Canadian Natural's large, unique and diversified asset base provides a key competitive advantage enabling us to effectively allocate capital across our asset base and manage the pace and timing of development activities, maximizing value for our shareholders. We are executing on our 2024 plan which is strategically weighted to longer cycle thermal development projects in the first half of the year and shorter cycle growth projects in the second half of the year, which aligns with increased market egress and improved forward strip crude oil pricing. As a result, we target to finish the year with strong exit rates as conventional activity ramps up in the second half of the year.
In Oil Sands Mining and Upgrading, at the Horizon site, we are well prepared for 2024 turnaround activity and final tie ins of the reliability enhancement project in the second quarter of the year which will be followed by targeted strong production in the second half of the year with high upgrader utilization. Through optimization efforts and early turnaround work done in early 2024, we have reduced the Horizon turnaround to 28 days from 30 days and improved the commissioning schedule for the reliability enhancement project. These optimizations will advance and shorten commissioning timing after the turnaround to support high targeted utilization and production rates in the second half of the year.
We have a defined path to reduce our environmental footprint and continue delivering sustainable, responsibly produced energy that the world needs. We are committed to supporting Canada's and Alberta's climate goals and have robust environmental targets, including net zero greenhouse gas ("GHG") emissions for the oil sands by 2050. We are uniquely positioned with diverse, long life low decline assets, which are ideal for applying GHG reduction technologies and providing industry leading environmental performance. It is important to continue working together with the Canadian and Alberta governments to make the Pathways Alliance a transformative industry collaboration and achieve meaningful GHG reductions in Canada. We believe Canadian energy is one of the most responsibly produced sources of energy in the world and should be the preferred energy choice."
Canadian Natural's Chief Financial Officer, Mark Stainthorpe, also added, "In Q1/24, we delivered strong financial results, including adjusted net earnings of approximately $1.5 billion and adjusted funds flow of $3.1 billion, which drove significant returns to shareholders totaling $1.7 billion in the quarter. Commencing in 2024, we are returning 100% of free cash flow to shareholders, as per our free cash flow allocation policy, and continue to manage the allocation on a forward looking annual basis.
At Canadian Natural, our culture of continuous improvement and employee ownership alignment with shareholders drives our teams to create significant value across all areas of the Company. Our effective and efficient operations combined with our flexible capital allocation maximizes value for our shareholders."
Â
HIGHLIGHTS
|
| Three Months Ended |
|
| ($ millions, except per common share amounts) |
| Mar 31
2024 |
|
| Dec 31
2023 |
|
| Mar 31
2023 | Â |
| Net earnings | $ | 987 |
| $ | 2,627 |
| $ | 1,799 |
|
| Â Â Per common share | - basic | $ | 0.92 |
| $ | 2.43 |
| $ | 1.63 |
|
| - diluted | $ | 0.91 |
| $ | 2.41 |
| $ | 1.62 |
|
| Adjusted net earnings from operations (1) | $ | 1,474 |
| $ | 2,546 |
| $ | 1,881 |
|
| Â Â Per common share | - basic (2) | $ | 1.38 |
| $ | 2.36 |
| $ | 1.71 |
|
| - diluted (2) | $ | 1.37 |
| $ | 2.34 |
| $ | 1.69 |
|
| Cash flows from operating activities | $ | 2,868 |
| $ | 4,815 |
| $ | 1,295 |
|
| Adjusted funds flow (1) | $ | 3,138 |
| $ | 4,419 |
| $ | 3,429 |
|
| Â Â Per common share | - basic (2) | $ | 2.93 |
| $ | 4.09 |
| $ | 3.12 |
|
| - diluted (2) | $ | 2.91 |
| $ | 4.05 |
| $ | 3.08 |
|
| Cash flows used in investing activities | $ | 1,392 |
| $ | 946 |
| $ | 1,153 |
|
| Net capital expenditures (3) | $ | 1,113 |
| $ | 975 |
| $ | 1,257 |
|
| Abandonment expenditures | $ | 162 |
| $ | 149 |
| $ | 137 |
|
| Daily production, before royalties |
| Â |
|
| Â |
|
| Â |
|
| Â Â Natural gas (MMcf/d) |
| 2,147 |
|
| 2,231 |
|
| 2,139 |
|
| Â Â Crude oil and NGLs (bbl/d) |
| 975,668 |
|
| 1,047,541 |
|
| 962,908 |
|
| Â Â Equivalent production (BOE/d) (4) |
| 1,333,502 |
|
| 1,419,313 |
|
| 1,319,391 | Â |
(1)Â Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024 dated May 1, 2024.
(2)Â Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024 dated May 1, 2024.
(3)Â Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2023 and has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024 dated May 1, 2024.
(4)Â 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, or to compare the value ratio using current crude oil and natural gas prices 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. |
|
Â
The strength of Canadian Natural's long life low decline asset base, supported by safe, effective and efficient operations, makes our business unique, robust and sustainable. In Q1/24, the Company generated strong financial results, including:
Net earnings of approximately $1.0 billion and adjusted net earnings from operations of approximately $1.5 billion.
Cash flows from operating activities of approximately $2.9 billion.
Adjusted funds flow of approximately $3.1 billion.
Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with approximately $6.8 billion in liquidity(1) as at March 31, 2024.
Canadian Natural achieved its $10 billion net debt level at year end 2023 and is returning 100% of free cash flow(1) in 2024 to shareholders, per the Company's free cash flow allocation policy. The Company will manage the allocation of free cash flow on a forward looking annual basis, while managing working capital and cash management as required.
(1) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the Company's MD&A for the three months ended March 31, 2024 dated May 1, 2024.
Canadian Natural continues to focus on safe, effective and efficient operations, and delivered quarterly average production in Q1/24 of 1,333,502 BOE/d, consisting of total liquids production of 975,668 bbl/d and natural gas production of 2,147 MMcf/d.
The Company is targeting strong production from its Oil Sands Mining and Upgrading assets in the second half of the year, as we optimize turnaround activity, complete final tie ins and advance commissioning of the reliability enhancement project in Q2/24.
Canadian Natural has significant growth opportunities across its asset base, including sustainable production enhancements at its Oil Sands Mining and Upgrading operations.
Near-term projects include the reliability enhancement project at Horizon, which targets to increase the two-year average SCO capacity by approximately 14,000 bbl/d by extending the turnaround schedule to once every two years. Additionally, the debottlenecking project at the Scotford Upgrader targets to add incremental capacity at the Athabasca Oil Sands Project ("AOSP") of approximately 5,600 bbl/‌d net to Canadian Natural.
Medium-term projects include the Naphtha Recovery Unit Tailings Treatment ("NRUTT") project at Horizon, which targets to add incremental production of approximately 6,300 bbl/d of SCO, reduce GHG emissions and lower reclamation costs.
Long-term projects at our Oil Sands operations include combining In-Pit Extraction Process ("IPEP") and Paraffinic Froth Treatment ("PFT") that have the potential to add approximately 195,000 bbl/d of additional annual bitumen production, reduce GHG emissions and lower reclamation costs.
The Company's 2024 development plan has conventional activity strategically weighted to the second half of 2024 to better align with increased market egress and improved crude oil pricing, maximizing value for our shareholders. Following completion of the Trans Mountain Expansion ("TMX") pipeline, there will be ample egress and optionality for our crude oil products.
The Company continues to evaluate and implement opportunities to maximize netbacks through the diversification of sales and optimized blending and transportation options through diverse market access. Canadian Natural has optionality for crude oil exports, including the following pipeline commitments:
In Q1/24, the Company increased its commitment on Flanagan South by 55,000 bbl/d to 77,500 bbl/d, further expanding the Company's heavy oil diversification and market access to the United States Gulf Coast ("USGC").
94,000 bbl/d on Trans Mountain Expansion ("TMX") pipeline that creates additional crude oil market diversification opportunities on the west coast, both by land and by water.
10,000 bbl/d on the Base Keystone Pipeline, with direct access to the USGC.
RETURNS TO SHAREHOLDERS
Canadian Natural has a strong history of growing its sustainable dividend for 24 consecutive years and commencing in 2024, we are now returning 100% of free cash flow to shareholders.
Returns to shareholders in Q1/24 were strong, totaling approximately $1.7 billion, comprised of $1.1 billion of dividends and $0.6 billion through the repurchase and cancellation of approximately 6.7 million common shares at a weighted average price of $90.78 per share.
Year to date in 2024, up to and including May 1, 2024, the Company has returned a total of approximately $3.1 billion directly to shareholders through $2.2 billion in dividends and $0.9 billion through the repurchase and cancellation of approximately 9.6 million common shares.
Subsequent to quarter end, the Company declared a quarterly cash dividend on its common shares of $1.05 (one dollar and five cents) per common share on a pre-stock split basis or $0.525 (fifty-two and one half cents) per common share after the two for one share split of the common shares, subject to shareholder approval at the Company's Annual and Special Meeting of Shareholders on May 2, 2024. The quarterly dividend will be payable on July 5, 2024 to shareholders of record at the close of business on June 17, 2024.
As previously announced on February 29, 2024, the Board of Directors increased the quarterly dividend by 5% to $1.05 per common share. This demonstrates the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base. The Company's leading track record of dividend increases continues, with 2024 being the 24th consecutive year of dividend increases with a compound annual growth rate ("CAGR") of 21% over that time.
On February 28, 2024, Canadian Natural's Board of Directors approved a resolution to subdivide the Company's common shares on a two for one basis, subject to shareholder approval at the Company's Annual and Special Meeting of Shareholders on May 2, 2024. The Company will also be required to obtain all regulatory approvals, including TSX approval.
Â
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 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 the Company's long life low decline production, representing approximately 79% of total budgeted liquids production in 2024, 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 the Company's long life low decline production comes from its top tier thermal in situ oil sands operations and Pelican Lake heavy crude oil assets. The combination of these long life low decline assets, low reserves replacement costs, 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 our shareholders. Supporting these projects is the Company's undeveloped land base which enables large, repeatable drilling programs that can be optimized over time. Additionally, Canadian Natural maximizes long-term value by maintaining high ownership and operatorship of its assets and has an extensive infrastructure network, allowing the Company to control the nature, timing and extent of development. Low capital exposure projects can be stopped or started relatively quickly 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 |
|
| Â | Mar 31, 2024 |
|
| Mar 31, 2023 |
|
| (number of wells) |
| Gross |
|
| Net |
|
| Gross |
|
| Net | Â |
| Crude oil (1) |
| 62 |
|
| 61 |
|
| 88 |
|
| 83 |
|
| Natural gas |
| 23 |
|
| 16 |
|
| 26 |
|
| 21 |
|
| Dry |
| - |
|
| - |
|
| 2 |
|
| 2 | Â |
| Subtotal |
| 85 |
|
| 77 |
|
| 116 |
|
| 106 |
|
| Stratigraphic test / service wells |
| 452 |
|
| 386 |
|
| 455 |
|
| 394 | Â |
| Total |
| 537 |
|
| 463 |
|
| 571 |
|
| 500 | Â |
| Â Â Success rate (excluding stratigraphic test / service wells) |
| Â |
|
| 100Â % |
|
| Â |
|
| 98 % | Â |
| (1)Â Includes bitumen wells. |
|
Â
- Canadian Natural drilled a total of 77 net crude oil and natural gas producer wells in Q1/24 compared to 106 net wells in Q1/23, a decrease of 29 net wells over this time period. This decrease in drilling activity reflects the Company's strategic decision to focus on longer cycle development opportunities in the first half of 2024 and shorter cycle development opportunities in the second half of 2024, as previously outlined in the Company's 2024 budget press release.
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North America Exploration and Production
| Crude oil and NGLs - excluding Thermal In Situ Oil Sands |
|
|
| Three Months Ended |
|
|
| Mar 31
2024 |
|
| Dec 31
2023 |
|
| Mar 31
2023 | Â |
| Crude oil and NGLs production (bbl/d) |
| 237,481 |
|
| 243,157 |
|
| 234,465 | Â |
| Net wells targeting crude oil |
| 38 |
|
| 42 |
|
| 60 |
|
| Net successful wells drilled |
| 38 |
|
| 42 |
|
| 58 | Â |
| Â Â Success rate |
| 100Â % |
|
| 100 % |
|
| 97 % | Â |
Â
North America E&P liquids production, excluding thermal in situ, averaged 237,481 bbl/d in Q1/24, comparable to Q1/23 levels. As previously outlined in the 2024 budget, the Company has strategically allocated capital for its conventional assets to the latter part of 2024 to better align with incremental market egress, driving strong targeted 2024 exit rates.
Primary heavy crude oil production averaged 78,431 bbl/d in Q1/24, comparable to Q1/23 levels, reflecting strong results from the Company's multilateral wells in the Mannville and Clearwater fairways which offset natural field declines.
The Company is targeting to drill 148 net multilateral wells in 2024, 12 more than budgeted, as we are shifting certain dry natural gas activity to these higher returning multilateral heavy oil wells. The majority of this activity is strategically planned for the second half of 2024.
Operating costs(1) in the Company's primary heavy crude oil operations averaged $19.16/bbl (US$14.21/‍bbl) in Q1/24, a decrease of 11% from Q1/23 levels, primarily reflecting lower energy costs.
Pelican Lake production averaged 45,145 bbl/d in Q1/24, a decrease of 6% from Q1/23 levels, reflecting low natural field declines from this long life low decline asset.
North America light crude oil and NGLs production averaged 113,905 bbl/d in Q1/24, an increase of 5% from Q1/23 production which was impacted by a third party pipeline outage. Production in Q1/24 reflects strong drilling results from the Company's liquids-rich Montney and Deep Basin assets partially offset by natural field declines.
Operating costs in the Company's North America light crude oil and NGLs operations averaged $15.25/‍bbl (US$11.31/bbl) in Q1/24, a decrease of 18% from Q1/23 levels, reflecting increased production and lower energy costs.
Â
| North America Natural Gas |
|
|
| Three Months Ended |
|
| Â | Mar 31
2024 |
|
| Dec 31
2023 |
|
| Mar 31
2023 | Â |
| Natural gas production (MMcf/d) |
| 2,135 |
|
| 2,218 |
|
| 2,127 | Â |
| Net wells targeting natural gas |
| 16 |
|
| 9 |
|
| 21 |
|
| Net successful wells drilled |
| 16 |
|
| 9 |
|
| 21 | Â |
| Â Â Success rate |
| 100Â % |
|
| 100 % |
|
| 100 % | Â |
Â
Canadian Natural's North America natural gas production averaged 2,135 MMcf/d in Q1/24, comparable to Q1/23 production which was impacted by a third party pipeline outage. Production in Q1/24 reflects strong results from the Company's capital efficient drill to fill development plan, offset by natural field declines.
(1) Calculated as production expense divided by respective sales volumes. Natural gas and NGLs production volumes approximate sales volumes.
Â
| Thermal In Situ Oil Sands |
|
|
| Three Months Ended |
|
|
| Mar 31
2024 |
|
| Dec 31
2023 |
|
| Mar 31
2023 | Â |
| Bitumen production (bbl/d) |
| 268,155 |
|
| 278,422 |
|
| 242,884 | Â |
| Net wells targeting bitumen |
| 23 |
|
| - |
|
| 25 |
|
| Net successful wells drilled |
| 23 |
|
| - |
|
| 25 | Â |
| Â Â Success rate |
| 100Â % |
|
| - % |
|
| 100 % | Â |
Â
Thermal in situ long life low decline production averaged 268,155 bbl/d in Q1/24, an increase of 10% from Q1/23 levels, driven by strong execution on Cyclic Steam Stimulation ("CSS") and Steam Assisted Gravity Drainage ("SAGD") pad developments in 2023.
The Company successfully completed the planned turnaround at Jackfish ahead of schedule in April 2024, and has an upcoming turnaround at Kirby North in May 2024. As a result of completing the turnaround at Jackfish ahead of schedule, the total impact to Q2/24 average production is now targeted to be approximately 15,300 bbl/d, an improvement from the previous target of 17,100 bbl/d.
Canadian Natural has decades of strong capital efficient growth opportunities on its long life low decline thermal in situ assets. As outlined in our 2024 budget, we continue to develop these assets in a disciplined manner to deliver safe and reliable thermal in situ production with the following opportunities:
At Primrose, the Company is currently drilling two CSS pads which are targeted to come on production in Q2/25. At Wolf Lake, the Company recently drilled one SAGD pad which is targeted to come on production in Q1/25.
At Jackfish, the first of two SAGD pads that were drilled in 2023 has ramped up to its targeted full production capacity in April 2024, ahead of budget. The second pad is targeted to ramp up to its full production capacity in Q4/24, supporting continued high utilization rates at the Jackfish facilities. Additionally, the Company is targeting to drill one SAGD pad at Jackfish in the second half of 2024, with production from this pad targeted to come on in Q3/25.
Canadian Natural has been piloting solvent enhanced oil recovery technology on certain thermal in situ assets with an objective to increase bitumen production while reducing the Steam to Oil Ratio ("SOR") and GHG intensities by 40% to 50% and optimizing solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
At Kirby North, the commercial scale solvent SAGD pad development is approximately 90% complete and the Company is targeting to begin solvent injection in July 2024.
At Primrose, the Company is continuing to use its solvent enhanced oil recovery pilot in the steam flood area to optimize solvent efficiency and to further evaluate the commercial development opportunity.
Â
North America Oil Sands Mining and Upgrading
|
| Three Months Ended |
|
| Â | Mar 31
2024 |
|
| Dec 31
2023 |
|
| Mar 31
2023 | Â |
| Synthetic crude oil production (bbl/d) (1)(2) |
| 445,209 |
|
| 500,133 |
|
| 458,228 | Â |
(1)Â SCO production before royalties and excludes production volumes consumed internally as diesel.
(2)Â Consists of heavy and light synthetic crude oil products. |
|
Â
Canadian Natural remains focused on safe, reliable, effective and efficient operations of its world class Oil Sands Mining and Upgrading assets. In Q1/24, the Company delivered average production of 445,209 bbl/d of high value SCO, a decrease of 3% from Q1/23 levels. Production in Q1/24 reflected planned and unplanned maintenance activities, including the advancement of the Scotford Upgrader planned turnaround to March 2024 from April 2024. These activities in Q1/24 reduced Oil Sands Mining and Upgrading production by approximately 45,000 bbl/d of SCO from what would have been achieved otherwise. Through the actions discussed below and other optimization efforts, the Company is targeting to recover these daily production volumes in the last three quarters of 2024.
Canadian Natural has the following upcoming turnarounds, including schedule optimizations, planned at our Oil Sands Mining and Upgrading operations:
 At Horizon, a planned turnaround is targeted to begin on May 15, 2024. Through continuous improvement, optimization efforts and early turnaround work done in Q1/24 during unplanned maintenance activities, the Company has reduced the targeted duration of the turnaround to 28 days from 30 days.
Additionally, following the turnaround, the Company is optimizing the commissioning schedule of the reliability enhancement project, which is targeted to increase Q3/24 SCO production.
At AOSP, a 49 day turnaround is targeted to begin in September 2024, when the Scotford Upgrader will run at reduced rates, impacting annual production by approximately 11,000 bbl/d.
The Company continues to progress sustainable production enhancements at both Horizon and AOSP.
At Horizon, the Company targets to complete the remaining components and tie-ins related to the reliability enhancement project during the planned turnaround in Q2/24.
This project targets to increase capacity of the zero decline, high value SCO production over a two year timeframe by shifting the planned turnarounds to once every two years from the current annual cycle, reducing downtime and increasing overall reliability. In 2025, annual production is targeted to increase by approximately 28,000 bbl/d, with the two year average annual SCO capacity targeted to increase by approximately 14,000 bbl/d.
At the Scotford Upgrader, a debottlenecking project, which targets to add incremental capacity at AOSP of approximately 5,600 bbl/‌d net to Canadian Natural, is targeted to be completed during the planned Fall 2024 turnaround.
At Horizon, the Company is progressing the Naphtha Recovery Unit Tailings Treatment ("NRUTT") project that targets incremental production of approximately 6,300 bbl/d of SCO following mechanical completion in Q3/27. This project is targeted to reduce GHG emissions, equivalent to 6% of Horizon's total Scope 1 emissions, and will result in lower reclamation costs.
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International Exploration and Production
|
| Three Months Ended |
|
|
| Mar 31
2024 |
|
| Dec 31
2023 |
|
| Mar 31
2023 | Â |
| Crude oil production (bbl/d) |
| 24,823 |
|
| 25,829 |
|
| 27,331 |
|
| Natural gas production (MMcf/d) |
| 12 |
|
| 13 |
|
| 12 | Â |
Â
- International E&P crude oil production volumes averaged 24,823 bbl/d in Q1/24, a decrease of 9% from Q1/23 levels, reflecting natural field declines and maintenance activities.
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MARKETING
|
| Three Months Ended |
|
| Â | Mar 31
2024 |
| Â |
| Dec 31
2023 |
|
| Mar 31
2023 | Â |
| Benchmark Commodity Prices |
|
|
| Â |
|
|
|
|
|
|
| Â Â WTI benchmark price (US$/bbl) (1) | $ | 76.97 |
| Â | $ | 78.33 |
| $ | 76.11 |
|
| Â Â WCS heavy differential (discount) to WTI (US$/bbl) (1) | $ | (19.34 | ) | Â | $ | (21.90 | ) | $ | (24.74 | ) |
| Â Â WCS heavy differential as a percentage of WTI (%) (1) |
| 25Â % |
| Â |
| 28 % |
|
| 33 % |
|
| Â Â Condensate benchmark price (US$/bbl) | $ | 72.79 |
| Â | $ | 76.22 |
| $ | 79.83 |
|
| Â Â SCO price (US$/bbl) (1) | $ | 69.43 |
| Â | $ | 78.64 |
| $ | 78.18 |
|
| Â Â SCO premium (discount) to WTI (US$/bbl) (1) | $ | (7.54 | ) | Â | $ | 0.31 |
| $ | 2.07 |
|
| Â Â AECO benchmark price (C$/GJ) | $ | 1.94 |
| Â | $ | 2.52 |
| $ | 4.12 |
|
| Realized Prices |
| Â |
| Â |
| Â |
|
| Â |
|
| Â Â Exploration & Production liquids realized price (C$/bbl) (2)(3)(4)(5) | $ | 70.01 |
| Â | $ | 69.39 |
| $ | 58.85 |
|
| Â Â SCO realized price (C$/bbl) (1)(3)(4)(5) | $ | 88.84 |
| Â | $ | 98.73 |
| $ | 96.07 |
|
| Â Â Natural gas realized price (C$/Mcf) (4) | $ | 2.55 |
| Â | $ | 2.80 |
| $ | 4.27 | Â |
(1)Â West Texas Intermediate ("WTI"); Western Canadian Select ("WCS"); Synthetic Crude Oil ("SCO").
(2)Â Exploration & Production crude oil and NGLs average realized price excludes SCO.
(3)Â Pricing is net of blending costs.
(4)Â Excludes risk management activities.
(5)Â Non-GAAP ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024 dated May 1, 2024. |
|
Â
Canadian Natural has a balanced and diverse product mix of natural gas, NGLs, heavy crude oil, light crude oil, bitumen and SCO.
WTI prices averaged US$76.97/bbl in Q1/24, comparable to both Q4/23 and Q1/23, although the global crude oil market continues to be impacted by heightened geopolitical tensions.
SCO pricing averaged US$69.43/bbl in Q1/24, representing a US$7.54/bbl price discount to WTI, compared to a US$2.07/bbl price premium to WTI in Q1/23. The lower SCO price in Q1/24 was primarily driven by egress constraints in the Western Canadian Sedimentary Basin ("WCSB").
The average WCS differential to WTI of US$19.34/bbl in Q1/24 has strengthened from both comparable periods, primarily reflecting the anticipated startup of TMX and stronger US Gulf Coast heavy oil pricing due to lower Mexican imports.
The Company continues to evaluate and implement opportunities to maximize netbacks through the diversification of sales and optimized blending and transportation options through diverse market access. Canadian Natural has optionality for crude oil exports, including the following pipeline commitments:
In Q1/24, the Company increased its commitment on Flanagan South by 55,000 bbl/d to 77,500 bbl/d, further expanding the Company's heavy oil diversification and market access to the USGC.
94,000 bbl/d on TMX pipeline that creates additional crude oil market diversification opportunities on the west coast, both by land and by water.
10,000 bbl/d on the Base Keystone Pipeline, with direct access to the USGC.
(1) Forward strip pricing as of April 30, 2024.
The North West Redwater ("NWR") refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 78,569 bbl/d in Q1/24.
AECO natural gas prices in Q1/24 compared to Q1/23 and Q4/23 reflect lower NYMEX benchmark pricing, increased production in the WCSB and higher storage inventories resulting from mild winter weather.
In 2024, the Company is targeting to use the equivalent of approximately 38% of its budgeted natural gas production in its operations, with approximately 25% targeted to be sold at AECO/Station 2 pricing, and approximately 37% targeted to be exported to other North American and international markets capturing higher natural gas prices, maximizing value from its diversified natural gas marketing portfolio.
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ENVIRONMENTAL, SOCIAL AND GOVERNANCE HIGHLIGHTS
Canada and Canadian Natural are well positioned to deliver affordable, reliable, safe and responsibly produced energy that the world needs, through leading ESG performance. Canadian Natural's diverse portfolio is supported by a significant amount of long life low decline assets which have low risk, high value reserves that require low maintenance capital. This allows the Company to remain flexible with our capital allocation and creates an ideal opportunity to pilot and apply technologies for GHG emissions reductions. Canadian Natural continues to invest in a range of technologies to reduce emissions, such as solvents for enhanced recovery and Carbon Capture, Utilization and Storage ("CCUS") projects. Our culture of continuous improvement provides a significant advantage to delivering on our strategy of investing in GHG technologies across our assets, including opportunities for methane emissions reduction.
Environmental Targets
Canadian Natural is committed to reducing our environmental footprint and as previously announced, has committed to the following environmental targets:
40% reduction in corporate Scope 1 and Scope 2 absolute GHG emissions by 2035, from a 2020 baseline
50% reduction in North America E&P (including thermal in situ) methane emissions by 2030, from a 2016 baseline
40% reduction in thermal in situ fresh water usage intensity by 2026, from a 2017 baseline
40% reduction in mining fresh river water usage intensity by 2026, from a 2017 baseline
Canadian Natural has a defined pathway to achieve long-term emissions reductions with an integrated GHG emissions management strategy that includes ongoing investments in technology and innovation while transferring technology across the Company. The areas of focus include, but are not limited to: carbon capture, sequestration/storage and utilization, the use of solvents, energy/steam efficiencies, methane reduction, and tailings and water management.
Pathways Alliance
The six major oil sands companies in the Pathways Alliance ("Pathways"), including Canadian Natural, operate approximately 95% of Canada's oil sands production. The goal of this unique alliance is to work together with governments to achieve net zero emissions from oil sands operations by 2050, support Canada in meeting its climate commitments and be the preferred source of crude oil globally. Pathways has a defined plan, including its foundational carbon capture and storage ("CCS") project involving a CO2 transportation line connecting Fort McMurray and Cold Lake to a carbon sequestration hub.
Pathways continues to work together with governments on the necessary co-investment and regulatory certainty needed to proceed. As a step in moving the project forward, Canadian Natural, on behalf of the Pathways Alliance, commenced regulatory applications in March 2024 to the Alberta Energy Regulator for the proposed CO2 Transportation Network and Storage Hub. Project engineering and environmental field programs are on track to meet timelines. Multiple feasibility studies on phase-one capture facilities, with engineering and design work continue to progress. Stakeholder engagement and consultation is ongoing with Indigenous and local communities in northern Alberta related to the Pathways CCS project.
Government Support for Emissions Reductions and Carbon Capture, Utilization and Storage
The Government of Canada announced a Regulatory Framework for an Oil and Gas Sector Greenhouse Gas Emissions Cap on December 7, 2023 with plans to publish draft regulations by mid-2024. The framework proposes to cap and cut emissions from the oil and natural gas sector through implementation of a national cap-and-trade system. The oil and natural gas sector has made significant progress in GHG emissions reductions along with investments in technology and innovation that have been enabled under existing carbon pricing systems. As such, the proposed oil and natural gas sector emissions cap is unnecessary, exceedingly complex and undermines the investor confidence required for large-scale, long-term emission reduction initiatives.
Canadian Natural is a leader in CCUS and GHG reduction projects and sees many opportunities to work collaboratively with industry peers and governments to advance investments in CCUS and to achieve meaningful GHG emissions reductions in support of Canada's climate goals. The Government of Canada has proposed an investment tax credit ("ITC") for CCUS projects for all sectors across Canada that would offer a refundable ITC of up to 50% on capture equipment and 37.5% on qualified carbon transportation, storage or usage equipment from 2022 to 2030. Additionally, the Government of Alberta announced it would provide a 12% tax credit on eligible capital costs associated with building new CCUS projects. It remains important for governments to work together with industry to ensure that policy and regulatory frameworks deliver the required support to enable CCUS project development.
Canadian Natural will continue to provide input to government on the importance of balancing environmental and economic objectives along with being able to support Canada's allies with energy security. By working together, industry and governments have the opportunity to help achieve climate goals, meet economic objectives and support Canada's role in energy security.
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ADVISORY
Special Note Regarding Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to the Company's capital budget, expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, abandonment expenditures, income tax expenses, and other targets provided throughout this document and the Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby thermal oil sands project, the Jackfish thermal oil sands project and 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; the abandonment and decommissioning of certain assets and the timing thereof; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; and the impact of the Pathways Alliance ("Pathways") initiative and activities, government support for Pathways and the ability to achieve net zero emissions from oil sands production, 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 earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of armed conflicts in the Middle East, the impact of the Russian invasion of Ukraine, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are 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; the ability of the Company to prevent and recover from a cyberattack, other cyber-related crime and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the Company's ability to implement strategies and leverage technologies to meet climate change initiatives and emissions targets on the expected timelines; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company to complete capital programs; the Company's ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; 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); interpretations of applicable tax laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.
The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this document or the Company's MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this document or the Company's MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company's estimates or opinions change.
Special Note Regarding Currency, Financial Information and Production
This document should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") and the Company's MD&A for the three months ended March 31, 2024, and audited consolidated financial statements for the year ended December 31, 2023. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements and MD&A for the three months ended March 31, 2024 have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").
Production volumes and per unit statistics are presented throughout this document 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 this document, 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, 2023, is available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. Information on the Company's website does not form part of and is not incorporated by reference in the Company's MD&A.
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Special Note Regarding Non-GAAP and Other Financial Measures
This document includes references to non-GAAP measures, which include non-GAAP and other financial measures as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure. These financial measures are used by the Company to evaluate its financial performance, financial position or cash flow and include non-GAAP financial measures, non-‍GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial measure presented in the Company's financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company's non-GAAP and other financial measures included in this document, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below as well as in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024, dated May 1, 2024.
Break-even WTI Price
The break-even WTI price is a supplementary financial measure that represents the equivalent US dollar WTI price per barrel where the Company's adjusted funds flow is equal to the sum of maintenance capital and dividends. The Company considers the break-even WTI price a key measure in evaluating its performance, as it demonstrates the efficiency and profitability of the Company's activities. The break-even WTI price incorporates the non-GAAP financial measure adjusted funds flow as reconciled in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. Maintenance capital is a supplementary financial measure that represents the capital required to maintain annual production at prior period levels.
Capital Budget
Capital budget is a forward looking non-GAAP financial measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for more details on net capital expenditures.
Capital Efficiency
Capital efficiency is a supplementary financial measure that represents the capital spent to add new or incremental production divided by the current rate of the new or incremental production. It is expressed as a dollar amount per flowing volume of a product ($‍/‍bbl/‍‍d or $/‍BOE‍/‍d). The Company considers capital efficiency a key measure in evaluating its performance, as it demonstrates the efficiency of the Company's capital investments.
Free Cash Flow Policy in 2023 and 2024
Free cash flow is a non-GAAP financial measure. 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 or maintain net debt levels, pursuant to the free cash flow allocation policy.
The Company's free cash flow is used to determine the target amount of shareholder returns after dividends. The calculation in determining free cash flow varies depending on the Company's net debt position, and as a result of achieving $10 billion in net debt at the end of 2023, the Company's free cash flow calculation has changed in 2024, when compared to 2023 as follows:
- Allocation of Free Cash Flow in 2024
As net debt of $10 billion was achieved at the end of 2023, commencing in 2024, the Company will target to return 100% of free cash flow to shareholders. Free cash flow is calculated as adjusted funds flow less dividends on common shares, net capital expenditures and abandonment expenditures. The Company targets to manage the allocation of free cash flow on a forward looking annual basis, while managing working capital and cash management as required.
The Company's free cash flow for the three months ended March 31, 2024 is shown below:
|
| Three Months Ended |
|
| ($ millions) | Â | Mar 31
2024 |
|
| Adjusted funds flow (1) | $ | 3,138 |
|
| Less: Dividends on common shares |
| 1,076 |
|
| Â Â Â Â Â Net capital expenditures (2) |
| 1,113 |
|
| Â Â Â Â Â Abandonment expenditures |
| 162 |
|
| Free cash flow | $ | 787 | Â |
(1)Â Refer to the descriptions and reconciliations to the most directly comparable GAAP measure, which are provided in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024, dated May 1, 2024.
(2)Â Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024, dated May 1, 2024. |
|
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- Allocation of Free Cash Flow in 2023
When net debt was between $10 billion and $15 billion, as was the case in 2023, approximately 50% of free cash flow was allocated to shareholder returns and 50% was allocated to the balance sheet, less strategic growth/acquisition opportunities. In 2023, free cash flow of $6.9 billion was calculated as adjusted funds flow of $15.3 billion less dividends on common shares of $3.9 billion, base capital expenditures of $4.0 million and abandonment expenditures of $0.5 billion.
Long-term Debt, net
Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents.
| ($ millions) | Â | Mar 31
2024 |
|
| Dec 31
2023 |
|
| Mar 31
2023 | Â |
| Long-term debt | $ | 11,040 |
| $ | 10,799 |
| $ | 12,024 |
|
| Less: cash and cash equivalents |
| 767 |
|
| 877 |
|
| 92 | Â
|
| Long-term debt, net | $ | 10,273 |
| $ | 9,922 |
| $ | 11,932 | Â |
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CONFERENCE CALL
Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) will be issuing its 2024 First Quarter Earnings Results on Thursday, May 2, 2024 before market open.
A conference call will be held at 7:00 a.m. MDT / 9:00 a.m. EDT on Thursday, May 2, 2024.
Dial-in to the live event:
North America 1-800-717-1738 / International 001-289-514-5100.
Listen to the audio webcast:
Access the audio webcast on the home page of our website, www.cnrl.com.
Conference call playback:
North America 1-888-660-6264 / International 001-289-819-1325 (Passcode: 56079#)
Canadian Natural is a senior crude 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
T (403) 517-6700 F (403) 517-7350 E ir@cnrl.com
2100, 855 - 2 Street S.W. Calgary, Alberta, T2P 4J8
www.cnrl.com
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SCOTT G. STAUTH
President
MARK A. STAINTHORPE
Chief Financial Officer
LANCE J. CASSON
Manager, Investor Relations
Trading Symbol - CNQ
Toronto Stock Exchange
New York Stock Exchange
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