Canadian Natural Resources Limited Announces 2019 Fourth Quarter and Year End Results

CALGARY, Alberta, March 05, 2020 (GLOBE NEWSWIRE) -- Commenting on the Company's 2019 results, Steve Laut, Executive Vice-Chairman of Canadian Natural stated, "2019 marked the 30th anniversary of Canadian Natural as an Exploration and Production ("E&P") company. Over the past 3 decades, our unwavering focus on returns and free cash flow generating assets has driven significant growth and high returns for our shareholders. Today, we are set up better than ever with a large, diversified portfolio underpinned by long life low decline assets that generate significant and sustainable free cash flow throughout the business cycles."

Canadian Natural's President, Tim McKay, added, "In 2019, we demonstrated that Canadian Natural is truly a unique, sustainable and robust company. Our unparalleled asset base underpinned by our long life low decline assets combined with our E&P assets generated record adjusted funds flow of approximately $10.3 billion and delivered record free cash flow of approximately $4.6 billion in 2019, excluding major acquisition costs. The Company achieved record production totaling 1,098,957 BOE/d, delivering 2% production growth over 2018 levels in a curtailed environment. Production per share growth in Q4/19 over Q4/18 levels was significant at 8% per share.

Canadian Natural's strong team of employees and corporate culture of leveraging technology, innovation and continuous improvement drove significant value growth as the Company captured approximately $550 million of annual incremental margins in 2019. The Company's continued focus on delivering margin growth through effective and efficient operations and cost control resulted in annual E&P operating costs decreasing by 10% from 2018 levels to $11.49/BOE. The Company continues to capture margin growth opportunities across our entire asset base delivering significant and sustainable free cash flow in 2020 and beyond.

In 2019, Canadian Natural continued its strong track record of delivering excellent finding, development and acquisition ("FD&A") costs and reserves replacement ratios, reflecting the strength of our mix of long life low decline assets and effective and efficient operations. Company Gross proved reserves increased 11% to 10.993 billion BOE, replacing 2019 production by 374% with a reserves life index of 27.8 years. Proved FD&A costs, including changes in future development costs, were $7.45/BOE.

Due to the volatile state of the current crude oil price environment, Canadian Natural has reduced its 2020 Oil Sands Mining and Upgrading capital budget by approximately $100 million, demonstrating the Company’s flexibility and ability to be nimble. This reduction will have no impact on 2020 production volumes. Total corporate capital expenditures in 2020 are now targeted to be $3,950 million."

Canadian Natural's Chief Financial Officer, Mark Stainthorpe, continued, "Throughout 2019, Canadian Natural's financial strength was once again displayed by maintaining a strong balance sheet while maximizing financial flexibility. In 2019, the Company achieved record net earnings of approximately $5.4 billion and adjusted net earnings of approximately $3.8 billion. At December 31, 2019 long-term debt totaled $20,982 million, comparable to Q1/19 levels prior to the Devon Canada asset acquisition, and debt to book capitalization strengthened to 37.3% from 39.1% at year end 2018 while debt to adjusted EBITDA improved to 1.9x from 2.0x at year end 2018. Returns to shareholders were significant, returning over $2.6 billion to shareholders through dividends of approximately $1.7 billion and share repurchases of approximately $0.9 billion. Looking forward to 2020, as we continue to deliver on our financial plan, our defined free cash flow allocation policy targets to further strengthen our balance sheet along with increasing returns to our shareholders.

Subsequent to year end, the Company's Board of Directors approved a quarterly dividend increase of 13% to $0.425 per share payable on April 1, 2020. The increase marks the 20th consecutive year of dividend increases, and reflects the Board of Directors' confidence in the strength and robustness of our assets and our ability to generate significant and sustainable free cash flow."

HIGHLIGHTS

			Three Months Ended													Year Ended
($ millions, except per common share amounts)			Dec 31 2019				Sep 30 2019				Dec 31 2018					Dec 31 2019				Dec 31 2018
Net earnings			$	597			$	1,027			$	(776	)			$	5,416			$	2,591
Per common share	– basic		$	0.50			$	0.87			$	(0.64	)			$	4.55			$	2.13
	– diluted		$	0.50			$	0.87			$	(0.64	)			$	4.54			$	2.12
Adjusted net earnings from operations (1)			$	686			$	1,229			$	(255	)			$	3,795			$	3,263
Per common share	– basic		$	0.58			$	1.04			$	(0.21	)			$	3.19			$	2.68
	– diluted		$	0.58			$	1.04			$	(0.21	)			$	3.18			$	2.67
Cash flows from operating activities			$	2,454			$	2,518			$	1,397				$	8,829			$	10,121
Adjusted funds flow (2)			$	2,494			$	2,881			$	1,229				$	10,267			$	9,088
Per common share	– basic		$	2.11			$	2.43			$	1.02				$	8.62			$	7.46
	– diluted		$	2.10			$	2.43			$	1.02				$	8.61			$	7.43
Cash flows used in investing activities			$	854			$	908			$	1,042				$	7,255			$	4,814
Net capital expenditures, excluding Devon Canada asset acquisition costs (3)			$	1,056			$	963			$	1,181				$	3,904			$	4,731
Total net capital expenditures, including Devon Canada asset acquisition costs (3)			$	1,056			$	963			$	1,181				$	7,121			$	4,731
Daily production, before royalties
Natural gas (MMcf/d)			1,455				1,469				1,488					1,491				1,548
Crude oil and NGLs (bbl/d)			913,782				931,546				833,358					850,393				820,778
Equivalent production (BOE/d) (4)			1,156,276				1,176,361				1,081,368					1,098,957				1,078,813

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

ANNUAL HIGHLIGHTS

• Net earnings of $5,416 million were realized in 2019, while adjusted net earnings of $3,795 million were achieved in 2019, a $532 million increase over 2018 levels.
• Cash flows from operating activities were $8,829 million in 2019, a decrease of $1,292 million compared to 2018 levels primarily due to the impact of changes in non-cash working capital.
• Canadian Natural generated record annual adjusted funds flow of $10,267 million in 2019, an increase of 13% or $1,179 million over 2018 levels. The increase over 2018 was primarily due to higher crude oil and NGL netbacks in the Company's Exploration and Production ("E&P") segment and higher volumes in the Company's thermal in situ and international areas.
• Cash flows used in investing activities were $7,255 million in 2019, an increase of $2,441 million compared to 2018 levels as a result of the Devon Canada asset acquisition completed in 2019, partially offset by lower capital expenditures in the year.
• Canadian Natural delivered record annual free cash flow of $4,620 million after net capital expenditures of $3,904 million and dividend requirements of $1,743 million, and excluding Devon Canada asset acquisition costs, reflecting the strength of the Company's long life low decline asset base and effective and efficient operations.
  • Balance sheet strength remains a focus as year end 2019 long-term debt totaled $20,982 million, comparable to Q1/19 levels prior to the Devon Canada asset acquisition, and debt to book capitalization strengthened to 37.3% from 39.1% at year end 2018 while debt to adjusted EBITDA improved to 1.9x from 2.0x at year end 2018. During 2019, the Company executed on the following:
    • The Company repaid $500 million of 3.05% notes and $500 million of 2.60% notes in Q2/19 and Q4/19, respectively.
    • The Company fully repaid and canceled the remaining balance of the $1,800 million non-revolving term loan credit facility that was used to finance the Athabasca Oil Sands Project ("AOSP") acquisition, ahead of its maturity in May 2020.
    • Additionally, the $2,200 million non-revolving term credit facility, originally due in October 2020, was extended to February 2023 and increased by $450 million to $2,650 million.
  • Canadian Natural is committed to returns to shareholders, returning a total of $2,684 million to shareholders in 2019, $1,743 million by way of dividends and $941 million by way of share repurchases.
    • Share repurchases for cancellation totaled 25,900,000 common shares at a weighted average share price of $36.32.
    • Subsequent to year end, up to and including March 4, 2020, the Company executed on additional share repurchases for cancellation of 6,600,000 common shares at a weighted average share price of $39.41.
    • Returns to shareholders have been significant as Canadian Natural returned approximately $6.2 billion by way of dividends and share repurchases between January 1, 2018 and March 4, 2020.
    • 2019 dividends increased 12% from 2018 levels to $1.50 per share. Subsequent to year end, the Company declared a quarterly dividend increase of 13% to $0.425 per share, payable on April 1, 2020. The increase marks the 20th consecutive year that the Company has increased its dividend, reflecting the Board of Directors' confidence in Canadian Natural's strength and robustness of the Company's assets and its ability to generate significant and sustainable free cash flow.
• Canadian Natural's strong team of employees and corporate culture of leveraging technology, innovation and continuous improvement drove significant value growth as the Company captured approximately $550 million of annual incremental margin in 2019, some of the key achievements are identified as follows:
  • Canadian Natural's continued focus on delivering margin growth through effective and efficient operations, execution on the Company's curtailment optimization strategy and cost control was demonstrated as the Company's E&P annual operating costs were $11.49/BOE in 2019, representing a 10% decrease or approximately $310 million of margin improvement from 2018 levels.
    • Pelican Lake annual operating costs decreased by 7% to $6.22/bbl from 2018 levels.
    • Thermal in situ annual operating costs decreased by 18% to $10.83/bbl from 2018 levels.
    • North America natural gas annual operating costs decreased by 7% to $1.16/Mcf from 2018 levels.
  • Oil Sands Mining and Upgrading annual operating costs, excluding energy costs, decreased $91 million or 3% from 2018 levels.
  • As part of Canadian Natural's natural gas marketing strategy, the Company has continued to diversify its natural gas sales points, equating to approximately $115 million of additional margin in 2019.
• The Company has identified approximately $900 million of additional annual margin growth opportunities of which approximately $180 million are targeted to be captured in 2020.
• The Company achieved record annual production volumes of 1,098,957 BOE/d in 2019, an increase of 2% over 2018 levels, primarily due to production from the acquisition of thermal in situ and primary heavy crude oil assets from Devon Canada and execution of the Company's curtailment optimization strategy, offsetting the impact of a proactive piping replacement in one of the hydrogen units at Horizon, together with the unplanned maintenance at the non-operated Scotford Upgrader and at Horizon in the first half of the year.
  • Production per share growth was significant at approximately 8% from Q4/18 to Q4/19, as a result of accretive acquisitions, effective and efficient operations and execution on the Company's free cash flow allocation policy.
  • The Company achieved record annual liquids production volumes of 850,393 bbl/d in 2019, an increase of 4% over 2018 levels.
• The Company continues to execute operational flexibility through its curtailment optimization strategy as follows:
  • Increasing crude oil production from the Company's balanced asset base to mitigate production impacts during periods of planned and unplanned downtime.
  • Modified timing of the Company's planned turnaround activities to target its monthly curtailment allowable production volumes.
  • Maximizing value through production optimization of higher netback assets.
  • Allowing the Company to execute on proactive maintenance activities to enhance long-term reliability.
• Thermal in situ oil sands production volumes were strong in 2019, averaging a record 167,942 bbl/d, a 56% increase over 2018 levels, primarily as a result of the Jackfish acquisition and increased production from Kirby North and pad additions at Primrose, reflecting the successful execution of the Company's curtailment optimization strategy.
  • At Kirby North, production ramp up continues to be strong, exceeding expectations as a result of top tier execution and productivity, with a December 2019 exit rate of approximately 26,500 bbl/d. As a result of improved well design, high plant reliability and effective and efficient operations, the project now targets to reach peak overall capacity of 40,000 bbl/d in early Q3/20, ahead of schedule, driving additional margins in 2020.
  • High return, drill to fill pad additions at Primrose came on ahead of schedule and on budget with strong production averaging approximately 32,000 bbl/d in Q4/19. As previously announced, these pad additions are targeted to add approximately 26,000 bbl/d in the first 12 months of production.
  • At Jackfish, the Company successfully completed tie in activities in Q4/19 on the previously drilled pad additions that have production capability of 21,000 bbl/d for minimal capital of approximately $8 million. Production from these pads is targeted to reach overall peak production in early 2022 and is targeted to offset conventional production declines with long life low decline thermal in situ production as the Company manages within its curtailment optimization strategy.
• At the Company's world class Oil Sands Mining and Upgrading assets, annual production volumes averaged 395,133 bbl/d of Synthetic Crude Oil ("SCO") in 2019, a decrease of 7% from 2018 levels, reflecting the proactive piping replacement in one of the hydrogen units at Horizon, together with the unplanned maintenance at the non-operated Scotford Upgrader and at Horizon in the first half of the year.
  • At AOSP, through increased reliability, process improvements and optimization projects, Canadian Natural increased gross production capacity at the Albian mines by approximately 40,000 bbl/d to approximately 320,000 bbl/d, representing a 14% increase in capacity while reducing AOSP operating costs by approximately 34% or $10.00/bbl since the announcement of the acquisition in 2017.
  • As part of the Company's overall strategy to maximize value and enhance margins, the Scotford Upgrader is targeting to increase capacity to approximately 320,000 bbl/d in Q3/20. This additional capacity at AOSP will allow for increased flexibility, margin improvements and can be managed through the Company's curtailment optimization strategy.
• International E&P crude oil production volumes were strong in 2019, averaging 49,290 bbl/d, an increase of 13% over 2018 levels. The increase over 2018 was primarily due to strong performance from wells drilled in the North Sea and at Baobab, partially offset by natural field declines.
• The Company now targets approximately $190 million in annual operating costs savings from assets acquired from Devon Canada, $55 million in excess of its initially identified targeted annual operating cost savings of $135 million.
• Due to the volatile state of the current crude oil price environment, Canadian Natural has reduced its 2020 Oil Sands Mining and Upgrading capital budget by approximately $100 million, demonstrating the Company’s flexibility and ability to be nimble. This reduction will have no impact on 2020 production volumes. Total corporate capital expenditures in 2020 are now targeted to be $3,950 million.
• In Q2/19, the Government of Alberta enacted a series of tax rate reductions which will decrease the provincial corporate income tax rate from 12% to 8% by 2022. As a result of this reduction, Canadian Natural estimates current tax savings of approximately $15 million in 2019 and approximately $30 million in 2020. As previously disclosed, these current tax savings coupled with the elimination of curtailment for certain conventional drilling in Alberta resulted in the Company increasing its 2020 E&P capital budget by approximately $250 million over 2019 levels, targeting 60 additional drilling locations across Alberta.
  • In accordance with International Financial Reporting Standards, the Company recorded a non-cash accounting reduction in its deferred tax liability of $1,618 million in Q2/19. Over the next several decades, the Company is expected to continue to realize current tax savings resulting from the tax rate reductions.

RESERVES UPDATE

• Canadian Natural's crude oil, SCO, bitumen, natural gas and NGL reserves were evaluated and reviewed by Independent Qualified Reserves Evaluators. The following highlights are based on the Company's reserves using forecast prices and costs at December 31, 2019 (all reserves values are Company Gross unless stated otherwise).
  • Canadian Natural’s 2019 performance has resulted in another year of excellent finding and development costs:
    • Finding, Development and Acquisition ("FD&A") costs, excluding changes in Future Development Costs ("FDC"), are $4.52/BOE for proved reserves and $5.34/BOE for proved plus probable reserves.
    • FD&A costs, including changes in FDC, are $7.45/BOE for proved reserves and $5.75/BOE for proved plus probable reserves.
  • Proved reserves increased 11% to 10.993 billion BOE with reserves additions and revisions of 1.501 billion BOE. Proved plus probable reserves increased 6% to 14.252 billion BOE with reserves additions and revisions of 1.271 billion BOE.
  • Proved reserves additions and revisions replaced 2019 production by 374%. Proved plus probable reserves additions and revisions replaced 2019 production by 317%.
  • The proved BOE reserves life index is 27.8 years and the proved plus probable BOE reserves life index is 36.0 years.
  • Proved developed producing reserves additions and revisions are 0.778 billion BOE, replacing 2019 production by 194%. The total proved developed producing BOE reserves life index is 20.2 years.
  • The net present value of future net revenues, before income tax, discounted at 10%, increased 1% to $107.6 billion for proved reserves and decreased 2% to $127.8 billion for proved plus probable reserves. The net present value for proved developed producing reserves is relatively unchanged at $84.3 billion.

MARKETING UPDATE

• Mainline enhancements of approximately 100,000 bbl/d of capacity were completed in December 2019, increasing pipeline capacity out of the Western Canadian Sedimentary Basin ("WCSB").
• Additional pipeline egress of approximately 190,000 bbl/d to move incremental crude oil production out of the WCSB is targeted to be added by industry over the near term, providing opportunities for the Company before new export pipelines are constructed:
  • Additional Mainline enhancements of 50,000 bbl/d of capacity are targeted in 2020.
  • Express pipeline optimization expansion is targeted to add approximately 50,000 bbl/d of capacity in 2020.
  • The North West Redwater Refinery ("NWR") is targeted to add approximately 40,000 bbl/d of incremental crude oil conversion capacity. Upon start-up of the Gasifier and LC Finer units, the refinery will process a total of approximately 80,000 bbl/d of diluted bitumen, increasing effective takeaway capacity out of the WCSB.
  • Base Keystone export pipeline optimization expansion of approximately 50,000 bbl/d was recently announced. In Q3/19, Canadian Natural committed to approximately 10,000 bbl/d of the expansion, which is targeted to be available in 2020.
• Crude by rail volumes continue to be strong at approximately 350,000 bbl/d for the month of December 2019.

ENVIRONMENTAL HIGHLIGHTS

• Canadian Natural is committed to achieving its aspirational goal of net zero Oil Sands emissions through its leading environmental performance and technology, innovation and continuous improvement potential pathways, which are listed on the Company's website at https://www.cnrl.com/corporate-responsibility/advancements-in-technology/.
• As part of Canadian Natural's commitment to its aspirational goal of net zero Oil Sands emissions, the Company announced the following environmental targets at its Investor Day in December 2019:
  • Reduction of Oil Sands greenhouse gas ("GHG") emissions intensity by 25% by 2025, from a 2016 baseline.
  • Reduction of methane emissions in its North America E&P operations by 20% by 2025, from a 2016 baseline.
  • Reduction in water intensity in its in situ operations by 50% by 2022, from a 2012 baseline.
  • Reduction of Oil Sands mining fresh river water intensity by 30% by 2022, from a 2012 baseline.
• At the end of 2019, highlights from the Company's environmental performance are as follows:
  • As part of Canadian Natural's industry leading reclamation and proactive liability management program, the Company achieved the following reclamation success in 2019:
    • In the Company's North America E&P segment, Canadian Natural proactively abandoned 2,035 wells, an increase of 57% over 2018 levels, as well as submitted 912 reclamation certificate applications and received 893 reclamation certificates during the year.
      • In Alberta, Canadian Natural received 850 reclamation certificates which is the largest number of certificates received by an operator and represents 18% of the total certificates issued.
    • The Company reclaimed 3,118 hectares of land in 2019 in the Company's North America E&P segment, a 125% increase over 2018 levels.
  • In the Oil Sands Mining and Upgrading segment, water use intensity decreased in 2019 by 17% from 2018 levels.
  • The Company reduced its fresh water usage by 28%, sourcing approximately 82% from recycled produced water at Primrose in 2019.
• The Company confirms that 100% of direct emissions from its Alberta Oil Sands in situ and mining operations were third party verified in 2018 and the verification process is underway for 2019 emissions. The verification is completed by a third party professional engineering firm.
• Canadian Natural has invested approximately $3.4 billion in research and development from 2009 to 2018 and continues to invest in technology to unlock reserves, become more effective and efficient, increase production 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.
• Canadian Natural has invested significant capital to capture and sequester CO2, making the Company one of the largest CO2 capturers and sequesterers for the oil and natural gas sector globally. The Company has carbon capture and sequestration facilities at Horizon, a 70% working interest in the Quest Carbon Capture and Storage project at Scotford, and carbon capture facilities at its 50% interest in the NWR refinery when on stream. As a result, Canadian Natural targets capacity to capture and sequester 2.7 million tonnes of CO2 annually, equivalent to taking 576,000 vehicles off the road per year.
• Canadian Natural's commitment to leverage technology, adopting innovation and continuous improvement is evidenced by projects described in its Creating Value through Technology and Innovation Case Studies published in December 2019, which is available on the Company's website at https://www.cnrl.com/upload/media_element/1279/05/technology-and-innovation-case-studies-web.pdf. Highlights from the publication are as follows:
  • The In Pit Extraction Process ("IPEP") pilot at Horizon will determine the feasibility of producing stackable dry tailings. 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 decreased material handling, 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.
    • Results from the initial testing phase for the Company's IPEP pilot have been positive, with excellent recovery rates and evidence of stackable tailings. The Company is implementing enhancements to improve overall operability in 2020.
  • Solvent Enhanced Oil Recovery technology is being tested at the Company's in situ operations to increase crude oil recovery, reduce steam-to-oil ratios ("SOR") by up to 50%, translating into GHG intensity reduction of up to 50%. To date, the Company has seen increases in crude oil production, lower SOR and high solvent recovery at its Kirby South operations. In addition, the Company is planning commercial scale demonstration tests to verify economics and execution details are being refined through 2020. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
  • Methane emission reduction projects will reduce the Company's emissions through focusing on operational practices and innovative technologies. Through the Company's pneumatic retrofit program which began in 2018, the Company reduced approximately 400,000 tonnes of CO2 equivalent per year by completing approximately 4,000 controller retrofits by the end of 2019. In 2020, the Company is targeting an additional 1,300 controller retrofits, a reduction of approximately 130,000 tonnes of CO2 equivalent per year.

FOURTH QUARTER HIGHLIGHTS

• Net earnings of $597 million were realized in Q4/19, while adjusted net earnings of $686 million were achieved in Q4/19, a $543 million decrease from Q3/19 levels.
• Cash flows from operating activities were $2,454 million in Q4/19, a decrease of $64 million compared to Q3/19 levels.
• Canadian Natural generated quarterly adjusted funds flow of $2,494 million in Q4/19, a decrease of 13% or $387 million from Q3/19 levels, primarily due to lower SCO volumes in the Oil Sands Mining and Upgrading segment and lower E&P crude oil and NGL netbacks driven largely by lower crude oil pricing, partially offset by lower E&P operating costs, higher North America crude oil and NGL production volumes and higher natural gas prices.
• Canadian Natural's continued focus on delivering effective and efficient operations and cost control was demonstrated as the Company's E&P Q4/19 operating costs were $10.79/BOE, 3% and 20% reductions from Q3/19 and Q4/18 levels respectively.
• Cash flows used in investing activities were $854 million in Q4/19.
• Canadian Natural delivered strong quarterly free cash flow of $994 million after net capital expenditures of $1,056 million and dividend requirements of $444 million in Q4/19, reflecting the strength of the Company's long life low decline asset base and effective and efficient operations.
  • Balance sheet strength remains a focus as long-term debt decreased by $1,507 million from Q3/19 levels to $20,982 million at December 31, 2019. Debt to book capitalization strengthened to 37.3% from 39.1% and debt to adjusted EBITDA improved to 1.9x from 2.6x quarter over quarter.
    • In Q4/19, Canadian Natural repaid $500 million of 2.60% notes and fully repaid and canceled the $1,000 million remaining balance on the non-revolving term loan credit facility that was used to finance the AOSP acquisition, ahead of its maturity in May 2020.
  • Canadian Natural is committed to returns to shareholders, returning a total of $584 million to shareholders in Q4/19, $444 million by way of dividends and $140 million by way of share repurchases.
• The Company achieved quarterly production volumes of 1,156,276 BOE/d in Q4/19, a 7% increase and 2% decrease from Q4/18 and Q3/19 levels respectively. The increase over Q4/18 primarily reflected production from the acquisition of thermal in situ and primary heavy crude oil assets from Devon Canada, offsetting the impact of the completion of the planned turnaround and a proactive piping replacement at Horizon in Q4/19. The decrease from Q3/19 primarily reflected the proactive piping replacement at Horizon in Q4/19 partially offset by the Company's execution of its curtailment optimization strategy.
  • Canadian Natural's North America E&P crude oil and NGLs production volumes, excluding thermal in situ, averaged 247,184 bbl/d in Q4/19, comparable to Q3/19 and a 3% increase over Q4/18 levels. The increase over Q4/18 was primarily due to production from primary heavy crude oil assets acquired from Devon Canada.
  • Thermal in situ oil sands production volumes were strong in the quarter, averaging a record 259,387 bbl/d, a 26% increase and 154% increase over Q3/19 and Q4/18 levels respectively. The increase over Q3/19, primarily reflected the successful execution of the Company's curtailment optimization strategy as production ramped up from Kirby North and Primrose pad additions and increased production at Jackfish. The increase over Q4/18 primarily reflected production volumes from the Devon Canada asset acquisition, together with new production from Kirby North and pad additions at Primrose, reflecting optimization of curtailment volumes across the Company's asset base.
    • Thermal in situ operating costs were strong in Q4/19 at $8.65/bbl, reductions of 11% and 35% from Q3/19 and Q4/18 levels respectively, primarily as a result of higher production volumes and synergies captured to date from the Devon Canada asset acquisition, partially offset by higher fuel costs.
  • At the Albian mines, top tier operations combined with optimization of facilities resulted in record gross bitumen production averaging approximately 306,000 bbl/d in Q4/19, forming a part of the Company’s curtailment optimization strategy during the turnaround and the proactive piping replacement at Horizon.
  • In Q4/19 at Horizon, as a result of Canadian Natural's industry leading integrity program, the Company identified the need to replace piping on one of the hydrogen manufacturing units during post turnaround start-up. To ensure increased reliability of operations and as part of the Company's curtailment optimization strategy, the Company made the proactive decision to replace the piping, at which time Horizon ran at restricted rates of approximately 170,500 bbl/d, and production impacts were managed as part of the Company's curtailment optimization strategy. The proactive piping replacement was completed for approximately $65 million and production resumed to full rates on January 19, 2020.
    • Record monthly production of approximately 262,600 bbl/d of SCO was achieved at Horizon in February 2020 as a result of continued high utilization, safe, steady and reliable operations.
  • International E&P crude oil production volumes averaged 49,355 bbl/d, in-line with Q3/19 and an increase of 14% over Q4/18 levels. The increase from Q4/18 was primarily as a result of strong volumes from wells drilled at Baobab and in the North Sea.

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, thermal in situ crude oil, bitumen and SCO (herein collectively referred to as “crude oil”), 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 from the Company's Oil Sands Mining and Upgrading, thermal in situ oil sands and 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.

Augmenting this, 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 with the right economic conditions, can provide excellent returns and maximize value for shareholders. Supporting these projects is the Company’s undeveloped land base which enables large, repeatable drilling programs which 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

	Year Ended Dec 31
	2019				2018
(number of wells)	Gross		Net		Gross		Net
Crude oil	96		86		513		483
Natural gas	30		19		25		18
Dry	3		3		9		9
Subtotal	129		108		547		510
Stratigraphic test / service wells	519		447		717		615
Total	648		555		1,264		1,125
Success rate (excluding stratigraphic test / service wells)			97	%			98	%

• The Company's total crude oil and natural gas drilling program of 108 net wells for the year ended December 31, 2019, excluding strat/service wells, represents a decrease of 402 net wells from the same period in 2018. The Company's drilling levels primarily reflect the impacts of reduced capital allocation as a result of Alberta curtailments and execution of the Company's curtailment optimization strategy.

North America Exploration and Production

Crude oil and NGLs – excluding Thermal In Situ Oil Sands
	Three Months Ended						Year Ended
	Dec 31 2019		Sep 30 2019		Dec 31 2018		Dec 31 2019		Dec 31 2018
Crude oil and NGLs production (bbl/d)	247,184		244,267		240,942		238,028		243,122
Net wells targeting crude oil	9		33		62		79		361
Net successful wells drilled	9		33		61		77		353
Success rate	100	%	100	%	98	%	97	%	98	%

• Canadian Natural's North America E&P crude oil and NGL production volumes, excluding thermal in situ, averaged 238,028 bbl/d in 2019, a 2% decrease from 2018 levels, primarily reflecting natural field declines and the Company's strategic decision to reduce activity due to mandatory production curtailments in Alberta, partially offset by the acquisition of primary heavy crude oil assets from Devon Canada.
  • Canadian Natural's primary heavy crude oil production averaged 82,189 bbl/d in 2019, a 5% decrease from 2018 levels as a result of the Company's strategic decision to reduce activity due to mandatory production curtailments in Alberta, partially offset by additional volumes from the Devon Canada asset acquisition.
    • Strong operating costs of $16.66/bbl were achieved in the Company's primary heavy crude oil operations in 2019, comparable to 2018 levels, impressive results given lower production volumes and the Company's continued focus on capturing synergies and margin improvements.
  • Pelican Lake annual production averaged 58,855 bbl/d in 2019, a decrease of 7% from 2018 levels, reflecting natural field declines and the Company's strategic decision to reduce activity due to mandatory production curtailments in Alberta.
    • At Pelican Lake, the Company continues to demonstrate effective and efficient operations as annual operating costs decreased by 7% from 2018 levels, averaging $6.22/bbl in 2019, as a result of the Company's focus on cost control. As part of Canadian Natural's margin enhancement opportunities, the Company is targeting to achieve approximately $10 million in incremental cost savings at Pelican Lake in 2020.
  • North American light crude oil and NGL production averaged 96,984 bbl/d in 2019, a 3% increase from 2018 levels primarily as a result of the Company's strategic decision to reallocate capital to non-curtailed light crude oil in Saskatchewan and liquids rich natural gas areas, combined with the execution of the Company's curtailment optimization strategy and continued strong production from 2018 and 2019 drilling in the Greater Wembley and Karr areas.
    • In 2019, operating costs were $15.21/bbl in the Company's North America light crude oil and NGL areas, comparable to 2018 levels.

Thermal In Situ Oil Sands
	Three Months Ended						Year Ended
	Dec 31 2019		Sep 30 2019		Dec 31 2018		Dec 31 2019		Dec 31 2018
Bitumen production (bbl/d)	259,387		206,395		102,112		167,942		107,839
Net wells targeting bitumen	3		—		41		3		125
Net successful wells drilled	3		—		40		3		124
Success rate	100	%	—		98	%	100	%	99	%

• Thermal in situ oil sands production volumes were strong in 2019, averaging a record 167,942 bbl/d, a 56% increase over 2018 levels, primarily as a result of the Jackfish acquisition and increased production from Kirby North and pad additions at Primrose, reflecting the successful execution of the Company's curtailment optimization strategy.
  • Thermal in situ operating costs were strong in 2019, a decrease of 18% from 2018 levels, averaging $10.83/bbl, primarily as a result of higher production volumes, synergies captured to date from the Devon Canada asset acquisition and the Company's continued focus on cost control, partially offset by higher energy costs.
  • At Primrose, 2019 production volumes averaged 78,606 bbl/d, an increase of 12% over 2018 levels, primarily due to new production from pad additions that came on in late Q3/19, together with execution of the Company's curtailment optimization strategy.
    • High return, drill to fill pad additions at Primrose came on ahead of schedule and on budget with strong production averaging approximately 32,000 bbl/d in Q4/19. As previously announced, these pad additions are targeted to add approximately 26,000 bbl/d in the first 12 months of production.
  • At Kirby, which now includes both Kirby South and Kirby North, SAGD production volumes averaged 34,094 bbl/d in 2019, a 3% decrease from 2018 levels due to natural field declines at Kirby South as a result of the Company's capital allocation decisions due to mandatory production curtailments in Alberta, offsetting the ramp up of Kirby North production.
    • At Kirby North, production ramp up continues to be strong, exceeding expectations as a result of top tier execution and productivity, with a December 2019 exit rate of approximately 26,500 bbl/d. As a result of improved well design, high plant reliability and effective and efficient operations, the project now targets to reach peak overall capacity of 40,000 bbl/d in early Q3/20, ahead of schedule, driving additional margins in 2020.
    • Results from the Company's solvent enhanced SAGD pilot that began in late Q2/19 at Kirby South continue to be positive, indicating that targeted SOR reductions of 30% to 50% remain achievable. If success continues during the two year pilot, learnings from this pilot have the potential for application throughout the Company's extensive thermal in situ asset base, significantly reducing the Company's GHG intensity by up to 50% and at the same time significantly reducing operating costs.
  • At Jackfish, SAGD production volumes averaged 102,106 bbl/d in Q4/19, a 5% increase over Q3/19 levels, reflecting execution on the Company's curtailment optimization strategy. The Company has successfully integrated the assets and captured synergies to date. The Company targets go forward operating costs based on current strip estimates, including energy costs, to be approximately $8.00 - $9.00/bbl. This represents a $3.50/bbl reduction at the midpoint or approximately 30% lower than operating cost indications for the asset at the time of acquisition.
    • At Jackfish, the Company successfully completed tie in activities in Q4/19 on the previously drilled pad additions that have production capability of 21,000 bbl/d for minimal capital of approximately $8 million. Production from these pads is targeted to reach overall peak production in early 2022 and is targeted to offset conventional production declines with long life low decline thermal in situ production as the Company manages within its curtailment optimization strategy.
    • The Company is targeting planned turnaround activity in late Q1/20 at Jackfish. Production impacts are reflected in annual guidance and will be managed as part of the Company's curtailment optimization strategy.

North America Natural Gas
	Three Months Ended						Year Ended
	Dec 31 2019		Sep 30 2019		Dec 31 2018		Dec 31 2019		Dec 31 2018
Natural gas production (MMcf/d)	1,411		1,425		1,441		1,443		1,490
Net wells targeting natural gas	4		5		3		20		18
Net successful wells drilled	4		5		3		19		18
Success rate	100	%	100	%	100	%	95	%	100	%

• North America natural gas production was 1,443 MMcf/d in 2019, a decrease of 3% from 2018 levels, reflecting natural field declines, together with the strategic reduction of capital allocated to natural gas activities due to low natural gas prices.
• Natural gas operating costs were strong in 2019, a decrease of 7% from 2018 levels to $1.16/Mcf, given the Company's strategic decision to allocate capital to other areas and let production decline. These results demonstrate the strength of the Company's strategy to own and control its infrastructure, continued focus on cost control and achieving efficiencies across the entire asset base.
  • At the Company's high value Septimus Montney liquids rich area, operating costs were strong in 2019, a 6% decrease from 2018 levels, averaging $0.30/Mcfe in 2019.
• The Company's Liquids Enhancement and Gas Storage ("LEGS") pilot at Septimus began in Q2/19 and has the potential to materially increase liquids recovery while storing natural gas in the reservoir, preserving the value of the natural gas for periods with higher market prices.
  • The Company completed two injection and production cycles at Septimus in 2019 and initial results are positive, indicating incremental liquids recovery within the expected range of 1.3x to 1.7x primary recovery. A third production cycle commenced in February 2020 and is proceeding as expected. Given the opportunities for this process across Canadian Natural's vast liquids rich Montney land base, the Company is executing on a second pilot site within the Company's Greater Wembley area and is targeting first injection in late Q2/20.
• Following the acquisition of the Pine River plant in Q2/19, the Company successfully completed a planned plant turnaround in Q4/19 designed to improve plant efficiency, run time, lower operating costs, and improve plant capability. Following the turnaround, plant capability has improved to 120 MMcf/d from previous levels of 95 MMcf/d.
• In 2019, Canadian Natural used the equivalent of approximately 44% of corporate annual natural gas production within its operations, providing a natural hedge from the challenging Western Canadian natural gas price environment. Approximately 34% of the Company's 2019 natural gas production was exported to other North American markets and sold internationally, while the remaining 22% of the Company's 2019 natural gas production was exposed to AECO/Station 2 pricing.

International Exploration and Production

	Three Months Ended						Year Ended
	Dec 31 2019		Sep 30 2019		Dec 31 2018		Dec 31 2019		Dec 31 2018
Crude oil production (bbl/d)
North Sea	30,860		27,454		21,071		27,919		23,965
Offshore Africa	18,495		21,227		22,185		21,371		19,662
Natural gas production (MMcf/d)
North Sea	25		20		22		24		32
Offshore Africa	19		24		25		24		26
Net wells targeting crude oil	—		3.0		1.1		5.5		5.6
Net successful wells drilled	—		3.0		1.1		5.5		5.6
Success rate	—		100	%	100	%	100	%	100	%

• International E&P crude oil production volumes were strong in 2019, averaging 49,290 bbl/d, an increase of 13% over 2018 levels. The increase over 2018 was primarily due to strong performance from wells drilled in the North Sea and at Baobab, partially offset by natural field declines.
• International production volumes benefit from premium Brent pricing, generating significant free cash flow for the Company.
  • In the North Sea, crude oil production volumes of 27,919 bbl/d were achieved in 2019, a 16% increase over 2018 levels, reflecting volumes from new wells after a successful 2019 drilling program of 5 gross (4.9 net) wells.
    • 2019 operating costs in the North Sea decreased by 9% from 2018 levels, averaging $36.39/bbl (£21.27/bbl), reflecting increased production volumes, together with fluctuations in the Canadian dollar.
    • The North Sea 2020 drilling program, targeting 6 gross (5.9 net) producer and 2 gross (1.9 net) injector wells, commenced in Q1/20 at Ninian.
  • Offshore Africa crude oil production volumes in 2019 averaged 21,371 bbl/d, a 9% increase over 2018 levels, primarily as a result of production from wells drilled in late 2018 and early 2019 at Baobab, partially offset by natural field declines.
    • Côte d'Ivoire crude oil operating costs decreased 16% from 2018 levels, averaging $11.21/bbl (US$8.45/bbl) in 2019, primarily due to timing of liftings from various fields that have different cost structures.
    • The Company is targeting planned turnaround activities at Espoir in Q1/20 and at Baobab in Q2/20.
    • Following the previously announced discovery of significant gas condensate in South Africa, where Canadian Natural has a 20% working interest, the operator commenced a comprehensive 3D and 2D seismic acquisition program in Q4/19, with targeted completion in Q2/20.
      • The operator has contracted a rig with targeted spud of an exploration well in Q2/20. Depending on the results of this well, the operator may drill an additional well in 2020 to further define volumes and deliverability.
      • Canadian Natural is carried to a maximum gross cost of approximately US$300 million.

North America Oil Sands Mining and Upgrading

	Three Months Ended						Year Ended
	Dec 31 2019		Sep 30 2019		Dec 31 2018		Dec 31 2019		Dec 31 2018
Synthetic crude oil production (bbl/d) (1) (2)	357,856		432,203		447,048		395,133		426,190

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

(2) Consists of heavy and light synthetic crude oil products.

• At the Company's world class Oil Sands Mining and Upgrading assets, annual production volumes averaged 395,133 bbl/d of SCO in 2019, a decrease of 7% from 2018 levels, reflecting the proactive piping replacement in one of the hydrogen units at Horizon, together with the unplanned maintenance at the non-operated Scotford Upgrader and at Horizon in the first half of the year.
  • Effective and efficient operations resulted in annual operating costs, excluding energy costs, of $3,276 million, a $91 million or 3% decrease from 2018 levels.
  • Industry leading annual operating costs averaged $22.56/bbl of SCO, a 4% increase from 2018 levels primarily reflecting reduced production volumes together with increased natural gas costs.
  • At AOSP, through increased reliability, process improvements and optimization projects, Canadian Natural increased gross production capacity at the Albian mines by approximately 40,000 bbl/d to approximately 320,000 bbl/d, representing a 14% increase in capacity while reducing AOSP operating costs by approximately 34% or $10.00/bbl since the announcement of the acquisition in 2017.
  • As part of the Company's overall strategy to maximize value and enhance margins, the Scotford Upgrader is targeting to increase capacity to approximately 320,000 bbl/d in Q3/20. This additional capacity at AOSP will allow for increased flexibility, margin improvements and can be managed through the Company's curtailment optimization strategy.
  • At the Albian mines, top tier operations combined with optimization of facilities resulted in record gross bitumen production averaging approximately 306,000 bbl/d in Q4/19, forming a part of the Company’s curtailment optimization strategy during the turnaround and the proactive piping replacement at Horizon.
  • In Q4/19 at Horizon, as a result of Canadian Natural's industry leading integrity program, the Company identified the need to replace piping on one of the hydrogen manufacturing units during post turnaround start-up. To ensure increased reliability of operations and as part of the Company's curtailment optimization strategy, the Company made the proactive decision to replace the piping, at which time Horizon ran at restricted rates of approximately 170,500 bbl/d, and production impacts were managed as part of the Company's curtailment optimization strategy. The proactive piping replacement was completed for approximately $65 million and production resumed to full rates on January 19, 2020.
    • Record monthly production of approximately 262,600 bbl/d of SCO was achieved at Horizon in February 2020 as a result of continued high utilization, safe, steady and reliable operations.
  • At the non-operated Scotford Upgrader, a planned 55 day turnaround is targeted to start in April 2020, at which time the Upgrader will run at gross restricted rates of approximately 160,000 bbl/d of SCO. Timing of planned pit stop activities at the AOSP mines is aligned with the planned turnaround at the Scotford Upgrader. Production impacts are reflected in the Company's annual 2020 guidance and will be managed as part of the Company's curtailment optimization strategy.
  • The Company continues to progress engineering work on a prudent basis for potential expansion opportunities at Horizon to increase reliability and lower costs, targeting to add production of 75,000 bbl/d to 95,000 bbl/d. The final investment decision on these opportunities will not be made until there is greater clarity on market access.

MARKETING

		Three Months Ended																			Year Ended
		Dec 31 2019						Sep 30 2019						Dec 31 2018							Dec 31 2019						Dec 31 2018
Crude oil and NGLs pricing
WTI benchmark price (US$/bbl) (1)		$			56.96			$			56.45			$			58.83				$			57.04			$			64.78
WCS heavy differential as a percentage of WTI (%) (2)		28				%		22				%		67				%			22				%		41				%
SCO price (US$/bbl)		$			56.32			$			56.87			$			37.48				$			56.35			$			58.62
Condensate benchmark pricing (US$/bbl)		$			52.99			$			52.00			$			45.27				$			52.84			$			60.98
Average realized pricing before risk management (C$/bbl) (3)		$			49.60			$			55.19			$			25.95				$			55.08			$			46.92
Natural gas pricing
AECO benchmark price (C$/GJ)		$			2.21			$			0.99			$			1.80				$			1.54			$			1.45
Average realized pricing before risk management (C$/Mcf)		$			2.64			$			1.64			$			3.46				$			2.34			$			2.61

(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.

• Mainline enhancements of approximately 100,000 bbl/d of capacity were completed in December 2019, increasing pipeline capacity out of the WCSB.
• Additional pipeline egress of approximately 190,000 bbl/d to move incremental crude oil production out of the WCSB is targeted to be added by industry over the near term, providing opportunities for the Company before new export pipelines are constructed:
  • Additional Mainline enhancements of 50,000 bbl/d of capacity is targeted in 2020.
  • Express pipeline optimization expansion is targeted to add approximately 50,000 bbl/d of capacity in 2020.
  • The NWR Refinery is targeted to add approximately 40,000 bbl/d of incremental crude oil conversion capacity. Upon start-up of the Gasifier and LC Finer units, the refinery will process a total of approximately 80,000 bbl/d of diluted bitumen, increasing effective takeaway capacity out of the WCSB.
    • The Company has a 50% interest in the NWR Partnership. For updates on the project, please refer to:
      https://nwrsturgeonrefinery.com/whats-happening/news/.
  • Base Keystone export pipeline optimization expansion of approximately 50,000 bbl/d was recently announced. In Q3/19, Canadian Natural committed to approximately 10,000 bbl/d of the expansion, which is targeted to be available in 2020.
• Crude by rail volumes continue to be strong at approximately 350,000 bbl/d for the month of December 2019.
• 2019 differentials between WCS and WTI benchmark pricing narrowed from 2018 levels following the Government of Alberta's announcement of mandatory curtailments of crude oil production that came into effect January 1, 2019.
• AECO natural gas prices increased in Q4/19 from Q3/19 and Q4/18 levels, reflecting additional egress capability, seasonal demand factors and the impact of the TC Energy Temporary Service Protocol in Q4/19.

GOVERNANCE

• As part of the Company's ongoing Governance process, Steve W. Laut, who was appointed Executive Vice-Chairman in March 2018 after serving as President for the previous 13 years, has decided to step back from the day to day operations of the Company at or before the Company's Annual General Meeting ("AGM") in May 2020. Mr. Laut will remain on the Board of Directors (the "Board") and stand for re-election at the 2020 AGM.
• As previously announced Dr. M. Elizabeth Cannon was appointed to the Board effective November 5, 2019 and will stand for election at the 2020 AGM. Dr. Cannon has many significant accomplishments with the most recent being President Emerita and Professor of Engineering at the University of Calgary having previously served at the University of Calgary as Dean of the Schulich School of Engineering from 2006-2010, President and Vice Chancellor from 2010 to 2018.
• Timothy W. Faithfull will be stepping down from the Board in accordance with the Company's mandatory retirement policy. Mr. Faithfull has been a valued member of the Board of Directors, serving as a member since November 2010.

FINANCIAL REVIEW

The Company continues to implement proven strategies and 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 programs all support a flexible financial position and provide the appropriate financial resources for the near-, mid- and long-term.

• The Company’s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved production levels of 1,098,957 BOE/d in 2019, with approximately 98% of total production located in G7 countries.
  • Canadian Natural maintains a balance of products with 2019 production mix on a BOE/d basis of 49% light crude oil and SCO blends, 28% heavy crude oil blends and 23% natural gas.
• Canadian Natural delivered record annual free cash flow of $4,620 million after net capital expenditures of $3,904 million and dividend requirements of $1,743 million, and excluding Devon Canada asset acquisition costs, reflecting the strength of the Company's long life low decline asset base and effective and efficient operations.
  • Balance sheet strength remains a focus as year end 2019 long-term debt totaled $20,982 million, comparable to Q1/19 levels prior to the Devon Canada asset acquisition, and debt to book capitalization strengthened to 37.3% from 39.1% at year end 2018 while debt to adjusted EBITDA improved to 1.9x from 2.0x at year end 2018. During 2019, the Company executed on the following:
    • The Company repaid $500 million of 3.05% notes and $500 million of 2.60% notes in Q2/19 and Q4/19, respectively.
    • The Company fully repaid and cancelled the remaining balance of the $1,800 million non-revolving term loan credit facility that was used to finance the AOSP acquisition, ahead of its maturity in May 2020.
    • In Q4/19, the Company extended the $2,425 million revolving syndicated credit facility scheduled to mature in June 2021 to June 2023. Additionally, the $2,200 million non-revolving term credit facility, originally due in October 2020, was extended to February 2023 and increased by $450 million to $2,650 million.
    • Canadian Natural maintains strong financial stability and liquidity represented by cash balances, and committed and demand bank credit facilities. At December 31, 2019, the Company had approximately $4,876 million of available liquidity, including cash and cash equivalents, an increase of approximately $52 million and $196 million over 2018 and Q3/19 levels respectively.
  • Canadian Natural is committed to returns to shareholders, returning a total of $2,684 million to shareholders in 2019, $1,743 million by way of dividends and $941 million by way of share repurchases.
    • Share repurchases for cancellation totaled 25,900,000 common shares at a weighted average share price of $36.32.
    • Subsequent to year end, up to and including March 4, 2020, the Company executed on additional share repurchases for cancellation of 6,600,000 common shares at a weighted average share price of $39.41.
    • Returns to shareholders have been significant as Canadian Natural returned approximately $6.2 billion by way of dividends and share repurchases between January 1, 2018 and March 4, 2020.
    • 2019 dividends increased 12% from 2018 levels to $1.50 per share. Subsequent to year end, the Company declared a quarterly dividend increase of 13% to $0.425 per share, payable on April 1, 2020. The increase marks the 20th consecutive year that the Company has increased its dividend, reflecting the Board of Directors' confidence in Canadian Natural's strength and robustness of the Company's assets and its ability to generate significant and sustainable free cash flow.
• In addition to the Company's strong adjusted funds flow, capital flexibility and access to debt capital markets, Canadian Natural has additional financial levers at its disposal to effectively manage its liquidity. As at December 31, 2019, these financial levers include the Company’s third party equity investments of $490 million, and cross currency swaps with a total value of $290 million.

OUTLOOK

The Company targets annual 2020 production levels to average between 910,000 bbl/d and 970,000 bbl/d of crude oil and NGLs and between 1,360 MMcf/d and 1,420 MMcf/d of natural gas, before royalties. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company’s website at www.cnrl.com.

Canadian Natural's annual 2020 capital expenditures are targeted to be approximately $3.95 billion.

2019 YEAR-END RESERVES

Determination of Reserves

For the year ended December 31, 2019, the Company retained Independent Qualified Reserves Evaluators (IQREs), Sproule Associates Limited, Sproule International Limited and GLJ Petroleum Consultants Limited, to evaluate and review all of the Company’s proved and proved plus probable reserves. The evaluation and review was conducted and prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook. The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and escalated costs.

The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with the IQREs as to the Company’s reserves. All reserves values are Company Gross unless stated otherwise.

Summary of Company Gross Reserves

As of December 31, 2019
Forecast Prices and Costs

	Light and Medium Crude Oil (MMbbl)			Primary Heavy Crude Oil (MMbbl)			Pelican Lake Heavy Crude Oil (MMbbl)			Bitumen (Thermal Oil) (MMbbl)			Synthetic Crude Oil (MMbbl)			Natural Gas (Bcf)			Natural Gas Liquids (MMbbl)			Barrels of Oil Equivalent (MMBOE)
North America
Proved
Developed Producing	97			103			235			653			6,219			3,150			92			7,925
Developed Non-Producing	12			14			—			14			—			162			6			72
Undeveloped	56			85			58			1,771			133			3,083			177			2,794
Total Proved	165			202			293			2,438			6,352			6,395			275			10,791
Probable	64			91			132			1,670			545			3,118			133			3,156
Total Proved plus Probable	229			293			425			4,108			6,897			9,513			408			13,947
North Sea
Proved
Developed Producing	37															10						39
Developed Non-Producing	4															1						4
Undeveloped	68															5						69
Total Proved	109															16						112
Probable	67															5						68
Total Proved plus Probable	176															21						179
Offshore Africa
Proved
Developed Producing	32															29						37
Developed Non-Producing	12															6						13
Undeveloped	39															13						41
Total Proved	83															48						91
Probable	31															24						35
Total Proved plus Probable	114															72						126
Total Company
Proved
Developed Producing	166			103			235			653			6,219			3,189			92			8,001
Developed Non-Producing	28			14			—			14			—			169			6			90
Undeveloped	163			85			58			1,771			133			3,101			177			2,903
Total Proved	357			202			293			2,438			6,352			6,460			275			10,993
Probable	162			91			132			1,670			545			3,147			133			3,258
Total Proved plus Probable	519			293			425			4,108			6,897			9,607			408			14,252

Reconciliation of Company Gross Reserves

As of December 31, 2019
Forecast Prices and Costs

PROVED

North America	Light and Medium Crude Oil (MMbbl)			Primary Heavy Crude Oil (MMbbl)			Pelican Lake Heavy Crude Oil (MMbbl)			Bitumen (Thermal Oil) (MMbbl)			Synthetic Crude Oil (MMbbl)			Natural Gas (Bcf)			Natural Gas Liquids (MMbbl)			Barrels of Oil Equivalent (MMBOE)
December 31, 2018	194			182			305			1,540			6,091			6,597			267			9,679
Discoveries	—			—			—			—			—			—			—			—
Extensions	3			6			—			17			385			112			11			440
Infill Drilling	5			5			—			—			—			206			8			52
Improved Recovery	—			—			—			237			—			2			—			238
Acquisitions	2			46			—			769			—			35			1			823
Dispositions	—			—			—			—			—			—			—			—
Economic Factors	(3		)	(3		)	(3		)	—			—			(228		)	(5		)	(53		)
Technical Revisions	(16		)	(3		)	12			(64		)	20			198			11			(8		)
Production	(19		)	(30		)	(21		)	(61		)	(144		)	(527		)	(16		)	(380		)
December 31, 2019	165			202			293			2,438			6,352			6,395			275			10,791
North Sea
December 31, 2018	119															27						124
Discoveries	—															—						—
Extensions	—															—						—
Infill Drilling	—															—						—
Improved Recovery	—															—						—
Acquisitions	—															—						—
Dispositions	—															—						—
Economic Factors	(2		)													—						(2		)
Technical Revisions	2															(2		)				2
Production	(10		)													(9		)				(12		)
December 31, 2019	109															16						112
Offshore Africa
December 31, 2018	86															28						90
Discoveries	—															—						—
Extensions	—															—						—
Infill Drilling	—															—						—
Improved Recovery	—															—						—
Acquisitions	—															—						—
Dispositions	—															—						—
Economic Factors	—															—						—
Technical Revisions	5															29						10
Production	(8		)													(9		)				(9		)
December 31, 2019	83															48						91
Total Company
December 31, 2018	399			182			305			1,540			6,091			6,652			267			9,893
Discoveries	—			—			—			—			—			—			—			—
Extensions	3			6			—			17			385			112			11			440
Infill Drilling	5			5			—			—			—			206			8			52
Improved Recovery	—			—			—			237			—			2			—			238
Acquisitions	2			46			—			769			—			35			1			823
Dispositions	—			—			—			—			—			—			—			—
Economic Factors	(5		)	(3		)	(3		)	—			—			(228		)	(5		)	(54		)
Technical Revisions	(9		)	(3		)	12			(64		)	20			225			11			3
Production	(37		)	(30		)	(21		)	(61		)	(144		)	(544		)	(16		)	(401		)
December 31, 2019	357			202			293			2,438			6,352			6,460			275			10,993

Reconciliation of Company Gross Reserves

As of December 31, 2019
Forecast Prices and Costs

PROVED PLUS PROBABLE

North America	Light and Medium Crude Oil (MMbbl)			Primary Heavy Crude Oil (MMbbl)			Pelican Lake Heavy Crude Oil (MMbbl)			Bitumen (Thermal Oil) (MMbbl)			Synthetic Crude Oil (MMbbl)			Natural Gas (Bcf)			Natural Gas Liquids (MMbbl)			Barrels of Oil Equivalent (MMBOE)
December 31, 2018	268			252			445			3,059			7,032			9,633			397			13,058
Discoveries	—			—			—			—			—			—			—			—
Extensions	4			12			—			26			—			177			17			89
Infill Drilling	6			7			—			—			—			476			15			108
Improved Recovery	—			—			—			329			—			3			—			329
Acquisitions	2			68			—			955			—			42			1			1,033
Dispositions	—			—			—			—			—			—			—			—
Economic Factors	(4		)	(3		)	(3		)	—			—			(266		)	(6		)	(60		)
Technical Revisions	(29		)	(12		)	4			(198		)	9			(26		)	(1		)	(230		)
Production	(19		)	(30		)	(21		)	(61		)	(144		)	(527		)	(16		)	(380		)
December 31, 2019	229			293			425			4,108			6,897			9,513			408			13,947
North Sea
December 31, 2018	186															38						193
Discoveries	—															—						—
Extensions	—															—						—
Infill Drilling	—															—						—
Improved Recovery	—															—						—
Acquisitions	—															—						—
Dispositions	—															—						—
Economic Factors	—															—						—
Technical Revisions	—															(9		)				(2		)
Production	(10		)													(9		)				(12		)
December 31, 2019	176															21						179
Offshore Africa
December 31, 2018	121															63						131
Discoveries	—															—						—
Extensions	—															—						—
Infill Drilling	—															—						—
Improved Recovery	—															—						—
Acquisitions	—															—						—
Dispositions	—															—						—
Economic Factors	—															—						—
Technical Revisions	—															18						3
Production	(8		)													(9		)				(9		)
December 31, 2019	114															72						126
Total Company
December 31, 2018	575			252			445			3,059			7,032			9,734			397			13,382
Discoveries	—			—			—			—			—			—			—			—
Extensions	4			12			—			26			—			177			17			89
Infill Drilling	6			7			—			—			—			476			15			108
Improved Recovery	—			—			—			329			—			3			—			329
Acquisitions	2			68			—			955			—			42			1			1,033
Dispositions	—			—			—			—			—			—			—			—
Economic Factors	(4		)	(3		)	(3		)	—			—			(266		)	(6		)	(60		)
Technical Revisions	(28		)	(12		)	4			(198		)	9			(16		)	(1		)	(228		)
Production	(37		)	(30		)	(21		)	(61		)	(144		)	(544		)	(16		)	(401		)
December 31, 2019	519			293			425			4,108			6,897			9,607			408			14,252

NOTES TO RESERVES:

1. Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.
2. Information in the reserves data tables may not add due to rounding. BOE values and oil and gas metrics may not calculate exactly due to rounding.
3. Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserves estimates were provided by Sproule Associates Limited:

	2020			2021			2022			2023			2024
Crude oil and NGL
WTI at Cushing (US$/bbl)	61.00			65.00			67.00			68.34			69.71
Western Canada Select (C$/bbl)	59.81			63.98			63.77			65.04			66.34
Canadian Light Sweet (C$/bbl)	73.84			78.51			78.73			80.30			81.91
Cromer LSB (C$/bbl)	73.84			77.51			77.73			79.30			80.91
Edmonton Pentanes+ (C$/bbl)	76.32			80.52			80.00			81.68			83.38
North Sea Brent (US$/bbl)	65.00			68.00			70.00			71.40			72.83
Natural gas
AECO (C$/MMBtu)	2.04			2.27			2.81			2.89			2.98
BC Westcoast Station 2 (C$/MMBtu)	1.54			1.87			2.41			2.49			2.58
Henry Hub (US$/MMBtu)	2.80			3.00			3.25			3.32			3.38

All prices increase at a rate of 2%/year after 2024.
A foreign exchange rate of 0.7600 US$/C$ for 2020, 0.7700 US$/C$ for 2021 and 0.8000 US$/C$ after 2021 was used in the 2019 evaluation.

4. A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet of natural gas to one barrel 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.
5. Oil and gas metrics included herein are commonly used in the crude oil and natural gas industry and are determined by Canadian Natural as set out in the notes below. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies and may be misleading when making comparisons. Management uses these metrics to evaluate Canadian Natural’s performance over time. However, such measures are not reliable indicators of Canadian Natural’s future performance and future performance may vary.
6. Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production.
7. Reserves replacement or Production replacement ratio is the Company Gross reserves additions and revisions, for the relevant reserves category, divided by the Company Gross production in the same period.
8. Reserves Life Index is based on the amount for the relevant reserves category divided by the 2020 proved developed producing production forecast prepared by the Independent Qualified Reserves Evaluators.
9. Finding, Development and Acquisition ("FD&A") costs excluding changes in Future Development Costs ("FDC") are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2019 by the sum of total additions and revisions for the relevant reserves category.
10. FD&A costs including changes in FDC are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2019 and net changes in FDC from December 31, 2018 to December 31, 2019 by the sum of total additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and reclamation costs.
11. Abandonment, decommissioning and reclamation ("ADR") costs included in the calculation of the Future Net Revenue (FNR) for 2019 consist of both the Company's total Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as at December 31, 2019 and forecast estimates of ADR costs attributable to future development activity.

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 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 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 Jackfish 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 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 and maintain 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; 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 (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.

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 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.

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 8 - 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 Company's MD&A and unaudited interim consolidated financial statements for the three months and year ended December 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 and year ended December 31, 2019 and the Company's 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 the Company's MD&A. In accordance with the new IFRS 16 "Leases" standard, comparative period balances in 2018 reported in the Company's MD&A have not been restated.

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 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 in the Company's MD&A for information purposes only.

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. Information on the Company's website, including such guidance, 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, March 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, March 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 2279046.

The conference call will also be webcast live and can be accessed on the home page of 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 STEVE W. LAUT Executive Vice-Chairman TIM S. MCKAY President MARK A. STAINTHORPE Chief Financial Officer and Senior Vice-President, Finance Trading Symbol - CNQ Toronto Stock Exchange New York Stock Exchange