Calgary, Alberta--(Newsfile Corp. - March 6, 2025) - Canadian Natural's (TSX: CNQ) (NYSE: CNQ) President, Scott Stauth, commented on the Company's 2024 fourth quarter and year end results, "2024 was an excellent year for us, as we achieved strong growth and set several new production records from our base operations, before including acquisitions that closed in 2024. Additionally, including acquisitions, we achieved record annual average production of over 1,363,000 BOE/d in 2024, which includes record annual liquids production of over one million barrels per day. At our world class Oil Sands Mining and Upgrading assets, we achieved record quarterly and annual Synthetic Crude Oil ("SCO") production of approximately 535,000 bbl/d and 472,000 bbl/d respectively. This strong operational performance resulted in a high annual utilization rate of 99%, anchored by industry leading SCO operating costs of $20.97/bbl (US$15.00/bbl) for Q4/24 and $22.88/bbl (US$16.70/bbl) for full year 2024, which drove significant free cash flow in the year. Thermal in situ production also reached record annual production levels of approximately 271,000 bbl/d combined with strong operating costs of $11.04/bbl (US$8.06/bbl). Our conventional crude oil and liquids-rich natural gas operations continue to provide significant free cash flow with further potential for flexible organic growth. When combined with our entire portfolio, we have significant organic growth opportunities.
Following the previously announced acquisition at the Athabasca Oil Sands Project ("AOSP") that closed in December 2024, and the AOSP swap transaction targeted to close in the first half of 2025, Canadian Natural's working interest will be 100% in the Albian mines and 80% in the non-operated Scotford Upgrader. Further, when combined with Horizon, our total oil sands mining production capacity is currently targeted at approximately 592,000 bbl/d, up from 570,000 bbl/d, following completion of the Horizon Reliability Enhancement Project and the Debottleneck Project at the Scotford Upgrader in 2024. These acquisitions are immediately cash flow accretive and when combined with the production capacity increases, drive significant value to shareholders for decades with no production decline. With our long history of driving value through continuous improvement that is engrained in our culture, we remain focused on delivering additional value from these world class assets, providing incremental and sustainable free cash flow.
Canadian Natural's reserves compete on a global scale supporting long-term organic growth opportunities, with total proved reserves of 15.2 billion BOE and total proved plus probable reserves of 20.1 billion BOE as of year end 2024, both of which increased 9% from year end 2023 levels. With approximately 74% of the Company's total proved reserves being long life low decline, the strength and depth of our assets is evident and provides us with a total proved reserves life index ("RLI") of 33 years and a total proved plus probable RLI of 44 years. This includes Oil Sands Mining and Upgrading reserves that have a total proved RLI of 43 years, providing significant production for decades.
We have a long track record of consistently delivering strong, industry leading results driven by our safe, reliable operations and relentless focus on continuous improvement, which maximizes long-term shareholder value."
Canadian Natural's Chief Financial Officer, Mark Stainthorpe, added "In 2024, we delivered strong financial results, with annual adjusted net earnings of approximately $7.4 billion and adjusted funds flow of $14.9 billion, including Q4/24 adjusted net earnings of approximately $2.0 billion and adjusted funds flow of $4.2 billion. We returned approximately $7.1 billion to shareholders in 2024, inclusive of our sustainable and growing dividend and share repurchases. We increased our quarterly dividend twice in 2024 and subsequent to year end, the Board approved a 4% increase to $2.35 per common share annualized, with 2025 being the 25th consecutive year of dividend increases by Canadian Natural, with a compound annual growth rate ("CAGR") of 21% over that time.
After the recent acquisitions, our US$ WTI breakeven remains top tier in the low to mid-$40 per barrel range and our balance sheet remains strong with year end metrics including Debt to Book Capitalization at 32% and Debt to Adjusted EBITDA at 1.1x. Our large, diverse portfolio is supported by long life low decline assets, which drive top tier operating costs and low maintenance capital. When combined, it results in significant and sustainable free cash flow that we can repeat for decades."
KEY 2024 ANNUAL OPERATIONAL HIGHLIGHTS
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Record total production of approximately 1,363,000 BOE/d.
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Record total corporate liquids production of approximately 1,006,000 bbl/d.
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Strong total corporate liquids operating costs(1) of $18.56/bbl (US$13.55/bbl).
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Record Oil Sands Mining and Upgrading production of approximately 472,000 bbl/d of zero decline SCO, with upgrader utilization of 99%, including planned turnarounds.
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Industry leading Oil Sands Mining and Upgrading operating costs of $22.88/bbl (US$16.70/bbl) of SCO.
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Record thermal in situ production of approximately 271,000 bbl/d of long life low decline production.
- Strong thermal in situ operating costs of $11.04/bbl (US$8.06/bbl).
KEY 2024 FOURTH QUARTER OPERATIONAL HIGHLIGHTS
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Record total production of approximately 1,470,000 BOE/d.
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Record total corporate liquids production of approximately 1,090,000 bbl/d.
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Strong total corporate liquids operating costs of $16.98/bbl (US$12.14/bbl).
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Record Oil Sands Mining and Upgrading production of approximately 535,000 bbl/d of zero decline SCO, with upgrader utilization of 105%, including planned turnarounds.
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Industry leading Oil Sands Mining and Upgrading operating costs of $20.97/bbl (US$15.00/bbl) of SCO.
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Record natural gas production of 2,283 MMcf/d.
CREATING LONG-TERM SHAREHOLDER VALUE
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Canadian Natural has unlocked significant long-term shareholder value at the Albian mines and Scotford Upgrader ("AOSP") since its initial acquisition of a 70% working interest in 2017, followed by 20% in December 2024 and the final 10% in the Muskeg River and Jackpine mines ("Albian mines"), which is targeted to close in the first half of 2025. The Company has strategically acquired this world class asset and added significant value by increasing production and reducing operating costs through implementing process improvements and optimization projects to improve reliability and increase utilization. Since 2017, Canadian Natural has:
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Increased gross production at the Albian mines by 30% or over 70,000 bbl/d. Upgrader capacity was also increased to match the increased production from the mines.
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Decreased AOSP per unit operating costs by over 30% or approximately $10/bbl. This equates to incremental margin of approximately $0.8 billion based on 2024 production.
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With 100% working interest in the Albian mines, once the swap transaction closes, Canadian Natural is targeting to unlock further value through its effective and efficient operations and relentless continuous improvement culture.
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Subsequent to year end, Oil Sands Mining and Upgrading continued to achieve strong production and high utilization. In January 2025 and February 2025, production averaged on a gross basis approximately 634,000 bbl/d over the two months. February 2025 was the highest monthly gross production in our history at approximately 640,000 bbl/d as we focus on continuous improvement initiatives combined with strong performance from the Reliability Enhancement Project at Horizon and Debottleneck Project at the Scotford Upgrader.
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Additionally, further value has been unlocked from piping modifications completed during the recent Debottleneck Project at the Scotford Upgrader. These modifications unlock approximately 5,000 bbl/d of annual gross production from the Albian mines, resulting in higher utilization during planned upgrader turnarounds. This increased zero decline production will continue to benefit Canadian Natural for decades, including our increased ownership in the Albian mines.
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The Company's 2025 corporate production guidance will be increased following the closing of the previously announced swap transaction where Canadian Natural will add approximately 31,000 bbl/d of bitumen.
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(1) Operating costs are calculated as production expense divided by respective sales volumes. Natural gas and NGLs production volumes approximate sales volumes.
HIGHLIGHTS
| Three Months Ended | Year Ended | |||||||||||||||
| ($ millions, except per common share amounts) | Dec 31 2024 |
Sep 30 2024 |
Dec 31 2023 |
Dec 31 2024 |
Dec 31 2023 |
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| Net earnings | $ | 1,138 | $ | 2,266 | $ | 2,627 | $ | 6,106 | $ | 8,233 | ||||||
| Per common share (1) | - basic | $ | 0.54 | $ | 1.07 | $ | 1.22 | $ | 2.87 | $ | 3.77 | |||||
| - diluted | $ | 0.54 | $ | 1.06 | $ | 1.21 | $ | 2.85 | $ | 3.74 | ||||||
| Adjusted net earnings from operations (2) | $ | 1,977 | $ | 2,071 | $ | 2,546 | $ | 7,414 | $ | 8,533 | ||||||
| Per common share (1) | - basic (3) | $ | 0.94 | $ | 0.98 | $ | 1.18 | $ | 3.49 | $ | 3.91 | |||||
| - diluted (3) | $ | 0.93 | $ | 0.97 | $ | 1.17 | $ | 3.46 | $ | 3.87 | ||||||
| Cash flows from operating activities | $ | 3,432 | $ | 3,002 | $ | 4,815 | $ | 13,386 | $ | 12,353 | ||||||
| Adjusted funds flow (2) | $ | 4,186 | $ | 3,921 | $ | 4,419 | $ | 14,859 | $ | 15,274 | ||||||
| Per common share (1) | - basic (3) | $ | 1.99 | $ | 1.85 | $ | 2.05 | $ | 6.99 | $ | 7.00 | |||||
| - diluted (3) | $ | 1.97 | $ | 1.84 | $ | 2.03 | $ | 6.94 | $ | 6.93 | ||||||
| Cash flows used in investing activities | $ | 10,414 | $ | 1,274 | $ | 946 | $ | 14,095 | $ | 4,858 | ||||||
| Net capital expenditures (4) | $ | 10,348 | $ | 1,349 | $ | 975 | $ | 14,431 | $ | 4,909 | ||||||
| Net capital expenditures, excluding net acquisition costs (5) | $ | 1,290 | $ | 1,349 | $ | 1,019 | $ | 5,286 | $ | 4,883 | ||||||
| Abandonment expenditures | $ | 151 | $ | 204 | $ | 149 | $ | 646 | $ | 509 | ||||||
| Daily production, before royalties | ||||||||||||||||
| Natural gas (MMcf/d) | 2,283 | 2,049 | 2,231 | 2,147 | 2,151 | |||||||||||
| Crude oil and NGLs (bbl/d) | 1,090,002 | 1,021,572 | 1,047,541 | 1,005,603 | 973,530 | |||||||||||
| Equivalent production (BOE/d) (6) | 1,470,428 | 1,363,086 | 1,419,313 | 1,363,496 | 1,332,105 | |||||||||||
| (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 and year ended December 31, 2024 dated March 5, 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 and year ended December 31, 2024 dated March 5, 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 and year ended December 31, 2024 dated March 5, 2025. (4) Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2024 and 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 and year ended December 31, 2024 dated March 5, 2025. (5) Calculated as net capital expenditures, less net property acquisitions (dispositions) for exploration and evaluation assets and property, plant and equipment for Exploration and Production and Oil Sands Mining and Upgrading, as reported in the Company's MD&A. (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. |
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ANNUAL HIGHLIGHTS
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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 2024, the Company generated strong financial results, including:
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Net earnings of approximately $6.1 billion and adjusted net earnings from operations of approximately $7.4 billion.
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Cash flows from operating activities of approximately $13.4 billion.
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Adjusted funds flow of approximately $14.9 billion.
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The Company's disciplined 2024 operating capital program, excluding net acquisition costs, was approximately $100 million under budget at $5.3 billion. Abandonment expenditures were essentially on budget.
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Our 2025 disciplined operating capital budget of approximately $6.0 billion, along with $787 million of abandonment expenditures before recoveries, $90 million on carbon capture and $45 million on a one-time office move, all remain on track.
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In 2024, Canadian Natural delivered record annual average production of 1,363,496 BOE/d, an increase of 2% or approximately 31,400 BOE/d from 2023 levels, or 5% on a production per share basis.
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The Company achieved record annual total liquids production of 1,005,603 bbl/d in 2024, an increase of 3% or approximately 32,000 bbl/d from 2023 levels. Strong annual liquids production in 2024 was driven by:
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Record annual Oil Sands Mining and Upgrading production of 472,245 bbl/d of SCO in 2024, an increase of 5% or approximately 21,000 bbl/d from 2023 levels.
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Industry leading annual Oil Sands Mining and Upgrading operating costs of $22.88/bbl (US$16.70/bbl) of SCO were achieved in 2024, a decrease of 6% from 2023 levels.
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Record annual thermal in situ production of 271,011 bbl/d, an increase of 3% or approximately 9,000 bbl/d from 2023 levels.
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Annual thermal in situ operating costs were strong, averaging $11.04/bbl (US$8.06/bbl) in 2024, a decrease of 16% from 2023 levels.
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During 2024, the Company increased its contracted crude oil transportation capacity to 256,500 bbl/d, expanding its committed volumes to Canada's west coast and to the United States Gulf Coast ("USGC") to approximately 23% of 2025 targeted liquids production based on the mid-point of 2025 corporate annual guidance. The additional egress supports Canadian Natural's long-term sales strategy by targeting expanded refining markets, driving stronger netbacks while also reducing exposure to egress constraints.
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In December 2024, the Company increased its total committed capacity on the Trans Mountain Expansion ("TMX") pipeline to 169,000 bbl/d, an incremental 75,000 bbl/d, further expanding access to Canada's west coast.
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In Q1/24, the Company increased its total committed capacity on the Flanagan South pipeline to 77,500 bbl/d, an incremental 55,000 bbl/d, further expanding the Company's heavy oil diversification and market access to the USGC.
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The Company also has committed capacity of 10,000 bbl/d on the Keystone Base pipeline, with direct access to the USGC.
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In December 2024, Canadian Natural closed the acquisition of Chevron's Alberta assets, including a 20% interest in AOSP and a 70% operated working interest in light crude oil and liquids-rich natural gas assets in the Duvernay play. Both of these acquisitions are targeted to contribute significant additional free cash flow to the Company.
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This acquisition brought Canadian Natural's total working interest in AOSP to 90%, adding approximately 62,500 bbl/d of long life no decline SCO production.
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The Duvernay assets add approximately 60,000 BOE/d in 2025, consisting of 30,000 bbl/d of liquids and 179 MMcf/d of natural gas, providing meaningful near term, drill to fill, liquids-rich natural gas growth.
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Subsequent to year end, Canadian Natural announced an agreement to swap Shell's remaining 10% working interest in the Albian mines for 10% working interest in the Scotford Upgrader and Quest Carbon Capture and Storage facilities. After closing, this swap brings Canadian Natural's total working interest in the Albian mines to 100% and adds approximately 31,000 bbl/d of incremental bitumen production.
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Following closing of the swap transaction, total Oil Sands Mining and Upgrading production capacity increases to approximately 592,000 bbl/d, 90% of which is SCO.
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Canadian Natural maintains a strong balance sheet and financial flexibility, with approximately $4.7 billion in liquidity(1) as at December 31, 2024. Debt ratios remain strong with a Debt to Book Capitalization of 32% and a Debt to Adjusted EBITDA of 1.1x. The Company executed on a number of initiatives in 2024 to strengthen its financial flexibility, including:
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Repaid $320 million of medium-term notes and US$500 million of US debt securities.
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Issued $500 million of medium-term notes and US$1,500 million of US debt securities.
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In connection with the acquisition of assets from Chevron (CVX), the Company entered into a $4,000 million non-revolving term credit facility maturing December 2027.
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Extended the Company's $2,425 million revolving syndicated credit facility from June 2025 to June 2028, and its $500 million revolving credit facility from February 2025 to February 2026.
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Subsequent to year end, the Company repaid US$600 million due February 2025.
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(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 and year ended December 31, 2024 dated March 5, 2025.
QUARTERLY HIGHLIGHTS
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In Q4/24, the Company generated strong financial results, including:
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Net earnings of approximately $1.1 billion and adjusted net earnings from operations of approximately $2.0 billion.
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Cash flows from operating activities of approximately $3.4 billion.
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Adjusted funds flow of approximately $4.2 billion.
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Canadian Natural achieved record quarterly average production of 1,470,428 BOE/d in Q4/24, consisting of record liquids production of 1,090,002 bbl/d and record natural gas production of 2,283 MMcf/d. The total BOE/d production represents a 4% increase from Q4/23 levels and an 8% increase from Q3/24 levels.
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Oil Sands Mining and Upgrading achieved record quarterly production of 534,631 bbl/d of SCO in Q4/24, including planned turnaround activities. Quarterly production volumes increased 7% or approximately 34,500 bbl/d from Q4/23 levels.
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Industry leading annual Oil Sands Mining and Upgrading operating costs of $20.97/bbl (US$15.00/bbl) were achieved in Q4/24.
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At AOSP, the planned turnaround was successfully completed on October 18, 2024. Due to strong execution, the annual net production impact to AOSP from the planned turnaround was reduced to approximately 5,400 bbl/d, a significant improvement compared to the budgeted annual net production impact of 11,000 bbl/d.
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Additionally, a Debottleneck Project was completed at the Scotford Upgrader which increased gross capacity at AOSP by approximately 8,000 bbl/d in October 2024.
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RETURNS TO SHAREHOLDERS
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Returns to shareholders in 2024 were significant, totaling approximately $7.1 billion, comprised of $4.4 billion of dividends and $2.7 billion through the repurchase and cancellation of approximately 55.4 million common shares at a weighted average price of $48.07 per share.
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In Q4/24, the Company returned a total of approximately $1.7 billion directly to shareholders through $1.1 billion in dividends and $0.6 billion through the repurchase and cancellation of approximately 11.7 million common shares at a weighted average price of $47.08 per share.
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Free cash flow is defined as adjusted funds flow, less capital and dividends. 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. As previously disclosed on October 7, 2024, the Board of Directors has adjusted the free cash flow allocation policy as follows:
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60% of free cash flow to shareholder returns and 40% to the balance sheet until net debt reaches $15 billion.
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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.
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When net debt is at or below $12 billion, free cash flow allocation will be 100% to shareholder returns.
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Subsequent to year end, the Board of Directors approved a 4% increase to the quarterly cash dividend to $0.5875 per common share, from $0.5625 per common share, payable on April 4, 2025 to shareholders of record at the close of business on March 21, 2025. This represents an annualized dividend of $2.35 per common share.
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The Company has a leading track record of dividend increases, with 2025 being the 25th consecutive year of dividend increases, with a CAGR of 21% over that time. This demonstrates the confidence that the Board 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.
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Subsequent to year end, on March 5, 2025, the Board of Directors approved the renewal of the Company's Normal Course Issuer Bid ("NCIB"), which states that during the 12 month period commencing on March 13, 2025 and ending on March 12, 2026, the Company can repurchase for cancellation up to 10% of the public float (as determined in accordance with the rules of the TSX), subject to TSX approval.
RESERVES HIGHLIGHTS
A key differentiator for Canadian Natural is the strength, diversity and balance of its world class, top tier assets. The Company's total proved reserve life index ("RLI")(1) of 33 years is supported by long life low decline assets that have been strategically assembled and developed over several decades. The low maintenance capital requirements relative to the size and quality of the reserves affords the Company significant flexibility when balancing its four pillars of capital allocation to maximize shareholder value.
The Company's reserves were evaluated and reviewed by Independent Qualified Reserves Evaluators ("IQREs"). The following highlights are based on the Company's reserves using forecast prices and costs at December 31, 2024 (all reserves values are Company Gross unless stated otherwise).
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Total proved reserves increased 9% to 15.231 billion BOE, with reserves additions and revisions of 1.820 billion BOE. Total proved plus probable reserves increased 9% to 20.110 billion BOE, with reserves additions and revisions of 2.105 billion BOE.
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The strength and depth of the Company's assets are evident as approximately 74% of total proved reserves are long life low decline reserves. This results in a total proved BOE RLI of 33 years and a total proved plus probable BOE RLI of 44 years.
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Additionally, high value, zero decline SCO represents approximately 50% of total proved reserves with a RLI of 43 years.
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Proved developed producing reserves additions and revisions are 1.322 million BOE, replacing 2024 production by 265%. The proved developed producing BOE RLI is 21 years.
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Total proved reserves additions and revisions replaced 2024 production by 365%. Total proved plus probable reserves additions and revisions replaced 2024 production by 422%.
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In 2024, Canadian Natural continued to achieve strong finding and development costs:
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Finding, development and acquisition ("FD&A")(1) costs, excluding changes in Future Development Cost ("FDC"), are $7.82/BOE for total proved reserves and $6.76/BOE for total proved plus probable reserves.
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FD&A costs, including changes in FDC, are $13.56/BOE for total proved reserves and $12.60/BOE for total proved plus probable reserves.
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The net present value of future net revenues, before income tax, discounted at 10%, is $118.3 billion for proved developed producing reserves, $170.2 billion for total proved reserves, and $205.7 billion for total proved plus probable reserves.
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The Company's total proved net asset value ("NAV") per share increased to $74.83 per share in 2024 from $69.53 per share in 2023 after adjusting for asset retirement obligations, net debt and the share split that occurred in June 2024. Total proved plus probable NAV per share increased to $91.72 per share in 2024 from $84.83 per share in 2023.
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(1) Supplementary financial measure. Refer to the "2024 Year End Reserves" section of this document.
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 | Year Ended | |||||||||||
| December 31, 2024 | December 31, 2023 | |||||||||||
| (number of wells) | Gross | Net | Gross | Net | ||||||||
| Crude oil (1) | 313 | 307 | 228 | 221 | ||||||||
| Natural gas | 94 | 78 | 78 | 61 | ||||||||
| Dry | 2 | 2 | 2 | 2 | ||||||||
| Subtotal | 409 | 387 | 308 | 284 | ||||||||
| Stratigraphic test / service wells | 474 | 407 | 481 | 419 | ||||||||
| Total | 883 | 794 | 789 | 703 | ||||||||
| Success rate (excluding stratigraphic test / service wells) | 99 % | 99 % | ||||||||||
| (1) Includes bitumen wells. | ||||||||||||
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Canadian Natural drilled a total of 387 net crude oil and natural gas producer wells in 2024, 103 more than in 2023.
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In 2024, the Company reallocated capital from certain dry natural gas development activity to multilateral primary heavy crude oil wells, given the success of our multilateral programs and low natural gas prices in 2024.
North America Exploration and Production
| Crude oil and NGLs - excluding Thermal In Situ Oil Sands | |||||||||||||||
| Three Months Ended | Year Ended | ||||||||||||||
| Dec 31 2024 |
Sep 30 2024 |
Dec 31 2023 |
Dec 31 2024 |
Dec 31 2023 |
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| Crude oil and NGLs production (bbl/d) | 255,729 | 228,221 | 243,157 | 238,277 | 234,100 | ||||||||||
| Net wells targeting crude oil | 84 | 59 | 42 | 214 | 173 | ||||||||||
| Net successful wells drilled | 84 | 58 | 42 | 213 | 171 | ||||||||||
| Success rate | 100 % | 98 % | 100 % | 99 % | 99 % | ||||||||||
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North America E&P liquids annual production, excluding thermal in situ, averaged 238,277 bbl/d in 2024, a 2% increase from 2023 levels, reflecting strong results from our liquids-rich natural gas and primary heavy crude oil drilling activity as well as the recently acquired Duvernay assets.
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Primary heavy crude oil production averaged 79,128 bbl/d in 2024, a 2% increase from 2023 levels, reflecting strong drilling results from the Company's multilateral wells, partially offset by natural field declines.
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Canadian Natural drilled 121 net horizontal multilateral primary heavy crude oil wells in 2024, compared to 104 in 2023. Multilateral wells combine increased reservoir capture and higher production with reduced servicing requirements which lowers operating costs. The Company continues to optimize well design and lengths in our highly successful multilateral program, achieving top tier average initial peak rates of approximately 250 bbl/d per well, which is 43% higher than budget average initial peak rates of 175 bbl/d per well, and a further 9% higher than the previously disclosed rate of 230 bbl/d.
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Operating costs in the Company's primary heavy crude oil operations averaged $18.11/bbl (US$13.22/bbl) in 2024, a decrease of 9% from 2023 levels, primarily reflecting lower energy and service costs.
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Pelican Lake production averaged 44,779 bbl/d in 2024, a decrease of 5% from 2023 levels, reflecting low natural field declines from this long life low decline asset, partially offset by increased drilling activity in 2024.
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Operating costs at Pelican Lake averaged $9.11/bbl (US$6.65/bbl) in 2024, an increase of 6% compared to 2023 levels, primarily reflecting lower volumes.
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North America light crude oil and NGLs production averaged 114,370 bbl/d in 2024, an increase of 5% compared to 2023 levels, primarily driven by strong organic growth in liquids-rich natural gas as well as the recently acquired Duvernay assets.
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Operating costs in the Company's North America light crude oil and NGLs operations averaged $13.55/bbl (US$9.89/bbl) in 2024, a decrease of 17% over 2023 levels, primarily reflecting higher volumes and lower energy costs.
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| North America Natural Gas | |||||||||||||||
| Three Months Ended | Year Ended | ||||||||||||||
| Dec 31 2024 |
Sep 30 2024 |
Dec 31 2023 |
Dec 31 2024 |
Dec 31 2023 |
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| Natural gas production (MMcf/d) | 2,273 | 2,039 | 2,218 | 2,136 | 2,139 | ||||||||||
| Net wells targeting natural gas | 14 | 24 | 9 | 79 | 61 | ||||||||||
| Net successful wells drilled | 14 | 24 | 9 | 78 | 61 | ||||||||||
| Success rate | 100 % | 100 % | 100 % | 99 % | 100 % | ||||||||||
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North America natural gas annual production averaged 2,136 MMcf/d in 2024, comparable to 2023 levels. The Company remained focused on liquids-rich natural gas activity in the Montney and Deep Basin, while certain dry natural gas drilling activity in 2024 was deferred due to low natural gas prices.
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Canadian Natural drilled a total of 79 net natural gas wells in 2024, 12 fewer than originally budgeted, as a result of the Company's strategic decision to reduce dry natural gas activity due to low natural gas prices.
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North America natural gas operating costs averaged $1.19/Mcf in 2024, a 6% decrease compared to 2023 levels, primarily reflecting lower energy costs.
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| Thermal In Situ Oil Sands | |||||||||||||||
| Three Months Ended | Year Ended | ||||||||||||||
| Dec 31 2024 |
Sep 30 2024 |
Dec 31 2023 |
Dec 31 2024 |
Dec 31 2023 |
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| Bitumen production (bbl/d) | 276,231 | 271,551 | 278,422 | 271,011 | 262,000 | ||||||||||
| Net wells targeting bitumen | 16 | 25 | - | 94 | 50 | ||||||||||
| Net successful wells drilled | 16 | 25 | - | 94 | 50 | ||||||||||
| Success rate | 100 % | 100 % | - % | 100 % | 100 % | ||||||||||
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Record annual thermal in situ production of 271,011 bbl/d, an increase of 3% or approximately 9,000 bbl/d from 2023 levels as a result of the Company's capital efficient thermal pad add development program.
-
Annual thermal in situ operating costs were strong, averaging $11.04/bbl (US$8.06/bbl) in 2024, a decrease of 16% from 2023 levels, primarily reflecting lower energy costs and higher production volumes.
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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.
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At Wolf Lake, the Company brought a steam assisted gravity drainage ("SAGD") pad on production ahead of schedule in Q4/24, originally targeted for Q1/25.
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At Primrose, the Company brought a CSS pad on production ahead of schedule in Q4/24, originally targeted for Q2/25. A second CSS pad has been drilled and is targeted to come on production ahead of schedule in late Q1/25, originally budgeted for Q2/25.
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At Jackfish, the Company finished drilling a SAGD pad in Q4/24, with production targeted to come on in Q3/25.
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At Pike, the Company is drilling two SAGD pads in the first half of 2025 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.
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At Kirby, the Company is currently drilling a SAGD pad which is targeted to come on production in Q4/25 with a second SAGD pad targeted to be drilled in Q4/25 and come on production in Q4/26.
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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.
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At the Company's commercial scale solvent SAGD pad at Kirby North, we began solvent injection in June 2024. Results to-date have been positive with recent SOR reductions of approximately 30%, trending towards a targeted reduction of 40% to 50%. Solvent recoveries continue to meet expectations, exceeding 80%. The Company will continue to monitor SORs, solvent recovery and production trends.
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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.
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North America Oil Sands Mining and Upgrading
| Three Months Ended | Year Ended | ||||||||||||||
| Dec 31 2024 |
Sep 30 2024 |
Dec 31 2023 |
Dec 31 2024 |
Dec 31 2023 |
|||||||||||
| Synthetic crude oil production (bbl/d) (1)(2) | 534,631 | 497,656 | 500,133 | 472,245 | 451,339 | ||||||||||
| (1) SCO production before royalties and excludes production volumes consumed internally as diesel. (2) Consists of heavy and light synthetic crude oil products. |
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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 2024, as follows:
-
Record annual Oil Sands Mining and Upgrading production of 472,245 bbl/d of SCO in 2024, an increase of 5% or approximately 21,000 bbl/d from 2023 levels.
-
Record quarterly production of 534,631 bbl/d of SCO was achieved in Q4/24, including planned turnaround activities. Quarterly production volumes increased 7% or approximately 34,500 bbl/d from Q4/23 levels.
-
At AOSP, the planned turnaround was successfully completed on October 18, 2024. Due to strong execution, the annual net production impact to AOSP from the planned turnaround was reduced to approximately 5,400 bbl/d, a significant improvement compared to the budgeted net production impact of 11,000 bbl/d.
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Industry leading annual Oil Sands Mining and Upgrading operating costs of $22.88/bbl (US$16.70/bbl) of SCO were achieved in 2024, a decrease of 6% from 2023 levels. The decrease in 2024 operating costs compared to 2023 was due primarily to higher production volumes and lower energy costs.
-
Canadian Natural's high value SCO represented approximately 47% of the Company's total liquids volumes in 2024 and captured strong annual realized SCO pricing of $98.03/bbl in 2024, generating significant free cash flow.
-
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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.
-
-
A Debottleneck Project was completed at the Scotford Upgrader which increased gross capacity at AOSP by approximately 8,000 bbl/d to 328,000 bbl/d in October 2024.
-
Subsequent to year end, Oil Sands Mining and Upgrading continued to achieve strong production and high utilization. In January 2025 and February 2025, production averaged on a gross basis approximately 634,000 bbl/d over the two months. February 2025 was the highest monthly gross production in our history at approximately 640,000 bbl/d as we focus on continuous improvement initiatives combined with strong performance from the Reliability Enhancement Project at Horizon and Debottleneck Project at the Scotford Upgrader.
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Additionally, further value has been unlocked from piping modifications completed during the recent Debottleneck Project at the Scotford Upgrader. These modifications unlock approximately 5,000 bbl/d of annual gross production from the Albian mines, resulting in higher utilization during planned upgrader turnarounds. This increased zero decline production will continue to benefit Canadian Natural for decades, including our increased ownership in the Albian mines.
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As previously announced with the 2025 budget, the only planned turnaround in 2025 in the Oil Sands Mining and Upgrading operations is at AOSP, where the Scotford Upgrader is targeted to operate at reduced rates for 73 days, impacting net annual average production by approximately 31,000 bbl/d, based on Canadian Natural's current 90% working interest.
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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 | Year Ended | ||||||||||||||
| Dec 31 2024 |
Sep 30 2024 |
Dec 31 2023 |
Dec 31 2024 |
Dec 31 2023 |
|||||||||||
| Crude oil production (bbl/d) | 23,411 | 24,144 | 25,829 | 24,070 | 26,091 | ||||||||||
| Natural gas production (MMcf/d) | 10 | 10 | 13 | 11 | 12 | ||||||||||
- International E&P crude oil production volumes averaged 24,070 bbl/d in 2024, a decrease of 8% compared to 2023 levels primarily due to natural field declines.
MARKETING
| Three Months Ended | Year Ended | ||||||||||||||||
| Dec 31 2024 |
Sep 30 2024 |
Dec 31 2023 |
Dec 31 2024 |
Dec 31 2023 |
|||||||||||||
| Benchmark Commodity Prices | |||||||||||||||||
| WTI benchmark price (US$/bbl) (1) | $ | 70.27 | $ | 75.16 | $ | 78.33 | $ | 75.72 | $ | 77.61 | |||||||
| WCS heavy differential (discount) to WTI (US$/bbl) (1) |
$ | (12.55 | ) | $ | (13.51 | ) | $ | (21.90 | ) | $ | (14.73 | ) | $ | (18.62 | ) | ||
| WCS heavy differential as a percentage of WTI (%) (1) |
18 % | 18 % | 28 % | 19 % | 24 % | ||||||||||||
| Condensate benchmark price (US$/bbl) | $ | 70.66 | $ | 71.24 | $ | 76.22 | $ | 72.94 | $ | 76.55 | |||||||
| SCO price (US$/bbl) (1) | $ | 71.13 | $ | 76.51 | $ | 78.64 | $ | 75.09 | $ | 79.64 | |||||||
| SCO premium (discount) to WTI (US$/bbl) (1) | $ | 0.86 | $ | 1.35 | $ | 0.31 | $ | (0.63 | ) | $ | 2.03 | ||||||
| AECO benchmark price (C$/GJ) | $ | 1.38 | $ | 0.77 | $ | 2.52 | $ | 1.36 | $ | 2.77 | |||||||
| Realized Prices | |||||||||||||||||
| Exploration & Production liquids realized price (C$/bbl) (2)(3)(4)(5) |
$ | 75.22 | $ | 79.15 | $ | 69.39 | $ | 77.76 | $ | 72.36 | |||||||
| SCO realized price (C$/bbl) (1)(3)(4)(5) | $ | 95.08 | $ | 100.93 | $ | 98.73 | $ | 98.03 | $ | 100.06 | |||||||
| Natural gas realized price (C$/Mcf) (4) | $ | 2.02 | $ | 1.25 | $ | 2.80 | $ | 1.86 | $ | 3.10 | |||||||
| (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 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 and year ended December 31, 2024 dated March 5, 2025. |
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Canadian Natural has a balanced and diverse product mix of natural gas, NGLs, heavy crude oil, light crude oil, bitumen and SCO.
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WTI prices averaged US$75.72/bbl in 2024, a decrease of US$1.89/bbl compared to 2023, primarily reflecting weaker global demand growth and concerns of higher non-OPEC+ supply, partially offset by continued supply quota management by OPEC+, and geopolitical tensions in the Middle East.
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SCO pricing averaged US$75.09/bbl in 2024, representing a US$0.63/bbl price discount to WTI pricing, compared to a US$2.03/bbl price premium to WTI in 2023.
-
The WCS differential to WTI averaged US$14.73/bbl, tightening by US$3.89/bbl in 2024, compared to US$18.62/bbl in 2023, primarily reflecting the start-up of the TMX pipeline in Q2/24, combined with stronger USGC heavy oil pricing.
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The North West Redwater ("NWR") refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 77,742 bbl/d in Q4/24.
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During 2024, the Company increased its contracted crude oil transportation capacity to 256,500 bbl/d, expanding its committed volumes to Canada's west coast and to the USGC to approximately 23% of its 2025 budgeted liquids production. The additional egress supports Canadian Natural's long-term sales strategy by targeting expanded refining markets, driving stronger netbacks while also reducing exposure to egress constraints.
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In December 2024, the Company increased its total committed capacity on the TMX pipeline to 169,000 bbl/d, an incremental 75,000 bbl/d, further expanding access to Canada's west coast.
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In Q1/24, the Company increased its total committed capacity on the Flanagan South pipeline to 77,500 bbl/d, an incremental 55,000 bbl/d, further expanding the Company's heavy oil diversification and market access to the USGC.
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The Company also has committed capacity of 10,000 bbl/d on the Keystone Base pipeline, with direct access to the USGC.
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AECO natural gas prices averaged $1.36/GJ in 2024, significantly lower compared to 2023, reflecting high storage inventories resulting from weaker demand and increased production levels in the WCSB, combined with lower NYMEX benchmark pricing.
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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.
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CORPORATE UPDATE
One of Canadian Natural's many strengths is our strong and deep leadership team. The Company takes a very proactive disciplined approach to succession, with well-planned and successful transitions, ensuring we maintain our strong corporate culture and top tier performance.
As part of ongoing management succession on April 30th, 2025, Mark Stainthorpe, Chief Financial Officer will become Executive Advisor, Finance and Victor Darel, currently Senior Vice President, Finance and Principal Accounting Officer will be promoted to Chief Financial Officer and Principal Accounting Officer.
Victor Darel is a Chartered Professional Accountant and has over 20 years of Finance and Accounting experience in both the public and private sectors. Victor has been with Canadian Natural for 11 years with increasing responsibilities in his roles over that time including as Senior Vice President, Finance and Principal Accounting Officer.
Mark Stainthorpe will continue to work together with the Finance and Investor Relations teams in his new role as Executive Advisor.
Sheryl Kapeluck, Vice President, Finance, Corporate will be promoted to the role of Senior Vice President, Finance and will join the Management Committee. Sheryl is a Chartered Professional Accountant with over 25 years of professional experience and has been with Canadian Natural for 14 years.
Scott Stauth, commenting on the succession stated, "Both Victor and Sheryl have brought a significant amount of expertise to their current roles, and we look forward to the contributions they will be making in their new positions as CFO and SVP Finance respectively. We thank Mark for his 6 years as our CFO and for the leadership Mark has provided as a key member of our Management Committee."
2024 YEAR END RESERVES
Determination of Reserves
For the year ended December 31, 2024, the Company retained IQREs, Sproule International Limited and GLJ Ltd., to evaluate and review all of the Company's proved and proved plus probable reserves. The evaluation and review was conducted and prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook. The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and escalated costs.
The Reserves Committee of the Company's Board of Directors has met with and carried out independent due diligence procedures with the IQREs as to the Company's reserves.
Additional reserves information is disclosed in the Company's Annual Information Form.
Summary of Company Gross Reserves
As of December 31, 2024
Forecast Prices and Costs
| Light and Medium Crude Oil (MMbbl) |
Primary Heavy Crude Oil (MMbbl) |
Pelican Lake Heavy Crude Oil (MMbbl) |
Bitumen (Thermal Oil) (MMbbl) |
Synthetic Crude Oil (MMbbl) |
Natural Gas (Bcf) |
Natural Gas Liquids (MMbbl) |
Barrels of Oil Equivalent (MMBOE) |
|
| Total Company | ||||||||
| Proved | ||||||||
| Developed Producing | 118 | 123 | 202 | 631 | 7,567 | 5,034 | 172 | 9,652 |
| Developed Non-Producing | 5 | 7 | - | 78 | - | 246 | 9 | 140 |
| Undeveloped | 129 | 88 | 53 | 2,603 | 96 | 11,625 | 533 | 5,440 |
| Total Proved | 252 | 219 | 255 | 3,312 | 7,663 | 16,904 | 713 | 15,231 |
| Probable | 94 | 99 | 105 | 1,878 | 593 | 10,252 | 403 | 4,879 |
| Total Proved plus Probable | 346 | 318 | 360 | 5,190 | 8,255 | 27,156 | 1,116 | 20,110 |
Notes to Reserves:
-
Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.
-
Information in the reserves data tables may not add due to rounding. BOE values and oil and natural gas metrics may not calculate exactly due to rounding.
-
Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserves estimates are the 3-Consultant-Average of price forecasts developed by Sproule International Limited, GLJ Ltd. and McDaniel & Associates Consultants Ltd., dated December 31, 2024:
| 2025 | 2026 | 2027 | 2028 | 2029 | ||
| Crude Oil and NGLs | ||||||
| WTI | US$/bbl | 71.58 | 74.48 | 75.81 | 77.66 | 79.22 |
| WCS | C$/bbl | 82.69 | 84.27 | 83.81 | 85.70 | 87.45 |
| Canadian Light Sweet | C$/bbl | 94.79 | 97.04 | 97.37 | 99.80 | 101.79 |
| Cromer LSB | C$/bbl | 93.30 | 96.05 | 95.92 | 98.55 | 100.51 |
| Edmonton C5+ | C$/bbl | 100.14 | 100.72 | 100.24 | 102.73 | 104.79 |
| Brent | US$/bbl | 75.58 | 78.51 | 79.89 | 81.82 | 83.46 |
| AECO | C$/MMBtu | 2.36 | 3.33 | 3.48 | 3.69 | 3.76 |
| BC Westcoast Station 2 | C$/MMBtu | 2.15 | 3.14 | 3.29 | 3.50 | 3.57 |
| Henry Hub | US$/MMBtu | 3.31 | 3.73 | 3.85 | 3.93 | 4.01 |
| All prices increase at a rate of 2% per year after 2029. | ||||||
| A US$/C$ foreign exchange rate of 0.7117 was used for 2025, 0.7283 for 2026, and 0.7433 for 2027 and thereafter in the year end 2024 evaluation. | ||||||
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A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet of natural gas to one barrel 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.
- Oil and natural gas metrics included herein are commonly used in the crude oil and natural gas industry and are determined by Canadian Natural as set out in the notes below. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies and may be misleading when making comparisons. Management uses these metrics to evaluate Canadian Natural's performance over time. However, such measures are not reliable indicators of Canadian Natural's future performance and future performance may vary.
-
Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production.
-
Reserves replacement or Production replacement ratio is the Company Gross reserves additions and revisions, for the relevant reserves category, divided by the Company Gross production in the same period.
-
Reserves Life Index ("RLI") is based on the amount for the relevant reserves category divided by the 2025 proved developed producing production forecast prepared by the IQREs.
-
Finding, Development and Acquisition ("FD&A") costs excluding changes in Future Development Costs ("FDC") are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2024 by the sum of total additions and revisions for the relevant reserves category.
-
FD&A costs including changes in FDC are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2024 and net changes in FDC from December 31, 2023 to December 31, 2024 by the sum of total additions and revisions for the relevant reserves category. FDC excludes all abandonment, decommissioning and reclamation costs.
-
Abandonment, decommissioning and reclamation ("ADR") costs included in the calculation of the Future Net Revenue ("FNR") consist of both the Company's total Asset Retirement Obligation ("ARO"), before inflation and discounting, for development existing as at December 31, 2024 and forecast estimates of ADR costs attributable to future development activity.
ADVISORY
Special Note Regarding Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (CNQ) (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, 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; changes and uncertainty in the international trade environment, including with respect to tariffs, export restrictions, embargoes and key trade agreements (including the tariffs on a variety of goods announced by the US government on March 4, 2025 and Canadian countermeasures subsequently announced, both of which are anticipated to evolve); 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, including the acquired working interests in AOSP and Duvernay assets from Chevron Canada Limited ("Chevron") in December 2024; 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 the tariffs on a variety of goods announced by the US government on March 4, 2025 and Canadian countermeasures subsequently announced, both of which are anticipated to evolve), 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 and year ended December 31, 2024, and the Company's 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 and year ended December 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 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.
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 and year ended December 31, 2024, dated March 5, 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:
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60% of free cash flow to shareholder returns and 40% to the balance sheet until net debt reaches $15 billion.
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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.
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When net debt is at or below $12 billion, free cash flow allocation will be 100% to shareholder returns.
The Company's free cash flow for the year ended December 31, 2024 is shown below:
| Year Ended | |||
| ($ millions) | Dec 31 2024 |
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| Adjusted funds flow (1) | $ | 14,859 | |
| Less: Dividends on common shares | 4,429 | ||
| Net capital expenditures,(2) excluding net acquisition costs | 5,286 | ||
| Abandonment expenditures | 646 | ||
| Free cash flow | $ | 4,498 | |
| (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 and year ended December 31, 2024, dated March 5, 2025. (2) Net Capital expenditures is a Non-GAAP Financial Measure. 2024 Net capital expenditures, excluding net acquisition costs is equal to net capital expenditures of $14,431 million less net acquisition costs of $9,145 million in the period. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2024, dated March 5, 2025. |
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Long-term Debt, net
Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents.
| ($ millions) | Dec 31 2024 |
Sep 30 2024 |
Dec 31 2023 |
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| Long-term debt | $ | 18,819 | $ | 10,029 | $ | 10,799 | |||
| Less: cash and cash equivalents | 131 | 721 | 877 | ||||||
| Long-term debt, net | $ | 18,688 | $ | 9,308 | $ | 9,922 |
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.
The 2025 capital budget reflects budgeted net capital expenditures, before capital related to the office relocation and 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 will be issuing its 2024 Fourth Quarter and Year End Earnings Results on Thursday, March 6, 2025 before market open.
A conference call will be held at 9:00 a.m. MST / 11:00 a.m. EST on Thursday, March 6, 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: 00761#)
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.
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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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To view the source version of this press release, please visit https://www.newsfilecorp.com/release/243502
SOURCE Canadian Natural Resources Limited