Canadian Natural Resources Limited Announces 2019 First Quarter Results

CALGARY, Alberta, May 09, 2019 (GLOBE NEWSWIRE) -- Commenting on the Company's first quarter 2019 results, Steve Laut, Executive Vice-Chairman of Canadian Natural stated, "In the first quarter, the Company demonstrated the resilience and strength of its long life low decline and low capital exposure assets, generating significant adjusted funds flow of approximately $2.2 billion. The Company was able to achieve adjusted funds flow that exceeded net capital expenditures by approximately $1.3 billion, largely due to a strong operational quarter and improvement in crude oil differentials, driven by the Government of Alberta's mandatory production curtailments which is strongly supported by Canadian Natural.

Canadian Natural's top tier low sustaining capital required to maintain production levels, combined with industry leading effective and efficient operations, were evident in Q1/19 as adjusted funds flow less net capital expenditures was comparable to Q1/18 when West Texas Intermediate ("WTI") was approximately US$8.00/bbl higher."

Canadian Natural's President, Tim McKay, added, "Operations were strong in the first quarter as our large, balanced and diverse asset base allowed the Company to strategically manage through the mandatory production curtailments to maximize value. Production was as expected in Q1/19, reaching approximately 1,035,000 BOE/d, consisting of 54% light crude oil, NGLs and Synthetic Crude Oil ("SCO"), 22% heavy crude oil and 24% natural gas.

Effective and efficient operations across the Company continue to be a significant driver of value creation for Canadian Natural. Our Oil Sands Mining and Upgrading segment Q1/19 operating costs were top tier at $21.46/bbl (US$16.14/bbl) of SCO. Equally as impressive were our Conventional E&P assets achieving operating costs of $12.68/BOE (US$9.54/BOE) in Q1/19, a reduction of 6% from Q4/18 levels, strong results given mandatory production curtailments in the quarter."

Canadian Natural's Chief Financial Officer, Mark Stainthorpe, continued, "In the first quarter, Canadian Natural realized solid results as profitability and value from our diverse asset base generated net earnings of approximately $1.0 billion. Net earnings were up dramatically from Q4/18, reflecting the dysfunctional crude oil market which existed in Q4/18 and the success of the Government of Alberta's mandatory production curtailment program to restore a normal market in Q1/19.

The Company's capital discipline and financial strength resulted in robust free cash flow of $860 million, after net capital expenditures and dividends. Share purchases were $241 million (6.65 million shares) in Q1/19 pursuant to the Company's free cash flow allocation policy. As a result of the increased confidence in free cash flow levels for the remainder of 2019, the rate of share purchases has increased as Q2/19 commenced, with purchases totaling $159 million (4.05 million shares) from April 1, 2019 to May 8th, 2019."

QUARTERLY HIGHLIGHTS

			Three Months Ended
($ millions, except per common share amounts)			Mar 31  2019				Dec 31  2018				Mar 31  2018
Net earnings (loss)			$	961			$	(776	)		$	583
Per common share	– basic		$	0.80			$	(0.64	)		$	0.48
	– diluted		$	0.80			$	(0.64	)		$	0.47
Adjusted net earnings (loss) from operations (1)			$	838			$	(255	)		$	885
Per common share	– basic		$	0.70			$	(0.21	)		$	0.72
	– diluted		$	0.70			$	(0.21	)		$	0.71
Cash flows from operating activities			$	996			$	1,397			$	2,469
Adjusted funds flow (2)			$	2,240			$	1,229			$	2,323
Per common share	– basic		$	1.87			$	1.02			$	1.90
	– diluted		$	1.86			$	1.02			$	1.89
Cash flows used in investing activities			$	1,029			$	1,042			$	1,369
Net capital expenditures (3)			$	977			$	1,181			$	1,103
Daily production, before royalties
Natural gas (MMcf/d)			1,510				1,488				1,614
Crude oil and NGLs (bbl/d)			783,512				833,358				854,558
Equivalent production (BOE/d) (4)			1,035,212				1,081,368				1,123,546

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 Management’s Discussion and Analysis (“MD&A”).
   
   
2. Adjusted funds flow (previously referred to as funds flow from operations) is a non-GAAP measure that the Company considers key 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 MD&A.
   
   
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 quarterly capital budget. For additional information and details, refer to the net capital expenditures table in the Company's MD&A.
   
   
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 $961 million were realized in Q1/19, increases of $1,737 million and $378 million over Q4/18 and Q1/18 levels, respectively. Adjusted net earnings of $838 million were achieved in Q1/19, a $1,093 million increase over Q4/18 levels.
  
  
• Cash flows from operating activities were $996 million in Q1/19, a decrease of $401 million compared to Q4/18 levels.
  
  
• Canadian Natural generated significant quarterly adjusted funds flow of $2,240 million in Q1/19, an increase of 82% or $1,011 million over Q4/18 levels. The increase quarter over quarter was primarily due to strong operations in the quarter and higher netbacks in all segments, as crude oil markets in Canada returned to normal with the Government of Alberta's mandatory production curtailments.
  
  
• Cash flows used in investing activities remain disciplined at $1,029 million in Q1/19, in-line with Q4/18 levels.
  
  
• Canadian Natural delivered strong quarterly free cash flow of $860 million after net capital expenditures of $977 million and dividend requirements of $403 million, reflecting the strength of our long life low decline asset base and our effective and efficient operations.
   
• Canadian Natural is committed to returns to shareholders, returning a total of $644 million in the quarter, $403 million by way of dividends and $241 million by way of share purchases.
  
  
  • Share purchases for cancellation in the quarter totaled 6,650,000 common shares at a weighted average share price of $36.24. Subsequent to quarter end and up to and including May 8, 2019, the Company executed on additional share purchases of 4,050,000 common shares for cancellation at a weighted average share price of $39.34.
    
    
  • In Q1/19 the Company increased its quarterly dividend by 12% from Q4/18 levels, marking the 19th consecutive year that the Company has increased its dividend, reflecting the Board of Directors' confidence in Canadian Natural's sustainability and robustness of the Company's asset base and its ability to generate significant adjusted funds flow.
    
    
  • Subsequent to quarter end, the Company declared a quarterly dividend of $0.375 per share, payable on July 1, 2019.
    
    
  • The Company's Board of Directors has approved a motion to renew the Normal Course Issuance Bid ("NCIB") and the continuation of the free cash flow allocation policy.
    
    
• The Company achieved quarterly production volumes of 1,035,212 BOE/d in Q1/19, a decrease of 4% from Q4/18 levels reflecting the Government of Alberta's mandatory production curtailments.
  
  
  • The Company continues to strategically adjust timing of planned maintenance activities across its asset base, including Oil Sands Mining and Upgrading, thermal in situ and North American Exploration & Production ("E&P") to maximize value within the current curtailment environment.
    
    
• At the Company's world class Oil Sands Mining and Upgrading assets, industry leading operations provided quarterly production of 416,206 bbl/d of Synthetic Crude Oil ("SCO"), a decrease of 7% from Q4/18 levels. The decrease in production was primarily due to mandatory curtailments, previously announced accelerated maintenance activities as well as unplanned maintenance.
  
  
  • Operating costs were top tier, as the Company realized quarterly unadjusted operating costs of $21.46/bbl (US$16.14/bbl) of SCO in Q1/19, in-line with Q1/18 levels, strong results given curtailment and maintenance activities in the quarter.
    
    
  • As previously announced on May 1, 2019, Canadian Natural provided a follow up on a fire which occurred at the Scotford Upgrader on April 15, 2019, in which the Company has a 70% interest. The fire was promptly extinguished, all personnel were accounted for, and there were no reported injuries.
    
    
    • The fire was contained to a process furnace in the North Upgrader, while operations at the base upgrader plant ("South Upgrader") were not impacted by the fire. The planned 38 day turnaround began on April 14, 2019 at the Scotford Upgrader, during which time the South Upgrader will run at a restricted net processing rate of approximately 140,000 bbl/d of SCO. Upon completion of the planned maintenance, May and June average net production at the Albian mines is targeted to be approximately 171,500 bbl/d versus the Company's previously targeted net curtailment production volumes at the Albian mines of approximately 178,500 bbl/d. The cost for repairs of the North Upgrader is estimated to be approximately $15 million gross and is targeted to be fully operational by early June. The Company continues to optimize other assets in Alberta to mitigate the impacts of curtailments on its production.
      
      
• International E&P quarterly production volumes were strong in Q1/19, averaging 47,869 bbl/d, increases of 11% and 17% from Q4/18 and Q1/18 levels respectively. The increases were mainly as a result of successful 2018 drilling and turnaround activities that were completed in Q4/18 in the North Sea. Additionally, in Offshore Africa, successful 2018 drilling contributed to International production increases from Q1/18, partially offset by natural declines.
  
  
  • International production volumes benefit from premium Brent pricing, generating significant adjusted funds flow for the Company.
    
    
• In the Company's thermal in situ operations, pad additions at Primrose continue to be on budget and ahead of schedule with initial production targeted in Q4/19. The program targets to add approximately 26,000 bbl/d in the first 12 months of production. These pad additions are high return activities as the Company utilizes available excess oil processing and steam capacity at Primrose.
  
  
• As previously announced, at the Company's Kirby North Steam Assisted Gravity Drainage ("SAGD") project, top tier execution and strong productivity have resulted in the project progressing two quarters ahead of the sanctioned schedule with overall cost performance remaining on budget. The commissioning of the central processing facility was also top tier and as a result, the project began steaming on May 1, 2019 and targets to progressively ramp up production towards Kirby North's overall capacity of 40,000 bbl/d, in late 2020.
  
  
• Canadian Natural maintains strong financial stability and liquidity represented by cash balances, and committed and demand bank credit facilities. At March 31, 2019 the Company had approximately $4,230 million of available liquidity, including cash and cash equivalents.

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 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 its 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 its 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

	Three Months Ended Mar 31
	2019				2018
(number of wells)	Gross		Net		Gross		Net
Crude oil	30		30		127		122
Natural gas	10		8		8		5
Dry	1		1		2		2
Subtotal	41		39		137		129
Stratigraphic test / service wells	375		332		528		450
Total	416		371		665		579
Success rate (excluding stratigraphic test / service wells)			97	%			98	%

• The Company's total crude oil and natural gas drilling program of 39 net wells for the three months ended March 31, 2019, excluding strat/service wells, decreased by 90 net wells from the same period in 2018. The Company's drilling levels reflect the disciplined capital allocation process and continued actions to improve execution.

North America Exploration and Production

Crude oil and NGLs – excluding Thermal In Situ Oil Sands
	Three Months Ended
	Mar 31  2019		Dec 31  2018		Mar 31  2018
Crude oil and NGLs production (bbl/d)	225,291		240,942		245,609
Net wells targeting crude oil	28		62		101
Net successful wells drilled	28		61		99
Success rate	100	%	98	%	98	%

• North America crude oil and NGLs averaged 225,291 bbl/d in Q1/19, reflecting mandatory production curtailments, representing a decrease of 6% from Q4/18 levels that were already voluntarily curtailed by approximately 10,600 bbl/d.
  
  
  • Canadian Natural's primary heavy crude oil production averaged 68,473 bbl/d in Q1/19, reflecting mandatory production curtailments, and the strategic decision to reduce activity on drilling, workovers, recompletions and optimization activities in a curtailed market in Q1/19, representing a decrease of 14% from Q4/18 levels that were already voluntarily curtailed by approximately 9,600 bbl/d.
    
    
    • Operating costs of $17.30/bbl were achieved in the Company's primary heavy crude oil operations in the quarter, a 2% increase from Q1/18 levels, strong results given lower production volumes due to mandatory production curtailments.
      
      
  • North America light crude oil and NGL production averaged 95,578 bbl/d in Q1/19, reflecting mandatory production curtailments in the Company's light crude oil segment, representing a decrease of 3% from Q4/18 levels that were already voluntarily curtailed by approximately 1,000 bbl/d.
    
    
    • Within the greater Wembley area, results continue to exceed expectations. The Company brought 10 net wells on production in Q1/19 that were drilled late in 2018, with initial 30 day liquids production rates averaging approximately 580 bbl/d per well. An additional 3 net wells are targeted to come on production in Q2/19 and Q3/19. Within the greater Wembley area, the Company has identified 155 net Montney sections and 363 incremental potential premium light crude oil and liquids rich well locations.
      
      
    • In the Company's Karr area, 12 net wells came on production in Q1/19, 9 were drilled in Q4/18 and 3 were drilled in Q1/19. Early results have been strong from these wells, with total liquids production of approximately 315 bbl/d per well, exceeding expectations.
      
      
    • In Southeast Saskatchewan and Manitoba, the Company drilled 9 net light crude oil wells in Q1/19. Subsequent to quarter end, these wells came on stream and are currently producing approximately 85 bbl/d per well, in-line with expectations. Production from these Saskatchewan and Manitoba wells are not impacted by production curtailments.
      
      
    • In Q1/19 operating costs of $15.86/bbl were realized in the Company's North America light crude oil and NGL areas, comparable to Q1/18 levels.
      
      
  • Pelican Lake quarterly production averaged 61,240 bbl/d in Q1/19, a decrease of 2% from Q4/18 levels.
    
    
    • Strong operating costs of $6.69/bbl were achieved in Q1/19 at Pelican Lake, a reduction of 5% from Q1/18 levels.
      
      
    • Subsequent to quarter end, in April 2019 facility consolidation was completed on time and on budget, and as a result operating cost savings of approximately $6 million per year are targeted.
      
      
    • The Company targets to expand the polymer flood further in Q2/19, with the conversion of 3 additional pads from water flood to polymer flood.
      
      
• The Company’s annual 2019 North America E&P crude oil and NGL production guidance remains unchanged and is targeted to range between 221,000 bbl/d - 241,000 bbl/d.

Thermal In Situ Oil Sands
	Three Months Ended
	Mar 31  2019		Dec 31  2018		Mar 31  2018
Bitumen production (bbl/d)	94,146		102,112		111,851
Net wells targeting bitumen	—		41		22
Net successful wells drilled	—		40		22
Success rate	—		98	%	100	%

• Thermal in situ production volumes averaged 94,146 bbl/d in Q1/19, reflecting mandatory production curtailments, representing a decrease of 8% from Q4/18 levels that were already voluntarily curtailed by approximately 13,900 bbl/d at Primrose.
  
  
  • At Primrose, Q1/19 production volumes averaged 61,925 bbl/d, a decrease of 9% from Q4/18 levels, as a result of production curtailments. Including energy costs, operating costs were $20.23/bbl in Q1/19, an increase of 22% from Q1/18, reflecting lower volumes due to curtailments and higher energy costs.
    
    
    • Pad additions at Primrose continue to be on budget and ahead of schedule with initial production targeted in Q4/19. The program targets to add approximately 26,000 bbl/d in the first 12 months of production. These pad additions are high return activities as the Company utilizes available excess oil processing and steam capacity at Primrose.
      
      
  • At Kirby South, SAGD production volumes averaged 29,692 bbl/d in Q1/19, a decrease of 8% from Q4/18 levels. Including energy costs, Kirby South quarterly operating costs were $12.31/bbl in Q1/19, an increase of 35% from Q1/18 as a result of lower volumes and higher energy costs.
    
    
  • As previously announced, at the Company's Kirby North SAGD project, top tier execution and strong productivity have resulted in the project progressing two quarters ahead of the sanctioned schedule with overall cost performance remaining on budget. The commissioning of the central processing facility was also top tier and as a result the project began steaming on May 1, 2019 and targets to progressively ramp up production towards Kirby North's overall capacity of 40,000 bbl/d, in late 2020.
    
    
• The Company’s annual 2019 thermal in situ production guidance remains unchanged and is targeted to range between 104,000 bbl/d - 124,000 bbl/d.

North America Natural Gas
	Three Months Ended
	Mar 31  2019		Dec 31  2018		Mar 31  2018
Natural gas production (MMcf/d)	1,454		1,441		1,547
Net wells targeting natural gas	9		3		5
Net successful wells drilled	8		3		5
Success rate	89	%	100	%	100	%

• North America natural gas production was 1,454 MMcf/d in Q1/19, in-line with Q4/18 levels.
  
  
• Operating costs of $1.30/Mcf were realized in Q1/19, in-line with Q1/18 levels.
  
  
• At the Company's high value Septimus Montney liquids rich area, 5 net wells were drilled in Q1/19 with targeted production of approximately 2,080 bbl/d of NGLs and approximately 30 MMcf/d of natural gas, in late Q2/19.
  
  
  • Modest drilling activity from prolific wells targets to return the Septimus plant to full capacity, while reducing already low Q1/19 operating costs of $0.36/Mcfe, supporting high netbacks and maximizing value.
    
    
  • The Company's natural gas reinjection pilot at Septimus is targeted to commence first injection of 5 MMcf/d late in Q2/19. This technology 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.
    
    
    • Results from the first injection and production cycle are targeted for late 2019 with the potential to proceed with additional cycles at the same location. Given the opportunities for this process across Canadian Natural's vast liquids rich Montney land base, the Company is advancing readiness for a second pilot site within the Company's Greater Wembley area.
      
      
• Regulatory approval was received from the National Energy Board on May 3, 2019 regarding the transfer of assets to British Columbia provincial jurisdiction of the Pine River plant and operatorship to a subsidiary of Canadian Natural. The acquisition is targeted to close in Q2/19 and targets better plant efficiency and running time.
  
  
• In 2019, based upon the midpoint of annual production guidance, Canadian Natural targets to use the equivalent of approximately 37% of its total corporate natural gas production in its operations, providing a natural hedge from the challenging Western Canadian natural gas price environment. Approximately 34% of the Company's guided 2019 natural gas production is targeted to be exported to other North American markets and sold internationally. The remaining 29% of the Company's 2019 targeted natural gas production would be exposed to AECO/Station 2 pricing.
  
  
• The Company’s annual 2019 corporate natural gas production guidance remains unchanged and is targeted to range between 1,485 MMcf/d - 1,545 MMcf/d.

International Exploration and Production

	Three Months Ended
	Mar 31  2019		Dec 31  2018		Mar 31  2018
Crude oil production (bbl/d)
North Sea	25,714		21,071		21,584
Offshore Africa	22,155		22,185		19,438
Natural gas production (MMcf/d)
North Sea	28		22		37
Offshore Africa	28		25		30
Net wells targeting crude oil	1.6		1.1		1.0
Net successful wells drilled	1.6		1.1		1.0
Success rate	100	%	100	%	100	%

• International E&P quarterly production volumes were strong in Q1/19, averaging 47,869 bbl/d, increases of 11% and 17% from Q4/18 and Q1/18 levels, respectively, as described below. The operating costs below include impacts of IFRS 16.
  
  
• International production volumes benefit from premium Brent pricing, generating significant adjusted funds flow for the Company.
  
  
  • In the North Sea, production volumes of 25,714 bbl/d were achieved in Q1/19, increases of 22% and 19% over Q4/18 and Q1/19 levels respectively. The increase over Q4/18 primarily reflected the impact of production resuming following the planned turnarounds and maintenance activities completed during Q4/18. The increase over Q1/18 primarily reflected the impact of the drilling program completed in 2018, partially offset by natural field declines.
    
    
    • Q1/19 operating costs in the North Sea averaged $39.68/bbl (£22.60/bbl), a reduction of 9% from Q1/18 levels.
      
      
    • The 2019 drilling program consists of high value and high netback production additions from 3.8 net producer wells targeted in the North Sea. Drilling commenced in Q1/19 at the Ninian South Platform and late in the quarter 1.0 net well was completed on time and on budget. Production came on stream subsequent to quarter end and is exceeding expectations of 3,900 bbl/d.
      
      
    • The Company is targeting planned turnaround activities at the Ninian Central Platform late in Q2/19. Production impacts are reflected in Q2/19 and annual 2019 guidance.
      
      
  • Offshore Africa production volumes in Q1/19 averaged 22,155 bbl/d, in-line with Q4/18 levels and an increase of 14% over Q1/18 levels. The increase in production over Q1/18 primarily reflected volumes from new wells drilled at Baobab in 2018, partially offset by the cessation of production at the Olowi field in Gabon in December 2018 and natural field declines.
    
    
    • Côte d'Ivoire crude oil operating costs averaged $9.79/bbl (US$7.36/bbl) in Q1/19, a reduction of 3% from Q1/18 levels.
      
      
    • The Company completed the last 0.6 net producer well from the Baobab drilling program late in Q1/19. The drilling program resulted in current high netback production of approximately 8,000 bbl/d net, exceeding budgeted expectations.
      
      
      • The total Baobab drilling program included 4 gross (2.4 net) producer wells and 2 gross (1.2 net) injector wells, of which the second gross (0.6 net) injector well was completed subsequent to quarter end in Q2/19.
        
        
    • The Company targets to drill an appraisal well (0.6 net) at Kossipo in Q2/19, and if successful may lead to development drilling and a pipeline tied-back to the Baobab Floating Production Storage and Offloading vessel, adding significant future value with potential gross production capability of 20,000 bbl/d targeted in 2022.
       
    • Following the successful completion of the Baobab drilling program, the Company targets to commence an additional high value drilling program in Q4/19 at Espoir, with initial production targeted for early 2020.
      
      
      • The Espoir drilling program is targeting 3 gross producer wells (1.8 net) and 2 gross injector wells (1.2 net) with the potential to add an average of approximately 2,500 BOE/d of high netback production per well in the first 12 months. Approximately 75% of production is targeted to be light crude oil.
        
        
    • In Q1/19, the operator of the South Africa exploration well, where Canadian Natural owns a 20% working interest, announced a discovery of significant gas condensate. The cost of the first exploration well is fully carried.
      
      
      • In 2019, the operator targets to acquire 3D seismic on the Block.
        
        
      • In 2020, the operator targets to drill a second exploration well and may drill two further exploration/appraisal wells to further define volumes and deliverability.
        
        
• The Company's annual 2019 International production guidance remains unchanged and is targeted to range from 42,000 bbl/d - 46,000 bbl/d.

North America Oil Sands Mining and Upgrading

	Three Months Ended
	Mar 31  2019		Dec 31  2018		Mar 31  2018
Synthetic crude oil production (bbl/d) (1) (2)	416,206		447,048		456,076

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, industry leading operations provided quarterly production of 416,206 bbl/d of SCO, a decrease of 7% from Q4/18 levels. The decrease in production was primarily due to mandatory curtailments, previously announced accelerated maintenance activities as well as unplanned maintenance.
  
  
  • Operating costs were top tier, as the Company realized quarterly unadjusted operating costs of $21.46/bbl (US$16.14/bbl) of SCO in Q1/19, in-line with Q1/18 levels, strong results given curtailment and maintenance activities in the quarter.
    
    
• The Company continues to progress engineering work on the previously announced potential expansion and reliability opportunities at Horizon to increase reliability and lower costs, targeting to add production of 75,000 bbl/d to 95,000 bbl/d. The engineering and design specification work continued in the quarter and is targeted to be complete in Q3/19.
  
  
  • The potential Paraffinic Froth Treatment expansion at Horizon is targeting 40,000 bbl/d to 50,000 bbl/d of high quality diluted bitumen at significantly lower operating costs as the Company leverages its existing infrastructure. The preliminary estimate of the capital required is approximately $1.4 billion.
    
    
  • Stage 1 and 2 reliability opportunities at Horizon are targeted to add 35,000 bbl/d to 45,000 bbl/d of SCO.
    
    
  • The Company targets to sanction the potential expansion and reliability opportunities with greater clarity on improved market access.
    
    
• As previously announced on May 1, 2019, Canadian Natural provided a follow up on a fire which occurred at the Scotford Upgrader on April 15, 2019, in which the Company has a 70% interest. The fire was promptly extinguished, all personnel were accounted for, and there were no reported injuries.
  
  
  • The fire was contained to a process furnace in the North Upgrader, while operations at the base upgrader plant ("South Upgrader") were not impacted by the fire. The planned 38 day turnaround began on April 14, 2019 at the Scotford Upgrader, during which time the South Upgrader will run at a restricted net processing rate of approximately 140,000 bbl/d of SCO. Upon completion of the planned maintenance, May and June average net production at the Albian mines is targeted to be approximately 171,500 bbl/d versus the Company's previously targeted net curtailment production volumes at the Albian mines of approximately 178,500 bbl/d. The cost for repairs of the North Upgrader is estimated to be approximately $15 million gross and is targeted to be fully operational by early June. The Company continues to optimize other assets in Alberta to mitigate the impacts of curtailments on its production.
    
    
• The Company's annual 2019 Oil Sands Mining and Upgrading production guidance remains unchanged and is targeted to range between 415,000 bbl/d - 450,000 bbl/d of SCO.

MARKETING

		Three Months Ended
		Mar 31  2019				Dec 31  2018				Mar 31  2018
Crude oil and NGLs pricing
WTI benchmark price (US$/bbl) (1)		$	54.90			$	58.83			$	62.89
WCS heavy differential as a percentage of WTI (%) (2)		23		%		67		%		39		%
SCO price (US$/bbl)		$	52.19			$	37.48			$	61.45
Condensate benchmark pricing (US$/bbl)		$	50.49			$	45.27			$	63.12
Average realized pricing before risk management (C$/bbl) (3)		$	53.98			$	25.95			$	43.06
Natural gas pricing
AECO benchmark price (C$/GJ)		$	1.84			$	1.80			$	1.75
Average realized pricing before risk management (C$/Mcf)		$	3.09			$	3.46			$	2.74

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.

• Q1/19 differentials between SCO and West Texas Intermediate ("WTI") benchmark pricing and Western Canadian Select ("WCS") and WTI benchmark pricing narrowed significantly to more normalized levels following the Government of Alberta's announcement of mandatory curtailments of crude oil production on December 2, 2018.
  
  
• AECO natural gas prices increased in Q1/19 from Q1/18 levels, reflecting the easing of third party pipeline constraints.
  
  
• The North West Redwater ("NWR") refinery, upon completion, will strengthen the Company’s position by providing a competitive return on investment and by creating incremental demand for approximately 80,000 bbl/d of heavy crude oil blends that will not require export pipelines, helping to reduce pricing volatility in all Western Canadian heavy crude oil.
  
  
  • The Company has a 50% interest in the NWR Partnership. For updates on the project, please refer to:                                                    https://nwrsturgeonrefinery.com/whats-happening/news/.

ENVIRONMENTAL HIGHLIGHTS

• Canadian Natural has invested over $3.4 billion in research and development since 2009 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. 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 through the NWR refinery. 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, making the Company one of the largest CO₂ capturer and sequester for the oil and natural gas sector globally once the NWR refinery is fully running.
  
  
• At Canadian Natural's Oil Sands Mining and Upgrading and thermal in situ operations, which represent approximately 65% of the Company's liquids production, the Company's emissions intensity is only approximately 5% higher than the average intensity for all global crude oils. By investing in and leveraging technology, including carbon capture initiatives, Canadian Natural has developed a pathway to reduce the Company's greenhouse gas emissions intensity to below the average for global crude oils.
  
  
• Canadian Natural's commitment to leverage technology, adopting innovation and continuous improvement is evidenced by its In Pit Extraction Process ("IPEP") pilot at Horizon, which will determine the feasibility of producing stackable dry tailings. The project has the potential to reduce the Company's carbon emissions and environmental footprint by reducing the usage of haul trucks, the size and need for tailings ponds and accelerating site reclamation. In addition, this process has the potential to significantly reduce capital and operating costs.
  
  
  • The initial testing phase for the Company's IPEP pilot has concluded and results have been positive with excellent recovery rates and evidence of stackable tailings. As a result of the positive results thus far, the Company continues to make enhancements and will operate and test the pilot through 2019.

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 1,035,212 BOE/d in Q1/19, with approximately 97% of total production located in G7 countries.
  
  
  • Canadian Natural maintains a balance of products with Q1/19 production mix on a BOE/d basis of 54% light crude oil and SCO blends, 22% heavy crude oil blends and 24% natural gas.
    
    
• Canadian Natural delivered strong quarterly free cash flow of $860 million after net capital expenditures of $977 million and dividend requirements of $403 million, reflecting the strength of our long life low decline asset base and our effective and efficient operations.
  
  
• Canadian Natural maintains strong financial stability and liquidity represented by cash balances, and committed and demand bank credit facilities. At March 31, 2019 the Company had approximately $4,230 million of available liquidity, including cash and cash equivalents.
  
  
• Canadian Natural is committed to returns to shareholders, returning a total of $644 million in the quarter, $403 million by way of dividends and $241 million by way of share purchases.
  
  
  • Share purchases for cancellation in the quarter totaled 6,650,000 common shares at a weighted average share price $36.24. Subsequent to quarter end and up to and including May 8, 2019, the Company executed on additional share purchases of 4,050,000 common shares for cancellation at a weighted average share price of $39.34.
    
    
  • In Q1/19 the Company increased its quarterly dividend 12% from Q4/18 levels, marking the 19th consecutive year that the Company has increased its dividend, reflecting the Board of Directors' confidence in Canadian Natural's sustainability and robustness of the asset base driving the ability to generate significant adjusted funds flow.
    
    
  • Subsequent to quarter end, the Company declared a quarterly dividend of $0.375 per share, payable on July 1, 2019.
    
    
• In 2018, the Board of Directors approved a more defined free cash flow allocation policy in accordance with the Company's four stated pillars. Under the new policy, the Company will target to allocate, on an annual basis, 50% of its residual free cash flow, after budgeted capital expenditures and dividends, to share purchases under its NCIB and the remaining 50% to reducing debt levels on the Company's balance sheet. This free cash flow policy will target a ratio of debt to adjusted 12 months trailing EBITDA of 1.5x, and an absolute debt level of $15.0 billion, at which time the policy will be reviewed by the Board. This policy was effective November 1, 2018.
  
  
  • The Company's Board of Director's has approved a motion to renew the NCIB and the continuation of the free cash flow allocation policy.
    
    
• In addition to its 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 March 31, 2018, these financial levers include the Company’s third party equity investments of $549 million, and cross currency swaps and foreign currency forward contracts with a total value of $266 million.
  
  
• All Q1/19 operating costs stated above reflect the impact of the adoption of IFRS 16. The lease liability recognized as required under IFRS 16 as a percentage of total enterprise value is approximately 2.4%, one of the lowest amongst the Company's Canadian peers, reflecting Canadian Natural's disciplined approach to managing longer term contractual arrangements.

OUTLOOK

The Company targets annual 2019 production levels to average between 782,000 bbl/d and 861,000 bbl/d of crude oil and NGLs and between 1,485 MMcf/d and 1,545 MMcf/d of natural gas, before royalties. Q2/19 production guidance before royalties is targeted to average between 773,000 bbl/d and 831,000 bbl/d of crude oil and NGLs and between 1,500 MMcf/d and 1,530 MMcf/d of natural gas. 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 2019 capital expenditures are targeted to be approximately $3.7 billion.

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 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 timing and future operations of the North West Redwater bitumen upgrader and refinery, construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil (“SCO”) that the Company may be reliant upon to transport its products to market, and the development and deployment of technology and technological innovations also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.
In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.

The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company’s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company’s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company’s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company’s and its subsidiaries’ ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of the Company’s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company’s bitumen products; availability and cost of financing; the Company’s and its subsidiaries’ success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset retirement obligations; the adequacy of the Company’s provision for taxes; and other circumstances affecting revenues and expenses.

The Company’s operations have been, and in the future may be, affected by political developments and by national, federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in 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, 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 and Other 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); net capital expenditures; free cash flow; debt to adjusted EBITDA; available liquidity; adjusted operating costs; unadjusted operating costs; and enterprise value. These financial measures are not defined by International Financial Reporting Standards ("IFRS") and therefore are referred to as non-GAAP measures and other financial 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, cash flows used in investing activities, and cash flows used in financing 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.

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.

Adjusted operating costs are derived as production expense based on sales volumes excluding costs incurred in turnaround periods. See "Operating Highlights - Oil Sands Mining and Upgrading" section in the Company’s MD&A.

Unadjusted operating costs also referred to as cash production costs in the Company’s MD&A.  See "Operating Highlights - Oil Sands Mining and Upgrading" section in the Company’s MD&A.

Enterprise value is derived as the sum of the Company’s market capitalization and total long-term debt less cash and cash equivalents. Market capitalization is derived as total outstanding common shares multiplied by the market price per common share at any given period.

Special Note Regarding Currency, Financial Information and Production

The Company's MD&A should be read in conjunction with the unaudited interim consolidated financial statements for the three months ended March 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 ended March 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 "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 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, 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.

CONFERENCE CALL

A conference call will be held at 8:00 a.m. Mountain Time, 10:00 a.m. Eastern Time on Thursday, May 9, 2019.

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, May 23, 2019. 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 9681416.

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