Canadian Natural Resources Limited

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE MONTHS ENDED MARCH 31, 2019

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” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses and other guidance 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 but not limited to the Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the timing and future operations of 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, and the development and deployment of technology and technological innovations 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 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 which will, among other things, impact demand for and market prices of the Company’s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company’s current guidance is 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 resumption of 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 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; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset retirement obligations; the adequacy of the Company’s provision for taxes; and other circumstances affecting revenues and expenses.

Canadian Natural Resources Limited 1 Three Months Ended March 31, 2019

The Company’s operations have been, and in the future may be, affected by political developments and by national, federal, provincial 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, 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 (previously referred to as funds flow from operations) and net capital expenditures. These financial measures are not defined by International Financial Reporting Standards ("IFRS") and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings (loss), cash flows from operating activities, and cash flows used in investing activities as determined in accordance with IFRS, as an indication of the Company's performance. The non-GAAP 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 measure adjusted funds flow is reconciled to cash flows from operating activities, as determined in accordance with IFRS, in the "Financial Highlights" section of this MD&A. The non-GAAP 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 months endedMarch 31, 2019 and the MD&A and the audited consolidated financial statements of the Company for the year ended December 31, 2018. 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 months endedMarch 31, 2019 and this MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board ("IASB"). Changes in the Company's accounting policies in accordance with IFRS, including the adoption of IFRS 16 "Leases" on January 1, 2019, are discussed in the "Changes in Accounting Policies" section of this MD&A. In accordance with the new "Leases" standard, comparative period balances in 2018 reported in this MD&A have not been restated.

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

The following discussion and analysis refers primarily to the Company’s financial results for the three months endedMarch 31, 2019 in relation to the first quarter of 2018 and the fourth quarter of 2018. 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, 2018, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. Detailed guidance on production levels, capital expenditures and production expenses can be found on the Company's website at www.cnrl.com, provided that such guidance does not form part of and is not incorporated by reference in this MD&A. This MD&A is dated May 8, 2019.

Canadian Natural Resources Limited 2 Three Months Ended March 31, 2019

FINANCIAL HIGHLIGHTS

		Three Months Ended
($ millions, except per common share amounts)		Mar 31 2019		Dec 31 2018			Mar 31 2018
Product sales (1)		$	5,541	$	3,831		$	5,735
Crude oil and NGLs		$	5,082	$	3,327		$	5,303
Natural gas		$	456	$	504		$	432
Net earnings (loss)		$	961	$	(776	)	$	583
Per common share	– basic	$	0.80	$	(0.64	)	$	0.48
	– diluted	$	0.80	$	(0.64	)	$	0.47
Adjusted net earnings (loss) from operations (2)		$	838	$	(255	)	$	885
Per common share	– basic	$	0.70	$	(0.21	)	$	0.72
	– diluted	$	0.70	$	(0.21	)	$	0.71
Cash flows from operating activities		$	996	$	1,397		$	2,469
Adjusted funds flow (3)		$	2,240	$	1,229		$	2,323
Per common share	– basic	$	1.87	$	1.02		$	1.90
	– diluted	$	1.86	$	1.02		$	1.89
Cash flows used in investing activities		$	1,029	$	1,042		$	1,369
Net capital expenditures (4)		$	977	$	1,181		$	1,103

(1) Further details related to product sales, including 'Other' income, for the three months ended March 31, 2019 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 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 (previously referred to as funds flow from operations) is a non-GAAP measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment expenditures and movements in other long-term assets, including the unamortized cost of the share bonus program and prepaid cost of service tolls.The Company considers adjusted funds flow a key measure in evaluating its performance as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities” is presented in this MD&A. Adjusted funds flow may not be comparable to similar measures presented by other companies.

(4) Net capital expenditures is a non-GAAP 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, investment in other long-term assets, share consideration in business acquisitions and abandonment expenditures. The Company considers net capital expenditures a key measure 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 Months Ended March 31, 2019

Adjusted Net Earnings (Loss) from Operations, as Reconciled to Net Earnings (Loss)
	Three Months Ended
($ millions)	Mar 31 2019			Dec 31 2018			Mar 31 2018
Net earnings (loss), as reported	$	961		$	(776	)	$	583
Share-based compensation, net of tax (1)	62			(148		)	(88		)
Unrealized risk management loss (gain), net of tax (2)	13			17			(31		)
Unrealized foreign exchange (gain) loss, net of tax (3)	(233		)	548			162
Realized foreign exchange loss on repayment of US dollar debt securities, net of tax (4)	—			—			146
Loss from investments, net of tax (5) (6)	35			134			113
Gain on acquisition, disposition and revaluation of properties, net of tax (7)	—			(30		)	—
Adjusted net earnings (loss) from operations	$	838		$	(255	)	$	885

(1) The Company’s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded 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 recorded 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 crude oil, 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 2018, the Company repaid US$600 million of 1.75% notes and US$400 million of 5.90% notes.

(5) The Company's investment in the 50% owned North West Redwater Partnership ("Redwater Partnership") is accounted for using the equity method of accounting. Included in the non-cash loss from investments is the Company's pro rata share of the Redwater Partnership's equity loss for the period.

(6) The Company’s investments in PrairieSky Royalty Ltd. (“PrairieSky”) and Inter Pipeline Ltd. ("Inter Pipeline") 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).

(7) During the fourth quarter of 2018, the Company recorded a pre-tax gain of $16 million ($12 million after-tax) on the disposition of a 30% interest in the exploration right in South Africa. Additionally, during the fourth quarter of 2018, the Gabonese Republic approved cessation of production from the Company’s Olowi field and associated asset retirement obligations, as well as the terms of termination of the Olowi Production Sharing Contract and the surrender of the permit area back to the Gabonese Republic, resulting in a pre-tax gain on disposition of property of $20 million ($14 million after-tax).

Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities (1)
	Three Months Ended
($ millions)	Mar 31 2019		Dec 31 2018			Mar 31 2018
Cash flows from operating activities	$	996	$	1,397		$	2,469
Net change in non-cash working capital	1,016		(279		)	(235		)
Abandonment expenditures (2)	108		93			90
Other (3)	120		18			(1		)
Adjusted funds flow	$	2,240	$	1,229		$	2,323

(1) Adjusted funds flow was previously referred to as funds flow from operations.

(2) 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.

(3) Movements in other long-term assets, including the unamortized cost of the share bonus program and prepaid cost of service tolls.

Canadian Natural Resources Limited 4 Three Months Ended March 31, 2019

SUMMARY OF FINANCIAL HIGHLIGHTS

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

Net earnings for the first quarter of 2019 were $961 million compared with net earnings of $583 million for the first quarter of 2018 and a net loss of $776 million for the fourth quarter of 2018. Net earnings for the first quarter of 2019 included net after-tax income of $123 million compared with net after-tax expenses of $302 million for the first quarter of 2018 and net after-tax expenses of $521 million for the fourth quarter of 2018 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of realized foreign exchange losses on repayments of long-term debt, the loss from investments, and the gain on acquisition, disposition and revaluation of properties. Excluding these items, adjusted net earnings from operations for the first quarter of 2019 were $838 million compared with adjusted net earnings from operations of $885 million for the first quarter of 2018 and an adjusted net loss from operations of $255 million for the fourth quarter of 2018.

Net earnings and adjusted net earnings from operations for the first quarter of 2019 compared with the first quarter of 2018 primarily reflected:

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

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

▪ higher realized foreign exchange gains;

partially offset by:

▪ lower sales volumes in the North America Exploration and Production and Oil Sands Mining and Upgrading segments due to the impact of the Government of Alberta mandated production curtailments; and

▪ higher realized risk management losses.

Net earnings and adjusted net earnings from operations for the first quarter of 2019 compared with the net loss and adjusted net loss from operations for the fourth quarter of 2018 primarily reflected:

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

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

▪ lower depletion, depreciation and amortization in the Exploration and Production segments due to lower sales volumes;

partially offset by:

▪ lower sales volumes in the North America Exploration and Production and Oil Sands Mining and Upgrading segments due to the impact of the Government of Alberta mandated production curtailments; and

▪ higher realized risk management losses.

For the first quarter of 2019, the adoption of IFRS 16 did not have a significant overall impact on net earnings and adjusted net earnings from operations. The impacts of share-based compensation, risk management activities and fluctuations in foreign exchange rates also contributed to the movements in net earnings (loss). These items are discussed in detail in the relevant sections of this MD&A.

Cash Flows from Operating Activities and Adjusted Funds Flow

Cash flows from operating activities for the first quarter of 2019 were $996 million compared with $2,469 million for the first quarter of 2018 and $1,397 million for the fourth quarter of 2018. The fluctuations in cash flows from operating activities from the comparable periods were primarily due to the factors noted above relating to the fluctuations in net earnings (loss) and adjusted net earnings (loss) from operations (excluding the effect of depletion, depreciation and amortization), as well as due to the impact of changes in non-cash working capital.

Adjusted funds flow for the first quarter of 2019 was $2,240 million compared with $2,323 million for the first quarter of 2018 and $1,229 million for the fourth quarter of 2018. 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 operating activities excluding the impact of the net change in non-cash working capital, abandonment expenditures and movements in other long-term assets, including the unamortized cost of the share bonus program and prepaid cost of service tolls.

Cash flows from operating activities and adjusted funds flow for the three months endedMarch 31, 2019 reflected an increase of $52 million related to the adoption of IFRS 16 on January 1, 2019. The adoption of IFRS 16 is discussed in the "Changes in Accounting Policies" section of this MD&A.

Canadian Natural Resources Limited 5 Three Months Ended March 31, 2019

Production Volumes

Total production before royalties for the first quarter of 2019decreased8% to 1,035,212 BOE/d from 1,123,546 BOE/d for the first quarter of 2018 and decreased4% from 1,081,368 BOE/d for the fourth quarter of 2018, reflecting the impact of the Government of Alberta mandated production curtailments that came into effect January 1, 2019. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production" section of this MD&A.

SUMMARY OF QUARTERLY FINANCIAL RESULTS

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

($ millions, except per common share amounts)	Mar 31 2019		Dec 31 2018			Sep 30 2018		Jun 30 2018
Product sales (1)	$	5,541	$	3,831		$	6,327	$	6,389
Crude oil and NGLs	$	5,082	$	3,327		$	5,967	$	6,071
Natural gas	$	456	$	504		$	360	$	318
Net earnings (loss)	$	961	$	(776	)	$	1,802	$	982
Net earnings (loss) per common share
– basic	$	0.80	$	(0.64	)	$	1.48	$	0.80
– diluted	$	0.80	$	(0.64	)	$	1.47	$	0.80
($ millions, except per common share amounts)	Mar 31 2018		Dec 31 2017			Sep 30 2017		Jun 30 2017
Product sales	$	5,735	$	5,516		$	4,725	$	4,127
Crude oil and NGLs	$	5,303	$	5,098		$	4,320	$	3,645
Natural gas	$	432	$	418		$	405	$	482
Net earnings (loss)	$	583	$	396		$	684	$	1,072
Net earnings (loss) per common share
– basic	$	0.48	$	0.32		$	0.56	$	0.93
– diluted	$	0.47	$	0.32		$	0.56	$	0.93

(1) Further details related to product sales, including 'Other' income, for the three months ended March 31, 2019 are disclosed in note 17 to the Company’s unaudited interim consolidated financial statements.

Canadian Natural Resources Limited 6 Three Months Ended March 31, 2019

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 the Organization of the Petroleum Exporting Countries (“OPEC”) and its impact on world supply, the impact of geopolitical uncertainties 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 including the impact of a shortage of takeaway capacity out of the Western Canadian Sedimentary Basin (the "Basin"), 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 January 1, 2019.

▪ 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 Primrosethermal projects, production from Kirby South, the results from the Pelican Lake water and polymer flood projects, the impact of the Company’s drilling program in North America and the International segments, the impact and timing of acquisitions, including the acquisition of AOSP and other assets, production from Horizon Phase 3 as well as the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, voluntarily curtailed production in late 2018 due to low commodity prices in North America and production curtailments mandated by the Government of Alberta that came into effect January 1, 2019. 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 higher return crude oil projects, natural decline rates, fluctuating capacity at a third-party processing facility, shut-in production due to third party pipeline restrictions and related pricing impacts, shut-in production due to low commodity prices, and the impact and timing of acquisitions.

▪ Production expense – Fluctuations primarily due to the impact of the demand and cost for services, fluctuations in product mix and production volumes, the impact of seasonal costs that are dependent on weather, the impact of increased carbon tax and energy costs, cost optimizations across all segments, the impact and timing of acquisitions, including the acquisition of AOSP and other assets, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, maintenance activities in the International segments, and the impact of the adoption of IFRS 16 on January 1, 2019.

▪ Depletion, depreciation and amortization – 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, fluctuations in depletion, depreciation and amortization expense in the North Sea due to the cessation of production at the Ninian North platform in the second quarter of 2017, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and the impact of the adoption of IFRS 16 on January 1, 2019.

▪ Share-based compensation – Fluctuations due to the determination of fair market value based on the Black-Scholes valuation model 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.

▪ Foreign exchange rates – Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company received 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.

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

▪ Gains on acquisition, disposition and revaluation of properties and gains/losses on investments – Fluctuations due to the recognition of gains on the acquisition of AOSP and other assets, the acquisition, disposition and revaluation of properties in the various periods, fair value changes in the investments in PrairieSky and Inter Pipeline shares, and the equity loss (gain) on the Company's interest in the Redwater Partnership.

Canadian Natural Resources Limited 7 Three Months Ended March 31, 2019

BUSINESS ENVIRONMENT

	Three Months Ended
(Average for the period)	Mar 31 2019		Dec 31 2018		Mar 31 2018
WTI benchmark price (US$/bbl)	$	54.90	$	58.83	$	62.89
Dated Brent benchmark price (US$/bbl)	$	63.34	$	67.45	$	66.99
WCS heavy differential from WTI (US$/bbl)	$	12.38	$	39.36	$	24.27
SCO price (US$/bbl)	$	52.19	$	37.48	$	61.45
Condensate benchmark price (US$/bbl)	$	50.49	$	45.27	$	63.12
Condensate differential from WTI (US$/bbl)	$	4.40	$	13.56	$	(0.23	)
NYMEX benchmark price (US$/MMBtu)	$	3.16	$	3.65	$	2.98
AECO benchmark price (C$/GJ)	$	1.84	$	1.80	$	1.75
US/Canadian dollar average exchange rate (US$)	$	0.7522	$	0.7573	$	0.7905

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 Alberta 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 in the Canadian dollar as the Canadian dollar sales price the Company received for its crude oil and natural gas sales is based on US dollar denominated benchmarks.

Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$54.90 per bbl for the first quarter of 2019, a decrease of 13% from US$62.89 per bbl for the first quarter of 2018, and a decrease of 7% from US$58.83 per bbl for the fourth quarter of 2018. WTI pricing for the first quarter of 2019 decreased from the comparable periods primarily due to increased shale oil supply in the US.

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$63.34 per bbl for the first quarter of 2019, a decrease of 5% from US$66.99 per bbl for the first quarter of 2018, and a decrease of 6% from US$67.45 per bbl for the fourth quarter of 2018.

The WCS heavy differential averaged US$12.38 per bbl for the first quarter of 2019, a decrease of 49% from US$24.27 per bbl for the first quarter of 2018, and a decrease of 69% from US$39.36 per bbl for the fourth quarter of 2018. The narrowing of the WCS heavy differential for the first quarter of 2019 from the comparable periods primarily reflected the impact of the Government of Alberta mandatory production curtailments that came into effect January 1, 2019. The WCS heavy differential in the first quarter of 2019 also reflected stronger US Gulf Coast heavy oil pricing due to supply shortfalls during the quarter.

The SCO price averaged US$52.19 per bbl for the first quarter of 2019, a decrease of 15% from US$61.45 per bbl for the first quarter of 2018, and an increase of 39% from US$37.48 per bbl for the fourth quarter of 2018. The decrease in SCO pricing for the first quarter of 2019 from the first quarter of 2018 primarily reflected a decrease in WTI benchmark pricing. The increase in SCO pricing for the first quarter of 2019 from the fourth quarter of 2018 reflected the impact of the Government of Alberta mandatory production curtailments that came into effect January 1, 2019.

The condensate differential averaged a US$4.40 per bbl discount for the first quarter of 2019, compared to a US$0.23 per bbl premium for the first quarter of 2018, and a US$13.56 per bbl discount for the fourth quarter of 2018. The narrowing of the condensate differential for the first quarter of 2019 from the fourth quarter of 2018 reflected the impact of the Government of Alberta mandatory production curtailments that came into effect January 1, 2019.

NYMEX natural gas pricing averaged US$3.16 per MMBtu for the first quarter of 2019, an increase of 6% from US$2.98 per MMBtu for the first quarter of 2018 and a decrease of 13% from US$3.65 per MMBtu for the fourth quarter of 2018. The increase in NYMEX natural gas pricing for the first quarter of 2019 from the first quarter of 2018 reflected low storage inventory levels in North America. The decrease in NYMEX natural gas pricing for the first quarter of 2019 from the fourth quarter of 2018 reflected the impact of colder than normal weather conditions in the fourth quarter of 2018.

AECO natural gas pricing averaged $1.84 per GJ for the first quarter of 2019, an increase of 5% from $1.75 per GJ for the first quarter of 2018 and comparable with $1.80 per GJ for the fourth quarter of 2018. The increase in AECO natural gas pricing for the first quarter of 2019 from the first quarter of 2018 primarily reflected the easing of third party pipeline constraints.

Canadian Natural Resources Limited 8 Three Months Ended March 31, 2019

DAILY PRODUCTION, before royalties

	Three Months Ended
	Mar 31 2019	Dec 31 2018	Mar 31 2018
Crude oil and NGLs (bbl/d)
North America – Exploration and Production	319,437	343,054	357,460
North America – Oil Sands Mining and Upgrading (1)	416,206	447,048	456,076
North Sea	25,714	21,071	21,584
Offshore Africa	22,155	22,185	19,438
	783,512	833,358	854,558
Natural gas (MMcf/d)
North America	1,454	1,441	1,547
North Sea	28	22	37
Offshore Africa	28	25	30
	1,510	1,488	1,614
Total barrels of oil equivalent(BOE/d)	1,035,212	1,081,368	1,123,546
Product mix
Light and medium crude oil and NGLs	14%	13%	12%
Pelican Lake heavy crude oil	6%	6%	6%
Primary heavy crude oil	7%	7%	8%
Bitumen (thermal oil)	9%	10%	10%
Synthetic crude oil (1)	40%	41%	40%
Natural gas	24%	23%	24%
Percentage of gross revenue(1)(2)
(excluding Midstream and Refining revenue)
Crude oil and NGLs	91%	85%	92%
Natural gas	9%	15%	8%

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

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

Canadian Natural Resources Limited 9 Three Months Ended March 31, 2019

DAILY PRODUCTION,net of royalties

	Three Months Ended
	Mar 31 2019	Dec 31 2018	Mar 31 2018
Crude oil and NGLs (bbl/d)
North America – Exploration and Production	281,233	304,324	310,783
North America – Oil Sands Mining and Upgrading	397,639	421,421	443,606
North Sea	25,675	21,021	21,521
Offshore Africa	20,260	21,366	18,652
	724,807	768,132	794,562
Natural gas (MMcf/d)
North America	1,399	1,396	1,473
North Sea	28	22	37
Offshore Africa	25	22	27
	1,452	1,440	1,537
Total barrels of oil equivalent (BOE/d)	966,758	1,008,210	1,050,702

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 for the first quarter of 2019decreased by 8% to average 783,512 bbl/d from 854,558 bbl/d for the first quarter of 2018, and decreased by 6% from 833,358 bbl/d for the fourth quarter of 2018.The decrease in crude oil and NGLs production for the first quarter of 2019 from the comparable periods primarily reflected the impact of the Government of Alberta mandated production curtailments that came into effect January 1, 2019. As a result of the mandated production curtailments, planned maintenance activities at Horizon were strategically advanced into the first quarter of 2019 from the second quarter of 2019. Decreased crude oil and NGLs production in the North America Exploration and Production and Oil Sands Mining and Upgrading segments was partially offset by increased production in the International segments due to the drilling programs completed in 2018.

First quarter 2019 crude oil and NGLs production was within the Company's previously issued guidance of 759,000 to 817,000 bbl/d. Second quarter 2019 crude oil and NGLs production guidance is targeted to average between 773,000 and 831,000 bbl/d, reflecting known production curtailments mandated by the Government of Alberta through June 2019.

Natural gas production for the first quarter of 2019 of 1,510 MMcf/d decreased6% from 1,614 MMcf/d for the first quarter of 2018, and was comparable with 1,488 MMcf/d for the fourth quarter of 2018. The decrease in natural gas production for the first quarter of 2019 from the first quarter of 2018 primarily reflected natural field declines and reduced drilling activity.

First quarter 2019 natural gas production was within the Company's previously issued guidance of 1,490 to 1,520 MMcf/d. Second quarter 2019 natural gas production guidance is targeted to average between 1,500 and 1,530 MMcf/d.

North America – Exploration and Production

North America crude oil and NGLs production for the first quarter of 2019decreased by 11% to average 319,437 bbl/d from 357,460 bbl/d for the first quarter of 2018, and decreased by 7% from 343,054 bbl/d for the fourth quarter of 2018. The decrease in crude oil and NGLs production for the first quarter of 2019 from the comparable periods primarily reflected the impact of the Government of Alberta mandated production curtailments that came into effect January 1, 2019.

Operating performance at Pelican Lake continued to be strong, with heavy crude oil production averaging 61,240 bbl/day in the first quarter of 2019, compared with 63,274 bbl/d in the first quarter of 2018 and 62,428 bbl/d in the fourth quarter of 2018.

Overall thermal oil production for the first quarter of 2019 averaged 94,146 bbl/d compared with 111,851 bbl/d for the first quarter of 2018 and 102,112 bbl/d for the fourth quarter of 2018, reflecting the impact of the Government of Alberta mandated production curtailments that came into effect January 1, 2019. First quarter 2019 thermal oil production was within the Company's previously issued guidance of 92,000 to 98,000 bbl/d. Second quarter 2019 thermal oil production is targeted to average between 100,000 and 106,000 bbl/d, reflecting known production curtailments mandated by the Government of Alberta through June 2019.

Canadian Natural Resources Limited 10 Three Months Ended March 31, 2019

First quarter 2019 crude oil and NGLs production, including thermal oil, was within the Company's previously issued guidance of 313,000 to 327,000 bbl/d. Second quarter 2019 crude oil and NGLs production guidance, including thermal oil, is targeted to average between 324,000 and 338,000 bbl/d, reflecting known production curtailments mandated by the Government of Alberta through June 2019.

Natural gas production for the first quarter of 2019decreased6% to 1,454 MMcf/d from 1,547 MMcf/d for the first quarter of 2018, and was comparable with 1,441 MMcf/d for the fourth quarter of 2018. The decrease in natural gas production for the first quarter of 2019 from the first quarter of 2018 primarily reflected natural field declines and reduced drilling activity.

North America – Oil Sands Mining and Upgrading

SCO production for the first quarter of 2019decreased9% to average 416,206 bbl/d from 456,076 bbl/d for the first quarter of 2018 and decreased7% from 447,048 bbl/d for the fourth quarter of 2018. The decrease in SCO production for the first quarter of 2019 from the comparable periods primarily reflected unplanned maintenance activities as well as the impact of the Government of Alberta mandated production curtailments that came into effect January 1, 2019. As a result of the mandated production curtailments, planned maintenance activities at Horizon were strategically advanced into the first quarter of 2019 from the second quarter of 2019.

First quarter 2019 SCO production was within the Company's previously issued guidance of 400,000 to 440,000 bbl/d. Second quarter 2019 SCO production guidance is targeted to average between 400,000 and 440,000 bbl/d, primarily reflecting planned maintenance activities, the impact of repairs related to the fire at the Scotford Upgrader, and to a lesser extent, the impact of known production curtailments mandated by the Government of Alberta through June 2019.

North Sea

North Sea crude oil production for the first quarter of 2019increased19% to 25,714 bbl/d from 21,584 bbl/d for the first quarter of 2018 and increased22% from 21,071 bbl/d for the fourth quarter of 2018. The increase in production for the first quarter of 2019 from the first quarter of 2018 primarily reflected the impact of the drilling program completed in 2018, partially offset by natural field declines. The increase in production for the first quarter of 2019 from the fourth quarter of 2018 primarily reflected the impact of production resuming following the planned turnarounds and maintenance activities completed during the fourth quarter of 2018.

Offshore Africa

Offshore Africa crude oil production for the first quarter of 2019increased14% to 22,155 bbl/d from 19,438 bbl/d for the first quarter of 2018 and was comparable with 22,185 bbl/d for the fourth quarter of 2018. The increase in production for the first quarter of 2019 from the first quarter of 2018 primarily reflected volumes from new wells drilled at Baobab in 2018, partially offset by the cessation of production at the Olowi field, Gabon in December 2018 and natural field declines.

International Guidance

First quarter 2019 International crude oil production of 47,869 bbl/d was within the Company's previously issued guidance of 46,000 to 50,000 bbl/d. Second quarter 2019 crude oil production guidance is targeted to average between 49,000 and 53,000 bbl/d.

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 business segments on crude oil volumes that were stored in various storage facilities or FPSOs, as follows:

	Three Months Ended
(bbl)	Mar 31 2019	Dec 31 2018	Mar 31 2018
North Sea	851,919	71,832	506,589
Offshore Africa	1,055,383	404,475	1,141,282
	1,907,302	476,307	1,647,871

Canadian Natural Resources Limited 11 Three Months Ended March 31, 2019

OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION

	Three Months Ended
	Mar 31 2019		Dec 31 2018		Mar 31 2018
Crude oil and NGLs ($/bbl)(1)
Sales price (2)	$	53.98	$	25.95	$	43.06
Transportation	3.26		2.94		3.10
Realized sales price, net of transportation	50.72		23.01		39.96
Royalties	5.95		0.92		4.87
Production expense	16.04		16.93		15.70
Netback	$	28.73	$	5.16	$	19.39
Natural gas ($/Mcf) (1)
Sales price (2)	$	3.09	$	3.46	$	2.74
Transportation	0.46		0.42		0.51
Realized sales price, net of transportation	2.63		3.04		2.23
Royalties	0.12		0.10		0.10
Production expense	1.33		1.32		1.41
Netback	$	1.18	$	1.62	$	0.72
Barrels of oil equivalent ($/BOE) (1)
Sales price (2)	$	39.27	$	24.04	$	32.02
Transportation	3.06		2.77		3.05
Realized sales price, net of transportation	36.21		21.27		28.97
Royalties	3.78		0.80		3.10
Production expense	12.68		13.51		12.68
Netback	$	19.75	$	6.96	$	13.19

(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 12 Three Months Ended March 31, 2019

PRODUCT PRICES – EXPLORATION AND PRODUCTION

	Three Months Ended
	Mar 31 2019		Dec 31 2018		Mar 31 2018
Crude oil and NGLs ($/bbl) (1) (2)
North America	$	50.92	$	17.03	$	40.66
North Sea	$	87.61	$	78.45	$	79.35
Offshore Africa	$	81.00	$	81.15	$	78.85
Average	$	53.98	$	25.95	$	43.06
Natural gas ($/Mcf) (1) (2)
North America	$	2.88	$	3.23	$	2.44
North Sea	$	10.05	$	14.09	$	11.67
Offshore Africa	$	7.34	$	7.32	$	6.95
Average	$	3.09	$	3.46	$	2.74
Average ($/BOE) (1) (2)	$	39.27	$	24.04	$	32.02

(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 averaged $50.92 per bbl for the first quarter of 2019, an increase of 25% compared with $40.66 per bbl for the first quarter of 2018 and an increase of 199% compared with $17.03 per bbl for the fourth quarter of 2018. The increase in realized crude oil prices for the first quarter of 2019 from the comparable periods was primarily due to the narrowing of the WCS heavy differential as a result of the Government of Alberta mandatory production curtailments that came into effect January 1, 2019. The Company continues to focus on its crude oil blending marketing strategy and in the first quarter of 2019, contributed approximately 189,100 bbl/d of heavy crude oil blends to the WCS stream.

North America realized natural gas prices increased18% to average $2.88 per Mcf for the first quarter of 2019 compared with $2.44 per Mcf for the first quarter of 2018, and decreased11% compared with $3.23 per Mcf for the fourth quarter of 2018. The increase in realized natural gas prices for the first quarter of 2019 compared with the first quarter of 2018 reflected low storage inventory levels in North America and the easing of third party pipeline constraints as well as higher natural gas export sales volumes and prices. The decrease in realized natural gas prices for the first quarter of 2019 compared with the fourth quarter of 2018primarily reflected the impact of colder than normal weather conditions in the fourth quarter of 2018 as well as a slight decrease in export prices in the first quarter of 2019.

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

	Three Months Ended
(Quarterly average)	Mar 31 2019		Dec 31 2018		Mar 31 2018
Wellhead Price (1) (2)
Light and medium crude oil and NGLs ($/bbl)	$	49.13	$	34.62	$	53.48
Pelican Lake heavy crude oil ($/bbl)	$	56.28	$	12.40	$	41.63
Primary heavy crude oil ($/bbl)	$	52.27	$	11.33	$	36.85
Bitumen (thermal oil) ($/bbl)	$	48.27	$	7.70	$	32.22
Natural gas ($/Mcf)	$	2.88	$	3.23	$	2.44

(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 13 Three Months Ended March 31, 2019

North Sea

North Sea realized crude oil prices increased10% to average $87.61 per bbl for the first quarter of 2019 from $79.35 per bbl for the first quarter of 2018 and increased12% from $78.45 per bbl for the fourth quarter of 2018. Realized crude oil prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings of 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 first quarter of 2019 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 increased3% to average $81.00 per bbl for the first quarter of 2019 from $78.85 per bbl for the first quarter of 2018 and was comparable with $81.15 per bbl for the fourth quarter of 2018. Realized crude oil prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings of 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 first quarter of 2019 from the comparable periods reflected prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.

ROYALTIES – EXPLORATION AND PRODUCTION

	Three Months Ended
	Mar 31 2019		Dec 31 2018		Mar 31 2018
Crude oil and NGLs ($/bbl) (1)
North America	$	6.22	$	0.82	$	5.11
North Sea	$	0.13	$	0.18	$	0.23
Offshore Africa	$	6.93	$	3.00	$	3.19
Average	$	5.95	$	0.92	$	4.87
Natural gas ($/Mcf) (1)
North America	$	0.11	$	0.09	$	0.09
Offshore Africa	$	0.85	$	0.80	$	0.87
Average	$	0.12	$	0.10	$	0.10
Average($/BOE) (1)	$	3.78	$	0.80	$	3.10

(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 first quarter of 2019 and the comparable periods reflected movements in benchmark commodity prices. North America crude oil royalties also reflected fluctuations in the WCS heavy differential.

Crude oil and NGLs royalty rates averaged approximately 12% of product sales for the first quarter of 2019 compared with 14% for the first quarter of 2018 and 6% for the fourth quarter of 2018. The decrease in royalty rates for the first quarter of 2019 from the first quarter of 2018 was primarily due to the underlying changes in the benchmark prices together with fluctuations in the WCS heavy differential. The increase in royalty rates for the first quarter of 2019 from the fourth quarter of 2018 reflected significantly higher crude oil prices following the Government of Alberta mandatory curtailment program that came into effect January 1, 2019.

Natural gas royalty rates averaged approximately 4% of product sales for the first quarter of 2019 compared with 5% for the first quarter of 2018 and 3% for the fourth quarter of 2018.

Canadian Natural Resources Limited 14 Three Months Ended March 31, 2019

Offshore Africa

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

Royalty rates as a percentage of product sales averaged approximately 9% for the first quarter of 2019, compared with 6% of product sales for the first quarter of 2018 and 4% for the fourth quarter of 2018. 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
	Mar 31 2019		Dec 31 2018		Mar 31 2018
Crude oil and NGLs ($/bbl) (1)
North America	$	15.07	$	13.36	$	14.15
North Sea	$	39.68	$	44.20	$	43.39
Offshore Africa	$	9.79	$	32.15	$	30.99
Average	$	16.04	$	16.93	$	15.70
Natural gas ($/Mcf) (1)
North America	$	1.30	$	1.23	$	1.31
North Sea (2)	$	2.41	$	5.76	$	4.67
Offshore Africa (2)	$	2.12	$	3.00	$	2.44
Average	$	1.33	$	1.32	$	1.41
Average($/BOE) (1)	$	12.68	$	13.51	$	12.68

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

(2) North Sea and Offshore Africa natural gas production expense for the first quarter of 2019 reflected a decrease of $6 million ($2.28 per Mcf) and $1 million ($0.48 per Mcf) respectively, related to the adoption of IFRS 16.

North America

North America crude oil and NGLs production expense for the first quarter of 2019 of $15.07 per bbl increased7% from $14.15 per bbl for the first quarter of 2018 and increased13% from $13.36 per bbl for the fourth quarter of 2018. The increase in production expense per bbl for the first quarter of 2019 from the comparable periods reflected lower sales volumes due to the impact of the Government of Alberta mandated production curtailments that came into effect January 1, 2019 and higher fuel and energy costs, partially offset by the Company's continuous focus on cost control and achieving efficiencies across the entire asset base. North America crude oil and NGLs production expense for the first quarter of 2019 reflected a decrease of $5 million ($0.18 per bbl) related to the adoption of IFRS 16.

North America natural gas production expense for the first quarter of 2019 of $1.30 per Mcf was comparable with $1.31 per Mcf for the first quarter of 2018 and increased6% from $1.23 per Mcf for the fourth quarter of 2018. The increase in production expense for the first quarter of 2019 from the fourth quarter of 2018 primarily reflected the impact of seasonal conditions, partially offset by the Company's continuous focus on cost control and achieving efficiencies across the entire asset base. North America natural gas production expense for the first quarter of 2019 reflected a decrease of $1 million ($0.01 per Mcf) related to the adoption of IFRS 16.

North Sea

North Sea crude oil production expense for the first quarter of 2019decreased9% to $39.68 per bbl from $43.39 per bbl for the first quarter of 2018 and decreased10% from $44.20 per bbl for the fourth quarter of 2018. The decrease in production expense per bbl for the first quarter of 2019 from the comparable periods primarily reflected the impact of higher volumes on a relatively fixed cost base. North Sea crude oil production expense for the first quarter of 2019 reflected a decrease of $1 million ($0.31 per bbl) related to the adoption of IFRS 16.

Canadian Natural Resources Limited 15 Three Months Ended March 31, 2019

Offshore Africa

Offshore Africa crude oil production expense for the first quarter of 2019decreased by 68% to $9.79 per bbl from $30.99 per bbl for the first quarter of 2018 and decreased by 70% from $32.15 per bbl for the fourth quarter of 2018. The decrease in crude oil production expense for the first quarter of 2019 from the comparable periods primarily reflected the cessation of production at the Olowi field, Gabon in December 2018. Crude oil production expense for the Baobab and Espoir fields in Côte d'Ivoire was $10.14 per bbl for the first quarter of 2018 and $11.68 per bbl for the fourth quarter of 2018. Production expense in Côte d'Ivoire for the first quarter of 2019 reflected a decrease of $2 million ($1.71 per bbl) related to the adoption of IFRS 16.

Crude oil production expense in Offshore Africa was also impacted by the timing of liftings from the various fields, which have different cost structures, fluctuating production volumes on a relatively fixed cost base and fluctuations in the Canadian dollar.

DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION

	Three Months Ended
($ millions, except per BOE amounts)	Mar 31 2019		Dec 31 2018		Mar 31 2018
Expense	$	843	$	929	$	850
$/BOE (1)	$	15.54	$	15.50	$	14.66

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

The decrease in depletion, depreciation and amortization expense for the first quarter of 2019 from the comparable periods primarily reflected the impact of lower sales volumes in the first quarter of 2019, partially offset by an increase of $31 million related to the adoption of IFRS 16.

Depletion, depreciation and amortization expense per BOE for the first quarter of 2019increased6% to $15.54 per BOE from $14.66 per BOE for the first quarter of 2018 and was comparable with $15.50 per BOE for the fourth quarter of 2018. The increase in depletion, depreciation and amortization expense per BOE for the first quarter of 2019 from the comparable periods reflected the adoption of IFRS 16, partially offset by lower depletion rates in Offshore Africa and North America. Depletion, depreciation and amortization expense for the first quarter of 2019 reflected an increase of $0.57 per BOE related to the adoption of IFRS 16.

ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION

	Three Months Ended
($ millions, except per BOE amounts)	Mar 31 2019		Dec 31 2018		Mar 31 2018
Expense	$	28	$	31	$	31
$/BOE (1)	$	0.54	$	0.52	$	0.53

(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 first quarter of 2019 of $0.54 per BOE increased2% from $0.53 per BOE for the first quarter of 2018 and increased4% from $0.52 per BOE for the fourth quarter of 2018. The increase in asset retirement obligation accretion expense per BOE for the first quarter of 2019 from the comparable periods primarily reflected lower sales volumes during the first quarter of 2019.

Canadian Natural Resources Limited 16 Three Months Ended March 31, 2019

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 sites. Production in the first quarter of 2019 averaged 416,206 bbl/d, reflecting unplanned maintenance activities and the impact of the Government of Alberta mandated production curtailments that came into effect January 1, 2019. As a result of the mandated production curtailments, planned maintenance activities at Horizon were strategically advanced into the first quarter of 2019 from the second quarter of 2019. Through the Company's continuous focus on cost control and efficiencies, high utilization rates and reliability of operations, production costs averaged $21.46 per bbl during the quarter.

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

	Three Months Ended
($/bbl) (1)	Mar 31 2019		Dec 31 2018		Mar 31 2018
SCO realized sales price (2)	$	65.86	$	42.73	$	71.61
Bitumen value for royalty purposes (3)	$	48.16	$	29.93	$	31.48
Bitumen royalties (4)	$	2.31	$	2.03	$	1.98
Transportation	$	1.17	$	1.56	$	1.54

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

(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 for the Oil Sands Mining and Upgrading segment averaged $65.86 per bbl for the first quarter of 2019, a decrease of 8% from $71.61 per bbl for the first quarter of 2018 and an increase of 54% from $42.73 per bbl for the fourth quarter of 2018. The decrease in the realized SCO sales price for the first quarter of 2019 from the first quarter of 2018 primarily reflected WTI benchmark pricing. The increase in the realized SCO sales price for the first quarter of 2019 from the fourth quarter of 2018 primarily reflected the impact of the Government of Alberta mandated production curtailments that came into effect January 1, 2019.

Transportation expense for the Oil Sands Mining and Upgrading segment averaged $1.17 per bbl for the first quarter of 2019, compared with $1.54 per bbl for the first quarter of 2018 and $1.56 per bbl for the fourth quarter of 2018. Transportation expense for the first quarter of 2019 reflected a decrease of $14 million ($0.37 per bbl) related to the adoption of IFRS 16.

Canadian Natural Resources Limited 17 Three Months Ended March 31, 2019

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
($ millions)	Mar 31 2019		Dec 31 2018		Mar 31 2018
Production costs, excluding natural gas costs	$	779	$	773	$	835
Natural gas costs	43		24		38
Production costs	$	822	$	797	$	873

	Three Months Ended
($/bbl) (1)	Mar 31 2019		Dec 31 2018		Mar 31 2018
Production costs, excluding natural gas costs	$	20.33	$	19.37	$	20.45
Natural gas costs	1.13		0.60		0.92
Production costs	$	21.46	$	19.97	$	21.37
Sales (bbl/d)	425,790		433,970		453,850

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

Production costs for the first quarter of 2019 averaged $21.46 per bbl, comparable with $21.37 per bbl for the first quarter of 2018 and an increase of 7% from $19.97 per bbl for the fourth quarter of 2018. The increase in production costs per bbl for the first quarter of 2019 from the fourth quarter of 2018 primarily reflected lower production volumes due to unplanned maintenance activities and the impact of the Government of Alberta mandated production curtailments, together with higher fuel and energy costs. Production costs for the first quarter of 2019 reflected a decrease of $7 million ($0.17 per bbl) related to the adoption of IFRS 16.

DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING

	Three Months Ended
($ millions, except per bbl amounts)	Mar 31 2019		Dec 31 2018		Mar 31 2018
Expense	$	417	$	396	$	404
$/bbl (1)	$	10.88	$	9.92	$	9.88

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

Depletion, depreciation and amortization expense per bbl for the first quarter of 2019increased10% to $10.88 per bbl from $9.88 per bbl for the first quarter of 2018 and increased10% from $9.92 per bbl for the fourth quarter of 2018. The increase in depletion, depreciation and amortization expense per bbl for the first quarter of 2019 from the comparable periods was primarily due to the impact of fluctuations in sales volumes from different underlying operations, with a higher proportion of sales in the first quarter of 2019 subject to a higher depletion rate, compared to the previous periods. Depletion, depreciation and amortization expense for the first quarter of 2019 reflected an increase of $19 million ($0.49 per bbl) related to the adoption of IFRS 16.

Canadian Natural Resources Limited 18 Three Months Ended March 31, 2019

ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING

	Three Months Ended
($ millions, except per bbl amounts)	Mar 31 2019		Dec 31 2018		Mar 31 2018
Expense	$	16	$	15	$	15
$/bbl (1)	$	0.41	$	0.38	$	0.38

(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 of $0.41 per bbl for the first quarter of 2019increased8% from $0.38 per bbl for the first quarter of 2018 and the fourth quarter of 2018, primarily due to lower sales volumes.

MIDSTREAM AND REFINING

	Three Months Ended
($ millions)	Mar 31 2019			Dec 31 2018		Mar 31 2018
Revenue	$	21		$	24	$	27
Less:
Production expense	6			5		5
Depreciation	3			3		3
Equity loss from investment	60			—		1
Segment earnings (loss) before taxes	$	(48	)	$	16	$	18

The Company has a 50% interest in the Redwater Partnership. Redwater Partnership has entered into agreements to construct and operate a 50,000 barrel per day bitumen upgrader and refinery (the "Project") under processing agreements that target to process 12,500 barrels per day of bitumen feedstock for the Company and 37,500 barrels per day of bitumen feedstock for the Alberta Petroleum Marketing Commission (“APMC”), an agent of the Government of Alberta, under a 30 year fee-for-service tolling agreement.

During 2018, Redwater Partnership commenced commissioning activities in the Projects' light oil units while continuing work on the heavy oil units. In the first quarter of 2019, the light oil units transitioned from pre-commissioning and startup to operations and are processing SCO into refined products. The Project's bitumen refining operations have been delayed and remain in the commissioning phase due to design modifications to the reactor burners in the gasifier unit and to address stress cracking identified in certain stainless steel piping. Currently, the heavy oil units are expected to commence commercial processing of bitumen in late 2019. As at March 31, 2019, the total facility capital cost ("FCC") budget for the Project, net of margins from pre-commercial sales, totaled approximately $9,800 million.

During 2013, the Company and APMC agreed, each with a 50% interest, to provide subordinated debt, bearing interest at prime plus 6%, as required for Project costs to reflect an agreed debt to equity ratio of 80/20. As at March 31, 2019, each party has provided $439 million of subordinated debt, together with accrued interest thereon of $167 million, for a Company total of $606 million. Any additional subordinated debt financing is not expected to be significant.

Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt portion of the monthly cost of service toll, currently consisting of interest and fees, with principal repayments beginning in 2020. The Company is unconditionally obligated to pay this portion of the cost of service toll over the 30-year tolling period. As at March 31, 2019, the Company had recognized $81 million in prepaid cost of service tolls (December 31, 2018 – $62 million).

Redwater Partnership has a secured $3,500 million syndicated credit facility of which $2,000 million is revolving and matures in June 2021 and the remaining $1,500 million is fully drawn on a non-revolving basis and matures in February 2020. As at March 31, 2019, Redwater Partnership had borrowings of $2,288 million under the credit facility.

During the three months ended March 31, 2019, the Company recognized an equity loss from Redwater Partnership of $60 million (December 31, 2018 – $nil, March 31, 2018 – loss of $1 million). The equity loss for the first quarter of 2019 includes the impact of $47 million of interest expense and $12 million of depletion, depreciation and amortization expense recognized following the completion of commissioning and startup activities in the light oil units.

Canadian Natural Resources Limited 19 Three Months Ended March 31, 2019

ADMINISTRATION EXPENSE

	Three Months Ended
($ millions, except per BOE amounts)	Mar 31 2019		Dec 31 2018		Mar 31 2018
Expense	$	70	$	91	$	81
$/BOE (1)	$	0.76	$	0.91	$	0.82

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

Administration expense for the first quarter of 2019 of $0.76 per BOE decreased7% from $0.82 per BOE for the first quarter of 2018 and decreased16% from $0.91 per BOE for the fourth quarter of 2018. Administration expense per BOE decreased for the first quarter of 2019 from the comparable periods due to lower personnel and other corporate costs in the first quarter of 2019. Administration expense for the first quarter of 2019 reflected a decrease of $6 million ($0.06 per BOE) related to the adoption of IFRS 16.

SHARE-BASED COMPENSATION

	Three Months Ended
($ millions)	Mar 31 2019		Dec 31 2018			Mar 31 2018
Expense (recovery)	$	62	$	(148	)	$	(88	)

The Company’s Stock Option Plan provides current employees with the right to receive common shares or a cash payment in exchange for stock options surrendered.

The Company recorded a $62 million share-based compensation expense for the first quarter of 2019, 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 first quarter of 2019 was an expense of $10 million related to performance share units granted to certain executive employees (March 31, 2018 – $1 million). For the first quarter of 2019, the Company charged $1 million of share-based compensation costs to the Oil Sands Mining and Upgrading segment (March 31, 2018 – $13 million costs recovered).

INTEREST AND OTHER FINANCING EXPENSE

	Three Months Ended
($ millions, except per BOE amounts and interest rates)	Mar 31 2019		Dec 31 2018		Mar 31 2018
Expense, gross	$	211	$	198	$	205
Less: capitalized interest	20		19		15
Expense, net	$	191	$	179	$	190
$/BOE (1)	$	2.06	$	1.78	$	1.92
Average effective interest rate	4.1%		4.1%		3.8%

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

Gross interest and other financing expense for the first quarter of 2019 included an increase of $15 million due to interest expense on lease liabilities recognized due to the adoption of IFRS 16. Capitalized interest of $20 million for the first quarter of 2019 was primarily related to the Kirby North project and residual project activities at Horizon.

Net interest and other financing expense per BOE for the first quarter of 2019increased7% to $2.06 per BOE from $1.92 per BOE for the first quarter of 2018 and increased16% from $1.78 per BOE for the fourth quarter of 2018. The increase in net interest and other financing expense per BOE for the first quarter of 2019 from the comparable periods primarily reflected the adoption of IFRS 16. The increase from the fourth quarter of 2018 also reflected the impact of lower sales volumes in the first quarter of 2019. Net interest and other financing expense per BOE for the first quarter of 2019 reflected an increase of $0.17 per BOE related to the adoption of IFRS 16.

The Company’s average effective interest rate for the first quarter of 2019 increased from the first quarter of 2018 primarily due to the impact of higher benchmark interest rates on the Company's outstanding bank credit facilities.

Canadian Natural Resources Limited 20 Three Months Ended March 31, 2019

RISK MANAGEMENT ACTIVITIES

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

	Three Months Ended
($ millions)	Mar 31 2019			Dec 31 2018			Mar 31 2018
Crude oil and NGLs financial instruments	$	28		$	(27	)	$	—
Natural gas financial instruments	(1		)	2			—
Foreign currency contracts	—			(20		)	(19		)
Realized loss (gain)	27			(45		)	(19		)
Crude oil and NGLs financial instruments	5			41			—
Natural gas financial instruments	—			(6		)	—
Foreign currency contracts	9			(8		)	(33		)
Unrealized loss (gain)	14			27			(33		)
Net loss (gain)	$	41		$	(18	)	$	(52	)

During the first quarter of 2019, the net realized risk management loss was related to the settlement of crude oil and NGLs financial instruments. The Company recorded a net unrealized loss of $14 million ($13 million after-tax) on its risk management activities for the first quarter of 2019 (three months ended December 31, 2018 – unrealized loss of $27 million; $17 million after-tax; three months ended March 31, 2018 – unrealized gain of $33 million; $31 million after-tax).

Further details related to outstanding derivative financial instruments at March 31, 2019 are disclosed in note 15 to the Company’s unaudited interim consolidated financial statements.

FOREIGN EXCHANGE

	Three Months Ended
($ millions)	Mar 31 2019			Dec 31 2018			Mar 31 2018
Net realized (gain) loss	$	(6	)	$	(2	)	$	116
Net unrealized (gain) loss	(233		)	548			162
Net (gain) loss (1)	$	(239	)	$	546		$	278

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

The net realized foreign exchange gain for the first quarter of 2019 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling. The net unrealized foreign exchange gain for the first quarter of 2019 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 included the impact of cross currency swaps (three months ended March 31, 2019 – unrealized loss of $30 million, December 31, 2018 – unrealized gain of $76 million, March 31, 2018 – unrealized gain of $40 million). The US/Canadian dollar exchange rate at March 31, 2019 was US$0.7485 (December 31, 2018 – US$0.7328, March 31, 2018 – US$0.7751).

Canadian Natural Resources Limited 21 Three Months Ended March 31, 2019

INCOME TAXES

	Three Months Ended
($ millions, except income tax rates)	Mar 31 2019			Dec 31 2018			Mar 31 2018
North America (1)	$	163		$	(254	)	$	150
North Sea	29			8			1
Offshore Africa	12			11			5
PRT (2) – North Sea	(42		)	—			(4		)
Other taxes	3			1			2
Current income tax expense (recovery)	165			(234		)	154
Deferred corporate income tax expense	94			112			127
Deferred PRT (2) – North Sea	—			(1		)	10
Deferred income tax expense	94			111			137
	$	259		$	(123	)	$	291
Effective income tax rate on adjusted net earnings (loss) from operations (3)	26		%	33		%	24		%

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

(2) Petroleum Revenue Tax.

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

The effective income tax rate for the first quarter of 2019 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 PRT recovery in the North Sea for the first quarter of 2019 and comparable 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.

For 2019, current income tax expense is now targeted to range from $600 million to $800 million in Canada and $75 million to $100 million in the North Sea and Offshore Africa.

Canadian Natural Resources Limited 22 Three Months Ended March 31, 2019

NET CAPITAL EXPENDITURES ⁽¹⁾ 

	Three Months Ended
($ millions)	Mar 31 2019		Dec 31 2018			Mar 31 2018
Exploration and Evaluation
Net expenditures (proceeds)	$	33	$	(95	)	$	56
Property, Plant and Equipment
Net property acquisitions	24		1			162
Well drilling, completion and equipping	254		359			321
Production and related facilities	287		365			264
Capitalized interest and other (2)	29		32			23
Net expenditures	594		757			770
Total Exploration and Production	627		662			826
Oil Sands Mining and Upgrading
Project costs (3)	76		178			66
Sustaining capital	140		235			105
Turnaround costs	8		12			13
Capitalized interest and other (2)	10		(8		)	(5		)
Total Oil Sands Mining and Upgrading	234		417			179
Midstream and Refining	2		2			4
Abandonments (4)	108		93			90
Head office	6		7			4
Total net capital expenditures	$	977	$	1,181		$	1,103
By segment
North America	$	524	$	604		$	772
North Sea	36		58			35
Offshore Africa	67		—			19
Oil Sands Mining and Upgrading	234		417			179
Midstream and Refining	2		2			4
Abandonments (4)	108		93			90
Head office	6		7			4
Total	$	977	$	1,181		$	1,103

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

(2) Capitalized interest and other includes expenditures related to land acquisition and retention, seismic and other adjustments.

(3) Includes Horizon Phases 2/3 construction costs.

(4) Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table.

Canadian Natural Resources Limited 23 Three Months Ended March 31, 2019

Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities
	Three Months Ended
($ millions)	Mar 31 2019			Dec 31 2018		Mar 31 2018
Cash flows used in investing activities	$	1,029		$	1,042	$	1,369
Net change in non-cash working capital	(160		)	46		(335		)
Investment in other long-term assets	—			—		(21		)
Abandonment expenditures (1)	108			93		90
Net capital expenditures	$	977		$	1,181	$	1,103

(1) The Company excludes abandonment expenditures from “Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities” in the "Financial Highlights" section of this MD&A.

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 first quarter of 2019 were $977 million compared with $1,103 million for the first quarter of 2018 and $1,181 million for the fourth quarter of 2018. Net capital expenditures for the first quarter of 2019 were consistent with the Company's previously announced capital allocation schedule.

Drilling Activity ⁽¹⁾  

	Three Months Ended
(number of wells)	Mar 31 2019	Dec 31 2018	Mar 31 2018
Net successful natural gas wells	8	3	5
Net successful crude oil wells (2)	30	102	122
Dry wells	1	2	2
Stratigraphic test / service wells	332	91	450
Total	371	198	579
Success rate (excluding stratigraphic test / service wells)	97%	98%	98%

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

(2) Includes bitumen wells.

North America

During the first quarter of 2019, the Company targeted 9 net natural gas wells, 7 net primary heavy crude oil wells and 21 net light crude oil wells.

North Sea

During the first quarter of 2019, the Company completed one gross light crude oil well (1.0 on a net basis) in the North Sea.

Offshore Africa

During the first quarter of 2019, the Company completed one gross light crude oil well and one gross injection well (combined 1.2 on a net basis) at Baobab.

Canadian Natural Resources Limited 24 Three Months Ended March 31, 2019

LIQUIDITY AND CAPITAL RESOURCES

($ millions, except ratios)	Mar 31 2019		Dec 31 2018			Mar 31 2018
Working capital (1)	$	319	$	(601	)	$	702
Long-term debt (2) (3)	$	20,990	$	20,623		$	21,978
Less: cash and cash equivalents	90		101			152
Long-term debt, net	$	20,900	$	20,522		$	21,826
Share capital	$	9,358	$	9,323		$	9,264
Retained earnings	22,852		22,529			22,785
Accumulated other comprehensive income (loss)	58		122			(23		)
Shareholders’ equity	$	32,268	$	31,974		$	32,026
Debt to book capitalization (3) (4)	39.3%		39.1%			40.5%
Debt to market capitalization (3) (5)	32.2%		34.1%			30.5%
After-tax return on average common shareholders’ equity (6)	9.2%		8.0%			8.7%
After-tax return on average capital employed (3) (7)	6.6%		5.9%			6.0%

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

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

(3) Long-term debt is stated at its carrying value, net of fair value adjustments, 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 for the twelve month trailing period.

As at March 31, 2019, 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 “Risks and Uncertainties” section of the Company's annual MD&A for the year ended December 31, 2018. 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 the conditions of the market. The Company continues to believe that 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;

▪ 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;

▪ Reviewing the Company's borrowing capacity:

◦ Borrowings under the 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 March 31, 2019, the non-revolving term credit facilities were fully drawn.

Canadian Natural Resources Limited 25 Three Months Ended March 31, 2019

◦ Each of the $2,425 million revolving syndicated 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 these 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.

◦ 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 bank credit facilities for amounts outstanding under this program.

◦ In July 2017, the Company filed base shelf prospectuses that allow for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada and US$3,000 million of debt securities in the United States, which expire in August 2019. 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.

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

▪ 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.

As at March 31, 2019, the Company had in place revolving bank credit facilities of $4,976 million, of which $4,142 million was available. Additionally, the Company had in place fully drawn term credit facilities of $4,750 million. This excludes certain other dedicated credit facilities supporting letters of credit.

As at March 31, 2019, the Company had total US dollar denominated debt with a carrying amount of $14,835 million (US$11,106 million), before transaction costs and original issue discounts. This included $6,015 million (US$4,506 million) hedged by way of cross currency swaps (US$1,050 million) and foreign currency forwards (US$3,456 million). The fixed repayment amount of these hedging instruments is $5,760 million, resulting in a notional reduction of the carrying amount of the Company’s US dollar denominated debt by approximately $255 million to $14,580 million as at March 31, 2019.

Net long-term debt was $20,900 million at March 31, 2019, resulting in a debt to book capitalization ratio of 39.3% (December 31, 2018 – 39.1%); 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 is 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 March 31, 2019 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 March 31, 2019, the Company was in compliance with this covenant.

The Company periodically utilizes commodity derivative financial instruments under its commodity hedge policy to reduce the risk of volatility in commodity prices and to support the Company’s cash flow for its capital expenditure programs. This policy currently allows for the hedging of up to 60% of the near 12 months budgeted production and up to 40% of the following 13 to 24 months estimated production. For the purpose of this policy, the purchase of put options is in addition to the above parameters. As at March 31, 2019, 8,000 bbl/d of currently forecasted crude oil volumes were hedged using WCS differential swaps for April to September 2019, as well as 115,000 GJ/d of currently forecasted natural gas volumes using AECO fixed price swaps for April to October 2019. Further details related to the Company’s commodity derivative financial instruments outstanding at March 31, 2019 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)	$	1,667	$	6,689	$	5,101	$	7,647
Other long-term liabilities (2)	$	260	$	200	$	390	$	857
Interest and other financing expense (3)	$	909	$	768	$	1,760	$	5,255

(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, $211 million; one to less than two years, $176 million; two to less than five years, $345 million; and thereafter, $857 million.

(3) Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates as at March 31, 2019.

Canadian Natural Resources Limited 26 Three Months Ended March 31, 2019

Share Capital

As at March 31, 2019, there were 1,197,653,000 common shares outstanding (December 31, 2018 – 1,201,886,000 common shares) and 53,353,000 stock options outstanding. As at May 7, 2019, the Company had 1,194,744,000 common shares outstanding and 51,970,000 stock options outstanding.

On March 6, 2019, the Board of Directors approved an increase in the quarterly dividend to $0.375 per common share, beginning with the dividend payable on April 1, 2019 (previous quarterly dividend rate of $0.335 per common share). The dividend policy undergoes periodic review by the Board of Directors and is subject to change.

On May 16, 2018, 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 61,454,856 common shares, over a 12-month period commencing on May 23, 2018 and ending May 22, 2019.

For the three months endedMarch 31, 2019, the Company purchased for cancellation 6,650,000 common shares at a weighted average price of $36.24 per common share for a total cost of $241 million. Retained earnings were reduced by $189 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to March 31, 2019, the Company purchased 4,050,000 common shares at a weighted average price of $39.34 per common share for a total cost of $159 million.

COMMITMENTS AND CONTINGENCIES

In the normal course of business, the Company has various commitments that will have an impact on the Company’s future operations. The following table summarizes the Company’s commitments as at March 31, 2019⁽¹⁾:

	Remaining 2019		2020		2021		2022		2023		Thereafter
Product transportation	$	416	$	544	$	516	$	445	$	325	$	3,436
North West Redwater Partnership service toll (2)	$	57	$	126	$	157	$	158	$	157	$	2,858
Offshore vessels and equipment	$	63	$	81	$	65	$	9	$	—	$	—
Field equipment and power	$	26	$	20	$	21	$	20	$	21	$	274
Other	$	37	$	20	$	19	$	16	$	16	$	47

(1) Subsequent to adoption of IFRS 16, the Company reports its payments for lease liabilities in the maturity table in the 'Liquidity and Capital Resources' section of this MD&A.

(2) Pursuant to the processing agreements, on June 1, 2018 the Company began paying its 25% pro rata share of the debt portion of the monthly cost of service toll, currently consisting of interest and fees, with principal repayments beginning in 2020. Included in the cost of service toll is $1,272 million of interest payable over the 30 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.

CHANGES IN ACCOUNTING POLICIES

For the impact of new accounting standards, including the adoption of IFRS 16 "Leases", refer also to the audited consolidated financial statements for the year ended December 31, 2018 and the unaudited interim financial statements for the three months endedMarch 31, 2019.

IFRS 16 "Leases"

In January 2016, the IASB issued IFRS 16 “Leases”, which provides guidance on accounting for leases. The new standard replaced IAS 17 “Leases” and related interpretations. IFRS 16 eliminates the distinction between operating leases and financing leases for lessees and generally requires balance sheet recognition for all leases. Certain short-term (less than 12 months) and low-value leases (as defined in the standard) are exempt from the requirements, and the Company continues to treat these leases as expenses. Leases to explore for or use crude oil, natural gas, minerals and similar non-regenerative resources are also exempt from the standard.

Canadian Natural Resources Limited 27 Three Months Ended March 31, 2019

The Company adopted IFRS 16 on January 1, 2019 using the modified retrospective approach with no impact to opening retained earnings at the date of adoption. In accordance with the transitional provisions in the standard, balances reported in the comparative periods have not been restated and continue to be reported using the Company's previous accounting policy under IAS 17.

On adoption, the Company applied the following practical expedients under the standard. Certain expedients are on a lease-by-lease basis and others are applicable by class of underlying assets:

• the use of a single discount rate to a portfolio of leases with reasonably similar characteristics;

• leases with a remaining lease term of less than twelve months as at January 1, 2019 were treated as short-term leases;

• exclusion of indirect costs for the measurement of lease assets at the date of initial application; and

• the application of the Company's previous assessment for onerous contracts under IAS 37, instead of re-assessing impairment on the Company's lease assets as at January 1, 2019.

The Company did not apply any practical expedients pertaining to grandfathering of leases assessed under the previous standard.

In connection with the adoption of IFRS 16, the Company recognized lease liabilities (included in other long-term liabilities) of $1,539 million, measured at the present value of the remaining lease payments, discounted at the Company’s incremental borrowing rate at the transition date. Lease assets were measured at an amount equal to the lease liability. The adoption of IFRS 16 resulted in increases in depletion, depreciation and amortization expense and interest expense and corresponding decreases in production, transportation and administration expenses. Under the new standard, the Company reports cash outflows for payment of the principal portion of the lease liability as cash flows from financing activities. The interest portion of the lease payments is classified as cash flows from operating activities.

For further details of the Company's lease assets and lease liabilities on transition to the new Leases standard at January 1, 2019 and as at March 31, 2019 refer to the audited consolidated financial statements for the year ended December 31, 2018 and the unaudited interim financial statements for the three months endedMarch 31, 2019.

The impacts of the adoption of IFRS 16 are discussed within the respective sections of this MD&A. The most significant impacts of the adoption of the new Leases standard are as follows:

• Cash flow from operating activities and adjusted funds flow increased as the principal portion of lease payments, previously classified as cash flows from operating activities is now reported as an investing activity;

• Increased depletion, depreciation and amortization expense and interest expense;

• Decreased production expense, transportation expense and administration expense; and

• Commitments for leases, previously reported in the "Commitments and Contingencies" section of this MD&A, are now reported in the maturity table in the 'Liquidity and Capital Resources' section of this MD&A.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the application of IFRS that have a significant impact on the financial results of the Company. Actual results could differ from estimated amounts, and those differences may be material. A comprehensive discussion of the Company's significant accounting estimates is contained in the MD&A and the audited consolidated financial statements for the year ended December 31, 2018.

CONTROL ENVIRONMENT

There have been no changes to internal control over financial reporting (“ICFR”) during the three months endedMarch 31, 2019 that have materially affected, or are reasonably likely to materially affect the Company’s ICFR. Based on 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 28 Three Months Ended March 31, 2019