Calgary, Alberta – Commenting on the Company’s first quarter 2021 results, Tim McKay, President of Canadian Natural stated “The COVID-19 pandemic continues to challenge our everyday living and the way we operate our businesses. With our strong measures in place we have minimized impacts on our operations, but it remains a daily challenge for our field staff to do it safe and do it right. As the global vaccine distribution increases and crude oil demand recovers, especially in the United States, we are seeing improved commodity pricing, and when combined with our top tier execution and disciplined capital program we are well positioned to generate significant free cash flow in 2021.
Our first quarter results were strong as we achieved record quarterly production of approximately 1,246 MBOE/d and record quarterly liquids production of over 979,000 bbl/d, as a result of our effective and efficient operations and high operating levels. As our large and diverse asset base realized strong netbacks, we drove significant adjusted funds flow in the quarter of over $2.7 billion.
In Q1/21 our Oil Sands Mining and Upgrading segment continued to achieve strong operating results with record quarterly production of approximately 468,800 bbl/d of high value Synthetic Crude Oil (“SCO”) and industry leading operating costs of $19.82/bbl (US$15.66/bbl), a decrease of 5% from Q1/20 levels, despite increased energy costs.”
Canadian Natural’s Chief Financial Officer, Mark Stainthorpe, added “Canadian Natural is in a strong financial position. Our robust business model delivered strong financial results with net earnings of approximately $1.4 billion and adjusted net earnings of over $1.2 billion in the first quarter.
Our top tier operating results generated strong quarterly free cash flow of approximately $1.4 billion after capital expenditures and dividends. Accordingly our balance sheet strengthened significantly in Q1/21, as we were able to reduce our net long-term debt by approximately $1.4 billion in Q1/21. Our first quarter debt reduction included the permanent repayment and cancellation of term debt totaling approximately $1.0 billion. Subsequent to quarter end we permanently repaid and cancelled approximately $0.7 billion of additional term debt.
Annual 2021 WTI strip pricing has strengthened and using approximately US$60/bbl our targeted free cash flow increases significantly to $5.7 billion to $6.2 billion, after our budgeted capital program of approximately $3.2 billion and dividends of approximately $2.2 billion. As a result our balance sheet is targeted to further strengthen throughout 2021, with debt to adjusted EBITDA targeted to improve to approximately 1.1x and debt to book capitalization targeted to improve to approximately 29%, at the mid-point of our targeted free cash flow range.”
QUARTERLY HIGHLIGHTS
Three Months Ended | |||||||||||
($ millions, except per common share amounts) | Mar 31 2021 |
Dec 31 2020 |
Mar 31 2020 |
||||||||
Net earnings (loss) | $ | 1,377 | $ | 749 | $ | (1,282 | ) | ||||
Per common share | – basic | $ | 1.16 | $ | 0.63 | $ | (1.08 | ) | |||
– diluted | $ | 1.16 | $ | 0.63 | $ | (1.08 | ) | ||||
Adjusted net earnings (loss) from operations (1) | $ | 1,219 | $ | 176 | $ | (295 | ) | ||||
Per common share | – basic | $ | 1.03 | $ | 0.15 | $ | (0.25 | ) | |||
– diluted | $ | 1.03 | $ | 0.15 | $ | (0.25 | ) | ||||
Cash flows from operating activities | $ | 2,536 | $ | 1,270 | $ | 1,725 | |||||
Adjusted funds flow (2) | $ | 2,712 | $ | 1,708 | $ | 1,337 | |||||
Per common share | – basic | $ | 2.29 | $ | 1.45 | $ | 1.13 | ||||
– diluted | $ | 2.28 | $ | 1.44 | $ | 1.13 | |||||
Cash flows used in investing activities | $ | 648 | $ | 624 | $ | 859 | |||||
Net capital expenditures, excluding net acquisition costs (3) | $ | 808 | $ | 655 | $ | 838 | |||||
Net capital expenditures, including net acquisition costs (3) | $ | 808 | $ | 1,176 | $ | 838 | |||||
Daily production, before royalties | |||||||||||
Natural gas (MMcf/d) | 1,598 | 1,644 | 1,440 | ||||||||
Crude oil and NGLs (bbl/d) | 979,352 | 927,190 | 938,676 | ||||||||
Equivalent production (BOE/d) (4) | 1,245,703 | 1,201,198 | 1,178,752 |
(1) Adjusted net earnings (loss) from operations is a non-GAAP measure the Company utilizes to evaluate its performance, as it demonstrates the Company’s ability to generate after-tax operating earnings from its core business areas. The derivation of this measure is discussed in the “Advisory” section of this press release.
(2) Adjusted funds flow is a non-GAAP measure the Company considers key to evaluate its performance as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The derivation of this measure is discussed in the “Advisory” section of this press release.
(3) Net capital expenditures is a non-GAAP measure the Company considers a key measure as it provides an understanding of the Company’s capital spending activities in comparison to the Company’s annual capital budget. For additional information and details, refer to the net capital expenditures table in the “Advisory” section of this press release.
(4) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
QUARTERLY HIGHLIGHTS
- Net earnings of $1,377 million and adjusted net earnings from operations of $1,219 million were realized in Q1/21.
- Adjusted net earnings increased by $1,043 million from Q4/20 levels as a result of higher realized pricing and effective and efficient operations.
- Cash flows from operating activities were $2,536 million in Q1/21.
- The strength of the Company’s assets supported by its safe, effective and efficient operations demonstrated its ability to generate significant and sustainable free cash flow over the long-term, making Canadian Natural’s business unique, robust and sustainable.
- As a result, Canadian Natural generated strong quarterly adjusted funds flow of $2,712 million in Q1/21, increases of $1,375 million and $1,004 million from Q1/20 and Q4/20 levels respectively, driven by higher realized pricing and effective and efficient operations.
- Canadian Natural generated robust quarterly free cash flow of $1,401 million in Q1/21, after net capital expenditures of $808 million and dividend payments of $503 million, reflecting the strength of the Company’s effective and efficient operations and its high quality, long life low decline asset base.
- The Company’s 2021 budgeted capital expenditure program of approximately $3.2 billion provides a targeted production range of 1,190 MBOE/d to 1,260 MBOE/d, an increase of 5% at the mid-point from 2020 levels.
- Canadian Natural demonstrated our focus on further strengthening our balance sheet with strong financial results in Q1/21, reducing net debt by approximately $1.4 billion from Q4/20 levels. Since Q2/20 net debt has decreased by approximately $2.9 billion.
- In Q1/21 the Company repaid $962.5 million on its $3,088 million non-revolving term loan, more than satisfying the required annual amortization of $162.5 million due in June 2021. Subsequent to quarter end, an additional $650 million was repaid on this facility, reducing the outstanding balance to $1,475 million.
- In Q1/21 the Company’s $1,000 million non-revolving term credit facility, originally due February 2022, was extended to February 2023.
- In March 2021, the Company declared a quarterly dividend of $0.47 per share, an increase of 11% from the previous level of $0.425 per share, marking 2021 as the Company’s 21st consecutive year of dividend increases, reflecting the Board of Directors’ confidence in Canadian Natural’s strength and the robustness of the Company’s assets and its ability to generate significant and sustainable free cash flow.
- Subsequent to quarter end the Company declared a quarterly dividend of $0.47 per share, payable on July 5, 2021.
- In March 2021, the Board of Directors authorized management to repurchase shares under a Normal Course Issuer Bid (“NCIB”) to approximately offset options exercised throughout the coming year, in order to minimize or eliminate dilution to shareholders.
- Share repurchases for cancellation in Q1/21 totaled 600,000 common shares at a weighted average price of $38.61.
- Subsequent to quarter end, up to and including May 5, 2021, the Company executed on additional share repurchases for cancellation of 960,000 common shares at a weighted average share price of $38.15.
- Returns to shareholders have been significant as Canadian Natural has returned approximately $1.1 billion by way of dividends and share repurchases in 2021 up to and including May 5, 2021.
- In Q1/21 the Company achieved record quarterly production volumes of 1,245,703 BOE/d, increases of 6% and 4% from Q1/20 and Q4/20 levels respectively, with continued focus on safe, effective and efficient operations.
- Record quarterly liquids production was achieved in Q1/21 averaging 979,352 bbl/d, increases of 4% and 6% from Q1/20 and Q4/20 levels respectively.
- Corporate natural gas production averaged 1,598 MMcf/d in Q1/21, an increase of 11% from Q1/20 levels. The increase from Q1/20 was primarily as a result of acquired production in Q4/20, strong base production and volume additions, partially offset by natural field declines and the shutdown of our Pine River gas plant in February 2021.
- Corporate natural gas operating costs in Q1/21 averaged $1.27/Mcf, a decrease of 3% from Q1/20 levels and an increase of 15% from Q4/20 levels. The increase from Q4/20 was primarily due to normal seasonality including an increase in electricity costs, partially offset by the impact of the continuous focus on operating costs.
- The Company’s world class Oil Sands Mining and Upgrading assets achieved record quarterly production averaging 468,803 bbl/d of SCO in Q1/21, increases of 7% and 12% from Q1/20 and Q4/20 levels respectively. Record SCO production was primarily as a result of industry leading utilization and operational enhancements.
- Operating costs from the Company’s Oil Sands Mining and Upgrading assets are top tier, averaging $19.82/bbl (US$15.66/bbl) of SCO in Q1/21, decreases of 5% and 2% from Q1/20 and Q4/20 levels respectively. The reductions were primarily due to our focus on continuous improvement, effective and efficient operations and operational enhancements, offsetting the impact of higher energy costs, including natural gas, in Q1/21.
- In Q1/21 the Company increased SCO sales from the Oil Sands Mining and Upgrading segment by over 41,000 bbl/d from Q1/20 levels while essentially maintaining absolute operating cost levels, excluding natural gas costs, over the same period, demonstrating the continued focus on effective and efficient operations and the underlying value of high utilization relative to fixed costs.
- Subsequent to quarter end the planned turnaround at Horizon was successfully completed and SCO production is targeted to resume on May 8, 2021. Additionally, at the Athabasca Oil Sands Project (“AOSP”) the Company targets to perform planned de-coking in May 2021. The Company’s annual 2021 budgeted total production volume range remains unchanged.
- Operating costs from the Company’s Oil Sands Mining and Upgrading assets are top tier, averaging $19.82/bbl (US$15.66/bbl) of SCO in Q1/21, decreases of 5% and 2% from Q1/20 and Q4/20 levels respectively. The reductions were primarily due to our focus on continuous improvement, effective and efficient operations and operational enhancements, offsetting the impact of higher energy costs, including natural gas, in Q1/21.
- Canadian Natural’s North America E&P liquids production, including thermal in situ, was strong in Q1/21 averaging 478,736 bbl/d, an increase of 5% from Q1/20 levels and comparable with Q4/20 levels.
- North American E&P liquids, including thermal in situ operations, achieved operating costs of $12.80/bbl (US$10.11/bbl) in Q1/21, comparable with Q1/20 levels of $12.69/bbl and an increase of 18% from Q4/20 levels of $10.81/bbl. The increase in operating costs from Q4/20 levels was primarily due to higher energy costs with the remainder from normal seasonality costs.
- Canadian Natural’s thermal in situ production was strong in Q1/21, averaging 267,530 bbl/d, an increase of 17% over Q1/20 levels and comparable with Q4/20 levels.
- Strong operating costs from the Company’s thermal in situ assets were achieved in Q1/21, averaging $11.40/bbl (US$9.01/bbl) an increase of 3% from Q1/20 levels. The increase in operating costs was primarily due to increases in energy costs, partially offset by cost reductions as a result of higher production volumes and effective and efficient operations.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural’s production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and Synthetic Crude Oil (“SCO”) (herein collectively referred to as “crude oil”) and 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, representing approximately 81% of the Company’s total liquids production in Q1/21, the majority of which is zero decline high value SCO production from the Company’s world class Oil Sands Mining and Upgrading assets. The remaining balance of long life low decline production comes from Canadian Natural’s top tier thermal in situ oil sands operations and the Company’s 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.
In addition, 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, in the right economic conditions, provide excellent returns and maximize value for shareholders. Supporting these projects is the Company’s undeveloped land base which enables large, repeatable drilling programs that can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control major components of the Company’s operating costs and minimize production commitments. Low capital exposure projects can be quickly stopped or started depending upon success, market conditions or corporate needs.
Canadian Natural’s balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.
Drilling Activity | Three Months Ended Mar 31 | |||||||||||
2021 | 2020 | |||||||||||
(number of wells) | Gross | Net | Gross | Net | ||||||||
Crude oil | 46 | 44 | 37 | 35 | ||||||||
Natural gas | 27 | 22 | 12 | 11 | ||||||||
Dry | – | – | – | – | ||||||||
Subtotal | 73 | 66 | 49 | 46 | ||||||||
Stratigraphic test / service wells | 395 | 328 | 420 | 367 | ||||||||
Total | 468 | 394 | 469 | 413 | ||||||||
Success rate (excluding stratigraphic test / service wells) | 100% | 100% |
- The Company’s total crude oil and natural gas drilling program of 66 net wells for the three months ended March 31, 2021, excluding stratigraphic/service wells, represents an increase of 20 net wells from the same period in 2020.
North America Exploration and Production
Crude oil and NGLs – excluding Thermal In Situ Oil Sands | |||||||||
Three Months Ended | |||||||||
Mar 31 2021 | Dec 31 2020 | Mar 31 2020 | |||||||
Crude oil and NGLs production (bbl/d) | 211,206 | 209,710 | 228,574 | ||||||
Net wells targeting crude oil | 39 | 5 | 28 | ||||||
Net successful wells drilled | 39 | 5 | 28 | ||||||
Success rate | 100% | 100% | 100% |
- Canadian Natural’s North America E&P crude oil and NGL production volumes, excluding thermal in situ operations, averaged 211,206 bbl/d in Q1/21, a decrease of 8% from Q1/20 levels and comparable with Q4/20 levels. The decrease from Q1/20 was primarily due to natural field declines and deferred 2020 drilling activity.
- Primary heavy crude oil production averaged 62,695 bbl/d in Q1/21, decreases of 24% and 4% from Q1/20 and Q4/20 levels respectively, primarily due to natural field declines.
- Operating costs in the Company’s primary heavy crude oil operations averaged $18.89/bbl (US$14.92/bbl) in Q1/21, comparable with Q1/20 levels, strong results given the decrease in production volumes and increase in energy costs.
- As a part of the 2021 budget, 13 net slant wells and 14 net horizontal multilateral wells were drilled in Q1/21 as planned.
- The majority of these wells are in the early stages of ramping up or target to come on production in Q2/21 as budgeted. Early highlights from the Q1/21 drilling include 5 net Clearwater horizontal multilateral wells at Smith, that are now on-stream. Production from these wells has been strong totaling approximately 2,700 bbl/d, above budgeted rates by approximately 900 bbl/d, with low capital efficiencies of approximately $3,400 per flowing BOE.
- Pelican Lake production was strong in Q1/21 averaging 55,498 bbl/d, comparable with prior periods, demonstrating the strength of this long life low decline asset and the continued success of the Company’s world class polymer flood.
-
- The Company continues to focus on safe, effective and efficient operations, realizing strong operating costs in Q1/21 at Pelican Lake, averaging $7.38/bbl (US$5.83/bbl), an increase of 19% from Q1/20 primarily due to increases in energy costs.
- North American light crude oil and NGL production averaged 93,013 bbl/d in Q1/21, increases of 5% and 6% from Q1/20 and Q4/20 levels respectively. The increases are primarily as a result of strong results from drilling completed in Q4/20 and Q1/21.
- Operating costs in the Company’s North America light crude oil and NGL areas averaged $16.07/bbl (US$12.70/bbl) in Q1/21, comparable with Q1/20 levels, as a result of effective and efficient operations.
- The Company continues to advance its high value Montney light crude oil development plan at Wembley, where 5 net wells have been drilled to date from the budgeted 18 net wells targeted to be on stream in 2021. Construction on the new crude oil battery is proceeding on time and on budget and is targeted to be on-stream in October 2021.
- With the crude oil battery in place the new wells are targeted to be brought on stream at strong capital efficiencies of approximately $9,400 per flowing BOE. This project is targeting to exit 2021 at total production rates of approximately 8,500 bbl/d of liquids and 28 MMcf/d.
- Primary heavy crude oil production averaged 62,695 bbl/d in Q1/21, decreases of 24% and 4% from Q1/20 and Q4/20 levels respectively, primarily due to natural field declines.
Thermal In Situ Oil Sands | |||||||||
Three Months Ended | |||||||||
Mar 31 2021 |
Dec 31 2020 |
Mar 31 2020 |
|||||||
Bitumen production (bbl/d) | 267,530 | 266,179 | 228,303 | ||||||
Net wells targeting bitumen | 3 | – | 6 | ||||||
Net successful wells drilled | 3 | – | 6 | ||||||
Success rate | 100% | – | 100% |
- Canadian Natural’s thermal in situ production was strong in Q1/21, averaging 267,530 bbl/d, an increase of 17% over Q1/20 levels and comparable with Q4/20 levels.
- Strong operating costs for the Company’s thermal in situ assets were achieved in Q1/21, averaging $11.40/bbl (US$9.01/bbl) an increase of 3% from Q1/20 levels. The increase in operating costs was primarily due to increases in energy costs, partially offset by cost reductions as a result of higher production volumes and effective and efficient operations.
- Solvent enhanced oil recovery technology targets to increase bitumen production, reduce Steam to Oil Ratio (“SOR”), reduce Green House Gas (“GHG”) intensity and have high solvent recovery. This technology has the potential for application throughout the Company’s extensive thermal in situ asset base.
- At Kirby South, results from our on-going two year pilot of this technology indicate a significant SOR and GHG intensity reduction of approximately 45%, within the targeted range, can be achieved with the process. Monitoring of solvent recovery will continue for the remainder of 2021 to conclude the pilot results.
- At Primrose, in the steam flood area, a solvent injection pilot is targeted to commence in Q4/21. This second pilot will consist of 9 wells (5 producers and 4 injectors) and similar to the first pilot at Kirby South, is targeted to operate for a two year period.
North America Natural Gas | |||||||||
Three Months Ended | |||||||||
Mar 31 2021 |
Dec 31 2020 |
Mar 31 2020 |
|||||||
Natural gas production (MMcf/d) | 1,585 | 1,623 | 1,407 | ||||||
Net wells targeting natural gas | 22 | 9 | 11 | ||||||
Net successful wells drilled | 22 | 9 | 11 | ||||||
Success rate | 100% | 100% | 100% |
- North America natural gas production was strong in Q1/21 averaging 1,585 MMcf/d, an increase of 13% from Q1/20 levels. The increase from Q1/20 was primarily as a result of acquired production in Q4/20, strong base production and volume additions, partially offset by natural field declines and the shutdown of our Pine River gas plant in February 2021.
- North America natural gas operating costs in Q1/21 averaged $1.24/Mcf, comparable with Q1/20 levels and an increase of 16% from Q4/20 levels. The increase from Q4/20 was primarily due to normal seasonality including an increase in electricity costs, partially offset by the impact of the continuous focus on operating costs.
- As part of the 2021 budget, in the liquids rich Montney, the Company targets to utilize facility capacity through its drill to fill strategy adding low cost, high value liquids rich natural gas volumes.
- At Septimus, production was strong in Q1/21, essentially at facility capacity of 150 MMcf/d and 9,000 bbl/d of liquids.
- A 5 net well pad is being drilled at Septimus, with a targeted on stream date in June 2021 and low capital efficiency of approximately $5,000 per flowing BOE. These wells target to keep the capacity full for the remainder of 2021.
- Operating costs at Septimus remained strong in Q1/21, averaging $0.28/Mcfe, a decrease of 7% from Q1/20 levels.
- At Townsend, Q1/21 production was approximately 255 MMcf/d and 5,500 bbl/d of liquids, above 2021 budget by 17 MMcf/d and 340 bbl/d of liquids.
- Completions on a 6 well pad at Townsend are progressing, with total targeted rates of approximately 44 MMcf/d, targeted to come on stream in June 2021 with a strong capital efficiency of approximately $4,200 per flowing BOE.
- Townsend remains on target to exit 2021 at a production rate of approximately 340 MMcf/d.
- At Septimus, production was strong in Q1/21, essentially at facility capacity of 150 MMcf/d and 9,000 bbl/d of liquids.
International Exploration and Production
Three Months Ended | |||||||||
Mar 31 2021 |
Dec 31 2020 |
Mar 31 2020 |
|||||||
Crude oil production (bbl/d) | |||||||||
North Sea | 19,959 | 17,057 | 27,755 | ||||||
Offshore Africa | 11,854 | 17,155 | 15,943 | ||||||
Natural gas production (MMcf/d) | |||||||||
North Sea | 4 | 4 | 23 | ||||||
Offshore Africa | 9 | 17 | 10 | ||||||
Net wells targeting crude oil | 2.0 | – | 1.0 | ||||||
Net successful wells drilled | 2.0 | – | 1.0 | ||||||
Success rate | 100% | – | 100% |
- International E&P crude oil production volumes averaged 31,813 bbl/d in Q1/21, decreases of 27% and 7% from Q1/20 and Q4/20 levels respectively.
- In Q2/21 and Q3/21 the Company is planning turnarounds at two platforms in the North Sea and at one field in Offshore Africa. Targeted production impacts were included in the Company’s annual 2021 budgeted production volume range.
- In the North Sea, crude oil production volumes averaged 19,959 bbl/d in Q1/21, a decrease of 28% from Q1/20 levels and an increase of 17% from Q4/20 levels. The decrease in production from Q1/20 was primarily a result of the permanent cessation of production from the Banff and Kyle fields and natural field declines. The increase in production from Q4/20 primarily reflects the impact of planned turnaround activity during Q4/20, partially offset by natural field declines.
- Crude oil operating costs in the North Sea averaged $42.24/bbl (US$33.37/bbl) in Q1/21, an increase of 42% from Q1/20 levels primarily due to lower volumes on a relatively fixed cost base and higher energy costs. Targeted operating costs remain in line with 2020 annual levels.
- Offshore Africa crude oil production volumes averaged 11,854 bbl/d in Q1/21, decreases of 26% and 31% from Q1/20 and Q4/20 levels respectively. The decreases were primarily due to a planned turnaround at Baobab and an unplanned outage at Espoir in Q1/21.
- Offshore Africa crude oil operating costs averaged $16.57/bbl (US$13.09/bbl) in Q1/21, an increase of 39% from Q1/20 levels, primarily due to the timing of liftings from various fields that have different cost structures and lower volumes on a relatively fixed cost base. Targeted operating costs remain in line with 2020 annual levels.
North America Oil Sands Mining and Upgrading
Three Months Ended | |||||||||
Mar 31 2021 |
Dec 31 2020 |
Mar 31 2020 |
|||||||
Synthetic crude oil production (bbl/d) (1) (2) | 468,803 | 417,089 | 438,101 |
(1) SCO production before royalties and excludes volumes consumed internally as diesel.
(2) Consists of heavy and light synthetic crude oil products.
- The Company’s world class Oil Sands Mining and Upgrading assets achieved record quarterly production averaging 468,803 bbl/d of SCO in Q1/21, increases of 7% and 12% from Q1/20 and Q4/20 levels respectively. Record SCO production was primarily as a result of industry leading utilization and operational enhancements.
- Operating costs from the Company’s Oil Sands Mining and Upgrading assets are top tier, averaging $19.82/bbl (US$15.66/bbl) of SCO in Q1/21, decreases of 5% and 2% from Q1/20 and Q4/20 levels respectively. The reductions were primarily due to our focus on continuous improvement, effective and efficient operations and operational enhancements, offsetting the impact of higher energy costs, including natural gas, in Q1/21.
- In Q1/21 the Company increased SCO sales from the Oil Sands Mining and Upgrading segment by over 41,000 bbl/d from Q1/20 levels while essentially maintaining absolute operating cost levels, excluding natural gas costs, over the same period, demonstrating the continued focus on effective and efficient operations and the underlying value of high utilization relative to fixed costs.
- Subsequent to quarter end the planned turnaround at Horizon was successfully completed and SCO production is targeted to resume on May 8, 2021. Additionally, at the Athabasca Oil Sands Project (“AOSP”) the Company targets to perform planned de-coking in May 2021. The Company’s annual 2021 budgeted total production volume range remains unchanged.
- Operating costs from the Company’s Oil Sands Mining and Upgrading assets are top tier, averaging $19.82/bbl (US$15.66/bbl) of SCO in Q1/21, decreases of 5% and 2% from Q1/20 and Q4/20 levels respectively. The reductions were primarily due to our focus on continuous improvement, effective and efficient operations and operational enhancements, offsetting the impact of higher energy costs, including natural gas, in Q1/21.
MARKETING
Three Months Ended | ||||||||||
Mar 31 2021 |
Dec 31 2020 |
Mar 31 2020 |
||||||||
Crude oil and NGLs pricing | ||||||||||
WTI benchmark price (US$/bbl) (1) | $ | 57.80 | $ | 42.67 | $ | 46.08 | ||||
WCS heavy differential as a percentage of | ||||||||||
WTI (%) (2) | 21% | 22% | 44% | |||||||
SCO price (US$/bbl) | $ | 54.30 | $ | 39.69 | $ | 43.39 | ||||
Condensate benchmark pricing (US$/bbl) | $ | 57.99 | $ | 42.54 | $ | 45.54 | ||||
Average realized pricing before risk management (C$/bbl) (3) | $ | 52.68 | $ | 40.56 | $ | 25.90 | ||||
Natural gas pricing | ||||||||||
AECO benchmark price (C$/GJ) | $ | 2.77 | $ | 2.62 | $ | 2.03 | ||||
Average realized pricing before risk management (C$/Mcf) | $ | 3.42 | $ | 2.94 | $ | 2.22 |
(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.
- Crude oil prices continues to improve with WTI averaging US$57.80/bbl in Q1/21, an increase of 25% from Q1/20 levels. The increase in WTI from comparable periods primarily reflected increased demand as a result of the positive impact of the global roll out of COVID-19 vaccinations on economic activity, the continuation of agreements by OPEC+ to maintain production cuts implemented in 2020 and the strengthening of the global economy.
- As at May 5, 2021 for crude oil, annual WTI pricing of US$62.50/bbl is currently 59% higher than 2020 levels and the annual WCS heavy oil differential has improved significantly from 2020, currently at approximately 21%, in line with average historical levels.
- Natural gas prices continue to improve with AECO averaging $2.77/GJ in Q1/21, an increase of 36% from Q1/20 levels. The increase in natural gas prices from the comparable period primarily reflected increased intra-provincial and export demand.
- Market egress is targeted to improve in the short- and mid-term as construction is progressing on the Trans Mountain Expansion (“TMX”) and the Enbridge Line 3 replacement.
- Enbridge Line 3 is targeted to be on stream in Q4/21.
- Canadian Natural is committed to approximately 10,000 bbl/d of the targeted 50,000 bbl/d base Keystone export pipeline optimization expansion, which is targeted to be on-stream in the latter half of 2021.
- TMX construction is on track for a targeted on stream date in early 2023, on which Canadian Natural has 94,000 bbl/d committed capacity.
- The North West Redwater (“NWR”) Refinery with targeted processing capacity of approximately 80,000 bbl/d of diluted bitumen, which improves heavy oil demand in western Canada, effectively increasing egress out of the WCSB. For more details, please contact the North West Redwater Partnership.
FINANCIAL REVIEW
The Company continues to implement proven strategies including its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural’s adjusted funds flow generation, credit facilities, US commercial paper program, access to capital markets, diverse asset base and related flexible capital expenditure program, all support a flexible financial position and provide the appropriate financial resources for the near-, mid- and long-term.
- The Company’s strategy to maintain a diverse portfolio, balanced across various commodity types, achieved record quarterly production of 1,245,703 BOE/d in Q1/21, with approximately 99% of total production located in G7 countries.
- Canadian Natural generated robust free cash flow of $1,401 million in Q1/21, after net capital expenditures of $808 million and dividend payments of $503 million in the quarter, reflecting the strength of the Company’s effective and efficient operations and its high quality, long life low decline asset base.
- Canadian Natural demonstrated our focus on further strengthening of the balance sheet with its strong financial results in Q1/21, reducing net debt by $1,426 million, from Q4/20 levels. Since Q2/20 levels net debt has been decreased by $2,944 million.
- In Q1/21 the Company repaid $962.5 million on its $3,088 million non-revolving term loan, more than satisfying the required annual amortization of $162.5 million originally due in June 2021. Subsequent to quarter end, an additional $650 million was repaid on this facility, reducing the outstanding balance to $1,475 million.
- In Q1/21 the Company’s $1,000 million non-revolving term credit facility, originally due February 2022, was extended to February 2023.
- As at March 31, 2021, the Company had undrawn revolving bank credit facilities of approximately $5.0 billion. Including cash and cash equivalents and short-term investments, the Company had significant liquidity of approximately $5.5 billion. At March 31, 2021, the Company had approximately $0.1 billion drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
- In March 2021, the Company declared a quarterly dividend of $0.47 per share, an increase of 11% from the previous level of $0.425 per share, marking 2021 as the Company’s 21st consecutive year of dividend increases, reflecting the Board of Directors’ confidence in Canadian Natural’s strength and the robustness of the Company’s assets and its ability to generate significant and sustainable free cash flow.
- Subsequent to quarter end the Company declared a quarterly dividend of $0.47 per share, payable on July 5, 2021.
- In March 2021, the Board of Directors authorized management to repurchase shares under a NCIB to approximately offset options exercised throughout the coming year, in order to minimize or eliminate dilution to shareholders.
- Share repurchases for cancellation in Q1/21 totaled 600,000 common shares at a weighted average price of $38.61.
- Subsequent to quarter end, up to and including May 5, 2021, the Company executed on additional share repurchases for cancellation of 960,000 common shares at a weighted average share price of $38.15.
- Canadian Natural demonstrated our focus on further strengthening of the balance sheet with its strong financial results in Q1/21, reducing net debt by $1,426 million, from Q4/20 levels. Since Q2/20 levels net debt has been decreased by $2,944 million.
- Returns to shareholders have been significant as Canadian Natural has returned approximately $1.1 billion by way of dividends and share repurchases in 2021 up to and including May 5, 2021.
- The strength of the Company’s assets supported by its safe effective and efficient operations demonstrated its ability to generate significant and sustainable free cash flow over the long-term, making Canadian Natural’s business unique, robust and sustainable.
- 2021 free cash flow is targeted to be robust at $5.7 billion to $6.2 billion using approximately US$60/bbl WTI, after budgeted capital expenditures and dividends.
- The Company’s 2021 budgeted capital expenditure program of approximately $3.2 billion, provides a targeted production range of 1,190 MBOE/d to 1,260 MBOE/d, an increase of 5% at the mid-point from 2020 levels.
- Corporate annual natural gas production is targeted to range between 1,620 MMcf/d to 1,680 MMcf/d in 2021, representing significant growth of over 170 MMcf/d at the mid-point from 2020 levels.
- Corporate annual liquids production is targeted to be strong in 2021 ranging from 920,000 bbl/d to 980,000 bbl/d, an increase of approximately 32,000 bbl/d at the mid-point from 2020 levels.
- Free cash flow is targeted to be allocated to the balance sheet in the near term resulting in targeted 2021 year ended debt to book capitalization and debt to adjusted EBITDA of approximately 29% and 1.1x respectively, at the mid-point of targeted free cash flow range.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE (“ESG”) HIGHLIGHTS
Canada and Canadian Natural are well positioned to deliver responsibly produced energy that the world needs through leading ESG performance. Canadian Natural’s culture of continuous improvement provides a significant advantage and results in continued improvement in the Company’s environmental performance.
- The Government of Canada’s announcement on April 19, 2021 of its 2021 budget recognized the important role of carbon capture, utilization and storage projects for the oil sands sector to continue contributing to Canada’s economic growth while working towards climate objectives. As a leader in Carbon, Capture, Utilization and Storage (“CCUS”), Canadian Natural sees many opportunities for industry to advance investments in CCUS projects. Details of the proposed government program are important and the Company looks forward to working together with government through the upcoming consultation period.
- Additionally on April 22, 2021, the Government of Canada announced new targets to reduce GHG emissions by 40% to 45% below 2005 levels by 2030.
- Based on these new announcements and the upcoming Government of Canada consultation period, the Company plans to update its environmental targets later in 2021.
2020 ESG HIGHLIGHTS
- Canadian Natural’s corporate GHG emissions intensity continues to improve, decreasing by 18% from 2016 to 2020, a material reduction in emissions intensity. For 2020 results showed a decrease of 2% from 2019 levels.
- The Company reduced methane emissions in its North American E&P segment by 28% from 2016 to 2020, which includes a decrease of 14% from 2019 levels.
- The Company continues to improve corporate total recordable injury frequency (“TRIF”) in 2020, with a TRIF of 0.21 in 2020 compared to 0.50 in 2016. The Company’s TRIF is down 58% since 2016, while man-hours have increased over this time period.
- Canadian Natural is one of the largest owners of Carbon Capture and Storage (“CCS”) and sequestration capacity in the oil and natural gas sector globally through projects at Horizon, the Company’s 70% owned Quest CCS facility located at Scotford, and its 50% working interest in the NWR Refinery. As part of our comprehensive GHG emissions reduction strategy, our CCS projects include carbon dioxide (“CO2“) storage in geological formations, the use of CO2 in enhanced oil recovery techniques and injection of CO2 into tailings. Gross carbon capture capacity through these projects combined is approximately 2.7 million tonnes of CO2 annually, equivalent to taking approximately 576,000 cars off the road per year.
- The Quest CCS facility captures and stores approximately 1.1 million tonnes of CO2 per year and in May 2020 reached the milestone of 5 million tonnes of stored carbon dioxide. 5 million tonnes of CO2 is equal to the annual emissions from approximately 1.25 million cars.
- At Horizon, annual capture capacity is approximately 0.4 million tonnes of CO2 from the hydrogen plant, the equivalent of removing approximately 85,000 cars off the road annually.
- At the NWR Refinery, captured CO2 from the refinery began to be delivered in March 2020 to the Alberta Carbon Truck Line for enhanced oil recovery and permanent storage in central Alberta. At full capacity, approximately 1.2 million tonnes of CO2 per year will be captured, the equivalent of removing approximately 256,000 cars off the road annually.
- The Company continues to increase the level of third party verified direct GHG emissions and indirect energy use.
- The Company targets to increase the total corporate level of third party verification of GHG emissions to 95% in 2021, an increase of 9% from 2020 levels of 87%.
- In 2020 the Company planted its one millionth tree at AOSP and its one and a half millionth tree at Horizon, reclaiming land and contributing to increased carbon capture.
- In 2020 the Company successfully achieved three of our stated four environmental targets for 2025 relating to GHG and methane emissions intensity reductions and reduced fresh water usage.
- The Company targets the release of its 2020 Stewardship Report to Stakeholders in Q3/21. In September 2020, Canadian Natural published its 2019 Stewardship Report to Stakeholders, which is available on the Company’s website at https://www.cnrl.com/report-to-stakeholders.