EX-99.2 3 a06302021q2mda.htm EX-99.2

Canadian Natural Resources Limited

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE AND SIX MONTHS ENDED JUNE 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, the disposition of shares of Inter Pipeline Ltd. ("IPL") to a third-party provided that all conditions of the third-party offer are satisfied, 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"), 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; the continued availability of the Canada Emergency Wage Subsidy ("CEWS") or other subsidies; and other circumstances affecting revenues and expenses.

Canadian Natural Resources Limited			1			Three and six months ended June 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 (used in) 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 (used in) 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 six months ended June 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 six months ended June 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 six months ended June 30, 2021 in relation to the comparable periods in 2020 and the first 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 August 4, 2021.

Canadian Natural Resources Limited			2			Three and six months ended June 30, 2021

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FINANCIAL HIGHLIGHTS

												Three Months Ended																					Six Months Ended
($ millions, except per common share amounts)												Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Product sales (1)												$	7,124					$	7,019					$	2,944								$	14,143					$	7,596
Crude oil and NGLs												$	6,382					$	6,288					$	2,462								$	12,670					$	6,785
Natural gas												$	509					$	555					$	307								$	1,064					$	644
Net earnings (loss)												$	1,551					$	1,377					$	(310)								$	2,928					$	(1,592)
Per common share						– basic						$	1.31					$	1.16					$	(0.26)								$	2.47					$	(1.35)
						– diluted						$	1.30					$	1.16					$	(0.26)								$	2.46					$	(1.35)
Adjusted net earnings (loss) from operations (2)												$	1,480					$	1,219					$	(772)								$	2,699					$	(1,067)
Per common share						– basic						$	1.25					$	1.03					$	(0.65)								$	2.28					$	(0.90)
						– diluted						$	1.24					$	1.03					$	(0.65)								$	2.27					$	(0.90)
Cash flows from (used in) operating activities												$	2,940					$	2,536					$	(351)								$	5,476					$	1,374
Adjusted funds flow (3)												$	3,049					$	2,712					$	415								$	5,761					$	1,752
Per common share						– basic						$	2.57					$	2.29					$	0.35								$	4.86					$	1.48
						– diluted						$	2.56					$	2.28					$	0.35								$	4.85					$	1.48
Cash flows used in investing activities												$	719					$	648					$	693								$	1,367					$	1,552
Net capital expenditures (4)												$	1,285					$	808					$	421								$	2,093					$	1,259

(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 (used in) 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 (used in) 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 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 six months ended June 30, 2021

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Adjusted Net Earnings (Loss) from Operations, as Reconciled to Net Earnings (Loss)
						Three Months Ended																					Six Months Ended
($ millions)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Net earnings (loss)						$	1,551					$	1,377					$	(310)								$	2,928					$	(1,592)
Share-based compensation, net of tax (1)						132						126						23									258						(198)
Unrealized risk management loss (gain), net of tax (2)						6						15						1									21						(14)
Unrealized foreign exchange (gain) loss, net of tax (3)						(151)						(172)						(433)									(323)						688
Realized foreign exchange gain on settlement of cross currency swaps, net of tax (4)						—						—						—									—						(166)
(Gain) loss from investments, net of tax (5)						(47)						(117)						(53)									(164)						215
Other, net of tax (6)						(11)						(10)						—									(21)						—
Adjusted net earnings (loss) from operations						$	1,480					$	1,219					$	(772)								$	2,699					$	(1,067)

(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) or are charged to (recovered from) the Oil Sands Mining and Upgrading segment.

(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 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.

(5)The Company’s investments in PrairieSky Royalty Ltd. ("PrairieSky") and IPL have been accounted for at fair value through profit and loss and are measured each period with changes in fair value recognized in net earnings (loss).

(6)"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 (used in) Operating Activities
						Three Months Ended																					Six Months Ended
($ millions)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Cash flows from (used in) operating activities						$	2,940					$	2,536					$	(351)								$	5,476					$	1,374
Net change in non-cash working capital						137						10						739									147						144
Abandonment expenditures (1)						44						67						40									111						129
Other (2)						(72)						99						(13)									27						105
Adjusted funds flow						$	3,049					$	2,712					$	415								$	5,761					$	1,752

(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 six months ended June 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 six months ended June 30, 2021 were $2,928 million compared with a net loss of $1,592 million for the six months ended June 30, 2020. Net earnings for the six months ended June 30, 2021 included net after-tax income of $229 million compared with net after-tax expenses of $525 million for the six months ended June 30, 2020 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the foreign exchange gain on the settlement of the cross currency swaps, the (gain) loss from investments, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the six months ended June 30, 2021 were $2,699 million compared with an adjusted net loss from operations of $1,067 million for the six months ended June 30, 2020.

Net earnings for the second quarter of 2021 were $1,551 million compared with a net loss of $310 million for the second quarter of 2020 and net earnings of $1,377 million for the first quarter of 2021. Net earnings for the second quarter of 2021 included net after-tax income of $71 million compared with net after-tax income of $462 million for the second quarter of 2020 and net after-tax income of $158 million for the first quarter of 2021 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the gain from investments, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the second quarter of 2021 were $1,480 million compared with an adjusted net loss from operations of $772 million for the second quarter of 2020 and adjusted net earnings from operations of $1,219 million for the first quarter of 2021.

Net earnings and adjusted net earnings from operations for the three and six months ended June 30, 2021 compared with a net loss and adjusted net loss from operations for the three and six months ended June 30, 2020 primarily reflected:

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

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

▪higher realized prices in the Oil Sands Mining and Upgrading segment, partially offset by lower sales volumes.

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

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

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

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

partially offset by:

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

▪lower natural gas netbacks in the North America segment.

The impacts of share-based compensation, risk management activities, fluctuations in foreign exchange rates, income from NWRP, and (gain) loss 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 six months ended June 30, 2021

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Cash Flows from (used in) Operating Activities and Adjusted Funds Flow

Cash flows from operating activities for the six months ended June 30, 2021 were $5,476 million compared with $1,374 million for the six months ended June 30, 2020. Cash flows from operating activities for the second quarter of 2021 were $2,940 million compared with cash flows used in operating activities of $351 million for the second quarter of 2020 and cash flows from operating activities of $2,536 million for the first quarter of 2021. The fluctuations in cash flows from (used in) operating activities from the comparable periods were primarily due to the factors previously noted relating 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 six months ended June 30, 2021 was $5,761 million compared with $1,752 million for the six months ended June 30, 2020. Adjusted funds flow for the second quarter of 2021 was $3,049 million compared with $415 million for the second quarter of 2020 and $2,712 million for the first quarter of 2021. The fluctuations in adjusted funds flow from the comparable periods were primarily due to the factors noted above relating to the fluctuations in cash flows from (used in) 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

Total production of crude oil and NGLs before royalties for the second quarter of 2021 decreased 5% to 872,718 bbl/d, from 921,895 bbl/d for the second quarter of 2020 and decreased 11% from 979,352 bbl/d for the first quarter of 2021. Total natural gas production before royalties for the second quarter of 2021 increased 10% to 1,614 MMcf/d from 1,462 MMcf/d for the second quarter of 2020 and was comparable with 1,598 MMcf/d for the first quarter of 2021. Total production before royalties for the second quarter of 2021 of 1,141,739 BOE/d was comparable with 1,165,487 BOE/d for the second quarter of 2020 and decreased 8% from 1,245,703 BOE/d for the first 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 $61.20 per bbl in the second quarter of 2021, an increase of 223% compared with $18.97 per bbl for the second quarter of 2020, and an increase of 16% from $52.68 per bbl for the first quarter of 2021. The natural gas realized price increased 56% to average $3.17 per Mcf for the second quarter of 2021 from $2.03 per Mcf for the second quarter of 2020, and decreased 7% from $3.42 per Mcf for the first quarter of 2021. In the Oil Sands Mining and Upgrading segment, the Company's SCO realized price increased 162% to average $76.19 per bbl for the second quarter of 2021 from $29.11 per bbl for the second quarter of 2020, and increased 18% from $64.60 per bbl for the first 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 $13.75 per bbl for the second quarter of 2021, an increase of 10% from $12.53 per bbl for the second quarter of 2020, and a decrease of 6% from $14.56 per bbl for the first quarter of 2021. Natural gas production expense averaged $1.19 per Mcf for the second quarter of 2021, an increase of 3% from $1.15 per Mcf for the second quarter of 2020 and a decrease of 6% from $1.27 per Mcf for the first quarter of 2021. In the Oil Sands Mining and Upgrading segment, production costs averaged $25.46 per bbl for the second quarter of 2021, an increase of 44% from $17.74 per bbl for the second quarter of 2020, and an increase of 28% from $19.82 per bbl for the first 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 six months ended June 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)						Jun 30 2021						Mar 31 2021						Dec 31 2020						Sep 30 2020
Product sales (1)						$	7,124					$	7,019					$	5,219					$	4,676
Crude oil and NGLs						$	6,382					$	6,288					$	4,592					$	4,202
Natural gas						$	509					$	555					$	496					$	338
Net earnings (loss)						$	1,551					$	1,377					$	749					$	408
Net earnings (loss) per common share
– basic						$	1.31					$	1.16					$	0.63					$	0.35
– diluted						$	1.30					$	1.16					$	0.63					$	0.35
($ millions, except per common share amounts)						Jun 30 2020						Mar 31 2020						Dec 31 2019						Sep 30 2019
Product sales (1)						$	2,944					$	4,652					$	6,335					$	6,587
Crude oil and NGLs						$	2,462					$	4,323					$	5,947					$	6,324
Natural gas						$	307					$	337					$	382					$	257
Net earnings (loss)						$	(310)					$	(1,282)					$	597					$	1,027
Net earnings (loss) per common share
– basic						$	(0.26)					$	(1.08)					$	0.50					$	0.87
– diluted						$	(0.26)					$	(1.08)					$	0.50					$	0.87

(1)Further details related to product sales for the three months ended June 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 six months ended June 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 due to the cyclic nature of the Company’s Primrose thermal oil projects, production from the Kirby Thermal Oil Sands Project, the results from the Pelican Lake water and polymer flood 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 of the Pine River gas plant, and the impact and timing of acquisitions, including the acquisition in the fourth quarter of 2020.

▪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 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 acquisition, gains/losses on investments and income from NWRP – Fluctuations due to the recognition of a gain on the acquisition in the fourth quarter of 2020, fair value changes in 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 six months ended June 30, 2021

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BUSINESS ENVIRONMENT

Global benchmark crude oil prices increased significantly in the first half 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 become less impactful to the global economy. Economic conditions and the outlook for crude oil prices remain somewhat uncertain.

During the second 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 June 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 $5,596 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit. At June 30, 2021, the Company had $682 million drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.

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 is related to conventional and unconventional assets and $1,860 million is allocated to long-life low decline assets. Production for 2021 is now 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.

Year to date in 2021 to the end of July, 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, and the Company's 2021 capital budget will increase by this amount.

The Company owns approximately 6.4 million shares of IPL, which is currently subject to a third-party offer to purchase, of which the current value is approximately $130 million to the Company. Provided that all conditions of the third-party offer for IPL shares are satisfied, the Company targets to utilize these proceeds to further invest in value adding opportunities in the Company's vast asset base, and plans to increase its 2021 capital budget, excluding acquisitions, to approximately $3,480 million, including approximate additions of $120 million related to conventional and unconventional assets, $110 million related to long-life low decline assets, and an additional $45 million related to abandonment and reclamation activities. 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.

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 six months ended June 30, 2021

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Benchmark Commodity Prices

						Three Months Ended																					Six Months Ended
(Average for the period)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
WTI benchmark price (US$/bbl)						$	66.06					$	57.80					$	27.85								$	61.95					$	36.97
Dated Brent benchmark price (US$/bbl)						$	68.63					$	60.58					$	31.38								$	64.63					$	40.90
WCS Heavy Differential from WTI (US$/bbl)						$	11.47					$	12.42					$	11.53								$	11.95					$	16.00
SCO price (US$/bbl)						$	66.49					$	54.30					$	23.28								$	60.43					$	33.33
Condensate benchmark price (US$/bbl)						$	66.39					$	57.99					$	22.19								$	62.22					$	33.86
Condensate Differential from WTI (US$/bbl)						$	(0.33)					$	(0.19)					$	5.66								$	(0.27)					$	3.11
NYMEX benchmark price (US$/MMBtu)						$	2.83					$	2.69					$	1.72								$	2.76					$	1.84
AECO benchmark price (C$/GJ)						$	2.70					$	2.77					$	1.81								$	2.74					$	1.92
US/Canadian dollar average exchange rate (US$)						$	0.8143					$	0.7900					$	0.7218								$	0.8020					$	0.7324

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$61.95 per bbl for the six months ended June 30, 2021, an increase of 68% from US$36.97 per bbl for the six months ended June 30, 2020. WTI averaged US$66.06 per bbl for the second quarter of 2021, an increase of 137% from US$27.85 per bbl for the second quarter of 2020, and an increase of 14% from US$57.80 per bbl for the first 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$64.63 per bbl for the six months ended June 30, 2021, an increase of 58% from US$40.90 per bbl for the six months ended June 30, 2020. Brent averaged US$68.63 per bbl for the second quarter of 2021, an increase of 119% from US$31.38 per bbl for the second quarter of 2020, and an increase of 13% from US$60.58 per bbl for the first quarter of 2021.

The increase in WTI and Brent pricing for the three and six months ended June 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 second quarter of 2021 from the first quarter of 2021 primarily reflected continued recovery in global demand.

The WCS Heavy Differential averaged US$11.95 per bbl for the six months ended June 30, 2021, a narrowing of 25% from US$16.00 per bbl for the six months ended June 30, 2020. The WCS Heavy Differential averaged US$11.47 per bbl for the second quarter of 2021, comparable with US$11.53 per bbl for the second quarter of 2020, and a narrowing of 8% from US$12.42 per bbl for the first quarter of 2021. The narrowing of the WCS Heavy Differential for the three and six months ended June 30, 2021 from the comparable periods primarily reflected continued recovery in North American refining demand.

The SCO price averaged US$60.43 per bbl for the six months ended June 30, 2021, an increase of 81% from US$33.33 per bbl for the six months ended June 30, 2020. The SCO price averaged US$66.49 per bbl for the second quarter of 2021, an increase of 186% from US$23.28 per bbl for the second quarter of 2020, and an increase of 22% from US$54.30 per bbl for the first quarter of 2021. The increase in SCO pricing for the three and six months ended June 30, 2021 from the comparable periods primarily reflected increases in WTI benchmark pricing. The increase in SCO pricing for the second quarter of 2021 from the first quarter of 2021 also reflected reduced supply from the planned and unplanned turnarounds at various upgraders in Alberta during the second quarter of 2021.

Canadian Natural Resources Limited			10			Three and six months ended June 30, 2021

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NYMEX natural gas prices averaged US$2.76 per MMBtu for the six months ended June 30, 2021, an increase of 50% from US$1.84 per MMBtu for the six months ended June 30, 2020. NYMEX natural gas prices averaged US$2.83 per MMBtu for the second quarter of 2021, an increase of 65% from US$1.72 per MMBtu for the second quarter of 2020, and an increase of 5% from US$2.69 per MMBtu for the first quarter of 2021. The increase in NYMEX natural gas prices for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected increased North American demand in 2021 due to the impact of COVID-19 in 2020, as well as lower production levels. The increase in NYMEX natural gas prices for the second quarter of 2021 from the first quarter of 2021 primarily reflected increased Liquefied Natural Gas exports, together with low storage levels.

AECO natural gas prices averaged $2.74 per GJ for the six months ended June 30, 2021, an increase of 43% from $1.92 per GJ for the six months ended June 30, 2020. AECO natural gas prices averaged $2.70 per GJ for the second quarter of 2021, an increase of 49% from $1.81 per GJ for the second quarter of 2020, and comparable with $2.77 per GJ for the first quarter of 2021. The increase in AECO natural gas prices for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected lower storage levels and increased NYMEX benchmark pricing.

DAILY PRODUCTION, before royalties

			Three Months Ended									Six Months Ended
			Jun 30 2021			Mar 31 2021			Jun 30 2020			Jun 30 2021			Jun 30 2020
Crude oil and NGLs (bbl/d)
North America – Exploration and Production			478,314			478,736			413,506			478,524			435,191
North America – Oil Sands Mining and Upgrading (1)			361,707			468,803			464,318			414,959			451,210
North Sea			16,458			19,959			26,627			18,199			27,191
Offshore Africa			16,239			11,854			17,444			14,059			16,694
			872,718			979,352			921,895			925,741			930,286
Natural gas (MMcf/d)
North America			1,594			1,585			1,431			1,589			1,419
North Sea			4			4			15			4			19
Offshore Africa			16			9			16			13			13
			1,614			1,598			1,462			1,606			1,451
Total barrels of oil equivalent (BOE/d)			1,141,739			1,245,703			1,165,487			1,193,434			1,172,120
Product mix
Light and medium crude oil and NGLs			11%			10%			11%			11%			11%
Pelican Lake heavy crude oil			5%			4%			5%			5%			5%
Primary heavy crude oil			6%			5%			5%			5%			6%
Bitumen (thermal oil)			23%			22%			18%			22%			19%
Synthetic crude oil (1)			32%			38%			40%			35%			38%
Natural gas			23%			21%			21%			22%			21%
Percentage of gross revenue (1) (2)
(excluding Midstream and Refining revenue)
Crude oil and NGLs			92%			92%			89%			92%			91%
Natural gas			8%			8%			11%			8%			9%

(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 six months ended June 30, 2021

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DAILY PRODUCTION, net of royalties

			Three Months Ended									Six Months Ended
			Jun 30 2021			Mar 31 2021			Jun 30 2020			Jun 30 2021			Jun 30 2020
Crude oil and NGLs (bbl/d)
North America – Exploration and Production			407,111			422,124			379,554			414,576			397,007
North America – Oil Sands Mining and Upgrading			331,214			448,315			462,143			389,441			447,539
North Sea			16,380			19,927			26,567			18,144			27,130
Offshore Africa			15,531			11,325			16,739			13,440			16,017
			770,236			901,691			885,003			835,601			887,693
Natural gas (MMcf/d)
North America			1,532			1,508			1,399			1,521			1,387
North Sea			4			4			15			4			19
Offshore Africa			16			9			15			12			12
			1,552			1,521			1,429			1,537			1,418
Total barrels of oil equivalent (BOE/d)			1,028,908			1,155,220			1,123,221			1,091,716			1,124,029

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

Crude oil and NGLs production before royalties for the six months ended June 30, 2021 averaged 925,741 bbl/d, comparable with 930,286 bbl/d for the six months ended June 30, 2020. Crude oil and NGLs production for the second quarter of 2021 averaged 872,718 bbl/d, a decrease of 5% from 921,895 bbl/d for the second quarter of 2020, and a decrease of 11% from 979,352 bbl/d for the first quarter of 2021. The decrease in crude oil and NGLs production for the second quarter of 2021 from the second quarter of 2020 and the first quarter of 2021 primarily reflected the impact of the timing of the planned turnaround at Horizon and de-coking at the Scotford Upgrader ("Scotford"), which were both completed during the second 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 six months ended June 30, 2021 of 1,606 MMcf/d increased 11% from 1,451 MMcf/d for the six months ended June 30, 2020. Natural gas production for the second quarter of 2021 of 1,614 MMcf/d increased 10% from 1,462 MMcf/d for the second quarter of 2020, and was comparable with 1,598 MMcf/d for the first quarter of 2021. The increase in natural gas production for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected production volumes from the acquisition in the fourth quarter of 2020 and strong drilling results, partially offset by natural field declines. Natural gas production in the first half of 2021 also reflected a decrease of approximately 75 MMcf/d due to the temporary shutdown of the Pine River Gas Plant. The plant resumed operations on July 24, 2021, restoring approximately 100 MMcf/d.

Annual crude oil and NGLs production for 2021 is now targeted to average between 940,000 bbl/d and 980,000 bbl/d. Annual natural gas production for 2021 is now 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 six months ended June 30, 2021

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North America – Exploration and Production

North America crude oil and NGLs production before royalties for the six months ended June 30, 2021 averaged 478,524 bbl/d, an increase of 10% from 435,191 bbl/d for the six months ended June 30, 2020. North America crude oil and NGLs production for the second quarter of 2021 of 478,314 bbl/d increased 16% from 413,506 bbl/d for the second quarter of 2020, and was comparable with 478,736 bbl/d for the first quarter of 2021. The increase in crude oil and NGLs production for the three and six months ended of June 30, 2021 from the comparable periods in 2020 primarily reflected the impact of the suspension of mandatory Government of Alberta curtailment on December 1, 2020.

Thermal oil production before royalties for the second quarter of 2021 averaged 258,551 bbl/d, an increase of 21% from 212,807 bbl/d for the second quarter of 2020, and a decrease of 3% from 267,530 bbl/d for the first quarter of 2021. The increase in thermal oil production for the second quarter of 2021 from the second quarter of 2020 reflected the impact of the Company's curtailment optimization strategy in the comparable period of 2020. Production in the second quarter of 2021 continued to reflect high utilization at Jackfish and Kirby North.

Pelican Lake heavy crude oil production before royalties averaged 55,212 bbl/d for the second quarter of 2021, comparable with 55,731 bbl/d for the second quarter of 2020, and 55,498 bbl/d for the first quarter of 2021, demonstrating Pelican Lake's long-life low decline production.

Natural gas production before royalties for the six months ended June 30, 2021 averaged 1,589 MMcf/d, an increase of 12% from 1,419 MMcf/d for the six months ended June 30, 2020. Natural gas production for the second quarter of 2021 averaged 1,594 MMcf/d, an increase of 11% from 1,431 MMcf/d for the second quarter of 2020, and was comparable with 1,585 MMcf/d for the first quarter of 2021. The increase in natural gas production for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected production volumes from the acquisition in the fourth quarter of 2020 and strong drilling results, partially offset by the impact of natural field declines. Natural gas production in the first half of 2021 also reflected a decrease of approximately 75 MMcf/d due to the temporary shutdown of the Pine River Gas Plant. The plant resumed operations on July 24, 2021, restoring approximately 100 MMcf/d.

North America – Oil Sands Mining and Upgrading

SCO production before royalties for the six months ended June 30, 2021 of 414,959 bbl/d decreased 8% from 451,210 bbl/d for the six months ended June 30, 2020. SCO production for the second quarter of 2021 of 361,707 bbl/d decreased 22% from 464,318 bbl/d for the second quarter of 2020 and decreased 23% from 468,803 bbl/d for the first quarter of 2021. The decrease in SCO production for the three and six months ended June 30, 2021 from the comparable periods primarily reflected the impact of the timing of the planned turnaround at Horizon and de-coking at Scotford, which were both completed during the second quarter of 2021.

North Sea

North Sea crude oil production before royalties for the six months ended June 30, 2021 of 18,199 bbl/d decreased 33% from 27,191 bbl/d for the six months ended June 30, 2020. North Sea crude oil production for the second quarter of 2021 of 16,458 bbl/d decreased 38% from 26,627 bbl/d for the second quarter of 2020 and decreased 18% from 19,959 bbl/d for the first quarter of 2021. The decrease in production for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected planned maintenance activities during the second quarter of 2021, natural field declines, and the permanent cessation of production at the Banff and Kyle fields in 2020. The decrease in production for the second quarter of 2021 from the first quarter of 2021 primarily reflected planned maintenance activities during the second quarter of 2021.

Offshore Africa

Offshore Africa crude oil production before royalties for the six months ended June 30, 2021 decreased 16% to 14,059 bbl/d from 16,694 bbl/d for the six months ended June 30, 2020. Offshore Africa crude oil production for the second quarter of 2021 of 16,239 bbl/d decreased 7% from 17,444 bbl/d for the second quarter of 2020 and increased 37% from 11,854 bbl/d for the first quarter of 2021. The decrease in production for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected maintenance activities during the first half of 2021 and natural field declines. The increase in production for the second quarter of 2021 from the first quarter of 2021 primarily reflected the completion of maintenance activities.

Canadian Natural Resources Limited			13			Three and six months ended June 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)			Jun 30 2021			Mar 31 2021			Jun 30 2020
North Sea			270,524			—			190,135
Offshore Africa			458,208			612,242			1,375,747
			728,732			612,242			1,565,882

OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION

						Three Months Ended																					Six Months Ended
						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Crude oil and NGLs ($/bbl) (1)
Sales price (2)						$	61.20					$	52.68					$	18.97								$	56.87					$	22.70
Transportation						3.98						3.56						4.20									3.77						4.02
Realized sales price, net of transportation						57.22						49.12						14.77									53.10						18.68
Royalties						8.50						5.69						1.48									7.07						1.94
Production expense						13.75						14.56						12.53									14.16						13.17
Netback						$	34.97					$	28.87					$	0.76								$	31.87					$	3.57
Natural gas ($/Mcf) (1)
Sales price (2)						$	3.17					$	3.42					$	2.03								$	3.29					$	2.13
Transportation						0.48						0.46						0.41									0.47						0.44
Realized sales price, net of transportation						2.69						2.96						1.62									2.82						1.69
Royalties						0.12						0.16						0.05									0.14						0.05
Production expense						1.19						1.27						1.15									1.23						1.23
Netback						$	1.38					$	1.53					$	0.42								$	1.45					$	0.41
Barrels of oil equivalent ($/BOE) (1)
Sales price (2)						$	46.40					$	41.80					$	16.57								$	44.08					$	19.37
Transportation						3.58						3.29						3.61									3.42						3.55
Realized sales price, net of transportation						42.82						38.51						12.96									40.66						15.82
Royalties						5.77						4.10						1.05									4.93						1.40
Production expense						11.42						12.20						10.55									11.82						11.24
Netback						$	25.63					$	22.21					$	1.36								$	23.91					$	3.18

(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 six months ended June 30, 2021

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PRODUCT PRICES – EXPLORATION AND PRODUCTION

						Three Months Ended																					Six Months Ended
						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Crude oil and NGLs ($/bbl) (1) (2)
North America						$	59.80					$	50.67					$	17.22								$	55.21					$	20.57
North Sea						$	85.09					$	75.16					$	45.60								$	77.48					$	45.74
Offshore Africa						$	85.78					$	80.00					$	29.40								$	83.62					$	48.35
Average						$	61.20					$	52.68					$	18.97								$	56.87					$	22.70
Natural gas ($/Mcf) (1) (2)
North America						$	3.13					$	3.41					$	1.97								$	3.27					$	2.06
North Sea						$	2.58					$	2.57					$	1.42								$	2.57					$	2.81
Offshore Africa						$	6.50					$	6.09					$	8.75								$	6.35					$	8.83
Average						$	3.17					$	3.42					$	2.03								$	3.29					$	2.13
Average ($/BOE) (1) (2)						$	46.40					$	41.80					$	16.57								$	44.08					$	19.37

(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 prices increased 168% to average $55.21 per bbl for the six months ended June 30, 2021 from $20.57 per bbl for the six months ended June 30, 2020. North America realized crude oil prices increased 247% to average $59.80 per bbl for the second quarter of 2021 from $17.22 per bbl for the second quarter of 2020, and increased 18% from $50.67 per bbl for the first quarter of 2021. The increase in realized crude oil prices for the three and six months ended June 30, 2021 from the comparable periods was primarily due to higher WTI benchmark pricing, together with the narrowing of the WCS Heavy Differential. The Company continues to focus on its crude oil blending marketing strategy and in the second quarter of 2021 contributed approximately 131,000 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices increased 59% to average $3.27 per Mcf for the six months ended June 30, 2021 from $2.06 per Mcf for the six months ended June 30, 2020. North America realized natural gas prices increased 59% to average $3.13 per Mcf for the second quarter of 2021 from $1.97 per Mcf for the second quarter of 2020, and decreased 8% from $3.41 per Mcf for the first quarter of 2021. The increase in realized natural gas prices for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected lower storage levels and increased benchmark pricing. The decrease in realized natural gas prices for the second quarter of 2021 from the first quarter of 2021 primarily reflected seasonal demand factors.

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

						Three Months Ended
(Quarterly average)						Jun 30 2021						Mar 31 2021						Jun 30 2020
Wellhead Price (1) (2)
Light and medium crude oil and NGLs ($/bbl)						$	55.81					$	50.54					$	20.36
Pelican Lake heavy crude oil ($/bbl)						$	67.75					$	55.26					$	20.98
Primary heavy crude oil ($/bbl)						$	64.24					$	54.24					$	17.98
Bitumen (thermal oil) ($/bbl)						$	58.50					$	48.92					$	14.79
Natural gas ($/Mcf)						$	3.13					$	3.41					$	1.97

(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 six months ended June 30, 2021

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North Sea

North Sea realized crude oil prices increased 69% to average $77.48 per bbl for the six months ended June 30, 2021 from $45.74 per bbl for the six months ended June 30, 2020. North Sea realized crude oil prices increased 87% to average $85.09 per bbl for the second quarter of 2021 from $45.60 per bbl for the second quarter of 2020 and increased 13% from $75.16 per bbl for the first quarter of 2021. Realized crude oil 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 prices for the three and six months ended June 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 prices increased 73% to average $83.62 per bbl for the six months ended June 30, 2021 from $48.35 per bbl for the six months ended June 30, 2020. Offshore Africa realized crude oil prices increased 192% to average $85.78 per bbl for the second quarter of 2021 from $29.40 per bbl for the second quarter of 2020 and increased 7% from $80.00 per bbl for the first quarter of 2021. Realized crude oil 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 prices for the three and six months ended June 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																					Six Months Ended
						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Crude oil and NGLs ($/bbl) (1)
North America						$	8.84					$	6.09					$	1.56								$	7.46					$	2.06
North Sea						$	0.39					$	0.12					$	0.10								$	0.18					$	0.10
Offshore Africa						$	3.74					$	3.57					$	1.19								$	3.68					$	1.96
Average						$	8.50					$	5.69					$	1.48								$	7.07					$	1.94
Natural gas ($/Mcf) (1)
North America						$	0.12					$	0.16					$	0.04								$	0.14					$	0.05
Offshore Africa						$	0.30					$	0.28					$	0.40								$	0.29					$	0.44
Average						$	0.12					$	0.16					$	0.05								$	0.14					$	0.05
Average ($/BOE) (1)						$	5.77					$	4.10					$	1.05								$	4.93					$	1.40

(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 six months ended June 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 six months ended June 30, 2021 compared with 10% of product sales for the six months ended June 30, 2020. Crude oil and NGLs royalty rates averaged approximately 15% of product sales for the second quarter of 2021 compared with 9% for the second quarter of 2020 and 12% for the first quarter of 2021. The increase in royalty rates for the three and six months ended June 30, 2021 from the comparable periods was primarily due to higher benchmark prices together with fluctuations in the WCS Heavy Differential.

Canadian Natural Resources Limited			16			Three and six months ended June 30, 2021

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Natural gas royalty rates averaged approximately 4% of product sales for the six months ended June 30, 2021 compared with 2% of product sales for the six months ended June 30, 2020. Natural gas royalty rates averaged approximately 4% of product sales for the second quarter of 2021 compared with 2% for the second quarter of 2020 and 5% for the first quarter of 2021. The increase in royalty rates for the three and six months ended June 30, 2021 from the comparable periods in 2020 was primarily due to higher benchmark prices. The decrease in royalty rates for the second quarter of 2021 from the first quarter of 2021 primarily reflected lower realized natural gas prices in the second quarter of 2021.

Offshore Africa

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

Royalty rates as a percentage of product sales averaged approximately 4% for the six months ended June 30, 2021, comparable with 4% of product sales for the six months ended June 30, 2020. Royalty rates as a percentage of product sales averaged approximately 4% for the second quarter of 2021 comparable with 4% of product sales for the second quarter of 2020 and 4% for the first 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																					Six Months Ended
						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Crude oil and NGLs ($/bbl) (1)
North America						$	12.82					$	12.80					$	11.65								$	12.81					$	12.20
North Sea						$	63.65					$	42.24					$	28.47								$	47.25					$	29.19
Offshore Africa						$	13.20					$	16.57					$	10.62								$	14.46					$	11.45
Average						$	13.75					$	14.56					$	12.53								$	14.16					$	13.17
Natural gas ($/Mcf) (1)
North America						$	1.15					$	1.24					$	1.11								$	1.20					$	1.17
North Sea						$	6.96					$	4.85					$	3.18								$	5.97					$	3.34
Offshore Africa						$	3.37					$	4.99					$	3.46								$	3.97					$	4.30
Average						$	1.19					$	1.27					$	1.15								$	1.23					$	1.23
Average ($/BOE) (1)						$	11.42					$	12.20					$	10.55								$	11.82					$	11.24

(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 six months ended June 30, 2021 averaged $12.81 per bbl, an increase of 5% from $12.20 per bbl for the six months ended June 30, 2020. North America crude oil and NGLs production expense for the second quarter of 2021 of $12.82 per bbl increased 10% from $11.65 per bbl for the second quarter of 2020 and was comparable with $12.80 per bbl for the first quarter of 2021. The increase in crude oil and NGLs production expense per bbl for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected an increase in energy costs in 2021.

North America natural gas production expense for the six months ended June 30, 2021 averaged $1.20 per Mcf, comparable with $1.17 per Mcf for the six months ended June 30, 2020. North America natural gas production expense for the second quarter of 2021 of $1.15 per Mcf increased 4% from $1.11 per Mcf for the second quarter of 2020 and decreased 7% from $1.24 per Mcf for the first quarter of 2021. Natural gas production expense per Mcf for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected the impact of an increase in electricity costs, offsetting the Company's continuous focus on cost control. The decrease in natural gas production expense per Mcf for the second quarter of 2021 from the first quarter of 2021 primarily reflected the impact of seasonality.

Canadian Natural Resources Limited			17			Three and six months ended June 30, 2021

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North Sea

North Sea crude oil production expense for the six months ended June 30, 2021 averaged $47.25 per bbl, an increase of 62% from $29.19 per bbl for the six months ended June 30, 2020. North Sea crude oil production expense for the second quarter of 2021 of $63.65 per bbl increased from $28.47 per bbl for the second quarter of 2020 and increased 51% from $42.24 per bbl for the first quarter of 2021. The increase in crude oil production expense per bbl for the three and six months ended June 30, 2021 from the comparable periods was primarily due to lower volumes due to maintenance activities on a relatively fixed cost base. The increase from the comparable periods in 2020 also reflected higher energy costs. North Sea production expense also reflected fluctuations in the Canadian dollar.

Offshore Africa

Offshore Africa crude oil production expense for the six months ended June 30, 2021 averaged $14.46 per bbl, an increase of 26% from $11.45 per bbl for the six months ended June 30, 2020. Offshore Africa crude oil production expense for the second quarter of 2021 of $13.20 per bbl increased 24% from $10.62 per bbl for the second quarter of 2020 and decreased 20% from $16.57 per bbl for the first quarter of 2021. The fluctuations in crude oil production expense per bbl for the three and six months ended June 30, 2021 from the comparable periods were primarily due to the timing of liftings from various fields that have different cost structures and fluctuating volumes due to maintenance activities, on a relatively fixed cost base. Offshore Africa production expense also reflected fluctuations in the Canadian dollar.

DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION

						Three Months Ended																					Six Months Ended
($ millions, except per BOE amounts)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
North America						$	881					$	868					$	871								$	1,749					$	1,826
North Sea						19						68						76									87						175
Offshore Africa						44						31						27									75						68
Expense						$	944					$	967					$	974								$	1,911					$	2,069
$/BOE (1)						$	13.57					$	13.70					$	15.47								$	13.63					$	15.62

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

Depletion, depreciation and amortization expense for the six months ended June 30, 2021 of $13.63 per BOE decreased 13% from $15.62 per BOE for the six months ended June 30, 2020. Depletion, depreciation and amortization expense for the second quarter of 2021 of $13.57 per BOE decreased 12% from $15.47 per BOE for the second quarter of 2020 and was comparable with $13.70 per BOE for the first quarter of 2021. The decrease in depletion, depreciation and amortization expense per BOE for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected lower depletion rates in the North America Exploration and Production segment, including the impact of the acquisition in the fourth quarter of 2020.

Canadian Natural Resources Limited			18			Three and six months ended June 30, 2021

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ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION

						Three Months Ended																					Six Months Ended
($ millions, except per BOE amounts)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
North America						$	25					$	25					$	23								$	50					$	50
North Sea						5						5						8									10						15
Offshore Africa						2						1						2									3						3
Expense						$	32					$	31					$	33								$	63					$	68
$/BOE (1)						$	0.46					$	0.45					$	0.53								$	0.45					$	0.51

(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 six months ended June 30, 2021 of $0.45 per BOE decreased 12% from $0.51 per BOE for the six months ended June 30, 2020. Asset retirement obligation accretion expense for the second quarter of 2021 of $0.46 per BOE decreased 13% from $0.53 per BOE for the second quarter of 2020 and was comparable with $0.45 per BOE for the first 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 second quarter of 2021 of 361,707 bbl/d reflected the impact of the timing of the planned turnaround at Horizon and de-coking at Scotford, which were both completed during the second quarter of 2021.

The Company incurred production costs, excluding natural gas costs, of $799 million ($23.94 per bbl) for the second quarter of 2021, a 3% increase (30% increase per bbl) from the first quarter of 2021.

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

						Three Months Ended																					Six Months Ended
($/bbl) (1)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
SCO realized sales price (2)						$	76.19					$	64.60					$	29.11								$	69.71					$	39.71
Bitumen value for royalty purposes (3)						$	58.46					$	46.39					$	18.35								$	51.75					$	17.60
Bitumen royalties (4)						$	5.92					$	2.88					$	0.15								$	4.22					$	0.50
Transportation						$	1.26					$	1.10					$	0.97								$	1.17					$	1.12

(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 $69.71 per bbl for the six months ended June 30, 2021, an increase of 76% from $39.71 per bbl for the six months ended June 30, 2020. The realized SCO sales price averaged $76.19 per bbl for the second quarter of 2021, an increase of 162% from $29.11 per bbl for the second quarter of 2020 and an increase of 18% from $64.60 per bbl for the first quarter of 2021. The increase in the realized SCO sales price for the three and six months ended June 30, 2021 from the comparable periods primarily reflected increases in WTI benchmark pricing. The increase in the realized SCO sales price for the second quarter of 2021 from the first quarter of 2021 also reflected reduced supply from the planned and unplanned turnarounds at various upgraders in Alberta during the second quarter of 2021.

Canadian Natural Resources Limited			19			Three and six months ended June 30, 2021

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Transportation expense averaged $1.17 per bbl for the six months ended June 30, 2021, an increase of 4% from $1.12 per bbl for the six months ended June 30, 2020. For the second quarter of 2021, transportation expense of $1.26 per bbl increased 30% from $0.97 per bbl for the second quarter of 2020 and increased 15% from $1.10 per bbl for the first quarter of 2021. The increase in transportation expense per bbl for the second quarter of 2021 from the second quarter of 2020 and the first quarter of 2021 primarily reflected the impact of lower sales volumes at Horizon during the second 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																					Six Months Ended
($ millions)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Production costs, excluding natural gas costs						$	799					$	779					$	699								$	1,578					$	1,472
Natural gas costs						51						59						31									110						67
Production costs						$	850					$	838					$	730								$	1,688					$	1,539

						Three Months Ended																					Six Months Ended
($/bbl) (1)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Production costs, excluding natural gas costs						$	23.94					$	18.42					$	16.98								$	20.86					$	18.37
Natural gas costs						1.52						1.40						0.76									1.45						0.84
Production costs						$	25.46					$	19.82					$	17.74								$	22.31					$	19.21
Sales (bbl/d)						366,843						469,953						452,066									418,113						440,290

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

Production costs for the six months ended June 30, 2021 increased 16% to $22.31 per bbl from $19.21 per bbl for the six months ended June 30, 2020. Production costs for the second quarter of 2021 averaged $25.46 per bbl, an increase of 44% from $17.74 per bbl for the second quarter of 2020 and an increase of 28% from $19.82 per bbl for the first quarter of 2021. The increase in production costs per bbl for the three and six months ended June 30, 2021 from the comparable periods in 2020 primarily reflected lower production volumes and higher production expenses due to the impact of the timing of the planned turnaround at Horizon and de-coking at Scotford, together with the impact of higher energy costs, including natural gas costs. The increase in production costs per bbl for the second quarter of 2021 from the first quarter of 2021 primarily reflected the impact of the timing of the planned turnaround at Horizon and de-coking at Scotford, which were both completed during the second quarter of 2021. 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																					Six Months Ended
($ millions, except per bbl amounts)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Expense						$	441					$	450					$	451								$	891					$	891
$/bbl (1)						$	13.20					$	10.64					$	10.97								$	11.77					$	11.12

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

Depletion, depreciation and amortization expense for the six months ended June 30, 2021 of $11.77 per bbl increased 6% from $11.12 per bbl for the six months ended June 30, 2020. Depletion, depreciation and amortization expense for the second quarter of 2021 of $13.20 per bbl increased 20% from $10.97 per bbl for the second quarter of 2020, and increased 24% from $10.64 per bbl for the first quarter of 2021. The increase in depletion, depreciation and amortization on a per barrel basis for the three and six months ended June 30, 2021 from the comparable periods primarily reflected the impact of lower sales volumes and minor asset derecognitions at Horizon during the second quarter of 2021.

Canadian Natural Resources Limited			20			Three and six months ended June 30, 2021

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ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING

						Three Months Ended																					Six Months Ended
($ millions, except per bbl amounts)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Expense						$	14					$	15					$	18								$	29					$	35
$/bbl (1)						$	0.43					$	0.34					$	0.44								$	0.38					$	0.44

(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 six months ended June 30, 2021 of $0.38 per bbl decreased 14% from $0.44 per bbl for the six months ended June 30, 2020. Asset retirement obligation accretion expense of $0.43 per bbl for the second quarter of 2021 was comparable with $0.44 per bbl for the second quarter of 2020 and increased 26% from $0.34 per bbl for the first quarter of 2021. Fluctuations in asset retirement obligation accretion expense on a per barrel basis primarily reflect fluctuating sales volumes.

MIDSTREAM AND REFINING

						Three Months Ended																					Six Months Ended
($ millions)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Product sales
Midstream activities						$	21					$	19					$	20								$	40					$	41
NWRP, refined product sales and other						171						131						25									302						25
Segmented revenue						192						150						45									342						66
Less:
Production expense
NWRP, refining toll						72						58						24									130						24
Midstream activities						7						5						5									12						11
NWRP, transportation and feedstock costs						134						105						22									239						22
Depreciation						3						4						3									7						7
Income from NWRP						(400)						—						—									(400)						—
Segmented earnings (loss) before taxes						$	376					$	(22)					$	(9)								$	354					$	2

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 second quarter of 2021, production of ultra-low sulphur diesel and other refined products averaged 73,465 BOE/d (18,366 BOE/d to the Company).

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.

Canadian Natural Resources Limited			21			Three and six months ended June 30, 2021

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As at June 30, 2021, the cumulative unrecognized share of the equity loss from NWRP of $129 million and total partnership distributions in excess of the cumulative share of equity income, was $529 million (December 31, 2020 – $153 million; June 30, 2020 – $175 million). For the three months ended June 30, 2021, unrecognized equity income was $7 million, (six months ended June 30, 2021 – unrecognized equity income of $24 million; three months ended June 30, 2020 – unrecognized equity loss of $23 million; six months ended June 30, 2020 – unrecognized equity loss of $116 million).

ADMINISTRATION EXPENSE

						Three Months Ended																					Six Months Ended
($ millions, except per BOE amounts)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Expense						$	87					$	95					$	88								$	182					$	196
$/BOE (1)						$	0.84					$	0.84					$	0.84								$	0.84					$	0.92

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

Administration expense for the six months ended June 30, 2021 of $0.84 per BOE decreased 9% from $0.92 per BOE for the six months ended June 30, 2020. Administration expense for the second quarter of 2021 of $0.84 per BOE was comparable with $0.84 per BOE for the second quarter of 2020 and the first quarter of 2021. Administration expense per BOE decreased for the six months ended June 30, 2021 from the six months ended June 30, 2020 primarily due to higher overhead recoveries.

SHARE-BASED COMPENSATION

						Three Months Ended																					Six Months Ended
($ millions)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Expense (recovery)						$	137					$	129					$	23								$	266					$	(200)

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 $266 million share-based compensation expense for the six months ended June 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 six months ended June 30, 2021 was an expense of $35 million related to PSUs granted to certain executive employees (June 30, 2020 – $6 million recovery). For the six months ended June 30, 2021, the Company charged $2 million of share-based compensation costs to the Oil Sands Mining and Upgrading segment (June 30, 2020 – $3 million charged).

Canadian Natural Resources Limited			22			Three and six months ended June 30, 2021

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INTEREST AND OTHER FINANCING EXPENSE

						Three Months Ended																					Six Months Ended
($ millions, except per BOE amounts and interest rates)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Expense, gross						$	177					$	185					$	206								$	362					$	420
Less: capitalized interest						—						—						7									—						15
Expense, net						$	177					$	185					$	199								$	362					$	405
$/BOE (1)						$	1.73					$	1.64					$	1.91								$	1.68					$	1.90
Average effective interest rate						3.5%						3.4%						3.5%									3.4%						3.7%

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

Net interest and other financing expense per BOE for the six months ended June 30, 2021 decreased 12% to $1.68 per BOE from $1.90 per BOE for the six months ended June 30, 2020. Net interest and other financing expense per BOE for the second quarter of 2021 decreased 9% to $1.73 per BOE from $1.91 per BOE for the second quarter of 2020 and increased 5% from $1.64 per BOE for the first quarter of 2021. The decrease in interest expense and other financing expense per BOE for the three and six months ended June 30, 2021 from the comparable periods in 2020 was primarily due to lower average debt levels and lower average interest rates in 2021. The increase in interest expense per BOE for the second quarter of 2021 from the first quarter of 2021 was primarily due to lower sales volumes in the second quarter of 2021.

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

RISK MANAGEMENT ACTIVITIES

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

						Three Months Ended																					Six Months Ended
($ millions)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Foreign currency contracts						$	15					$	15					$	28								$	30					$	(29)
Natural gas financial instruments						3						(6)						3									(3)						13
Net realized loss (gain)						18						9						31									27						(16)
Foreign currency contracts						(4)						(5)						—									(9)						(9)
Natural gas financial instruments						14						25						1									39						(7)
Net unrealized loss (gain)						10						20						1									30						(16)
Net loss (gain)						$	28					$	29					$	32								$	57					$	(32)

During the six months ended June 30, 2021, net realized risk management losses were related to the settlement of foreign currency contracts, partially offset by gains on the settlement of natural gas financial instruments. The Company recorded a net unrealized loss of $30 million ($21 million after-tax) on its risk management activities for the six months ended June 30, 2021, including an unrealized loss of $10 million ($6 million after-tax) for the second quarter of 2021 (March 31, 2021 – unrealized loss of $20 million, $15 million after-tax; June 30, 2020 – unrealized loss of $1 million, $1 million after-tax).

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

Canadian Natural Resources Limited			23			Three and six months ended June 30, 2021

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FOREIGN EXCHANGE

						Three Months Ended																					Six Months Ended
($ millions)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Net realized loss (gain)						$	11					$	10					$	3								$	21					$	(196)
Net unrealized (gain) loss						(151)						(172)						(433)									(323)						688
Net (gain) loss (1)						$	(140)					$	(162)					$	(430)								$	(302)					$	492

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

The net realized foreign exchange loss for the six months ended June 30, 2021 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling. The net unrealized foreign exchange gain for the six months ended June 30, 2021 was primarily related to the impact of a stronger Canadian dollar with respect to outstanding US dollar debt. The net unrealized (gain) loss for each of the periods presented reflected the impact of the cross currency swaps, including the settlement of US$500 million in cross currency swaps in the first quarter of 2020 (three months ended June 30, 2021 – unrealized loss of $9 million, March 31, 2021 – unrealized loss of $10 million, June 30, 2020 – unrealized loss of $28 million; six months ended June 30, 2021 – unrealized loss of $19 million, June 30, 2020 – unrealized loss of $102 million). The US/Canadian dollar exchange rate at June 30, 2021 was US$0.8062 (March 31, 2021 – US$0.7954, June 30, 2020 – US$0.7345).

INCOME TAXES

						Three Months Ended																					Six Months Ended
($ millions, except income tax rates)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
North America (1)						$	324					$	285					$	(34)								$	609					$	(228)
North Sea						(5)						11						1									6						10
Offshore Africa						7						4						2									11						6
PRT (2) – North Sea						(12)						(5)						—									(17)						—
Other taxes						3						2						—									5						2
Current income tax expense (recovery)						317						297						(31)									614						(210)
Deferred income tax expense (recovery)						129						21						(267)									150						(247)
						$	446					$	318					$	(298)								$	764					$	(457)
Effective income tax rate on adjusted net earnings (loss) from operations (3)						24%						21%						28%									23%						30%

(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 six months ended June 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 six months ended June 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 six months ended June 30, 2021

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NET CAPITAL EXPENDITURES (1)

						Three Months Ended																					Six Months Ended
($ millions)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Exploration and Evaluation
Net property dispositions						$	(4)					$	—					$	—								$	(4)					$	(18)
Net expenditures						1						4						1									5						26
Total Exploration and Evaluation						(3)						4						1									1						8
Property, Plant and Equipment
Net property acquisitions						7						1						2									8						15
Well drilling, completion and equipping						224						266						32									490						234
Production and related facilities						186						192						78									378						292
Other						16						13						14									29						26
Total Property, Plant and Equipment						433						472						126									905						567
Total Exploration and Production						430						476						127									906						575
Oil Sands Mining and Upgrading
Project costs						61						41						49									102						105
Sustaining capital						346						186						172									532						373
Turnaround costs						74						29						20									103						43
Other (2)						326						1						9									327						18
Total Oil Sands Mining and Upgrading						807						257						250									1,064						539
Midstream and Refining						1						2						2									3						3
Abandonments (3)						44						67						40									111						129
Head office						3						6						2									9						13
Total net capital expenditures						$	1,285					$	808					$	421								$	2,093					$	1,259
By segment
North America						$	378					$	419					$	95								$	797					$	490
North Sea						44						32						17									76						43
Offshore Africa						8						25						15									33						42
Oil Sands Mining and Upgrading						807						257						250									1,064						539
Midstream and Refining						1						2						2									3						3
Abandonments (3)						44						67						40									111						129
Head office						3						6						2									9						13
Total						$	1,285					$	808					$	421								$	2,093					$	1,259

(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 six months ended June 30, 2021

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Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities
						Three Months Ended																					Six Months Ended
($ millions)						Jun 30 2021						Mar 31 2021						Jun 30 2020									Jun 30 2021						Jun 30 2020
Cash flows used in investing activities						$	719					$	648					$	693								$	1,367					$	1,552
Net change in non-cash working capital						(33)						93						(312)									60						(422)
Repayment of NWRP subordinated debt advances						555						—						—									555						—
Abandonment expenditures (1)						44						67						40									111						129
Net capital expenditures						$	1,285					$	808					$	421								$	2,093					$	1,259

(1)The Company excludes abandonment expenditures from "Adjusted Funds Flow, as Reconciled to Cash Flows from (used in) 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 six months ended June 30, 2021 were $2,093 million compared with $1,259 million for the six months ended June 30, 2020. Net capital expenditures for the second quarter of 2021 were $1,285 million compared with $421 million for the second quarter of 2020 and $808 million for the first quarter of 2021.

Year to date in 2021 to the end of July, 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, and the Company's 2021 capital budget will increase by this amount.

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 is related to conventional and unconventional assets and $1,860 million is allocated to long-life low decline assets.

As discussed on page 9 in the "Business Environment" section of this MD&A, the Company targets to increase its 2021 capital budget, excluding acquisitions, to approximately $3,480 million, including approximate additions of $120 million related to conventional and unconventional assets, $110 million related to long-life low decline assets, and an additional $45 million related to abandonment and reclamation activities. 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.

Canadian Natural Resources Limited			26			Three and six months ended June 30, 2021

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Drilling Activity (1)

						Three Months Ended																		Six Months Ended
(number of net wells)						Jun 30 2021						Mar 31 2021						Jun 30 2020						Jun 30 2021						Jun 30 2020
Net successful natural gas wells						9						22						1						31						12
Net successful crude oil wells (2)						27						44						2						71						37
Stratigraphic test / service wells						1						328						4						329						371
Total						37						394						7						431						420
Success rate (excluding stratigraphic test / service wells)						100%						100%						100%						100%						100%

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

(2)Includes bitumen wells.

North America

During the second quarter of 2021, the Company targeted 9 net natural gas wells, 7 net primary heavy crude oil wells, 10 net Pelican Lake heavy crude oil wells, 4 net bitumen (thermal oil) wells and 5 net light crude oil wells.

North Sea

During the second quarter of 2021, the Company targeted 1 net light crude oil well in the North Sea.

LIQUIDITY AND CAPITAL RESOURCES

($ millions, except ratios)						Jun 30 2021						Mar 31 2021						Dec 31 2020						Jun 30 2020
Working capital (1)						$	723					$	626					$	626					$	993
Long-term debt (2) (3)						$	18,331					$	20,009					$	21,453					$	23,020
Less: cash and cash equivalents						168						166						184						233
Long-term debt, net						$	18,163					$	19,843					$	21,269					$	22,787
Share capital						$	9,863					$	9,685					$	9,606					$	9,521
Retained earnings						24,390						23,567						22,766						22,614
Accumulated other comprehensive income						(46)						(21)						8						198
Shareholders’ equity						$	34,207					$	33,231					$	32,380					$	32,333
Debt to book capitalization (3) (4)						34.7%						37.4%						39.6%						41.3%
Debt to market capitalization (3) (5)						25.4%						30.1%						37.0%						45.0%
After-tax return on average common shareholders’ equity (6)						12.4%						6.8%						(1.3)%						0.1%
After-tax return on average capital employed (3) (7)						8.6%						5.1%						0.2%						1.2%

(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 six months ended June 30, 2021

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As at June 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 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.

◦As at June 30, 2021, the Company had $2,200 million remaining on its base shelf prospectus that allowed for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada. Subsequent to June 30, 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.

◦As at June 30, 2021, the Company had US$1,900 million remaining on its base shelf prospectus that allowed for the offer for sale from time to time of up to US$3,000 million of debt securities in the United States. Subsequent to June 30, 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. Subsequent to June 30, 2021, the Company filed a notice for the early repayment of US$500 million of 3.45% debt securities in August 2021, 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 June 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 six months ended June 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 June 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 $5,596 million in liquidity. Additionally, the Company had in place fully drawn term credit facilities of $3,650 million. The Company also has certain other dedicated credit facilities supporting letters of credit. At June 30, 2021, the Company had $682 million drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.

As at June 30, 2021, the Company had total US dollar denominated debt with a carrying amount of $15,224 million (US$12,273 million), before transaction costs and original issue discounts. This included $5,052 million (US$4,073 million) hedged by way of a cross currency swap (US$550 million) and foreign currency forwards (US$3,523 million). The fixed repayment amount of these hedging instruments is $4,946 million, resulting in a notional reduction of the carrying amount of the Company’s US dollar denominated debt by approximately $106 million to $15,118 million as at June 30, 2021.

Net long-term debt was $18,163 million at June 30, 2021, resulting in a debt to book capitalization ratio of 34.7% (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 June 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 June 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 June 30, 2021 are discussed in note 15 of the Company’s unaudited interim consolidated financial statements.

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)			$	2,300					$	4,931					$	3,109					$	8,084
Other long-term liabilities (2)			$	250					$	189					$	414					$	877
Interest and other financing expense (3)			$	694					$	629					$	1,505					$	4,123

(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, $153 million; two to less than five years, $403 million; and thereafter, $877 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 June 30, 2021.

Share Capital

As at June 30, 2021, there were 1,185,595,000 common shares outstanding (December 31, 2020 – 1,183,866,000 common shares) and 50,156,000 stock options outstanding. As at August 3, 2021, the Company had 1,180,683,000 common shares outstanding and 49,604,000 stock options outstanding.

On March 3, 2021, the Board of Directors approved an increase in the quarterly dividend to $0.47 per common share, beginning with the dividend payable on April 5, 2021 (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 six months ended June 30, 2021

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For the six months ended June 30, 2021, the Company purchased 5,640,000 common shares at a weighted average price of $41.89 per common share for a total cost of $236 million. Retained earnings were reduced by $190 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to June 30, 2021, the Company purchased 5,404,400 common shares at a weighted average price of $42.12 per common share for a total cost of $228 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 June 30, 2021:

($ millions)			Remaining 2021						2022						2023						2024						2025						Thereafter
Product transportation and processing (1)			$	442					$	838					$	907					$	846					$	811					$	10,360
North West Redwater Partnership service toll (2)			$	63					$	123					$	123					$	122					$	119					$	3,784
Offshore vessels and equipment			$	33					$	41					$	—					$	—					$	—					$	—
Field equipment and power			$	14					$	21					$	21					$	21					$	21					$	246
Other			$	14					$	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 $1,546 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.

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 six months ended June 30, 2021, COVID-19 continued to have an impact on the global economy, including the oil and gas industry. Business conditions in the second 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.

CONTROL ENVIRONMENT

There have been no changes to internal control over financial reporting ("ICFR") during the six months ended June 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			30			Three and six months ended June 30, 2021