Canadian Natural’s Vice Chairman, Tim McKay, also commented “In 2023, we delivered on our capital allocation strategy by strengthening our balance sheet, providing significant returns to shareholders and strategically developing our assets. We achieved record annual production while growing our reserves organically on both a total proved and total proved plus probable basis, with reserve replacement ratios of 166% and 194% respectively.
Our strong execution in 2023 sets us up to continue delivering on our four pillars of capital allocation through our disciplined 2024 capital budget of approximately $5.4 billion. This budget is strategically weighted to longer cycle thermal development in the first half of 2024 and shorter cycle growth in the second half of the year, targeting strong exit production levels. As well it provides us with the flexibility to adjust to changing market egress and evolving market conditions, ensuring we are allocating capital effectively and maximizing value for our shareholders.
We are committed to supporting Canada’s and Alberta’s climate goals and continue to reduce our environmental footprint with our robust environmental targets, including net zero greenhouse gas (“GHG”) emissions in the oil sands by 2050. We are uniquely positioned with diverse, long life low decline assets which are ideal to apply technologies, to reduce GHG emissions and provide industry leading environmental performance. It is important to continue working together with the Canadian and the Alberta governments to make the Pathways Alliance a transformative industry collaboration and achieve meaningful GHG reductions in Canada. We believe Canadian energy is one of the most responsibly produced sources of energy in the world and should be the preferred energy choice.”
Canadian Natural’s President, Scott Stauth, also commented “The Company delivered strong operational results in 2023 and achieved multiple production records, including record annual average total production of approximately 1,332 MBOE/d, representing 7% production per share growth as a result of safe, effective and efficient operations and significant share repurchases. We also achieved record quarterly average total production of approximately 1,419 MBOE/d in Q4/23. With our focus on continuous improvement and process optimization, we had high reliability and utilization at our oil sands mining operations, achieving record synthetic crude oil (“SCO”) production of approximately 500 Mbbl/d in Q4/23.
One of Canadian Natural’s advantages is our significant reserves base, with total proved reserves of 13.9 billion BOE and total proved plus probable reserves of 18.5 billion BOE as of year end 2023, which increased 2% and 3% respectively from year end 2022. The increase in our reserves reflects the success of our capital efficient development opportunities across our asset base. With approximately 75% 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 of 32 years and a total proved plus probable reserves life index of 43 years.”
Mark Stainthorpe also added “In 2023, we successfully executed on our capital program and remained focused on cost control in an inflationary environment. We delivered strong financial results in 2023, including net earnings of approximately $8.2 billion and adjusted funds flow of $15.3 billion, which drove significant returns to shareholders totaling $7.2 billion.
In the past three years, we have reduced our net debt by over $11 billion and delivered approximately $21.5 billion directly to shareholders through $11.0 billion in dividends and $10.5 billion in share repurchases. These impressive results delivered returns to shareholders of approximately $30 per share through debt reductions and shareholder distributions over the three year time period.
Subsequent to quarter end, the Board of Directors approved a 5% increase to our quarterly dividend to $1.05 per common share, up from the previous dividend level of $1.00 per common share, payable on April 5, 2024 to shareholders of record on March 15, 2024. This demonstrates the confidence that the Board has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base. With this increase announced today, we have increased our quarterly dividend 24% through three separate increases over the past year. This year marks the 24th consecutive year of dividend increases, with a compound annual growth rate (“CAGR”) of 21% over that time.
In addition, our Board of Directors approved a resolution to subdivide the Company’s common shares on a two for one basis, subject to shareholder approval and having obtained all regulatory approvals, including TSX approval. The proposal will be voted on at the Company’s Annual and Special Meeting of Shareholders to be held on May 2, 2024.
With our disciplined 2024 capital budget, low maintenance capital requirements and a long life low decline asset base, we target to deliver strong returns on capital with robust free cash flow while continuing to provide significant returns to shareholders in 2024.”
HIGHLIGHTS
| Three Months Ended | Year Ended | |||||||||||||||
| ($ millions, except per common share amounts) | Dec 31 2023 |
Sep 30 2023 |
Dec 31 2022 |
Dec 31 2023 |
Dec 31 2022 |
|||||||||||
| Net earnings | $ | 2,627 | $ | 2,344 | $ | 1,520 | $ | 8,233 | $ | 10,937 | ||||||
| Per common share | – basic | $ | 2.43 | $ | 2.15 | $ | 1.37 | $ | 7.54 | $ | 9.64 | |||||
| – diluted | $ | 2.41 | $ | 2.13 | $ | 1.36 | $ | 7.47 | $ | 9.52 | ||||||
| Adjusted net earnings from operations (1) | $ | 2,546 | $ | 2,850 | $ | 2,194 | $ | 8,533 | $ | 12,863 | ||||||
| Per common share | – basic (2) | $ | 2.36 | $ | 2.61 | $ | 1.98 | $ | 7.82 | $ | 11.33 | |||||
| – diluted (2) | $ | 2.34 | $ | 2.59 | $ | 1.96 | $ | 7.74 | $ | 11.19 | ||||||
| Cash flows from operating activities | $ | 4,815 | $ | 3,498 | $ | 4,544 | $ | 12,353 | $ | 19,391 | ||||||
| Adjusted funds flow (1) | $ | 4,419 | $ | 4,684 | $ | 4,176 | $ | 15,274 | $ | 19,791 | ||||||
| Per common share | – basic (2) | $ | 4.09 | $ | 4.30 | $ | 3.78 | $ | 14.00 | $ | 17.44 | |||||
| – diluted (2) | $ | 4.05 | $ | 4.26 | $ | 3.73 | $ | 13.86 | $ | 17.22 | ||||||
| Cash flows used in investing activities | $ | 946 | $ | 1,199 | $ | 1,262 | $ | 4,858 | $ | 4,987 | ||||||
| Net capital expenditures (3) | $ | 975 | $ | 1,108 | $ | 1,233 | $ | 4,909 | $ | 5,136 | ||||||
| Abandonment expenditures, net (1) | $ | 149 | $ | 123 | $ | 84 | $ | 509 | $ | 335 | ||||||
| Daily production, before royalties | ||||||||||||||||
| Natural gas (MMcf/d) | 2,231 | 2,151 | 2,115 | 2,151 | 2,090 | |||||||||||
| Crude oil and NGLs (bbl/d) | 1,047,541 | 1,035,153 | 942,258 | 973,530 | 933,149 | |||||||||||
| Equivalent production (BOE/d)Â (4) | 1,419,313 | 1,393,614 | 1,294,679 | 1,332,105 | 1,281,434 | |||||||||||
| (1) 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, 2023 dated February 28, 2024. (2) 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, 2023 dated February 28, 2024. (3) Non-GAAP Financial Measure. The composition of this measure 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, 2023 dated February 28, 2024. (4) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, 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. |
||||||||||||||||
ANNUAL HIGHLIGHTS
- 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 2023, the Company generated strong annual financial results, including:
- Net earnings of approximately $8.2 billion and adjusted net earnings from operations of approximately $8.5 billion.
- Cash flows from operating activities of approximately $12.4 billion.
- Adjusted funds flow of approximately $15.3 billion.
- Free cash flow(1)Â of approximately $6.9 billion after total dividend payments of $3.9 billion, base capital expenditures(2)Â of $4.0 billion and $0.5 billion in abandonment expenditures.
- Canadian Natural achieved its $10 billion net debt level and as a result, is targeting to return 100% of free cash flow to shareholders, per the free cash flow allocation policy.
- The Company remained disciplined in 2023, meeting its annual targeted net capital expenditures of approximately $4.9 billion and $0.5 billion in abandonment expenditures.
(1) Non-GAAP Financial Measure. Refer to the “Non-GAAP and Other Financial Measures” section of this press release and the “Non-GAAP and Other Financial Measures” section of the Company’s MD&A for the three months and year ended December 31, 2023, dated February 28, 2024.
(2) Item is a component of net capital expenditures. 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, 2023 for more details on net capital expenditures.
- In 2023, Canadian Natural continued to focus on safe, effective and efficient operations, delivering record annual average production of 1,332,105 BOE/d, an increase of 4% from 2022 levels, or 7% on a production per share basis.
- The Company delivered record annual total liquids production of 973,530 bbl/d in 2023, an increase of 4% or approximately 40,400 bbl/‌d from 2022 levels. Strong annual liquids production in 2023 was driven by:
- Record annual Oil Sands Mining and Upgrading production of 451,339 bbl/d, an increase of 6% or approximately 25,400 bbl/‌d from 2022 levels as a result of the Company’s focus on continuous improvement and increased reliability.
- The Company also achieved record annual thermal production of 262,000 bbl/d, an increase of 4% or approximately 10,000 bbl/d from 2022 levels as a result of the Company’s capital efficient thermal pad add development program.
- The Company achieved record annual natural gas production of 2,151 MMcf/d, an increase of 3% or approximately 61 MMcf/d from 2022 levels, reflecting strong results from our capital efficient drill to fill development plan.
- The Company delivered record annual total liquids production of 973,530 bbl/d in 2023, an increase of 4% or approximately 40,400 bbl/‌d from 2022 levels. Strong annual liquids production in 2023 was driven by:
- Canadian Natural continues to maintain a strong balance sheet and financial flexibility, ending the year with approximately $9.9 billion in net debt, with significant liquidity(1)Â of approximately $6.9 billion. The Company executed on a number of initiatives in 2023 to strengthen its financial flexibility, including:
- In Q2/23, the Company extended its $2.425 billion revolving syndicated credit facility originally maturing June 2024 to June 2027.
- In Q3/23, the Company extended its $0.5 billion revolving credit facility originally maturing February 2024 to February 2025.
- In Q4/23, the Company repaid $0.405 billion of 1.45% medium-term notes.
RETURNS TO SHAREHOLDERS
- Returns to shareholders in 2023 were significant, having directly returned to shareholders approximately $7.2 billion, comprised of $3.9 billion in dividends and $3.3 billion in share repurchases as a result of the Company’s ability to generate substantial free cash flow.
- In 2023, the Company repurchased a total of approximately 40.1 million common shares for cancellation at a weighted average price of $82.86 per share for a total of $3.3 billion.
- With the Company’s net debt below $10 billion at year end 2023, the Company is now targeting in 2024 to return 100% of free cash flow to shareholders through dividends and share repurchases, per our free cash flow allocation policy. Going forward, the Company will manage this allocation of free cash flow on a forward looking annual basis, while managing working capital and cash management as required.
- Subsequent to quarter end, the Board of Directors approved a 5% increase to the quarterly dividend to $1.05 per common share, up from the previous dividend level of $1.00 per common share, payable on April 5, 2024 to shareholders of record on March 15, 2024. 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.
- Since March 2, 2023, the Company has increased its quarterly dividend 24% through three separate increases for a combined increase of $0.20 per share.
- The Company’s leading track record of dividend increases continues, with 2024 marking the 24th consecutive year of dividend increases with a compound annual growth rate (“CAGR”) of 21% over that time.
- To date in 2024, up to and including February 28, 2024, the Company has returned a total of approximately $1.4 billion directly to shareholders through $1.1 billion in dividends and $0.35 billion from the repurchase and cancellation of approximately 4.1 million common shares.
- On February 28, 2024, the Board of Directors approved the renewal of the Company’s NCIB, which states that during the 12 month period commencing March 13, 2024 and ending March 12, 2025, the Company can repurchase for cancellation up to 10% of the public float (determined in accordance with the rules of the TSX), subject to TSX approval.
(1) 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, 2023, dated February 28, 2024.
- On February 28, 2024, Canadian Natural’s Board of Directors approved a resolution to subdivide the Company’s common shares on a two for one basis, subject to shareholder approval and the Company having obtained all regulatory approvals, including TSX approval. The proposal will be voted on at the Company’s Annual and Special Meeting of Shareholders to be held on May 2, 2024.
QUARTERLY HIGHLIGHTS
- In Q4/23, the Company generated strong quarterly financial results, including:
- Net earnings of approximately $2.6 billion and adjusted net earnings from operations of approximately $2.5 billion.
- Cash flows from operating activities of approximately $4.8 billion.
- Adjusted funds flow of approximately $4.4 billion.
- Free cash flow of approximately $2.5 billion after total dividend payments of $1.0 billion and base capital expenditures of $0.8 billion and $0.1 billion in abandonment expenditures.
- Direct returns to shareholders in Q4/23 were strong, totaling approximately $2.5 billion, comprised of $1.0 billion of dividends and $1.5 billion through the repurchase and cancellation of approximately 17.6 million common shares at a weighted average price of $88.26 per share.
- In Q4/23, Canadian Natural achieved record quarterly average production volumes of 1,419,313 BOE/d, an increase of 10% or approximately 125,000 BOE/d compared to Q4/22 levels.
- The Company achieved record quarterly average liquids production volumes in Q4/23 of 1,047,541 bbl/d, an increase of 11% or approximately 105,000 bbl/d over Q4/22 levels.
- Oil Sands Mining and Upgrading achieved record quarterly average production of 500,133 bbl/d in Q4/23, an increase of 17% from Q4/22 levels as a result of the Company’s focus on continuous improvements and increased reliability.
- The Company delivered record quarterly natural gas production volumes of 2,231 MMcf/d in Q4/23, an increase of 5% compared to Q4/22 levels, reflecting strong results from our capital efficient drill to fill development plan.
- The Company achieved record quarterly average liquids production volumes in Q4/23 of 1,047,541 bbl/d, an increase of 11% or approximately 105,000 bbl/d over Q4/22 levels.
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 proven reserve life index (“RLI”)(1) of 32 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, 2023 (all reserves values are Company Gross unless stated otherwise).
- Total proved reserves increased 2% to 13.910 billion BOE, with reserves additions and revisions of 0.809 billion BOE. Total proved plus probable reserves increased 3% to 18.504 billion BOE, with reserves additions and revisions of 0.944 billion BOE.
- The strength and depth of the Company’s assets are evident as approximately 75% of total proved reserves are long life low decline reserves. This results in a total proved BOE RLI of 32 years and a total proved plus probable BOE RLI of 43 years.
- Additionally, high value, zero decline SCO represents approximately 50% of total proved reserves with a RLI of 44 years.
- The strength and depth of the Company’s assets are evident as approximately 75% of total proved reserves are long life low decline reserves. This results in a total proved BOE RLI of 32 years and a total proved plus probable BOE RLI of 43 years.
- Proved developed producing reserves additions and revisions are 540 million BOE, replacing 2023 production by 111%. The proved developed producing BOE RLI is 21 years.
- Total proved reserves additions and revisions replaced 2023 production by 166%. Total proved plus probable reserves additions and revisions replaced 2023 production by 194%.
- In 2023, Canadian Natural continued to achieve strong finding and development costs:
- Finding, development and acquisition (“FD&A”)(1) costs, excluding changes in Future Development Cost (“FDC”), are $5.86/BOE for total proved reserves and $5.02/BOE for total proved plus probable reserves.
- FD&A costs, including changes in FDC, are $9.25/BOE for total proved reserves and $8.28/BOE for total proved plus probable reserves.
- The net present value of future net revenues, before income tax, discounted at 10%, is $105.9 billion for proved developed producing reserves, $153.7 billion for total proved reserves, and $186.5 billion for total proved plus probable reserves.
- The Company’s total proved net asset value (“NAV”) per share increased to $139.07 per share in 2023 from $131.79 per share in 2022 after adjusting for asset retirement obligations and net debt. Total proved plus probable NAV per share increased to $169.65 per share in 2023 from $161.53 per share in 2022.
CORPORATE UPDATE
Canadian Natural is pleased to announce the appointment of Ms. Christine Healy to the Board of Directors of the Company, effective February 28, 2024. Ms. Healy is currently the President, AMEA (Asia, Middle East and Australia) of AtkinsRealis, a globally-leading design, engineering and project-management company headquartered in Montreal, Canada. Prior to that, she served as Senior Vice President, Carbon Neutrality and Continental Europe for TotalEnergies from 2021 to 2023. From 2018 to 2020, Ms. Healy served as Country Chair, President and Chief Executive Officer for Total E&P Canada. Prior to her tenure with TotalEnergies, Ms. Healy was Chief Strategy Officer and General Counsel of Maersk Oil and Gas where she was responsible for M&A, strategy, commercial, communications, government relations, compliance and legal. She has also held senior executive positions with Equinor and the Government of Newfoundland and Labrador. Ms. Healy holds a B.A. (Hon.), Economics from Memorial University and a Juris Doctor from Osgoode Hall Law School.
As part of the Company’s previously announced management changes, Scott Stauth was promoted to President of Canadian Natural and joined the Board of Directors effective February 28, 2024. Additionally, Tim McKay, Vice Chairman, has resigned from the Board of Directors and will continue to support the management transition until his retirement.
(1) Supplementary financial measure. Refer to the “2023 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 73% of total liquids production in 2023, the majority of which is zero decline high value SCO production from the Company’s world class Oil Sands Mining and Upgrading assets. The remaining balance of the Company’s long life low decline production comes from its top tier thermal in situ oil sands operations and Pelican Lake heavy crude oil assets. The combination of these long life low decline assets, low reserves replacement costs, and effective and efficient operations results in substantial and sustainable adjusted funds flow throughout the commodity price cycle.
In addition, Canadian Natural maintains a substantial inventory of low capital exposure projects within the Company’s conventional asset base. These projects can be executed quickly and, in the right economic conditions, provide excellent returns and maximize value for our shareholders. Supporting these projects is the Company’s undeveloped land base which enables large, repeatable drilling programs that can be optimized over time. Additionally, Canadian Natural maximizes long-term value by maintaining high ownership and operatorship of its assets and has an extensive infrastructure network, allowing the Company to control the nature, timing and extent of development. Low capital exposure projects can be stopped or started relatively quickly depending upon success, market conditions or corporate needs.
Canadian Natural’s balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.
| Drilling Activity | Year Ended December 31 | |||||||||||
| 2023 | 2022 | |||||||||||
| (number of wells) | Gross | Net | Gross | Net | ||||||||
| Crude oil (1) | 228 | 221 | 332 | 317 | ||||||||
| Natural gas | 78 | 61 | 100 | 72 | ||||||||
| Dry | 2 | 2 | 1 | 1 | ||||||||
| Subtotal | 308 | 284 | 433 | 390 | ||||||||
| Stratigraphic test / service wells | 481 | 419 | 530 | 452 | ||||||||
| Total | 789 | 703 | 963 | 842 | ||||||||
| Success rate (excluding stratigraphic test / service wells) | 99Â % | 99 % | ||||||||||
| (1)Â Includes bitumen wells. | ||||||||||||
- Canadian Natural drilled a total of 284 net crude oil and natural gas producer wells in 2023 compared to 390 net wells in 2022, a decrease of 106 net wells over this time period.
2024 BUDGET STRATEGY
Canadian Natural’s unique and diversified asset base provides a key competitive advantage as it can manage the pace and timing of development activities to maximize value growth from our assets. The Company reiterates its disciplined 2024 capital budget at approximately $5.4 billion(1) and targets to provide production growth in 2024, 2025 and beyond.
In 2024, the drilling program is strategically weighted toward longer cycle projects, primarily thermal in situ pads, in the first half of the year, and shorter cycle development opportunities in the second half of the year to better align with incremental market egress, maximizing value for shareholders.
(1) Forward looking non-GAAP Financial Measure. The composition of this measure 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, 2023 dated February 28, 2024.
North America Exploration and Production
| Crude oil and NGLs – excluding Thermal In Situ Oil Sands | |||||||||||||||
| Three Months Ended | Year Ended | ||||||||||||||
| Dec 31 2023 |
Sep 30 2023 |
Dec 31 2022 |
Dec 31 2023 |
Dec 31 2022 |
|||||||||||
| Crude oil and NGLs production (bbl/d) | 243,157 | 232,496 | 233,371 | 234,100 | 227,953 | ||||||||||
| Net wells targeting crude oil | 42 | 42 | 71 | 173 | 214 | ||||||||||
| Net successful wells drilled | 42 | 42 | 71 | 171 | 213 | ||||||||||
| Success rate | 100Â % | 100 % | 100 % | 99Â % | 99 % | ||||||||||
- Annual North America E&P liquids production, excluding thermal in situ, averaged 234,100 bbl/d in 2023, a 3% increase compared to 2022 levels. The increase in production from the prior periods primarily reflects growth in the Company’s primary heavy crude oil and liquids-rich Montney assets, partially offset by the impacts of wildfires, a third party pipeline outage and natural field declines.
- Primary heavy crude oil production averaged 77,668 bbl/d in 2023, a 15% increase from 2022 levels, reflecting strong drilling results from the Company’s multilateral wells in the Mannville and Clearwater fairways. The Company drilled 104 horizontal multilateral primary heavy crude oil wells in 2023.
- Operating costs(1) in the Company’s primary heavy crude oil operations averaged $19.85/bbl (US$14.71/‍bbl) in 2023, a decrease of 9% from 2022 levels, primarily reflecting lower energy costs.
- Pelican Lake production averaged 46,046 bbl/d in 2023, a decrease of 5% from 2022 levels, reflecting historical low natural field declines from this long life low decline asset.
- Operating costs at Pelican Lake averaged $8.58/bbl (US$6.36/bbl) in 2023, an increase of 3% compared to 2022 levels, primarily due to lower volumes.
- North America light crude oil and NGLs production averaged 109,354 bbl/d in 2023, comparable to 2022 levels, reflecting strong liquids results, primarily from the Montney, which offset the impacts of wildfires, a third party pipeline outage and natural field declines.
- Operating costs in the Company’s North America light crude oil and NGLs operations averaged $16.28/‍bbl (US$12.06/bbl) in 2023, an increase of 2% over 2022 levels, reflecting higher service costs.
- Primary heavy crude oil production averaged 77,668 bbl/d in 2023, a 15% increase from 2022 levels, reflecting strong drilling results from the Company’s multilateral wells in the Mannville and Clearwater fairways. The Company drilled 104 horizontal multilateral primary heavy crude oil wells in 2023.
| North America Natural Gas | |||||||||||||||
| Three Months Ended | Year Ended | ||||||||||||||
| Dec 31 2023 |
Sep 30 2023 |
Dec 31 2022 |
Dec 31 2023 |
Dec 31 2022 |
|||||||||||
| Natural gas production (MMcf/d) | 2,218 | 2,139 | 2,105 | 2,139 | 2,075 | ||||||||||
| Net wells targeting natural gas | 9 | 10 | 15 | 61 | 72 | ||||||||||
| Net successful wells drilled | 9 | 10 | 15 | 61 | 72 | ||||||||||
| Success rate | 100Â % | 100 % | 100 % | 100Â % | 100 % | ||||||||||
- Canadian Natural achieved record annual North America natural gas production of 2,139 MMcf/d in 2023, an increase of 3% from 2022 levels. This growth reflects strong drilling results from the Company’s capital efficient drill to fill development plan, which was partially offset by the impacts from wildfires, a third party pipeline outage and natural field declines.
- North America natural gas operating costs averaged $1.27/Mcf in 2023, a 7% increase compared to 2022 levels, primarily reflecting higher service costs. The Company continues to focus on cost control and effective and efficient operations to offset cost pressures.
(1) Calculated as production expense divided by respective sales volumes. Natural gas and NGLs production volumes approximate sales volumes.
| Thermal In Situ Oil Sands | |||||||||||||||
| Three Months Ended | Year Ended | ||||||||||||||
| Dec 31 2023 |
Sep 30 2023 |
Dec 31 2022 |
Dec 31 2023 |
Dec 31 2022 |
|||||||||||
| Bitumen production (bbl/d) | 278,422 | 287,085 | 253,188 | 262,000 | 252,018 | ||||||||||
| Net wells targeting bitumen | – | 2 | 9 | 50 | 104 | ||||||||||
| Net successful wells drilled | – | 2 | 9 | 50 | 104 | ||||||||||
| Success rate | – % | 100 % | 100 % | 100 % | 100 % | ||||||||||
- Record annual thermal in situ production levels averaged 262,000 bbl/d in 2023, an increase of 4% from 2022 levels. The increase in thermal in situ production is driven by strong execution on the Company’s strategic development plan, including capital efficient pad additions at Primrose and Kirby in 2023, partially offset by natural field declines.
- Thermal in situ operating costs averaged $13.17/bbl (US$9.76/bbl) in 2023, a decrease of 20% from 2022 levels, primarily reflecting the impact of higher production volumes and lower energy costs.
- At Jackfish and Kirby North, planned turnarounds are targeted to occur in Q2/24, impacting quarterly average production by approximately 17,100 bbl/d.
- Canadian Natural has decades of strong capital efficient growth opportunities on its long life low decline thermal in situ assets. As outlined in our 2024 budget, we continue to develop these assets in a disciplined manner to deliver safe, reliable, thermal in situ production, with the following opportunities:
- At Primrose, the Company is currently drilling the first of two CSS pads which are targeted to come on production in Q2/25, and one SAGD pad at Wolf Lake which is targeted to come on production in Q1/25.
- At Kirby, two of the four previously drilled SAGD pads have reached full production capacities, with the two remaining pads targeted to ramp up to their full production capacities in mid-2024.
- At Jackfish, two SAGD pads that were drilled in 2023 are targeted to ramp up to their full production capacities in Q3/24 and Q4/24, supporting continued high utilization rates at the Jackfish facilities. The Company is targeting to drill one SAGD pad at Jackfish in the second half of 2024, with production from this pad targeted to come on in Q3/25.
- Canadian Natural has been piloting solvent enhanced oil recovery technology on certain thermal in situ assets with an objective to increase bitumen production while reducing the Steam to Oil Ratio (“SOR”) and GHG intensities by 40% to 50% and optimizing solvent recovery. This technology has the potential for application throughout the Company’s extensive thermal in situ asset base.
- At Kirby North, the commercial scale solvent SAGD pad development is approximately 80% complete and the Company is targeting to begin solvent injection in mid-2024.
- At Primrose, the Company is continuing to use its solvent enhanced oil recovery pilot in the steam flood area to optimize solvent efficiency and to further evaluate the commercial development opportunity.
North America Oil Sands Mining and Upgrading
| Three Months Ended | Year Ended | ||||||||||||||
| Dec 31 2023 |
Sep 30 2023 |
Dec 31 2022 |
Dec 31 2023 |
Dec 31 2022 |
|||||||||||
| Synthetic crude oil production (bbl/d)Â (1)(2) | 500,133 | 490,853 | 428,784 | 451,339 | 425,945 | ||||||||||
| (1)Â SCO production before royalties and excludes production volumes consumed internally as diesel. (2)Â Consists of heavy and light synthetic crude oil products. |
|||||||||||||||
- Canadian Natural achieved record annual production of 451,339 bbl/d of high value SCO in 2023, an increase of 6% or approximately 25,400 bbl/‌d from 2022 levels. This increase is driven by the Company’s focus on continuous improvement and increased reliability through safe, reliable, effective and efficient operations from its world class Oil Sands Mining and Upgrading assets.
- Oil Sands Mining and Upgrading operating costs are top tier, averaging $24.32/bbl (US$18.02/bbl) in 2023, a decrease of 7% from 2022 levels, primarily reflecting higher production volumes and lower energy costs.
- The Company’s high value SCO, representing approximately 46% of the Company’s total liquids volumes, captured an average price premium to WTI of US$2.03/bbl and strong annual realized SCO pricing of $100.06‍/‍bbl in 2023, generating significant free cash flow for the Company.
- As previously announced with the 2024 budget, the Company is targeting turnarounds at its Oil Sands Mining and Upgrading operations:
- At the Athabasca Oil Sands Project (“AOSP”), there are two turnarounds planned at non-operated Scotford Upgrader, where it will operate at reduced rates.
- The first turnaround was originally targeted for 10 days in April 2024. It has now been moved into March 2024 for a duration of 17 days which includes additional scope and is targeted to impact Q1/24 quarterly average production by approximately 10,000 bbl/d, the same volume as originally budgeted in Q2/24.
- The second turnaround is targeted to begin in September 2024 for a duration of 49 days, as previously announced.
- The total combined targeted annual impact to production remains unchanged from the budget at approximately 12,400 bbl/d.
- At Horizon, a planned turnaround is targeted to occur in Q2/24 with a full plant outage targeted for approximately 30 days, impacting quarterly average production by approximately 89,000 bbl/d.
- At the Athabasca Oil Sands Project (“AOSP”), there are two turnarounds planned at non-operated Scotford Upgrader, where it will operate at reduced rates.
- The Company continues to pursue opportunities to increase production at both Horizon and at AOSP.
- At Horizon, the Company targets to complete the remaining components and tie-ins related to the reliability enhancement project during the planned turnaround in Q2/24.
- This project targets to increase capacity of the zero decline, high value SCO production at Horizon over a two year timeframe by shifting the planned turnarounds to once every two years from the current annual cycle, reducing downtime and increasing overall reliability. In 2025, annual production at Horizon is targeted to increase by approximately 28,000 bbl/d, with the two year average annual SCO capacity targeted to increase by approximately 14,000 bbl/d.
- At the Scotford Upgrader, during the 49 day turnaround in Q4/24, a debottlenecking project will be completed which targets to add incremental capacity at AOSP of approximately 5,600 bbl/d net to Canadian Natural.
- At Horizon, the Company is progressing its Naphtha Recovery Unit Tailings Treatment (“NRUTT”) project that targets incremental production of approximately 6,300 bbl/d of SCO following mechanical completion in Q3/27. This project is targeted to reduce GHG emissions, equivalent to 6% of Horizon’s total Scope 1 emissions, and will result in lower reclamation costs over the life of the Horizon project.
- At Horizon, the Company targets to complete the remaining components and tie-ins related to the reliability enhancement project during the planned turnaround in Q2/24.
International Exploration and Production
| Three Months Ended | Year Ended | ||||||||||||||
| Dec 31 2023 |
Sep 30 2023 |
Dec 31 2022 |
Dec 31 2023 |
Dec 31 2022 |
|||||||||||
| Crude oil production (bbl/d) | 25,829 | 24,719 | 26,915 | 26,091 | 27,233 | ||||||||||
| Natural gas production (MMcf/d) | 13 | 12 | 10 | 12 | 15 | ||||||||||
- International E&P crude oil production volumes averaged 26,091 bbl/d in 2023, a decrease of 4% from 2022 levels, reflecting natural field declines.
MARKETING
| Three Months Ended | Year Ended | ||||||||||||||
| Dec 31 2023 |
Sep 30 2023 |
Dec 31 2022 |
Dec 31 2023 |
Dec 31 2022 |
|||||||||||
| Crude oil and NGLs pricing | |||||||||||||||
| WTI benchmark price (US$/bbl)Â (1) | $ | 78.33 | $ | 82.18 | $ | 82.62 | $ | 77.61 | $ | 94.23 | |||||
| WCS Heavy Differential from WTI (US$/bbl) | $ | 21.90 | $ | 12.86 | $ | 25.65 | $ | 18.62 | $ | 18.26 | |||||
| WCS heavy differential as a percentage of | |||||||||||||||
| Â WTI (%)Â (2) | 28Â % | 16 % | 31 % | 24Â % | 19 % | ||||||||||
| SCO benchmark price (US$/bbl) | $ | 78.64 | $ | 84.99 | $ | 86.78 | $ | 79.64 | $ | 98.66 | |||||
| Condensate benchmark price (US$/bbl) | $ | 76.22 | $ | 77.91 | $ | 83.33 | $ | 76.55 | $ | 93.69 | |||||
| Exploration & Production liquids realized | |||||||||||||||
| pricing (C$/bbl)Â (3)(4) | $ | Â 69.39 | $ | Â 87.83 | $ | Â 69.34 | $ | Â 72.36 | $ | Â 90.64 | |||||
| SCO realized pricing (C$/bbl)Â (4)(5) | $ | 98.73 | $ | 108.55 | $ | 103.79 | $ | 100.06 | $ | 117.69 | |||||
| Natural gas pricing | |||||||||||||||
| AECO benchmark price (C$/GJ) | $ | 2.52 | $ | 2.26 | $ | 5.29 | $ | 2.77 | $ | 5.28 | |||||
| Natural gas realized pricing (C$/Mcf)Â (5) | $ | 2.80 | $ | 2.81 | $ | 6.39 | $ | 3.10 | $ | 6.55 | |||||
| (1) West Texas Intermediate (“WTI”). (2) Western Canadian Select (“WCS”). (3) Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities. (4) 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, 2023 dated February 28, 2024. (5) Pricing is net of blending costs and excluding risk management activities. |
|||||||||||||||
- Canadian Natural has a balanced and diverse product mix of natural gas, NGLs, heavy crude oil, light crude oil, bitumen and SCO.
- WTI prices in 2023 were down 18% compared to 2022, reflecting concerns of higher non-OPEC supply and lower than anticipated global crude oil demand as a result of persistent inflation and the resulting increase in interest rates. Crude oil prices remain volatile as the global crude oil market continues to be impacted by heightened geopolitical tensions.
- SCO benchmark pricing averaged US$79.64/bbl in 2023, representing a US$2.03/bbl price premium to WTI in 2023, compared to a US$4.43/bbl price premium to WTI in 2022. SCO has traded at a premium to WTI in recent years as a result of strong North American demand for refined products; however, the lower price premium in 2023 relative to 2022 was driven by increased production and egress constraints in the Western Canadian Sedimentary Basin (“WCSB”), particularly in Q4/23.
- The WCS differential to WTI was US$18.62/bbl in 2023, comparable to US$18.26/bbl in 2022. As a percentage of WTI, the WCS differential widened to 24% in 2023 from 19% in 2022, primarily as a result of increased production and egress constraints in the WCSB.
- The North West Redwater (“NWR”) refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 81,525 bbl/d in 2023.
- Natural gas prices decreased in 2023, with AECO averaging $2.77/GJ in 2023 compared to $5.28/GJ in 2022, reflecting lower NYMEX benchmark pricing, increased production in the WCSB and lower storage draws due to decreased demand resulting from mild winter weather in 2023.
- As a result of the Company’s diversified sale points, average natural gas realized pricing of $3.10/‍Mcf was achieved in 2023, which was 15% above the average AECO benchmark price, maximizing value for shareholders. Approximately 26% of the Company’s natural gas production was sold at AECO/Station 2 pricing, and approximately 37% was exported to other North American and international markets, capturing higher natural gas prices. Additionally, the Company used the equivalent of approximately 37% of its natural gas production in its operations in 2023.
- Canadian Natural has been a supporter of incremental pipeline projects to ensure Canadian crude oil and natural gas can access global markets to deliver the most responsible and leading ESG production that the world needs.
- Canadian Natural has committed 94,000 bbl/d on Trans Mountain Corporation’s (“Trans Mountain”) 590,000 bbl/‌d Trans Mountain Expansion project (“TMX”).
- TMX is approximately 98% complete and is targeting to be in service in Q2/24.
- Canadian Natural has committed 94,000 bbl/d on Trans Mountain Corporation’s (“Trans Mountain”) 590,000 bbl/‌d Trans Mountain Expansion project (“TMX”).
FINANCIAL REVIEW
- Canadian Natural’s financial positions remains strong, given its proven strategies including its disciplined approach to capital allocation. The Company’s adjusted funds flow generation, credit facilities, US commercial paper program, access to capital markets, diverse asset base and flexible capital expenditure program all support a strong financial position and provide the appropriate financial resources for the near-‍, mid- and long-term.
- The Company’s safe, effective and efficient operations combined with a high quality, long life low decline asset base generated annual free cash flow of approximately $6.9 billion in 2023 after dividend payments of $3.9 billion and base capital expenditures of $4.5 billion (excluding net acquisitions and strategic growth capital of $0.9 billion, as per the Company’s free cash flow allocation policy in 2023).
- In 2023, the Company directly returned to shareholders approximately $7.2 billion through $3.9 billion in dividends and $3.3 billion through the repurchase and cancellation of approximately 40.1 million common shares.
- In Q4/23, returns to shareholders were strong, totaling approximately $2.5 billion, comprised of $1.0 billion of dividends and $1.5 billion through the repurchase and cancellation of approximately 17.6 million common shares at a weighted average price of $88.26 per share.
- Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with net debt of approximately $9.9 billion and significant liquidity of approximately $6.9 billion at the end of 2023.
- Undrawn revolving bank credit facilities totaling approximately $5.5 billion were available at December 31, 2023. Including cash and cash equivalents and short-term investments, the Company had significant liquidity of approximately $6.9 billion. At December 31, 2023, the Company had no commercial paper drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
- In Q2/23, the Company extended its $2.425 billion revolving syndicated credit facility originally maturing June 2024 to June 2027.
- In Q3/23, the Company extended its $0.5 billion revolving credit facility originally maturing February 2024 to February 2025.
- In Q4/23, the Company repaid $0.405 billion of 1.45% medium-term notes.
- With the Company’s net debt below $10 billion at year end 2023, the Company is now targeting in 2024 to return 100% of free cash flow to shareholders through dividends and share repurchases, per our free cash flow allocation policy. Going forward, the Company will manage this allocation of free cash flow on a forward looking annual basis, while managing working capital and cash management as required.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE HIGHLIGHTS
Canada and Canadian Natural are well positioned to deliver affordable, reliable, safe, and responsibly produced energy that the world needs, through leading ESG performance. Canadian Natural’s diverse portfolio is supported by a large amount of long life low decline assets which have low risk, high value reserves that require low maintenance capital. This allows the Company to remain flexible with its capital allocation and creates an ideal opportunity to pilot and apply technologies for GHG emissions reductions. Canadian Natural continues to invest in a range of technologies to reduce emissions, such as solvents for enhanced recovery and Carbon Capture, Utilization and Storage (“CCUS”) projects. Our culture of continuous improvement provides a significant advantage to delivering on our strategy of investing in GHG technologies across our assets, including opportunities for methane emissions reduction, which will enhance the Company’s environmental performance and long-term sustainability.
Environmental Targets
Canadian Natural is committed to reducing its environmental footprint and as previously announced, has committed to the following environmental targets:
- 40% reduction in corporate Scope 1 and Scope 2 absolute GHG emissions by 2035, from a 2020 baseline
- 50% reduction in North America E&P (including thermal in situ) methane emissions by 2030, from a 2016 baseline
- 40% reduction in thermal in situ fresh water usage intensity by 2026, from a 2017 baseline
- 40% reduction in mining fresh river water usage intensity by 2026, from a 2017 baseline
Canadian Natural has a defined pathway to achieve long-term emissions reductions with an integrated GHG emissions management strategy that includes ongoing investments in technology and innovation while transferring technology across the Company. The areas of focus include, but are not limited to: carbon capture, sequestration/storage and utilization, the use of solvents, energy/steam efficiencies, methane reduction, and tailings and water management.
Pathways Alliance
The six major oil sands companies in the Pathways Alliance (“Pathways”), including Canadian Natural, operate approximately 95% of Canada’s oil sands production. The goal of this unique alliance is to work together with governments to achieve net zero emissions from oil sands operations by 2050, support Canada in meeting its climate commitments and be the preferred source of crude oil globally. Pathways has a defined plan, including its foundational carbon capture and storage (“CCS”) project involving a CO2 transportation line connecting Fort McMurray and Cold Lake to a carbon sequestration hub. The proposed carbon storage hub would be one of the world’s largest carbon capture and storage projects and would be connected to a transportation line that would initially gather captured CO2 from oil sands facilities in the Fort McMurray, Christina Lake and Cold Lake regions. Future phases of the plan have the potential to grow the transportation network to include over 20 oil sands facilities, and to accommodate other industries in the region interested in CCS.
Pathways continues to advance its proposed foundational carbon capture and storage project as it works with governments on the necessary co-investment and regulatory certainty needed to proceed. Work is ongoing to obtain a carbon sequestration agreement from the Government of Alberta to support regulatory applications for the proposed CO2 transportation network and carbon storage hub, which are targeted for submission in the first half of 2024.  Project engineering and environmental field programs are on track to meet timelines. Multiple feasibility studies on phase-one capture facilities, with engineering and design work continue to progress. Stakeholder engagement and consultation is ongoing with Indigenous and local communities in northern Alberta related to the Pathways CCS project.
Government Support for Emissions Reductions and Carbon Capture, Utilization and Storage
The Government of Canada announced a Regulatory Framework for an Oil and Gas Sector Greenhouse Gas Emissions Cap on December 7, 2023 with plans to publish draft regulations by mid-2024. The framework proposes to cap and cut emissions from the oil and natural gas sector through implementation of a national cap-and-trade system. The oil and natural gas sector has made significant progress in GHG emissions reductions along with investments in technology and innovation that have been enabled under existing carbon pricing systems. As such, the proposed oil and natural gas sector emissions cap is unnecessary, exceedingly complex and undermines the investor confidence required for large-scale, long-term emission reduction initiatives.
Canadian Natural is a leader in CCUS and GHG reduction projects and sees many opportunities to work collaboratively with industry peers and governments to advance investments in CCUS and to achieve meaningful GHG emissions reductions in support of Canada’s climate goals. The Government of Canada has proposed an investment tax credit (“ITC”) for CCUS projects for all sectors across Canada that would offer a refundable ITC of up to 50% on capture equipment and 37.5% on qualified carbon transportation, storage or usage equipment from 2022 to 2030. In November 2023, the Government of Alberta announced it would provide a 12% tax credit on eligible capital costs associated with building new CCUS projects. It remains important for governments to work together with industry to ensure that policy and regulatory frameworks deliver the required support to enable CCUS project development.
Canadian Natural will continue to provide input to government on the importance of balancing environmental and economic objectives along with being able to support Canada’s allies with energy security. By working together, industry and governments have the opportunity to help achieve climate goals, meet economic objectives and support Canada’s role in energy security.
2023 YEAR END RESERVES
Determination of Reserves
For the year ended December 31, 2023, the Company retained IQREs, Sproule Associates Limited, 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, 2023
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 | 114 | 106 | 203 | 653 | 6,827 | 4,730 | 138 | 8,829 | ||||||||||||||||
| Developed Non-Producing | 5 | 7 | – | 38 | – | 229 | 7 | 95 | ||||||||||||||||
| Undeveloped | 100 | 80 | 55 | 2,596 | 83 | 10,045 | 398 | 4,986 | ||||||||||||||||
| Total Proved | 218 | 193 | 258 | 3,287 | 6,910 | 15,005 | 543 | 13,910 | ||||||||||||||||
| Probable | 87 | 95 | 107 | 1,903 | 550 | 9,279 | 305 | 4,594 | ||||||||||||||||
| Total Proved plus Probable | 305 | 288 | 365 | 5,191 | 7,460 | 24,284 | 848 | 18,504 |
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 Associates Limited, GLJ Ltd. and McDaniel & Associates Consultants Ltd., dated December 31, 2023:
| 2024 | 2025 | 2026 | 2027 | 2028 | ||||||||||||
| Crude Oil and NGLs | ||||||||||||||||
| WTI | US$/bbl | 73.67 | 74.98 | 76.14 | 77.66 | 79.22 | ||||||||||
| WCS | C$/bbl | 76.74 | 79.77 | 81.12 | 82.88 | 85.04 | ||||||||||
| Canadian Light Sweet | C$/bbl | 92.91 | 95.04 | 96.07 | 97.99 | 99.95 | ||||||||||
| Cromer LSB | C$/bbl | 93.57 | 95.86 | 96.46 | 98.39 | 100.36 | ||||||||||
| Edmonton C5+ | C$/bbl | 96.79 | 98.75 | 100.71 | 102.72 | 104.78 | ||||||||||
| Brent | US$/bbl | 78.00 | 79.18 | 80.36 | 81.79 | 83.41 | ||||||||||
| AECO | C$/MMBtu | 2.20 | 3.37 | 4.05 | 4.13 | 4.21 | ||||||||||
| BC Westcoast Station 2 | C$/MMBtu | 2.06 | 3.25 | 3.93 | 4.01 | 4.09 | ||||||||||
| Henry Hub | US$/MMBtu | 2.75 | 3.64 | 4.02 | 4.10 | 4.18 | ||||||||||
| All prices increase at a rate of 2% per year after 2028. A foreign exchange rate of 0.7517 US$/C$ was used for 2024 and 2025, and 0.7550 US$/C$ was used for 2026 and thereafter in the year end 2023 evaluation. |
||||||||||||||||
- 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 2024 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 2023 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 2023 and net changes in FDC from December 31, 2022 to December 31, 2023 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, 2023 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 (the “Company”) in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule”, “proposed”, “aspiration” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses, and other targets provided throughout this press release and the Management’s Discussion and Analysis (“MD&A”) of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company’s assets at Horizon Oil Sands (“Horizon”), the Athabasca Oil Sands Project (“AOSP”), the Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby thermal oil sands project, the Jackfish thermal oil sands project and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids (“NGLs”) or synthetic crude oil (“SCO”) that the Company may be reliant upon to transport its products to market; the abandonment of certain assets and the timing thereof, the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; and the impact of the Pathways Alliance (“Pathways”) initiative and activities, government support for Pathways and the ability to achieve net zero emissions from oil production, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus (“OPEC+”), the impact of armed conflicts in the Middle East, the impact of the Russian invasion of Ukraine, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company’s products, and the availability and cost of resources required by the Company’s operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company’s current targets are based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the ability of the Company to prevent and recover from a cyberattack, other cyber-related crime and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the Company’s ability to implement strategies and leverage technologies to meet climate change initiatives and emissions targets on the expected timelines; the impact of competition; the Company’s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company’s and its subsidiaries’ ability to secure adequate transportation for its products; unexpected disruptions or delays in the 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 and its subsidiaries’ success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company’s ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); 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; and other circumstances affecting revenues and expenses.
The Company’s operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company’s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this press release 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 press release or the Company’s MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company’s estimates or opinions change.
Special Note Regarding Currency, Financial Information and Production
This press release should be read in conjunction with the Company’s unaudited interim consolidated financial statements (the “financial statements”) and the Company’s MD&A for the three months and year ended December 31, 2023, and audited consolidated financial statements for the year ended December 31, 2022. 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, 2023 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 press release 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 press release, 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, 2022, is available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. Information on the Company’s website does not form part of and is not incorporated by reference in the Company’s MD&A.
Special Note Regarding Non-GAAP and Other Financial Measures
This press release 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 press release, 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, 2023, dated February 28, 2024.
Free Cash Flow
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 debt, pursuant to the free cash flow allocation policy.
| Three Months Ended | Year Ended | ||||||||||||||
| ($ millions) | Dec 31 2023 |
Sep 30 2023 |
Dec 31 2022 |
Dec 31 2023 |
Dec 31 2022 |
||||||||||
| Adjusted funds flow (1) | $ | 4,419 | $ | 4,684 | $ | 4,176 | $ | 15,274 | $ | 19,791 | |||||
| Less: Base capital expenditures (2) | $ | 795 | $ | 896 | $ | 766 | $ | 3,958 | $ | 3,621 | |||||
| Abandonment expenditures, net (3) | $ | 149 | $ | 123 | $ | 84 | $ | 509 | $ | 335 | |||||
| Dividends on common shares | $ | 980 | $ | 984 | $ | 834 | $ | 3,891 | $ | 4,926 | |||||
| Free cash flow | $ | 2,495 | $ | 2,681 | $ | 2,492 | $ | 6,917 | $ | 10,909 | |||||
| (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, 2023, dated February 28, 2024. (2) Item is a component of net capital expenditures. Refer to the “Non-GAAP and Other Financial Measures” section of Company’s MD&A for the three months and year ended December 31, 2023, dated February 28, 2024 for more details on net capital expenditures. (3) Non-GAAP Financial Measure. In prior reporting periods, abandonment expenditures was reported as part of base capital; however, in Q4/23, the Company revised the composition of its net capital expenditures non-GAAP financial measure to exclude expenditures related to the Company’s abandonment program. A reconciliation of abandonment expenditures and abandonment expenditures, net is presented in the “Non-GAAP and Other Financial Measures” section of the Company’s MD&A for the three months and year ended December 31, 2023, dated February 28, 2024. |
|||||||||||||||
The Company’s free cash flow allocation policy is applied based on the Company’s net debt level as follows:
- In 2023 when net debt was between $10 billion and $15 billion, approximately 50% of free cash flow was allocated to shareholder returns and 50% was allocated to the balance sheet, less strategic growth / acquisition opportunities, with free cash flow calculated as adjusted funds flow less base capital expenditures, abandonment expenditures, and dividends on common shares.
- When net debt is at approximately $10 billion, the Company targets to return 100% of free cash flow to shareholders, with free cash flow calculated as adjusted funds flow less net capital expenditures, abandonment expenditures, and dividends on common shares. The Company targets to manage the allocation of free cash flow on a forward looking annual basis, while managing working capital and cash management as required.
Capital Budget
Capital budget is a forward looking non-GAAP financial measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net acquisition costs. Refer to the “Non-GAAP and Other Financial Measures” section of the Company’s MD&A for more details on net capital expenditures.
Long-term Debt, net
Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents.
| ($ millions) | Dec 31 2023 |
Sep 30 2023 |
Dec 31 2022 |
||||||
| Long-term debt | $ | 10,799 | $ | 11,644 | $ | 11,445 | |||
| Less: cash and cash equivalents | 877 | 125 | 920 | ||||||
| Long-term debt, net | $ | 9,922 | $ | 11,519 | $ | 10,525 |
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.
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.
CONFERENCE CALL
Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) will be issuing its 2023 Fourth Quarter and Year End Earnings Results on Thursday, February 29, 2024 before market open.
A conference call will be held at 9:00 a.m. MST / 11:00 a.m. EST on Thursday, February 29, 2024.
Dial-in to the live event:
North America 1-800-717-1738 / International 001-289-514-5100.
Listen to the audio webcast:
Access the audio webcast on the home page of our website, www.cnrl.com.
Conference call playback:
North America 1-888-660-6264 / International 001-289-819-1325 (Passcode: 26260#)
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
2100, 855 – 2nd Street S.W. Calgary, Alberta, T2P4J8
Phone: 403-514-7777 Email:Â ir@cnrl.com
www.cnrl.com
TIM S. MCKAY
Vice-Chairman
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
Share This:
