Canadian Natural Resources Limited Announces 2020 Second Quarter Results

8/6, 11:00 AM (Source: GlobeNewswire)

CALGARY, Alberta, Aug. 06, 2020 (GLOBE NEWSWIRE) -- Commenting on the Company's second quarter 2020 results, Tim McKay, President of Canadian Natural, stated "Canadian Natural is in a strong position as a result of our capital flexibility and continued focus on cost control, which maximizes margins in a volatile commodity price environment. The effectiveness of our strategies and our ability to execute on those strategies allows us to react quickly to changing markets and commodity price volatility.

In Q2/20, we delivered top tier operational results, producing approximately 1,165 MBOE/d, including liquids production of approximately 922 Mbbl/d, as our teams worked effectively to bring the majority of the voluntary curtailed volumes back on production in June 2020. Importantly, in our Oil Sands Mining and Upgrading assets, we achieved record quarterly production of high value Synthetic Crude Oil ("SCO") of approximately 464,300 bbl/d, inclusive of planned maintenance at Horizon in May. As well, we achieved record low Oil Sands Mining and Upgrading operating costs of $17.74/bbl (US$12.80/bbl) in Q2/20 levels, a 15% decrease from Q1/20, by continuing to focus on cost control.

In response to COVID-19, the Company implemented comprehensive precautions to ensure the health and safety of our workers while maintaining safe, reliable operations. We continue to focus on our environmental, social and governance ("ESG") performance throughout this volatility. ESG performance remains a top priority within the Company and there has been no change to our environmental targets set in December 2019, nor our environmental focused investments, which help reduce our environmental footprint and our GHG emissions, despite the economic impacts of COVID-19."

Canadian Natural's Chief Financial Officer, Mark Stainthorpe, added "The Company maintains a flexible and disciplined capital allocation strategy, with a focus on maintaining a strong financial position throughout the commodity price cycle. We have been proactive in managing our balance sheet and executing on our capital flexibility, with our targeted 2020 capital program on track at approximately $2.7 billion, while maintaining strong production levels throughout the year.

We generated adjusted funds flow of $415 million in Q2/20, reflecting the strength of the Company's long life low decline asset base, effective and efficient operations and our ability to maximize netbacks. Maximizing value for our shareholders, the Company elected to store as inventory at quarter end, a higher portion than normal of our SCO and International light crude oil production in the low commodity price quarter. If these barrels had been sold during the second quarter of 2020, based on June 2020 commodity prices, the Company would have generated approximately $60 million in additional cash flows from operating activities and adjusted funds flow in the quarter.

Our long life low decline assets continue to have industry leading low breakeven prices required to cover our low sustaining capital requirements and our current dividend, of approximately US$30 to US$31 WTI per barrel, reflecting our effective and efficient operations and our low to no reservoir risk, a distinct advantage in a volatile price environment. As a result, a small percentage of our total proved reserves are produced during challenging commodity price periods, resulting in very little impact to the Company's net asset value, thereby preserving long-term value for our shareholders and creditors.

At June 30, 2020, liquidity was strong at approximately $4.1 billion. As previously announced, in June we successfully completed the issue of two US dollar denominated bonds raising approximately $1.5 billion (US$1.1 billion). The Company's balance sheet remains resilient through this commodity price cycle, supported by strong investment grade credit ratings. In the second half of 2020, targeted free cash flow generation is significant, supporting a sustainable dividend and at current strip pricing targeted net debt at year end December 31, 2020 to be flat year-over-year."

QUARTERLY HIGHLIGHTS

  Three Months Ended  Six Months Ended
            
($ millions, except per common share amounts) Jun 30
2020
 Mar 31
2020
 Jun 30
2019
  Jun 30
2020
 Jun 30
2019
Net earnings (loss) $(310)  $(1,282)  $2,831    $(1,592)  $3,792  
Per common share– basic $(0.26)  $(1.08)  $2.37    $(1.35)  $3.17  
 – diluted $(0.26)  $(1.08)  $2.36    $(1.35)  $3.16  
Adjusted net earnings (loss) from operations (1) $(772)  $(295)  $1,042    $(1,067)  $1,880  
Per common share– basic $(0.65)  $(0.25)  $0.87    $(0.90)  $1.57  
 – diluted $(0.65)  $(0.25)  $0.87    $(0.90)  $1.57  
Cash flows (used in) from operating activities $(351)  $1,725    $2,861    $1,374    $3,857  
Adjusted funds flow (2) $415    $1,337    $2,652    $1,752    $4,892  
Per common share– basic $0.35    $1.13    $2.22    $1.48    $4.09  
 – diluted $0.35    $1.13    $2.22    $1.48    $4.08  
Cash flows used in investing activities $693    $859    $4,464    $1,552    $5,493  
Net capital expenditures (3) $421    $838    $4,125    $1,259    $5,102  
                  
Daily production, before royalties                   
Natural gas (MMcf/d) 1,462
   1,440   1,532   1,451
   1,521 
Crude oil and NGLs (bbl/d) 921,895
   938,676   770,409   930,286
   776,924 
Equivalent production (BOE/d) (4) 1,165,487
   1,178,752   1,025,800   1,172,120
   1,030,480 

(1) Adjusted net earnings (loss) from operations is a non-GAAP measure that the Company utilizes to evaluate its performance, as it demonstrates the Company’s ability to generate after-tax operating earnings from its core business areas. The derivation of this measure is discussed in the "Advisory" section of this press release.
(2) Adjusted funds flow is a non-GAAP measure that the Company considers key to evaluate its performance as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The derivation of this measure is discussed in the "Advisory" section of this press release.
(3) Net capital expenditures is a non-GAAP measure that the Company considers a key measure as it provides an understanding of the Company’s capital spending activities in comparison to the Company's annual capital budget. For additional information and details, refer to the net capital expenditures table in the "Advisory" section of this press release.
(4) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.

  • A net loss of $310 million was realized in Q2/20, while the adjusted net loss in Q2/20 was $772 million.
  • Cash flows used in operating activities were $351 million in Q2/20.
  • Adjusted funds flow of $415 million in Q2/20 reflect the strength of the Company's long life low decline asset base and its effective and efficient operations.
    • Maximizing value for shareholders, the Company elected to store as inventory at quarter end, a higher portion than normal of its Synthetic Crude Oil ("SCO") and International light crude oil production in the low commodity price quarter. If these barrels had been sold during the second quarter of 2020, based on June 2020 commodity prices, the Company would have generated approximately $60 million in additional cash flows from operating activities and adjusted funds flow in the quarter.
  • The Company reacted quickly to the changing commodity prices by executing planned maintenance and temporarily curtailing production when crude oil prices were low, optimizing its production mix and maximizing margins. Despite the impact of COVID-19 on the economy, Canadian Natural effectively executed on its curtailment optimization strategy, prioritizing its high netback SCO volumes, and achieved strong quarterly production volumes of 1,165,487 BOE/d in Q2/20, an increase of 14% from Q2/19 and comparable to Q1/20 levels.
  • Liquids production in Q2/20 was 921,895 bbl/d, an increase of 20% from Q2/19 and a decrease of 2% from Q1/20 levels. Increased production relative to Q2/19 reflects high utilization rates and safe, reliable operations in Oil Sands Mining and Upgrading, increased production from the acquisition of Jackfish and primary heavy crude oil assets in 2019 and the ramp up of Kirby North volumes.
    • Higher value light crude oil, NGLs and SCO production was prioritized in Q2/20, representing approximately 51% of total corporate BOE production volumes and will continue to be a key focus of the Company at current commodity price levels. 
    • As a result of improved commodity prices, substantially all of the previously announced voluntarily curtailed production in the Company's thermal in situ and North America Exploration and Production ("E&P") crude oil and NGL areas was brought back on production in June 2020.
  • At the Company's world class Oil Sands Mining and Upgrading assets, record quarterly production of 464,318 bbl/d of SCO was achieved in Q2/20. Increases over Q2/19 and Q1/20 levels of 24% and 6% respectively were achieved as a result of high utilization rates and operational enhancements at both Horizon and Athabasca Oil Sands Project ("AOSP"), partially offset by the impact from planned maintenance activities at Horizon in May 2020. 
    • The Company's industry leading Oil Sands Mining and Upgrading assets achieved record low operating costs of $17.74/bbl (US$12.80/bbl) of SCO in Q2/20, representing decreases of 27% and 15% from Q2/19 and Q1/20 levels respectively. The record low operating costs in Q2/20 were primarily due to safe, reliable production, operational enhancements and continued focus on cost control.
    • At AOSP, as previously announced, the Scotford Upgrader ("Scotford") is targeting to increase upgrading capacity to approximately 320,000 bbl/d in Q3/20. Canadian Natural has increased gross production capacity at the Albian mines ("Albian") through optimization projects, process improvements, and enhanced reliability. In preparation for the increased capacity at Scotford, Canadian Natural confirmed Albian's ability to deliver incremental capacity in June 2020, during which time Albian gross production averaged approximately 339,000 bbl/d. This additional capacity at AOSP is targeted to provide Canadian Natural with increased margins and flexibility, maximizing the value of the Company's Oil Sands Mining and Upgrading assets.
  • Canadian Natural's continued focus on delivering effective and efficient operations and cost control was also demonstrated as the Company's North American E&P liquids, including thermal in situ, achieved operating costs of $11.65/bbl (US$8.41/bbl) in Q2/20, decreases of 11% and 8% from Q2/19 and Q1/20 levels respectively.
  • Thermal in situ production volumes averaged 212,807 bbl/d in Q2/20, a 94% increase over Q2/19 levels and a 7% decrease from Q1/20 levels. Production in Q2/20 increased relative to Q2/19 as a result of the Jackfish acquisition in 2019 and the strong ramp up of Kirby North. Production in Q2/20 decreased relative to Q1/20 as the Company temporarily curtailed volumes and accelerated maintenance activities into Q2/20 as a result of low commodity prices.
    • Thermal in situ operating costs were strong in Q2/20, averaging $10.13/bbl (US$7.31/bbl), decreases of 14% and 8% from Q2/19 and Q1/20 levels respectively. The Company maximized margins by prioritizing lower Steam to Oil Ratio ("SOR") production, capturing synergies from the Jackfish acquisition and lower power costs.
    • The ramp up of Kirby North is ahead of schedule and has been top tier with July 2020 production averaging approximately 43,200 bbl/d, exceeding the nameplate capacity of 40,000 bbl/d. Kirby North's low SOR of 2.3x in Q2/20 resulted in strong operating costs, maximizing margins within the Company's thermal in situ segment.
  • North America natural gas production averaged 1,431 MMcf/d in Q2/20, a 3% decrease from Q2/19 levels and a 2% increase from Q1/20 levels. The increase from the prior quarter reflects the increased volumes from the Company's previously announced production additions and high reliability, offsetting natural declines. The Company continues to execute on its plan to add approximately 60 MMcf/d of highly economic natural gas volumes at less than $3,000 per flowing BOE and is on track to achieve the Company's annual incremental production target of approximately 35 MMcf/d.
    • North America natural gas operating costs were strong in Q2/20, averaging $1.11/Mcf, decreases of 3% and 10% from Q2/19 and Q1/20 levels respectively. These results demonstrate the strength of the Company's strategy to own and control its infrastructure, continued focus on cost control and efficient operations.
  • Canadian Natural maintained a strong financial position in Q2/20 with significant liquidity available at June 30, 2020 of approximately $4.1 billion, including credit facilities and cash balances. In addition, the Company has approximately $5.6 billion of availability under its United States (US$1.9 billion) and Canadian (C$3.0 billion) base shelf prospectuses, which expire August 2021, allowing the Company to offer these securities for sale from time to time. During Q2/20, the Company repaid $900 million of 2.05% medium-term notes and issued two US$ denominated notes raising approximately $1.5 billion (US$1.1 billion).
  • The Government of Alberta enacted legislation in Q2/19 decreasing the provincial corporate income tax rate from 12% to 8% over time, commencing on July 1, 2019 through to 2022. In Q2/20, the Government of Alberta announced its intention to accelerate this legislation, lowering the current rate from 10% to 8% effective July 1, 2020. Canadian Natural estimates current tax savings for 2020 of approximately $35 million, including the reduction announced in 2019 and the acceleration in 2020. As a result of the tax rate reduction, the Company targets to invest these 2020 savings in economic projects across its Alberta operations. The acceleration of the tax rate reduction will also have an impact on 2021 current taxes and Canadian Natural will consider the tax savings for inclusion in 2021 investment.
  • Canadian Natural appreciates the support from the Federal and Provincial governments and their commitment on getting oil and natural gas service providers back to work through the Abandonment and Reclamation Funding Program. Based on the total funding that has been announced to date by each province, the Company will be increasing its investment in abandonment programs in British Columbia, Saskatchewan and Alberta. The investments will be deployed to provide much needed jobs in each of the respective provinces.
  • Canadian Natural is leading the crude oil and natural gas industry in Carbon Capture and Storage ("CCS") and sequestration initiatives and is one of the largest carbon dioxide ("CO2") capturers and sequesterers for the oil and natural gas sector globally. As part of our comprehensive Greenhouse Gas ("GHG") emissions reduction strategy, our CCS projects include CO2 storage in geological formations, use of CO2 in enhanced oil recovery techniques and CO2 injection into tailings. Gross carbon capture capacity through these projects combined is approximately 2.7 million tonnes of CO2 annually, equivalent to taking approximately 576,000 vehicles off the road per year.
    • At the Company’s 70% owned Quest CCS facility located at Scotford, the facility captures and stores approximately 1.1 million tonnes of CO2 per year. This highlights Canadian Natural’s leadership in leveraging technology and innovation and the strength of industry and government collaboration to continuously improve operational and environmental performance.
    • Canadian Natural has a 50% working interest in the North West Redwater Refinery, which combines gasification technology with an integrated carbon capture and storage program, capturing approximately 1.2 million tonnes of CO2 per year and eliminating approximately 70% of the refinery's total carbon footprint. This project successfully reached commercial operations on June 1, 2020.
    • The Company has approximately 400,000 tonnes of CO2 capture capacity per year for sequestration at Horizon by injecting CO2 into its tailings ponds. This improves the Company's operating costs as a result of smaller tailings footprint and more efficient use of natural gas, as well as reduces GHG emissions and accelerates reclamation.

 

OPERATIONS REVIEW AND CAPITAL ALLOCATION

Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural’s production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and Synthetic Crude Oil ("SCO") (herein collectively referred to as “crude oil”), 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, representing approximately 79% of the Company's total liquids production in Q2/20. 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 that can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control major components of the Company's operating costs and minimize production commitments. Low capital exposure projects can be quickly stopped or started depending upon success, market conditions or corporate needs.

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

Drilling ActivitySix Months Ended June 30
   
 20202019
(number of wells)GrossNetGrossNet
Crude oil43  37  39  38  
Natural gas13  12  12  10  
Dry—  —    
Subtotal56  49  54  51  
Stratigraphic test / service wells424  371  379  335  
Total480  420  433  386  
Success rate (excluding stratigraphic test / service wells) 100 % 94 %
  • The Company's total crude oil and natural gas drilling program of 49 net wells for the six months ended June 30, 2020, excluding stratigraphic/service wells, represents a decrease of 2 net wells from the same period in 2019.

 

North America Exploration and Production

Crude oil and NGLs – excluding Thermal In Situ Oil Sands  
 

 
Three Months EndedSix Months Ended
 Jun 30
2020
Mar 31
2020
Jun 30
2019
Jun 30
2020
Jun 30
2019
Crude oil and NGLs production (bbl/d)200,699  228,574  235,066  214,637  230,205  
Net wells targeting crude oil 28   30  37  
Net successful wells drilled 28   30  35  
Success rate100 %100 %78 %100 %95 %
  • Canadian Natural's North America E&P crude oil and NGL production volumes, excluding thermal in situ, averaged 200,699 bbl/d, decreases of 15% and 12% from Q2/19 and Q1/20 levels respectively. The decrease in Q2/20 reflects the Company's decision to temporarily curtail production and reduce well servicing activities, as a result of low commodity prices in the quarter.
  • Primary heavy crude oil production averaged 62,546 bbl/d in Q2/20, decreases of 19% and 24% from Q2/19 and Q1/20 levels respectively. The decrease in production was primarily as a result of temporarily curtailed production and reduced well servicing activity as a result of low commodity prices, as well as the execution of the Company's curtailment optimization strategy.
    • Operating costs in the Company's primary heavy crude oil operations in Q2/20 averaged $17.97/bbl      (US$12.97/bbl), a 4% decrease from Q1/20 levels, as the Company continues to focus on cost control and maximizing margins.
  • Pelican Lake production averaged 55,731 bbl/d in Q2/20, comparable to Q2/19 and a 4% decrease from Q1/20 levels. The decrease from Q1/20 is primarily due to reduced well servicing activity as a result of low crude oil prices in Q2/20.
    • The Company continues to demonstrate effective and efficient operations as Q2/20 operating costs at Pelican Lake of $6.31/bbl (US$4.55/bbl) decreased by 6% from Q2/19 levels and increased 2% from Q1/20 levels.
  • North American light crude oil and NGL production averaged 82,422 bbl/d in Q2/20, decreases of 19% and 7% from Q2/19 and Q1/20 levels respectively, primarily as a result of temporarily curtailed production and reduced well servicing activity as a result of low commodity prices in Q2/20.
    • Operating costs in the Company's North America light crude oil and NGL areas averaged $14.41/bbl     (US$10.40/bbl) in Q2/20, decreases of 2% and 10% from Q2/19 and Q1/20 levels respectively.
   
Thermal In Situ Oil Sands  
 

Three Months EndedSix Months Ended
      
 Jun 30
2020
Mar 31
2020
Jun 30
2019
Jun 30
2020
Jun 30
2019
Bitumen production (bbl/d)212,807  228,303  109,599  220,555  101,915  
Net wells targeting bitumen—   —   —  
Net successful wells drilled—   —   —  
Success rate—  100 %—  100 %—  
  • Thermal in situ production volumes averaged 212,807 bbl/d in Q2/20, a 94% increase over Q2/19 levels and a 7% decrease from Q1/20 levels. Production in Q2/20 increased relative to Q2/19 as a result of the Jackfish acquisition in 2019 and the strong ramp up of Kirby North. Production in Q2/20 decreased relative to Q1/20 as the Company temporarily curtailed volumes and accelerated maintenance activities into Q2/20 as a result of low commodity prices.
    • Thermal in situ operating costs were strong in Q2/20, averaging $10.13/bbl (US$7.31/bbl), decreases of 14% and 8% from Q2/19 and Q1/20 levels respectively. The Company maximized margins by prioritizing lower SOR production, capturing synergies from the Jackfish acquisition and lower power costs.
    • The ramp up of Kirby North is ahead of schedule and has been top tier with July 2020 production averaging approximately 43,200 bbl/d, exceeding the nameplate capacity of 40,000 bbl/d. Kirby North's low SOR of 2.3x in Q2/20 resulted in strong operating costs, maximizing margins within the Company's thermal in situ segment.
  • At Kirby South, the solvent enhanced oil recovery technology pilot targets to increase oil recovery, reduce SOR by up to 50% and lower GHG intensity by up to 50%. To date, the Company continues to see positive results with increased bitumen production, lower SOR and high solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
   
North America Natural Gas  
 

 
Three Months EndedSix Months Ended
      
 Jun 30
2020
Mar 31
2020
Jun 30
2019
Jun 30
2020
Jun 30
2019
Natural gas production (MMcf/d)1,431  1,407  1,482  1,419  1,468  
Net wells targeting natural gas 11   12  11  
Net successful wells drilled 11   12  10  
Success rate100 %100 %100 %100 %91 %
  • North America natural gas production averaged 1,431 MMcf/d in Q2/20, a 3% decrease from Q2/19 levels and a 2% increase from Q1/20 levels. The increase from the prior quarter reflects the increased volumes from the Company's previously announced production additions, high reliability and strong base production, offsetting natural declines. The Company continues to execute on its plan to add approximately 60 MMcf/d of highly economic natural gas volumes at less than $3,000 per flowing BOE and is on track to achieve the Company's annual incremental production target of approximately 35 MMcf/d.
    • North America natural gas operating costs were strong in Q2/20, averaging $1.11/Mcf, decreases of 3% and 10% from Q2/19 and Q1/20 levels respectively. These results demonstrate the strength of the Company's strategy to own and control its infrastructure, continued focus on cost control and efficient operations.
    • At the Company's high value Septimus Montney liquids rich area, operating costs remained strong, averaging $0.31/Mcfe in Q2/20, a 6% decrease from Q2/19 levels.
  • In Q2/20, Canadian Natural used the equivalent of approximately 49% of corporate annual natural gas production within its operations, providing a natural hedge from Western Canadian natural gas prices. Approximately 32% was exported to other North American markets and sold internationally, while the remaining 19% was exposed to AECO/Station 2 pricing.

 

International Exploration and Production

 
 
Three Months EndedSix Months Ended
      
 Jun 30
2020
Mar 31
2020
Jun 30
2019
Jun 30
2020
Jun 30
2019
Crude oil production (bbl/d)     
North Sea26,627  27,755  27,594  27,191  26,659  
Offshore Africa17,444  15,943  23,650  16,694  22,907  
Natural gas production (MMcf/d)     
North Sea15  23  23  19  25  
Offshore Africa16  10  27  13  28  
Net wells targeting crude oil—  1.0  0.9  1.0  2.5  
Net successful wells drilled—  1.0  0.9  1.0  2.5  
Success rate—  100 %100 %100 %100 %
  • International E&P crude oil production volumes averaged 44,071 bbl/d in Q2/20, a decrease of 14% from Q2/19 levels and comparable to Q1/20 levels.
    • In the North Sea, crude oil production volumes averaged of 26,627 bbl/d in Q2/20, a decrease of 4% from both Q2/19 and Q1/20 levels as expected. Production in Q2/20 was lower, primarily as a result of the planned permanent cessation of production in the Banff and Kyle fields on June 1, 2020 and natural field declines. The Banff decommissioning project is on time and on budget.
      • Crude oil operating costs in the North Sea decreased by 24% and 4% from Q2/19 and Q1/20 levels respectively, averaging $28.47/bbl (US$20.55/bbl) in Q2/20. The decreases from the comparable periods primarily reflected reduced maintenance activities, timing of liftings from various fields that have different cost structures and the Company's continued focus on cost control.
    • Offshore Africa crude oil production volumes averaged 17,444 bbl/d in Q2/20, a decrease of 26% from Q2/19 levels and an increase of 9% from Q1/20 levels. The decrease in production from Q2/19 levels was primarily due to natural field declines. The increase in production from Q1/20 levels primarily reflects the successful completion of planned turnaround activities at Espoir in Q1/20.
      • Offshore Africa crude oil operating costs averaged $10.62/bbl (US$7.67/bbl) in Q2/20, an increase of 26% from Q2/19 and a decrease of 11% from Q1/20 levels. The changes in operating costs from the comparable periods primarily reflected fluctuations in production volumes on a relatively fixed cost base and the Company's continued focus on cost control.
      • In Q3/20, the operator is targeting to commence the drilling program of the previously announced discovery of significant gas condensate in South Africa, where Canadian Natural has a 20% working interest.

 

North America Oil Sands Mining and Upgrading

 

 
Three Months EndedSix Months Ended
      
 Jun 30
2020
Mar 31
2020
Jun 30
2019
Jun 30
2020
Jun 30
2019
Synthetic crude oil production (bbl/d) (1) (2) 464,318  438,101 374,500 451,210  395,238 

(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, record quarterly production of 464,318 bbl/d of SCO was achieved in Q2/20. Increases over Q2/19 and Q1/20 levels of 24% and 6% respectively were achieved as a result of high utilization rates and operational enhancements at both Horizon and AOSP, partially offset by the impact from planned maintenance activities at Horizon in May 2020.
    • The Company's industry leading Oil Sands Mining and Upgrading assets achieved record low operating costs of $17.74/bbl (US$12.80/bbl) of SCO in Q2/20, representing decreases of 27% and 15% from Q2/19 and Q1/20 levels respectively. The record low operating costs in Q2/20 are primarily due to safe, reliable production, operational enhancements and continued focus on cost control.
    • Oil Sands Mining and Upgrading reduced operating costs by approximately $84 million or 10% from Q2/19 levels to approximately $730 million in Q2/20, as a result of safe, reliable production, operational enhancements and continued focus on cost control.
  • In the second half of 2020, the Company is targeting planned turnaround activities at both AOSP and Horizon. The Company's strength of operations and diverse asset base allows Canadian Natural to optimize maintenance activities within its Oil Sands Mining and Upgrading assets.
    • The turnaround at the non-operated Scotford Upgrader base plant began on July 8, 2020 and is targeted to be completed in 55 days, during which time the plant will run at restricted rates. Timing of maintenance activities at Albian is aligned with the turnaround at the Scotford Upgrader. During the turnaround, net production from AOSP is targeted to average approximately 100,000 bbl/d lower than normal.
    • At Horizon, the Company is targeting to begin a 20 day planned turnaround in mid-September. Monthly average production is targeted to be approximately 80,000 bbl/d lower than normal in September 2020 and October 2020.
  • At AOSP, as previously announced, the Scotford Upgrader is targeting to increase upgrading capacity to approximately 320,000 bbl/d in Q3/20. Canadian Natural has increased gross production capacity at the Albian mines ("Albian") through optimization projects, process improvements, and enhanced reliability. In preparation for the increased capacity at Scotford, Canadian Natural confirmed Albian's ability to deliver incremental capacity in June 2020, during which time Albian gross production averaged approximately 339,000 bbl/d. This additional capacity at AOSP is targeted to provide Canadian Natural with increased margins and flexibility, maximizing the value of the Company's Oil Sands Mining and Upgrading assets.
  • Commercial engineering of the In Pit Extraction Process ("IPEP") for Horizon continues, although the Company has temporarily delayed the field pilot in order to limit staffing levels to personnel who are critical to maintaining safe, reliable operations in response to COVID-19 guidelines. Canadian Natural is confident in the results from the initial testing phase of the pilot, which shows excellent recovery rates and evidence of stackable tailings. The IPEP pilot will determine the feasibility of producing stackable dry tailings on a commercial basis. The project has the potential to reduce the Company's bitumen production GHG emissions by approximately 40% and lower the Company's environmental footprint by decreasing the handling of material, reducing the distance driven by its fleet of haul trucks, decreasing the size and need for tailings ponds and accelerating site reclamation. In addition, this process has the potential to reduce capital and operating costs.

 

MARKETING

  Three Months Ended  Six Months Ended
            
  Jun 30
2020
 Mar 31
2020
 Jun 30
2019
  Jun 30
2020
 Jun 30
2019
Crude oil and NGLs pricing           
WTI benchmark price (US$/bbl) (1) $27.85   $46.08   $59.83    $36.97   $57.38  
WCS heavy differential as a percentage of WTI (%) (2) 41 % 44 % 18 %  43 % 20 %
SCO price (US$/bbl) $23.28   $43.39   $59.96    $33.33   $56.10  
Condensate benchmark pricing (US$/bbl) $22.19   $45.54   $55.86    $33.86   $53.19  
Average realized pricing before risk management (C$/bbl) (3) $18.97   $25.90   $63.45    $22.70   $59.05  
Natural gas pricing           
AECO benchmark price (C$/GJ) $1.81   $2.03   $1.11    $1.92   $1.47  
Average realized pricing before risk management (C$/Mcf) $2.03   $2.22   $1.98    $2.13   $2.53  

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

  • Canadian Natural has many strengths when marketing its products, including a balanced and diverse product mix of natural gas, conventional heavy crude oil, conventional light crude oil, thermal in situ and SCO.
  • Commodity prices continue to improve and Western Canadian Select ("WCS") differentials have tightened as a result of reduced activity in the Western Canadian Sedimentary Basin, production declines and price-related curtailments and shut-ins. Since June, WCS differentials to WTI remain relatively tight, with Q3/20 estimated to be approximately 22%. The Company continues to see sufficient egress in the foreseeable future as operators bring back on production volumes.
  • Canadian Natural has storage at major hubs in Edmonton and Hardisty, which allows the Company to adjust monthly sales, manage pipeline logistical constraints, and production fluctuations, as well as pricing differences from month to month.
  • Market egress continues to improve in the mid-term as the Trans Mountain Expansion ("TMX") and Keystone XL projects are progressing with construction, on which Canadian Natural has 94,000 bbl/d and 200,000 bbl/d of committed capacity respectively. Combining these two pipeline projects and including Enbridge Line 3 replacement, Western Canadian egress is targeted to increase by approximately 1.8 MMbbl/d in the mid-term.
    • TMX construction continues to progress and is targeted to be on stream in late 2022.
    • Canadian Natural is committed to approximately 10,000 bbl/d of the targeted 50,000 bbl/d base Keystone export pipeline optimization expansion, which is targeted to be available in 2021.
  • The North West Redwater Refinery reached commercial operations on June 1, 2020 and targets to process approximately 80,000 bbl/d of diluted bitumen, which will improve heavy oil demand in western Canada, effectively increasing egress out of the Western Canadian Sedimentary Basin. For more details, please contact the North West Redwater Partnership.

FINANCIAL REVIEW  

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

  • The Company’s strategy to maintain a diverse portfolio, balanced across various commodity types, achieved production of 1,165,487 BOE/d in Q2/20, with approximately 98% of total production located in G7 countries.
  • Canadian Natural generated quarterly adjusted funds flow of $415 million in Q2/20, reflecting the strength of the Company's long life low decline asset base and its effective and efficient operations.
    • Maximizing value for shareholders, the Company elected to store as inventory at quarter end, a higher portion than normal of its SCO and International light crude oil production in the low commodity price quarter. If these barrels had been sold during the second quarter of 2020, based on June 2020 commodity prices, the Company would have generated approximately $60 million in additional cash flows from operating activities and adjusted funds flow in the quarter.
  • Net capital expenditures in Q2/20 were disciplined at approximately $421 million.
  • Returns to shareholders totaled $502 million in Q2/20 by way of dividends paid on April 1, 2020. As previously announced on March 18, 2020, the Company's share repurchase program has been suspended and the Board of Directors made the decision to not renew the Company's NCIB program, which expired in May 2020.
  • Canadian Natural maintained a strong financial position in Q2/20 with significant liquidity available at June 30, 2020 of approximately $4.1 billion, including credit facilities and cash balances. The Company's liquidity is more than sufficient to retire, when due, any upcoming debt maturities.
    • In May 2020, the Company's $750 million non-revolving term credit facility, originally due February 2021, was increased by $250 million to $1,000 million and extended to February 2022.
    • The Company repaid $900 million of 2.05% medium-term notes that matured on June 1, 2020.
    • In June 2020, the Company issued two US$ denominated notes for total proceeds of approximately $1.5 billion (US$1.1 billion), including US$600 million of unsecured notes due in 2025 and US$500 million of unsecured notes due in 2030. Net proceeds from these notes were used primarily to refinance the Company's outstanding short-term indebtedness and for general corporate purposes.
    • The Company has approximately $5.6 billion of availability under its United States (US$1.9 billion) and Canadian (C$3.0 billion) base shelf prospectuses, which expire August 2021, allowing the Company to offer these securities for sale from time to time.
    • In addition to 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. The current approximate value of these financial levers includes third party equity investments of $275 million and cross currency swaps with a total value of $206 million.
    • Debt to book capitalization and debt to adjusted EBITDA remained strong at 41.3% and 3.0x respectively.
  • Canadian Natural continues to maintain strong investment grade credit ratings. The Company has a high degree of communication with credit rating agencies to ensure they understand the robust and sustainable nature of the Company's assets.
  • Canadian Natural’s business is unique, robust and sustainable. The strength of the Company's assets and its ability to generate significant and sustainable free cash flow over the long term combined with strong liquidity, production flexibility, significant capital reductions and targeted operating costs savings provided the Board of Directors with the confidence that the Company’s current dividend levels can be sustained through the commodity price cycle.
    • Subsequent to quarter end, the Company declared a quarterly dividend of $0.425 per share, payable on October 5, 2020.

ADVISORY

Special Note Regarding Forward-Looking Statements

Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses and other guidance provided throughout this press release and the Company's Management’s Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the Jackfish Thermal Oil Sands Project, the North West Redwater bitumen upgrader and refinery, construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market, and the development and deployment of technology and technological innovations also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.

In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.

The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of effects of the novel coronavirus ("COVID-19") pandemic and the actions of the Organization of the Petroleum Exporting Countries ("OPEC") and non-OPEC countries) which may impact, among other things, demand and supply for and market prices of the Company’s products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil and natural gas and NGLs prices including due to actions of OPEC and non-OPEC countries taken in response to COVID-19 or otherwise; fluctuations in currency and interest rates; assumptions on which the Company’s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company’s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company’s and its subsidiaries’ ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting or upgrading of the Company’s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company’s bitumen products; availability and cost of financing; the Company’s and its subsidiaries’ success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities (including production curtailments mandated by the Government of Alberta); government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset retirement obligations; the adequacy of the Company’s provision for taxes; the continued availability of the Canada Emergency Wage Subsidy ("CEWS") or other subsidies; and other circumstances affecting revenues and expenses.

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

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

Special Note Regarding non-GAAP Financial Measures

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

Adjusted funds flow (previously referred to as funds flow from operations) is a non-GAAP measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment expenditures and movements in other long-term assets, including the unamortized cost of the share bonus program and prepaid cost of service tolls. The Company considers adjusted funds flow a key measure as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities” is presented in the Company’s MD&A.

Net capital expenditures is a non-GAAP measure that represents cash flows used in investing activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, investment in other long-term assets, share consideration in business acquisitions and abandonment expenditures. The Company considers net capital expenditures a key measure as it provides an understanding of the Company’s capital spending activities in comparison to the Company's annual capital budget. The reconciliation “Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities” is presented in the Net Capital Expenditures section of the Company’s MD&A.

Free cash flow is a non-GAAP measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital from operating activities, abandonment, certain movements in other long-term assets, less net capital expenditures and dividends on common shares. The Company considers free cash flow a key measure in demonstrating the Company’s ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders, and to repay debt.

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

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

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

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

Special Note Regarding Currency, Financial Information and Production

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

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

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

CONFERENCE CALL

A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, August 6, 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, August 20, 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 6796237.

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

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

 
CANADIAN NATURAL RESOURCES LIMITED
2100, 855 - 2nd Street S.W. Calgary, Alberta, T2P4J8 
Phone: 403-514-7777  Email: ir@cnrl.com
www.cnrl.com
 
 
TIM S. MCKAY
President

MARK A. STAINTHORPE
Chief Financial Officer and Senior Vice-President, Finance

JASON M. POPKO
Manager, Investor Relations

Trading Symbol - CNQ
Toronto Stock Exchange
New York Stock Exchange

 

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