Canadian Natural Resources Limited Announces 2019 Second Quarter Results
August 1, 2019 - 5:00 AM EDT
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Canadian Natural Resources Limited Announces 2019 Second Quarter Results
CALGARY, Alberta, Aug. 01, 2019 (GLOBE NEWSWIRE) -- Commenting on the Company's second quarter 2019 results, Steve Laut, Executive Vice-Chairman of Canadian Natural stated, "Canadian Natural's second quarter results demonstrated the advantages of our diverse and balanced asset base combined with our flexible capital allocation resulting in significant adjusted funds flow in the quarter of approximately $2.7 billion. Throughout the first half of 2019 we were able to deliver on our four pillars of capital allocation through disciplined economic resource development, increasing returns to shareholders, strengthening our balance sheet and opportunistically acquiring accretive assets. The Company continues its focus on maximizing shareholder value while delivering responsible and sustainable operations."
Canadian Natural's President, Tim McKay, added, "Canadian Natural's ability to effectively and efficiently execute, delivered strong operating costs of $11.68/BOE across our Exploration and Production ("E&P") assets in the second quarter, resulting in operating cost reductions of 8% from both Q1/19 and Q2/18 levels. The Company achieved strong second quarter production of 1,025,800 BOE/d, strategically managing maintenance activities and optimizing its production volumes by executing on our curtailment optimization strategy.
The integration of the Devon assets that were recently acquired on June 27, 2019, continues to progress smoothly and our teams are working together to leverage learnings and maximize synergies between our existing and the acquired crude oil assets. Since the close of the acquisition, the Company has already realized significant cost savings. In addition, we are targeting to move a portion of heavy crude oil production from the acquired properties to the Company's 100% owned ECHO pipeline by the end of Q3/19, more than one year ahead of our initial plan."
Canadian Natural's Chief Financial Officer, Mark Stainthorpe, continued, "In the second quarter of 2019, the Company delivered another quarter of strong financial results with net earnings of approximately $2.8 billion and adjusted net earnings of approximately $1.0 billion, an increase of $204 million over Q1/19 levels.
Canadian Natural continues to deliver on its free cash flow allocation policy. In the first half of 2019, the Company returned a total of $1,484 million to shareholders, $852 million by way of dividends and $632 million by way of share purchases. Subsequent to the quarter, up to July 31, 2019, an additional 2.3 million common shares were purchased for cancellation at an average share price of $34.55. Our financial position remains strong as net long-term debt, excluding financing related to the recently closed acquisition, decreased by approximately $1.2 billion over Q1/19 levels. To fund the asset acquisition in the quarter, we successfully syndicated a 3 year, $3.25 billion term facility while available liquidity improved over the quarter to approximately $4.6 billion, including cash and cash equivalents.
At current strip pricing and based on our corporate guidance, we target to exit 2019 with a debt to adjusted EBITDA, debt to cash flow and debt to book capital ratios at levels below those existing at December 31, 2018, despite the completion of the $3.2 billion Devon acquisition which was financed through the Company's strong balance sheet and after returns to shareholders by way of dividends and share purchases throughout the year. The accretive Devon acquisition results in the Company growing long life low decline reserves and production and when combined with the robustness of the business model allows for significant free cash flow generation, continued returns to shareholders and further strengthening of our financial position through 2019."
QUARTERLY HIGHLIGHTS
Three Months Ended
Six Months Ended
($ millions, except per common share amounts)
Jun 30 2019
Mar 31 2019
Jun 30 2018
Jun 30 2019
Jun 30 2018
Net earnings
$
2,831
$
961
$
982
$
3,792
$
1,565
Per common share
– basic
$
2.37
$
0.80
$
0.80
$
3.17
$
1.28
– diluted
$
2.36
$
0.80
$
0.80
$
3.16
$
1.27
Adjusted net earnings from operations (1)
$
1,042
$
838
$
1,279
$
1,880
$
2,164
Per common share
– basic
$
0.87
$
0.70
$
1.05
$
1.57
$
1.77
– diluted
$
0.87
$
0.70
$
1.04
$
1.57
$
1.76
Cash flows from operating activities
$
2,861
$
996
$
2,613
$
3,857
$
5,082
Adjusted funds flow (2)
$
2,652
$
2,240
$
2,706
$
4,892
$
5,029
Per common share
– basic
$
2.22
$
1.87
$
2.20
$
4.09
$
4.10
– diluted
$
2.22
$
1.86
$
2.19
$
4.08
$
4.08
Cash flows used in investing activities
$
4,464
$
1,029
$
1,138
$
5,493
$
2,507
Net capital expenditures, excluding Devon acquisition costs (3)
$
908
$
977
$
974
$
1,885
$
2,077
Total net capital expenditures, including Devon acquisition costs (3)
$
4,125
$
977
$
974
$
5,102
$
2,077
Daily production, before royalties
Natural gas (MMcf/d)
1,532
1,510
1,539
1,521
1,576
Crude oil and NGLs (bbl/d)
770,409
783,512
793,899
776,924
824,060
Equivalent production (BOE/d) (4)
1,025,800
1,035,212
1,050,376
1,030,480
1,086,757
Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance, as it demonstrates the Company’s ability to generate after-tax operating earnings from its core business areas. The derivation of this measure is discussed in the Management’s Discussion and Analysis (“MD&A”).
Adjusted funds flow (previously referred to as funds flow from operations) is a non-GAAP measure that the Company considers key to evaluate its performance as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The derivation of this measure is discussed in the MD&A.
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 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.
Net earnings of $2,831 million were realized in Q2/19, increases of $1,870 million and $1,849 million over Q1/19 and Q2/18 levels, respectively. Adjusted net earnings of $1,042 million were achieved in Q2/19, a $204 million increase over Q1/19 levels.
Cash flows from operating activities were $2,861 million in Q2/19, an increase of $1,865 million compared to Q1/19 levels.
Canadian Natural generated significant quarterly adjusted funds flow of $2,652 million in Q2/19, an increase of 18% or $412 million over Q1/19 levels. The increase over Q1/19 was primarily due to higher crude oil and NGLs netbacks in the Company's North America and International segments, partially offset by lower Synthetic Crude Oil ("SCO") production volumes in the Oil Sands Mining and Upgrading segment and lower natural gas netbacks.
Cash flows used in investing activities were $4,464 million in Q2/19. Before net acquisitions, the Company's cash flows used in investing activities were $1,052 million in Q2/19.
Canadian Natural delivered strong quarterly free cash flow of $1,295 million after net capital expenditures of $908 million, and dividend requirements of $449 million, excluding costs related to the recently closed acquisition, reflecting the strength of our long life low decline asset base and our effective and efficient operations.
Canadian Natural is committed to returns to shareholders, returning a total of $840 million in the quarter, $449 million by way of dividends and $391 million by way of share purchases. In the first half of 2019, the Company has returned a total of $1,484 million to shareholders, $852 million by way of dividends and $632 million by way of share purchases.
Share purchases for cancellation in the quarter totaled 10,450,000 common shares at a weighted average share price of $37.41.
Subsequent to quarter end, up to and including July 31, 2019, the Company executed on additional share purchases for cancellation of 2,300,000 common shares at a weighted average share price of $34.55.
Subsequent to quarter end, the Company declared a quarterly dividend of $0.375 per share, payable on October 1, 2019.
Capital expenditures in the first six months of 2019 were approximately $190 million below the original budget, showing strong discipline on capital spending with flexibility for potential execution of these projects later in 2019 or into 2020. Annual 2019 corporate capital guidance has increased by $100 million, representing amounts required to maintain the acquired Devon assets.
Curtailment Optimization Strategy Update
On December 5, 2018, the Company released its budgeted annual 2019 production guidance which only included Company originated estimated voluntary curtailments through to the end of Q2/19. Subsequently, on January 1, 2019, the Government of Alberta mandatory curtailment program came into effect, which superseded the Company's voluntary curtailment estimates. The government mandatory curtailment has been successful in stabilizing the crude oil differential discount that Alberta was receiving for both light crude oil and heavy crude oil. As the year has progressed, mandatory curtailments have continued and timing of the cessation of mandatory curtailments remains uncertain. Crude by rail has continued to increase from Q1/19 levels, while storage levels have trended down, albeit at a slower rate than was originally envisioned. As a result, the Company now budgets for continued government mandated curtailments through to the end of 2019. The Company currently has significant additional production capacity beyond the currently mandated curtailed production levels available and continues to execute operational flexibility through its curtailment optimization strategy as follows:
Mitigating production impacts from unplanned maintenance activities at both Scotford and Horizon by increasing conventional and thermal in situ crude oil production. As a result of the Company's execution on its curtailment optimization strategy, North America Exploration and Production ("E&P") and thermal in situ oil sands production exceeded Q2/19 production guidance, excluding acquisition volumes.
During the planned turnaround at Horizon in the fall, the Company targets to achieve its mandatory curtailment allowable by executing its curtailment optimization strategy along with production from pad additions at Primrose, which continue to be ahead of schedule, demonstrating the Company's ability to manage production while under curtailment.
Modifying timing of the Company's planned turnaround activities to achieve its monthly curtailment allowable.
Maximizing value through production optimization of higher netback assets and reducing operating costs.
Despite mandatory government curtailments being beyond the Company budgeted voluntary curtailment estimates, the Company's revised production guidance still remains in the range of original budget guidance levels, adjusted for the targeted production from the recently closed Devon acquisition, reflecting the Company’s strong asset base, flexible operations as well as the implementation of the Company's curtailment optimization strategy.
On June 27, 2019, the Company successfully closed the acquisition of substantially all of the assets of Devon Canada Corporation, adding to the Company's long life low decline asset base. In total, approximately 720 employees were successfully transitioned to Canadian Natural. The Company's teams are working together to leverage technology and maximize synergies between the existing and acquired crude oil assets. The Company is ahead of its initial plan in achieving targeted annual cost savings of $135 million which includes the following cost saving opportunities, for both primary heavy and thermal in situ crude oil assets, with the potential for more:
The Company is targeting to consolidate acquired facilities and move a portion of the heavy crude oil production from the acquired properties to its 100% owned ECHO pipeline by the end of Q3/19, more than one year ahead of its initial plan, targeting approximately $25 million in margin improvements per year.
Utilizing acquired sand storage, deferring the need to construct a new facility.
Redirecting approximately 3,700 bbl/d of primary heavy crude oil previously processed by a third party to Canadian Natural facilities.
Reducing trucking costs through optimization of fluids in field production tanks, and disposing of water volumes at acquired facilities.
Capturing operating cost synergies through consolidation of regional camps and aerodromes.
Capturing economies of scale for warehousing, contracting, as well as parts and procurement.
Leveraging operational and technical expertise for preventative maintenance programs across the thermal in situ Steam Assisted Gravity Drainage ("SAGD") assets.
Reducing costs by optimizing well servicing activities and rig utilization.
Canadian Natural's continued focus on delivering effective and efficient operations was demonstrated as the Company's Exploration and Production ("E&P") Q2/19 operating costs were $11.68/BOE, an 8% reduction from both Q1/19 and Q2/18 levels.
The Company achieved quarterly production volumes of 1,025,800 BOE/d in Q2/19, comparable to Q1/19 and a 2% decrease from Q2/18 levels, reflecting the Company's execution on its curtailment optimization strategy to offset the impacts of the extended time to complete repairs at the Scotford Upgrader and proactive maintenance activities at Horizon, as well as production impacts of approximately 6,300 bbl/d from wildfires near the Company's Pelican Lake and Woodenhouse operations.
Canadian Natural's North America E&P crude oil and NGLs production volumes, excluding thermal in situ, averaged 235,066 bbl/d in Q2/19, exceeding Q2/19 production guidance and a 4% increase over Q1/19 levels. The increase was primarily due to execution on the Company's curtailment optimization strategy, partially offset by production impacts in late May and early June of approximately 6,300 bbl/d of quarterly production lost due to wildfires near the Company's Pelican Lake and Woodenhouse operations. The Company restarted operations at Pelican Lake on June 8, 2019 and production for July averaged approximately 62,000 bbl/d, comparable to rates prior to the shutdown.
Thermal in situ oil sands production volumes averaged 109,599 bbl/d in Q2/19, a 16% increase over Q1/19 levels, primarily due to execution on the Company's curtailment optimization strategy and additional volumes from the Devon asset acquisition that closed on June 27, 2019. Excluding the acquisition volumes, thermal in situ crude oil production exceeded Q2/19 production guidance.
Pad additions at Primrose continue to be ahead of schedule and on budget with initial production targeted in Q3/19, offsetting production impacts from the planned turnaround at Horizon as part of the Company's curtailment optimization strategy. These pad additions are high return activities as the Company utilizes available excess oil processing and steam capacity at Primrose.
As previously announced, at the Company's Kirby North SAGD project, top tier execution and strong productivity have resulted in the project remaining two quarters ahead of the sanctioned schedule with overall cost performance remaining on budget. The commissioning of the central processing facility was ahead of schedule and as a result, the project began steaming in Q2/19. As part of the Company's curtailment optimization strategy, the Company targets to manage the ramp up of production towards Kirby North's overall capacity of 40,000 bbl/d in early 2021.
North America natural gas production was 1,482 MMcf/d in Q2/19, an increase of 2% over Q1/19 levels and comparable with Q2/18 levels. The increase in Q2/19 was primarily due to associated gas from the Company's light crude oil and liquids rich natural gas drilling program, partially offset by natural field declines.
International E&P production volumes were strong in Q2/19, averaging 51,244 bbl/d, increasing by 7% and 20% over Q1/19 and Q2/18 levels, respectively. The increases over the comparable periods are due to the successful drilling programs at Ninian and Baobab, partially offset by the planned turnaround at Ninian and natural field declines. As a result these strong operational results, the Company has increased its annual 2019 International production guidance.
International production volumes benefit from premium Brent pricing, generating significant free cash flow for the Company.
At the Company's world class Oil Sands Mining and Upgrading assets, second quarter production volumes averaged 374,500 bbl/d of SCO, a decrease of 10% from Q1/19 levels. The decrease in production primarily reflected extended time to complete repairs at the Scotford Upgrader, as well as proactive maintenance activities at Horizon. After completion of these repairs and maintenance activities Oil Sands Mining production has been strong, averaging approximately 463,000 bbl/d of SCO production in the month of July.
Total production costs were $814 million in Q2/19, comparable to Q1/19 levels and a 5% decrease from $855 million in Q2/18. Production costs for the first half of 2019 were $1,636 million, a 5% or $92 million decrease from the comparable period in 2018, demonstrating the Company's focus on effective and efficient operations.
Canadian Natural realized quarterly operating costs of $24.17/bbl (US$18.06/bbl) of SCO in Q2/19, a 13% increase over Q1/19 and a 5% increase over Q2/18 levels, reflecting lower production volumes in the quarter.
At Horizon, as a result of Canadian Natural's industry leading integrity program, the Company identified a portion of the piping to the amine unit that had reduced thickness and made the proactive decision to advance this maintenance in Q2/19, ahead of the planned fall turnaround. The Company was able to mitigate some of the production impact from the 16 day outage by bringing on curtailed production.
The Company has reviewed and optimized the scope of work for the planned Horizon fall turnaround and as a result, the turnaround is now targeted for 25 days starting in late Q3/19, a reduction of 3 days.
Canadian Natural maintains strong financial stability and liquidity represented by cash balances, and committed and demand bank credit facilities. At June 30, 2019 the Company had approximately $4,560 million of available liquidity, including cash and cash equivalents.
ENVIRONMENTAL HIGHLIGHTS
In July 2019, Canadian Natural published its 2018 Stewardship Report to Stakeholders, now available on the Company's website at https://www.cnrl.com/report-to-stakeholders. The report displays how Canadian Natural continues to focus on safe, reliable, effective and efficient operations while minimizing its environmental footprint. Highlights from the 2018 report are as follows:
Canadian Natural's corporate greenhouse gas ("GHG") emissions intensity has decreased by approximately 29% from 2012 to 2018, a material reduction in emissions intensity.
The Company's corporate GHG emissions intensity decreased in 2018 by approximately 5% from 2017 levels, including a reduction of approximately 18% in Oil Sands Mining and Upgrading.
Methane emissions have decreased 78% from 2012 to 2018 at the Company's Alberta primary heavy crude oil operations.
In the Company's North America E&P segment, in 2018 natural gas flaring decreased by 4% and natural gas venting decreased by 6% from 2017 levels.
In 2018, in the Company's North America E&P segment, Canadian Natural abandoned 1,293 wells, an increase of 68% over 2017 levels, and submitted 1,012 reclamation certificates, an increase of approximately 67% over 2017 levels.
The Company reclaimed 1,383 hectares of land in 2018 in the Company's North America E&P segment, equivalent to approximately 1,700 Canadian football fields and a 9% increase over 2017 levels.
In the Oil Sands Mining and Upgrading segment, water use intensity decreased in 2018 by 30% from 2017 levels.
Approximately 75% of water used at Primrose was sourced from recycled produced water in 2018.
Canadian Natural has invested over $3.4 billion in research and development since 2009 and continues to invest in technology to unlock reserves, become more effective and efficient, increase production and reduce the Company's environmental footprint. Canadian Natural's culture of continuous improvement leverages the use of technology and innovation to drive sustainable operations and long-term value for shareholders.
Canadian Natural has invested significant capital to capture and sequester CO2. The Company has carbon capture and sequestration facilities at Horizon, a 70% working interest in the Quest Carbon Capture and Storage project at Scotford, and through carbon capture facilities through 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 576,000 vehicles off the road per year, making the Company one of the largest CO2 capturer and sequester for the oil and natural gas sector globally.
Canadian Natural's commitment to leverage technology, adopting innovation and continuous improvement is evidenced by its In Pit Extraction Process ("IPEP") pilot at Horizon, which will determine the feasibility of producing stackable dry tailings. The project has the potential to reduce the Company's carbon emissions and environmental footprint by reducing the usage of haul trucks, the size and need for tailings ponds and accelerating site reclamation. In addition, this process has the potential to significantly reduce capital and operating costs.
The initial testing phase for the Company's IPEP pilot has concluded and results have been positive with excellent recovery rates and evidence of stackable tailings. Given the positive results thus far, the Company continues to make enhancements and will operate and test the pilot through 2019.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural’s production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, thermal in situ crude oil, bitumen and SCO (herein collectively referred to as “crude oil”), natural gas and NGLs. This balance provides optionality for capital investments, maximizing value for the Company’s shareholders.
Underpinning this asset base is long life low decline production from the Company's Oil Sands Mining and Upgrading, thermal in situ oil sands and Pelican Lake heavy crude oil assets. The combination of long life low decline, low reserves replacement cost, and effective and efficient operations results in substantial and sustainable adjusted funds flow throughout the commodity price cycle.
Augmenting this, Canadian Natural maintains a substantial inventory of low capital exposure projects within the Company's conventional asset base. These projects can be executed quickly and with the right economic conditions, can provide excellent returns and maximize value for shareholders. Supporting these projects is the Company’s undeveloped land base which enables large, repeatable drilling programs which can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control major components of the Company's operating costs and minimize production commitments. Low capital exposure projects can be quickly stopped or started depending upon success, market conditions, or corporate needs.
Canadian Natural’s balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.
Drilling Activity
Six Months Ended June 30
2019
2018
(number of wells)
Gross
Net
Gross
Net
Crude oil
39
38
210
203
Natural gas
12
10
13
9
Dry
3
3
2
2
Subtotal
54
51
225
214
Stratigraphic test / service wells
379
335
555
477
Total
433
386
780
691
Success rate (excluding stratigraphic test / service wells)
94
%
99
%
The Company's total crude oil and natural gas drilling program of 51 net wells for the six months ended June 30, 2019, excluding strat/service wells, decreased by 163 net wells from the same period in 2018. The Company's drilling levels reflect the disciplined capital allocation process, continued actions to enhance operations, and execution on the Company's curtailment optimization strategy.
North America Exploration and Production
Crude oil and NGLs – excluding Thermal In Situ Oil Sands
Three Months Ended
Six Months Ended
Jun 30 2019
Mar 31 2019
Jun 30 2018
Jun 30 2019
Jun 30 2018
Crude oil and NGLs production (bbl/d)
235,066
225,291
238,631
230,205
242,101
Net wells targeting crude oil
9
28
58
37
159
Net successful wells drilled
7
28
58
35
157
Success rate
78
%
100
%
100
%
95
%
99
%
North America E&P crude oil and NGLs production volumes averaged 235,066 bbl/d in Q2/19, exceeding Q2/19 production guidance and a 4% increase over Q1/19 levels. The increase was primarily due to execution on the Company's curtailment optimization strategy, partially offset by production impacts of approximately 6,300 bbl/d from wildfires near the Company's Pelican Lake and Woodenhouse operations.
Canadian Natural's primary heavy crude oil production averaged 77,667 bbl/d in Q2/19, a 13% increase over Q1/19 levels primarily due to execution on the Company's curtailment optimization strategy and additional volumes from the Devon asset acquisition that closed on June 27, 2019. Primary heavy crude oil production decreased by 8% from Q2/18 levels primarily due to the Company's strategic decision to reduce activity through 2018 as a result of the widening price differentials in 2018 and the impact of the Government of Alberta mandated production curtailments that came into effect January 1, 2019.
Operating costs of $17.52/bbl were achieved in the Company's primary heavy crude oil operations in the quarter, comparable to Q1/19 and a 3% increase over Q2/18 levels, strong results given the 8% decrease in volumes.
The Company drilled 5 net primary heavy crude oil wells in Q2/19, targeting strategic opportunities for future development, particularly in Saskatchewan, where 3 of the 5 wells were drilled as production is not impacted by curtailments. Canadian Natural is leveraging the Company's multilateral horizontal technology expertise on 2 of these wells.
An additional 11 net multilateral horizontal wells, primarily in Saskatchewan, are targeted to be drilled in the last half of the year. By leveraging technology and taking advantage of the Company's expertise, the Company continues to unlock value in its primary heavy crude oil assets.
The recently acquired primary heavy crude oil Manatokan lands, with the potential for 658 net locations, are an excellent fit within the Company's existing primary heavy crude oil operations. As part of the Company's continued focus on technology and innovation, 85% of the identified potential locations are multilateral horizontal wells. The Company's teams are working together to leverage technology and maximize synergies.
The Company is ahead of its initial plan in achieving targeted annual cost savings of $135 million on the Devon properties, including both primary heavy and thermal in situ crude oil assets. In addition to economies of scale, the Company has identified the following primary heavy crude oil cost saving opportunities, with the potential for more:
The Company is targeting to consolidate acquired facilities and move a portion of the heavy crude oil production from the acquired properties to the Company's 100% owned ECHO pipeline by the end of Q3/19, more than one year ahead of its initial plan, targeting approximately $25 million in margin improvements per year.
Utilizing acquired sand storage, deferring the need to construct a new facility.
Redirecting approximately 3,700 bbl/d of primary heavy crude oil previously processed by a third party to Canadian Natural facilities.
Reducing trucking costs through optimization of fluids in field production tanks, and disposing of water volumes at acquired facilities.
North America light crude oil and NGL production averaged 102,368 bbl/d in Q2/19, a 14% increase over Q2/18 and 7% increase over Q1/19 levels, reflecting the Company's strategic decision to reallocate capital to light crude oil and liquids rich areas, along with strong results from the 2018 and 2019 drilling programs at Wembley, Karr, and Southeast Saskatchewan, and execution on the Company's curtailment optimization strategy.
Within the greater Wembley area, results continue to exceed expectations. In the first half of the year, the Company brought 12 net wells on production with initial 30 day liquids production rates averaging approximately 680 bbl/d per well, exceeding expectations of approximately 560 bbl/d per well. An additional 2 net wells are targeted to come on production in Q3/19. The Company has identified the potential for 363 incremental high quality premium light crude oil and liquids rich Montney drilling locations on the Company's 155 net sections.
In the first half of the year, in the Company's Karr area, 12 net wells have come on production, delivering strong results. The wells are currently producing at approximately 2,750 bbl/d total, in-line with expectations and being further optimized. Canadian Natural holds approximately 50 net sections of prospective Dunvegan rights with the potential of 45 high quality light crude oil locations. The Company is currently evaluating water flood implementation at Karr to increase recoveries and maximize long term value.
In Southeast Saskatchewan, the Company drilled 4 net light crude oil wells in Q2/19, with an additional 7 net wells targeted to be drilled in Q3/19. All 11 of these high return wells are targeted to be on stream in Q3/19, with expected rates averaging approximately 80 bbl/d per well. The Company strategically reallocated capital from Alberta to Saskatchewan as production from these wells are not impacted by the Government of Alberta mandated production curtailments.
In Q2/19 operating costs of $14.67/bbl were strong in the Company's North America light crude oil and NGL areas, decreases of 8% and 7% from Q1/19 and Q2/18 levels respectively, primarily due to increased production volumes and the Company's focus on cost control.
Pelican Lake quarterly production averaged 55,031 bbl/d in Q2/19, a decrease of 10% from Q1/19 levels, reflecting production impacts of approximately 5,400 bbl/d from the temporary shut-in of crude oil production due to wildfires in northern Alberta.
As previously announced, Canadian Natural completed a safe, temporary shut down of Pelican Lake production on May 30, 2019 due to wildfires in the region. The Company restarted operations on June 8, 2019 and production for July averaged approximately 62,000 bbl/d, comparable to rates prior to the shut down.
Strong operating costs of $6.72/bbl were achieved in Q2/19 at Pelican Lake, comparable to Q1/19 and a 3% decrease from Q2/18 levels, impressive results given the decrease in production due to the Alberta wildfires in the quarter.
The Company’s annual 2019 North America E&P crude oil and NGL production guidance has been increased to incorporate the Devon acquisition and is now targeted to range between 231,000 bbl/d - 251,000 bbl/d.
Thermal In Situ Oil Sands
Three Months Ended
Six Months Ended
Jun 30 2019
Mar 31 2019
Jun 30 2018
Jun 30 2019
Jun 30 2018
Bitumen production (bbl/d)
109,599
94,146
104,907
101,915
108,359
Net wells targeting bitumen
—
—
21
—
43
Net successful wells drilled
—
—
21
—
43
Success rate
—
—
100
%
—
100
%
Thermal in situ oil sands production volumes averaged 109,599 bbl/d in Q2/19, a 16% increase over Q1/19 levels, primarily due to the Company's execution on its curtailment optimization strategy and additional volumes from the Devon asset acquisition that closed on June 27, 2019. Excluding the acquisition volumes, thermal in situ crude oil production exceeded Q2/19 production guidance.
At Primrose, Q2/19 production volumes averaged 71,917 bbl/d, an increase of 16% over Q1/19 levels, primarily due to execution on the Company's curtailment optimization strategy. Including energy costs, operating costs were strong at $12.39/bbl in Q2/19, decreases of 39% and 15% from Q1/19 and Q2/18 levels respectively, reflecting higher volumes and lower energy costs.
Pad additions at Primrose continue to be ahead of schedule and on budget with initial production targeted in Q3/19, offsetting production impacts from the planned turnaround at Horizon as part of the Company's curtailment optimization strategy. These pad additions are high return activities as the Company utilizes available excess oil processing and steam capacity at Primrose.
At Kirby South, SAGD production volumes averaged 28,597 bbl/d in Q2/19, a 4% decrease from Q1/19 and a 19% decrease from Q2/18 levels. Including energy costs, Kirby South quarterly operating costs were strong at $10.55/bbl in Q2/19, a reduction of 14% from Q1/19 levels, primarily as a result of lower energy costs. Operating costs increased by 16% from Q2/18 levels primarily due to lower production volumes.
In Q2/19 at Kirby South, the Company began its solvent enhanced SAGD pilot as planned. Initial results are positive indicating reduced Steam to Oil Ratios ("SORs") in line with expectations. If successful, solvent enhanced SAGD has the potential to significantly reduce SORs, operating costs and greenhouse gas emissions. The Company targets to continue to operate the pilot for approximately 2 years.
As previously announced, at the Company's Kirby North SAGD project, top tier execution and strong productivity have resulted in the project remaining two quarters ahead of the sanctioned schedule with overall cost performance remaining on budget. The commissioning of the central processing facility was ahead of schedule and as a result, the project began steaming in Q2/19. As part of the Company's curtailment optimization strategy, the Company targets to manage the ramp up of production towards Kirby North's overall capacity of 40,000 bbl/d in early 2021.
The recently acquired Jackfish thermal in situ crude oil assets are an excellent fit with our existing thermal in situ crude oil assets, adding to the Company's long life low decline asset base. The Company's teams are working together to leverage technology and maximize synergies between the existing and acquired crude oil assets.
The Company is ahead of its initial plan in achieving targeted annual cost savings of $135 million on the Devon properties, including both thermal in situ and primary heavy crude oil assets. The Company has identified the following thermal in situ crude oil cost savings and optimization opportunities, with the potential for more:
Capturing operating cost synergies through consolidation of regional camps and aerodromes.
Capturing economies of scale for warehousing, contracting, as well as parts and procurement.
Leveraging operational and technical expertise for preventative maintenance programs across the thermal in situ SAGD assets.
Reducing costs by optimizing well servicing activities and rig utilization.
The Company’s annual 2019 thermal in situ production guidance has been increased to incorporate the Devon acquisition and is now targeted to range between 157,000 bbl/d - 172,000 bbl/d.
North America Natural Gas
Three Months Ended
Six Months Ended
Jun 30 2019
Mar 31 2019
Jun 30 2018
Jun 30 2019
Jun 30 2018
Natural gas production (MMcf/d)
1,482
1,454
1,485
1,468
1,515
Net wells targeting natural gas
2
9
4
11
9
Net successful wells drilled
2
8
4
10
9
Success rate
100
%
89
%
100
%
91
%
100
%
North America natural gas production was 1,482 MMcf/d in Q2/19, an increase of 2% over Q1/19 levels and comparable with Q2/18 levels. The increase in Q2/19 was primarily due to associated gas from the Company's light crude oil and liquids rich natural gas drilling program, partially offset by natural field declines.
Strong operating costs of $1.15/Mcf were achieved in Q2/19, a decrease of 12% from Q1/19 and 10% from Q2/18 levels, primarily due to the Company's continued focus on cost control and due to the 2% increase in volumes over Q1/19 levels.
At the Company's high value Septimus Montney liquids rich area, 5 net wells, with targeted production capacity of approximately 2,080 bbl/d of NGLs and 30 MMcf/d of natural gas, were completed in late Q2/19. Rates for the new wells are in line with expectations. The Septimus plant is expected to be maintained at full capacity for the remainder of 2019.
Septimus operating costs were $0.33/Mcfe in Q2/19, an 8% reduction from Q1/19 levels, and a further reduction of 12% to $0.29/Mcfe is targeted for the remainder of 2019. Continued low operating costs at Septimus support the Company's high value liquids rich development.
The Company's natural gas reinjection pilot at Septimus commenced its first injection of 5 MMcf/d in Q2/19. Depending on results of the pilot, this technology has the potential to materially increase liquids recovery while storing natural gas in the reservoir, preserving the value of the natural gas for periods with higher market prices.
Results from the first injection and production cycle are targeted for late 2019 with the potential to proceed with additional cycles at the same location. Given the opportunities for this process across Canadian Natural's vast liquids rich Montney land base, the Company is advancing readiness for a second pilot site within the Company's Greater Wembley area.
A portion of the capital reallocated from Alberta crude oil projects was deployed in the Company's liquids rich Gold Creek assets, which are not subject to curtailment. In the Gold Creek area, 2 net wells came on production in Q2/19 with initial rates of approximately 650 bbl/d and 4.9 MMcf/d per well, exceeding liquids expectations by 44% per well. Subsequent to quarter end, an additional 2 net wells came on production with initial rates of approximately 900 bbl/d and 5 MMcf/d per well, exceeding liquids expectations by 43% per well.
The Company successfully closed the acquisition of the Pine River plant on May 3, 2019. A 45 day planned plant turnaround designed to improve plant efficiency, run time, lower operating costs, and improve plant capability to 120 MMcf/d from current levels of 95 MMcf/d, is targeted to commence in late Q3/19.
In 2019, based upon the midpoint of annual production guidance, Canadian Natural targets to use the equivalent of approximately 45% of its total corporate natural gas production in its operations, providing a natural hedge from the challenging Western Canadian natural gas price environment. Approximately 34% of the Company's guided 2019 natural gas production is targeted to be exported to other North American markets and sold internationally. The remaining 21% of the Company's 2019 targeted natural gas production would be exposed to AECO/Station 2 pricing.
The Company’s annual 2019 corporate natural gas production guidance remains unchanged and is targeted to range between 1,485 MMcf/d - 1,545 MMcf/d.
International Exploration and Production
Three Months Ended
Six Months Ended
Jun 30 2019
Mar 31 2019
Jun 30 2018
Jun 30 2019
Jun 30 2018
Crude oil production (bbl/d)
North Sea
27,594
25,714
24,456
26,659
23,028
Offshore Africa
23,650
22,155
18,201
22,907
18,816
Natural gas production (MMcf/d)
North Sea
23
28
30
25
34
Offshore Africa
27
28
24
28
27
Net wells targeting crude oil
0.9
1.6
1.9
2.5
2.9
Net successful wells drilled
0.9
1.6
1.9
2.5
2.9
Success rate
100
%
100
%
100
%
100
%
100
%
International E&P production volumes were strong in Q2/19, averaging 51,244 bbl/d, increasing by 7% and 20% over Q1/19 and Q2/18 levels, respectively. The increases from the comparable periods are due to the successful drilling programs at Ninian and Baobab, partially offset by the planned turnaround at Ninian and natural field declines.
International production volumes benefit from premium Brent pricing, generating significant free cash flow for the Company.
In the North Sea, production volumes of 27,594 bbl/d were achieved in Q2/19, increasing by 7% and 13% over Q1/19 and Q2/18 levels, respectively. The increases over Q1/19 and Q2/18 were primarily as a result of successful drilling in 2018 and the first half of 2019, partially offset by planned maintenance activities at the Ninian Central Platform and natural field declines. Current production for the 2 gross (1.9 net) wells drilled in 2019 is exceeding budgeted expectations of 4,200 bbl/d net, by approximately 1,000 bbl/d.
Q2/19 operating costs in the North Sea averaged $37.31/bbl (£22.39/bbl), a reduction of 6% from Q1/19 levels, primarily due to timing of liftings from various fields that have different cost structures, partially offset by the impact of turnaround costs.
In the second half of 2019, the Company targets to drill 3 gross (2.9 net) high netback producer wells. The total 2019 North Sea drilling program now consists of 5 gross (4.8 net) high return producer wells, capturing improving margins in the Company's successful North Sea operations.
The Company is targeting planned turnaround activities at the Tiffany platform and Banff Floating Production Storage and Offloading ("FPSO") vessel in Q3/19. Production impacts are reflected in Q3/19 guidance.
Offshore Africa production volumes in Q2/19 averaged 23,650 bbl/d, increases of 7% and 30% increase over Q1/19 and Q2/18 levels, respectively. The increases over Q1/19 and Q2/18 were primarily as a result of production from the successful Baobab drilling program, partially offset by natural field declines.
Côte d'Ivoire crude oil operating costs averaged $8.40/bbl (US$6.28/bbl) in Q2/19, a reduction of 14% from Q1/19 levels primarily due to increased volumes and timing of liftings from various fields that have different cost structures.
In Q2/19, the Company drilled 1.0 gross (0.6 net) injector well, completing the Baobab drilling program. The total Baobab drilling program of 4 gross (2.4 net) producer wells and 2 gross (1.2 net) injectors was completed on budget. Production from the new wells is exceeding budgeted expectations by approximately 3,000 bbl/d net.
As previously announced, the Company had targeted to commence a high value drilling program in Q4/19 at Espoir. Due to ongoing discussions with the Côte d'Ivoire Government, the Espoir drilling program has been canceled until such time as certain foreign exchange practices can be clarified.
Canadian Natural successfully drilled an appraisal well (0.6 net) at Kossipo in Q2/19. The well flowed light crude oil at a facility constrained rate of 7,360 bbl/d, exceeding expectations. The Company is currently evaluating project economics and contractual terms for development drilling and a pipeline tied-back to the Baobab FPSO vessel, adding significant future value with potential gross production capability of 20,000 bbl/d targeted in 2022.
Following the previously announced discovery of significant gas condensate in South Africa, where Canadian Natural owns a 20% working interest, the operator targets to acquire 3D seismic on the Block in 2019.
In the first half of 2020, the operator targets to drill 1 gross exploration well and depending on results, may drill 2 additional wells to further define volumes and deliverability.
Based on positive drilling results, the Company's annual 2019 International production guidance has been increased and is now targeted to range from 46,000 bbl/d - 50,000 bbl/d.
North America Oil Sands Mining and Upgrading
Three Months Ended
Six Months Ended
Jun 30 2019
Mar 31 2019
Jun 30 2018
Jun 30 2019
Jun 30 2018
Synthetic crude oil production (bbl/d) (1) (2)
374,500
416,206
407,704
395,238
431,756
SCO production before royalties and excludes volumes consumed internally as diesel.
Consists of heavy and light synthetic crude oil products.
At the Company's world class Oil Sands Mining and Upgrading assets, quarterly production volumes averaged 374,500 bbl/d of SCO, a decrease of 10% from Q1/19 levels. The decrease in production primarily reflected extended time to complete repairs at the Scotford Upgrader, as well as proactive maintenance activities at Horizon.
Total production costs were $814 million in Q2/19, comparable to Q1/19 levels and a 5% decrease from $855 million in Q2/18. Production costs for the first half of 2019 were $1,636 million, a 5% or $92 million decrease from the comparable period in 2018, demonstrating the Company's focus on effective and efficient operations.
Canadian Natural realized quarterly operating costs of $24.17/bbl (US$18.06/bbl) of SCO in Q2/19, a 13% increase over Q1/19 and a 5% increase over Q2/18 levels, reflecting lower production volumes in the quarter.
As previously announced, a fire occurred at the non-operated Scotford North Upgrader on April 15, 2019. The fire was promptly extinguished, all personnel were accounted for, and there were no reported injuries. Repairs were successfully completed for approximately $21 million gross and took an additional 28 days to complete following the planned 38 day turnaround. Operations resumed to full production on June 24, 2019 and the Company was able to minimize the impacts of Scotford repairs by bringing on curtailed production in other areas of its asset base.
At Horizon, as a result of Canadian Natural's industry leading integrity program, the Company identified a portion of the piping to the amine unit that had reduced thickness and made the proactive decision to advance this maintenance in Q2/19, ahead of the planned fall turnaround. The Company was able to mitigate some of the production impact from the 16 day outage by bringing on curtailed production.
The Company has reviewed and optimized the scope of work for the planned Horizon fall turnaround and as a result, the turnaround is now targeted for 25 days starting in late Q3/19, a reduction of 3 days.
The Company continues to progress engineering work on the previously announced potential expansion opportunities at Horizon to increase reliability and lower costs, targeting to add production of 75,000 bbl/d to 95,000 bbl/d. The engineering and design specification work continued in the quarter and is targeted to be complete in Q3/19. The final investment decision on these opportunities will not be made until there is greater clarity on market access.
The potential Paraffinic Froth Treatment expansion at Horizon is targeting 40,000 bbl/d to 50,000 bbl/d of high quality diluted bitumen at significantly lower operating costs as the Company leverages its existing infrastructure. The preliminary estimate of the capital required is approximately $1.4 billion.
Stage 1 and 2 reliability opportunities at Horizon are targeted to add 35,000 bbl/d to 45,000 bbl/d of SCO.
Based on the impacts of the repairs and maintenance activities undertaken in the Company's Oil Sands Mining and Upgrading operations in Q2/19, the Company's annual 2019 Oil Sands Mining and Upgrading production guidance has been adjusted and is now targeted to range between 405,000 bbl/d - 415,000 bbl/d of SCO.
MARKETING
Three Months Ended
Six Months Ended
Jun 30 2019
Mar 31 2019
Jun 30 2018
Jun 30 2019
Jun 30 2018
Crude oil and NGLs pricing
WTI benchmark price (US$/bbl) (1)
$
59.83
$
54.90
$
67.90
$
57.38
$
65.41
WCS heavy differential as a percentage of WTI (%) (2)
18
%
23
%
28
%
20
%
33
%
SCO price (US$/bbl)
$
59.96
$
52.19
$
67.27
$
56.10
$
64.38
Condensate benchmark pricing (US$/bbl)
$
55.86
$
50.49
$
68.85
$
53.19
$
66.00
Average realized pricing before risk management (C$/bbl) (3)
$
63.45
$
53.98
$
61.14
$
59.05
$
52.32
Natural gas pricing
AECO benchmark price (C$/GJ)
$
1.11
$
1.84
$
0.97
$
1.47
$
1.36
Average realized pricing before risk management (C$/Mcf)
$
1.98
$
3.09
$
1.95
$
2.53
$
2.35
West Texas Intermediate (“WTI”).
Western Canadian Select (“WCS”).
Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities.
Q2/19 differentials between Western Canadian Select ("WCS") and WTI benchmark pricing narrowed from Q2/18 levels following the Government of Alberta's announcement of mandatory curtailments of crude oil production that came into effect January 1, 2019.
AECO natural gas prices decreased in Q2/19 from Q1/19 levels, primarily reflecting seasonal demand factors. AECO natural gas prices increased in Q2/19 from Q2/18 levels, primarily reflecting the easing of third party pipeline constraints to export markets.
The North West Redwater ("NWR") refinery, upon completion, targets to strengthen the Company’s position by providing a competitive return on investment and by creating incremental demand for approximately 80,000 bbl/d of heavy crude oil blends that will not require export pipelines, helping to reduce pricing volatility in all Western Canadian heavy crude oil.
The Company has a 50% interest in the NWR Partnership. For updates on the project, please refer to: https://nwrsturgeonrefinery.com/whats-happening/news/.
FINANCIAL REVIEW
The Company continues to implement proven strategies and its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural’s adjusted funds flow generation, credit facilities, US commercial paper program, access to capital markets, diverse asset base and related flexible capital expenditure programs all support a flexible financial position and provide the appropriate financial resources for the near-, mid- and long-term.
The Company’s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved production levels of 1,025,800 BOE/d in Q2/19, with approximately 97% of total production located in G7 countries.
Canadian Natural maintains a balance of products with Q2/19 production mix on a BOE/d basis of 51% light crude oil and SCO blends, 24% heavy crude oil blends and 25% natural gas.
Canadian Natural delivered strong quarterly free cash flow of $1,295 million after net capital expenditures of $908 million, and dividend requirements of $449 million, excluding the Devon acquisition that closed on June 27, 2019, reflecting the strength of our long life low decline asset base and our effective and efficient operations.
Balance sheet strength and strong financial performance was demonstrated in Q2/19 through the the repayment of C$500 million of 3.05% notes and reduction in long-term debt, excluding the Devon acquisition that closed on June 27, 2019.
In Q2/19, including the Devon acquisition, net long-term debt increased by $2,209 million to $23,109 million. Excluding financing related to the recently closed Devon acquisition, net long-term debt decreased by approximately $1,200 million from Q1/19 levels.
In June 2019, the Company successfully executed on its funding plan for the acquisition through a $3,250 million, 3 year term facility.
Canadian Natural maintains strong financial stability and liquidity represented by cash balances, and committed and demand bank credit facilities. At June 30, 2019 the Company had approximately $4,560 million of available liquidity, including cash and cash equivalents, an increase of approximately $330 million over Q1/19 levels.
Canadian Natural is committed to returns to shareholders, returning a total of $840 million in the quarter, $449 million by way of dividends and $391 million by way of share purchases. In the first half of 2019, the Company has returned a total of $1,484 million to shareholders, $852 million by way of dividends and $632 million by way of share purchases.
Share purchases for cancellation in the quarter totaled 10,450,000 common shares at a weighted average share price of $37.41.
Subsequent to quarter end, up to and including July 31, 2019, the Company executed on additional share purchases for cancellation of 2,300,000 common shares at a weighted average share price of $34.55.
Subsequent to quarter end, the Company declared a quarterly dividend of $0.375 per share, payable on October 1, 2019.
In 2018, the Board of Directors approved a more defined free cash flow allocation policy in accordance with the Company's four stated pillars. Under the policy, in 2019 the Company will target to allocate, on an annual basis, 50% of its residual free cash flow, after budgeted capital expenditures, dividends and large opportunistic acquisitions, to share purchases under its NCIB and the remaining 50% to reducing debt levels on the Company's balance sheet. This free cash flow policy will target a ratio of debt to adjusted 12 months trailing EBITDA of 1.5x, and an absolute debt level of $15.0 billion, at which time the policy will be reviewed by the Board. This policy was effective November 1, 2018.
As previously announced, the Company renewed its NCIB for the 12 month period commencing on May 23, 2019 and ending May 22, 2020.
In addition to the Company's strong adjusted funds flow, capital flexibility and access to debt capital markets, Canadian Natural has additional financial levers at its disposal to effectively manage its liquidity. As at June 30, 2019, these financial levers include the Company’s third party equity investments of $547 million, and cross currency swaps with a total value of $264 million.
Subsequent to quarter end, in July 2019, the Company filed base shelf prospectuses that allow for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada and US$3,000 million of debt securities in the United States, which expire August 2021, replacing the Company's previous base shelf prospectuses which would have expired in August 2019. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.
OUTLOOK
The Company targets annual 2019 production levels to average between 839,000 bbl/d and 888,000 bbl/d of crude oil and NGLs and between 1,485 MMcf/d and 1,545 MMcf/d of natural gas, before royalties. Q3/19 production guidance before royalties is targeted to average between 897,000 bbl/d and 939,000 bbl/d of crude oil and NGLs and between 1,440 MMcf/d and 1,460 MMcf/d of natural gas. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company’s website at www.cnrl.com.
Canadian Natural's annual 2019 capital expenditures are targeted to be approximately $3.8 billion.
ADVISORY
Special Note Regarding Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule”, “proposed” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses and other guidance provided throughout the Company's Management’s Discussion and Analysis (“MD&A”) of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the Jackfish Thermal Oil Sands Project, the timing and future operations of the North West Redwater bitumen upgrader and refinery, construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil (“SCO”) that the Company may be reliant upon to transport its products to market, and the development and deployment of technology and technological innovations also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.
In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company’s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company’s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company’s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company’s and its subsidiaries’ ability to secure adequate transportation for its products; unexpected disruptions or delays in the 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 in situ and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company’s bitumen products; availability and cost of financing; the Company’s and its subsidiaries’ success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); asset retirement obligations; the adequacy of the Company’s provision for taxes; and other circumstances affecting revenues and expenses.
The Company’s operations have been, and in the future may be, affected by political developments and by national, federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in the Company's MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company’s estimates or opinions change.
Special Note Regarding Non-GAAP and other Financial Measures
This press release includes references to financial measures commonly used in the crude oil and natural gas industry, such as: adjusted net earnings from operations; adjusted funds flow (previously referred to as funds flow from operations); net capital expenditures; free cash flow; debt to adjusted EBITDA; debt to cash flow; available liquidity. These financial measures are not defined by International Financial Reporting Standards ("IFRS") and therefore are referred to as non-GAAP measures and other financial measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, cash flows from operating activities, cash flows used in investing activities, and cash flows used in financing activities as determined in accordance with IFRS, as an indication of the Company's performance.
Adjusted net earnings (loss) from operations is a non-GAAP measure that represents net earnings (loss) as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for the after-tax effects of certain items of a non- operational nature. The Company considers adjusted net earnings (loss) from operations a key measure in evaluating its performance, as it demonstrates the Company's ability to generate after-tax operating earnings from its core business areas. The reconciliation “Adjusted Net Earnings (Loss) from Operations, as Reconciled to Net Earnings (Loss)" is presented in the Company’s MD&A.
Adjusted funds flow (previously referred to as funds flow from operations) is a non-GAAP measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment expenditures and movements in other long-term assets, including the unamortized cost of the share bonus program and prepaid cost of service tolls. The Company considers adjusted funds flow a key measure as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities” is presented in the Company’s MD&A.
Net capital expenditures is a non-GAAP measure that represents cash flows used in investing activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, investment in other long-term assets, share consideration in business acquisitions and abandonment expenditures. The Company considers net capital expenditures a key measure as it provides an understanding of the Company’s capital spending activities in comparison to the Company's annual capital budget. The reconciliation “Net Capital Expenditures, as Reconciled to Cash Flows used in Investing Activities” is presented in the Net Capital Expenditures section of the Company’s MD&A.
Free cash flow is a non-GAAP measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital from operating activities, abandonment, certain movements in other long-term assets, less net capital expenditures and dividends on common shares. The Company considers free cash flow a key measure in demonstrating the Company’s ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders, and to repay debt.
Adjusted EBITDA is a non-GAAP measure that represents net earnings (loss) as presented in the Company's consolidated Statements of Earnings (Loss), adjusted for interest, taxes, depletion, depreciation and amortization, stock based compensation expense (recovery), unrealized risk management gains (losses), unrealized foreign exchange gains (losses), and accretion of the Company’s asset retirement obligation. The Company considers adjusted EBITDA a key measure in evaluating its operating profitability by excluding non-cash items.
Debt to Adjusted EBITDA is a non-GAAP measure that is derived as the current and long-term portions of long-term debt, divided by the 12 month trailing Adjusted EBITDA, as defined above. The Company considers this ratio to be a key measure in evaluating the Company's ability to pay off its debt.
Debt to cash flow 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 funds flow, as defined above. The Company considers this ratio to be a key measure in evaluating the Company's ability to pay off its debt.
Available liquidity is a non-GAAP measure that is derived as cash and cash equivalents, total bank and term credit facilities, less amounts drawn on the bank and credit facilities including under the commercial paper program. The Company considers available liquidity a key measure in evaluating the sustainability of the Company’s operations and ability to fund future growth. See note 8 - Long-term Debt in the Company’s consolidated financial statements.
Special Note Regarding Currency, Financial Information and Production
The Company's MD&A should be read in conjunction with the unaudited interim consolidated financial statements for the three and six months ended June 30, 2019 and the MD&A and the audited consolidated financial statements of the Company for the year ended December 31, 2018.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company’s unaudited interim consolidated financial statements for the three and six months ended June 30, 2019 and the Company's MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board ("IASB"). Changes in the Company's accounting policies in accordance with IFRS, including the adoption of IFRS 16 "Leases" on January 1, 2019, are discussed in the "Changes in Accounting Policies" section of the Company's MD&A. In accordance with the new "Leases" standard, comparative period balances in 2018 reported in the Company's MD&A have not been restated.
Production volumes and per unit statistics are presented throughout the Company's MD&A on a “before royalties” or “company gross” basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of the Company's MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an “after royalties” or “company net” basis is also presented for information purposes only.
Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2018, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. Detailed guidance on production levels, capital expenditures and production expenses can be found on the Company's website at www.cnrl.com.
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, August 1, 2019.
The North American conference call number is 1-866-521-4909 and the outside North American conference call number is 001-647-427-2311. Please call in 10 minutes prior to the call starting time.
An archive of the broadcast will be available until 6:00 p.m. Mountain Time, Thursday, August 15, 2019. To access the rebroadcast in North America, dial 1-800-585-8367. Those outside of North America, dial 001-416-621-4642. The conference archive ID number is 4282479.
The conference call will also be webcast live and can be accessed on the home page of our website at www.cnrl.com.
Canadian Natural is a senior oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.
CANADIAN NATURAL RESOURCES LIMITED
2100, 855 - 2nd Street S.W. Calgary, Alberta, T2P4J8
Phone: 403-514-7777 Email: ir@cnrl.com
www.cnrl.com
STEVE W. LAUT
Executive Vice-Chairman
TIM S. MCKAY
President
MARK A. STAINTHORPE
Chief Financial Officer and Senior Vice-President, Finance
Trading Symbol - CNQ
Toronto Stock Exchange
New York Stock Exchange
Source: GlobeNewswire
(August 1, 2019 - 5:00 AM EDT)
