Market Overview

Canadian Natural Resources Limited Announces 2018 Second Quarter Results

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CALGARY, Alberta, Aug. 02, 2018 (GLOBE NEWSWIRE) -- Commenting on second quarter 2018 results, Steve Laut, Executive Vice-Chairman of Canadian Natural stated, "The Company's balanced strategy was once again evident in the quarter as our robust long life low decline asset base provided  record quarterly funds flow of approximately $2.7 billion. The allocation of funds flow was balanced among our four pillars to maximize value for our shareholders through strengthening the balance sheet, returns to shareholders through dividends and share buybacks, economic resource development, and some minor opportunistic acquisitions year to date. The Company's ability to execute on our strategy is reflected in our second quarter results, and continues a long track record of strong results."

Canadian Natural's President, Tim McKay, added, "In the second quarter of 2018, operations were strong and cost control remained a focus, specifically at our Oil Sands Mining and Upgrading assets, where costs continue to come down. Operating costs of $22.94/bbl (US$17.77/bbl) of Synthetic Crude Oil ("SCO") were impressive given the successfully completed turnaround and pit stop activities in the quarter.

Canadian Natural's ability to effectively allocate capital was demonstrated in the quarter as we have made strategic and proactive decisions to take advantage of our large, balanced and diverse asset base due to changing market conditions. Our asset base is a key competitive advantage providing significant capital flexibility and as a result, to maximize value, we are shifting capital from primary heavy crude oil to light crude oil.

At Kirby North, top tier execution and strong productivity have resulted in accelerating the projects time line, bringing forward targeted first oil of the project's 40,000 bbl/d, by three months into Q4/19, one quarter earlier than originally planned.

At Horizon, the Company has identified opportunities to increase reliability, lower costs and add production growth of between 75,000 bbl/d and 95,000 bbl/d in the near and long term. The near term opportunities are targeted to add production growth of 35,000 bbl/d to 45,000 bbl/d of SCO. High grading of these near term opportunities and further defining of substantial long term growth opportunities is ongoing and is targeted to be completed by the end of the year. Additionally, early results from engineering and design specification work at the potential Paraffinic Froth Treatment expansion has indicated that the optimal production range for the expansion has increased by 10,000 bbl/d and is now targeted to add 40,000 bbl/d to 50,000 bbl/d. All of the these identified production growth opportunities at Horizon are over and above the previously disclosed annual corporate growth target of approximately 4% or 45,000 BOE/d of organic production over the next few years. These Horizon opportunities will be executed in a disciplined and step wise manner which preserves Canadian Natural's capital flexibility."

Canadian Natural's Chief Financial Officer, Corey Bieber, continued, "In the second quarter of 2018, the strength of our asset base and effective and efficient operations delivered net earnings of $982 million and funds flow from operations of $2,706 million. Our strong financial results allowed the Company to further strengthen the balance sheet by decreasing absolute long term net debt by over $600 million from the previous quarter, and returning over $850 million to shareholders by way of dividends and share buybacks in the quarter.

The Company's acquisitions in 2017 were transformational and our results continue to show the accretive nature and resilience of these assets. Supported by successful expansions at Horizon, long life low decline and low capital exposure assets, we have been able to reduce long term net debt in the last 12 months since the Athabasca Oil Sands Project ("AOSP") acquisition by approximately $2,500 million, including the retirement of the deferred AOSP acquisition liability, improving our debt to book capitalization to 39.6% from 42.8% and debt to adjusted EBITDA to 2.1x from 3.4x over the same time frame, clearly demonstrating our commitment to strengthening the balance sheet."

HIGHLIGHTS

    Three Months Ended     Six Months Ended
                       
($ millions, except per common share amounts)   Jun 30
 2018
  Mar 31
 2018
  Jun 30
 2017
    Jun 30
 2018
  Jun 30
 2017
Net earnings                                            
      $ 982     $ 583     $ 1,072       $ 1,565     $ 1,317  
Per common share  – basic   $ 0.80     $ 0.48     $ 0.93       $ 1.28     $ 1.16  
  – diluted   $ 0.80     $ 0.47     $ 0.93       $ 1.27     $ 1.16  
Adjusted net earnings from operations (1)   $ 1,279     $ 885     $ 332       $ 2,164     $ 609  
Per common share  – basic   $ 1.05     $ 0.72     $ 0.29       $ 1.77     $ 0.54  
  – diluted   $ 1.04     $ 0.71     $ 0.29       $ 1.76     $ 0.54  
Funds flow from operations (2)   $ 2,706     $ 2,323     $ 1,726       $ 5,029     $ 3,365  
Per common share  – basic   $ 2.20     $ 1.90     $ 1.50       $ 4.10     $ 2.97  
  – diluted   $ 2.19     $ 1.89     $ 1.49       $ 4.08     $ 2.95  
Total net capital expenditures (3)   $ 974     $ 1,103     $ 13,046       $ 2,077     $ 13,892  
                       
Daily production, before royalties                      
Natural gas (MMcf/d)   1,539     1,614     1,656       1,576     1,664  
Crude oil and NGLs (bbl/d)   793,899     854,558     637,127       824,060     617,728  
Equivalent production (BOE/d) (4)   1,050,376     1,123,546     913,171       1,086,757     895,139  


(1) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation of this measure is discussed in the Management's Discussion and Analysis ("MD&A").
(2) Funds flow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company's ability to fund capital reinvestment and debt repayment. The derivation of this measure is discussed in the MD&A.
(3) 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 $982 million were realized in Q2/18, an increase of 68% over Q1/18 levels, and adjusted net earnings of $1,279 million were achieved, a 45% increase over Q1/18 levels.

• Canadian Natural generated record quarterly funds flow from operations of $2,706 million in Q2/18, increases of $383 million and $980 million from Q1/18 and Q2/17 levels respectively. The increase over Q1/18 and Q2/17 primarily reflects higher realized prices from the Company's liquids production together with higher liquids production volumes when compared to Q2/17.

• In Q2/18, Canadian Natural delivered funds flow from operations in excess of capital expenditures of approximately $1,730 million, an increase of approximately $510 million and $890 million from Q1/18 and Q2/17 levels respectively.

• In the first half of 2018, after dividend requirements, free cash flow totaled approximately $2,200 million.

• The Company maintained balance in the allocation of its funds flow from operations, consistent with the Company's four pillar strategy:

  • The Company remained disciplined in economic resource development with capital expenditures of $2,077 million in the first half of 2018.
  • In the first half of the year the Company has reduced long term net debt by $1,106 million, resulting in debt to adjusted EBITDA strengthening to 2.1x and debt to book capitalization improving to 39.6%.
  • Returns to shareholders remain a key focus for Canadian Natural as the Company has returned approximately $1,188 million by way of dividends and share buybacks in the first six months of 2018. Share buybacks for cancellation totaled 10,140,127 shares in Q2/18 at a weighted average share price of $43.52. 
  • Subsequent to quarter end Canadian Natural declared a quarterly cash dividend on common shares of $0.335 per share payable on October 1, 2018.
  • Subsequent to quarter end, the Company executed additional share buybacks of 722,600 common shares for cancellation at a weighted average price of $46.95 per common share.
  • Opportunistic acquisitions have been minor in 2018, with year to date net expenditures of less than $100 million.

• The Company's production volumes in Q2/18 averaged 1,050,376 BOE/d, an increase of 15% from Q2/17 levels, mainly due to the Horizon Phase 3 expansion and acquisitions in 2017. Production decreased from Q1/18 levels by 7%, primarily as a result of major planned turnaround activities at the Company's Oil Sands Mining and Upgrading and thermal in situ operations as well as proactive and strategic actions taken to maximize value.

• Canadian Natural's corporate crude oil and NGL production volumes averaged 793,899 bbl/d, a decrease of 7% from Q1/18 levels and a 25% increase from Q2/17 levels. The decrease from Q1/18 was primarily as a result of proactive  turnaround activities at our Oil Sands Mining and Upgrading and thermal in situ operations as well as curtailments in Q2/18. The increase from Q2/17 was primarily as a result of production from the Horizon Phase 3 expansion, as well as high reliability and strong production from acquisitions completed in 2017.

• At the Company's world class Oil Sands Mining and Upgrading assets, operations were as expected in Q2/18 with quarterly production of 407,704 bbl/d of Synthetic Crude Oil ("SCO"), a decrease of 11% from Q1/18 levels, as planned turnaround and pit stop activities at all three of the Company's oil sands mines, as well as a major 62 day turnaround at the Scotford Upgrader were successfully completed in the quarter.

  • Cost control remains a strong focus for the Company as costs continued to come down resulting in industry leading operating costs of $22.94/bbl (US$17.77/bbl) of SCO in Q2/18, a 2% decrease from Q2/17 levels and a 7% increase from Q1/18 levels, impressive results considering major turnarounds decreased production by 11% in Q2/18 from Q1/18 levels.
  • At the Athabasca Oil Sands Project ("AOSP"), a significant milestone was reached in July, when the asset produced its 1 billionth barrel of mined bitumen during its first 15 years of operations, one of the few world class assets to reach such a milestone. This is a true demonstration of the quality, size and scale of the Company's Oil Sands Mining and Upgrading operations which through environmentally responsible, safe, reliable, effective and efficient operations, provide sustainable long life low decline production and significant value for stakeholders.
  • At Horizon, following the successful completion of the Phase 3 expansion and after operating the plant for the last 8 months, the Company continues to evaluate potential expansions and has identified additional opportunities to increase reliability, lower costs and add production.
  • Results at the potential Paraffinic Froth Treatment expansion at Horizon are evident as the engineering and design specification work completed year to date has shown that the optimal production range of the proposed expansion has increased by 10,000 bbl/d and is now targeted to be 40,000 bbl/d to 50,000 bbl/d. The expansion is targeted to produce high quality diluted bitumen at significantly lower operating costs as the Company  leverages its existing infrastructure. Preliminary estimates of the capital required for the proposed expansion are approximately $1.4 billion.
  • Defining and high grading additional opportunities is ongoing with the completion of the process targeted by year end. These opportunities are targeted to add near term growth of 35,000 bbl/d to 45,000 bbl/d of SCO. All opportunities will be executed in a disciplined and step wise manner, which preserves Canadian Natural's capital flexibility. The previously discussed Vacuum Gas Oil ("VGO") expansion will be included in the high grading process.
  • In preparation to execute on these opportunities in 2019 and 2020, Canadian Natural has increased 2018 capital expenditures guidance by $170 million to advance engineering and procurement of certain long lead equipment.

• At Kirby North, top tier execution and strong productivity has resulted in the project progressing ahead of schedule, advancing targeted first oil by three months into Q4/19, one quarter earlier than originally planned. Cost performance remains on budget with 95% of the Central Processing Facility equipment delivered to site and Steam Assisted Gravity Drainage ("SAGD") drilling nearing 45% completion. Kirby North targets to add 40,000 bbl/d of SAGD production.

• Balance sheet strength continues to be a focus of the Company and strong financial performance was demonstrated in Q2/18 through reduced long term debt and extensions of select credit facilities.

  • In Q2/18, Standard & Poor's revised the Company's rating outlook from BBB+/negative to BBB+/stable.
  • In Q2/18, the Company reduced absolute long term net debt by approximately $610 million, from Q1/18 levels.
  • Canadian Natural maintains strong financial stability and liquidity represented by cash balances and committed bank credit facilities. At June 30, 2018 the Company had approximately $4,800 million of available liquidity, including cash and cash equivalents, an increase of approximately $800 million from Q1/18.
  • In Q2/18 Canadian Natural continued to have significant support from its large and diverse banking group as indicated by extensions of certain credit facilities completed in the quarter.

• In Q2/18 Canadian Natural published its 2017 Stewardship Report to Stakeholders, now available on the Company's website at https://www.cnrl.com/corporate-responsibility/stewardship-report/#2017. The report displays how Canadian Natural continues to focus on safe, reliable, effective and efficient operations while minimizing the Company's environmental footprint.

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 and 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, facilitating improved 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 low decline, low reserves replacement costs, and effective and efficient operations means these assets provide substantial and sustainable 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 a major component of its operating cost 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

  Six Months Ended Jun 30
     
  2018 2017
(number of wells) Gross   Net   Gross   Net  
Crude oil 210   203   236   216  
Natural gas 13   9   16   16  
Dry 2   2   3   3  
Subtotal 225   214   255   235  
Stratigraphic test / service wells 555   477   232   232  
Total 780   691   487   467  
Success rate (excluding stratigraphic test / service wells)   99 %   99 %
  • The Company's total Q2/18 crude oil and natural gas drilling program was 85 net wells, excluding strat/service wells, an increase of 17 net wells from the 68 net wells drilled in Q2/17. The Company's drilling levels reflects the disciplined capital allocation process and proactive actions to improve execution and control costs by balancing overall drilling levels throughout the year.

North America Exploration and Production

Crude oil and NGLs – excluding Thermal In Situ Oil Sands    
 

 
Three Months Ended Six Months Ended
           
  June 30 2018 March 31 2018 June 30 2017 June 30 2018 June 30 2017
Crude oil and NGLs production (bbl/d) 238,631   245,609   227,083   242,101   229,325  
Net wells targeting crude oil 58   101   57   159   204  
Net successful wells drilled 58   99   55   157   202  
Success rate 100 % 98 % 96 % 99 % 99 %

• North America crude oil and NGLs averaged 238,631 bbl/d in Q2/18, within quarterly corporate guidance, representing a 3% decrease from Q1/18 levels and a 5% increase from Q2/17 levels. The volume decrease in Q2/18 compared to Q1/18 levels was primarily as a result of production curtailments and shut-in volumes of approximately 10,350 bbl/d as well as reduced drilling activity and delayed completion and ramp up of certain primary heavy crude oil wells drilled in Q1/18 and Q2/18.

• Due to current market conditions the Company has exercised its capital flexibility by shifting capital from primary heavy crude oil to light crude oil in 2018, resulting in an additional 7 net light crude oil wells targeted to be drilled in the second half of the year. Primary heavy crude oil drilling was reduced by 24 net primary heavy crude oil wells in Q2/18, with an additional 35 primary heavy crude oil well reduction targeted for the second half of the year.

• Canadian Natural's primary heavy crude oil production averaged 84,811 bbl/d in Q2/18, a 5% decrease from Q1/18 levels. In order to maximize value from the Company's primary heavy crude oil assets, Canadian Natural  implemented and executed on proactive decisions and strategic actions in the first half of 2018, such as:

  • Disciplined capital allocation and proactive actions to target only the highest return wells in our primary heavy crude oil assets which resulted in 39 net wells drilled in Q2/18, less than originally budgeted.
  • The shut in of marginal high cost primary heavy crude oil production in 2018, which impacted Q2/18 production by approximately 2,900 bbl/d.
  • Proactive decisions to not sell marginal production in the wider spot WCS differential market versus the index WCS differential, caused by pipeline apportionment issues. As a result, the Company curtailed volumes of approximately 7,450 bbl/d in Q2/18.

• Controlling costs remains a focus with operating costs of $17.02/bbl in Q2/18, comparable to Q1/18 levels, strong results given the lower production volumes that were primarily as a result of proactive curtailments.

• At the Company's Smith primary heavy crude oil play, initial results have been strong from the 6 net multilateral wells drilled year to date and are currently producing approximately 340 bbl/d per well. There is significant potential at Smith for future development as Canadian Natural has 19 net sections in the fairway with the potential to add approximately 125 net horizontal multilateral primary heavy crude oil wells. Smith is an example of Canadian Natural's large, high quality primary heavy crude oil asset base.

• North America light crude oil and NGL quarterly production averaged 89,906 bbl/d, a decrease of 3% from Q1/18 levels and comparable to Q2/17 levels. Production from additional capital allocated to light crude oil assets is targeted to begin to be added in Q3/18.

  • The Company successfully drilled 38 net light crude oil wells in the first half of the year. Some initial results from wells coming on production in the quarter are as follows:
  • At the Company's light crude oil development at Tower, 7 net wells have been drilled and related facility construction has been completed. Operations are currently ramping up with initial well capacity targeted to be 850 bbl/d per well. Based on initial flow back rates, facility capacity of approximately 3,000 bbl/d is targeted to be reached in late Q3/18. There is additional potential at Tower with 41 targeted net light crude oil wells locations, on the Company's 11 net sections in the area.
  • At Wembley, 2 net Montney wells that were drilled in Q1/18 came on production late in Q2/18. Initial results are strong with production currently reaching approximately 800 bbl/d per well. There is meaningful potential at Wembley with 175 targeted net light crude oil well locations, on the Company's 77 net sections of Montney lands in the area.
  • Operating costs of $15.81/bbl were realized in Q2/18, comparable to Q1/18 levels in the Company's light crude oil and NGL areas.

• Pelican Lake quarterly production averaged 63,914 bbl/d, comparable with Q1/18 levels and an increase of 36% from Q2/17 levels. The increase from Q2/17 was as a result of the Company's successful integration of the acquired assets in 2017.

  • Polymer flood restoration on the acquired lands continues to proceed ahead of schedule, where approximately 60% of acquired lands are now under polymer flood. To optimize long term oil recovery and effectiveness of the polymer flood, the Company is using modified injection parameters in the near term. As polymer flood conformance improves, the Company expects to increase oil recovery and further maximize value.
  • Operating costs of $6.96/bbl were achieved in Q2/18, a 2% decrease from Q1/18 levels.
  • In the quarter, the Company successfully drilled 11 net producer wells. When incorporating the 7 net wells drilled in Q1/18, the Company has drilled 18 net Pelican Lake wells in the first half of the year, which are performing as expected and are currently producing approximately 90 bbl/d per well.

• The Company's 2018 North America E&P crude oil and NGL annual production guidance remains unchanged and is targeted to range from 253,000 bbl/d - 263,000 bbl/d.

     
Thermal In Situ Oil Sands    
 

 
Three Months Ended Six Months Ended
           
  Jun 30
 2018
  Mar 31
 2018
  Jun 30
 2017
  Jun 30
 2018
  Jun 30
 2017
 
Bitumen production (bbl/d) 104,907   111,851   105,719   108,359   116,983  
Net wells targeting bitumen 21   22   4   43   12  
Net successful wells drilled 21   22   4   43   12  
Success rate 100 % 100 % 100 % 100 % 100 %
                     

• Thermal in situ quarterly production volumes averaged 104,907 bbl/d, within Q2/18 guidance and a decrease of 6% as expected from Q1/18 levels primarily as the Company advanced and completed turnaround activities in the quarter. Production curtailments impacted Q2/18 by approximately 700 bbl/d, mainly at Kirby South.

  • At Primrose, Q2/18 production volumes averaged 67,569 bbl/d, a decrease of 6% from Q1/18 levels, primarily as a result of major turnaround activities. Including energy costs, operating costs were strong at $14.66/bbl in Q2/18, a decrease of 12% and 8% from Q1/18 and Q2/17 levels respectively, excellent results given downtime relating to the turnarounds in the quarter. 
  • Pad additions at Primrose are going as planned with the drilling targeted to add approximately 32,000 bbl/d in 2020, with initial production targeted late in 2019. These pad additions are high return activities as the Company utilizes available oil processing and steam capacity.
  • At Kirby South, SAGD production volumes of 35,322 bbl/d were achieved in Q2/18, a decrease of 5% from Q1/18 levels following planned turnaround activities brought forward into Q2/18 and curtailments of approximately 700 bbl/d and a 2% increase from Q2/17 levels.
  • Including energy costs, Kirby South achieved strong Q2/18 operating costs of $9.12/bbl, comparable to Q1/18 and a decrease of 11% from Q2/17 levels.
  • At Kirby North, top tier execution and strong productivity has resulted in the project progressing ahead of schedule, advancing targeted first oil by three months into Q4/19, one quarter earlier than originally planned. Cost performance remains on budget with 95% of the Central Processing Facility equipment delivered to site and SAGD drilling nearing 45% completion. Kirby North targets to add 40,000 bbl/d of SAGD production.

• The Company's 2018 thermal in situ annual production guidance remains unchanged and is targeted to range between 107,000 bbl/d - 127,000 bbl/d.

     
North America Natural Gas    
 

 
Three Months Ended Six Months Ended
           
  Jun 30
 2018
  Mar 31
 2018
  Jun 30
 2017
  Jun 30
 2018
  Jun 30
 2017
 
Natural gas production (MMcf/d) 1,485   1,547   1,603   1,515   1,607  
Net wells targeting natural gas 4   5   5   9   17  
Net successful wells drilled 4   5   5   9   16  
Success rate 100 % 100 % 100 % 100 % 94 %

• North America natural gas production was as expected at 1,485 MMcf/d in Q2/18, representing decreases of 4% and 7% from Q1/18 and Q2/17 levels respectively.

• Operating costs of $1.28/Mcf were realized in Q2/18, a decrease of 2% from Q1/18 levels, strong results given lower natural gas volumes due to the Company's proactive decision to shut-in volumes and delay activity on certain natural gas assets.

• In Q2/18 the Company has made the following proactive and strategic actions to maximize value in the Company's natural gas assets, including:

  • Completion of major turnaround activities at natural gas processing facilities to correspond with challenged natural gas prices.
  • Deferred capital and development activity including recompletions and workovers of certain natural gas assets, resulting in a production impact of approximately 20 MMcf/d in Q2/18. The Company will look to execute these deferrals in Q3/18 or Q4/18 with improved natural gas prices.
  • Q2/18 production volumes of approximately 27 MMcf/d were shut-in, due to low natural gas prices.
  • Q2/18 production was impacted by 12 MMcf/d related to solution gas associated with the curtailment of primary heavy crude oil production.

• Additionally, the Company's natural gas production was reduced by approximately 65 MMcf/d in Q2/18 due to restrictions at the Pine River plant, operated by a third party. In Q2/18 Canadian Natural, subject to regulatory approval, agreed to acquire the facility from the third party, which needs to complete a meter upgrade that will take approximately four weeks, at which time the Company targets to complete maintenance work on the facility and will assess increasing plant throughput and reliability to match field capacity of approximately 145 MMcf/d.

• As a result of the items listed above and proactive actions going forward, the Company's 2018 corporate natural gas annual production guidance has been revised and is targeted to range from 1,550 MMcf/d - 1,600 MMcf/d.

• The Company uses natural gas in its operations representing approximately 35% of its total equivalent gas production providing a natural hedge from the challenging Western Canadian natural gas price environment. Approximately 32% of the natural gas production is exported to other North American markets or sold internationally, with the remaining 33% of the Company's production being exposed to AECO/Station 2 pricing.

International Exploration and Production

 

 
Three Months Ended Six Months Ended
           
  Jun 30
 2018
  Mar 31
 2018
  Jun 30
 2017
  Jun 30
 2018
  Jun 30
 2017
 
Crude oil production (bbl/d)                    
North Sea 24,456   21,584   26,304   23,028   24,682  
Offshore Africa 18,201   19,438   20,480   18,816   21,542  
Natural gas production (MMcf/d)          
North Sea 30   37   37   34   37  
Offshore Africa 24   30   16   27   20  
Net wells targeting crude oil 1.9   1.0   1.8   2.9   1.8  
Net successful wells drilled 1.9   1.0   1.8   2.9   1.8  
Success rate 100 % 100 % 100 % 100 % 100 %
                     

• International E&P quarterly production volumes were within quarterly production guidance and reached 42,657 bbl/d in Q2/18, an increase of 4% from Q1/18 levels.

  • In the North Sea, volumes of 24,456 bbl/d were achieved in Q2/18, an increase of 13% from Q1/18 levels and a decrease of 7% from Q2/17 levels. The increase in production in Q2/18 from Q1/18 levels was primarily due to new wells at Tiffany and Ninian. The decrease from Q2/17 levels was a result of the impact of the shut-in of the Ninian North platform in May 2017 in preparation for decommissioning and natural field declines, partially offset by new wells at Ninian South and production optimization.
  • The Company's continued focus on production enhancements, increased reliability and water flood optimization in the North Sea resulted in Q2/18 operating costs decreasing by 19% from Q1/18 levels to $35.12/bbl.
  • In the first half of 2018, 2.9 net wells were drilled in the North Sea, with current light crude oil production exceeding 1,700 bbl/d per well.
  • On April 26, 2018, the Ninian North platform was permanently de-manned in readiness for future removal as part of the ongoing decommissioning program. This milestone was achieved 3 months ahead of schedule and below budget.
  • Offshore Africa production volumes in Q2/18 averaged 18,201 bbl/d, a decrease of 6% and 11% from Q1/18 and Q2/17 levels respectively. The decrease from Q2/17 was primarily as a result of planned maintenance activities at Espoir that were successfully completed in Q2/18, as well as natural field declines.
  • Côte d'Ivoire crude oil operating costs in Q2/18 were strong at $16.39/bbl, a 5% decrease from Q2/17 levels.
  • The Company is targeting to drill 1.7 net producing wells at Baobab, where drilling has commenced. The program targets to add average net production of approximately 5,700 bbl/d of light crude oil with the first well targeted to come on production in late Q3/18.

• The Company's 2018 International annual production guidance remains unchanged and is targeted to range from 40,000 bbl/d - 45,000 bbl/d.

North America Oil Sands Mining and Upgrading

 

 
Three Months Ended Three Months Ended
           
  Jun 30
 2018
Mar 31
 2018
Jun 30
 2017
Jun 30
 2018
Jun 30
 2017
Synthetic crude oil production (bbl/d) (1) (2) 407,704   456,076   257,541   431,756   225,196  


Q2/18 SCO production before royalties excludes 3,026 bbl/d of SCO consumed internally as diesel (Q1/18 – 3,224 bbl/d; Q2/17 – 438 bbl/d).
(3) Consists of heavy and light synthetic crude oil products.

• At the Company's world class Oil Sands Mining and Upgrading assets, operations were as expected in Q2/18 with quarterly production of 407,704 bbl/d of SCO, a decrease of 11% from Q1/18 levels as planned turnaround and pit stop activities at all three of the Company's oil sands mines as well as a major 62 day turnaround at the Scotford Upgrader were successfully completed in the quarter.

  • Cost control remains a strong focus for the Company as costs continued to come down resulting in industry leading operating costs of $22.94/bbl (US$17.77/bbl) of SCO in Q2/18, a 2% decrease from Q2/17 levels and a 7% increase from Q1/18 levels, impressive results considering major turnarounds decreased production by 11% in Q2/18 from Q1/18 levels.
  • At the AOSP, a significant milestone was reached in July, when the asset produced its 1 billionth barrel of mined bitumen during its first 15 years of operations, one of the few world class assets to reach such a milestone. This is a true demonstration of the quality, size and scale of the Company's Oil Sands Mining and Upgrading operations which through environmentally responsible, safe, reliable, effective and efficient operations, provide sustainable long life low decline production and significant value for stakeholders.
  • At Horizon, following the successful completion of the Phase 3 expansion and after operating the plant for the last 8 months, the Company continues to evaluate potential expansions and has identified additional opportunities to increase reliability, lower costs and add production.
  • Results at the potential Paraffinic Froth Treatment expansion at Horizon are evident as the engineering and design specification work completed year to date has shown that the optimal production range of the proposed expansion has increased by 10,000 bbl/d and is now targeted to be 40,000 bbl/d to 50,000 bbl/d. The expansion is targeted to produce high quality diluted bitumen at significantly lower operating costs as the Company  leverages its existing infrastructure. Preliminary estimates of the capital required for the proposed expansion are approximately $1.4 billion.
  • Defining and high grading additional opportunities is ongoing with the completion of the process targeted by year end. These opportunities are targeted to add near term growth of 35,000 bbl/d to 45,000 bbl/d of SCO. All opportunities will be executed in a disciplined and step wise manner, which preserves Canadian Natural's capital flexibility. The previously discussed VGO expansion will be included in the high grading process.
  • The Company's planned 21 day turnaround is targeted for September 2018. Subsequently, the plant will run at restricted rates of approximately 130,000 bbl/d for 12 days to perform maintenance on the Vacuum Distillate Unit ("VDU") furnaces.

• The Company's 2018 Oil Sands Mining and Upgrading annual production guidance remains unchanged and is targeted to range from 415,000 bbl/d - 450,000 bbl/d of upgraded products.

MARKETING

    Three Months Ended     Six Months Ended
 
                     
    Jun 30
 2018
  Mar 31
 2018
  Jun 30
 2017
    Jun 30
 2018
  Jun 30
 2017
Crude oil and NGLs pricing                    
                     
WTI benchmark price (US$/bbl) (1)   $ 67.90     $ 62.89     $ 48.29       $ 65.41     $ 50.07  
WCS heavy differential as a percentage  of WTI (%) (2)   28 %   39 %   23 %     33 %   26 %
SCO price (US$/bbl)   $ 67.27     $ 61.45     $ 49.83       $ 64.38     $ 50.63  
Condensate benchmark pricing (US$/bbl)   $ 68.85     $ 63.12     $ 48.44       $ 66.00     $ 50.31  
Average realized pricing before risk management (C$/bbl) (3)   $ 61.14     $ 43.06     $ 47.12       $ 52.32     $ 47.08  
Natural gas pricing                      
AECO benchmark price (C$/GJ)   $ 0.97     $ 1.75     $ 2.63       $ 1.36     $ 2.71  
Average realized pricing before risk management (C$/Mcf)   $ 1.95     $ 2.74     $ 2.97       $ 2.35     $ 3.11  

(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.

• In Q2/18, the WCS heavy differential narrowed as heavy crude oil began to be moved to market. The WCS heavy differential widened in Q1/18 as a result of third party pipeline outages backing up heavy crude oil into Western Canada. This resulted in anomalous heavy crude oil pricing as the pipeline operators and rail transport worked to remove the backlog of inventory.

• Canadian Natural and other industry participants, as part of a working committee, are working towards a more effective nomination process that verifies actual production and sales.

  • Having an effective nomination process is significant to Canadian Natural as the Company is required to sell portions of its heavy crude oil production at a discount to the WCS index as a result of apportionment on the Enbridge pipeline.

• AECO natural gas prices for Q2/18 continued to reflect third party pipeline constraints limiting flow of natural gas to export markets, increased natural gas production in the basin and constraints on export capacity out of Western Canada.

• 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 North West Redwater refinery began processing light crude oil late in November 2017 and continues to progress as expected.
  • The Company has a 50% interest in the NWR Partnership. For updates on the project, please refer to: https://nwrsturgeonrefinery.com/whats-happening/news/.

2017 Stewardship Report to Stakeholders

In Q2/18 Canadian Natural published its 2017 Stewardship Report to Stakeholders, now available on the Company's website at https://www.cnrl.com/corporate-responsibility/stewardship-report/#2017. The report displays how Canadian Natural continues to focus on safe, reliable, effective and efficient operations while minimizing its environmental footprint.

  • 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 has carbon capture facilities at its 50% interest in the NWR refinery. As a result, Canadian Natural targets capacity to capture and sequester 2.7 million tonnes of CO2 annually, equivalent to taking 570,000 vehicles off the road, making the Company the 5th largest capturer and sequester of CO2 globally once the NWR refinery is fully running.
  • At Canadian Natural's Oil Sands operations, which represent approximately 66% 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, specifically carbon capture initiatives, Canadian Natural has developed a pathway to reduce the Company's greenhouse gas ("GHG") emissions intensity to be 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 Company's GHG emissions intensity has decreased materially by 18% from 2013 to 2017.
  • Methane emissions have decreased 71% from 2013 to 2017 at the Company's Alberta primary heavy crude oil operations.

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 funds flow generation, credit facilities, US commercial paper program, 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 1,050,376 BOE/d in Q1/18, with approximately 98% of total production located in G7 countries.

  • Canadian Natural maintains a balance of products with current approximate product mix on a BOE/d basis of 50% light crude oil and SCO blends, 25% heavy crude oil blends and 25% natural gas, based upon the midpoint of annual 2018 production guidance.
  • Canadian Natural's production is resilient as long life low decline assets make up approximately 73% of 2018 liquids production guidance, including the AOSP, Horizon, Pelican Lake and thermal in situ oil sands assets.

• In Q2/18, Canadian Natural delivered funds flow from operations in excess of capital expenditures of approximately $1,730 million, an increase of approximately $510 million and $890 million from Q1/18 and Q2/17 levels respectively.

• Balance sheet strength continues to be a focus of the Company and strong financial performance was demonstrated in Q2/18 through reduced long term debt and extensions of select credit facilities.

  • In Q2/18, Standard & Poor's revised the Company's rating outlook from BBB+/negative to BBB+/stable.
  • In Q2/18, the Company reduced long term net debt by approximately $610 million, from Q1/18 levels.
  • Additionally, the Company has reduced long term debt in the past 12 months since the AOSP acquisition by approximately $2,500 million, from Q2/17 levels, when including the retirement of the deferred AOSP acquisition liability.
  • Canadian Natural maintains strong financial stability and liquidity represented by cash balances and committed bank credit facilities. At June 30, 2018 the Company had approximately $4,800 million of available liquidity, including cash and cash equivalents, an increase of approximately $800 million from Q1/18.
  • Canadian Natural continues to have significant support from its large and diverse banking group as indicated by credit facility extensions during the quarter. In Q2/18 the Company extended its $2,425 million revolving syndicated credit facility originally maturing in June 2020 to June 2022. Additionally in the quarter, Canadian Natural's $2,200 million non-revolving facility was extended from October 2019 to October 2020.
  • As at June 30, 2018, debt to book capitalization improved to 39.6% from 40.5% in Q1/18 and debt to adjusted EBITDA strengthened to 2.1x from 2.5x from Q1/18.

• Returns to shareholders remains a key focus for Canadian Natural as the Company returned approximately $850 million by way of dividend and share buybacks in Q2/18. Share buybacks for cancellation totaled 10,140,127 shares in the quarter at an weighted average share price of $43.52.

  • Subsequent to quarter end, the Company had additional share buybacks of 722,600 common shares for cancellation at a weighted average price of $46.95 per common share.

• In addition to its strong 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 June 30, 2018, these financial levers include the Company's third party equity investments of approximately $745 million.

• Subsequent to quarter end, Canadian Natural declared a quarterly cash dividend on common shares of $0.335 per share payable on October 1, 2018.

OUTLOOK

The Company forecasts annual 2018 production levels to average between 815,000 and 885,000 bbl/d of crude oil and NGLs and between 1,550 and 1,600 MMcf/d of natural gas, before royalties. Q3/18 production guidance before royalties is forecast to average between 771,000 and 819,000 bbl/d of crude oil and NGLs and between 1,535 and 1,565 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 2018 capital expenditures are targeted to be approximately $4.6 billion.

Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses and other guidance provided throughout this Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands ("Horizon") operations and future expansions, the Athabasca Oil Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the cost and timing of construction 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 or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market, and the assumption of operations at processing facilities also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts, and is 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 natural gas liquids ("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 reserve 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 reserve 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 this MD&A could also have material 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 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 Currency, Production and Non-GAAP Financial Measures

The Company's MD&A of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements for the six months ended June 30, 2018 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2017.

All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's unaudited interim consolidated financial statements for the period ended June 30, 2018 and the Company's MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. The Company's MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings from operations, funds flow from operations, adjusted cash production costs and adjusted depreciation, depletion and amortization. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings and cash flows from operating activities, as determined in accordance with IFRS, as an indication of the Company's performance. The non-GAAP measures adjusted net earnings from operations and funds flow from operations are reconciled to net earnings, as determined in accordance with IFRS, in the "Financial Highlights" section of the Company's MD&A. The non-GAAP measure funds flow from operations is also reconciled to cash flows from operating activities in this section. The derivation of adjusted cash production costs and adjusted depreciation, depletion and amortization are included in the "Operating Highlights - Oil Sands Mining and Upgrading" 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.

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. 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 volumes and per unit statistics are presented throughout the Company's MD&A on a "before royalty" or "gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. Production on an "after royalty" or "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, 2017, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov.

CONFERENCE CALL

A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, August 2, 2018.

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 16, 2018. 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 5289004.

The conference call will also be webcast live and may 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: 403-517-7777  Email: ir@cnrl.com
www.cnrl.com
 
 
STEVE W. LAUT
Executive Vice-Chairman

TIM S. MCKAY
President

COREY B. BIEBER
Chief Financial Officer and Senior Vice-President, Finance

MARK A. STAINTHORPE
Vice-President, Finance – Capital Markets

Trading Symbol - CNQ
Toronto Stock Exchange
New York Stock Exchange 

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