Following our first few months of operating the Duvernay assets acquired in December 2024, we are achieving strong production results and cost reductions. We are confident we will add more value than we planned for at the time of the acquisition. This is made possible through our commitment to continuous improvement and a strong team culture that focuses on improving our already top tier operating costs, driving execution of organic growth opportunities and maximizing value to shareholders.
Canadian Natural's constant focus on continuous improvement has resulted in capturing cost efficiencies throughout our operations year to date. As a result of these efficiencies, we are in a position to reduce our 2025 capital budget by $100 million, resulting in an updated total capital forecast of $6.05 billion, excluding abandonment expenditures. This reduction in our 2025 capital will have no impact on our planned operating activities or targeted production levels for 2025."
Canadian Natural's Chief Financial Officer, Victor Darel, added "In Q1/25, we achieved strong financial results, including adjusted net earnings of $2.4 billion or $1.16 per share and adjusted funds flow of $4.5 billion, or $2.16 per share. We returned approximately $1.7 billion to our shareholders in Q1/25, including $1.2 billion in dividends and $0.5 billion in share repurchases. At the same time we strengthened our balance sheet by reducing net debt in the quarter by approximately $1.4 billion from December 31, 2024 levels.
We are committed to maximizing shareholder value and increasing sustainable returns to shareholders. As previously announced, in March 2025 the Board of Directors approved a 4% increase to our quarterly dividend to $0.5875 per common share or $2.35 per common share annualized, with 2025 being the 25th consecutive year of dividend increases by Canadian Natural, with a compound annual growth rate ("CAGR") of 21% over that time.
Our business model is robust and sustainable as our top tier US$ WTI breakeven, defined as the adjusted funds flow required to cover maintenance capital and dividends, remains in the low to mid-US$40 per barrel range. Our balance sheet is already very strong and we improved it further by reducing net debt by approximately $1.4 billion in Q1/25 as mentioned above, and maintained liquidity of approximately $5.1 billion as at March 31, 2025, providing significant flexibility.
Our leading financial results combined with our top tier, safe, reliable, effective and efficient operations provide us with unique competitive advantages, all of which drive material free cash flow generation and strong returns on capital."
HIGHLIGHTS
|
| Three Months Ended |
|
| ($ millions, except per common share amounts) |
| Mar 31
2025 |
|
| Dec 31
2024 |
|
| Mar 31
2024 |
|
| Net earnings | $ | 2,458 |
| $ | 1,138 |
| $ | 987 |
|
| Per common share (1) | - basic | $ | 1.17 |
| $ | 0.54 |
| $ | 0.46 |
|
| - diluted | $ | 1.17 |
| $ | 0.54 |
| $ | 0.46 |
|
| Adjusted net earnings from operations (2) | $ | 2,436 |
| $ | 1,977 |
| $ | 1,474 |
|
| Per common share (1) | - basic (3) | $ | 1.16 |
| $ | 0.94 |
| $ | 0.69 |
|
| - diluted (3) | $ | 1.16 |
| $ | 0.93 |
| $ | 0.68 |
|
| Cash flows from operating activities | $ | 4,284 |
| $ | 3,432 |
| $ | 2,868 |
|
| Adjusted funds flow (2) | $ | 4,530 |
| $ | 4,186 |
| $ | 3,138 |
|
| Per common share (1) | - basic (3) | $ | 2.16 |
| $ | 1.99 |
| $ | 1.47 |
|
| - diluted (3) | $ | 2.15 |
| $ | 1.97 |
| $ | 1.45 |
|
| Cash flows used in investing activities | $ | 1,312 |
| $ | 10,414 |
| $ | 1,392 |
|
| Net capital expenditures (4) | $ | 1,303 |
| $ | 10,348 |
| $ | 1,113 |
|
| Net capital expenditures, excluding net acquisition costs (5) | $ | 1,303 |
| $ | 1,290 |
| $ | 1,113 |
|
| Abandonment expenditures | $ | 188 |
| $ | 151 |
| $ | 162 |
|
| Daily production, before royalties |
| |
|
| |
|
| |
|
| Natural gas (MMcf/d) |
| 2,451 |
|
| 2,283 |
|
| 2,147 |
|
| Crude oil and NGLs (bbl/d) |
| 1,173,804 |
|
| 1,090,002 |
|
| 975,668 |
|
| Equivalent production (BOE/d) (6) |
| 1,582,348 |
|
| 1,470,428 |
|
| 1,333,502 |
|
(1) Per common share and dividend amounts have been updated to reflect the two for one common share split. Further details are disclosed in the Advisory section of the Company's MD&A and in the financial statements for the three months ended March 31, 2025 dated May 7, 2025.
(2) 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, 2025 dated May 7, 2025.
(3) 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, 2025 dated May 7, 2025.
(4) Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2024. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2025 dated May 7, 2025.
(5) Excludes net acquisition costs of $9,058 million for the three months ended December 31, 2024 related to the acquisition of assets in the period.
(6) 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. |
|
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 Q1/25, the Company generated strong financial results, including:
Net earnings of approximately $2.5 billion and adjusted net earnings from operations of approximately $2.4 billion.
Cash flows from operating activities of approximately $4.3 billion.
Adjusted funds flow of approximately $4.5 billion.
Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with approximately $5.1 billion in liquidity(1) as at March 31, 2025.
(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, 2025 dated May 7, 2025.
Canadian Natural continues to focus on safe, effective and efficient operations delivering record quarterly average production in Q1/25 of 1,582,348 BOE/d, consisting of record total liquids production of 1,173,804 bbl/d and record natural gas production of 2,451 MMcf/d.
Canadian Natural's world class Oil Sands Mining and Upgrading assets delivered record quarterly production of 595,116 bbl/d of SCO in Q1/25, an increase of 34% or approximately 150,000 bbl/d from Q1/24 levels.
Gross production of approximately 630,000 bbl/d in Q1/25, with upgrader utilization of 106%, was the highest quarterly Oil Sands Mining and Upgrading gross production in the Company's history, achieved through successes from the recently completed Reliability Enhancement Project and Scotford Upgrader debottleneck work, driving strong performance.
When comparing utilization over the last 5 years Canadian Natural's was approximately 8% higher versus a comparable peer average. This equates to approximately 40,000 bbl/d of incremental annual production based on 2024 capacity.
Industry leading quarterly Oil Sands Mining and Upgrading operating costs of $21.88/bbl (US$15.25/bbl) of SCO were achieved in Q1/25, a decrease of 12% from Q1/24 levels.
Canadian Natural's high value SCO represented approximately 51% of the Company's total liquids volumes in Q1/25 and captured strong quarterly realized SCO pricing of $95.52/bbl, generating significant free cash flow.
Thermal in situ quarterly production averaged 284,706 bbl/d in Q1/25, an increase of 6% or approximately 16,500 bbl/d from Q1/24 levels as a result of the Company's capital efficient thermal pad add development program. Results have been strong from the two Cyclic Steam Stimulation ("CSS") pads that came on production ahead of schedule at Primrose in Q4/24 and Q1/25.
Quarterly thermal in situ operating costs were strong, averaging $11.23/bbl (US$7.83/bbl) in Q1/25, a decrease of 20% from Q1/24 levels, primarily reflecting higher production volumes and lower energy costs.
On the recently acquired Duvernay assets, Canadian Natural's effective and efficient operations, area synergies and expertise in similar plays, such as the Montney, have resulted in both capital and operating cost efficiencies. Additionally, we are on track to achieve 2025 budget production of approximately 60,000 BOE/d.
By optimizing well length and completions design combined with top tier execution, we are drilling longer wells with improved reservoir access at lower costs. On a length normalized basis, combined drilling and completion costs for 2025 are targeting an improvement of approximately 14% or $1.8 million per well compared to 2024 costs.
The Company is targeting to drill 43 gross wells in the Duvernay as part of the 2025 capital development program.
Operating costs in Q1/25 were strong, averaging approximately $9.52/BOE.
RETURNS TO SHAREHOLDERS
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 77% of total budgeted liquids production in 2025, 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 landbase 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, 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 |
|
|
| March 31, 2025 |
|
| March 31, 2024 |
|
| (number of wells) |
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Crude oil (1) |
| 75 |
|
| 74 |
|
| 62 |
|
| 61 |
|
| Natural gas |
| 23 |
|
| 19 |
|
| 23 |
|
| 16 |
|
| Dry |
| 1 |
|
| 1 |
|
| - |
|
| - |
|
| Subtotal |
| 99 |
|
| 94 |
|
| 85 |
|
| 77 |
|
| Stratigraphic test / service wells |
| 484 |
|
| 462 |
|
| 452 |
|
| 386 |
|
| Total |
| 583 |
|
| 556 |
|
| 537 |
|
| 463 |
|
| Success rate (excluding stratigraphic test / service wells) |
| |
|
| 99 % |
|
| |
|
| 100 % |
|
| (1) Includes bitumen wells. |
|
North America Exploration and Production
| Crude oil and NGLs - excluding Thermal In Situ Oil Sands |
|
|
| Three Months Ended |
|
|
| Mar 31
2025 |
|
| Dec 31
2024 |
|
| Mar 31
2024 |
|
| Crude oil and NGLs production (bbl/d) |
| 276,532 |
|
| 255,729 |
|
| 237,481 |
|
| Net wells targeting crude oil |
| 57 |
|
| 84 |
|
| 38 |
|
| Net successful wells drilled |
| 56 |
|
| 84 |
|
| 38 |
|
| Success rate |
| 98 % |
|
| 100 % |
|
| 100 % |
|
North America E&P liquids production, excluding thermal in situ, averaged 276,532 bbl/d in Q1/25, a 16% increase from Q1/24 levels, reflecting production volumes from the Duvernay assets acquired in December 2024, along with strong organic growth from our liquids-rich natural gas and primary heavy crude oil assets.
Primary heavy crude oil production averaged 85,604 bbl/d in Q1/25, a 9% increase from Q1/24 levels, reflecting strong drilling results from the Company's multilateral wells, partially offset by natural field declines.
Continuing to build on the Company's highly successful multilateral drilling program, Canadian Natural targets to drill 156 net primary heavy crude oil multilateral wells in 2025.
Operating costs in the Company's primary heavy crude oil operations averaged $18.13/bbl (US$12.63/bbl) in Q1/25, a decrease of 5% from Q1/24 levels, primarily reflecting higher production volumes and lower energy costs.
Pelican Lake production averaged 43,175 bbl/d in Q1/25 a decrease of 4% from Q1/24 levels, reflecting low natural field declines from this long life low decline asset.
North America light crude oil and NGLs production averaged 147,753 bbl/d in Q1/25, an increase of 30% or approximately 34,000 bbl/d compared to Q1/24 levels, primarily driven by the recently acquired Duvernay assets and strong drilling results in our liquids-rich natural gas assets.
Operating costs in the Company's North America light crude oil and NGLs operations averaged $13.15/bbl (US$9.16/bbl) in Q1/25, a decrease of 14% from Q1/24 levels, primarily reflecting higher production volumes and lower energy costs.
| North America Natural Gas |
|
|
| Three Months Ended |
|
|
| Mar 31
2025 |
|
| Dec 31
2024 |
|
| Mar 31
2024 |
|
| Natural gas production (MMcf/d) |
| 2,436 |
|
| 2,273 |
|
| 2,135 |
|
| Net wells targeting natural gas |
| 19 |
|
| 14 |
|
| 16 |
|
| Net successful wells drilled |
| 19 |
|
| 14 |
|
| 16 |
|
| Success rate |
| 100 % |
|
| 100 % |
|
| 100 % |
|
North America natural gas production averaged 2,436 MMcf/d in Q1/25, an increase of 14% from Q1/24 levels, driven by the recently acquired Duvernay assets and strong drilling results in the Company's liquids-rich natural gas assets. The Company remains focused on delivering strong returns on organic growth with our liquids-rich natural gas activity in the Duvernay, Montney and Deep Basin.
| Thermal In Situ Oil Sands |
|
|
| Three Months Ended |
|
|
| Mar 31
2025 |
|
| Dec 31
2024 |
|
| Mar 31
2024 |
|
| Bitumen production (bbl/d) |
| 284,706 |
|
| 276,231 |
|
| 268,155 |
|
| Net wells targeting bitumen |
| 18 |
|
| 16 |
|
| 23 |
|
| Net successful wells drilled |
| 18 |
|
| 16 |
|
| 23 |
|
| Success rate |
| 100 % |
|
| 100 % |
|
| 100 % |
|
Thermal in situ production averaged 284,706 bbl/d in Q1/25, an increase of 6% or approximately 16,500 bbl/d from Q1/24 levels as a result of the Company's capital efficient thermal pad add development program. Results have been strong from the two CSS pads that came on production ahead of schedule at Primrose in Q4/24 and Q1/25.
Quarterly thermal in situ operating costs were strong, averaging $11.23/bbl (US$7.83/bbl) in Q1/25, a decrease of 20% from Q1/24 levels, primarily reflecting higher production volumes and lower energy costs.
Canadian Natural has significant thermal in situ facility processing capacity of approximately 340,000 bbl/d, resulting in 70,000 bbl/d of available capacity. The Company has decades of strong capital efficient drill to fill growth opportunities on its long life low decline thermal in situ assets, which we continue to develop in a disciplined manner to deliver safe and reliable thermal in situ production.
At Primrose, following strong results from the recently drilled CSS pads, the Company is planning to reallocate a portion of pad add capital in 2025 to Primrose from Kirby to maximize returns. The Company now targets to drill a CSS pad in Q4/25 with production targeted to come on in 2026.
At Jackfish, the Company finished drilling a SAGD pad in Q4/24, with production targeted to come on in Q3/25.
At Pike, the Company has completed drilling one SAGD pad and is currently drilling a second SAGD pad, both of which will be tied into existing Jackfish facilities. These two pads are targeted to come on production in 2026 and keep the Jackfish plants at full capacity.
At Kirby, the Company recently finished drilling a SAGD pad which is targeted to come on production in Q4/25.
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 optimizing solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
At the Company's commercial scale solvent SAGD pad at Kirby North, we began solvent injection in June 2024 and solvent recoveries continue to meet expectations, exceeding 80%. Pad performance monitoring has identified several well pair workover opportunities to further enhance SORs, solvent recovery and production trends. These workovers are targeted to be completed in Q2/25 with continued monitoring over the second half of 2025.
At Primrose, the Company is continuing to operate its solvent enhanced oil recovery pilot in the steam flood area to optimize solvent efficiency and to further evaluate this commercial development opportunity.
North America Oil Sands Mining and Upgrading
|
| Three Months Ended |
|
|
| Mar 31
2025 |
|
| Dec 31
2024 |
|
| Mar 31
2024 |
|
| Synthetic crude oil production (bbl/d) (1)(2) |
| 595,116 |
|
| 534,631 |
|
| 445,209 |
|
(1) SCO production before royalties and excludes production volumes consumed internally as diesel.
(2) Consists of heavy and light synthetic crude oil products. |
|
Oil Sands Mining and Upgrading continues to outperform expectations, through our relentless focus on continuous improvement combined with strong performance from the completed Reliability Enhancement Project at Horizon and Debottleneck Project at the Scotford Upgrader. As a result, the Company achieved strong operational results in Q1/25 as follows:
Record quarterly production of 595,116 bbl/d of SCO was achieved in Q1/25, an increase of 34% or approximately 150,000 bbl/d from Q1/24 levels, reflecting strong operating results, the acquisition of an additional 20% working interest in AOSP in December 2024, and planned and unplanned maintenance a year earlier in Q1/24.
Gross production of approximately 630,000 bbl/d in Q1/25, with upgrader utilization of 106%, was the highest quarterly Oil Sands Mining and Upgrading gross production in the Company's history, as a result of continuous improvement initiatives resulting in strong performance.
Industry leading Oil Sands Mining and Upgrading operating costs of $21.88/bbl (US$15.25/bbl) of SCO were achieved in Q1/25, a decrease of 12% from Q1/24 levels. The decrease in operating costs in Q1/25 compared to Q1/24 was due primarily to higher production volumes and lower energy costs.
Canadian Natural's high value SCO represented approximately 51% of the Company's total liquids volumes in Q1/25 and captured strong quarterly realized SCO pricing of $95.52/bbl, generating significant free cash flow.
As previously announced, the planned AOSP turnaround began on April 4, 2025 and is targeted for 73 days. During this turnaround, the Scotford Upgrader will operate at reduced rates, impacting net annual average production by approximately 31,000 bbl/d, based on Canadian Natural's current 90% working interest.
At Horizon, the Company completed the Reliability Enhancement Project in 2024 which increased the capacity of the zero decline, high value SCO production at Horizon to 264,000 bbl/d over a two year timeframe by shifting the planned turnarounds to once every two years from the previous annual cycle. As a result, 2025 will be the first year without a planned turnaround, resulting in high targeted utilization at Horizon.
With additional infrastructure in place following the completion of this project, the Company can perform certain maintenance activities with zero production impact. Capital savings are targeted to be approximately $75 million in 2025 from 2024 levels as a result of no planned turnaround impacting production.
At Horizon, the Company is progressing its Naphtha Recovery Unit Tailings Treatment ("NRUTT") project which targets incremental production of approximately 6,300 bbl/d of SCO following mechanical completion in Q3/27.
International Exploration and Production
|
| Three Months Ended |
|
|
| Mar 31
2025 |
|
| Dec 31
2024 |
|
| Mar 31
2024 |
|
| Crude oil production (bbl/d) |
| 17,450 |
|
| 23,411 |
|
| 24,823 |
|
| Natural gas production (MMcf/d) |
| 15 |
|
| 10 |
|
| 12 |
|
- International E&P crude oil production volumes averaged 17,450 bbl/d in Q1/25, a decrease of 30% compared to Q1/24 levels primarily reflecting suspended production at Baobab in Offshore Africa due to the planned life extension project on its floating production storage and offloading vessel which commenced in January 2025, which is targeted to impact 2025 net annual production by approximately 7,800 bbl/d, combined with natural field declines. Production at Baobab is targeted to resume in Q2/26.
MARKETING
|
| Three Months Ended |
|
|
| Mar 31
2025 |
| |
| Dec 31
2024 |
|
| Mar 31
2024 |
|
| Benchmark Commodity Prices |
|
|
| |
|
|
|
|
|
|
| WTI benchmark price (US$/bbl) (1) | $ | 71.42 |
| | $ | 70.27 |
| $ | 76.97 |
|
| WCS heavy differential (discount) to WTI (US$/bbl) (1) | $ | (12.66 | ) | | $ | (12.55 | ) | $ | (19.34 | ) |
| WCS heavy differential as a percentage of WTI (%) (1) |
| 18 % |
| |
| 18 % |
|
| 25 % |
|
| Condensate benchmark price (US$/bbl) | $ | 69.89 |
| | $ | 70.66 |
| $ | 72.79 |
|
| SCO price (US$/bbl) (1) | $ | 69.07 |
| | $ | 71.13 |
| $ | 69.43 |
|
| SCO premium (discount) to WTI (US$/bbl) (1) | $ | (2.35 | ) | | $ | 0.86 |
| $ | (7.54 | ) |
| AECO benchmark price (C$/GJ) | $ | 1.92 |
| | $ | 1.38 |
| $ | 1.94 |
|
| Realized Prices |
| |
| |
| |
|
| |
|
| Exploration & Production liquids realized price (C$/bbl) (2)(3)(4)(5) | $ | 79.85 |
| | $ | 75.22 |
| $ | 70.01 |
|
| SCO realized price (C$/bbl) (1)(3)(4)(5) | $ | 95.52 |
| | $ | 95.08 |
| $ | 88.84 |
|
| Natural gas realized price (C$/Mcf) (4) | $ | 3.13 |
| | $ | 2.02 |
| $ | 2.55 |
|
(1) West Texas Intermediate ("WTI"); Western Canadian Select ("WCS"); Synthetic Crude Oil ("SCO").
(2) Exploration & Production crude oil and NGLs average realized price excludes SCO.
(3) Pricing is net of blending and feedstock costs.
(4) Excludes risk management activities.
(5) 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, 2025 dated May 7, 2025. |
|
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$71.42/bbl in Q1/25, comparable to Q4/24 and a decrease of US$5.55/bbl compared to Q1/24 levels. The decrease compared to Q1/24 reflected weaker global demand growth outlooks amid escalating trade tensions, combined with concerns of supply growth from non-OPEC+ producers.
SCO pricing averaged US$69.07/bbl in Q1/25, representing a US$2.35/bbl discount to WTI pricing, compared to a US$0.86/bbl premium to WTI in Q4/24 and a US$7.54 discount to WTI in Q1/24. The SCO differential weakened in Q1/25 relative to Q4/24, driven in part by production levels in the Western Canadian Sedimentary Basin ("WCSB").
The WCS differential to WTI averaged US$12.66/bbl in Q1/25, comparable to Q4/24 and a US$6.68/bbl improvement compared to the US$19.34/bbl discount in Q1/24. The narrowing of the WCS differential to WTI in Q1/25 compared to Q1/24 primarily reflects the start-up of the TMX pipeline in Q2/24, combined with stronger United States Gulf Coast ("USGC") heavy oil pricing.
The North West Redwater refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 83,863 bbl/d in Q1/25.
Canadian Natural has total contracted crude oil transportation capacity of 256,500 bbl/d, with committed volumes to Canada's west coast and to the USGC of approximately 23% of 2025 budgeted liquids production. The egress supports Canadian Natural's long-term sales strategy by targeting expanded refining markets, driving stronger netbacks while also reducing exposure to egress constraints.
The Company has total committed capacity on the TMX pipeline of 169,000 bbl/d providing access to markets on Canada's west coast.
Canadian Natural has total committed capacity of 77,500 bbl/d on the Flanagan South pipeline and an additional 10,000 bbl/d of committed capacity on the Keystone Base pipeline, diversifying the Company's heavy oil access to the USGC.
AECO natural gas prices averaged $1.92/GJ in Q1/25, a $0.54/GJ improvement compared to Q4/24 and comparable to Q1/24. The increase in AECO natural gas pricing compared to Q4/24 primarily reflects stronger NYMEX benchmark pricing, combined with increased exports out of the WCSB. Stronger AECO pricing in Q1/25 also reflects the anticipated start-up of LNG Canada targeted for the second half of 2025.
In 2025, the Company is targeting to use the equivalent of approximately 33% of budgeted natural gas production in its operations, with approximately 35% targeted to be sold at AECO/Station 2 pricing, and approximately 32% 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.
As a result of Canadian Natural's diversified natural gas marketing strategy, the Company's Q1/25 realized natural gas price of $3.13/Mcf represents a $1.07/Mcf or 52% premium over the AECO benchmark price of $2.06/Mcf.
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", "focus", "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 strategy or strategic focus, 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, including the strength of the Company's balance sheet, the sources and adequacy of the Company's liquidity, and the flexibility of the Company's capital structure, 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 ("Primrose"), the Pelican Lake water and polymer flood projects ("Pelican Lake"), the Kirby thermal oil sands project ("Kirby"), the Jackfish thermal oil sands project ("Jackfish") 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 materiality of the impact of tax interpretations and litigation on the Company's results, 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 conflicts in the Middle East, and in 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; changes and uncertainty in the international trade environment, including with respect to tariffs, export restrictions, embargoes and key trade agreements (including tariffs on certain goods announced by the US government and Canadian countermeasures subsequently announced, both of which are anticipated to evolve and may be continued, suspended, increased, decreased, or imposed on additional goods); uncertainty in the regulatory framework governing greenhouse gas emissions including, among other things, financial and other support from various levels of government for climate related initiatives and potential emissions or production caps; political uncertainty, including changes in government, 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 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, competition, environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition 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, the imposition of tariffs, embargoes or export restrictions on the Company's products (including tariffs on certain goods announced by the US government and Canadian countermeasures subsequently announced, both of which are anticipated to evolve and may be continued, suspended, increased, decreased, or imposed on additional goods), 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 Common Share Split and Comparative Figures
At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a Special Resolution approving a two for one common share split effective for shareholders of record as of market close on June 3, 2024. On June 10, 2024, shareholders of record received one additional share for every one common share held, with common shares trading on a split-adjusted basis beginning June 11, 2024. Common share, per common share, dividend, and stock option amounts for periods prior to the two for one common share split have been updated to reflect the common share split.
Special Note Regarding Amendments to the Competition Act (Canada)
On June 20, 2024, amendments to the Competition Act (Canada) came into force with the adoption of Bill C-59, An Act to Implement Certain Provisions of the Fall Economic Statement which impact environmental and climate disclosures by businesses. As a result of these amendments, certain public representations by a business regarding the benefits of the work it is doing to protect or restore the environment or mitigate the environmental and ecological causes or effects of climate change may violate the Competition Act's deceptive marketing practices provisions. These amendments include substantial financial penalties and, effective June 20, 2025, a private right of action which will permit private parties to seek an order from the Competition Tribunal under the deceptive marketing practices provisions. Uncertainty surrounding the interpretation and enforcement of this legislation may expose the Company to increased litigation and financial penalties, the outcome and impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business, reputation, financial condition, and results.
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 MD&A for the three months ended March 31, 2025 and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2024. 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, 2025 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, 2024, is available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. Information in such Annual Information Form and on the Company's website does not form part of and is not incorporated by reference in the Company's MD&A, dated May 7, 2025.
ADVISORY
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 and 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 March 31, 2025, dated May 7, 2025.
Free Cash Flow Allocation Policy
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 targeted amount of shareholder returns after dividends. The amount allocated to shareholders varies depending on the Company's net debt position.
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.
Up to October 2024, before the announcement of the Chevron acquisition, the Company was targeting to allocate 100% of its free cash flow in 2024 to shareholder returns.
In October 2024, with the announcement of the Chevron acquisition, the Board of Directors adjusted the allocation of free cash flow as follows:
60% of free cash flow to shareholder returns and 40% to the balance sheet until net debt reaches $15 billion.
When net debt is between $12 billion and $15 billion, free cash flow allocation will be 75% to shareholder returns and 25% to the balance sheet.
When net debt is at or below $12 billion, free cash flow allocation will be 100% to shareholder returns.
The Company's free cash flow for the three months ended March 31, 2025 is shown below:
|
| Three Months Ended |
|
| ($ millions) |
| Mar 31
2025 |
|
| Dec 31
2024 |
|
| Mar 31
2024 |
|
| Adjusted funds flow (1) | $ | 4,530 |
| $ | 4,186 |
| $ | 3,138 |
|
| Less: Dividends on common shares |
| 1,184 |
|
| 1,110 |
|
| 1,076 |
|
| Net capital expenditures,(2) excluding net acquisition costs (3) |
| 1,303 |
|
| 1,290 |
|
| 1,113 |
|
| Abandonment expenditures |
| 188 |
|
| 151 |
|
| 162 |
|
| Free cash flow | $ | 1,855 |
| $ | 1,635 |
| $ | 787 |
|
(1) 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, 2025, dated May 7, 2025.
(2) Net Capital expenditures is a 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, 2025, dated May 7, 2025.
(3) Excludes net acquisition costs of $9,058 million for the three months ended December 31, 2024 related to the acquisition of assets in the period. |
|
Long-term Debt, net
Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents.
| ($ millions) |
| Mar 31
2025 |
|
| Dec 31
2024 |
|
| Mar 31
2024 |
|
| Long-term debt | $ | 17,428 |
| $ | 18,819 |
| $ | 11,040 |
|
| Less: cash and cash equivalents |
| 93 |
|
| 131 |
|
| 767 |
|
| Long-term debt, net | $ | 17,335 |
| $ | 18,688 |
| $ | 10,273 |
|
Breakeven WTI Price
The breakeven 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 breakeven WTI price a key measure in evaluating its performance, as it demonstrates the efficiency and profitability of the Company's activities. The breakeven 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 includes acquisition capital related to a number of acquisitions for which agreements between parties have been reached as at the time of the Company's 2025 budget press release on January 9, 2025. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for more details on net capital expenditures.
The 2025 capital budget reflects budgeted net capital expenditures, before abandonment expenditures related to the execution of the Company's abandonment and reclamation programs in North America and the North Sea. The Company currently carries an Asset Retirement Obligation ("ARO") liability on its balance sheet for these budgeted future expenditures. Abandonment expenditures are reported before the impact of current income tax recoveries. Current tax recoveries are refundable at a rate of approximately 23% in Canada and a combined current income tax and Petroleum Revenue Tax ("PRT") rate approximating 70% to 75% in the UK portion of the North Sea. The Company is eligible to recover interest on refunded PRT previously paid.
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.
CONFERENCE CALL
Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) will be issuing its 2025 First Quarter Earnings Results on Thursday, May 8, 2025 before market open.
A conference call will be held at 7:00 a.m. MDT / 9:00 a.m. EDT on Thursday, May 8, 2025.
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: 62718#)
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 | |
| |
| |
| |
| |
| | SCOTT G. STAUTH
President
VICTOR C. DAREL
Chief Financial Officer
LANCE J. CASSON
Manager, Investor Relations
Trading Symbol - CNQ
Toronto Stock Exchange
New York Stock Exchange | |
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