UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
Pursuant to Rule 13a-16 or 15d-16 of the
Securities Exchange Act of 1934
Dated: November 2, 2023
Commission File Number: 333-12138
CANADIAN NATURAL RESOURCES LIMITED
(Exact name of registrant as specified in its charter)
2100, 855 - 2ND Street S. W., Calgary, Alberta T2P 4J8
(Address of principal executive offices)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ____ Form 40-F X
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ____
Note: Regulation S-T Rule 101(b)(1) only permits the submission in paper of a Form 6-K if submitted solely to provide an attached annual report to security holders.
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ____
Note: Regulation S-T Rule 101(b)(7) only permits the submission in paper of a Form 6-K if submitted to furnish a report or other document that the registrant foreign private issuer must furnish and make public under the laws of the jurisdiction in which the registrant is incorporated, domiciled or legally organized (the registrant's "home country"), or under the rules of the home country exchange on which the registrant's securities are traded, as long as the report or other document is not a press release, is not required to be and has not been distributed to the registrant's security holders, and, if discussing a material event, has already been the subject of a Form 6-K submission or other Commission filing on EDGAR.
Exhibits 99.1, 99.2 and 99.3 to this report, filed on Form 6-K, shall be incorporated by reference as exhibits to the registrant's Registration Statements under the Securities Act of 1933 on Form F-10 (File Nos. 333-219366 and 333-219367).
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| Exhibit Number | Description |
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| 99.1 | |
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| Canadian Natural Resources Limited Announces 2023 Third Quarter Results |
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| 99.2 | |
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| 99.3 | |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | Canadian Natural Resources Limited (Registrant) | |
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| Date: November 2, 2023 | By: | /s/ Stephanie A. Graham | |
| | | Stephanie A. Graham | |
| | | Corporate Secretary & Associate General Counsel, Canada | |
CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES
2023 THIRD QUARTER RESULTS
CALGARY, ALBERTA – NOVEMBER 2, 2023 – FOR IMMEDIATE RELEASE
Commenting on the Company's third quarter 2023 results, Tim McKay, President, stated "Our quarterly results demonstrate how our effective and efficient operations, combined with our diverse product mix generates significant free cash flow, resulting in strong shareholder returns through our sustainable and growing dividend and significant share repurchases.
Our world class assets delivered top tier operational and financial results in Q3/23 with average quarterly production volumes of approximately 1,394,000 BOE/d, which is the highest quarterly volumes in the history of the Company, including record quarterly production volumes for both liquids and natural gas of approximately 1,035,000 bbl/d and 2,151 MMcf/d respectively. Following the completion of planned turnarounds at our Oil Sands Mining and Upgrading assets, synthetic crude oil ("SCO") production was strong, averaging approximately 491,000 bbl/d during Q3/23, capturing robust SCO pricing at a premium to WTI. Additionally, as a result of strong execution in our thermal assets, production growth was ahead of plan, as Q3/23 average thermal production volumes increased by approximately 44,000 bbl/d to 287,000 bbl/d from Q3/22 levels. As a result of our focus on effective and efficient operations, the Company had strong liquid netbacks in Q3/23, similar to Q3/22 netback levels when commodity prices were much higher. This resulted in significant free cash flow for the Company.
Environmental, Social and Governance ("ESG") remains a priority for the Company. Canadian Natural is an investment leader in research and development ("R&D") and our strong track record of R&D investment will continue in 2024 and beyond and is targeted to grow with our participation in the Pathways Alliance. It is critical to work together with the Government of Canada and the Alberta government to make the Pathways Alliance a transformative industry collaboration. Through the foundational Carbon Capture and Storage ("CCS") project, we have a significant opportunity to achieve meaningful GHG emissions reductions in support of industry's, Alberta's and Canada's climate goals and to provide affordable, reliable, responsibly produced energy to the world."
Canadian Natural's Chief Financial Officer, Mark Stainthorpe, added "During the third quarter of 2023, our robust business model delivered strong net earnings of over $2.3 billion, adjusted net earnings of approximately $2.9 billion and strong quarterly adjusted funds flow of approximately $4.7 billion. After our base capital expenditures and dividend, the Company generated significant quarterly free cash flow of approximately $2.7 billion in Q3/23. Our diversified portfolio, including our long life low decline assets, combined with our effective and efficient operations allowed us to continue to deliver robust returns to shareholders by repurchasing shares and reducing debt. Year-to-date, up to and including November 1, 2023, we have returned approximately $6.1 billion to shareholders through dividends and share repurchases.
With current strong production volumes and expected free cash flow in Q4/23 and beyond, based on current strip pricing, we are quickly approaching a net debt level of $10 billion, which we forecast to achieve in Q1/24, at which time we target to increase returns to shareholders to 100% of free cash flow.
Subsequent to quarter end, the Board of Directors has approved an 11% increase to our base quarterly dividend to $1.00 per common share, from $0.90 per common share, demonstrating 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, the Company has increased its dividend by 18% in 2023 to $4.00 per share annually. As a result, the Company's leading track record of dividend increases continues, as this increase will mark 2024 as the 24th consecutive year of dividend increases, with a CAGR of 21% over that time.”
CORPORATE UPDATE
One of Canadian Natural’s many strengths is our strong and deep leadership team. The Company takes a very proactive and 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, at Canadian Natural’s 2023 year end Board meeting on February 28, 2024, Tim McKay will assume the role of Vice Chairman and Scott Stauth, currently Chief Operating Officer, Oil Sands, will be promoted to President of Canadian Natural.
Mr. Stauth has been with Canadian Natural for 26 years in increasingly responsible management roles across all our operations in Canada. Scott Stauth, as Chief Operating Officer, Oil Sands, has played an integral role in delivering top tier performance across all of the Company’s Oil Sands operations.
As Vice Chairman, Mr. McKay will support the management transition until his retirement in summer 2024.
In addition, as part of the succession plan, Jay Froc, currently Senior Vice President Oil Sands Mining and Upgrading, will be promoted to Chief Operating Officer, Oil Sands on January 1, 2024. Mr. Froc has been with Canadian Natural for 10 years.
Trevor Cassidy, Chief Operating Officer, E&P, after over 23 years of contributing to the Company’s success will be retiring in Q4/23, at which time Robin Zabek, currently Senior Vice President Exploitation E&P, will be promoted to Chief Operating Officer, E&P. Mr. Zabek has been with Canadian Natural for 20 years.
Murray Edwards, Executive Chairman of the Company, commenting on the succession stated “Canadian Natural has a strong track record of successful succession at our senior leadership level, ensuring Canadian Natural continues to deliver top tier performance. Mr. Stauth has been a significant contributor to Canadian Natural’s top tier performance over the last 26 years and we are very confident Scott will make even greater contributions as President. In addition, Tim as Vice Chairman will continue to provide oversight and guidance on our operations to ensure a smooth transition.”
Tim McKay, commenting on the succession stated “Scott and I have worked closely together over the years and he has outstanding leadership, technical and operational skills and is an excellent role model for Canadian Natural’s culture, one of our key competitive advantages. We are very confident in Scott’s abilities.”
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| Canadian Natural Resources Limited | 2 | Three and nine months ended September 30, 2023 |
QUARTERLY HIGHLIGHTS
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| Three Months Ended | Nine Months Ended |
($ millions, except per common share amounts) | Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
| Net earnings | $ | 2,344 | | $ | 1,463 | | $ | 2,814 | | $ | 5,606 | | $ | 9,417 | |
| Per common share | – basic | $ | 2.15 | | $ | 1.34 | | $ | 2.52 | | $ | 5.12 | | $ | 8.23 | |
| – diluted | $ | 2.13 | | $ | 1.32 | | $ | 2.49 | | $ | 5.07 | | $ | 8.12 | |
Adjusted net earnings from operations (1) | $ | 2,850 | | $ | 1,256 | | $ | 3,493 | | $ | 5,987 | | $ | 10,669 | |
| Per common share | – basic (2) | $ | 2.61 | | $ | 1.15 | | $ | 3.12 | | $ | 5.47 | | $ | 9.32 | |
| – diluted (2) | $ | 2.59 | | $ | 1.14 | | $ | 3.09 | | $ | 5.41 | | $ | 9.20 | |
| Cash flows from operating activities | $ | 3,498 | | $ | 2,745 | | $ | 6,098 | | $ | 7,538 | | $ | 14,847 | |
Adjusted funds flow (1) | $ | 4,684 | | $ | 2,742 | | $ | 5,208 | | $ | 10,855 | | $ | 15,615 | |
| Per common share | – basic (2) | $ | 4.30 | | $ | 2.50 | | $ | 4.66 | | $ | 9.91 | | $ | 13.64 | |
| – diluted (2) | $ | 4.26 | | $ | 2.48 | | $ | 4.60 | | $ | 9.81 | | $ | 13.47 | |
| Cash flows used in investing activities | $ | 1,199 | | $ | 1,560 | | $ | 1,129 | | $ | 3,912 | | $ | 3,725 | |
Net capital expenditures, excluding net acquisition costs and strategic growth capital (3) | $ | 1,019 | | $ | 1,385 | | $ | 996 | | $ | 3,522 | | $ | 3,106 | |
Net capital expenditures (1) | $ | 1,231 | | $ | 1,669 | | $ | 1,249 | | $ | 4,294 | | $ | 4,154 | |
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| Daily production, before royalties | | | | | |
| Natural gas (MMcf/d) | 2,151 | 2,085 | 2,132 | 2,125 | 2,081 |
| Crude oil and NGLs (bbl/d) | 1,035,153 | 846,909 | 983,678 | 948,587 | 930,079 |
Equivalent production (BOE/d) (4) | 1,393,614 | 1,194,326 | 1,338,940 | 1,302,715 | 1,276,970 |
(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 and nine months ended September 30, 2023 dated November 1, 2023.
(2)Non-GAAP Ratio. 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 and nine months ended September 30, 2023 dated November 1, 2023.
(3)Net capital expenditures, excluding net acquisition costs and strategic growth capital, is defined as base capital expenditures.
(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.
▪The strength of Canadian Natural's long life low decline asset base, supported by our safe, effective and efficient operations, makes our business unique, robust and sustainable. In Q3/23, the Company generated strong financial results, including:
•Net earnings of approximately $2.3 billion and adjusted net earnings from operations of approximately $2.9 billion.
•Cash flows from operating activities of approximately $3.5 billion.
•Adjusted funds flow of approximately $4.7 billion.
•Free cash flow(1) of approximately $2.7 billion(2) after total dividend payments of approximately $1.0 billion and base capital expenditures(3) of approximately $1.0 billion.
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| Canadian Natural Resources Limited | 3 | Three and nine months ended September 30, 2023 |
DIVIDEND INCREASE
▪Subsequent to quarter end, the Board of Directors has approved an 11% increase to our quarterly dividend to $1.00 per common share, from $0.90 per common share, payable on January 5, 2024 to shareholders of record on December 8, 2023. 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. The Company's leading track record of dividend increases continues, as this increase will mark the 24th consecutive year of dividend increases.
•Canadian Natural increased its sustainable and growing dividend twice in 2023 for a total combined increase of 18% to $4.00 per share annually.
QUARTERLY HIGHLIGHTS
▪Returns to shareholders in Q3/23 were strong, totaling approximately $1.6 billion, comprised of approximately $1.0 billion of dividends and approximately $0.6 billion of share repurchases.
•In Q3/23, the Company repurchased approximately 7.2 million common shares for cancellation at a weighted average price of $82.57 per share for a total of approximately $0.6 billion.
▪Year-to-date, up to and including November 1, 2023, the Company has returned approximately $6.1 billion to shareholders through approximately $3.9 billion in dividends and $2.2 billion through the repurchase and cancellation of approximately 27.9 million common shares.
▪Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with net debt(1) of approximately $11.5 billion and significant liquidity(1) of approximately $6.1 billion at the end of Q3/23.
•In September 2023, the Company extended its $0.5 billion revolving credit facility by one year, now maturing February 2025.
▪With current strong production volumes and expected free cash flow in Q4/23 and beyond, based on current strip pricing we are quickly approaching a net debt level of $10 billion, which we forecast to achieve in Q1/24, at which time we target to increase returns to shareholders to 100% of free cash flow. At that time, the free cash flow definition will be adjusted funds flow less dividends and total capital expenditures for the year.
•The Company's current free cash flow allocation policy provides that when net debt is between $10 billion and $15 billion, 50% of free cash flow will be allocated to share repurchases and 50% of free cash flow will be allocated to the balance sheet, less strategic growth / acquisition opportunities. Free cash flow for the purpose of the policy is defined as adjusted funds flow less dividends, less base capital.
▪In Q3/23, Canadian Natural continued to focus on safe, effective and efficient operations, achieving record quarterly average production volumes of 1,393,614 BOE/d, an increase of 4% or approximately 55,000 BOE/d compared to Q3/22 levels.
•The Company achieved record quarterly average liquids production volumes in Q3/23 of 1,035,153 bbl/d, an increase of 5% over Q3/22 levels of 983,678 bbl/d.
•Our focus on execution and effective and efficient operations drove strong liquids netbacks in Q3/23, similar to Q3/22 netback levels when commodity prices were much higher, generating significant free cash flow for the Company.
◦Canadian Natural continues to focus on safe, effective and efficient operations of its world class Oil Sands Mining and Upgrading assets to deliver high value SCO, with strong quarterly production averaging 490,853 bbl/d in Q3/23, comparable to Q3/22 levels of 487,553 bbl/d.
◦Oil Sands Mining and Upgrading operating costs were top tier, averaging $22.12/bbl (US$16.49/bbl) of SCO in Q3/23, comparable to Q3/22 costs of $22.35/bbl (US$17.12/bbl).
◦Based on the current forward strip as of October 30, 2023, these high margin SCO barrels will capture strong pricing with a strip average premium to WTI pricing of approximately US$2.24/bbl in Q4/23, generating significant free cash flow for the Company.
◦As a result of strong execution on the Company's thermal growth plan, total thermal production averaged 287,085 bbl/d in Q3/23, an increase of 43,692 bbl/d or 18% compared to Q3/22 levels of 243,393 bbl/d. The increase in production was primarily driven by strong execution and bringing production on earlier than originally planned on the new Primrose CSS and Kirby SAGD pads.
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| Canadian Natural Resources Limited | 4 | Three and nine months ended September 30, 2023 |
◦Thermal in situ operating costs averaged $11.47/bbl (US$8.55/bbl) in Q3/23, a decrease of 27% from Q3/22 levels, primarily reflecting the impact of higher production volumes and lower natural gas fuel costs.
•The Company achieved record quarterly natural gas production volumes in Q3/23, averaging 2,151 MMcf/d, comparable to Q3/22 levels of 2,132 MMcf/d.
▪The Company's strategic growth plan includes increasing production from our long life no decline Oil Sands Mining and Upgrading assets. At Horizon, after the planned turnaround in 2024, the reliability enhancement project is targeted to be completed which will increase SCO production capacity by approximately 14,000 bbl/d in 2025 as the Company targets to shift maintenance to once every two years, reducing downtime and increasing overall reliability.
(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 and nine months ended September 30, 2023, dated November 1, 2023.
(2)Based on sum of rounded numbers.
(3)Item is component of net capital expenditures. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and nine months ended September 30, 2023 for more details on net capital expenditures.
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| Canadian Natural Resources Limited | 5 | Three and nine months ended September 30, 2023 |
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 budgeted 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 our top tier thermal in situ oil sands operations and our 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, by owning and operating most of the related infrastructure, Canadian Natural is able to control major components of the Company's operating costs and minimize production commitments. Low capital exposure projects can be quickly stopped or started depending upon success, market conditions or corporate needs.
Canadian Natural’s balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.
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| Drilling Activity | Nine Months Ended September 30 |
| 2023 | 2022 |
(number of wells) | Gross | Net | Gross | Net |
Crude oil (1) | 186 | | 179 | 242 | | 237 |
| Natural gas | 61 | | 52 | 85 | | 57 |
| Dry | 2 | | 2 | 1 | | 1 |
| Subtotal | 249 | | 233 | 328 | | 295 |
| Stratigraphic test / service wells | 476 | | 414 | 477 | | 409 |
| Total | 725 | | 647 | 805 | | 704 |
| Success rate (excluding stratigraphic test / service wells) | | 99% | | 99% |
(1)Includes bitumen wells.
▪The Company drilled a total of 233 net crude oil and natural gas producer wells in the nine months ended September 30, 2023 compared to 295 during the nine months ended September 30, 2022, a decrease of 62 net wells over this time period.
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| Canadian Natural Resources Limited | 6 | Three and nine months ended September 30, 2023 |
North America Exploration and Production
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Crude oil and NGLs – excluding Thermal In Situ Oil Sands | | |
| Three Months Ended | Nine Months Ended |
| Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
Crude oil and NGLs production (bbl/d) | 232,496 | 226,202 | 228,239 | 231,047 | 226,125 |
Net wells targeting crude oil | 42 | 29 | 60 | 131 | 143 |
Net successful wells drilled | 42 | 29 | 60 | 129 | 142 |
Success rate | 100% | 100% | 100% | 98% | 99% |
▪North America E&P liquids production, excluding thermal in situ, averaged 232,496 bbl/d in Q3/23, a 2% increase compared to Q3/22 levels, primarily reflecting drilling activity on the Company's primary heavy crude oil assets, offset by natural field declines.
•Primary heavy crude oil production averaged 76,377 bbl/d in Q3/23, an 11% increase from Q3/22 levels, reflecting drilling results. The Company continues to successfully drill Mannville multilateral wells in the Bonnyville/Lloydminster and Clearwater fairways, having drilled 34 and 78 net multilateral primary heavy crude oil wells in Q3/23 and the first nine months of 2023 respectively.
◦Operating costs(1) in the Company's primary heavy crude oil operations averaged $19.68/bbl (US$14.67/bbl) in Q3/23, a decrease of 8% from Q3/22 levels, primarily reflecting higher volumes.
•Pelican Lake production averaged 46,897 bbl/d in Q3/23, a decrease of 6% from Q3/22 levels, consistent with historical low natural field declines from this long life low decline asset.
◦Operating costs at Pelican Lake averaged $8.02/bbl (US$5.98/bbl) in Q3/23, representing a decrease of 10% from Q3/22 levels, primarily due to lower power costs.
•North America light crude oil and NGLs production averaged 109,222 bbl/d in Q3/23, comparable to Q3/22 levels.
◦Operating costs on the Company's North America light crude oil and NGLs production averaged $15.49/bbl (US$11.55/bbl) in Q3/23, a 7% decrease from Q3/22 levels, primarily due to lower power costs.
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Thermal In Situ Oil Sands | | |
| Three Months Ended | Nine Months Ended |
| Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
Bitumen production (bbl/d) | 287,085 | 238,941 | 243,393 | 256,466 | 251,626 |
Net wells targeting bitumen | 2 | 23 | 38 | 50 | 95 |
Net successful wells drilled | 2 | 23 | 38 | 50 | 95 |
Success rate | 100% | 100% | 100% | 100% | 100% |
▪As a result of strong execution on the Company's thermal growth plan, total thermal production averaged 287,085 bbl/d in Q3/23, an increase of 43,692 bbl/d or 18% compared to Q3/22 levels of 243,393 bbl/d. The increase in production was primarily driven by strong execution, bringing production on earlier than originally planned on the new Primrose CSS and Kirby SAGD pads.
•Thermal in situ operating costs averaged $11.47/bbl (US$8.55/bbl) in Q3/23, a decrease of 27% from Q3/22 levels, primarily reflecting the impact of higher production volumes and lower natural gas fuel costs.
▪Canadian Natural continues to deliver safe, reliable, production growth from its long life low decline thermal in situ assets which have decades of strong capital efficient growth opportunities. Highlights include:
•At Primrose, the Company delivered production of 107,814 bbl/d in Q3/23, significant growth from prior periods as a result of production from the two CSS pads drilled in 2022, which came on production ahead of schedule.
(1)Calculated as production expense divided by respective sales volumes. Natural gas and NGLs production volumes approximate sales volumes.
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| Canadian Natural Resources Limited | 7 | Three and nine months ended September 30, 2023 |
•At Kirby, current production is approximately 65,000 bbl/d as the Company has grown production by approximately 15,000 bbl/d from Q4/22 levels. The significant production growth is due to the development of four SAGD pads, the first of which reached full production capacity in Q3/23. The three remaining pads are targeted to ramp up to full production capacity over the first nine months of 2024, at a pace of one pad per quarter, maintaining this production level.
•At Jackfish, two SAGD pads were drilled in the first half of 2023, with production from these pads targeted to ramp up to their full production capacities in Q3/24 and Q4/24, supporting continued high utilization rates.
▪Canadian Natural has been piloting solvent enhanced oil recovery technology on certain thermal in situ assets with an objective to increase bitumen production, reduce the Steam to Oil Ratio ("SOR"), reduce GHG intensity and realize high solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
•At Kirby North, the Company is moving forward with the commercial scale solvent SAGD pad development. The Company continued facility module fabrication in Q3/23 and targets to begin solvent injection in mid-2024.
•At Primrose, the Company is currently piloting solvent enhanced oil recovery in the steam flood area and is targeting SOR and GHG intensity reductions of 40% to 45%, with solvent recovery greater than 70%, which has been successful to-date. The Company targets to continue to use the pilot into 2024 to evaluate the potential of various solvent concentrations to improve overall performance.
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North America Natural Gas | | |
| Three Months Ended | Nine Months Ended |
| Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
Natural gas production (MMcf/d) | 2,139 | 2,072 | 2,117 | 2,113 | 2,065 |
Net wells targeting natural gas | 10 | 21 | 14 | 52 | 57 |
Net successful wells drilled | 10 | 21 | 14 | 52 | 57 |
Success rate | 100% | 100% | 100% | 100% | 100% |
▪Canadian Natural achieved record quarterly natural gas production in North America of 2,139 MMcf/d in Q3/23, comparable to Q3/22 levels of 2,117 MMcf/d. Production in Q3/23 included minor impacts from wildfires of approximately 11 MMcf/d.
•North America natural gas operating costs averaged $1.22/Mcf in Q3/23, an increase of 8% compared to Q3/22 levels, primarily reflecting higher service costs. The Company continues to focus on cost control and effective and efficient operations to offset cost pressures.
International Exploration and Production
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| Three Months Ended | Nine Months Ended |
| Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
Crude oil production (bbl/d) | 24,719 | 26,520 | 24,493 | 26,180 | 27,340 |
Natural gas production (MMcf/d) | 12 | 13 | 15 | 12 | 16 |
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▪International E&P crude oil production volumes averaged 24,719 bbl/d in Q3/23, comparable to Q3/22 levels. Production volumes in the North Sea during Q3/23 were impacted by maintenance activities with additional planned maintenance activities targeted to continue into Q4/23.
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| Canadian Natural Resources Limited | 8 | Three and nine months ended September 30, 2023 |
North America Oil Sands Mining and Upgrading
| | | | | | | | | | | | | | | | | |
| Three Months Ended | Nine Months Ended |
| Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
Synthetic crude oil production (bbl/d) (1)(2) | 490,853 | 355,246 | 487,553 | 434,895 | | 424,988 | |
(1)SCO production before royalties and excludes production volumes consumed internally as diesel.
(2)Consists of heavy and light synthetic crude oil products.
▪Canadian Natural continues to focus on safe, reliable, effective and efficient operations of its world class Oil Sands Mining and Upgrading assets to deliver high value SCO, with strong production averaging 490,853 bbl/d in Q3/23, comparable to Q3/22 levels.
•Oil Sands Mining and Upgrading operating costs were top tier, averaging $22.12/bbl (US$16.49/bbl) in Q3/23, comparable to Q3/22 levels of $22.35/bbl (US$17.12/bbl).
▪The Company realized strong SCO pricing based on benchmark pricing of US$84.99/bbl in Q3/23, representing a US$2.81/bbl premium to WTI, generating significant free cash flow for the Company.
▪Based on the current forward strip as of October 30, 2023, these high margin SCO barrels will capture strong pricing with a strip average premium to WTI pricing of approximately US$2.24/bbl in Q4/23, generating significant free cash flow for the Company.
▪At Horizon, after the planned turnaround in 2024, the reliability enhancement project is targeted to be completed which will increase SCO production capacity by approximately 14,000 bbl/d in 2025 as the Company targets to shift maintenance to once every two years, reducing downtime and increasing overall reliability.
MARKETING
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| Three Months Ended | Nine Months Ended |
| Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
| Crude oil and NGLs pricing | | | | | |
WTI benchmark price (US$/bbl) (1) | $ | 82.18 | $ | 73.75 | $ | 91.64 | $ | 77.37 | $ | 98.14 |
WCS heavy differential as a percentage of WTI (%) (2) | 16% | 20% | 22% | 23% | 16% |
SCO benchmark price (US$/bbl) | $ | 84.99 | $ | 76.67 | $ | 100.51 | $ | 79.97 | $ | 102.66 |
Condensate benchmark price (US$/bbl) | $ | 77.91 | $ | 72.28 | $ | 87.15 | $ | 76.66 | $ | 97.19 |
Exploration & Production liquids realized pricing (C$/bbl) (3)(4) | $ | 87.83 | $ | 72.06 | $ | 84.91 | $ | 73.45 | $ | 97.99 |
SCO realized pricing (C$/bbl) (4)(5) | $ | 108.55 | $ | 95.08 | $ | 120.91 | $ | 100.57 | $ | 122.45 |
| Natural gas pricing | | | | | |
AECO benchmark price (C$/GJ) | $ | 2.26 | $ | 2.22 | $ | 5.51 | $ | 2.86 | $ | 5.27 |
Natural gas realized pricing (C$/Mcf) (5) | $ | 2.81 | $ | 2.53 | $ | 6.57 | $ | 3.20 | $ | 6.61 |
(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 and nine months ended September 30, 2023 dated November 1, 2023.
(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, thermal in situ bitumen and SCO.
▪WTI prices were strong in Q3/23, averaging US$82.18/bbl, however remain volatile as a result of geopolitical factors and demand concerns driven by the risk of a global recession due to persistent inflation and rising interest rates.
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| Canadian Natural Resources Limited | 9 | Three and nine months ended September 30, 2023 |
▪SCO benchmark pricing continued to represent a price premium of US$2.81/bbl to WTI pricing as a result of strong North American demand for refined products, with the SCO benchmark price averaging US$84.99/bbl in Q3/23.
▪The WCS differential to WTI was US$12.86/bbl or 16% in Q3/23 compared to US$24.74/bbl or 33% in Q1/23. Strong differentials in Q3/23 primarily reflected strengthening of US Gulf Coast heavy oil pricing in 2023 and a decrease in supply from the US Strategic Petroleum Reserve following releases in 2022.
▪The North West Redwater ("NWR") refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 78,376 BOE/d in Q3/23.
▪Canadian Natural has diversified sales points which limits exposure to any one particular market and maximizes value for our shareholders. Based on production volumes during the first nine months of 2023, the Company purchased natural gas at AECO to use in our operations, offsetting the equivalent of approximately 37% of our natural gas production, with approximately 26% of our natural gas production sold at AECO/Station 2 pricing, and approximately 37% exported and sold to other North American and international markets.
•As a result of the Company's diversified sales points, Canadian Natural's North American natural gas production of 2,139 MMcf/d realized a premium to AECO of 14% above the monthly AECO natural gas quarterly benchmark price of $2.26/GJ in Q3/23. Benchmark natural gas prices primarily reflect increased North American production and higher storage levels.
▪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.
•The Trans Mountain Corporation ("Trans Mountain") provided an update on its 590,000 bbl/d Trans Mountain Expansion project ("TMX"), on which Canadian Natural has committed 94,000 bbl/d.
◦Trans Mountain has filed an application with the Canada Energy Regulator ("CER") to set the interim tolls for transportation on the TMX expansion.
FINANCIAL REVIEW
▪The Company continues to implement proven strategies including its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. 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.
▪Safe, effective and efficient operations combined with our high quality, long life low decline asset base generated quarterly free cash flow of approximately $2.7 billion after dividend payments of approximately $1.0 billion and base capital expenditures of approximately $1.0 billion (excluding net acquisitions and strategic growth capital of approximately $0.2 billion in the quarter, as per the Company's free cash flow allocation policy).
▪With current strong production volumes and expected free cash flow in Q4/23 and beyond, based on current strip pricing we are quickly approaching a net debt level of $10 billion, which we forecast to achieve in Q1/24, at which time we target to increase returns to shareholders to 100% of free cash flow. At that time, the free cash flow definition will be adjusted funds flow less dividends and total capital expenditures for the year.
•The Company's current free cash flow allocation policy provides that when net debt is between $10 billion and $15 billion, 50% of free cash flow will be allocated to share repurchases and 50% of free cash flow will be allocated to the balance sheet, less strategic growth / acquisition opportunities. Free cash flow for the purpose of the policy is defined as adjusted funds flow less dividends, less base capital.
▪Returns to shareholders in Q3/23 were strong, totaling approximately $1.6 billion, comprised of approximately $1.0 billion of dividends and approximately $0.6 billion of share repurchases.
•In Q3/23, the Company repurchased approximately 7.2 million common shares for cancellation at a weighted average price of $82.57 per share for a total of approximately $0.6 billion.
▪Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with net debt of approximately $11.5 billion and significant liquidity of approximately $6.1 billion at the end of Q3/23.
•Undrawn revolving bank credit facilities totaling approximately $5.5 billion were available at September 30, 2023. Including cash and cash equivalents and short-term investments, the Company had significant liquidity of approximately $6.1 billion. At September 30, 2023, the Company had $202 million drawn
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| Canadian Natural Resources Limited | 10 | Three and nine months ended September 30, 2023 |
under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
•In September 2023, the Company extended its $0.5 billion revolving credit facility by one year, now maturing February 2025.
▪Year-to-date, up to and including November 1, 2023, the Company has returned approximately $6.1 billion to shareholders through approximately $3.9 billion in dividends and $2.2 billion through the repurchase and cancellation of approximately 27.9 million common shares.
DIVIDEND INCREASE
▪Subsequent to quarter end, the Board of Directors has approved an 11% increase to our quarterly dividend to $1.00 per common share, from $0.90 per common share, payable on January 5, 2024 to shareholders of record on December 8, 2023. 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. The Company's leading track record of dividend increases continues, as this increase will mark the 24th consecutive year of dividend increases.
•Canadian Natural increased its sustainable and growing dividend twice in 2023 for a total combined increase of 18% to $4.00 per share annually.
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 us to remain flexible with our capital allocation and creates an ideal opportunity to pilot and apply technologies for GHG emissions reductions. Canadian Natural continues to invest in a range of technologies to reduce emissions, such as solvents for enhanced recovery and Carbon Capture, Utilization and Storage ("CCUS") projects. Our culture of continuous improvement provides a significant advantage to delivering on our strategy of investing in GHG technologies across our assets, including opportunities for methane emissions reduction, 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.
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 support Canada in meeting its climate commitments and position Canada to be the preferred source of crude oil globally.
Working collectively with the federal and provincial governments, Pathways has a goal to achieve net zero GHG emissions from oil sands operations by 2050 and is pursuing realistic and workable solutions to deliver significant emissions reductions. Pathways recognizes there are multiple technologies which contribute to achieving net zero emissions in the oil sands, including the deployment of existing and emerging GHG reduction technologies such as direct air capture, clean hydrogen, process improvements, energy efficiency, fuel switching and electrification.
Pathways has a defined plan, including its foundational CCS project involving a CO2 trunkline connecting Fort McMurray and Cold Lake to a carbon sequestration hub. In January 2023, Pathways entered into a Carbon Sequestration Evaluation Agreement with the Government of Alberta. During Q3/23, technical teams continued to advance detailed evaluations for the proposed storage hub to enhance understanding of the geology in the hub region. 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 an anticipated 14 oil sands facilities in the Fort McMurray, Christina Lake and Cold Lake regions. Future phases of the plan have the potential to
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| Canadian Natural Resources Limited | 11 | Three and nine months ended September 30, 2023 |
grow the transportation network to include over 20 oil sands facilities, and to accommodate other industries in the region interested in CCS.
Members of Pathways continue to advance community engagement and environmental field programs to minimize the project’s environmental disturbance. Project engineering and environmental field programs are on track for this anchor project to meet timelines set out, subject to government support on these efforts. 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
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. Updated draft legislation was released for consultation in Q3/23. It will be important for government to work together with industry to ensure that the ITC implementation delivers required support to enable CCUS project development.
The Government of Alberta's 2023 Budget announcement on February 28, 2023 included support for CCS projects and coordination with federal CCS initiatives. In addition, the Government of Alberta released its Emissions Reduction and Energy Development Plan ("ERED") on April 19, 2023, which outlines the importance of ensuring a globally competitive oil and natural gas industry while reducing emissions and an aspiration to achieve net zero by 2050. By working together, industry and governments have the opportunity to help achieve climate goals, meet economic objectives and support Canada’s role in energy security.
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| Canadian Natural Resources Limited | 12 | Three and nine months ended September 30, 2023 |
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 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, continuing effects of the novel coronavirus ("COVID-19") pandemic, 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, 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 and other cyber-related crime; 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; 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 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
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| Canadian Natural Resources Limited | 13 | Three and nine months ended September 30, 2023 |
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 and nine months ended September 30, 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 and nine months ended September 30, 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.
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| Canadian Natural Resources Limited | 14 | Three and nine months ended September 30, 2023 |
Special Note Regarding Non-GAAP and Other Financial Measures
This press release includes references to 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 and nine months ended September 30, 2023, dated November 1, 2023.
Free Cash Flow
Free cash flow is a non-GAAP financial measure that represents adjusted funds flow adjusted for base capital expenditures and dividends on common shares. 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.
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| Three Months Ended | Nine Months Ended | |
| ($ millions) | Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 | |
Adjusted funds flow (1) | $ | 4,684 | | $ | 2,742 | | $ | 5,208 | | $ | 10,855 | | $ | 15,615 | | |
Less: Base capital expenditures (2) | $ | 1,019 | | $ | 1,385 | | $ | 996 | | $ | 3,522 | | $ | 3,106 | | |
| Dividends on common shares | $ | 984 | | $ | 989 | | $ | 2,532 | | $ | 2,911 | | $ | 4,092 | | |
| Free cash flow | $ | 2,681 | | $ | 368 | | $ | 1,680 | | $ | 4,422 | | $ | 8,417 | | |
(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 and nine months ended September 30, 2023, dated November 1, 2023.
(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 and nine months ended September 30, 2023, dated November 1, 2023 for more details on net capital expenditures.
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.
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.
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| Canadian Natural Resources Limited | 15 | Three and nine months ended September 30, 2023 |
CONFERENCE CALL
Canadian Natural Resources Limited (TSX-CNQ / NYSE-CNQ) will be issuing its 2023 Third Quarter Earnings Results on Thursday, November 2, 2023 before market open.
A conference call will be held at 9:00 a.m. MDT / 11:00 a.m. EDT on Thursday, November 2, 2023.
Dial-in to the live event:
North America 1-888-886-7786 / International 001-416-764-8658
Listen to the audio webcast:
Access the audio webcast on the home page of our website, www.cnrl.com.
Conference call playback:
North America 1-877-674-7070 / International 001-416-764-8692 (Passcode: 113056#)
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 |
2100, 855 - 2nd Street S.W. Calgary, Alberta, T2P4J8 Phone: 403-514-7777 Email: ir@cnrl.com www.cnrl.com |
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TIM S. MCKAY 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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| Canadian Natural Resources Limited | 16 | Three and nine months ended September 30, 2023 |
CANADIAN NATURAL RESOURCES LIMITED
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MANAGEMENT'S DISCUSSION & ANALYSIS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2023 |
| NOVEMBER 1, 2023 |
MANAGEMENT'S DISCUSSION AND ANALYSIS
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 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 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, continuing effects of the novel coronavirus ("COVID-19") pandemic, 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, 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 and other cyber-related crime; 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; 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 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
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| Canadian Natural Resources Limited | 1 | Three and nine months ended September 30, 2023 |
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 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 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 Non-GAAP and Other Financial Measures
This MD&A 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 ("NI 52-112"). Non-GAAP measures are used by the Company to evaluate its financial performance, financial position or cash flow. Descriptions of the Company's non-GAAP and other financial measures included in this MD&A, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided in the "Non-GAAP and Other Financial Measures" section of this MD&A.
Special Note Regarding Currency, Financial Information and Production
This MD&A should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") for the three and nine months ended September 30, 2023, and the Company's MD&A 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 for the three and nine months ended September 30, 2023 and this MD&A 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 MD&A 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 MD&A, 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.
The following discussion and analysis refers primarily to the Company's financial results for the three and nine months ended September 30, 2023 in relation to the comparable periods in 2022 and the second quarter of 2023. The accompanying tables form an integral part of this MD&A. 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 this MD&A. This MD&A is dated November 1, 2023.
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| Canadian Natural Resources Limited | 2 | Three and nine months ended September 30, 2023 |
FINANCIAL HIGHLIGHTS
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| | | Three Months Ended | | | Nine Months Ended |
| ($ millions, except per common share amounts) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Product sales (1) | | $ | 11,762 | | | $ | 8,846 | | | $ | 12,574 | | | | $ | 30,156 | | | $ | 38,518 | |
| Crude oil and NGLs | | $ | 10,944 | | | $ | 8,115 | | | $ | 11,001 | | | | $ | 27,471 | | | $ | 33,501 | |
| Natural gas | | | $ | 599 | | | $ | 522 | | | $ | 1,342 | | | | $ | 1,972 | | | $ | 3,949 | |
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| Net earnings | | $ | 2,344 | | | $ | 1,463 | | | $ | 2,814 | | | | $ | 5,606 | | | $ | 9,417 | |
| Per common share | – basic | | $ | 2.15 | | | $ | 1.34 | | | $ | 2.52 | | | | $ | 5.12 | | | $ | 8.23 | |
| | – diluted | | $ | 2.13 | | | $ | 1.32 | | | $ | 2.49 | | | | $ | 5.07 | | | $ | 8.12 | |
Adjusted net earnings from operations (2) | | $ | 2,850 | | | $ | 1,256 | | | $ | 3,493 | | | | $ | 5,987 | | | $ | 10,669 | |
| Per common share | – basic (3) | | $ | 2.61 | | | $ | 1.15 | | | $ | 3.12 | | | | $ | 5.47 | | | $ | 9.32 | |
| | – diluted (3) | | $ | 2.59 | | | $ | 1.14 | | | $ | 3.09 | | | | $ | 5.41 | | | $ | 9.20 | |
| Cash flows from operating activities | | $ | 3,498 | | | $ | 2,745 | | | $ | 6,098 | | | | $ | 7,538 | | | $ | 14,847 | |
Adjusted funds flow (2) | | $ | 4,684 | | | $ | 2,742 | | | $ | 5,208 | | | | $ | 10,855 | | | $ | 15,615 | |
| Per common share | – basic (3) | | $ | 4.30 | | | $ | 2.50 | | | $ | 4.66 | | | | $ | 9.91 | | | $ | 13.64 | |
| | – diluted (3) | | $ | 4.26 | | | $ | 2.48 | | | $ | 4.60 | | | | $ | 9.81 | | | $ | 13.47 | |
| Cash flows used in investing activities | | $ | 1,199 | | | $ | 1,560 | | | $ | 1,129 | | | | $ | 3,912 | | | $ | 3,725 | |
Net capital expenditures (2) | | $ | 1,231 | | | $ | 1,669 | | | $ | 1,249 | | | | $ | 4,294 | | | $ | 4,154 | |
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(1)Further details related to product sales are disclosed in note 17 to the financial statements.
(2)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
SUMMARY OF FINANCIAL HIGHLIGHTS
Consolidated Net Earnings and Adjusted Net Earnings from Operations
Net earnings for the nine months ended September 30, 2023 were $5,606 million compared with $9,417 million for the nine months ended September 30, 2022. Net earnings for the nine months ended September 30, 2023 included non-operating losses, net of tax, of $381 million compared with non-operating losses of $1,252 million for the nine months ended September 30, 2022 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on the settlement of the cross currency swap, the gain from investments, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the nine months ended September 30, 2023 were $5,987 million compared with $10,669 million for the nine months ended September 30, 2022.
Net earnings for the third quarter of 2023 were $2,344 million compared with $2,814 million for the third quarter of 2022 and $1,463 million for the second quarter of 2023. Net earnings for the third quarter of 2023 included non-operating losses, net of tax, of $506 million compared with non-operating losses of $679 million for the third quarter of 2022 and non-operating income of $207 million for the second quarter of 2023 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, the gain from investments, and government grant income under the provincial well-site rehabilitation programs. Excluding these items, adjusted net earnings from operations for the third quarter of 2023 were $2,850 million compared with $3,493 million for the third quarter of 2022 and $1,256 million for the second quarter of 2023.
The decrease in net earnings and adjusted net earnings from operations for the nine months ended September 30, 2023 from the nine months ended September 30, 2022 primarily reflected:
▪lower realized crude oil and NGLs pricing (1) in the North America segment;
▪lower realized SCO sales pricing (1) in the Oil Sands Mining and Upgrading segment; and
▪lower realized natural gas pricing in the Exploration and Production segments;
partially offset by:
▪higher crude oil and NGLs sales volumes in the North America segment; and
▪higher SCO sales volumes in the Oil Sands Mining and Upgrading segment.
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
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| Canadian Natural Resources Limited | 3 | Three and nine months ended September 30, 2023 |
The decrease in net earnings and adjusted net earnings from operations for the third quarter of 2023 from the third quarter of 2022 primarily reflected:
▪lower realized natural gas pricing in the North America segment; and
▪lower realized SCO sales pricing in the Oil Sands Mining and Upgrading segment;
partially offset by:
▪higher crude oil and NGLs sales volumes and netbacks in the North America segment.
The increase in net earnings and adjusted net earnings from operations for the third quarter of 2023 from the second quarter of 2023 primarily reflected:
▪higher SCO sales volumes and realized SCO sales pricing in the Oil Sands Mining and Upgrading segment;
▪higher crude oil and NGLs sales volumes and netbacks in the North America segment; and
▪higher natural gas sales volumes and realized natural gas pricing in the North America segment.
The impacts of share-based compensation, risk management activities, fluctuations in foreign exchange rates, and the gain from investments, also contributed to the movements in net earnings. These items are discussed in detail in the relevant sections of this MD&A.
Cash Flows from Operating Activities and Adjusted Funds Flow
Cash flows from operating activities for the nine months ended September 30, 2023 were $7,538 million compared with $14,847 million for the nine months ended September 30, 2022. Cash flows from operating activities for the third quarter of 2023 were $3,498 million compared with $6,098 million for the third quarter of 2022 and $2,745 million for the second quarter of 2023. The fluctuations in cash flows from operating activities from the comparable periods were primarily due to the factors previously noted related to the fluctuations in adjusted net earnings from operations, together with the impact of net changes in non-cash working capital.
Adjusted funds flow for the nine months ended September 30, 2023 was $10,855 million compared with $15,615 million for the nine months ended September 30, 2022. Adjusted funds flow for the third quarter of 2023 was $4,684 million compared with $5,208 million for the third quarter of 2022 and $2,742 million for the second quarter of 2023. The fluctuations in adjusted funds flow from the comparable periods were primarily due to the factors noted above related to the fluctuations in cash flows from operating activities, excluding the impact of the net change in non-cash working capital, abandonment expenditures, government grant income under the provincial well-site rehabilitation programs, and movements in other long-term assets, including the unamortized cost of the share bonus program.
Production Volumes
Crude oil and NGLs production before royalties for the third quarter of 2023 of 1,035,153 bbl/d increased 5% from 983,678 bbl/d for the third quarter of 2022, and increased 22% from 846,909 bbl/d for the second quarter of 2023. Record natural gas production before royalties for the third quarter of 2023 of 2,151 MMcf/d was comparable with 2,132 MMcf/d for the third quarter of 2022, and increased 3% from 2,085 MMcf/d for the second quarter of 2023. Total production before royalties for the third quarter of 2023 of 1,393,614 BOE/d increased 4% from 1,338,940 BOE/d for the third quarter of 2022, and increased 17% from 1,194,326 BOE/d for the second quarter of 2023. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production, before royalties" section of this MD&A.
Product Prices
In the Company's Exploration and Production segments, realized crude oil and NGLs prices averaged $87.83 per bbl for the third quarter of 2023, an increase of 3% from $84.91 per bbl for the third quarter of 2022, and an increase of 22% from $72.06 per bbl for the second quarter of 2023. The realized natural gas price decreased 57% to average $2.81 per Mcf for the third quarter of 2023 from $6.57 per Mcf for the third quarter of 2022, and increased 11% from $2.53 per Mcf for the second quarter of 2023. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price decreased 10% to average $108.55 per bbl for the third quarter of 2023 from $120.91 per bbl for the third quarter of 2022, and increased 14% from $95.08 per bbl for the second quarter of 2023. The Company's realized pricing reflected prevailing benchmark pricing. Crude oil and NGLs and natural gas prices are discussed in detail in the "Business Environment", "Realized Product Prices – Exploration and Production", and the "Oil Sands Mining and Upgrading" sections of this MD&A.
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| Canadian Natural Resources Limited | 4 | Three and nine months ended September 30, 2023 |
Production Expense
In the Company's Exploration and Production segments, crude oil and NGLs production expense (1) averaged $14.40 per bbl for the third quarter of 2023, a decrease of 15% from $16.86 per bbl for the third quarter of 2022, and a decrease of 22% from $18.38 per bbl for the second quarter of 2023. Natural gas production expense (1) averaged $1.25 per Mcf for the third quarter of 2023, an increase of 8% from $1.16 per Mcf for the third quarter of 2022, and a decrease of 9% from $1.37 per Mcf for the second quarter of 2023. In the Oil Sands Mining and Upgrading segment, production expense (1) averaged $22.12 per bbl for the third quarter of 2023, comparable with $22.35 per bbl for the third quarter of 2022, and a decrease of 29% from $31.28 per bbl for the second quarter of 2023. Crude oil and NGLs and natural gas production expense is discussed in detail in the "Production Expense – Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.
SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company's quarterly financial results for the eight most recently completed quarters:
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| ($ millions, except per common share amounts) | | Sep 30
2023 | | Jun 30
2023 | | Mar 31
2023 | | Dec 31
2022 |
Product sales (1) | | $ | 11,762 | | | $ | 8,846 | | | $ | 9,548 | | | $ | 11,012 | |
| Crude oil and NGLs | | $ | 10,944 | | | $ | 8,115 | | | $ | 8,412 | | | $ | 9,508 | |
| Natural gas | | $ | 599 | | | $ | 522 | | | $ | 851 | | | $ | 1,287 | |
| Net earnings | | $ | 2,344 | | | $ | 1,463 | | | $ | 1,799 | | | $ | 1,520 | |
| Net earnings per common share | | | | | | | | |
| – basic | | $ | 2.15 | | | $ | 1.34 | | | $ | 1.63 | | | $ | 1.37 | |
| – diluted | | $ | 2.13 | | | $ | 1.32 | | | $ | 1.62 | | | $ | 1.36 | |
| ($ millions, except per common share amounts) | | Sep 30
2022 | | Jun 30
2022 | | Mar 31
2022 | | Dec 31
2021 |
Product sales (1) | | $ | 12,574 | | | $ | 13,812 | | | $ | 12,132 | | | $ | 10,190 | |
| Crude oil and NGLs | | $ | 11,001 | | | $ | 11,727 | | | $ | 10,773 | | | $ | 8,979 | |
| Natural gas | | $ | 1,342 | | | $ | 1,605 | | | $ | 1,002 | | | $ | 958 | |
| Net earnings | | $ | 2,814 | | | $ | 3,502 | | | $ | 3,101 | | | $ | 2,534 | |
| Net earnings per common share | | | | | | | | |
| – basic | | $ | 2.52 | | | $ | 3.04 | | | $ | 2.66 | | | $ | 2.16 | |
| – diluted | | $ | 2.49 | | | $ | 3.00 | | | $ | 2.63 | | | $ | 2.14 | |
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(1)Further details related to product sales for the three months ended September 30, 2023 and 2022 are disclosed in note 17 to the financial statements.
Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to:
▪Crude oil pricing – Fluctuating global supply/demand including crude oil production levels from OPEC+ and its impact on world supply; the impact of geopolitical and market uncertainties, including those due to COVID-19 and in connection with governmental responses to COVID-19, and the impact of the Russian invasion of Ukraine on worldwide benchmark pricing; the impact of shale oil production in North America; the impact of the Western Canadian Select ("WCS") Heavy Differential from the West Texas Intermediate reference location at Cushing, Oklahoma ("WTI") in North America; and the impact of the differential between WTI and Dated Brent ("Brent") benchmark pricing in the International segments.
▪Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, third-party pipeline maintenance and outages, the impact of geopolitical and market uncertainties, the impact of seasonal conditions, and the impact of shale gas production in the US.
(1)Calculated as respective production expense divided by respective sales volumes.
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| Canadian Natural Resources Limited | 5 | Three and nine months ended September 30, 2023 |
▪Crude oil and NGLs sales volumes – Fluctuations in production from the Kirby and Jackfish thermal oil sands projects, fluctuations in production due to the cyclic nature of the Primrose thermal oil projects, fluctuations in the Company's drilling program in North America and the International segments, natural decline rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and wildfires and a third-party pipeline outage in the North America segment. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the International segments.
▪Natural gas sales volumes – Fluctuations in production due to the Company's drilling program in North America and the International segments, natural decline rates, the impact and timing of acquisitions, and wildfires and a third-party pipeline outage in the North America segment.
▪Production expense – Fluctuations primarily due to the impacts of the demand and cost for services, fluctuations in product mix and production volumes, seasonal conditions, increased carbon tax and energy costs, inflationary cost pressures, cost optimizations across all segments, the impact and timing of acquisitions, turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and maintenance activities in the International segments.
▪Depletion, depreciation and amortization expense – Fluctuations due to changes in sales volumes including the impact and timing of acquisitions and dispositions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company's proved undeveloped reserves, fluctuations in International sales volumes subject to higher depletion rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, and a recoverability charge relating to the de-booking of reserves at the Ninian field in the North Sea at December 31, 2022.
▪Share-based compensation – Fluctuations due to the measurement of fair market value of the Company's share-based compensation liability.
▪Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company's risk management activities.
▪Interest expense – Fluctuations due to changing long-term debt levels, and the impact of movements in benchmark interest rates on outstanding floating rate long-term debt and accrued interest on the deferred Petroleum Revenue Tax ("PRT") recovery.
▪Foreign exchange – Fluctuations in the Canadian dollar relative to the US dollar, which impact the realized price the Company receives for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar denominated debt, partially offset by the impact of any cross currency swap hedges outstanding.
▪(Gain) loss from investments – Fluctuations due to the (gain) loss from the investment in PrairieSky Royalty Ltd. shares.
BUSINESS ENVIRONMENT
Risks and Uncertainties
Global benchmark crude oil prices gained momentum in the third quarter of 2023 following the OPEC+ decision to extend production cuts into 2024. The global crude oil market continues to be impacted by heightened geopolitical tensions, which has led to price volatility in benchmark crude oil prices. Additionally, although inflationary pressures are easing, the Company has experienced and may continue to experience inflationary pressures on its operating and capital expenditures in addition to higher than normal fluctuations in commodity prices and interest rates.
Liquidity
As at September 30, 2023, the Company had undrawn revolving bank credit facilities of $5,450 million. Including cash and cash equivalents and short-term investments, the Company had approximately $6,140 million in liquidity (1). The Company also has certain other dedicated credit facilities supporting letters of credit.
The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital structure. Refer to the "Liquidity and Capital Resources" section of this MD&A for further details.
(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
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| Canadian Natural Resources Limited | 6 | Three and nine months ended September 30, 2023 |
Benchmark Commodity Prices
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| | Three Months Ended | | | Nine Months Ended |
(Average for the period) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| WTI benchmark price (US$/bbl) | | $ | 82.18 | | | $ | 73.75 | | | $ | 91.64 | | | | $ | 77.37 | | | $ | 98.14 | |
| Dated Brent benchmark price (US$/bbl) | | $ | 86.68 | | | $ | 78.37 | | | $ | 99.34 | | | | $ | 82.11 | | | $ | 103.73 | |
| WCS Heavy Differential from WTI (US$/bbl) | | $ | 12.86 | | | $ | 15.07 | | | $ | 19.87 | | | | $ | 17.51 | | | $ | 15.78 | |
| SCO price (US$/bbl) | | $ | 84.99 | | | $ | 76.67 | | | $ | 100.51 | | | | $ | 79.97 | | | $ | 102.66 | |
| Condensate benchmark price (US$/bbl) | | $ | 77.91 | | | $ | 72.28 | | | $ | 87.15 | | | | $ | 76.66 | | | $ | 97.19 | |
| Condensate Differential from WTI (US$/bbl) | | $ | 4.27 | | | $ | 1.47 | | | $ | 4.49 | | | | $ | 0.71 | | | $ | 0.95 | |
| NYMEX benchmark price (US$/MMBtu) | | $ | 2.55 | | | $ | 2.10 | | | $ | 8.18 | | | | $ | 2.69 | | | $ | 6.77 | |
| AECO benchmark price (C$/GJ) | | $ | 2.26 | | | $ | 2.22 | | | $ | 5.51 | | | | $ | 2.86 | | | $ | 5.27 | |
US/Canadian dollar average exchange rate (US$) | | $ | 0.7456 | | | $ | 0.7447 | | | $ | 0.7660 | | | | $ | 0.7432 | | | $ | 0.7796 | |
Substantially all of the Company's production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based on WTI and Brent indices. Canadian natural gas pricing is primarily based on AECO reference pricing, which is derived from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at Henry Hub. The Company's realized prices are directly impacted by fluctuations in foreign exchange rates, and its product revenues continued to be impacted by the volatility of the Canadian dollar as the Canadian dollar sales price the Company received for its crude oil and natural gas sales is based on US dollar denominated benchmarks.
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$77.37 per bbl for the nine months ended September 30, 2023, a decrease of 21% from US$98.14 per bbl for the nine months ended September 30, 2022. WTI averaged US$82.18 per bbl for the third quarter of 2023, a decrease of 10% from US$91.64 per bbl for the third quarter of 2022, and an increase of 11% from US$73.75 per bbl for the second quarter of 2023.
Crude oil sales contracts for the Company's International segments are typically based on Brent pricing, which is representative of international markets and overall global supply and demand. Brent averaged US$82.11 per bbl for the nine months ended September 30, 2023, a decrease of 21% from US$103.73 per bbl for the nine months ended September 30, 2022. Brent averaged US$86.68 per bbl for the third quarter of 2023, a decrease of 13% from US$99.34 per bbl for the third quarter of 2022, and an increase of 11% from US$78.37 per bbl for the second quarter of 2023.
The decrease in WTI and Brent pricing for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected concerns of lower global crude oil demand as a result of persistent inflation and the resulting increase in interest rates. The increase in WTI and Brent pricing for the third quarter of 2023 from the second quarter of 2023 primarily reflected the OPEC+ decision to extend production cuts into 2024.
The WCS Heavy Differential averaged US$17.51 per bbl for the nine months ended September 30, 2023, compared with US$15.78 per bbl for the nine months ended September 30, 2022. The WCS Heavy Differential averaged US$12.86 per bbl for the third quarter of 2023, compared with US$19.87 per bbl for the third quarter of 2022, and US$15.07 per bbl for the second quarter of 2023. The widening of the WCS Heavy Differential for the nine months ended September 30, 2023 from the comparable period in 2022 primarily reflected weaker global sour crude oil pricing in part due to the availability of discounted Russian crude oil in the market, and US Strategic Petroleum Reserve sour crude oil releases that carried over into the first half of 2023. The narrowing of the WCS Heavy Differential for the third quarter of 2023 from the third quarter of 2022 primarily reflected strengthening of US Gulf Coast heavy oil pricing in 2023 and a decrease in supply from the US Strategic Petroleum Reserve following releases in 2022. The narrowing of the WCS Heavy Differential for the third quarter of 2023 from the second quarter of 2023 primarily reflected strengthening global sour crude oil pricing due to OPEC+ production cuts.
The SCO price averaged US$79.97 per bbl for the nine months ended September 30, 2023, a decrease of 22% from US$102.66 per bbl for the nine months ended September 30, 2022. The SCO price averaged US$84.99 per bbl for the third quarter of 2023, a decrease of 15% from US$100.51 per bbl for the third quarter of 2022, and an increase of 11% from US$76.67 per bbl for the second quarter of 2023. The change in SCO pricing for the three and nine months ended September 30, 2023 from the comparable periods primarily reflected movements in WTI benchmark pricing.
| | | | | | | | |
| Canadian Natural Resources Limited | 7 | Three and nine months ended September 30, 2023 |
NYMEX natural gas prices averaged US$2.69 per MMBtu for the nine months ended September 30, 2023, a decrease of 60% from US$6.77 per MMBtu for the nine months ended September 30, 2022. NYMEX natural gas prices averaged US$2.55 per MMBtu for the third quarter of 2023, a decrease of 69% from US$8.18 per MMBtu for the third quarter of 2022, and an increase of 21% from US$2.10 per MMBtu for the second quarter of 2023. The decrease in NYMEX natural gas prices for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected lower storage draws due to mild winter weather in 2023, combined with increased production in North America. Additionally, lower global LNG prices amid ample supply put downward pressure on NYMEX benchmark prices. The increase in NYMEX natural gas prices for the third quarter of 2023 from the second quarter of 2023 primarily reflected record temperatures in major consuming regions of the US, significantly increasing demand.
AECO natural gas prices averaged $2.86 per GJ for the nine months ended September 30, 2023, a decrease of 46% from $5.27 per GJ for the nine months ended September 30, 2022. AECO natural gas prices averaged $2.26 per GJ for the third quarter of 2023, a decrease of 59% from $5.51 per GJ for the third quarter of 2022, and comparable with $2.22 per GJ for the second quarter of 2023. The decrease in AECO natural gas prices for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected NYMEX benchmark pricing, and increased production levels in the Western Canadian Sedimentary Basin.
DAILY PRODUCTION, before royalties
| | | | | | | | | | | | | | | | | |
| Three Months Ended | Nine Months Ended |
| | Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
Crude oil and NGLs (bbl/d) | | | | | |
| North America – Exploration and Production | 519,581 | | 465,143 | | 471,632 | | 487,512 | | 477,751 | |
North America – Oil Sands Mining and Upgrading (1) | 490,853 | | 355,246 | | 487,553 | | 434,895 | | 424,988 | |
| International – Exploration and Production | | | | | |
North Sea | 12,016 | | 12,699 | | 10,855 | | 12,647 | | 12,514 | |
Offshore Africa | 12,703 | | 13,821 | | 13,638 | | 13,533 | | 14,826 | |
Total International (2) | 24,719 | | 26,520 | | 24,493 | | 26,180 | | 27,340 | |
| Total Crude oil and NGLs | 1,035,153 | | 846,909 | | 983,678 | | 948,587 | | 930,079 | |
Natural gas (MMcf/d) (3) | | | | | |
| North America | 2,139 | | 2,072 | | 2,117 | | 2,113 | | 2,065 | |
| International | | | | | |
North Sea | 1 | | 2 | | 1 | | 2 | | 2 | |
Offshore Africa | 11 | | 11 | | 14 | | 10 | | 14 | |
| Total International | 12 | | 13 | | 15 | | 12 | | 16 | |
| Total Natural gas | 2,151 | | 2,085 | | 2,132 | | 2,125 | | 2,081 | |
| Total Barrels of oil equivalent (BOE/d) | 1,393,614 | | 1,194,326 | | 1,338,940 | | 1,302,715 | | 1,276,970 | |
| Product mix | | | | | |
| Light and medium crude oil and NGLs | 10% | 11% | 10% | 10% | 11% |
| Pelican Lake heavy crude oil | 3% | 4% | 4% | 4% | 4% |
| Primary heavy crude oil | 5% | 6% | 5% | 6% | 5% |
| Bitumen (thermal oil) | 21% | 20% | 18% | 20% | 20% |
Synthetic crude oil (1) | 35% | 30% | 36% | 33% | 33% |
| Natural gas | 26% | 29% | 27% | 27% | 27% |
Percentage of gross revenue (1) (4) (5) | | | | | |
| Crude oil and NGLs | 95% | 93% | 88% | 93% | 89% |
| Natural gas | 5% | 7% | 12% | 7% | 11% |
(1)SCO production before royalties excludes SCO consumed internally as diesel.
(2)"International" includes North Sea and Offshore Africa Exploration and Production segments in all instances used.
(3)Natural gas production volumes approximate sales volumes.
(4)Net of blending and feedstock costs and excluding risk management activities.
(5)Excluding Midstream and Refining revenue.
| | | | | | | | |
| Canadian Natural Resources Limited | 8 | Three and nine months ended September 30, 2023 |
DAILY PRODUCTION, net of royalties
| | | | | | | | | | | | | | | | | |
| Three Months Ended | Nine Months Ended |
| | Sep 30
2023 | Jun 30
2023 | Sep 30
2022 | Sep 30
2023 | Sep 30
2022 |
Crude oil and NGLs (bbl/d) | | | | | |
| North America – Exploration and Production | 409,479 | | 388,670 | | 361,987 | | 398,258 | | 371,575 | |
| North America – Oil Sands Mining and Upgrading | 387,407 | | 301,239 | | 391,165 | | 366,606 | | 344,611 | |
| International – Exploration and Production | | | | | |
| North Sea | 11,968 | | 12,654 | | 10,776 | | 12,616 | | 12,466 | |
| Offshore Africa | 11,746 | | 12,343 | | 11,965 | | 12,273 | | 13,586 | |
| Total International | 23,714 | | 24,997 | | 22,741 | | 24,889 | | 26,052 | |
| Total Crude oil and NGLs | 820,600 | | 714,906 | | 775,893 | | 789,753 | | 742,238 | |
Natural gas (MMcf/d) | | | | | |
| North America | 2,068 | | 2,014 | | 1,920 | | 2,024 | | 1,868 | |
| International | | | | | |
| North Sea | 1 | | 2 | | 1 | | 2 | | 2 | |
| Offshore Africa | 10 | | 10 | | 12 | | 10 | | 13 | |
| Total International | 11 | | 12 | | 13 | | 12 | | 15 | |
| Total Natural gas | 2,079 | | 2,026 | | 1,933 | | 2,036 | | 1,883 | |
| Total Barrels of oil equivalent (BOE/d) | 1,167,139 | | 1,052,602 | | 1,098,001 | | 1,129,014 | | 1,056,008 | |
The Company's business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO, and natural gas.
Crude oil and NGLs production before royalties for the nine months ended September 30, 2023 averaged 948,587 bbl/d, comparable with 930,079 bbl/d for the nine months ended September 30, 2022. Crude oil and NGLs production for the third quarter of 2023 averaged 1,035,153 bbl/d, an increase of 5% from 983,678 bbl/d for the third quarter of 2022, and an increase of 22% from 846,909 bbl/d for the second quarter of 2023. The increase in crude oil and NGLs production for the third quarter of 2023 from the third quarter of 2022 primarily reflected increased thermal oil production resulting from pad additions at Primrose and Kirby. The increase in crude oil and NGLs production for the third quarter of 2023 from the second quarter of 2023 primarily reflected the completion of planned turnaround activities at Horizon and the non-operated Scotford Upgrader ("Scotford") in the second quarter of 2023, combined with strong thermal oil production.
Natural gas production before royalties for the nine months ended September 30, 2023 of 2,125 MMcf/d was comparable with 2,081 MMcf/d for the nine months ended September 30, 2022. Record natural gas production for the third quarter of 2023 averaged 2,151 MMcf/d, comparable with 2,132 MMcf/d for the third quarter of 2022, and an increase of 3% from 2,085 MMcf/d for the second quarter of 2023. The increase in natural gas production for the third quarter of 2023 from the second quarter of 2023 primarily reflected reduced wildfire impacts, restored volumes following a third-party pipeline outage through the second quarter of 2023, together with drilling activity, partially offset by natural field declines.
The Company's 2023 production is targeted to be at the lower end of the corporate guidance range of 1,330,000 BOE/d to 1,374,000 BOE/d, due to wildfires in Western Canada in the second and third quarters, a third-party pipeline outage in the first half of the year, and the previously announced unplanned outages at Horizon in January 2023.
| | | | | | | | |
| Canadian Natural Resources Limited | 9 | Three and nine months ended September 30, 2023 |
North America – Exploration and Production
North America crude oil and NGLs production before royalties for the nine months ended September 30, 2023 averaged 487,512 bbl/d, comparable with 477,751 bbl/d for the nine months ended September 30, 2022. Record North America crude oil and NGLs production for the third quarter of 2023 of 519,581 bbl/d increased 10% from 471,632 bbl/d for the third quarter of 2022, and increased 12% from 465,143 bbl/d for the second quarter of 2023. The increase in North America crude oil and NGLs production for the third quarter of 2023 from the comparable periods primarily reflected increased thermal oil production and drilling activity, partially offset by natural field declines. The increase from the second quarter of 2023 also reflected reduced wildfire impacts, and restored volumes following a third-party pipeline outage through the second quarter of 2023.
The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 287,085 bbl/d for the third quarter of 2023, an increase of 18% from 243,393 bbl/d for the third quarter of 2022, and an increase of 20% from 238,941 bbl/d for the second quarter of 2023. The increase in thermal in situ production in the third quarter of 2023 from the comparable periods primarily reflected pad additions at Primrose and Kirby, partially offset by natural field declines.
Pelican Lake heavy crude oil production before royalties for the third quarter of 2023 averaged 46,897 bbl/d, a decrease of 6% from 50,051 bbl/d for the third quarter of 2022, and comparable with 47,151 bbl/d for the second quarter of 2023, demonstrating Pelican Lake's long life low decline production.
Natural gas production before royalties for the nine months ended September 30, 2023 averaged 2,113 MMcf/d, comparable with 2,065 MMcf/d for the nine months ended September 30, 2022. Record natural gas production for the third quarter of 2023 averaged 2,139 MMcf/d, comparable with 2,117 MMcf/d for the third quarter of 2022, and an increase of 3% from 2,072 MMcf/d for the second quarter of 2023. The increase in natural gas production for the third quarter of 2023 from the second quarter of 2023 primarily reflected reduced wildfire impacts, restored volumes following a third-party pipeline outage through the second quarter of 2023, together with drilling activity, partially offset by natural field declines.
North America – Oil Sands Mining and Upgrading
SCO production before royalties for the nine months ended September 30, 2023 of 434,895 bbl/d was comparable with 424,988 bbl/d for the nine months ended September 30, 2022. SCO production for the third quarter of 2023 of 490,853 bbl/d was comparable with 487,553 bbl/d for the third quarter of 2022, and increased 38% from 355,246 bbl/d for the second quarter of 2023. The increase in SCO production for the third quarter of 2023 from the second quarter of 2023 primarily reflected the completion of planned turnaround activities at Horizon and Scotford during the second quarter of 2023.
International – Exploration and Production
International crude oil and NGLs production before royalties for the nine months ended September 30, 2023 averaged 26,180 bbl/d, a decrease of 4% from 27,340 bbl/d for the nine months ended September 30, 2022. International crude oil and NGLs production for the third quarter of 2023 averaged 24,719 bbl/d, comparable with 24,493 bbl/d for the third quarter of 2022, and a decrease of 7% from 26,520 bbl/d for the second quarter of 2023, primarily reflecting the impact of planned maintenance activities, together with natural field declines.
International Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when control of the product passes to the customer and delivery has taken place. Revenue has not been recognized in the International segments on crude oil volumes held in various storage facilities or FPSOs, as follows:
| | | | | | | | | | | |
| (bbl) | Sep 30
2023 | Jun 30
2023 | Sep 30
2022 |
| | | |
| | | |
| International | 1,167,250 | | 816,475 | | 1,126,786 | |
| | | | | | | | |
| Canadian Natural Resources Limited | 10 | Three and nine months ended September 30, 2023 |
OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
Realized price (2) | | $ | 87.83 | | | $ | 72.06 | | | $ | 84.91 | | | | $ | 73.45 | | | $ | 97.99 | |
Transportation (2) | | 4.07 | | | 4.57 | | | 4.10 | | | | 4.37 | | | 4.14 | |
Realized price, net of transportation (2) | | 83.76 | | | 67.49 | | | 80.81 | | | | 69.08 | | | 93.85 | |
Royalties (3) | | 17.32 | | | 11.09 | | | 19.48 | | | | 12.98 | | | 20.75 | |
Production expense (4) | | 14.40 | | | 18.38 | | | 16.86 | | | | 16.51 | | | 17.41 | |
Netback (2) | | $ | 52.04 | | | $ | 38.02 | | | $ | 44.47 | | | | $ | 39.59 | | | $ | 55.69 | |
Natural gas ($/Mcf) (1) | | | | | | | | | | | |
Realized price (5) | | $ | 2.81 | | | $ | 2.53 | | | $ | 6.57 | | | | $ | 3.20 | | | $ | 6.61 | |
Transportation (6) | | 0.56 | | | 0.58 | | | 0.51 | | | | 0.56 | | | 0.50 | |
Realized price, net of transportation | | 2.25 | | | 1.95 | | | 6.06 | | | | 2.64 | | | 6.11 | |
Royalties (3) | | 0.09 | | | 0.07 | | | 0.61 | | | | 0.15 | | | 0.65 | |
Production expense (4) | | 1.25 | | | 1.37 | | | 1.16 | | | | 1.36 | | | 1.21 | |
Netback | | $ | 0.91 | | | $ | 0.51 | | | $ | 4.29 | | | | $ | 1.13 | | | $ | 4.25 | |
Barrels of oil equivalent ($/BOE) (1) | | | | | | | | | | | |
Realized price (2) | | $ | 59.40 | | | $ | 48.94 | | | $ | 66.04 | | | | $ | 51.31 | | | $ | 74.62 | |
Transportation (2) | | 3.78 | | | 4.11 | | | 3.64 | | | | 3.97 | | | 3.68 | |
Realized price, net of transportation (2) | | 55.62 | | | 44.83 | | | 62.40 | | | | 47.34 | | | 70.94 | |
Royalties (3) | | 10.61 | | | 6.75 | | | 12.88 | | | | 8.03 | | | 13.94 | |
Production expense (4) | | 11.64 | | | 14.24 | | | 12.68 | | | | 13.10 | | | 13.28 | |
Netback (2) | | $ | 33.37 | | | $ | 23.84 | | | $ | 36.84 | | | | $ | 26.21 | | | $ | 43.72 | |
(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Calculated as royalties divided by respective sales volumes.
(4)Calculated as production expense divided by respective sales volumes.
(5)Calculated as natural gas sales divided by natural gas sales volumes.
(6)Calculated as natural gas transportation expense divided by natural gas sales volumes.
| | | | | | | | |
| Canadian Natural Resources Limited | 11 | Three and nine months ended September 30, 2023 |
REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
North America (2) | | $ | 86.77 | | | $ | 69.44 | | | $ | 83.62 | | | | $ | 71.90 | | | $ | 96.11 | |
International average (3) | | $ | 113.59 | | | $ | 103.64 | | | $ | 120.09 | | | | $ | 105.20 | | | $ | 132.96 | |
North Sea (3) | | $ | 108.22 | | | $ | 106.39 | | | $ | 123.18 | | | | $ | 106.91 | | | $ | 135.73 | |
Offshore Africa (3) | | $ | 118.09 | | | $ | 100.68 | | | $ | 119.08 | | | | $ | 105.55 | | | $ | 131.02 | |
Crude oil and NGLs average (2) | | $ | 87.83 | | | $ | 72.06 | | | $ | 84.91 | | | | $ | 73.45 | | | $ | 97.99 | |
| | | | | | | | | | | |
Natural gas ($/Mcf) (1) (3) | | | | | | | | | | | |
| North America | | $ | 2.76 | | | $ | 2.47 | | | $ | 6.51 | | | | $ | 3.15 | | | $ | 6.56 | |
| International average | | $ | 12.21 | | | $ | 13.16 | | | $ | 14.83 | | | | $ | 13.04 | | | $ | 12.60 | |
| North Sea | | $ | 9.99 | | | $ | 9.48 | | | $ | 20.88 | | | | $ | 10.70 | | | $ | 16.91 | |
| Offshore Africa | | $ | 12.44 | | | $ | 13.71 | | | $ | 14.27 | | | | $ | 13.44 | | | $ | 11.99 | |
| Natural gas average | | $ | 2.81 | | | $ | 2.53 | | | $ | 6.57 | | | | $ | 3.20 | | | $ | 6.61 | |
| | | | | | | | | | | |
Average ($/BOE) (1) (2) | | $ | 59.40 | | | $ | 48.94 | | | $ | 66.04 | | | | $ | 51.31 | | | $ | 74.62 | |
(1)For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
(2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(3)Calculated as crude oil and NGLs sales and natural gas sales divided by respective sales volumes.
North America
North America realized crude oil and NGLs prices decreased 25% to average $71.90 per bbl for the nine months ended September 30, 2023 from $96.11 per bbl for the nine months ended September 30, 2022. North America realized crude oil and NGLs prices increased 4% to average $86.77 per bbl for the third quarter of 2023 from $83.62 per bbl for the third quarter of 2022, and increased 25% from $69.44 per bbl for the second quarter of 2023. The decrease for the nine months ended September 30, 2023 from the comparable period in 2022 was primarily due to lower WTI benchmark pricing and the widening of the WCS Heavy Differential. The increase in North America realized crude oil and NGLs prices for the third quarter of 2023 from the comparable period in 2022, primarily reflected the narrowing of the WCS differential, partially offset by lower WTI benchmark pricing. The increase for the third quarter of 2023 from the second quarter of 2023 primarily reflected higher WTI benchmark pricing, combined with the narrowing of the WCS Heavy Differential. The Company continues to focus on its crude oil blending marketing strategy and in the third quarter of 2023 contributed approximately 210,000 bbl/d of heavy crude oil blends to the WCS stream.
North America realized natural gas prices decreased 52% to average $3.15 per Mcf for the nine months ended September 30, 2023 from $6.56 per Mcf for the nine months ended September 30, 2022. North America realized natural gas prices decreased 58% to average $2.76 per Mcf for the third quarter of 2023 from $6.51 per Mcf for the third quarter of 2022, and increased 12% from $2.47 per Mcf for the second quarter of 2023. The decrease in North America realized natural gas prices for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected decreased AECO benchmark and export pricing. The increase for the third quarter of 2023 from the second quarter of 2023 primarily reflected increased NYMEX pricing on the Company's exports to the US.
| | | | | | | | |
| Canadian Natural Resources Limited | 12 | Three and nine months ended September 30, 2023 |
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended |
| (Quarterly average) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 |
Wellhead Price (1) | | | | | | |
| Light and medium crude oil and NGLs ($/bbl) | | $ | 72.07 | | | $ | 68.11 | | | $ | 82.26 | |
| Pelican Lake heavy crude oil ($/bbl) | | $ | 93.19 | | | $ | 76.66 | | | $ | 91.98 | |
| Primary heavy crude oil ($/bbl) | | $ | 93.80 | | | $ | 76.20 | | | $ | 89.80 | |
| Bitumen (thermal oil) ($/bbl) | | $ | 89.50 | | | $ | 66.51 | | | $ | 80.74 | |
| Natural gas ($/Mcf) | | $ | 2.76 | | | $ | 2.47 | | | $ | 6.51 | |
(1)Amounts expressed on a per unit basis are based on sales volumes of the respective product type.
International
International realized crude oil and NGLs prices decreased 21% to average $105.20 per bbl for the nine months ended September 30, 2023 from $132.96 per bbl for the nine months ended September 30, 2022. International realized crude oil and NGLs prices decreased 5% to average $113.59 per bbl for the third quarter of 2023 from $120.09 per bbl for the third quarter of 2022, and increased 10% from $103.64 per bbl for the second quarter of 2023. Realized crude oil and NGLs prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The fluctuations in realized crude oil and NGLs prices for the three and nine months ended September 30, 2023 from the comparable periods reflected prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.
ROYALTIES – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
| North America | | $ | 17.79 | | | $ | 11.56 | | | $ | 19.78 | | | | $ | 13.31 | | | $ | 21.53 | |
| International average | | $ | 5.67 | | | $ | 5.38 | | | $ | 11.24 | | | | $ | 6.07 | | | $ | 6.30 | |
| North Sea | | $ | 0.42 | | | $ | 0.36 | | | $ | 0.86 | | | | $ | 0.38 | | | $ | 0.38 | |
| Offshore Africa | | $ | 8.90 | | | $ | 10.77 | | | $ | 14.61 | | | | $ | 9.87 | | | $ | 10.47 | |
| Crude oil and NGLs average | | $ | 17.32 | | | $ | 11.09 | | | $ | 19.48 | | | | $ | 12.98 | | | $ | 20.75 | |
| | | | | | | | | | | |
Natural gas ($/Mcf) (1) | | | | | | | | | | | |
| North America | | $ | 0.09 | | | $ | 0.07 | | | $ | 0.61 | | | | $ | 0.14 | | | $ | 0.64 | |
| Offshore Africa | | $ | 0.59 | | | $ | 0.65 | | | $ | 1.73 | | | | $ | 0.64 | | | $ | 1.62 | |
| Natural gas average | | $ | 0.09 | | | $ | 0.07 | | | $ | 0.61 | | | | $ | 0.15 | | | $ | 0.65 | |
| | | | | | | | | | | |
Average ($/BOE) (1) | | $ | 10.61 | | | $ | 6.75 | | | $ | 12.88 | | | | $ | 8.03 | | | $ | 13.94 | |
(1)Calculated as royalties divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
North America crude oil and NGLs and natural gas royalties for the three and nine months ended September 30, 2023 and the comparable periods reflected movements in benchmark commodity prices, fluctuations in the WCS Heavy Differential and the impact of sliding scale royalty rates.
Crude oil and NGLs royalty rates (1) averaged approximately 19% of product sales for the nine months ended September 30, 2023 compared with 22% of product sales for the nine months ended September 30, 2022. Crude oil and NGLs royalty rates averaged approximately 21% of product sales for the third quarter of 2023 compared with 24% for the third quarter of 2022 and 17% for the second quarter of 2023.
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
| | | | | | | | |
| Canadian Natural Resources Limited | 13 | Three and nine months ended September 30, 2023 |
The decrease in royalty rates for the three and nine months ended September 30, 2023 from the comparable periods in 2022 was primarily due to lower benchmark prices and fluctuations in the WCS Heavy Differential. The increase in royalty rates for the third quarter of 2023 compared to the second quarter of 2023 primarily reflected higher benchmark pricing and the narrowing of the WCS Heavy Differential.
Natural gas royalty rates averaged approximately 5% of product sales for the nine months ended September 30, 2023 compared with 10% of product sales for the nine months ended September 30, 2022. Natural gas royalty rates averaged approximately 3% of product sales for the third quarter of 2023 compared with 9% for the third quarter of 2022, and 3% for the second quarter of 2023. The decrease in royalty rates for the three and nine months ended September 30, 2023 from the comparable periods in 2022 was primarily due to lower benchmark prices.
Offshore Africa
Under the terms of the various Production Sharing Contracts royalty rates fluctuate based on realized commodity pricing, capital expenditures and production expenses, the status of payouts, and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 9% for the nine months ended September 30, 2023 compared with 8% of product sales for the nine months ended September 30, 2022. Royalty rates as a percentage of product sales averaged approximately 7% for the third quarter of 2023 compared with 12% of product sales for the third quarter of 2022, and 10% for the second quarter of 2023. Royalty rates as a percentage of product sales reflected the timing of liftings and the status of payout in the various fields.
PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
| North America | | $ | 13.21 | | | $ | 15.64 | | | $ | 15.98 | | | | $ | 15.16 | | | $ | 16.06 | |
| International average | | $ | 44.16 | | | $ | 51.50 | | | $ | 40.86 | | | | $ | 44.94 | | | $ | 42.49 | |
| North Sea | | $ | 83.44 | | | $ | 81.32 | | | $ | 115.41 | | | | $ | 81.92 | | | $ | 81.52 | |
| Offshore Africa | | $ | 20.04 | | | $ | 19.44 | | | $ | 16.64 | | | | $ | 20.23 | | | $ | 15.05 | |
| Crude oil and NGLs average | | $ | 14.40 | | | $ | 18.38 | | | $ | 16.86 | | | | $ | 16.51 | | | $ | 17.41 | |
| | | | | | | | | | | |
Natural gas ($/Mcf) (1) | | | | | | | | | | | |
| North America | | $ | 1.22 | | | $ | 1.35 | | | $ | 1.13 | | | | $ | 1.33 | | | $ | 1.18 | |
| International average | | $ | 7.40 | | | $ | 4.83 | | | $ | 4.99 | | | | $ | 6.72 | | | $ | 4.57 | |
| North Sea | | $ | 9.19 | | | $ | 9.17 | | | $ | 12.67 | | | | $ | 9.95 | | | $ | 8.68 | |
| Offshore Africa | | $ | 7.21 | | | $ | 4.17 | | | $ | 4.27 | | | | $ | 6.17 | | | $ | 3.99 | |
| Natural gas average | | $ | 1.25 | | | $ | 1.37 | | | $ | 1.16 | | | | $ | 1.36 | | | $ | 1.21 | |
| | | | | | | | | | | |
Average ($/BOE) (1) | | $ | 11.64 | | | $ | 14.24 | | | $ | 12.68 | | | | $ | 13.10 | | | $ | 13.28 | |
(1)Calculated as production expense divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
North America crude oil and NGLs production expense for the nine months ended September 30, 2023 averaged $15.16 per bbl, a decrease of 6% from $16.06 per bbl for the nine months ended September 30, 2022. North America crude oil and NGLs production expense for the third quarter of 2023 of $13.21 per bbl decreased 17% from $15.98 per bbl for the third quarter of 2022, and decreased 16% from $15.64 per bbl for the second quarter of 2023. The decrease in crude oil and NGLs production expense per bbl for the nine months ended September 30, 2023 from the comparable period in 2022 primarily reflected lower natural gas fuel costs, partially offset by higher service costs. The decrease in crude oil and NGLs production expense per bbl for the third quarter of 2023 from the comparable periods primarily reflected increased production volumes in the third quarter of 2023, combined with lower energy costs.
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| Canadian Natural Resources Limited | 14 | Three and nine months ended September 30, 2023 |
North America natural gas production expense averaged $1.33 per Mcf for the nine months ended September 30, 2023, an increase of 13% from $1.18 per Mcf for the nine months ended September 30, 2022. North America natural gas production expense for the third quarter of 2023 averaged $1.22 per Mcf, an increase of 8% from $1.13 per Mcf for the third quarter of 2022, and a decrease of 10% from $1.35 per Mcf for the second quarter of 2023. The increase in natural gas production expense per Mcf for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected higher service costs. The decrease in natural gas production expense per Mcf for the third quarter of 2023 from the second quarter of 2023 primarily reflected the impact of higher production volumes.
International
International crude oil and NGLs production expense for the nine months ended September 30, 2023 averaged $44.94 per bbl, an increase of 6% from $42.49 per bbl for the nine months ended September 30, 2022. International crude oil and NGLs production expense for the third quarter of 2023 of $44.16 per bbl increased 8% from $40.86 per bbl for the third quarter of 2022, and decreased 14% from $51.50 per bbl for the second quarter of 2023. The fluctuations in crude oil and NGLs production expense per bbl primarily reflected the timing of liftings from various fields that have different cost structures, the timing of maintenance activities, lower production volumes, and the impact of foreign exchange.
DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except per BOE amounts) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| North America | | $ | 947 | | | $ | 871 | | | $ | 913 | | | | $ | 2,708 | | | $ | 2,646 | |
| North Sea | | 12 | | | 15 | | | 15 | | | | 28 | | | 94 | |
| Offshore Africa | | 47 | | | 65 | | | 39 | | | | 147 | | | 132 | |
| Depletion, depreciation and amortization | | $ | 1,006 | | | $ | 951 | | | $ | 967 | | | | $ | 2,883 | | | $ | 2,872 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
$/BOE (1) | | $ | 12.22 | | | $ | 12.26 | | | $ | 12.48 | | | | $ | 12.21 | | | $ | 12.34 | |
(1)Calculated as depletion, depreciation and amortization divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
Depletion, depreciation and amortization expense for the nine months ended September 30, 2023 of $12.21 per BOE was comparable with $12.34 per BOE for the nine months ended September 30, 2022. Depletion, depreciation and amortization expense for the third quarter of 2023 of $12.22 per BOE was comparable with $12.48 per BOE for the third quarter of 2022, and $12.26 per BOE for the second quarter of 2023.
ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions, except per BOE amounts) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| North America | | $ | 59 | | | $ | 58 | | | $ | 50 | | | | $ | 176 | | | $ | 120 | |
| North Sea | | 11 | | | 12 | | | 10 | | | | 34 | | | 23 | |
| Offshore Africa | | 2 | | | 2 | | | 2 | | | | 6 | | | 5 | |
| Asset retirement obligation accretion | | $ | 72 | | | $ | 72 | | | $ | 62 | | | | $ | 216 | | | $ | 148 | |
$/BOE (1) | | $ | 0.87 | | | $ | 0.93 | | | $ | 0.80 | | | | $ | 0.91 | | | $ | 0.64 | |
(1)Calculated as asset retirement obligation accretion divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. Asset retirement obligation accretion expense on an absolute and per BOE basis also reflects the impact of the timing of liftings from each field in the North Sea and Offshore Africa.
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| Canadian Natural Resources Limited | 15 | Three and nine months ended September 30, 2023 |
Asset retirement obligation accretion expense for the nine months ended September 30, 2023 of $0.91 per BOE increased 42% from $0.64 per BOE for the nine months ended September 30, 2022. Asset retirement obligation accretion expense for the third quarter of 2023 of $0.87 per BOE increased 9% from $0.80 per BOE for the third quarter of 2022, and decreased 6% from $0.93 per BOE for the second quarter of 2023. The increase in asset retirement obligation accretion expense per BOE for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected the impact of cost estimate and discount rate revisions made to the asset retirement obligation during 2022, partially offset by higher sales volumes in 2023. The decrease in asset retirement obligation accretion expense per BOE for the third quarter of 2023 from the second quarter of 2023 reflected higher sales volumes.
OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING
The Company continues to focus on safe, reliable, and efficient operations leveraging its technical expertise across the Horizon and AOSP sites. SCO production averaged 490,853 bbl/d in the third quarter of 2023 following the completion of planned turnaround activities in the second quarter of 2023.
The Company incurred production expense of $1,003 million for the third quarter of 2023, comparable with $1,005 million for the third quarter of 2022, and $997 million for the second quarter of 2023, reflecting the Company's continued focus on cost control and efficiencies across the entire asset base.
REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($/bbl) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
Realized SCO sales price (1) | | $ | 108.55 | | | $ | 95.08 | | | $ | 120.91 | | | | $ | 100.57 | | | $ | 122.45 | |
Bitumen value for royalty purposes (2) | | $ | 84.66 | | | $ | 66.51 | | | $ | 82.19 | | | | $ | 66.85 | | | $ | 91.69 | |
Bitumen royalties (3) | | $ | 21.90 | | | $ | 13.58 | | | $ | 24.87 | | | | $ | 15.52 | | | $ | 22.85 | |
Transportation (1) | | $ | 2.18 | | | $ | 2.03 | | | $ | 1.55 | | | | $ | 1.91 | | | $ | 1.69 | |
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2)Calculated as the quarterly average of the bitumen methodology price.
(3)Calculated as royalties divided by sales volumes.
The realized SCO sales price averaged $100.57 per bbl for the nine months ended September 30, 2023, a decrease of 18% from $122.45 per bbl for the nine months ended September 30, 2022. The realized SCO sales price averaged $108.55 per bbl for the third quarter of 2023, a decrease of 10% from $120.91 per bbl for the third quarter of 2022, and an increase of 14% from $95.08 per bbl for the second quarter of 2023. The decrease in the realized SCO sales price for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected the decrease in WTI benchmark pricing. The increase in realized SCO sales price for the third quarter of 2023 from the second quarter of 2023 primarily reflected an increase in WTI benchmark pricing.
The decrease in bitumen royalties per bbl for the nine months ended September 30, 2023 from the comparable period in 2022 primarily reflected the impact of lower prevailing bitumen pricing. The increase for the third quarter of 2023 from the second quarter of 2023 primarily reflected higher prevailing bitumen pricing and the impact of sliding scale royalty rates.
Transportation expense averaged $1.91 per bbl for the nine months ended September 30, 2023, an increase of 13% from $1.69 per bbl for the nine months ended September 30, 2022. Transportation expense averaged $2.18 per bbl for the third quarter of 2023, an increase of 41% from $1.55 per bbl for the third quarter of 2022, and an increase of 7% from $2.03 per bbl for the second quarter of 2023. The increase in transportation expense per bbl for the three and nine months ended September 30, 2023 from the comparable periods in 2022 primarily reflected higher sales to the US Gulf Coast in 2023. The increase for third quarter of 2023 from the second quarter of 2023 primarily reflected higher sales to the US Gulf Coast, partially offset by higher total sales volumes.
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| Canadian Natural Resources Limited | 16 | Three and nine months ended September 30, 2023 |
PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and Upgrading production expense disclosed in note 17 to the financial statements.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended |
| ($ millions) | | Sep 30
2023 | | Jun 30
2023 | | Sep 30
2022 | | | Sep 30
2023 | | Sep 30
2022 |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Production expense, excluding natural gas costs | | $ | 962 | | |