EX-99.2 3 a09302021q3mda.htm EX-99.2

Canadian Natural Resources Limited

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2021

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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 Oil Sands Pathway to Net Zero Initiative, 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, 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, and the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term 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 effects of the novel coronavirus ("COVID-19") pandemic and the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+")) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil and natural gas and NGLs prices including due to actions of OPEC+ taken in response to COVID-19 or otherwise; 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; 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 (including production curtailments mandated by the Government of Alberta); 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 and nine months ended September 30, 2021

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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 Financial Measures

This MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as: adjusted net earnings (loss) from operations, adjusted funds flow and net capital expenditures. These financial measures are not defined by International Financial Reporting Standards ("IFRS") and therefore are referred to as non-GAAP financial measures. The non-GAAP financial measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP financial measures to evaluate its performance. The non-GAAP financial measures should not be considered an alternative to or more meaningful than net earnings (loss), cash flows from operating activities, and cash flows used in investing activities as determined in accordance with IFRS, as an indication of the Company's performance. The non-GAAP financial measure adjusted net earnings (loss) from operations is reconciled to net earnings (loss), as determined in accordance with IFRS, in the "Financial Highlights" section of this MD&A. Additionally, the non-GAAP financial measure adjusted funds flow is reconciled to cash flows from operating activities, as determined in accordance with IFRS, in the "Financial Highlights" section of this MD&A. The non-GAAP financial measure net capital expenditures is reconciled to cash flows used in investing activities, as determined in accordance with IFRS, in the "Net Capital Expenditures" section of this MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the "Liquidity and Capital Resources" section of this MD&A.

Special Note Regarding Currency, Financial Information and Production

This MD&A should be read in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2021 and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2020. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company’s unaudited interim consolidated financial statements for the three and nine months ended September 30, 2021 and this MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board ("IASB").

Production volumes and per unit statistics are presented throughout this MD&A on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.

The following discussion and analysis refers primarily to the Company's financial results for the three and nine months ended September 30, 2021 in relation to the comparable periods in 2020 and the second quarter of 2021. 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, 2020, 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 November 3, 2021.

Canadian Natural Resources Limited			2			Three and nine months ended September 30, 2021

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FINANCIAL HIGHLIGHTS

												Three Months Ended																					Nine Months Ended
($ millions, except per common share amounts)												Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Product sales (1)												$	8,521					$	7,124					$	4,676								$	22,664					$	12,272
Crude oil and NGLs												$	7,607					$	6,382					$	4,202								$	20,277					$	10,987
Natural gas												$	694					$	509					$	338								$	1,758					$	982
Net earnings (loss)												$	2,202					$	1,551					$	408								$	5,130					$	(1,184)
Per common share						– basic						$	1.87					$	1.31					$	0.35								$	4.33					$	(1.00)
						– diluted						$	1.86					$	1.30					$	0.35								$	4.32					$	(1.00)
Adjusted net earnings (loss) from operations (2)												$	2,095					$	1,480					$	135								$	4,794					$	(932)
Per common share						– basic						$	1.78					$	1.25					$	0.11								$	4.05					$	(0.79)
						– diluted						$	1.77					$	1.24					$	0.11								$	4.04					$	(0.79)
Cash flows from operating activities												$	4,290					$	2,940					$	2,070								$	9,766					$	3,444
Adjusted funds flow (3)												$	3,634					$	3,049					$	1,740								$	9,395					$	3,492
Per common share						– basic						$	3.08					$	2.57					$	1.47								$	7.94					$	2.96
						– diluted						$	3.07					$	2.56					$	1.47								$	7.91					$	2.96
Cash flows used in investing activities												$	721					$	719					$	643								$	2,088					$	2,195
Net capital expenditures (4)												$	1,011					$	1,285					$	771								$	3,104					$	2,030

(1)Further details related to product sales are disclosed in note 17 to the Company’s unaudited interim consolidated financial statements.

(2)Adjusted net earnings (loss) from operations is a non-GAAP financial measure that represents net earnings (loss) as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for the after-tax effects of certain items of a non-operational nature. The Company considers adjusted net earnings (loss) 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. The reconciliation "Adjusted Net Earnings (Loss) from Operations, as Reconciled to Net Earnings (Loss)" is presented in this MD&A. Adjusted net earnings (loss) from operations may not be comparable to similar measures presented by other companies.

(3)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, including the unamortized cost of the share bonus program, accrued interest on subordinated debt advances to North West Redwater Partnership ("NWRP"), and prepaid cost of service tolls. 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. The reconciliation "Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities" is presented in this MD&A. Adjusted funds flow may not be comparable to similar measures presented by other companies.

(4)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 investment, 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. The reconciliation "Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities" is presented in the "Net Capital Expenditures" section of this MD&A. Net capital expenditures may not be comparable to similar measures presented by other companies.

Canadian Natural Resources Limited			3			Three and nine months ended September 30, 2021

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Adjusted Net Earnings (Loss) from Operations, as Reconciled to Net Earnings (Loss)
						Three Months Ended																					Nine Months Ended
($ millions)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Net earnings (loss)						$	2,202					$	1,551					$	408								$	5,130					$	(1,184)
Share-based compensation, net of tax (1)						54						132						(5)									312						(203)
Unrealized risk management (gain) loss, net of tax (2)						(15)						6						(1)									6						(15)
Unrealized foreign exchange loss (gain), net of tax (3)						197						(151)						(270)									(126)						418
Realized foreign exchange loss on repayment of US dollar debt securities, net of tax (4)						118						—						—									118						—
Realized foreign exchange gain on settlement of cross currency swaps, net of tax (5)						—						—						—									—						(166)
Gain on acquisitions, net of tax (6)						(478)						—						—									(478)						—
Loss (gain) from investments, net of tax (7)						35						(47)						3									(129)						218
Other, net of tax (8)						(18)						(11)						—									(39)						—
Adjusted net earnings (loss) from operations						$	2,095					$	1,480					$	135								$	4,794					$	(932)

(1)Share-based compensation includes costs incurred under the Company's Stock Option Plan and Performance Share Unit ("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 (loss).

(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 (loss). The amounts ultimately realized may be materially different than those amounts reflected in the financial statements due to changes in prices of the underlying items hedged, primarily natural gas and foreign exchange.

(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 (loss).

(4)During the third quarter of 2021, the Company repaid US$500 million of 3.45% debt securities, originally due November 2021, resulting in a pre- and after-tax foreign exchange loss of $118 million.

(5)During the first quarter of 2020, the Company settled the US$500 million cross currency swaps designated as cash flow hedges of the US$500 million 3.45% US dollar debt securities due November 2021. The Company realized cash proceeds of $166 million on settlement.

(6)During the third quarter of 2021, the Company completed two acquisitions resulting in a gain of $478 million.

(7)The Company's investments in PrairieSky Royalty Ltd. ("PrairieSky") and Inter Pipeline Ltd. ("IPL") have been accounted for at fair value through profit and loss and are measured each period with (gains) losses recognized in net earnings (loss).

(8)"Other" reflects the after-tax impact of government grant income under the provincial well-site rehabilitation programs.

Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities
						Three Months Ended																					Nine Months Ended
($ millions)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Cash flows from operating activities						$	4,290					$	2,940					$	2,070								$	9,766					$	3,444
Net change in non-cash working capital						(691)						137						(372)									(544)						(228)
Abandonment expenditures (1)						54						44						68									165						197
Other (2)						(19)						(72)						(26)									8						79
Adjusted funds flow						$	3,634					$	3,049					$	1,740								$	9,395					$	3,492

(1)The Company includes abandonment expenditures in "Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities" in the "Net Capital Expenditures" section of this MD&A and excludes the impact of government grant income under the provincial well-site rehabilitation programs.

(2)Movements in other long-term assets, including the unamortized cost of the share bonus program, accrued interest on subordinated debt advances to NWRP and prepaid cost of service tolls.

Canadian Natural Resources Limited			4			Three and nine months ended September 30, 2021

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SUMMARY OF FINANCIAL HIGHLIGHTS

Consolidated Net Earnings (Loss) and Adjusted Net Earnings (Loss) from Operations

Net earnings for the nine months ended September 30, 2021 were $5,130 million compared with a net loss of $1,184 million for the nine months ended September 30, 2020. Net earnings for the nine months ended September 30, 2021 included net after-tax income of $336 million compared with net after-tax expenses of $252 million for the nine months ended September 30, 2020 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of a realized foreign exchange loss on repayment of US dollar debt securities, the foreign exchange gain on the settlement of the cross currency swaps, the gain on acquisitions, the loss (gain) from investments, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the nine months ended September 30, 2021 were $4,794 million compared with an adjusted net loss from operations of $932 million for the nine months ended September 30, 2020.

Net earnings for the third quarter of 2021 were $2,202 million compared with $408 million for the third quarter of 2020 and $1,551 million for the second quarter of 2021. Net earnings for the third quarter of 2021 included net after-tax income of $107 million compared with net after-tax income of $273 million for the third quarter of 2020 and net after-tax income of $71 million for the second quarter of 2021 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of a realized foreign exchange loss on repayment of US dollar debt securities, the gain on acquisitions, the loss (gain) from investments, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the third quarter of 2021 were $2,095 million compared with $135 million for the third quarter of 2020 and $1,480 million for the second quarter of 2021.

Net earnings and adjusted net earnings from operations for the nine months ended September 30, 2021 compared with a net loss and an adjusted net loss from operations for the nine months ended September 30, 2020 primarily reflected:

▪higher crude oil and NGLs netbacks and natural gas netbacks in the Exploration and Production segments;

▪higher realized SCO prices in the Oil Sands Mining and Upgrading segment;

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

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

partially offset by:

▪higher production costs in the Oil Sands Mining and Upgrading segment; and

▪higher realized foreign exchange losses.

Net earnings and adjusted net earnings from operations for the third quarter of 2021 compared with net earnings and adjusted net earnings from operations for the third quarter of 2020 and the second quarter of 2021 primarily reflected:

▪higher crude oil and NGLs netbacks and natural gas netbacks in the Exploration and Production segments;

▪higher realized SCO prices in the Oil Sands Mining and Upgrading segment;

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

▪higher natural gas sales volumes in the North America segment;

partially offset by:

▪lower crude oil and NGLs sales volumes in the Exploration and Production segments.

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

Canadian Natural Resources Limited			5			Three and nine months ended September 30, 2021

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Cash Flows from Operating Activities and Adjusted Funds Flow

Cash flows from operating activities for the nine months ended September 30, 2021 were $9,766 million compared with $3,444 million for the nine months ended September 30, 2020. Cash flows from operating activities for the third quarter of 2021 were $4,290 million compared with $2,070 million for the third quarter of 2020 and $2,940 million for the second quarter of 2021. 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 net earnings (loss) from operations, as well as due to the impact of changes in non-cash working capital.

Adjusted funds flow for the nine months ended September 30, 2021 was $9,395 million compared with $3,492 million for the nine months ended September 30, 2020. Adjusted funds flow for the third quarter of 2021 was $3,634 million compared with $1,740 million for the third quarter of 2020 and $3,049 million for the second quarter of 2021. 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, accrued interest on subordinated debt advances to NWRP, and prepaid cost of service tolls.

Production Volumes

Crude oil and NGLs production before royalties for the third quarter of 2021 increased 8% to 952,839 bbl/d, from 884,342 bbl/d for the third quarter of 2020 and increased 9% from 872,718 bbl/d for the second quarter of 2021. Natural gas production before royalties for the third quarter of 2021 increased 25% to 1,708 MMcf/d from 1,362 MMcf/d for the third quarter of 2020 and increased 6% from 1,614 MMcf/d for the second quarter of 2021. Total production before royalties for the third quarter of 2021 of 1,237,503 BOE/d increased 11% from 1,111,286 BOE/d for the third quarter of 2020 and increased 8% from 1,141,739 BOE/d for the second quarter of 2021. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production" section of this MD&A.

Product Prices

In the Company's Exploration and Production segments, crude oil and NGLs realized prices averaged $68.06 per bbl for the third quarter of 2021, an increase of 70% compared with $40.14 per bbl for the third quarter of 2020, and an increase of 11% from $61.20 per bbl for the second quarter of 2021. The natural gas realized price increased 79% to average $4.13 per Mcf for the third quarter of 2021 from $2.31 per Mcf for the third quarter of 2020, and increased 30% from $3.17 per Mcf for the second quarter of 2021. In the Oil Sands Mining and Upgrading segment, the Company's SCO realized price increased 67% to average $81.54 per bbl for the third quarter of 2021 from $48.92 per bbl for the third quarter of 2020, and increased 7% from $76.19 per bbl for the second quarter of 2021. 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", "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 averaged $14.78 per bbl for the third quarter of 2021, an increase of 34% from $11.03 per bbl for the third quarter of 2020, and an increase of 7% from $13.75 per bbl for the second quarter of 2021. Natural gas production expense averaged $1.17 per Mcf for the third quarter of 2021, comparable with $1.18 per Mcf for the third quarter of 2020 and $1.19 per Mcf for the second quarter of 2021. In the Oil Sands Mining and Upgrading segment, production costs averaged $19.86 per bbl for the third quarter of 2021, a decrease of 17% from $23.81 per bbl for the third quarter of 2020, and a decrease of 22% from $25.46 per bbl for the second quarter of 2021. 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.

Canadian Natural Resources Limited			6			Three and nine months ended September 30, 2021

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SUMMARY OF QUARTERLY FINANCIAL RESULTS

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

($ millions, except per common share amounts)						Sep 30 2021						Jun 30 2021						Mar 31 2021						Dec 31 2020
Product sales (1)						$	8,521					$	7,124					$	7,019					$	5,219
Crude oil and NGLs						$	7,607					$	6,382					$	6,288					$	4,592
Natural gas						$	694					$	509					$	555					$	496
Net earnings (loss)						$	2,202					$	1,551					$	1,377					$	749
Net earnings (loss) per common share
– basic						$	1.87					$	1.31					$	1.16					$	0.63
– diluted						$	1.86					$	1.30					$	1.16					$	0.63
($ millions, except per common share amounts)						Sep 30 2020						Jun 30 2020						Mar 31 2020						Dec 31 2019
Product sales (1)						$	4,676					$	2,944					$	4,652					$	6,335
Crude oil and NGLs						$	4,202					$	2,462					$	4,323					$	5,947
Natural gas						$	338					$	307					$	337					$	382
Net earnings (loss)						$	408					$	(310)					$	(1,282)					$	597
Net earnings (loss) per common share
– basic						$	0.35					$	(0.26)					$	(1.08)					$	0.50
– diluted						$	0.35					$	(0.26)					$	(1.08)					$	0.50

(1)Further details related to product sales for the three months ended September 30, 2021 and 2020 are disclosed in note 17 to the Company’s unaudited interim consolidated financial statements.

Canadian Natural Resources Limited			7			Three and nine months ended September 30, 2021

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Volatility in the quarterly net earnings (loss) 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, 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; the impact of the differential between WTI and Dated Brent ("Brent") benchmark pricing in the North Sea and Offshore Africa; and the impact of production curtailments mandated by the Government of Alberta that came into effect on January 1, 2019 and were suspended effective December 1, 2020.

▪Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, third-party pipeline maintenance and outages, 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 Company's Primrose thermal oil projects, fluctuations in the Company’s drilling program in North America and the International segments, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, production curtailments mandated by the Government of Alberta that came into effect January 1, 2019 and were suspended effective December 1, 2020, 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 allocation of capital to high return projects, drilling results, natural decline rates, the temporary shut-down and subsequent reinstatement of the Pine River Gas Plant, and the impact and timing of acquisitions.

▪Production expense – Fluctuations primarily due to the impact of the demand and cost for services, fluctuations in product mix and production volumes, the impact of seasonality, the impact of increased carbon tax and energy costs, cost optimizations across all segments, the impact and timing of acquisitions, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments.

▪Transportation, blending, and feedstock expense – Fluctuations due to the provision recognized relating to the cancellation of the Keystone XL pipeline project in the fourth quarter of 2020.

▪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, and the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment.

▪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.

▪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. Fluctuations in realized and unrealized foreign exchange gains and losses were also recorded with respect to US dollar denominated debt, partially offset by the impact of cross currency swap hedges.

▪Gain on acquisitions, loss (gain) from investments and income from NWRP – Fluctuations due to the recognition of gains on acquisitions, loss (gain) from the investments in PrairieSky and IPL shares, equity income and losses on the Company's interest in NWRP, and the distribution from NWRP in the second quarter of 2021.

▪Income taxes – Fluctuations due to statutory tax rate and other legislative changes substantively enacted in the various periods.

Canadian Natural Resources Limited			8			Three and nine months ended September 30, 2021

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BUSINESS ENVIRONMENT

Global benchmark crude oil prices increased significantly through the third quarter of 2021, partially in response to the OPEC+ decision to maintain substantially all of the production cut agreements implemented in the first half of 2020. Additionally, global demand for crude oil increased due to improved economic conditions, as the effects of COVID-19 became less impactful to the global economy. Improved economic conditions continue to positively impact the outlook for crude oil prices, although market conditions remain uncertain.

During the third quarter of 2021, the Company continued to utilize federal and provincial government programs to support employment during the COVID-19 pandemic, including in Canada, the provincial well-site rehabilitation program.

Liquidity

As at September 30, 2021, the Company had undrawn revolving bank credit facilities of $4,959 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,159 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit.

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

Capital Spending

Safe, reliable, effective and efficient operations continue to be a focus for the Company. On December 9, 2020, the Company announced its 2021 capital budget targeted at approximately $3,205 million, of which $1,345 million was related to conventional and unconventional assets and $1,860 million was allocated to long-life low decline assets. On August 5, 2021, the 2021 capital budget was increased by $275 million to $3,480 million, excluding acquisitions. The increase included $120 million for conventional and unconventional assets, $110 million for long-life low decline assets, and $45 million for additional well abandonment activities. Production for 2021 is targeted between 1,220,000 BOE/d and 1,267,000 BOE/d. Annual budgets are developed and scrutinized throughout the year and can be changed, if necessary, in the context of price volatility, project returns and the balancing of project risks and time horizons. The 2021 capital budget and production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

During the nine months ended September 30, 2021, the Company completed three opportunistic acquisitions. The first two acquisitions consisted of natural gas assets located in the Montney region of British Columbia, with aggregate production of approximately 11,100 BOE/d, consisting of 63 MMcf/d and 600 bbl/d of NGLs, approximately 107,000 acres of Montney lands, and related processing infrastructure with approximately 140 MMcf/d of capacity. These two acquisitions build on the Company’s expansive natural gas operations in northeastern British Columbia, increasing the Company's total Montney lands to approximately 1.3 million acres. The third acquisition consisted of a net carried interest on an existing Canadian Natural oil sands lease, from which all of the Company's current Horizon volumes are derived. Total cash consideration paid for these acquisitions was approximately $450 million.

During the third quarter of 2021, in accordance with a third-party offer to purchase, the Company elected to take total cash proceeds of $128 million, or $20.00 per common share, in exchange for its 6.4 million common share investment in IPL.

Risks and Uncertainties

COVID-19, including variants of concern, continues to have the potential to further disrupt the Company’s operations, projects and financial condition through the disruption of the local or global supply chain and transportation services, or the loss of manpower resulting from quarantines that affect the Company’s labour pools in their local communities, workforce camps or operating sites or that are instituted by local health authorities as a precautionary measure, any of which may require the Company to temporarily reduce or shutdown its operations depending on their extent and severity.

Canadian Natural Resources Limited			9			Three and nine months ended September 30, 2021

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Benchmark Commodity Prices

						Three Months Ended																					Nine Months Ended
(Average for the period)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
WTI benchmark price (US$/bbl)						$	70.55					$	66.06					$	40.94								$	64.85					$	38.30
Dated Brent benchmark price (US$/bbl)						$	72.98					$	68.63					$	42.74								$	67.44					$	41.51
WCS Heavy Differential from WTI (US$/bbl)						$	13.58					$	11.47					$	9.06								$	12.50					$	13.67
SCO price (US$/bbl)						$	68.98					$	66.49					$	38.61								$	63.31					$	35.11
Condensate benchmark price (US$/bbl)						$	69.22					$	66.39					$	37.55								$	64.58					$	35.10
Condensate Differential from WTI (US$/bbl)						$	1.33					$	(0.33)					$	3.39								$	0.27					$	3.20
NYMEX benchmark price (US$/MMBtu)						$	4.01					$	2.83					$	1.97								$	3.18					$	1.88
AECO benchmark price (C$/GJ)						$	3.36					$	2.70					$	2.03								$	2.95					$	1.96
US/Canadian dollar average exchange rate (US$)						$	0.7936					$	0.8143					$	0.7507								$	0.7992					$	0.7384

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 highly sensitive to fluctuations in foreign exchange rates. Product revenue 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$64.85 per bbl for the nine months ended September 30, 2021, an increase of 69% from US$38.30 per bbl for the nine months ended September 30, 2020. WTI averaged US$70.55 per bbl for the third quarter of 2021, an increase of 72% from US$40.94 per bbl for the third quarter of 2020, and an increase of 7% from US$66.06 per bbl for the second quarter of 2021.

Crude oil sales contracts for the Company’s North Sea and Offshore Africa segments are typically based on Brent pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$67.44 per bbl for the nine months ended September 30, 2021, an increase of 62% from US$41.51 per bbl for the nine months ended September 30, 2020. Brent averaged US$72.98 per bbl for the third quarter of 2021, an increase of 71% from US$42.74 per bbl for the third quarter of 2020, and an increase of 6% from US$68.63 per bbl for the second quarter of 2021.

The increase in WTI and Brent pricing for the three and nine months ended September 30, 2021 from the comparable periods in 2020 primarily reflected the OPEC+ decision to maintain substantially all of the production cut agreements that were implemented in the first half of 2020. Additionally, global demand for crude oil increased due to improved economic conditions. The increase in WTI and Brent pricing for the third quarter of 2021 from the second quarter of 2021 primarily reflected the continued recovery of global demand.

The WCS Heavy Differential averaged US$12.50 per bbl for the nine months ended September 30, 2021, a narrowing of 9% from US$13.67 per bbl for the nine months ended September 30, 2020. The WCS Heavy Differential averaged US$13.58 per bbl for the third quarter of 2021, a widening of 50% from US$9.06 per bbl for the third quarter of 2020, and a widening of 18% from US$11.47 per bbl for the second quarter of 2021. The widening of the WCS Heavy Differential for the third quarter of 2021 from the comparable periods primarily reflected increases in WTI benchmark pricing and the widening of the US Gulf Coast heavy oil pricing.

The SCO price averaged US$63.31 per bbl for the nine months ended September 30, 2021, an increase of 80% from US$35.11 per bbl for the nine months ended September 30, 2020. The SCO price averaged US$68.98 per bbl for the third quarter of 2021, an increase of 79% from US$38.61 per bbl for the third quarter of 2020, and an increase of 4% from US$66.49 per bbl for the second quarter of 2021. The increase in SCO pricing for the three and nine months ended September 30, 2021 from the comparable periods primarily reflected increases in WTI benchmark pricing.

NYMEX natural gas prices averaged US$3.18 per MMBtu for the nine months ended September 30, 2021, an increase of 69% from US$1.88 per MMBtu for the nine months ended September 30, 2020. NYMEX natural gas prices averaged US$4.01 per MMBtu for the third quarter of 2021, an increase of 104% from US$1.97 per MMBtu for the

Canadian Natural Resources Limited			10			Three and nine months ended September 30, 2021

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third quarter of 2020, and an increase of 42% from US$2.83 per MMBtu for the second quarter of 2021. The increase in NYMEX natural gas prices for the three and nine months ended September 30, 2021 from the comparable periods in 2020 primarily reflected increased North American demand in 2021, following the impact of COVID-19 in 2020, as well as lower storage levels. The increase in NYMEX natural gas prices for the third quarter of 2021 from the second quarter of 2021 primarily reflected increased international Liquefied Natural Gas prices, together with low storage levels.

AECO natural gas prices averaged $2.95 per GJ for the nine months ended September 30, 2021, an increase of 51% from $1.96 per GJ for the nine months ended September 30, 2020. AECO natural gas prices averaged $3.36 per GJ for the third quarter of 2021, an increase of 66% from $2.03 per GJ for the third quarter of 2020, and an increase of 24% from $2.70 per GJ for the second quarter of 2021. The increase in AECO natural gas prices for the three and nine months ended September 30, 2021 from the comparable periods primarily reflected lower storage levels and increased NYMEX benchmark pricing.

DAILY PRODUCTION, before royalties

			Three Months Ended									Nine Months Ended
			Sep 30 2021			Jun 30 2021			Sep 30 2020			Sep 30 2021			Sep 30 2020
Crude oil and NGLs (bbl/d)
North America – Exploration and Production			454,888			478,314			494,952			470,558			455,257
North America – Oil Sands Mining and Upgrading (1)			468,126			361,707			350,633			432,876			417,439
North Sea			16,294			16,458			21,220			17,557			25,186
Offshore Africa			13,531			16,239			17,537			13,882			16,977
			952,839			872,718			884,342			934,873			914,859
Natural gas (MMcf/d)
North America			1,698			1,594			1,340			1,626			1,393
North Sea			2			4			5			3			14
Offshore Africa			8			16			17			11			14
			1,708			1,614			1,362			1,640			1,421
Total barrels of oil equivalent (BOE/d)			1,237,503			1,141,739			1,111,286			1,208,285			1,151,693
Product mix
Light and medium crude oil and NGLs			10%			11%			11%			10%			11%
Pelican Lake heavy crude oil			4%			5%			5%			5%			5%
Primary heavy crude oil			5%			6%			6%			5%			6%
Bitumen (thermal oil)			20%			23%			26%			21%			21%
Synthetic crude oil (1)			38%			32%			32%			36%			36%
Natural gas			23%			23%			20%			23%			21%
Percentage of gross revenue (1) (2)
(excluding Midstream and Refining revenue)
Crude oil and NGLs			91%			92%			93%			92%			92%
Natural gas			9%			8%			7%			8%			8%

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

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

Canadian Natural Resources Limited			11			Three and nine months ended September 30, 2021

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DAILY PRODUCTION, net of royalties

			Three Months Ended									Nine Months Ended
			Sep 30 2021			Jun 30 2021			Sep 30 2020			Sep 30 2021			Sep 30 2020
Crude oil and NGLs (bbl/d)
North America – Exploration and Production			386,416			407,111			455,393			405,086			416,611
North America – Oil Sands Mining and Upgrading			421,483			331,214			347,475			400,239			413,941
North Sea			16,256			16,380			21,150			17,508			25,122
Offshore Africa			12,901			15,531			16,767			13,258			16,269
			837,056			770,236			840,785			836,091			871,943
Natural gas (MMcf/d)
North America			1,609			1,532			1,298			1,550			1,357
North Sea			2			4			5			3			14
Offshore Africa			7			16			16			11			14
			1,618			1,552			1,319			1,564			1,385
Total barrels of oil equivalent (BOE/d)			1,106,743			1,028,908			1,060,629			1,096,779			1,102,742

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

Crude oil and NGLs production before royalties for the nine months ended September 30, 2021 averaged 934,873 bbl/d, an increase of 2% from 914,859 bbl/d for the nine months ended September 30, 2020. Crude oil and NGLs production for the third quarter of 2021 averaged 952,839 bbl/d, an increase of 8% from 884,342 bbl/d for the third quarter of 2020, and an increase of 9% from 872,718 bbl/d for the second quarter of 2021. The increase in crude oil and NGLs production for the nine months ended September 30, 2021 from the comparable period in 2020 primarily reflected the completion of expansion activities at the Scotford Upgrader ("Scotford") in the prior year, and high utilization at Jackfish. The increase in crude oil and NGLs production for the third quarter of 2021 from the comparable periods primarily reflected the timing of turnaround activities in the Oil Sands Mining and Upgrading segment, partially offset by planned turnaround activities at Jackfish in the third quarter of 2021. Crude oil and NGLs production in North America Exploration and Production and Oil Sands Mining and Upgrading segments for the comparable periods in 2020 reflected the impact of the Company's curtailment optimization strategy during mandatory Government of Alberta curtailment.

Natural gas production before royalties for the nine months ended September 30, 2021 of 1,640 MMcf/d increased 15% from 1,421 MMcf/d for the nine months ended September 30, 2020. Natural gas production for the third quarter of 2021 of 1,708 MMcf/d increased 25% from 1,362 MMcf/d for the third quarter of 2020, and increased 6% from 1,614 MMcf/d for the second quarter of 2021. The increase in natural gas production for the three and nine months ended September 30, 2021 from the comparable periods in 2020 primarily reflected production volumes from the acquisition in 2020, and strong drilling results, partially offset by natural field declines. The increase in natural gas production for the third quarter of 2021 from the second quarter of 2021 primarily reflected reinstated volumes from the Pine River Gas Plant, acquisitions, and strong drilling results, partially offset by natural field declines.

Annual crude oil and NGLs production for 2021 is targeted to average between 940,000 bbl/d and 980,000 bbl/d. Annual natural gas production for 2021 is targeted to average between 1,680 MMcf/d and 1,720 MMcf/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Canadian Natural Resources Limited			12			Three and nine months ended September 30, 2021

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North America – Exploration and Production

North America crude oil and NGLs production before royalties for the nine months ended September 30, 2021 averaged 470,558 bbl/d, an increase of 3% from 455,257 bbl/d for the nine months ended September 30, 2020. North America crude oil and NGLs production for the third quarter of 2021 of 454,888 bbl/d decreased 8% from 494,952 bbl/d for the third quarter of 2020, and decreased 5% from 478,314 bbl/d for the second quarter of 2021. The increase in crude oil and NGLs production for the nine months ended September 30, 2021 from the comparable period in 2020 primarily reflected the impact of the suspension of mandatory Government of Alberta curtailment on December 1, 2020. The decrease in production for the third quarter of 2021 from the comparable periods primarily reflected decreased thermal oil production due to planned turnaround activities at Jackfish in the third quarter of 2021 and natural field declines. The decrease in production for the third quarter of 2021 from the second quarter of 2021 also reflected decreased NGLs production primarily due to third-party outages.

Thermal oil production before royalties for the third quarter of 2021 averaged 248,113 bbl/d, a decrease of 14% from 287,978 bbl/d for the third quarter of 2020, and a decrease of 4% from 258,551 bbl/d for the second quarter of 2021. The decrease in thermal oil production for the third quarter of 2021 from the comparable periods primarily reflected planned turnaround activities at Jackfish in the third quarter of 2021 and natural field declines.

Pelican Lake heavy crude oil production before royalties averaged 53,923 bbl/d for the third quarter of 2021, a decrease of 4% from 56,392 bbl/d for the third quarter of 2020, and comparable with 55,212 bbl/d for the second quarter of 2021, demonstrating Pelican Lake's long-life low decline production.

Natural gas production before royalties for the nine months ended September 30, 2021 averaged 1,626 MMcf/d, an increase of 17% from 1,393 MMcf/d for the nine months ended September 30, 2020. Natural gas production for the third quarter of 2021 averaged 1,698 MMcf/d, an increase of 27% from 1,340 MMcf/d for the third quarter of 2020, and an increase of 7% from 1,594 MMcf/d for the second quarter of 2021. The increase in natural gas production for the three and nine months ended September 30, 2021 from the comparable periods in 2020 primarily reflected production volumes from the acquisition in 2020 and strong drilling results, partially offset by natural field declines. The increase in natural gas production for the third quarter of 2021 from the second quarter of 2021 primarily reflected reinstated volumes from the Pine River Gas Plant, acquisitions, and strong drilling results, partially offset by natural field declines.

North America – Oil Sands Mining and Upgrading

SCO production before royalties for the nine months ended September 30, 2021 of 432,876 bbl/d increased 4% from 417,439 bbl/d for the nine months ended September 30, 2020. SCO production for the third quarter of 2021 of 468,126 bbl/d increased 34% from 350,633 bbl/d for the third quarter of 2020 and increased 29% from 361,707 bbl/d for the second quarter of 2021. The increase in SCO production for the nine months ended September 30, 2021 from the comparable period primarily reflected the completion of expansion activities at Scotford in the prior year. The increase in the third quarter of 2021 from the comparable periods primarily reflected the timing of planned turnaround activities.

North Sea

North Sea crude oil production before royalties for the nine months ended September 30, 2021 of 17,557 bbl/d decreased 30% from 25,186 bbl/d for the nine months ended September 30, 2020. North Sea crude oil production for the third quarter of 2021 of 16,294 bbl/d decreased 23% from 21,220 bbl/d for the third quarter of 2020 and was comparable with 16,458 bbl/d for the second quarter of 2021. The decrease in production for the three and nine months ended September 30, 2021 from the comparable periods in 2020 primarily reflected planned maintenance activities and natural field declines.

Offshore Africa

Offshore Africa crude oil production before royalties for the nine months ended September 30, 2021 decreased 18% to 13,882 bbl/d from 16,977 bbl/d for the nine months ended September 30, 2020. Offshore Africa crude oil production for the third quarter of 2021 of 13,531 bbl/d decreased 23% from 17,537 bbl/d for the third quarter of 2020 and decreased 17% from 16,239 bbl/d for the second quarter of 2021. The decrease in production for the three and nine months ended September 30, 2021 from the comparable periods primarily reflected planned maintenance activities at Espoir, which were completed subsequent to the third quarter of 2021.

Canadian Natural Resources Limited			13			Three and nine months ended September 30, 2021

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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)			Sep 30 2021			Jun 30 2021			Sep 30 2020
North Sea			295,014			270,524			730,801
Offshore Africa			—			458,208			779,347
			295,014			728,732			1,510,148

OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION

						Three Months Ended																					Nine Months Ended
						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Crude oil and NGLs ($/bbl) (1)
Sales price (2)						$	68.06					$	61.20					$	40.14								$	60.53					$	28.91
Transportation						4.00						3.98						3.60									3.84						3.87
Realized sales price, net of transportation						64.06						57.22						36.54									56.69						25.04
Royalties						9.46						8.50						3.03									7.86						2.33
Production expense						14.78						13.75						11.03									14.36						12.41
Netback						$	39.82					$	34.97					$	22.48								$	34.47					$	10.30
Natural gas ($/Mcf) (1)
Sales price (2)						$	4.13					$	3.17					$	2.31								$	3.59					$	2.19
Transportation						0.44						0.48						0.42									0.46						0.44
Realized sales price, net of transportation						3.69						2.69						1.89									3.13						1.75
Royalties						0.22						0.12						0.07									0.17						0.06
Production expense						1.17						1.19						1.18									1.21						1.21
Netback						$	2.30					$	1.38					$	0.64								$	1.75					$	0.48
Barrels of oil equivalent ($/BOE) (1)
Sales price (2)						$	52.09					$	46.40					$	32.28								$	46.77					$	23.82
Transportation						3.50						3.58						3.28									3.45						3.46
Realized sales price, net of transportation						48.59						42.82						29.00									43.32						20.36
Royalties						6.45						5.77						2.25									5.44						1.69
Production expense						11.91						11.42						9.84									11.85						10.76
Netback						$	30.23					$	25.63					$	16.91								$	26.03					$	7.91

(1)Amounts expressed on a per unit basis are based on sales volumes.

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

Canadian Natural Resources Limited			14			Three and nine months ended September 30, 2021

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PRODUCT PRICES – EXPLORATION AND PRODUCTION

						Three Months Ended																					Nine Months Ended
						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Crude oil and NGLs ($/bbl) (1) (2)
North America						$	66.03					$	59.80					$	38.86								$	58.74					$	27.11
North Sea						$	96.11					$	85.09					$	57.84								$	83.03					$	48.36
Offshore Africa						$	91.73					$	85.78					$	55.11								$	86.92					$	51.74
Average						$	68.06					$	61.20					$	40.14								$	60.53					$	28.91
Natural gas ($/Mcf) (1) (2)
North America						$	4.12					$	3.13					$	2.25								$	3.57					$	2.12
North Sea						$	3.75					$	2.58					$	3.44								$	2.86					$	2.87
Offshore Africa						$	6.83					$	6.50					$	7.32								$	6.46					$	8.22
Average						$	4.13					$	3.17					$	2.31								$	3.59					$	2.19
Average ($/BOE) (1) (2)						$	52.09					$	46.40					$	32.28								$	46.77					$	23.82

(1)Amounts expressed on a per unit basis are based on sales volumes.

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

North America

North America realized crude oil and NGLs prices increased 117% to average $58.74 per bbl for the nine months ended September 30, 2021 from $27.11 per bbl for the nine months ended September 30, 2020. North America realized crude oil and NGLs prices increased 70% to average $66.03 per bbl for the third quarter of 2021 from $38.86 per bbl for the third quarter of 2020, and increased 10% from $59.80 per bbl for the second quarter of 2021. The increase in realized crude oil and NGLs prices for the three and nine months ended September 30, 2021 from the comparable periods was primarily due to higher WTI benchmark pricing. The Company continues to focus on its crude oil blending marketing strategy and in the third quarter of 2021 contributed approximately 163,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices increased 68% to average $3.57 per Mcf for the nine months ended September 30, 2021 from $2.12 per Mcf for the nine months ended September 30, 2020. North America realized natural gas prices increased 83% to average $4.12 per Mcf for the third quarter of 2021 from $2.25 per Mcf for the third quarter of 2020, and increased 32% from $3.13 per Mcf for the second quarter of 2021. The increase in realized natural gas prices for the three and nine months ended September 30, 2021 from the comparable periods primarily reflected lower storage levels and increased benchmark pricing.

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

						Three Months Ended
(Quarterly average)						Sep 30 2021						Jun 30 2021						Sep 30 2020
Wellhead Price (1) (2)
Light and medium crude oil and NGLs ($/bbl)						$	63.88					$	55.81					$	36.48
Pelican Lake heavy crude oil ($/bbl)						$	71.92					$	67.75					$	42.97
Primary heavy crude oil ($/bbl)						$	68.72					$	64.24					$	42.63
Bitumen (thermal oil) ($/bbl)						$	64.81					$	58.50					$	37.78
Natural gas ($/Mcf)						$	4.12					$	3.13					$	2.25

(1)Amounts expressed on a per unit basis are based on sales volumes.

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

Canadian Natural Resources Limited			15			Three and nine months ended September 30, 2021

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North Sea

North Sea realized crude oil and NGLs prices increased 72% to average $83.03 per bbl for the nine months ended September 30, 2021 from $48.36 per bbl for the nine months ended September 30, 2020. North Sea realized crude oil and NGLs prices increased 66% to average $96.11 per bbl for the third quarter of 2021 from $57.84 per bbl for the third quarter of 2020 and increased 13% from $85.09 per bbl for the second quarter of 2021. Realized crude oil and NGLs prices per barrel in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The fluctuations in realized crude oil and NGLs prices for the three and nine months ended September 30, 2021 from the comparable periods reflected prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.

Offshore Africa

Offshore Africa realized crude oil and NGLs prices increased 68% to average $86.92 per bbl for the nine months ended September 30, 2021 from $51.74 per bbl for the nine months ended September 30, 2020. Offshore Africa realized crude oil and NGLs prices increased 66% to average $91.73 per bbl for the third quarter of 2021 from $55.11 per bbl for the third quarter of 2020 and increased 7% from $85.78 per bbl for the second quarter of 2021. Realized crude oil and NGLs prices per barrel in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The fluctuations in realized crude oil and NGLs prices for the three and nine months ended September 30, 2021 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																					Nine Months Ended
						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Crude oil and NGLs ($/bbl) (1)
North America						$	10.02					$	8.84					$	3.15								$	8.29					$	2.45
North Sea						$	0.22					$	0.39					$	0.19								$	0.19					$	0.12
Offshore Africa						$	4.27					$	3.74					$	2.42								$	3.92					$	2.19
Average						$	9.46					$	8.50					$	3.03								$	7.86					$	2.33
Natural gas ($/Mcf) (1)
North America						$	0.22					$	0.12					$	0.07								$	0.17					$	0.05
Offshore Africa						$	0.31					$	0.30					$	0.34								$	0.29					$	0.40
Average						$	0.22					$	0.12					$	0.07								$	0.17					$	0.06
Average ($/BOE) (1)						$	6.45					$	5.77					$	2.25								$	5.44					$	1.69

(1)Amounts expressed on a per unit basis are based on sales volumes.

North America

North America crude oil and natural gas royalties for the three and nine months ended September 30, 2021 and the comparable periods reflected movements in benchmark commodity prices. North America crude oil royalties also reflected fluctuations in the WCS Heavy Differential and changes in the production mix between high and low royalty rate product types.

Crude oil and NGLs royalty rates averaged approximately 14% of product sales for the nine months ended September 30, 2021 compared with 9% of product sales for the nine months ended September 30, 2020. Crude oil and NGLs royalty rates averaged approximately 15% of product sales for the third quarter of 2021 compared with 8% for the third quarter of 2020 and 15% for the second quarter of 2021. The increase in royalty rates for the three and nine months ended September 30, 2021 from the comparable periods in 2020 was primarily due to higher benchmark prices together with fluctuations in the WCS Heavy Differential.

Canadian Natural Resources Limited			16			Three and nine months ended September 30, 2021

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Natural gas royalty rates averaged approximately 5% of product sales for the nine months ended September 30, 2021 compared with 3% of product sales for the nine months ended September 30, 2020. Natural gas royalty rates averaged approximately 5% of product sales for the third quarter of 2021 compared with 3% for the third quarter of 2020 and 4% for the second quarter of 2021. The increase in royalty rates for the three and nine months ended September 30, 2021 from the comparable periods was primarily due to higher 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 5% for the nine months ended September 30, 2021, compared with 4% of product sales for the nine months ended September 30, 2020. Royalty rates as a percentage of product sales averaged approximately 5% for the third quarter of 2021 compared with 4% of product sales for the third quarter of 2020 and 4% for the second quarter of 2021. Royalty rates as a percentage of product sales reflected the timing of liftings and the status of payout in the various fields.

PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION 

						Three Months Ended																					Nine Months Ended
						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Crude oil and NGLs ($/bbl) (1)
North America						$	13.33					$	12.82					$	9.80								$	12.98					$	11.34
North Sea						$	55.90					$	63.65					$	42.10								$	49.83					$	31.99
Offshore Africa						$	14.53					$	13.20					$	16.41								$	14.49					$	13.94
Average						$	14.78					$	13.75					$	11.03								$	14.36					$	12.41
Natural gas ($/Mcf) (1)
North America						$	1.14					$	1.15					$	1.14								$	1.18					$	1.16
North Sea						$	8.86					$	6.96					$	5.38								$	6.66					$	3.56
Offshore Africa						$	5.76					$	3.37					$	3.03								$	4.37					$	3.79
Average						$	1.17					$	1.19					$	1.18								$	1.21					$	1.21
Average ($/BOE) (1)						$	11.91					$	11.42					$	9.84								$	11.85					$	10.76

(1)Amounts expressed on a per unit basis are based on sales volumes.

North America

North America crude oil and NGLs production expense for the nine months ended September 30, 2021 averaged $12.98 per bbl, an increase of 14% from $11.34 per bbl for the nine months ended September 30, 2020. North America crude oil and NGLs production expense for the third quarter of 2021 of $13.33 per bbl increased 36% from $9.80 per bbl for the third quarter of 2020 and increased 4% from $12.82 per bbl for the second quarter of 2021. The increase in crude oil and NGLs production expense per bbl for the nine months ended September 30, 2021 from the comparable period in 2020 primarily reflected an increase in energy costs in 2021. The increase in crude oil and NGLs production expense per bbl for the third quarter of 2021 from the comparable periods primarily reflected lower production volumes in the third quarter of 2021 and higher energy costs.

North America natural gas production expense for the nine months ended September 30, 2021 averaged $1.18 per Mcf, comparable with $1.16 per Mcf for the nine months ended September 30, 2020. North America natural gas production expense for the third quarter of 2021 of $1.14 per Mcf was comparable with $1.14 per Mcf for the third quarter of 2020 and $1.15 per Mcf for the second quarter of 2021, reflecting the Company's continuous focus on cost control.

Canadian Natural Resources Limited			17			Three and nine months ended September 30, 2021

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North Sea

North Sea crude oil production expense for the nine months ended September 30, 2021 averaged $49.83 per bbl, an increase of 56% from $31.99 per bbl for the nine months ended September 30, 2020. North Sea crude oil production expense for the third quarter of 2021 of $55.90 per bbl increased 33% from $42.10 per bbl for the third quarter of 2020 and decreased 12% from $63.65 per bbl for the second quarter of 2021. The increase in crude oil production expense per bbl for the three and nine months ended September 30, 2021 from the comparable periods in 2020 primarily reflected lower volumes due to planned maintenance activities, on a relatively fixed cost base, together with higher energy costs. The decrease in crude oil production expense per bbl for the third quarter of 2021 from the second quarter of 2021 reflected the timing of liftings from various fields that have different cost structures. North Sea production expense also reflected fluctuations in the Canadian dollar.

Offshore Africa

Offshore Africa crude oil production expense for the nine months ended September 30, 2021 averaged $14.49 per bbl, an increase of 4% from $13.94 per bbl for the nine months ended September 30, 2020. Offshore Africa crude oil production expense for the third quarter of 2021 of $14.53 per bbl decreased 11% from $16.41 per bbl for the third quarter of 2020 and increased 10% from $13.20 per bbl for the second quarter of 2021. The fluctuations in crude oil production expense per bbl from the comparable periods reflected the timing of liftings from various fields that have different cost structures. Offshore Africa production expense also reflected fluctuations in the Canadian dollar.

DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION

						Three Months Ended																					Nine Months Ended
($ millions, except per BOE amounts)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
North America						$	881					$	881					$	937								$	2,630					$	2,763
North Sea						40						19						41									127						216
Offshore Africa						48						44						68									123						136
Expense						$	969					$	944					$	1,046								$	2,880					$	3,115
$/BOE (1)						$	13.70					$	13.57					$	15.01								$	13.66					$	15.41

(1)Amounts expressed on a per unit basis are based on sales volumes.

Depletion, depreciation and amortization expense for the nine months ended September 30, 2021 of $13.66 per BOE decreased 11% from $15.41 per BOE for the nine months ended September 30, 2020. Depletion, depreciation and amortization expense for the third quarter of 2021 of $13.70 per BOE decreased 9% from $15.01 per BOE for the third quarter of 2020 and was comparable with $13.57 per BOE for the second quarter of 2021. The decrease in depletion, depreciation and amortization expense per BOE for the three and nine months ended September 30, 2021 from the comparable periods in 2020 primarily reflected lower depletion rates in the North America Exploration and Production segment.

ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION

						Three Months Ended																					Nine Months Ended
($ millions, except per BOE amounts)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
North America						$	26					$	25					$	23								$	76					$	73
North Sea						6						5						7									16						22
Offshore Africa						1						2						2									4						5
Expense						$	33					$	32					$	32								$	96					$	100
$/BOE (1)						$	0.45					$	0.46					$	0.47								$	0.45					$	0.50

(1)Amounts expressed on a per unit basis are based on 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.

Canadian Natural Resources Limited			18			Three and nine months ended September 30, 2021

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Asset retirement obligation accretion expense for the nine months ended September 30, 2021 of $0.45 per BOE decreased 10% from $0.50 per BOE for the nine months ended September 30, 2020. Asset retirement obligation accretion expense for the third quarter of 2021 of $0.45 per BOE decreased 4% from $0.47 per BOE for the third quarter of 2020 and was comparable with $0.46 per BOE for the second quarter of 2021. Fluctuations in asset retirement obligation accretion expense on a per BOE basis primarily reflect fluctuating sales volumes.

OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING

The Company continues to focus on safe, reliable and efficient operations and leveraging its technical expertise across the Horizon and AOSP sites. SCO production in the third quarter of 2021 of 468,126 bbl/d primarily reflected the completion of expansion activities at Scotford in the prior year and the completion of planned turnaround activities in the second quarter of 2021.

The Company incurred production costs, excluding natural gas costs, of $802 million ($18.63 per bbl) for the third quarter of 2021, a 22% decrease per bbl from the second quarter of 2021.

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

						Three Months Ended																					Nine Months Ended
($/bbl) (1)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
SCO realized sales price (2)						$	81.54					$	76.19					$	48.92								$	74.00					$	42.40
Bitumen value for royalty purposes (3)						$	62.28					$	58.46					$	36.26								$	55.54					$	22.77
Bitumen royalties (4)						$	8.21					$	5.92					$	0.46								$	5.67					$	0.49
Transportation						$	1.14					$	1.26					$	1.30								$	1.16					$	1.17

(1)Amounts expressed on a per unit basis are based on sales volumes.

(2)Net of blending and feedstock costs.

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

(4)Calculated based on bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes.

The realized SCO sales price averaged $74.00 per bbl for the nine months ended September 30, 2021, an increase of 75% from $42.40 per bbl for the nine months ended September 30, 2020. The realized SCO sales price averaged $81.54 per bbl for the third quarter of 2021, an increase of 67% from $48.92 per bbl for the third quarter of 2020 and an increase of 7% from $76.19 per bbl for the second quarter of 2021. The increase in the realized SCO sales price for the three and nine months ended September 30, 2021 from the comparable periods primarily reflected increases in WTI benchmark pricing.

The increase in bitumen royalties per bbl for the three and nine months ended September 30, 2021 from the comparable periods primarily reflected the impact of higher prevailing bitumen pricing and AOSP reaching full payout.

Transportation expense averaged $1.16 per bbl for the nine months ended September 30, 2021, comparable with $1.17 per bbl for the nine months ended September 30, 2020. For the third quarter of 2021, transportation expense of $1.14 per bbl decreased 12% from $1.30 per bbl for the third quarter of 2020 and decreased 10% from $1.26 per bbl for the second quarter of 2021. The decrease in transportation expense per bbl for the third quarter of 2021 from the comparable periods primarily reflected the impact of higher sales volumes during the third quarter of 2021.

PRODUCTION COSTS – OIL SANDS MINING AND UPGRADING

The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 17 to the Company’s unaudited interim consolidated financial statements.

						Three Months Ended																					Nine Months Ended
($ millions)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Production costs, excluding natural gas costs						$	802					$	799					$	760								$	2,380					$	2,232
Natural gas costs						53						51						28									163						95
Production costs						$	855					$	850					$	788								$	2,543					$	2,327

Canadian Natural Resources Limited			19			Three and nine months ended September 30, 2021

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						Three Months Ended																					Nine Months Ended
($/bbl) (1)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Production costs, excluding natural gas costs						$	18.63					$	23.94					$	22.96								$	20.05					$	19.71
Natural gas costs						1.23						1.52						0.85									1.37						0.84
Production costs						$	19.86					$	25.46					$	23.81								$	21.42					$	20.55
Sales (bbl/d)						467,772						366,843						359,479									434,848						413,157

(1)Amounts expressed on a per unit basis are based on sales volumes.

Production costs for the nine months ended September 30, 2021 increased 4% to $21.42 per bbl from $20.55 per bbl for the nine months ended September 30, 2020. Production costs for the third quarter of 2021 averaged $19.86 per bbl, a decrease of 17% from $23.81 per bbl for the third quarter of 2020 and a decrease of 22% from $25.46 per bbl for the second quarter of 2021. The increase in production costs per bbl for the nine months ended September 30, 2021 from the comparable period in 2020 primarily reflected the impact of higher energy costs, including natural gas and diesel. The decrease in production costs per bbl for the third quarter of 2021 from the comparable periods primarily reflected the timing of planned turnaround activities. The Company continued to focus on cost control and efficiencies across the entire asset base.

DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING

						Three Months Ended																					Nine Months Ended
($ millions, except per bbl amounts)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Expense						$	469					$	441					$	414								$	1,360					$	1,305
$/bbl (1)						$	10.90					$	13.20					$	12.51								$	11.45					$	11.53

(1) Amounts expressed on a per unit basis are based on sales volumes.

Depletion, depreciation and amortization expense for the nine months ended September 30, 2021 of $11.45 per bbl was comparable with $11.53 per bbl for the nine months ended September 30, 2020. Depletion, depreciation and amortization expense for the third quarter of 2021 of $10.90 per bbl decreased 13% from $12.51 per bbl for the third quarter of 2020, and decreased 17% from $13.20 per bbl for the second quarter of 2021. The decrease in depletion, depreciation and amortization on a per barrel basis for the third quarter of 2021 from the comparable periods primarily reflected the impact of higher sales volumes in the third quarter of 2021 and minor asset derecognitions in the comparable periods.

ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING

						Three Months Ended																					Nine Months Ended
($ millions, except per bbl amounts)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Expense						$	14					$	14					$	19								$	43					$	54
$/bbl (1)						$	0.33					$	0.43					$	0.55								$	0.36					$	0.47

(1)Amounts expressed on a per unit basis are based on sales volumes.

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

Asset retirement obligation accretion expense for the nine months ended September 30, 2021 of $0.36 per bbl decreased 23% from $0.47 per bbl for the nine months ended September 30, 2020. Asset retirement obligation accretion expense of $0.33 per bbl for the third quarter of 2021 decreased 40% from $0.55 per bbl for the third quarter of 2020 and decreased 23% from $0.43 per bbl for the second quarter of 2021. Fluctuations in asset retirement obligation accretion expense on a per barrel basis primarily reflect fluctuating sales volumes.

Canadian Natural Resources Limited			20			Three and nine months ended September 30, 2021

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MIDSTREAM AND REFINING

						Three Months Ended																					Nine Months Ended
($ millions)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Product sales
Midstream activities						$	21					$	21					$	21								$	61					$	62
NWRP, refined product sales and other						179						171						78									481						103
Segmented revenue						200						192						99									542						165
Less:
NWRP, refining toll						46						72						70									176						94
Midstream activities						4						7						4									16						15
Production expense						50						79						74									192						109
NWRP, transportation and feedstock costs						146						134						76									385						98
Depreciation						4						3						4									11						11
Income from NWRP						—						(400)						—									(400)						—
Segmented earnings (loss) before taxes						$	—					$	376					$	(55)								$	354					$	(53)

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 barrels per day bitumen upgrader and refinery that processes approximately 12,500 barrels per day (25% toll payer) of bitumen feedstock for the Company and 37,500 barrels per day (75% toll payer) of bitumen feedstock for the Alberta Petroleum Marketing Commission ("APMC"), an agent of the Government of Alberta. Sales of diesel and refined products and associated refining tolls are recognized in the Midstream and Refining segment. For the third quarter of 2021, production of ultra-low sulphur diesel and other refined products averaged 77,387 BOE/d (19,347 BOE/d to the Company), (three months ended September 30, 2020 – 52,678 BOE/d; 13,169 BOE/d to the Company), reflecting the 25% toll payer commitment.

On June 30, 2021, the equity partners together with the toll payers, agreed to optimize the structure of NWRP to better align the commercial interests of the equity partners and the toll payers (the "Optimization Transaction"). As a result, North West Refining Inc. transferred its entire 50% partnership interest in NWRP to APMC. The Company's 50% equity interest remained unchanged.

Under the Optimization Transaction, the original term of the processing agreements was extended by 10 years from 2048 to 2058. NWRP retired higher cost subordinated debt, which carried interest rates of prime plus 6%, with lower cost senior secured bonds at an average rate of approximately 2.55%, reducing interest costs to NWRP and associated tolls to the toll payers. As such, NWRP repaid the Company's and APMC's subordinated debt advances of $555 million each. In addition, the Company received a $400 million distribution from NWRP during the second quarter of 2021.

As at September 30, 2021, the cumulative unrecognized share of the equity loss from NWRP of $150 million and total partnership distributions in excess of the cumulative share of equity loss, was $550 million (December 31, 2020 – $153 million; September 30, 2020 – $159 million). For the three months ended September 30, 2021, unrecognized equity loss was $21 million, (nine months ended September 30, 2021 – unrecognized equity income of $3 million; three months ended September 30, 2020 – unrecognized equity income of $16 million; nine months ended September 30, 2020 – unrecognized equity loss of $100 million).

Canadian Natural Resources Limited			21			Three and nine months ended September 30, 2021

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ADMINISTRATION EXPENSE

						Three Months Ended																					Nine Months Ended
($ millions, except per BOE amounts)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Expense						$	87					$	87					$	88								$	269					$	284
$/BOE (1)						$	0.77					$	0.84					$	0.85								$	0.82					$	0.90

(1)Amounts expressed on a per unit basis are based on sales volumes.

Administration expense for the nine months ended September 30, 2021 of $0.82 per BOE decreased 9% from $0.90 per BOE for the nine months ended September 30, 2020. Administration expense for the third quarter of 2021 of $0.77 per BOE decreased 9% from $0.85 per BOE for the third quarter of 2020 and decreased 8% from $0.84 per BOE for the second quarter of 2021. Administration expense per BOE decreased for the three and nine months ended September 30, 2021 from the comparable periods primarily due to higher sales volumes. The decrease in administration expense per BOE for the nine months ended September 30, 2021 from the comparable period also reflected higher overhead recoveries.

SHARE-BASED COMPENSATION

						Three Months Ended																					Nine Months Ended
($ millions)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Expense (recovery)						$	57					$	137					$	(5)								$	323					$	(205)

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 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 $323 million share-based compensation expense for the nine months ended September 30, 2021, 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. Included within the share-based compensation expense for the nine months ended September 30, 2021 was an expense of $46 million related to PSUs granted to certain executive employees (September 30, 2020 – $4 million recovery).

INTEREST AND OTHER FINANCING EXPENSE

						Three Months Ended																					Nine Months Ended
($ millions, except per BOE amounts and interest rates)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Expense, gross						$	178					$	177					$	180								$	540					$	600
Less: capitalized interest						—						—						6									—						21
Expense, net						$	178					$	177					$	174								$	540					$	579
$/BOE (1)						$	1.56					$	1.73					$	1.69								$	1.64					$	1.84
Average effective interest rate						3.6%						3.5%						3.4%									3.5%						3.6%

(1)Amounts expressed on a per unit basis are based on sales volumes.

Net interest and other financing expense per BOE for the nine months ended September 30, 2021 decreased 11% to $1.64 per BOE from $1.84 per BOE for the nine months ended September 30, 2020. Net interest and other financing expense per BOE for the third quarter of 2021 decreased 8% to $1.56 per BOE from $1.69 per BOE for the third quarter of 2020 and decreased 10% from $1.73 per BOE for the second quarter of 2021. The decrease in interest expense and other financing expense per BOE for the three and nine months ended September 30, 2021 from the comparable periods was primarily due to lower average debt levels in 2021, partially offset by lower interest income.

The Company's average effective interest rate for the third quarter of 2021 was comparable with the second quarter of 2021.

Canadian Natural Resources Limited			22			Three and nine months ended September 30, 2021

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RISK MANAGEMENT ACTIVITIES

The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These derivative financial instruments are not intended for trading or speculative purposes.

						Three Months Ended																					Nine Months Ended
($ millions)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Foreign currency contracts						$	(18)					$	15					$	20								$	12					$	(9)
Natural gas financial instruments						14						3						5									11						18
Net realized (gain) loss						(4)						18						25									23						9
Foreign currency contracts						(1)						(4)						—									(10)						(9)
Natural gas financial instruments						(18)						14						(2)									21						(9)
Net unrealized (gain) loss						(19)						10						(2)									11						(18)
Net (gain) loss						$	(23)					$	28					$	23								$	34					$	(9)

During the nine months ended September 30, 2021, net realized risk management losses were related to the settlement of foreign currency contracts and natural gas financial instruments. The Company recorded a net unrealized loss of $11 million ($6 million after-tax) on its risk management activities for the nine months ended September 30, 2021, including an unrealized gain of $19 million ($15 million after-tax) for the third quarter of 2021 (June 30, 2021 – unrealized loss of $10 million, $6 million after-tax; September 30, 2020 – unrealized gain of $2 million, $1 million after-tax).

Further details related to outstanding derivative financial instruments at September 30, 2021 are disclosed in note 15 to the Company's unaudited interim consolidated financial statements.

FOREIGN EXCHANGE

						Three Months Ended																					Nine Months Ended
($ millions)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Net realized loss (gain)						$	84					$	11					$	16								$	105					$	(180)
Net unrealized loss (gain)						197						(151)						(270)									(126)						418
Net loss (gain) (1)						$	281					$	(140)					$	(254)								$	(21)					$	238

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

The net realized foreign exchange loss for the nine months ended September 30, 2021 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling and the repayment of US$500 million of 3.45% debt securities. The net unrealized foreign exchange gain for the nine months ended September 30, 2021 was primarily related to the impact of the reversal of the net unrealized foreign exchange loss on the repayment of US$500 million of 3.45% debt securities. The US/Canadian dollar exchange rate at September 30, 2021 was US$0.7843 (June 30, 2021 – US$0.8062, September 30, 2020 – US$0.7505).

Canadian Natural Resources Limited			23			Three and nine months ended September 30, 2021

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INCOME TAXES

						Three Months Ended																					Nine Months Ended
($ millions, except income tax rates)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
North America (1)						$	541					$	324					$	(59)								$	1,150					$	(287)
North Sea						4						(5)						(14)									10						(4)
Offshore Africa						7						7						6									18						12
PRT (2) – North Sea						(5)						(12)						(17)									(22)						(17)
Other taxes						4						3						2									9						4
Current income tax expense (recovery)						551						317						(82)									1,165						(292)
Deferred income tax expense (recovery)						56						129						91									206						(156)
						$	607					$	446					$	9								$	1,371					$	(448)
Effective income tax rate on adjusted net earnings (loss) from operations (3)						22%						24%						15%									22%						32%

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

(2)Petroleum Revenue Tax.

(3)Excludes the impact of current and deferred PRT and other current income tax.

The effective income tax rate for the three and nine months ended September 30, 2021 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 (loss).

The current corporate income tax and PRT in the North Sea for the three and nine months ended September 30, 2021 and the prior periods included the impact of carrybacks of abandonment expenditures related to decommissioning activities at the Company's platforms in the North Sea.

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.

Canadian Natural Resources Limited			24			Three and nine months ended September 30, 2021

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NET CAPITAL EXPENDITURES (1)

						Three Months Ended																					Nine Months Ended
($ millions)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Exploration and Evaluation
Net property dispositions						$	(1)					$	(4)					$	(12)								$	(5)					$	(30)
Net expenditures						5						1						1									10						27
Total Exploration and Evaluation						4						(3)						(11)									5						(3)
Property, Plant and Equipment
Net property acquisitions						131						7						(1)									139						14
Well drilling, completion and equipping						232						224						80									722						314
Production and related facilities						244						186						157									622						449
Other						12						16						14									41						40
Total Property, Plant and Equipment						619						433						250									1,524						817
Total Exploration and Production						623						430						239									1,529						814
Oil Sands Mining and Upgrading
Project costs						69						61						67									171						172
Sustaining capital						233						346						254									765						627
Turnaround costs						19						74						131									122						174
Other (2)						3						326						8									330						26
Total Oil Sands Mining and Upgrading						324						807						460									1,388						999
Midstream and Refining						3						1						1									6						4
Abandonments (3)						54						44						68									165						197
Head office						7						3						3									16						16
Total net capital expenditures						$	1,011					$	1,285					$	771								$	3,104					$	2,030
By segment
North America						$	564					$	378					$	170								$	1,361					$	660
North Sea						49						44						45									125						88
Offshore Africa						10						8						24									43						66
Oil Sands Mining and Upgrading						324						807						460									1,388						999
Midstream and Refining						3						1						1									6						4
Abandonments (3)						54						44						68									165						197
Head office						7						3						3									16						16
Total						$	1,011					$	1,285					$	771								$	3,104					$	2,030

(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)Includes the acquisition of a 5% net carried interest on an existing oil sands lease in the second quarter of 2021.

(3)Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table and are net of the impact of government grant income under the provincial well-site rehabilitation programs.

Canadian Natural Resources Limited			25			Three and nine months ended September 30, 2021

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Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities
						Three Months Ended																					Nine Months Ended
($ millions)						Sep 30 2021						Jun 30 2021						Sep 30 2020									Sep 30 2021						Sep 30 2020
Cash flows used in investing activities						$	721					$	719					$	643								$	2,088					$	2,195
Net change in non-cash working capital						108						(33)						60									168						(362)
Proceeds from investment						128						—						—									128						—
Repayment of NWRP subordinated debt advances						—						555						—									555						—
Abandonment expenditures (1)						54						44						68									165						197
Net capital expenditures						$	1,011					$	1,285					$	771								$	3,104					$	2,030

(1)The Company excludes abandonment expenditures from "Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities" in the "Financial Highlights" section of this MD&A and are net of the impact of government grant income under the provincial well-site rehabilitation programs.

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

Net capital expenditures for the nine months ended September 30, 2021 were $3,104 million compared with $2,030 million for the nine months ended September 30, 2020. Net capital expenditures for the third quarter of 2021 were $1,011 million compared with $771 million for the third quarter of 2020 and $1,285 million for the second quarter of 2021.

During the nine months ended September 30, 2021, the Company has completed three opportunistic acquisitions. The first two acquisitions consisted of natural gas assets located in the Montney region of British Columbia, with aggregate production of approximately 11,100 BOE/d, consisting of 63 MMcf/d and 600 bbl/d of NGLs, approximately 107,000 acres of Montney lands, and related processing infrastructure with approximately 140 MMcf/d of capacity. These two acquisitions build on the Company’s expansive natural gas operations in northeastern British Columbia, increasing the Company's total Montney lands to approximately 1.3 million acres. The third acquisition consisted of a net carried interest on an existing Canadian Natural oil sands lease, from which all of the Company's current Horizon volumes are derived. Total cash consideration paid for these acquisitions was approximately $450 million.

2021 Capital Budget

On December 9, 2020, the Company announced its 2021 capital budget targeted at approximately $3,205 million, of which $1,345 million was related to conventional and unconventional assets and $1,860 million was allocated to long-life low decline assets. On August 5, 2021, the 2021 capital budget was increased by $275 million to $3,480 million, excluding acquisitions. The increase included $120 million for conventional and unconventional assets, $110 million for long-life low decline assets, and $45 million for additional well abandonment activities.

The 2021 capital budget constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.

Canadian Natural Resources Limited			26			Three and nine months ended September 30, 2021

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Drilling Activity (1)

						Three Months Ended																		Nine Months Ended
(number of net wells)						Sep 30 2021						Jun 30 2021						Sep 30 2020						Sep 30 2021						Sep 30 2020
Net successful natural gas wells						9						9						9						40						21
Net successful crude oil wells (2)						56						27						—						127						37
Dry wells						1						—						—						1						—
Stratigraphic test / service wells						7						1						1						336						372
Total						73						37						10						504						430
Success rate (excluding stratigraphic test / service wells)						98%						100%						100%						99%						100%

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

(2)Includes bitumen wells.

North America

During the third quarter of 2021, the Company targeted 9 net natural gas wells, 49 net primary heavy crude oil wells, and 6 net light crude oil wells.

North Sea

During the third quarter of 2021, the Company targeted 1.9 net light crude oil wells in the North Sea.

LIQUIDITY AND CAPITAL RESOURCES

($ millions, except ratios)						Sep 30 2021						Jun 30 2021						Dec 31 2020						Sep 30 2020
Working capital (1)						$	423					$	723					$	626					$	707
Long-term debt (2) (3)						$	16,774					$	18,331					$	21,453					$	21,876
Less: cash and cash equivalents						894						168						184						175
Long-term debt, net						$	15,880					$	18,163					$	21,269					$	21,701
Share capital						$	9,857					$	9,863					$	9,606					$	9,522
Retained earnings						25,632						24,390						22,766						22,520
Accumulated other comprehensive income (loss)						37						(46)						8						124
Shareholders’ equity						$	35,526					$	34,207					$	32,380					$	32,166
Debt to book capitalization (3) (4)						30.9%						34.7%						39.6%						40.3%
Debt to market capitalization (3) (5)						22.5%						25.4%						37.0%						46.3%
After-tax return on average common shareholders’ equity (6)						17.5%						12.4%						(1.3)%						(1.8)%
After-tax return on average capital employed (3) (7)						12.1%						8.6%						0.2%						0.0%

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

(2)Includes the current portion of long-term debt.

(3)Long-term debt is stated at its carrying value, net of original issue discounts and premiums and transaction costs.

(4)Calculated as net current and long-term debt; divided by the book value of common shareholders’ equity plus net current and long-term debt.

(5)Calculated as net current and long-term debt; divided by the market value of common shareholders’ equity plus net current and long-term debt.

(6)Calculated as net earnings (loss) for the twelve month trailing period; as a percentage of average common shareholders’ equity for the twelve month trailing period.

(7)Calculated as net earnings (loss) 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.

Canadian Natural Resources Limited			27			Three and nine months ended September 30, 2021

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As at September 30, 2021, 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, 2020. 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 the implementation of its ongoing hedge policy, the flexibility of its capital expenditure programs and multi-year financial plans, its existing bank credit facilities, and its ability to raise new debt on commercially acceptable terms will provide sufficient liquidity to sustain its operations in the short, medium and long-term and support its growth strategy.

On an ongoing basis the Company continues to focus on its balance sheet strength and available liquidity by:

▪Monitoring cash flows from operating activities, which is the primary source of funds;

▪Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place, and as applicable, taking other mitigating actions to minimize the impact in the event of a default;

▪Actively managing the allocation of maintenance and growth capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. The Company continues to exercise its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments and long-term debt;

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

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

▪Reviewing the Company's borrowing capacity:

◦During the first quarter of 2021, the $1,000 million non-revolving term credit facility, originally due February 2022, was extended to February 2023.

◦During the third quarter of 2021, the Company repaid $500 million of the $2,650 million non-revolving term credit facility, reducing the outstanding balance to $2,150 million. Subsequent to September 30, 2021, the Company repaid an additional $1,000 million on the facility, reducing the outstanding balance to $1,150 million.

◦During 2019, the Company entered into a $3,250 million non-revolving term credit facility with an original maturity of June 2022, to finance the acquisition of assets from Devon Canada Corporation. During the second quarter of 2021, the outstanding balance of $2,125 million was repaid and the facility was cancelled.

◦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, replacing the Company's previous base shelf prospectus, which would have expired in August 2021. 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, replacing the Company's previous base shelf prospectus, which would have expired in August 2021. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.

◦During the third quarter of 2021, the Company early repaid US$500 million of 3.45% debt securities, originally due November 2021.

◦Borrowings under the Company's non-revolving term credit facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers’ acceptances, LIBOR, US base rate or Canadian prime rate. As at September 30, 2021, the non-revolving term credit facilities were fully drawn.

◦Each of the $2,425 million revolving credit facilities is extendible annually at the mutual agreement of the Company and the lenders. If the facilities are not extended, the full amount of the outstanding principal is repayable on the maturity date. Borrowings under the Company's revolving term credit facilities may be made by way of pricing referenced to Canadian dollar bankers' acceptances, US dollar bankers' acceptances, LIBOR, US base rate or Canadian prime rate.

Canadian Natural Resources Limited			28			Three and nine months ended September 30, 2021

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◦The Company's borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million. The Company reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.

As at September 30, 2021, the Company had undrawn revolving bank credit facilities of $4,959 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,159 million in liquidity. Additionally, the Company had in place fully drawn term credit facilities of $3,150 million. The Company also has certain other dedicated credit facilities supporting letters of credit.

As at September 30, 2021, the Company had total US dollar denominated debt with a carrying amount of $13,444 million (US$10,545 million), before transaction costs and original issue discounts. This included $3,627 million (US$2,845 million) hedged by way of a cross currency swap (US$550 million) and foreign currency forwards (US$2,295 million). The fixed repayment amount of these hedging instruments is $3,560 million, resulting in a notional reduction of the carrying amount of the Company’s US dollar denominated debt by approximately $67 million to $13,377 million as at September 30, 2021.

Net long-term debt was $15,880 million at September 30, 2021, resulting in a debt to book capitalization ratio of 30.9% (December 31, 2020 – 39.6%); this ratio is within 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 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 at September 30, 2021 are discussed in note 8 of the Company's unaudited interim consolidated 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 September 30, 2021, 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 at September 30, 2021 are discussed in note 15 of the Company’s unaudited interim consolidated financial statements.

As at September 30, 2021, the maturity dates of long-term debt and other long-term liabilities and related interest payments were as follows:

			Less than 1 year						1 to less than 2 years						2 to less than 5 years						Thereafter
Long-term debt (1)			$	1,000					$	4,419					$	3,167					$	8,276
Other long-term liabilities (2)			$	231					$	180					$	431					$	851
Interest and other financing expense (3)			$	676					$	606					$	1,511					$	4,090

(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, $186 million; one to less than two years, $147 million; two to less than five years, $422 million; and thereafter, $851 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 September 30, 2021.

Share Capital

As at September 30, 2021, there were 1,175,701,000 common shares outstanding (December 31, 2020 – 1,183,866,000 common shares) and 47,780,000 stock options outstanding. As at November 2, 2021, the Company had 1,176,819,000 common shares outstanding and 42,625,000 stock options outstanding.

On November 3, 2021, the Board of Directors approved an increase in the quarterly dividend to $0.5875 per common share, a 25% increase from the previous quarterly dividend, beginning with the dividend payable on January 5, 2022. On March 3, 2021, the Board of Directors approved an increase in the quarterly dividend to $0.47 per common share (previous quarterly dividend rate of $0.425 per common share). The dividend policy undergoes periodic review by the Board of Directors and is subject to change.

On March 9, 2021, 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 59,278,474 common shares, over a 12-month period commencing March 11, 2021 and ending March 10, 2022.

Canadian Natural Resources Limited			29			Three and nine months ended September 30, 2021

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For the nine months ended September 30, 2021, the Company purchased 17,624,400 common shares at a weighted average price of $42.14 per common share for a total cost of $743 million. Retained earnings were reduced by $597 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to September 30, 2021, the Company purchased 3,840,000 common shares at a weighted average price of $51.22 per common share for a total cost of $197 million.

COMMITMENTS AND CONTINGENCIES

In the normal course of business, the Company has committed to certain payments. The following table summarizes the Company's commitments as at September 30, 2021:

($ millions)			Remaining 2021						2022						2023						2024						2025						Thereafter
Product transportation and processing (1)			$	221					$	851					$	934					$	853					$	820					$	10,478
North West Redwater Partnership service toll (2)			$	31					$	123					$	123					$	121					$	119					$	3,760
Offshore vessels and equipment			$	19					$	42					$	—					$	—					$	—					$	—
Field equipment and power			$	9					$	21					$	21					$	21					$	21					$	246
Other			$	7					$	21					$	20					$	21					$	21					$	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 $1,499 million of interest payable over the 40-year tolling period.

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.

ACCOUNTING POLICIES

Regulatory Developments

On May 27, 2021, the Canadian Securities Administrators (CSA) announced the adoption of National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure ("NI 52-112") and related amendments. This National Instrument replaces the previous CSA staff notice on Non-GAAP Measures. NI 52-112 governs how entities present non-GAAP and other financial measures and ratios. The requirements will apply to the Company's MD&A and certain other disclosure documents for the three months and year ended December 31, 2021. The Company is in the process of assessing required changes to the MD&A and certain other disclosure documents.

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. For the three and nine months ended September 30, 2021, COVID-19 continued to have an impact on the global economy, including the oil and gas industry. Business conditions in the third quarter of 2021 continued to reflect the market uncertainty associated with COVID-19, with some improvements to global crude oil demand and supply conditions. The Company has taken into account the impacts of COVID-19 and the unique circumstances it has created in making estimates, assumptions, and judgements in the preparation of the unaudited interim consolidated financial statements, and continues to monitor the developments in the business environment and commodity market. 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, 2020.

Canadian Natural Resources Limited			30			Three and nine months ended September 30, 2021

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CONTROL ENVIRONMENT

There have been no changes to internal control over financial reporting ("ICFR") during the nine months ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect the Company’s ICFR. 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			31			Three and nine months ended September 30, 2021