Canadian Natural Resources Limited Announces 2020 Third Quarter Results

Rhea-AI Summary

Canadian Natural reported strong Q3 2020 results, achieving net earnings of $408 million, a significant increase from a loss in Q2. The company maintained production volumes, particularly liquids production, which rose to 494,952 bbl/d. Canadian Natural's operating cost savings target is $745 million for 2020, and it generated $1.74 billion in adjusted funds flow. The acquisition of Painted Pony Energy complements its asset base, boosting natural gas production forecasts to over 1.6 Bcf/d in Q4. Financial resilience is highlighted by a $1.1 billion reduction in net debt and a robust liquidity position of $4.2 billion.

Positive

• Achieved net earnings of $408 million in Q3 2020, up from a loss in Q2 2020.
• Increased liquids production to 494,952 bbl/d, a 20% rise from Q2 2020.
• Generated $1.74 billion in adjusted funds flow, reflecting a 319% increase over Q2 2020.
• Reduced net debt by $1.1 billion, strengthening the balance sheet.
• Maintained significant liquidity of approximately $4.2 billion as of September 30, 2020.

Negative

• Crude oil and NGLs production saw a 5% decrease from Q3 2019 levels.
• Oil Sands Mining and Upgrading segment experienced production declines due to planned maintenance.

CALGARY, Alberta, Nov. 05, 2020 (GLOBE NEWSWIRE) -- Canadian Natural's President, Tim McKay, commented on the third quarter results stating "The resilience of our business model, as witnessed in our third quarter 2020 results, demonstrates Canadian Natural's competitive advantage as the strength of our long life low decline asset base allows the Company to effectively manage through commodity price cycles while preserving net asset value. Canadian Natural is focused on continuous improvement and is on track for the targeted operating cost savings in 2020 of approximately $745 million dollars. With a disciplined capital program in 2020 of approximately $2.7 billion, we have been able to maintain our production volumes, grow our dividend and keep a strong balance sheet.

In the third quarter, we increased liquids production from our North America Exploration and Production ("E&P") assets by approximately 20% from Q2/20 levels to 494,952 bbl/d and achieved record daily thermal in situ production in the quarter of 287,978 bbl/d, while achieving low thermal operating costs of $7.85/bbl (US$5.89/bbl). These results were achieved as we successfully executed on our curtailment optimization strategy while we conducted planned maintenance and turnaround activities in our Oil Sands Mining and Upgrading segment.

Environmental, Social and Governance ("ESG") performance remains a priority and investments in improving environmental performance and reducing our environmental footprint continue in the current pricing environment. We recently released our 2019 Report to Stakeholders, which highlights our commitment to ESG excellence and reducing our environmental footprint.

Subsequent to quarter end, the acquisition of Painted Pony Energy Ltd. ("Painted Pony") closed on October 6, 2020. With a significant amount of pre-built infrastructure, these high quality assets in the Townsend areas of Northeast British Columbia complement our already high quality natural gas asset base in Western Canada. The Company’s natural gas production, targeted at over 1.6 Bcf/d in the fourth quarter, and associated natural gas liquids is forecast to generate approximately $1.2 billion in annualized operating cash flow at current strip pricing."

Canadian Natural's Chief Financial Officer, Mark Stainthorpe, added, "Our unique and diversified asset base allows us to generate significant free cash flow above our disciplined capital program and maintain our dividend payment level, unchanged through the commodity price cycle. In the third quarter, we generated approximately $1.74 billion in adjusted funds flow and approximately $467 million in free cash flow, after capital expenditures and dividend payments, reflecting the flexibility and strength of our long life low decline asset base.

The Company maintains a flexible and disciplined capital allocation strategy, with a focus on maintaining a strong and resilient financial position throughout the commodity price cycle. In the third quarter we allocated our free cash flow to the balance sheet, contributing to a significant reduction in net debt of approximately $1.1 billion. Including committed and undrawn credit facilities, cash balances and short-term investments, the Company had significant liquidity available at September 30, 2020 of approximately $4.2 billion.

Our effective and efficient operations along with our low cost structure drives our industry leading break-even of WTI US$30-$31 per barrel to cover sustaining capital and current dividend payment levels. Our low break-even maximizes netbacks, ultimately increasing free cash flow and creating value for our shareholders."

QUARTERLY HIGHLIGHTS

			Three Months Ended													Nine Months Ended
($ millions, except per common share amounts)			Sep 30 2020				Jun 30 2020				Sep 30 2019					Sep 30 2020				Sep 30 2019
Net earnings (loss)			$	408			$	(310	)		$	1,027				$	(1,184	)		$	4,819
Per common share	– basic		$	0.35			$	(0.26	)		$	0.87				$	(1.00	)		$	4.04
	– diluted		$	0.35			$	(0.26	)		$	0.87				$	(1.00	)		$	4.03
Adjusted net earnings (loss) from operations (1)			$	135			$	(772	)		$	1,229				$	(932	)		$	3,109
Per common share	– basic		$	0.11			$	(0.65	)		$	1.04				$	(0.79	)		$	2.61
	– diluted		$	0.11			$	(0.65	)		$	1.04				$	(0.79	)		$	2.60
Cash flows from (used in) operating activities			$	2,070			$	(351	)		$	2,518				$	3,444			$	6,375
Adjusted funds flow (2)			$	1,740			$	415			$	2,881				$	3,492			$	7,773
Per common share	– basic		$	1.47			$	0.35			$	2.43				$	2.96			$	6.51
	– diluted		$	1.47			$	0.35			$	2.43				$	2.96			$	6.50
Cash flows used in investing activities			$	643			$	693			$	908				$	2,195			$	6,401
Net capital expenditures (3)			$	771			$	421			$	963				$	2,030			$	6,065
Daily production, before royalties
Natural gas (MMcf/d)			1,362				1,462				1,469					1,421				1,504
Crude oil and NGLs (bbl/d)			884,342				921,895				931,546					914,859				829,031
Equivalent production (BOE/d) (4)			1,111,286				1,165,487				1,176,361					1,151,693				1,079,641

⁽¹⁾ Adjusted net earnings (loss) from operations is a non-GAAP measure that the Company utilizes to evaluate its performance, as it demonstrates the Company’s ability to generate after-tax operating earnings from its core business areas. The derivation of this measure is discussed in the "Advisory" section of this press release.

⁽²⁾ Adjusted funds flow is a non-GAAP measure that the Company considers key to evaluate 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 derivation of this measure is discussed in the "Advisory" section of this press release.

⁽³⁾ Net capital expenditures is a non-GAAP measure that the Company considers a key measure as it provides an understanding of the Company’s capital spending activities in comparison to the Company's annual capital budget. For additional information and details, refer to the net capital expenditures table in the "Advisory" section of this press release.

⁽⁴⁾ A barrel of oil equivalent (“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.

• Net earnings of $408 million and adjusted net earnings of $135 million were realized in Q3/20, a significant improvement over Q2/20 levels. The increases in net earnings and adjusted net earnings are primarily a result of strong production volumes, continued reduction in operating cost levels and improved commodity prices in Q3/20.
• Cash flows from operating activities were $2,070 million in Q3/20, a significant increase over Q2/20 levels.
• Canadian Natural generated quarterly adjusted funds flow of $1,740 million in Q3/20, an increase of 319% over Q2/20 levels, driven by the Company's effective and efficient operations as well as higher commodity prices in the quarter.
• Canadian Natural generated approximately $467 million in free cash flow in Q3/20, after net capital expenditures of $771 million and dividend payments of $502 million in the quarter, reflecting the strength of the Company's effective and efficient operations and its high quality, long life low decline asset base.
• Canadian Natural maintained a strong financial position in Q3/20 and reduced net debt by approximately $1.1 billion, from Q2/20 levels.
  
  • The Company had significant liquidity available at September 30, 2020 of approximately $4.2 billion, including committed and undrawn credit facilities, cash balances and short-term investments.
• The Company effectively executed on its curtailment optimization strategy by utilizing its high quality, flexible asset base to maximize production to offset the previously announced maintenance and turnaround activities in the Oil Sands Mining and Upgrading segment.
• In Q3/20, the Company achieved quarterly production volumes of 1,111,286 BOE/d, including liquids production of 884,342 bbl/d which decreased as expected 5% and 4% from Q3/19 and Q2/20 levels respectively. The decrease was due to the planned maintenance and turnaround activities in the Oil Sands Mining and Upgrading segment, primarily offset by strong thermal in situ production as a result of the Company's curtailment optimization strategy and improved commodity pricing in Q3/20.
• Canadian Natural's North America Exploration and Production ("E&P") liquids production averaged 494,952 bbl/d in Q3/20, a 10% increase from Q3/19 levels and a 20% increase from Q2/20 levels. The increase over both periods was due to the Company's curtailment optimization strategy, primarily as a result of increased thermal in situ production at Kirby North and Jackfish as well as the optimization of steam cycles at Primrose.
  • Canadian Natural's continued focus on delivering effective and efficient operations and cost control across its entire asset base was also demonstrated as the Company's North American E&P liquids, including thermal in situ operations, achieved operating costs of $9.80/bbl (US$7.36/bbl) in Q3/20, a decrease of 17% from Q3/19 levels and a decrease of 16% from Q2/20 levels.
• Canadian Natural's thermal in situ assets achieved record daily production levels in Q3/20, averaging 287,978 bbl/d, an increase of 40% and 35% over Q3/19 and Q2/20 levels respectively. The record daily production levels in Q3/20 was as a result of the Company leveraging the flexibility of its thermal in situ assets to maximize production during planned maintenance and turnaround activities in the Company's Oil Sands Mining and Upgrading segment as a part of the Company's curtailment optimization strategy.
  • Thermal in situ achieved low operating costs in Q3/20, averaging $7.85/bbl (US$5.89/bbl), a decrease of 20% and 23% from Q3/19 and Q2/20 levels respectively. The decrease in unit operating costs was primarily due to higher production volumes and continued focus on effective and efficient operations.
  • Kirby North had strong quarterly production of approximately 42,400 bbl/d in Q3/20, and has been producing above its nameplate capacity of 40,000 bbl/d since achieving full ramp-up in June 2020.
  • At Jackfish, the Company achieved quarterly production of 122,346 bbl/d in Q3/20, a record quarterly production level since acquiring the asset in June 2019.
    
• The Company's world class Oil Sands Mining and Upgrading assets averaged 350,633 bbl/d of SCO production in Q3/20, decreasing by 19% and 24% from Q3/19 and Q2/20 levels respectively, primarily due to planned maintenance and turnaround activities at both the Athabasca Oil Sands Project ("AOSP") and Horizon.
  • Operating costs from the Company's Oil Sands Mining and Upgrading assets averaged $23.81/bbl (US$17.88/bbl) of SCO in Q3/20 and remain industry leading, driven by the Company's continued focus on cost control.
• A strategic advantage of Canadian Natural is its flexible portfolio of assets, allowing the Company to allocate capital to its highest return projects, maximizing value for the Company's shareholders. As a result of improved natural gas prices, Canadian Natural has strategically reallocated a portion of its capital program to its high value, liquids rich natural gas assets at Septimus and the assets recently acquired as part of the Painted Pony Energy Ltd. ("Painted Pony") acquisition. As one of the largest natural gas producers in Canada, the Company's natural gas assets provide significant value. The Company's natural gas production, targeted at over 1.6 Bcf/d in Q4/20, and associated natural gas liquids is forecast to generate approximately $1.2 billion in annualized operating cash flow at current strip pricing.
  • Canadian Natural drilled seven wells at Septimus in Q3/20, with one additional well drilled subsequent to quarter end. All eight wells are expected to be on production in Q4/20 at a targeted rate of 41 MMcf/d and 2,500 bbl/d of NGLs, for a cost of approximately $5,000 per flowing BOE.
  • Subsequent to quarter end, in October 2020, Canadian Natural initiated drilling the first of seven wells on the high quality Montney lands acquired with the Painted Pony acquisition. These wells are expected to come on production in the first half of 2021 at a targeted initial rate of 54 MMcf/d and 440 bbl/d of NGLs.
• Canadian Natural targets to release its 2021 capital and operational budget in December 2020.

OPERATIONS REVIEW AND CAPITAL ALLOCATION

Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural’s production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and Synthetic Crude Oil ("SCO") (herein collectively referred to as “crude oil”) and natural gas and NGLs. This balance provides optionality for capital investments, maximizing value for the Company’s shareholders.

Underpinning this asset base is long life low decline production, representing approximately 79% of the Company's total liquids production in Q3/20, the majority of which is zero decline high value SCO production from the Company's world class Oil Sands Mining and Upgrading assets. The remaining balance of long life low decline production comes from Canadian Natural's top tier thermal in situ oil sands operations and the Company's Pelican Lake heavy crude oil assets. The combination of long life low decline, low reserves replacement cost, and effective and efficient operations, results in substantial and sustainable adjusted funds flow throughout the commodity price cycle.

In addition, Canadian Natural maintains a substantial inventory of low capital exposure projects within the Company's conventional asset base. These projects can be executed quickly and, in the right economic conditions, provide excellent returns and maximize value for shareholders. Supporting these projects is the Company’s undeveloped land base which enables large, repeatable drilling programs that can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control major components of the Company's operating costs and minimize production commitments. Low capital exposure projects can be quickly stopped or started depending upon success, market conditions or corporate needs.

Canadian Natural’s balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.

Drilling Activity	Nine Months Ended Sep 30
	2020				2019
(number of wells)	Gross		Net		Gross		Net
Crude oil	43		37		80		74
Natural gas	25		21		21		15
Dry	—		—		3		3
Subtotal	68		58		104		92
Stratigraphic test / service wells	426		372		411		358
Total	494		430		515		450
Success rate (excluding stratigraphic test / service wells)			100	%			97	%

• The Company's total crude oil and natural gas drilling program of 58 net wells for the nine months ended September 30, 2020, excluding stratigraphic/service wells, represents a decrease of 34 net wells from the same period in 2019.

North America Exploration and Production

Crude oil and NGLs – excluding Thermal In Situ Oil Sands
	Three Months Ended					Nine Months Ended
	Sep 30 2020	Jun 30 2020		Sep 30 2019		Sep 30 2020		Sep 30 2019
Crude oil and NGLs production (bbl/d)	206,974	200,699		244,267		212,064		234,944
Net wells targeting crude oil	—	2		33		30		70
Net successful wells drilled	—	2		33		30		68
Success rate	—	100	%	100	%	100	%	97	%

• Canadian Natural's North America E&P crude oil and NGL production volumes, excluding the Company's thermal in situ operations, averaged 206,974 bbl/d, a decrease of 15% from Q3/19 levels and an increase of 3% from Q2/20 levels. The decrease from Q3/19 reflects natural declines and limited investment, while the increase over Q2/20 reflects the reinstatement of production as a result of the Company curtailing production in Q2/20 due to low commodity prices.
  • Primary heavy crude oil production averaged 70,982 bbl/d in Q3/20, a decrease of 19% from Q3/19 levels and an increase of 13% from Q2/20 levels. The decrease in production relative to Q3/19 was due to natural field declines and low levels of field activity due to the Government of Alberta's curtailment rules. The increase from Q2/20 was due to the reinstatement of previously shut-in production as a result of improved commodity prices in Q3/20.
    • Operating costs in the Company's primary heavy crude oil operations in Q3/20 averaged $15.96/bbl (US$11.98/bbl), a 7% decrease from Q3/19 levels and an 11% decrease from Q2/20 levels as the Company focused on cost control.
  • Pelican Lake production averaged 56,392 bbl/d in Q3/20, a decrease of 6% from Q3/19 levels and a slight increase from Q2/20 levels. The decrease from Q3/19 levels reflects the field's low natural decline rate, while the slight increase from Q2/20 levels was primarily due to reduced well servicing activity in Q2/20 due to low commodity prices.
    • The Company continues to demonstrate effective and efficient operations as Q3/20 operating costs at Pelican Lake averaged $5.76/bbl (US$4.32/bbl), a decrease of 6% from Q3/19 levels and a decrease of 9% from Q2/20 levels, reflecting the Company's continued focus on cost control.
  • North American light crude oil and NGL production averaged 79,600 bbl/d in Q3/20, a decrease of 17% and 3% from Q3/19 and Q2/20 levels respectively. The decrease from Q3/19 was a result of natural field declines. The decrease from Q2/20 was primarily a result of natural field declines and deferral of maintenance activities into Q3/20 as a result of COVID-19.
    • Operating costs in the Company's North America light crude oil and NGL areas averaged $14.13/bbl (US$10.61/bbl) in Q3/20, a decrease of 6% and 2% from Q3/19 and Q2/20 levels respectively as a result of the Company's continued focus on cost control.

Thermal In Situ Oil Sands
	Three Months Ended			Nine Months Ended
	Sep 30 2020	Jun 30 2020	Sep 30 2019	Sep 30 2020		Sep 30 2019
Bitumen production (bbl/d)	287,978	212,807	206,395	243,193		137,124
Net wells targeting bitumen	—	—	—	6		—
Net successful wells drilled	—	—	—	6		—
Success rate	—	—	—	100	%	—

• Canadian Natural's thermal in situ assets achieved record daily production levels in Q3/20, averaging 287,978 bbl/d, an increase of 40% and 35% over Q3/19 and Q2/20 levels respectively. The record daily production levels in Q3/20 was as a result of the Company leveraging the flexibility of its thermal in situ assets to maximize production during planned maintenance and turnaround activities in the Company's Oil Sands Mining and Upgrading segment as a part of the Company's curtailment optimization strategy.
  • Thermal in situ achieved low operating costs in Q3/20, averaging $7.85/bbl (US$5.89/bbl), a decrease of 20% and 23% from Q3/19 and Q2/20 levels respectively. The decrease in unit operating costs was primarily due to higher production volumes and continued focus on effective and efficient operations.
  • Kirby North had strong quarterly production of approximately 42,400 bbl/d in Q3/20, and has been producing above its nameplate capacity of 40,000 bbl/d since achieving full ramp-up in June 2020.
  • At Jackfish, the Company achieved quarterly production of 122,346 bbl/d in Q3/20, a record quarterly production level since acquiring the asset in June 2019.
• The Company continues to see positive results from its targeted two year solvent enhanced oil recovery technology pilot at Kirby South, with increased bitumen production, a SOR reduction of up to 50%, Greenhouse Gas ("GHG") intensity reduction of up to 50% and high solvent recovery. The Company will continue to monitor the solvent recovery of the pilot over the next year. This technology has the potential for application throughout the Company's extensive thermal in situ asset base. At Primrose, in the steam flood area, the Company is targeting to commence a second solvent pilot in the latter half of 2021.

North America Natural Gas
	Three Months Ended						Nine Months Ended
	Sep 30 2020		Jun 30 2020		Sep 30 2019		Sep 30 2020		Sep 30 2019
Natural gas production (MMcf/d)	1,340		1,431		1,425		1,393		1,454
Net wells targeting natural gas	9		1		5		21		16
Net successful wells drilled	9		1		5		21		15
Success rate	100	%	100	%	100	%	100	%	94	%

• North America natural gas production averaged 1,340 MMcf/d in Q3/20, a decrease of 6% from both Q3/19 and Q2/20 levels. The decrease in production was primarily as a result of natural field declines and planned maintenance and turnaround activities undertaken in the third quarter of 2020, partially offset by natural gas volumes added through low cost opportunities identified by the Company in May 2020.
  • Through additional cost efficiencies, the Company now targets to bring on these highly economic incremental volumes for less than $2,000 per flowing BOE, approximately $1,000 per flowing BOE lower than previously estimated. Current production from these additional gas volumes is 58 MMcf/d and the Company is on track to achieve annualized production of approximately 35 MMcf/d from these opportunities.
• North America natural gas operating costs were strong in Q3/20, averaging $1.14/Mcf, an increase of 7% and 3% from Q3/19 and Q2/20 levels respectively. The increase in operating costs relative to prior periods reflects lower production volumes in Q3/20. As a result of the Company's strategy to own and control its infrastructure and its continued focus on cost control, natural gas operating costs for the first nine months of 2020 were comparable to the first nine months of 2019.
• Operating costs at Septimus remained strong, averaging $0.28/Mcfe in Q3/20, a 10% decrease from Q2/20 levels.
• A strategic advantage of Canadian Natural is its flexible portfolio of assets, allowing the Company to allocate capital to its highest return projects, maximizing value for the Company's shareholders. As a result of improved natural gas prices, Canadian Natural has strategically reallocated a portion of its capital program to its high value, liquids rich natural gas assets at Septimus and the assets recently acquired as part of the Painted Pony acquisition. The Company's natural gas production, targeted at over 1.6 Bcf/d in Q4/20, and associated natural gas liquids is forecast to generate approximately $1.2 billion in annualized operating cash flow at current strip pricing.
  • Canadian Natural drilled seven wells at Septimus in Q3/20, with one additional well drilled subsequent to quarter end. All eight wells are expected to be on production in Q4/20 at a targeted rate of 41 MMcf/d and 2,500 bbl/d of NGLs, for a cost of approximately $5,000 per flowing BOE.
  • Subsequent to quarter end, in October 2020, Canadian Natural initiated drilling the first of seven wells on the high quality Montney lands acquired with the Painted Pony acquisition. These wells are expected to come on production in the first half of 2021 at a targeted initial rate of 54 MMcf/d and 440 bbl/d of NGLs.
• In Q3/20, Canadian Natural used the equivalent of approximately 49% of corporate annual natural gas production within its operations, providing a natural hedge from Western Canadian natural gas prices. Approximately 34% was exported to other North American markets and sold internationally, while the remaining 17% was exposed to AECO/Station 2 pricing.

International Exploration and Production

	Three Months Ended				Nine Months Ended
	Sep 30 2020	Jun 30 2020	Sep 30 2019		Sep 30 2020		Sep 30 2019
Crude oil production (bbl/d)
North Sea	21,220	26,627	27,454		25,186		26,927
Offshore Africa	17,537	17,444	21,227		16,977		22,341
Natural gas production (MMcf/d)
North Sea	5	15	20		14		24
Offshore Africa	17	16	24		14		26
Net wells targeting crude oil	—	—	3.0		1.0		5.5
Net successful wells drilled	—	—	3.0		1.0		5.5
Success rate	—	—	100	%	100	%	100	%

• International E&P crude oil production volumes averaged 38,757 bbl/d in Q3/20, a decrease of 20% and 12% from Q3/19 and Q2/20 levels respectively.
  • In the North Sea, crude oil production volumes averaged 21,220 bbl/d in Q3/20, a decrease of 23% and 20% from Q3/19 and Q2/20 levels respectively. The decrease in production in Q3/20 was primarily a result of planned maintenance and turnaround activities, the permanent cessation of production from the Banff and Kyle fields and natural field declines.
    • Crude oil operating costs in the North Sea increased by 13% and 48% from Q3/19 and Q2/20 levels respectively, averaging $42.10/bbl (US$31.61/bbl) in Q3/20. The increase in operating costs from the comparable periods primarily reflects lower production volumes on a relatively fixed cost base, together with the timing of liftings from various fields that have different cost structures.
  • Offshore Africa crude oil production volumes averaged 17,537 bbl/d in Q3/20, a decrease of 17% from Q3/19 levels and comparable to Q2/20 levels. The decrease in production from Q3/19 levels was primarily due to natural field declines.
    • Offshore Africa crude oil operating costs averaged $16.41/bbl (US$12.32/bbl) in Q3/20, an increase of 48% and 55% from Q3/19 and Q2/20 levels respectively. The increase in operating costs from the comparable periods was primarily due to the timing of liftings from various fields that have different cost structures.
  • Subsequent to quarter end, as announced on October 28, 2020, the operator of the South Africa block 11B/12B has made a significant gas condensate discovery on the Luiperd prospect. This discovery follows the previously announced Brulpadda discovery in 2019. The Luiperd exploratory well encountered 73 meters of net gas condensate pay, and is currently being tested with deliverability results targeted by year end 2020. Canadian Natural has a 20% working interest and expects the costs for this well to be fully carried pursuant to Farm-Out Agreements.

North America Oil Sands Mining and Upgrading

	Three Months Ended						Nine Months Ended
	Sep 30 2020		Jun 30 2020		Sep 30 2019		Sep 30 2020		Sep 30 2019
Synthetic crude oil production (bbl/d) (1) (2)	350,633		464,318		432,203		417,439		407,695

⁽¹⁾ SCO production before royalties and excludes volumes consumed internally as diesel.
⁽²⁾ Consists of heavy and light synthetic crude oil products.

• The Company's world class Oil Sands Mining and Upgrading assets averaged 350,633 bbl/d of SCO production in Q3/20, decreasing by 19% and 24% from Q3/19 and Q2/20 levels respectively, primarily due to planned maintenance and turnaround activities at both AOSP and Horizon.
  • Operating costs from the Company's Oil Sands Mining and Upgrading assets remain industry leading, driven by the Company's continued focus on cost control. In Q3/20, operating costs averaged $23.81/bbl (US$17.88/bbl) of SCO, an increase of 19% and 34% from Q3/19 and Q2/20 levels respectively. The increase in operating costs in Q3/20 includes the cost of planned maintenance and turnaround activities and impact of lower production volumes.
• During the maintenance period at the Scotford Upgrader ("Scotford"), the front end capacity was expanded to approximately 320,000 bbl/d from the previous capacity of 300,000 bbl/d. This additional capacity at AOSP is targeted to increase margins, further maximizing value of the Company's Oil Sands Mining and Upgrading assets.
  • At the non-operated Scotford Upgrader, maintenance activities were completed 13 days later than originally planned. As well, upon start-up of Scotford, additional work was identified resulting in the plant running at reduced gross rates until October 16, 2020. As a result, gross production at AOSP averaged approximately 267,000 bbl/d in October 2020.
  • In late October, Albian ran at gross rates of approximately 345,000 bbl/d of bitumen, and Scotford processed rates at approximately 323,000 bbl/d. As a result of mandatory curtailments in November 2020, AOSP will target to resume production near these full expanded capacity rates in December 2020.
  • Maintenance activities at the Albian mines were aligned with the timing of maintenance and turnaround activities at Scotford.
• Planned maintenance and turnaround activities at Horizon, which commenced in late September, were successfully completed subsequent to quarter end. Upon start-up, a small bore pipe failed, which resulted in the plant running initially at reduced rates. The cost of the repair was minor and is included within the Horizon maintenance budget. Production at Horizon in October 2020 averaged approximately 134,000 bbl/d of SCO, and is currently at approximately 260,000 bbl/d.

MARKETING

		Three Months Ended													Nine Months Ended
		Sep 30 2020				Jun 30 2020				Sep 30 2019					Sep 30 2020				Sep 30 2019
Crude oil and NGLs pricing
WTI benchmark price (US$/bbl) (1)		$	40.94			$	27.85			$	56.45				$	38.30			$	57.06
WCS heavy differential as a percentage of WTI (%) (2)		22		%		41		%		22		%			36		%		21		%
SCO price (US$/bbl)		$	38.61			$	23.28			$	56.87				$	35.11			$	56.36
Condensate benchmark pricing (US$/bbl)		$	37.55			$	22.19			$	52.00				$	35.10			$	52.79
Average realized pricing before risk management (C$/bbl) (3)		$	40.14			$	18.97			$	55.19				$	28.91			$	57.49
Natural gas pricing
AECO benchmark price (C$/GJ)		$	2.03			$	1.81			$	0.99				$	1.96			$	1.31
Average realized pricing before risk management (C$/Mcf)		$	2.31			$	2.03			$	1.64				$	2.19			$	2.24

⁽¹⁾ West Texas Intermediate ("WTI").
⁽²⁾ Western Canadian Select ("WCS").
⁽³⁾ Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities.

• Canadian Natural has a balanced and diverse product mix with a history of strong expertise in marketing its products.
• Commodity prices, including WTI, have improved and stabilized relative to the volatility experienced in the first half of 2020 and Western Canadian Select ("WCS") differentials have tightened as a result of returning demand combined with reduced activity in the Western Canadian Sedimentary Basin ("WCSB"), production declines and price-related curtailments and shut-ins.
• Natural gas prices have also improved in Q3/20, with AECO averaging $2.03/GJ, an increase of 105% and 12% from the Q3/19 and Q2/20 averages respectively. The increase in natural gas prices from the comparable periods primarily reflects lower WCSB production.
• Canadian Natural has storage at major hubs in Edmonton and Hardisty, which allows the Company to adjust monthly sales and manage pipeline logistical constraints and production fluctuations, as well as pricing differences from month to month.
• Market egress will continue to improve in the mid-term as construction is progressing on the Trans Mountain Expansion ("TMX") and Keystone XL projects, on which Canadian Natural has 94,000 bbl/d and 200,000 bbl/d respectively of committed capacity. Combining these two pipeline projects and including Enbridge Line 3 replacement, Western Canadian egress is targeted to increase by approximately 1.8 MMbbl/d in the mid-term.
  • TMX construction continues to progress and is targeted to be on stream in late 2022.
  • Keystone XL construction continues to progress in both Canada and the United States.
  • Canadian Natural is committed to approximately 10,000 bbl/d of the targeted 50,000 bbl/d base Keystone export pipeline optimization expansion, which is targeted to be available in 2021.
• The North West Redwater Refinery reached commercial operations on June 1, 2020 and continues to ramp-up to its targeted processing capacity of approximately 80,000 bbl/d of diluted bitumen, which will improve heavy oil demand in western Canada, effectively increasing egress out of the WCSB. For more details, please contact the North West Redwater Partnership.
• Subsequent to quarter end, the Government of Alberta has suspended the mandatory curtailment production limits as of December 2020 and will only issue curtailment orders in 2021 when deemed necessary.

FINANCIAL REVIEW  

The Company continues to implement proven strategies including its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural’s adjusted funds flow generation, credit facilities, US commercial paper program, access to capital markets, diverse asset base and related flexible capital expenditure program, all support a flexible financial position and provide the appropriate financial resources for the near-, mid- and long-term.

• The Company’s strategy to maintain a diverse portfolio, balanced across various commodity types, achieved production of 1,111,286 BOE/d in Q3/20, with approximately 98% of total production located in G7 countries.
• Canadian Natural generated quarterly adjusted funds flow of $1,740 million in Q3/20, an increase of 319% over Q2/20 levels, driven by the Company's effective and efficient operations as well as higher commodity prices in the quarter.
• Canadian Natural generated approximately $467 million in free cash flow, after net capital expenditures and dividend payments in Q3/20 reflecting the strength of the Company's effective and efficient operations and its high quality, long life low decline asset base.
• Returns to shareholders totaled $502 million in Q3/20 by way of dividends paid on July 1, 2020. As previously announced on March 18, 2020, the Company's share repurchase program has been suspended and the Board of Directors made the decision to not renew the Company's NCIB program, which expired in May 2020.
• Canadian Natural maintained a strong financial position and reduced net debt in Q3/20 from Q2/20 levels by approximately $1.1 billion. The Company has significant liquidity available at September 30, 2020 of approximately $4.2 billion, including committed and undrawn credit facilities, cash balances and short-term investments.
  • The Company repaid $1.0 billion in medium term notes that matured in August 2020.
  • The Company has approximately $5.5 billion of availability under its United States (US$1.9 billion) and Canadian (C$3.0 billion) base shelf prospectuses, which expire August 2021, allowing the Company to offer these securities for sale from time to time.
  • Debt to book capitalization and debt to adjusted EBITDA remained strong at 40.3% and 3.4x respectively.
• Canadian Natural continues to maintain strong investment grade credit ratings. The Company has a high degree of communication with credit rating agencies to ensure they understand the robust and sustainable nature of the Company's assets.
• Canadian Natural’s business is unique, robust and sustainable. The strength of the Company's assets are shown in its ability to generate significant and sustainable free cash flow over the long term, combined with its low cost structure and industry leading corporate break-even price of WTI US$30-31 per barrel.
• The Company's 2020 capital program is on target to be approximately $2.7 billion, before acquisitions, while maintaining base production near 2019 levels.
• Subsequent to quarter end, the Company declared a quarterly dividend of $0.425 per share, payable on January 5, 2021.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE ("ESG") HIGHLIGHTS

Canada and Canadian Natural are well positioned to deliver responsibly produced energy the world needs through leading ESG performance.

In September 2020, Canadian Natural published its 2019 Stewardship Report to Stakeholders, which is available on the Company's website at https://www.cnrl.com/report-to-stakeholders. The report displays how Canadian Natural continues to focus on safe, reliable, effective and efficient operations while minimizing its environmental footprint. Canadian Natural outlined its pathway to lower carbon emissions and its journey to achieve its aspirational goal of net zero GHG emissions in the oil sands. Highlights from the Company's 2019 report are as follows:

• Achieved record low corporate total recordable injury frequency ("TRIF") in 2019, with a TRIF of 0.28 in 2019 compared to 0.57 in 2015. The Company's TRIF is down 51% since 2015, while man-hours have increased over this time period.
• 3 of the 8 independent directors of the Board are female, achieving the Company's Board gender diversity target of no less than 30% of independent directors.
• Awarded over $550 million in contracts to more than 150 Indigenous businesses in 2019.
• Canadian Natural has invested over $3.7 billion in research and development over the last decade and continues to invest in technology to unlock reserves, become more effective and efficient and reduce the Company's environmental footprint. Canadian Natural's culture of continuous improvement leverages the use of technology and innovation to drive sustainable operations and long-term value for shareholders. In 2019, the Company invested $77.4 million in GHG research, technologies and projects as part of its research and development budget.
• Canadian Natural's corporate GHG emissions intensity has decreased by 16% from 2015 to 2019, a material reduction in emissions intensity.
• Canadian Natural is leading the crude oil and natural gas industry in Carbon Capture and Storage ("CCS") and sequestration initiatives and is one of the largest owners of carbon capture capacity in the oil and natural gas sector globally. As part of our comprehensive GHG emissions reduction strategy, our CCS projects include carbon dioxide ("CO₂") storage in geological formations, the use of CO₂ in enhanced oil recovery techniques and injection of CO₂ into tailings. Gross carbon capture capacity through these projects combined is approximately 2.7 million tonnes of CO₂ annually, equivalent to taking approximately 576,000 vehicles off the road per year.
  • At the Company’s 70% owned Quest CCS facility located at Scotford, the facility captures and stores approximately 1.1 million tonnes of CO₂ per year and recently reached the milestone of 5 million tonnes of stored carbon dioxide. Quest highlights the crude oil and natural gas industry's leadership in leveraging technology and innovation and the strength of industry and government collaboration to continuously improve operational and environmental performance.
  • Canadian Natural has a 50% working interest in the North West Redwater Refinery, which combines gasification technology with an integrated carbon capture and storage program, capturing approximately 1.2 million tonnes of CO₂ per year and eliminating approximately 70% of the refinery's total carbon footprint. This project successfully reached commercial operations on June 1, 2020.
  • The Company has approximately 400,000 tonnes of CO₂ capture capacity per year for sequestration at Horizon by injecting CO₂ into its tailings ponds. This improves the Company's operating costs as a result of smaller tailings footprint and more efficient use of natural gas, as well as reduces GHG emissions and accelerates reclamation.
• The Company reduced its GHG emissions intensity in its Oil Sands Mining and Upgrading and thermal in situ segments by 36% from 2016 to 2019.
• The Company reduced methane emissions in its North American E&P segment by 15% from 2016 to 2019.
• Oil Sands Mining and Upgrading fresh river water use intensity decreased by 68% from 2012 to 2019.
• Thermal in situ fresh water use intensity decreased by 61% from 2012 to 2019.
• In 2019, Canadian Natural abandoned 2,035 inactive wells in its North America E&P segment, a corporate record, and an increase of 57% over 2018 levels. The Company also submitted 912 reclamation certificates in 2019.
• The Company has reclaimed more than 7,600 hectares of land since 2015 in its North America E&P segment, equivalent to approximately 9,400 Canadian football fields. In 2019 alone, the Company reclaimed 2,160 hectares of land, a 56% increase from 2018.
• Commercial engineering of the In Pit Extraction Process ("IPEP") at Horizon continues, although the Company has temporarily delayed the field pilot in order to limit staffing levels to personnel who are critical to maintaining safe, reliable operations in response to COVID-19 guidelines. Canadian Natural is pleased with the results from the initial testing phase of the pilot, which showed excellent recovery rates and evidence of stackable tailings. The IPEP pilot will determine the feasibility of producing stackable dry tailings on a commercial basis. The project has the potential to reduce the Company's bitumen production GHG emissions by approximately 40% and lower the Company's environmental footprint by decreasing the handling of material, reducing the distance driven by its fleet of haul trucks, decreasing the size and need for tailings ponds and accelerating site reclamation. In addition, this process has the potential to reduce capital and operating costs.

ADVISORY

Special Note Regarding Forward-Looking Statements

Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses and other guidance provided throughout this press release and the Company's Management’s Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), Primrose thermal oil projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the Jackfish Thermal Oil Sands Project, the North West Redwater bitumen upgrader and refinery, construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market, 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 (including as a result of effects of the novel coronavirus ("COVID-19") pandemic and the actions of the Organization of the Petroleum Exporting Countries ("OPEC") and non-OPEC countries) which may impact, among other things, demand and supply for and market prices of the Company’s products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil and natural gas and NGL prices including due to actions of OPEC and non-OPEC countries taken in response to COVID-19 or otherwise; 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 mining, extracting or upgrading of the Company’s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company’s bitumen products; availability and cost of financing; the Company’s and its subsidiaries’ success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities (including production curtailments mandated by the Government of Alberta); government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset retirement obligations; the adequacy of the Company’s provision for taxes; the continued availability of the Canada Emergency Wage Subsidy ("CEWS") or other subsidies; and other circumstances affecting revenues and expenses.

The Company’s operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all information then available.

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

Special Note Regarding non-GAAP Financial Measures

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

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 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 the Company’s MD&A.

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 the Company’s MD&A.

Free cash flow 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 from operating activities, abandonment, certain movements in other long-term assets, less net capital expenditures and dividends on common shares. The Company considers free cash flow a key measure in demonstrating the Company’s ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders, and to repay debt.

Operating cash flow is a forward looking supplementary measure that represents the Company’s currently forecasted cash flow from operating activities for the stated forecast period for a particular product or group of products or segment, excluding the impact of administration expense, interest, foreign exchange, and taxes. The Company considers operating cash flow by product or segment a key measure in evaluating the contribution of a product to the Company’s cash flow from operating activities.

Adjusted EBITDA is a non-GAAP measure that represents net earnings (loss) as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for interest, taxes, depletion, depreciation and amortization, stock based compensation expense (recovery), unrealized risk management gains (losses), unrealized foreign exchange gains (losses), and accretion of the Company’s asset retirement obligation. The Company considers adjusted EBITDA a key measure in evaluating its operating profitability by excluding non-cash items.

Debt to adjusted EBITDA is a non-GAAP measure that is derived as the current and long-term portions of long-term debt, divided by the 12 month trailing Adjusted EBITDA, as defined above. The Company considers this ratio to be a key measure in evaluating the Company's ability to pay off its debt.

Debt to book capitalization is a non-GAAP measure that is derived as net current and long-term debt, divided by the book value of common shareholders' equity plus net current and long-term debt. The Company considers this ratio to be a key measure in evaluating the Company's ability to pay off its debt.

Available liquidity is a non-GAAP measure that is derived as cash and cash equivalents, total bank and term credit facilities, less amounts drawn on the bank and credit facilities including under the commercial paper program. The Company considers available liquidity a key measure in evaluating the sustainability of the Company’s operations and ability to fund future growth. See note 9 - Long-term Debt in the Company’s consolidated financial statements.

Special Note Regarding Currency, Financial Information and Production

This press release should be read in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2020 and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2019. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company’s unaudited interim consolidated financial statements for the three and nine months ended September 30, 2020 and the Company's MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board ("IASB").

Production volumes and per unit statistics are presented throughout the Company's 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 the Company's 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.

Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2019, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. Information on the Company's website does not form part of and is not incorporated by reference in the Company's MD&A.

CONFERENCE CALL

A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, November 5, 2020.

The North American conference call number is 1-866-521-4909 and the outside North American conference call number is 001-647-427-2311. Please call in 10 minutes prior to the call starting time.

An archive of the broadcast will be available until 6:00 p.m. Mountain Time, Thursday, November 19, 2020. To access the rebroadcast in North America, dial 1-800-585-8367. Those outside of North America, dial 001-416-621-4642. The conference archive ID number is 2768477

The conference call will also be webcast and can be accessed on the home page our website at www.cnrl.com.

Canadian Natural is a senior oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.

CANADIAN NATURAL RESOURCES LIMITED

2100, 855 - 2nd Street S.W. Calgary, Alberta, T2P4J8 Phone: 403-514-7777   Email: ir@cnrl.com www.cnrl.com

TIM S. MCKAY President MARK A. STAINTHORPE Chief Financial Officer and Senior Vice-President, Finance JASON M. POPKO Manager, Investor Relations Trading Symbol - CNQ Toronto Stock Exchange New York Stock Exchange

 

FAQ

What were Canadian Natural's net earnings for Q3 2020?

Canadian Natural reported net earnings of $408 million for Q3 2020.

How much did Canadian Natural increase its liquids production in Q3 2020?

Canadian Natural increased its liquids production to 494,952 bbl/d, marking a 20% rise from Q2 2020.

What was the adjusted funds flow for Canadian Natural in Q3 2020?

In Q3 2020, Canadian Natural generated $1.74 billion in adjusted funds flow.

How much did Canadian Natural reduce its net debt by in Q3 2020?

Canadian Natural reduced its net debt by approximately $1.1 billion in Q3 2020.

What is Canadian Natural's projected natural gas production for Q4 2020?

Canadian Natural's natural gas production is targeted at over 1.6 Bcf/d in Q4 2020.