
Natural gas	$	851	$	1,287	$	1,342	$	1,605
Net earnings	$	1,799	$	1,520	$	2,814	$	3,502
Net earnings per common share
– basic	$	1.63	$	1.37	$	2.52	$	3.04
– diluted	$	1.62	$	1.36	$	2.49	$	3.00
($ millions, except per common share amounts)	Mar 31 2022		Dec 31 2021		Sep 30 2021		Jun 30 2021
Product sales (1)	$	12,132	$	10,190	$	8,521	$	7,124
Crude oil and NGLs	$	10,773	$	8,979	$	7,607	$	6,382
Natural gas	$	1,002	$	958	$	694	$	509
Net earnings	$	3,101	$	2,534	$	2,202	$	1,551
Net earnings per common share
– basic	$	2.66	$	2.16	$	1.87	$	1.31
– diluted	$	2.63	$	2.14	$	1.86	$	1.30

(1)Further details related to product sales for the three months ended March 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 – Fluctuating 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 COVID-19 and in connection with governmental responses to COVID-19, and the impact of 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 – The impact of 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 North America and the International segments, natural decline rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and the impact of shut-in production due to lower demand during COVID-19. 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 North America and the International segments, natural decline rates, the temporary shutdown and subsequent reinstatement of the Pine River Gas Plant during 2021, and the impact and timing of acquisitions.

▪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 and energy costs, inflationary cost pressures, cost optimizations across all segments, the impact and timing of acquisitions, turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments.

Canadian Natural Resources Limited           5 Three months ended March 31, 2023

▪Depletion, depreciation and amortization expense – Fluctuations due to changes in sales volumes including the impact and timing of acquisitions and dispositions, 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, and a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea.

▪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.

▪Gain on acquisitions, loss (gain) from investments, and income from North West Redwater Partnership ("NWRP") – Fluctuations due to the recognition of gains on acquisitions, loss (gain) from the investments in PrairieSky Royalty Ltd. and Inter Pipeline Ltd. shares, and the distribution from NWRP in the second quarter of 2021.

BUSINESS ENVIRONMENT

Global benchmark crude oil prices continued to reflect conditions seen in the second half of 2022, including demand concerns related to rising interest rates in response to persistent inflation, and concerns of a global recession. Pricing also continued to be impacted by geopolitical factors such as the Russian invasion of Ukraine. Global crude oil supply outstripped demand in the first quarter of 2023, with Russian crude supply, as well as withdrawals from the US Strategic Petroleum Reserve through the end of 2022.

Liquidity

As at March 31, 2023, the Company had undrawn revolving bank credit facilities of $5,520 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,096 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.

Risks and Uncertainties

The global economy, including Canada, is experiencing higher and more persistent inflation, in part due to the Russian invasion of Ukraine and ongoing supply constraints due to the continuing impacts of COVID-19. As a result of these conditions, the Company has experienced and may continue to experience higher than normal fluctuations in commodity prices and interest rates, and may experience inflationary pressures on its operating and capital expenditures.

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

Canadian Natural Resources Limited           6 Three months ended March 31, 2023

Benchmark Commodity Prices

	Three Months Ended
(Average for the period)	Mar 31 2023		Dec 31 2022		Mar 31 2022
WTI benchmark price (US$/bbl)	$	76.11	$	82.62	$	94.38
Dated Brent benchmark price (US$/bbl)	$	81.24	$	88.15	$	99.17
WCS Heavy Differential from WTI (US$/bbl)	$	24.74	$	25.65	$	14.60
SCO price (US$/bbl)	$	78.18	$	86.78	$	93.05
Condensate benchmark price (US$/bbl)	$	79.83	$	83.33	$	96.16
Condensate Differential from WTI (US$/bbl)	$	(3.72)	$	(0.71)	$	(1.78)
NYMEX benchmark price (US$/MMBtu)	$	3.43	$	6.27	$	4.91
AECO benchmark price (C$/GJ)	$	4.12	$	5.29	$	4.35
US/Canadian dollar average exchange rate (US$)	$	0.7393	$	0.7366	$	0.7899

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, and its product revenues continued to be impacted by the volatility of 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 the North America segment are typically based on WTI benchmark pricing. WTI averaged US$76.11 per bbl for the first quarter of 2023, a decrease of 19% from US$94.38 per bbl for the first quarter of 2022, and a decrease of 8% from US$82.62 per bbl for the fourth quarter of 2022.

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$81.24 per bbl for the first quarter of 2023, a decrease of 18% from US$99.17 per bbl for the first quarter of 2022, and a decrease of 8% from US$88.15 per bbl for the fourth quarter of 2022.

The decrease in WTI and Brent pricing for the first quarter of 2023 from the comparable periods primarily reflected continuing demand concerns related to rising interest rates in response to persistent inflation and concerns of a global recession.

The WCS Heavy Differential averaged US$24.74 per bbl for the first quarter of 2023, compared to US$14.60 per bbl for the first quarter of 2022 and US$25.65 per bbl for the fourth quarter of 2022. The widening of the WCS Heavy Differential for the first quarter of 2023 from the first quarter of 2022 primarily reflected lower US Gulf Coast pricing and continued withdrawals from the US Strategic Petroleum Reserve through the end of 2022. The slight narrowing of the WCS Heavy Differential for the first quarter of 2023 from the fourth quarter of 2022 primarily reflected the completion of US Strategic Petroleum Reserve releases and the restart of certain refineries in the US Midwest.

The SCO price averaged US$78.18 per bbl for the first quarter of 2023, a decrease of 16% from US$93.05 per bbl for the first quarter of 2022, and a decrease of 10% from US$86.78 per bbl for the fourth quarter of 2022. The decrease in SCO pricing for the first quarter of 2023 from the comparable periods primarily reflected the decrease in WTI benchmark pricing as well as weakening diesel fuel crack spreads.

NYMEX natural gas prices averaged US$3.43 per MMBtu for the first quarter of 2023, a decrease of 30% from US$4.91 per MMBtu for the first quarter of 2022, and a decrease of 45% from US$6.27 per MMBtu for the fourth quarter of 2022. The decrease in NYMEX natural gas prices for the first quarter of 2023 from the first quarter of 2022 primarily reflected increased North American production and higher storage levels due to seasonally mild winter weather and lower heating demand. The decrease in NYMEX natural gas prices for the first quarter of 2023 from the fourth quarter of 2022 primarily reflected lower storage draws due to mild winter weather, combined with increased production in North America. Additionally, the restart of the Freeport LNG facility was delayed until late in the first quarter of 2023.

Canadian Natural Resources Limited           7 Three months ended March 31, 2023

AECO natural gas prices averaged $4.12 per GJ for the first quarter of 2023, a decrease of 5% from $4.35 per GJ for the first quarter of 2022, and a decrease of 22% from $5.29 per GJ for the fourth quarter of 2022. The decrease in AECO natural gas prices for the first quarter of 2023 from the comparable periods primarily reflected NYMEX benchmark pricing, and increased production levels in the Western Canadian Sedimentary Basin.

DAILY PRODUCTION, before royalties

	Three Months Ended
	Mar 31 2023	Dec 31 2022	Mar 31 2022
Crude oil and NGLs (bbl/d)
North America – Exploration and Production	477,349	486,559	484,280
North America – Oil Sands Mining and Upgrading (1)	458,228	428,784	429,826
International – Exploration and Production
North Sea	13,240	14,006	15,961
Offshore Africa	14,091	12,909	15,742
Total International (2)	27,331	26,915	31,703
Total Crude oil and NGLs	962,908	942,258	945,809
Natural gas (MMcf/d) (3)
North America	2,127	2,105	1,988
International
North Sea	3	3	3
Offshore Africa	9	7	15
Total International	12	10	18
Total Natural gas	2,139	2,115	2,006
Total Barrels of oil equivalent(BOE/d)	1,319,391	1,294,679	1,280,180
Product mix
Light and medium crude oil and NGLs	10%	11%	11%
Pelican Lake heavy crude oil	4%	4%	4%
Primary heavy crude oil	6%	5%	5%
Bitumen (thermal oil)	18%	20%	20%
Synthetic crude oil (1)	35%	33%	34%
Natural gas	27%	27%	26%
Percentage of gross revenue(1) (4) (5)
Crude oil and NGLs	90%	87%	91%
Natural gas	10%	13%	9%

(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 costs and excluding risk management activities.

(5)Excluding Midstream and Refining revenue.

Canadian Natural Resources Limited           8 Three months ended March 31, 2023

DAILY PRODUCTION, net of royalties

	Three Months Ended
	Mar 31 2023	Dec 31 2022	Mar 31 2022
Crude oil and NGLs (bbl/d)
North America – Exploration and Production	396,482	381,546	386,621
North America – Oil Sands Mining and Upgrading	411,434	372,894	376,984
International – Exploration and Production
North Sea	13,240	13,985	15,908
Offshore Africa	12,740	11,153	15,010
Total International	25,980	25,138	30,918
Total Crude oil and NGLs	833,896	779,578	794,523
Natural gas (MMcf/d)
North America	1,988	1,937	1,829
International
North Sea	3	3	3
Offshore Africa	9	6	14
Total International	12	9	17
Total Natural gas	2,000	1,946	1,846
Total Barrels of oil equivalent (BOE/d)	1,167,300	1,103,833	1,102,221

The Company's business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO, and natural gas.

Crude oil and NGLs production before royalties for the first quarter of 2023 averaged 962,908 bbl/d, an increase of 2% from 945,809 bbl/d for the first quarter of 2022, and an increase of 2% from 942,258 bbl/d for the fourth quarter of 2022. The increase in crude oil and NGLs production for the first quarter of 2023 as compared to the prior periods primarily reflected increased production in the Oil Sands Mining and Upgrading segment, partially offset by decreased thermal oil production.

Annual crude oil and NGLs production before royalties for 2023 is targeted to average between 969,000 bbl/d and 1,001,000 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 first quarter of 2023 of 2,139 MMcf/d increased 7% from 2,006 MMcf/d for the first quarter of 2022, and was comparable with 2,115 MMcf/d for the fourth quarter of 2022. The increase in natural gas production for the first quarter of 2023 from the first quarter of 2022 primarily reflected strong drilling results, partially offset by a third-party pipeline outage and natural field declines.

Annual natural gas production before royalties for 2023 is targeted to average between 2,170 MMcf/d and 2,242 MMcf/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

North America – Exploration and Production

North America crude oil and NGLs production before royalties for the first quarter of 2023 averaged 477,349 bbl/d, which was comparable with 484,280 bbl/d for the first quarter of 2022, and decreased 2% from 486,559 bbl/d for the fourth quarter of 2022. Crude oil and NGLs production for the first quarter of 2023 as compared to the prior periods primarily reflected natural field declines in thermal, offset by drilling activity in conventional E&P.

The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 242,884 bbl/d for the first quarter of 2023, a decrease of 7% from 261,743 bbl/d for the first quarter of 2022 and a decrease of 4% from 253,188 bbl/d for the fourth quarter of 2022, primarily reflecting natural field declines.

Pelican Lake heavy crude oil production before royalties averaged 48,244 bbl/d for the first quarter of 2023, a decrease of 7% from 51,991 bbl/d for the first quarter of 2022, and comparable with 48,221 bbl/d for the fourth quarter of 2022, demonstrating Pelican Lake's long life low decline production.

Canadian Natural Resources Limited           9 Three months ended March 31, 2023

Record natural gas production before royalties for the first quarter of 2023 averaged 2,127 MMcf/d, an increase of 7% from 1,988 MMcf/d for the first quarter of 2022, and comparable with 2,105 MMcf/d for the fourth quarter of 2022. The increase in natural gas production for the first quarter of 2023 from the first quarter of 2022 primarily reflected strong drilling results, partially offset by a third-party pipeline outage and natural field declines.

North America – Oil Sands Mining and Upgrading

SCO production before royalties for the first quarter of 2023 of 458,228 bbl/d increased 7% from 429,826 bbl/d for the first quarter of 2022 primarily reflecting facility restrictions at the Scotford Upgrader during the first quarter of 2022. SCO production before royalties increased 7% from 428,784 bbl/d for the fourth quarter of 2022, primarily reflecting the reinstatement of production volumes following unplanned outages in the fourth quarter of 2022 and the completion of related mining equipment repairs in January 2023.

International – Exploration and Production

International crude oil and NGLs production before royalties for the first quarter of 2023 of 27,331 bbl/d decreased 14% from 31,703 bbl/d for the first quarter of 2022, and was comparable with 26,915 bbl/d for the fourth quarter of 2022. The decrease from the first quarter of 2022 primarily reflected natural field declines, together with the impact of maintenance activities.

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)	Mar 31 2023	Dec 31 2022	Mar 31 2022
International	1,912,388	390,959	872,196

During the first quarter of 2023, there were no crude oil liftings from the Company's platforms in the North Sea.

Canadian Natural Resources Limited           10 Three months ended March 31, 2023

OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION

	Three Months Ended
	Mar 31 2023		Dec 31 2022		Mar 31 2022
Crude oil and NGLs ($/bbl) (1)
Realized price (2)	$	58.85	$	69.34	$	93.54
Transportation (2)	4.52		4.11		4.18
Realized price, net of transportation (2)	54.33		65.23		89.36
Royalties (3)	10.09		13.56		17.80
Production expense (4)	16.93		20.37		15.80
Netback (2)	$	27.31	$	31.30	$	55.76
Natural gas ($/Mcf) (1)
Realized price (5)	$	4.27	$	6.39	$	5.26
Transportation (6)	0.55		0.55		0.50
Realized price, net of transportation	3.72		5.84		4.76
Royalties (3)	0.28		0.51		0.42
Production expense (4)	1.47		1.25		1.31
Netback (2)	$	1.97	$	4.08	$	3.03
Barrels of oil equivalent ($/BOE) (1)
Realized price (2)	$	44.98	$	56.83	$	69.66
Transportation (2)	4.03		3.80		3.72
Realized price, net of transportation (2)	40.95		53.03		65.94
Royalties (3)	6.56		9.31		11.88
Production expense (4)	13.51		15.17		12.70
Netback (2)	$	20.88	$	28.55	$	41.36

(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           11 Three months ended March 31, 2023

REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION

	Three Months Ended
	Mar 31 2023		Dec 31 2022		Mar 31 2022
Crude oil and NGLs ($/bbl) (1)
North America (2)	$	57.99	$	65.79	$	91.44
International average (3)	$	98.60	$	118.44	$	128.35
North Sea (3)	$	—	$	118.91	$	125.20
Offshore Africa (3)	$	98.60	$	117.74	$	130.25
Crude oil and NGLs average (2)	$	58.85	$	69.34	$	93.54
Natural gas ($/Mcf) (1) (3)
North America	$	4.22	$	6.36	$	5.20
International average	$	13.76	$	13.70	$	11.32
North Sea	$	11.81	$	13.51	$	20.68
Offshore Africa	$	14.28	$	13.80	$	9.57
Natural gas average	$	4.27	$	6.39	$	5.26
Average ($/BOE) (1) (2)	$	44.98	$	56.83	$	69.66

(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 37% to average $57.99 per bbl for the first quarter of 2023 from $91.44 per bbl for the first quarter of 2022, and decreased 12% from $65.79 per bbl for the fourth quarter of 2022. The decrease in realized crude oil and NGLs prices for the first quarter of 2023 from the comparable periods was primarily due to lower WTI benchmark pricing and fluctuations in the WCS differential.The Company continues to focus on its crude oil blending marketing strategy and in the first quarter of 2023 contributed approximately 217,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices decreased 19% to average $4.22 per Mcf for the first quarter of 2023 from $5.20 per Mcf for the first quarter of 2022, and decreased 34% from $6.36 per Mcf for the fourth quarter of 2022. The decrease in realized natural gas prices for the first quarter of 2023 from the comparable periods primarily reflected decreased AECO benchmark and export pricing in 2023.

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

	Three Months Ended
(Quarterly average)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Wellhead Price (1)
Light and medium crude oil and NGLs ($/bbl)	$	73.26	$	77.08	$	88.63
Pelican Lake heavy crude oil ($/bbl)	$	67.57	$	73.25	$	97.73
Primary heavy crude oil ($/bbl)	$	60.31	$	69.20	$	97.21
Bitumen (thermal oil) ($/bbl)	$	48.60	$	58.13	$	89.93
Natural gas ($/Mcf)	$	4.22	$	6.36	$	5.20

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

Canadian Natural Resources Limited           12 Three months ended March 31, 2023

International

International realized crude oil and NGLs prices decreased 23% to average $98.60 per bbl for the first quarter of 2023 from $128.35 per bbl for the first quarter of 2022 and decreased 17% from $118.44 per bbl for the fourth quarter of 2022. 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 first quarter of 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
	Mar 31 2023		Dec 31 2022		Mar 31 2022
Crude oil and NGLs ($/bbl) (1)
North America	$	10.10	$	14.07	$	18.64
International average	$	9.46	$	6.56	$	3.93
North Sea	$	—	$	0.18	$	0.41
Offshore Africa	$	9.46	$	16.02	$	6.06
Crude oil and NGLs average	$	10.09	$	13.56	$	17.80
Natural gas ($/Mcf) (1)
North America	$	0.27	$	0.51	$	0.41
Offshore Africa	$	0.69	$	0.71	$	0.98
Natural gas average	$	0.28	$	0.51	$	0.42
Average($/BOE) (1)	$	6.56	$	9.31	$	11.88

(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 first quarter of 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 17% of product sales for the first quarter of 2023 compared with 20% for the first quarter of 2022, and 21% for the fourth quarter of 2022. The decrease in royalty rates for the first quarter of 2023 from the comparable periods was primarily due to lower benchmark prices.

Natural gas royalty rates averaged approximately 6% of product sales for the first quarter of 2023 compared with 8% for the first quarter of 2022, and 8% for the fourth quarter of 2022. The decrease in royalty rates for the first quarter of 2023 from the comparable periods was primarily due to lower benchmark prices.

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 first quarter of 2023 compared with 5% of product sales for the first quarter of 2022 and 13% for the fourth quarter of 2022. Royalty rates as a percentage of product sales reflected the timing of liftings and the status of payout in the various fields.

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

Canadian Natural Resources Limited           13 Three months ended March 31, 2023

PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION 

	Three Months Ended
	Mar 31 2023		Dec 31 2022		Mar 31 2022
Crude oil and NGLs ($/bbl) (1)
North America	$	16.82	$	16.80	$	14.79
International average	$	21.90	$	69.70	$	32.58
North Sea	$	—	$	100.30	$	64.24
Offshore Africa	$	21.90	$	24.30	$	13.38
Crude oil and NGLs average	$	16.93	$	20.37	$	15.80
Natural gas ($/Mcf) (1)
North America	$	1.43	$	1.22	$	1.28
International average	$	8.08	$	8.07	$	4.61
North Sea	$	10.80	$	10.38	$	8.21
Offshore Africa	$	7.35	$	6.98	$	3.93
Natural gas average	$	1.47	$	1.25	$	1.31
Average($/BOE) (1)	$	13.51	$	15.17	$	12.70

(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 first quarter of 2023 of $16.82 per bbl increased 14% from $14.79 per bbl for the first quarter of 2022, and was comparable with $16.80 per bbl for the fourth quarter of 2022. The increase in crude oil and NGLs production expense per bbl from the first quarter of 2022 was primarily due to increased power and service costs.

North America natural gas production expense for the first quarter of 2023 of $1.43 per Mcf increased 12% from $1.28 per Mcf for the first quarter of 2022, and increased 17% from $1.22 per Mcf for the fourth quarter of 2022. The increase in natural gas production expense per Mcf for the first quarter of 2023 from the comparable periods primarily reflected increased service costs. The increase from the fourth quarter of 2022 also reflected the impact of seasonal weather conditions.

International

International crude oil and NGLs production expense for the first quarter of 2023 of $21.90 per bbl decreased 33% from $32.58 per bbl for the first quarter of 2022, and decreased 69% from $69.70 per bbl for the fourth quarter of 2022. The decrease in crude oil and NGLs production expense per bbl from the comparable periods primarily reflected the timing of liftings from various fields that have different cost structures, and fluctuations in the Canadian dollar. During the first quarter of 2023, there were no crude oil liftings from the Company's platforms in the North Sea.

Canadian Natural Resources Limited           14 Three months ended March 31, 2023

DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION

	Three Months Ended
($ millions, except per BOE amounts)	Mar 31 2023		Dec 31 2022		Mar 31 2022
North America	$	890	$	949	$	878
North Sea	1		1,653		29
Offshore Africa	35		41		51
Depletion, depreciation and amortization	$	926	$	2,643	$	958
Less: Recoverability charge (1)	—		1,620		—
Adjusted depletion, depreciation and amortization (2)	$	926	$	1,023	$	958
$/BOE (3)	$	12.14	$	12.78	$	12.40

(1)Prevailing regulatory and economic conditions in 2022 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. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked associated 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 recoverability charge of $1,620 million in depletion, depreciation and amortization.

(2)This is a non-GAAP measure used to calculate depletion, depreciation and amortization, excluding the impact of non-recurring charges that do not reflect the Company's normal course depletion, depreciation and amortization costs. 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. It is calculated as depletion, depreciation and amortization expense, less the impact of non-recurring charges.

(3)Non-GAAP ratio calculated as adjusted depletion, depreciation and amortization 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 first quarter of 2023 of $12.14 per BOE was comparable with $12.40 per BOE for the first quarter of 2022, and decreased 5% from $12.78 per BOE for the fourth quarter of 2022. The decrease in adjusted depletion, depreciation and amortization expense per BOE for the first quarter of 2023 from the fourth quarter of 2022 reflected lower depletion rates, primarily due to increases to the Company's North America Exploration and Production reserve estimates at December 31, 2022.

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

ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION

	Three Months Ended
($ millions, except per BOE amounts)	Mar 31 2023		Dec 31 2022		Mar 31 2022
North America	$	59	$	51	$	35
North Sea	11		10		7
Offshore Africa	2		2		2
Asset retirement obligation accretion	$	72	$	63	$	44
$/BOE (1)	$	0.94	$	0.78	$	0.56

(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 on an absolute and per BOE basis also reflects the impact of the timing of liftings from each field in the North Sea and Offshore Africa.

Asset retirement obligation accretion expense for the first quarter of 2023 of $0.94 per BOE increased 68% from $0.56 per BOE for the first quarter of 2022, and increased 21% from $0.78 per BOE for the fourth quarter of 2022. The increase in asset retirement obligation accretion expense for the first quarter of 2023 from the comparable periods on a per BOE basis primarily reflected the impact of cost estimate and discount rate revisions made to the asset retirement obligation during 2022.

Canadian Natural Resources Limited           15 Three months ended March 31, 2023

OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING

The Company continues to focus on safe, reliable, and efficient operations leveraging its technical expertise across the Horizon and AOSP sites. SCO production in the first quarter of 2023 averaged 458,228 bbl/d, primarily reflecting the reinstatement of production volumes following unplanned outages in the fourth quarter of 2022 and the completion of related mining equipment repairs in January 2023.

The Company incurred production expense of $1,042 million for the first quarter of 2023, an increase of 7% from $977 million for the first quarter of 2022, and comparable with $1,017 million for the fourth quarter of 2022. The increase in production expense in the first quarter of 2023 from the first quarter of 2022 primarily reflected higher mining service costs, partially offset by lower energy costs.

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

	Three Months Ended
($/bbl)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Realized SCO sales price (1)	$	96.07	$	103.79	$	112.05
Bitumen value for royalty purposes (2)	$	47.73	$	58.24	$	85.75
Bitumen royalties (3)	$	10.04	$	14.48	$	13.51
Transportation (1)	$	1.52	$	1.80	$	1.55

(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 $96.07 per bbl for the first quarter of 2023, a decrease of 14% from $112.05 per bbl for the first quarter of 2022, and a decrease of 7% from $103.79 per bbl for the fourth quarter of 2022. The decrease in the realized SCO sales price for the first quarter of 2023 from the comparable periods primarily reflected the decrease in WTI benchmark pricing.

The decrease in bitumen royalties per bbl for the first quarter of 2023 from the comparable periods primarily reflected the impact of lower prevailing bitumen pricing.

Transportation expense averaged $1.52 per bbl for the first quarter of 2023, comparable with $1.55 per bbl for the first quarter of 2022, and decreased 16% from $1.80 per bbl for the fourth quarter of 2022. The decrease in transportation expense per bbl for the first quarter of 2023 from the fourth quarter of 2022 primarily reflected the impact of lower sales to the US Gulf Coast, combined with higher overall sales volumes.

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
($ millions)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Production expense, excluding natural gas costs	$	971	$	933	$	896
Natural gas costs	71		84		81
Production expense	$	1,042	$	1,017	$	977

Canadian Natural Resources Limited           16 Three months ended March 31, 2023

	Three Months Ended
($/bbl)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Production expense, excluding natural gas costs (1)	$	23.35	$	23.37	$	22.57
Natural gas costs (2)	1.71		2.11		2.03
Production expense (3)	$	25.06	$	25.48	$	24.60
Sales volumes (bbl/d)	462,021		433,731		441,324

(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 first quarter of 2023 averaged $25.06 per bbl, which was comparable with $24.60 per bbl for the first quarter of 2022, and $25.48 per bbl for the fourth quarter of 2022.

DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING

	Three Months Ended
($ millions, except per bbl amounts)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Depletion, depreciation and amortization	$	488	$	481	$	445
$/bbl (1)	$	11.74	$	12.07	$	11.20

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

Depletion, depreciation and amortization expense for the first quarter of 2023 of $11.74 per bbl increased 5% from $11.20 per bbl for the first quarter of 2022, and decreased 3% from $12.07 per bbl for the fourth quarter of 2022. The increase in depletion, depreciation and amortization on a per bbl basis for the first quarter of 2023 from the first quarter of 2022 primarily reflected the impact of equipment lease additions in the first quarter of 2023. The decrease on a per bbl basis for the first quarter of 2023 compared to the fourth quarter of 2022 primarily reflected the impact of higher sales volumes.

ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING

	Three Months Ended
($ millions, except per bbl amounts)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Asset retirement obligation accretion	$	20	$	19	$	15
$/bbl (1)	$	0.47	$	0.49	$	0.39

(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 of $0.47 per bbl for the first quarter of 2023 increased 21% from $0.39 per bbl for the first quarter of 2022, and decreased 4% from $0.49 per bbl for the fourth quarter of 2022. The increase on a per bbl basis from the first quarter of 2022 primarily reflected the impact of cost estimate and discount rate revisions made to the asset retirement obligation during 2022, while the decrease from the fourth quarter of 2022 primarily reflected the impact of higher sales volumes.

Canadian Natural Resources Limited           17 Three months ended March 31, 2023

MIDSTREAM AND REFINING

	Three Months Ended
($ millions)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Product sales
Midstream activities	$	21	$	21	$	20
NWRP, refined product sales and other	250		205		249
Segmented revenue	271		226		269
Less:
NWRP, refining toll	70		57		61
Midstream activities	8		6		5
Production expense	78		63		66
NWRP, transportation and feedstock costs	153		155		179
Depreciation	4		5		4
Segmented earnings	$	36	$	3	$	20

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

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 first quarter of 2023, production of ultra-low sulphur diesel and other refined products averaged 85,376 BOE/d (21,344 BOE/d to the Company) (three months ended March 31, 2022 – 71,975 BOE/d; 17,994 BOE/d to the Company) reflecting the 25% toll payer commitment.

As at March 31, 2023, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $567 million (December 31, 2022 – $551 million). For the three months ended March 31, 2023, the unrecognized share of the equity loss was $16 million (three months ended March 31, 2022 – unrecognized equity loss of $10 million).

ADMINISTRATION EXPENSE

	Three Months Ended
($ millions, except per BOE amounts)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Administration expense	$	106	$	108	$	116
$/BOE (1)	$	0.90	$	0.90	$	0.99
Sales volumes (BOE/d) (2)	1,309,942		1,303,996		1,300,300

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

(2)Total Company sales volumes.

Administration expense for the first quarter of 2023 of $0.90 per BOE decreased 9% from $0.99 per BOE for the first quarter of 2022, and was comparable with $0.90 per BOE for the fourth quarter of 2022. The decrease in administration expense per BOE for the first quarter of 2023 from the first quarter of 2022 was primarily due to higher overhead recoveries.

Canadian Natural Resources Limited           18 Three months ended March 31, 2023

SHARE-BASED COMPENSATION

	Three Months Ended
($ millions)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Share-based compensation expense	$	66	$	319	$	534

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 by individual employee performance and the extent to which certain other performance measures are met.

The Company recognized a $66 million share-based compensation expense for the three months ended March 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.

INTEREST AND OTHER FINANCING EXPENSE

	Three Months Ended
($ millions, except effective interest rate)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Interest and other financing expense	$	154	$	76	$	163
Less: Interest income and other (1)	(9)		(93)		(4)
Interest expense on long-term debt and lease liabilities (1)	$	163	$	169	$	167
Average current and long-term debt (2)	$	12,343	$	13,174	$	14,950
Average lease liabilities (2)	1,516		1,508		1,551
Average long-term debt and lease liabilities (2)	$	13,859	$	14,682	$	16,501
Average effective interest rate (3) (4)	4.6%		4.5%		4.0%
Interest and other financing expense per $/BOE (5)	$	1.30	$	0.63	$	1.40
Sales volumes (BOE/d) (6)	1,309,942		1,303,996		1,300,300

(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 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 first quarter of 2023 decreased $0.10 per BOE to $1.30 per BOE from $1.40 per BOE for the first quarter of 2022, and increased $0.67 per BOE from $0.63 per BOE for the fourth quarter of 2022. The decrease in interest and other financing expense per BOE for the first quarter of 2023 from the first quarter of 2022 was primarily due to lower debt levels. The increase in the first quarter of 2023 from the fourth quarter of 2022 reflected the impact of accrued interest on the deferred PRT recovery in the fourth quarter of 2022.

The Company's average effective interest rate for the first quarter of 2023 increased from the first quarter of 2022 primarily due to higher benchmark interest rates on commercial paper drawn during the first quarter of 2023 and the repayment of medium-term notes during 2022.

Canadian Natural Resources Limited           19 Three months ended March 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
($ millions)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Foreign currency contracts	$	(2)	$	3	$	22
Natural gas financial instruments (1)	3		(6)		5
Crude oil and NGLs financial instruments (1)	—		1		5
Net realized loss (gain)	1		(2)		32
Foreign currency contracts	3		(2)		(13)
Natural gas financial instruments (1)	17		18		32
Crude oil and NGLs financial instruments (1)	—		(1)		7
Net unrealized loss	20		15		26
Net loss	$	21	$	13	$	58

(1)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.

During the first quarter of 2023, net realized risk management losses were related to the settlement of natural gas financial instruments, partially offset by gains on foreign currency contracts. The Company recorded a net unrealized loss of $20 million ($16 million after-tax of $4 million) on its risk management activities for the three months ended March 31, 2023 (three months ended December 31, 2022 – unrealized loss of $15 million, $11 million after-tax of $4 million; three months ended March 31, 2022 – unrealized loss of $26 million, $17 million after-tax of $9 million).

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

FOREIGN EXCHANGE

	Three Months Ended
($ millions)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Net realized (gain) loss	$	(11)	$	18	$	10
Net unrealized gain	(3)		(203)		(156)
Net gain (1)	$	(14)	$	(185)	$	(146)

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

The net realized foreign exchange gain for the first quarter of 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 first quarter of 2023 was primarily related to the translation of outstanding US dollar debt. The US/Canadian dollar exchange rate at March 31, 2023 was US$0.7392 (December 31, 2022 – US$0.7389, March 31, 2022 – US$0.8010).

Canadian Natural Resources Limited           20 Three months ended March 31, 2023

INCOME TAXES

	Three Months Ended
($ millions, except effective tax rates)	Mar 31 2023		Dec 31 2022		Mar 31 2022
North America (1)	$	480	$	345	$	834
North Sea	6		33		7
Offshore Africa	10		23		12
PRT – North Sea	(40)		(5)		(7)
Other taxes	3		3		5
Current income tax	459		399		851
Deferred corporate income tax	23		(148)		125
Deferred PRT– North Sea	7		(441)		—
Deferred income tax	30		(589)		125
Income tax	$	489	$	(190)	$	976
Earnings before taxes	$	2,288	$	1,330	$	4,077
Effective tax rate on net earnings (2)	21%		(14)%		24%
	Three Months Ended
($ millions, except effective tax rates)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Income tax	$	489	$	(190)	$	976
Tax effect on non-operating items (3)	8		980		8
Current PRT - North Sea	40		5		7
Other taxes	(3)		(3)		(5)
Effective tax on adjusted net earnings	$	534	$	792	$	986
Adjusted net earnings from operations (4)	$	1,881	$	2,194	$	3,376
Adjusted net earnings from operations, before taxes	$	2,415	$	2,986	$	4,362
Effective tax rate on adjusted net earnings from operations (5) (6)	22%		27%		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 tax effect of PSUs, unrealized risk management, abandonment expenditure recovery, and the recoverability charge recognized in the fourth quarter of 2022 in adjusted net earnings from operations.

(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 first quarter of 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 corporate income tax and PRT in the North Sea for the first quarter of 2023 and the comparable periods included the impact of carrybacks of abandonment expenditures related to decommissioning activities at the Company's platforms in the North Sea. Deferred PRT and income taxes for the three months ended December 31, 2022 also reflected the impact of the recoverability charge recognized in depletion, depreciation and amortization during the period related to the North Sea.

Canadian Natural Resources Limited           21 Three months ended March 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
($ millions)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Exploration and Evaluation
Net expenditures	$	28	$	11	$	22
Net property dispositions	—		(2)		(3)
Total Exploration and Evaluation	28		9		19
Property, Plant and Equipment
Net property acquisitions	—		—		482
Well drilling, completion and equipping	510		407		344
Production and related facilities	361		351		211
Other	11		15		13
Total Property, Plant and Equipment	882		773		1,050
Total Exploration and Production	910		782		1,069
Oil Sands Mining and Upgrading
Project costs	52		98		45
Sustaining capital	261		367		206
Turnaround costs	22		16		60
Net property dispositions	—		(40)		—
Other	1		1		1
Total Oil Sands Mining and Upgrading	336		442		312
Midstream and Refining	3		2		2
Head office	8		7		5
Abandonments expenditures, net (2)	137		84		67
Net capital expenditures	$	1,394	$	1,317	$	1,455
By Segment
North America	$	884	$	677	$	1,045
North Sea	3		48		11
Offshore Africa	23		57		13
Oil Sands Mining and Upgrading	336		442		312
Midstream and Refining	3		2		2
Head office	8		7		5
Abandonments expenditures, net (2)	137		84		67
Net capital expenditures	$	1,394	$	1,317	$	1,455

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

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.

Canadian Natural Resources Limited           22 Three months ended March 31, 2023

Net capital expenditures for the first quarter of 2023 included base capital expenditures (1) of $1,117 million and strategic growth capital expenditures (1) of $277 million, in accordance with the Company's capital budget.

2023 Capital Budget

On November 30, 2022, the Company announced its 2023 base capital budget (2) targeted at approximately $4,190 million. The budget also includes incremental strategic growth capital of approximately $1,020 million that targets to add additional production and capacity growth beyond 2023 in the Company's Exploration and Production segments, and long life low decline thermal in situ and Oil Sands Mining and Upgrading assets.

The 2023 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
(number of net wells)	Mar 31 2023	Dec 31 2022	Mar 31 2022
Net successful crude oil wells (3)	83	80	56
Net successful natural gas wells	21	15	23
Dry wells	2	—	—
Total	106	95	79
Success rate	98%	100%	100%

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

(2)In the first quarter of 2023, on a net basis, the Company drilled 334 stratigraphic wells and 7 service wells in the Oil Sands Mining and Upgrading segment, as well as 24 stratigraphic and 27 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 first quarter of 2023, the Company drilled 21 net natural gas wells, 42 net primary heavy crude oil wells, 2 net Pelican Lake heavy crude oil wells, 25 net bitumen (thermal oil) wells, and 16 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)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           23 Three months ended March 31, 2023

LIQUIDITY AND CAPITAL RESOURCES

($ millions, except ratios)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Adjusted working capital (1)	$	(307)	$	(1,190)	$	281
Long-term debt, net (2)	$	11,932	$	10,525	$	13,782
Shareholders’ equity	$	38,585	$	38,175	$	38,490
Debt to book capitalization (2)	23.6%		21.6%		26.4%
After-tax return on average capital employed (3)	19.7%		22.1%		18.9%

(1)Calculated as current assets less current liabilities, excluding the current portion of long-term debt.

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

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

As at March 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 is 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:

◦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, LIBOR, SOFR, US base rate or Canadian prime rate.

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

◦In July 2021, 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 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 2021, 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 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.

Canadian Natural Resources Limited           24 Three months ended March 31, 2023

As at March 31, 2023, the Company had undrawn revolving bank credit facilities of $5,520 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,096 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit. At March 31, 2023, the Company had $588 million drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.

Long-term debt, net was $11,932 million at March 31, 2023, resulting in a debt to book capitalization ratio (1) of 23.6% (December 31, 2022 – 21.6%), which was below the 25% to 45% internal range utilized by management. This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. The Company may also be below the low end of the targeted range when cash flows from operating activities are greater than current investment activities. 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 March 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 March 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. Further details related to the Company’s commodity derivative financial instruments outstanding as at March 31, 2023 are discussed in note 15 to the financial statements.

As at March 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)	$	992	$	1,809	$	3,168	$	6,121
Other long-term liabilities (2)	$	253	$	158	$	413	$	720
Interest and other financing expense (3)	$	629	$	589	$	1,400	$	3,664

(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, $244 million; one to less than two years, $158 million; two to less than five years, $413 million; and thereafter, $720 million.

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

Share Capital

As at March 31, 2023, there were 1,097,390,000 common shares outstanding (December 31, 2022 – 1,102,636,000 common shares) and 32,633,000 stock options outstanding (December 31, 2022 - 31,150,000). As at May 2, 2023, the Company had 1,096,088,000 common shares outstanding and 31,532,000 stock options outstanding.

On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.90 per common share, beginning with the dividend paid on April 5, 2023. 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 three months ended March 31, 2023, the Company purchased 8,900,000 common shares at a weighted average price of $76.96 per common share for a total cost of $685 million. Retained earnings were reduced by $601 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to March 31, 2023, the Company purchased 2,100,000 common shares at a weighted average price of $80.60 per common share for a total cost of $169 million.

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

Canadian Natural Resources Limited           25 Three months ended March 31, 2023

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 March 31, 2023:

($ millions)	Remaining 2023		2024		2025		2026		2027		Thereafter
Product transportation and processing (1)	$	892	$	1,387	$	1,238	$	1,147	$	1,096	$	11,273
North West Redwater Partnership service toll (2)	$	114	$	154	$	153	$	135	$	120	$	4,952
Offshore vessels and equipment	$	31	$	35	$	—	$	—	$	—	$	—
Field equipment and power	$	30	$	28	$	26	$	23	$	22	$	215
Other	$	18	$	24	$	22	$	16	$	—	$	—

(1)Includes commitments pertaining to a 20-year product transportation agreement on the Trans Mountain Pipeline Expansion.

(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 $2,913 million of interest payable over the 40-year tolling period, ending in 2058.

In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and construction of its various development projects. These contracts can be cancelled by the Company upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation.

LEGAL PROCEEDINGS AND OTHER CONTINGENCIES

The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition, the Company is subject to certain contractor construction claims. The Company believes that any liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the application of IFRS that have a significant impact on the financial results of the Company. Actual results may differ from estimated amounts, and those differences may be material. A comprehensive discussion of the Company's significant accounting estimates is contained in the Company's annual MD&A and audited consolidated financial statements for the year ended December 31, 2022.

CONTROL ENVIRONMENT

There have been no changes to internal control over financial reporting ("ICFR") during the three months ended March 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           26 Three months ended March 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 or 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. 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
($ millions)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Net earnings	$	1,799	$	1,520	$	3,101
Share-based compensation, net of tax (1)	62		309		526
Unrealized risk management loss, net of tax (2)	16		11		17
Unrealized foreign exchange gain, net of tax (3)	(3)		(203)		(156)
Realized foreign exchange loss on debt settlement, net of tax	—		7		—
Loss (gain) from investments, net of tax (4)	7		(88)		(83)
Recoverability charge, net of tax (5)	—		651		—
Other, net of tax (6)	—		(13)		(29)
Non-operating items, net of tax	82		674		275
Adjusted net earnings from operations	$	1,881	$	2,194	$	3,376

(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 March 31, 2023 was an expense of $66 million (three months ended December 31, 2022 – $319 million expense, three months ended March 31, 2022 – $534 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 loss for the three months ended March 31, 2023 was $20 million (three months ended December 31, 2022 – $15 million loss, three months ended March 31, 2022 – $26 million loss).

(3)Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings. Pre- and after-tax amounts for these unrealized foreign exchange losses and gains are the same.

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

(5)The Company recognized a recoverability charge of $1,620 million in depletion, depreciation and amortization at December 31, 2022 relating to the de-booking of reserves at the Ninian field in the North Sea. Prevailing regulatory and economic conditions in 2022 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. Following a detailed review of its development plans, the Company determined that the Ninian field is no longer economic, de-booked associated reserves as at December 31, 2022 and is accelerating abandonment.

(6)Other relates to the impact of government grant income under the provincial well-site rehabilitation programs. Pre-tax other for the three months ended March 31, 2023 was $nil (three months ended December 31, 2022 – $16 million, three months ended March 31, 2022 – $38 million).

Canadian Natural Resources Limited           27 Three months ended March 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 and to repay debt. A reconciliation for adjusted funds flow, from cash flows from operating activities is presented below.

	Three Months Ended
($ millions)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Cash flows from operating activities	$	1,295	$	4,544	$	2,853
Net change in non-cash working capital	1,908		(517)		1,940
Abandonment expenditures, net (1)	137		84		67
Movements in other long-term assets (2)	89		65		115
Adjusted funds flow	$	3,429	$	4,176	$	4,975

(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.

Adjusted Net Earnings from Operations and Adjusted Funds Flow, Per Share (Basic and Diluted)

Adjusted net earnings from operations and adjusted funds flow, per common share (basic and diluted), are non-GAAP ratios that represent those non-GAAP measures divided by the weighted average number of basic and diluted common shares outstanding for the period, respectively, as presented in note 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 annual capital budget. 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
($ millions)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Abandonment expenditures	$	137	$	100	$	105
Government grants for abandonment expenditures	—		(16)		(38)
Abandonment expenditures, net	$	137	$	84	$	67

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, natural gas 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           28 Three months ended March 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 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
($ millions, except bbl/d and $/bbl)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Crude oil and NGLs (bbl/d)
North America	481,045		482,931		494,810
International
North Sea	—		20,854		11,245
Offshore Africa	10,393		14,059		18,550
Total International	10,393		34,913		29,795
Total sales volumes	491,438		517,844		524,605
Crude oil and NGLs sales (1)	$	3,841	$	4,505	$	5,883
Less: Blending and feedstock costs (2)	1,238		1,202		1,466
Realized crude oil and NGLs sales	$	2,603	$	3,303	$	4,417
Realized price ($/bbl)	$	58.85	$	69.34	$	93.54

(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
($ millions, except BOE/d and $/BOE)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Barrels of oil equivalent (BOE/d)
North America	835,542		833,719		826,161
International
North Sea	419		21,375		11,720
Offshore Africa	11,961		15,171		21,095
Total International	12,380		36,546		32,815
Total sales volumes	847,922		870,265		858,976
Barrels of oil equivalent sales (1)	$	4,663	$	5,751	$	6,832
Less: Blending and feedstock costs (2)	1,238		1,202		1,466
Less: Sulphur income	(8)		(3)		(19)
Realized barrels of oil equivalent sales	$	3,433	$	4,552	$	5,385
Realized price ($/BOE)	$	44.98	$	56.83	$	69.66

(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           29 Three months ended March 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
($ millions, except $ per unit amounts)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Transportation, blending and feedstock (1)	$	1,546	$	1,506	$	1,754
Less: Blending and feedstock costs	1,238		1,202		1,466
Transportation	$	308	$	304	$	288
Transportation ($/BOE)	$	4.03	$	3.80	$	3.72
Amounts attributed to crude oil and NGLs	$	200	$	196	$	197
Transportation ($/bbl)	$	4.52	$	4.11	$	4.18
Amounts attributed to natural gas	$	108	$	108	$	91
Transportation ($/Mcf)	$	0.55	$	0.55	$	0.50

(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
($ millions, except $/bbl and royalty rates)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Crude oil and NGLs sales (1)	$	3,749	$	4,124	$	5,539
Less: Blending and feedstock costs (2)	1,238		1,202		1,466
Realized crude oil and NGLs sales	$	2,511	$	2,922	$	4,073
Realized crude oil and NGLs prices ($/bbl)	$	57.99	$	65.79	$	91.44
Crude oil and NGLs royalties (3)	$	437	$	625	$	830
Crude oil and NGLs royalty rates	17%		21%		20%

(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.

Canadian Natural Resources Limited           30 Three months ended March 31, 2023

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.

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
($ millions, except for bbl/d and $/bbl)	Mar 31 2023		Dec 31 2022		Mar 31 2022
SCO sales volumes (bbl/d)	462,021		433,731		441,324
Crude oil and NGLs sales (1)	$	4,482	$	4,935	$	4,851
Less: Blending and feedstock costs	487		795		401
Realized SCO sales	$	3,995	$	4,140	$	4,450
Realized SCO sales price ($/bbl)	$	96.07	$	103.79	$	112.05
Transportation, blending and feedstock (2)	$	550	$	867	$	463
Less: Blending and feedstock costs	487		795		401
Transportation	$	63	$	72	$	62
Transportation ($/bbl)	$	1.52	$	1.80	$	1.55

(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.

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, the proceeds from investments, the repayment of NWRP subordinated debt advances, and abandonment expenditures including the impact of government grant income under the provincial well-site rehabilitation programs. 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
($ millions)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Cash flows used in investing activities	$	1,153	$	1,262	$	1,251
Net change in non-cash working capital	104		(29)		137
Capital expenditures	1,257		1,233		1,388
Abandonment expenditures, net (1)	137		84		67
Net capital expenditures (2)	$	1,394	$	1,317	$	1,455

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

(2)Includes base capital expenditures of $1,117 million and strategic growth capital expenditures of $277 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.

Canadian Natural Resources Limited           31 Three months ended March 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)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Undrawn bank credit facilities	$	5,520	$	5,520	$	5,590
Cash and cash equivalents	92		920		125
Investments	484		491		392
Liquidity	$	6,096	$	6,931	$	6,107

Long-term Debt, net

Long-term debt, net, is a capital management measure that represents long-term debt less cash and cash equivalents, as disclosed in note 13 to the financial statements.

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)	Mar 31 2023		Dec 31 2022		Mar 31 2022
Interest adjusted after-tax return:
Net earnings, 12 months trailing	$	9,635	$	10,937	$	9,388
Interest and other financing expense, net of tax, 12 months trailing (1)	417		424		531
Interest adjusted after-tax return	$	10,052	$	11,361	$	9,919
12 months average current portion long-term debt (2)	$	1,357	$	1,359	$	1,762
12 months average long-term debt (2)	11,228		11,761		14,981
12 months average common shareholders' equity (2)	38,544		38,218		35,680
12 months average capital employed	$	51,129	$	51,338	$	52,423
After-tax return on average capital employed	19.7%		22.1%		18.9%

(1)The blended tax rate on interest was 23% for each of the periods presented.

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

Canadian Natural Resources Limited           32 Three months ended March 31, 2023