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: August 1, 2024
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 2024 Second 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: August 1, 2024 | By: | /s/ Stephanie A. Graham | |
| | | Stephanie A. Graham | |
| | | Corporate Secretary & Associate General Counsel, Canada | |
CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES
2024 SECOND QUARTER RESULTS
CALGARY, ALBERTA – AUGUST 1, 2024 – FOR IMMEDIATE RELEASE
Canadian Natural's President, Scott Stauth, commented on the Company's second quarter results, "The strength of our well-balanced and diverse portfolio, combined with Canadian Natural's ability to execute safe, effective and efficient operations, delivered an excellent second quarter. Canadian Natural strategically managed turnaround activities and optimized production resulting in strong Q2/24 volumes of approximately 934,000 bbl/d of liquids and 2.1 Bcf/d of natural gas, totaling 1,286,000 BOE/d, an increase of 8% from Q2/23 levels of 1,194,000 BOE/d. In Q2/24, we delivered strong thermal production of approximately 268,000 bbl/d primarily due to better than expected performance from new pads as well as the early completion of planned turnarounds. At Horizon, we successfully completed the final tie-ins related to the reliability enhancement project as well as planned turnaround activities. Through optimization efforts, we completed the turnaround at Horizon in 28 days, two days earlier than budgeted.
Subsequent to quarter end we achieved a significant milestone at Horizon in July 2024 with production of the one billionth barrel of bitumen since operations began in 2009. Supporting this milestone is the Company's significant total proved SCO reserves at approximately 6.9 billion barrels with a Reserve Life Index ("RLI") of approximately 44 years as at year end 2023. Also during the month of July 2024, Synthetic Crude Oil ("SCO") production of approximately 500,000 bbl/d was achieved, partially due to strong production at Horizon which is benefiting from the final tie-ins and commissioning of the reliability enhancement project.
The efficient commissioning of the Trans Mountain Expansion ("TMX") pipeline during Q2/24 and the positive impact this incremental egress has on the Canadian economy represents a significant achievement for all Canadians. The impact on the energy industry has been positive with narrowing of heavy oil differentials, improved realized pricing along with the development of a more diverse market for western Canadian crude oil. TMX is a significant accomplishment for Canada, adding much-needed egress capacity and increasing exposure to global market pricing for crude oil products.
Our strong execution, effective and efficient operations, combined with stronger realized prices, drove significant free cash flow during the quarter despite planned turnarounds.
In June 2024, the Canadian Government amended the Competition Act and due to uncertainty on how this new legislation will be interpreted and applied we are unable to provide an environment and climate update at this time. This legislation does not change our commitment to the environment and to ensuring safe, reliable operations, only the way in which we are publicly communicating these important aspects of our business."
Canadian Natural's Chief Financial Officer, Mark Stainthorpe, also added "In Q2/24, we delivered strong financial results, including adjusted net earnings of approximately $1.9 billion and adjusted funds flow of $3.6 billion, which drove significant returns to shareholders totaling $1.9 billion in the quarter. Our capital program for 2024 remains on target and as per our free cash flow allocation policy, we are returning 100% of free cash flow to shareholders in 2024 and we will continue to manage this allocation on a forward looking annual basis.
Year-to-date up to and including July 31, 2024, we have distributed significant value to shareholders, totaling approximately $4.9 billion, inclusive of our sustainable and growing dividend and share repurchases.
At Canadian Natural, our culture of continuous improvement and employee ownership alignment with shareholders drives our teams to create significant value across all areas of the Company. Our safe, effective and efficient operations combined with flexible capital allocation maximizes value for our shareholders."
HIGHLIGHTS
| | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | Six Months Ended |
| ($ millions, except per common share amounts) | Jun 30
2024 | Mar 31
2024 | Jun 30
2023 | Jun 30
2024 | Jun 30
2023 |
| Net earnings | $ | 1,715 | $ | 987 | $ | 1,463 | $ | 2,702 | $ | 3,262 |
Per common share (1) | – basic | $ | 0.80 | $ | 0.46 | $ | 0.67 | $ | 1.26 | $ | 1.49 |
| – diluted | $ | 0.80 | $ | 0.46 | $ | 0.66 | $ | 1.25 | $ | 1.47 |
Adjusted net earnings from operations (2) | $ | 1,892 | $ | 1,474 | $ | 1,256 | $ | 3,366 | $ | 3,137 |
Per common share(1) | – basic (3) | $ | 0.89 | $ | 0.69 | $ | 0.57 | $ | 1.57 | $ | 1.43 |
| – diluted (3) | $ | 0.88 | $ | 0.68 | $ | 0.57 | $ | 1.56 | $ | 1.41 |
| Cash flows from operating activities | $ | 4,084 | $ | 2,868 | $ | 2,745 | $ | 6,952 | $ | 4,040 |
Adjusted funds flow (2) | $ | 3,614 | $ | 3,138 | $ | 2,742 | $ | 6,752 | $ | 6,171 |
Per common share(1) | – basic (3) | $ | 1.69 | $ | 1.47 | $ | 1.25 | $ | 3.16 | $ | 2.81 |
| – diluted (3) | $ | 1.68 | $ | 1.45 | $ | 1.24 | $ | 3.13 | $ | 2.78 |
| Cash flows used in investing activities | $ | 1,015 | $ | 1,392 | $ | 1,560 | $ | 2,407 | $ | 2,713 |
Net capital expenditures (4) | $ | 1,621 | $ | 1,113 | $ | 1,569 | $ | 2,734 | $ | 2,826 |
| Abandonment expenditures | $ | 129 | $ | 162 | $ | 100 | $ | 291 | $ | 237 |
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| Daily production, before royalties | | | | | |
| Natural gas (MMcf/d) | 2,110 | 2,147 | 2,085 | 2,129 | 2,112 |
| Crude oil and NGLs (bbl/d) | 934,066 | 975,668 | 846,909 | 954,866 | 904,588 |
Equivalent production (BOE/d) (5) | 1,285,798 | 1,333,502 | 1,194,326 | 1,309,649 | 1,256,513 |
(1)Per common share and dividend amounts have been updated to reflect the two for one common share split. Further details are disclosed in the Advisory section of the Company's MD&A and in the financial statements for the three and six months ended June 30, 2024 dated July 31, 2024.
(2)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and six months ended June 30, 2024 dated July 31, 2024.
(3)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and six months ended June 30, 2024 dated July 31, 2024.
(4)Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2023 and has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and six months ended June 30, 2024 dated July 31, 2024.
(5)A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, or to compare the value ratio using current crude oil and natural gas prices since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
▪The strength of Canadian Natural's long life low decline asset base, supported by safe, effective and efficient operations, makes our business unique, robust and sustainable. In Q2/24, the Company generated strong financial results, including:
•Net earnings of approximately $1.7 billion and adjusted net earnings from operations of approximately $1.9 billion.
•Cash flows from operating activities of approximately $4.1 billion.
•Adjusted funds flow of approximately $3.6 billion.
▪Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with approximately $6.4 billion in liquidity(1) as at June 30, 2024.
•In Q2/24, the Company repaid:
◦US$0.5 billion of 3.8% debt securities that were due April 15, 2024.
◦$0.3 billion of 3.55% medium term notes that were due June 3, 2024.
▪Following shareholder approval in May 2024, Canadian Natural's common shares were subdivided on a two for one basis at market close on June 3, 2024. The Company's common shares commenced trading on a split-adjusted basis on June 11, 2024.
▪During the second quarter of 2024, the Company sold its 22.6 million common share investment in PrairieSky Royalty Ltd. for $25.65 per common share with net proceeds, after fees and expenses, of $575 million. The proceeds reduce net debt and further strengthen our financial position while maximizing value for shareholders.
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| Canadian Natural Resources Limited | 2 | Three and six months ended June 30, 2024 |
▪Despite the second quarter of each calendar year being a period of high turnaround activity compared to other quarters, Canadian Natural delivered strong quarterly average production in Q2/24 of 1,285,798 BOE/d, an increase of 8% from Q2/23 levels of 1,194,326 BOE/d. Q2/24 consists of total liquids production of 934,066 bbl/d and natural gas production of 2,110 MMcf/d.
•The Company's world class Oil Sands Mining and Upgrading assets delivered average production of 410,518 bbl/d of high value SCO in Q2/24, an increase of 16% from Q2/23 levels. The increase in production reflected planned turnaround activities successfully completed ahead of schedule at Horizon, compared to Q2/23 which included planned turnarounds at both Horizon and the non-operated Scotford Upgrader.
◦During the planned turnaround at Horizon in Q2/24, the Company successfully completed all tie-ins and commissioning of the reliability enhancement project components.
–The reliability enhancement project targets to increase the two year average SCO capacity by approximately 14,000 bbl/d by extending the turnaround schedule to once every two years, with 2025 being the first year of operations without a planned turnaround.
◦Subsequent to quarter end, the Company achieved strong monthly SCO production of approximately 500,000 bbl/d in July 2024. This was primarily a result of high utilization and effective execution of tie-ins and commissioning associated with the Horizon reliability enhancement project completed in June 2024.
◦In July 2024, the Company achieved a milestone at Horizon with the production of the one billionth bitumen barrel since operations began in 2009.
–Supporting this milestone is the Company's significant total proved SCO reserves at approximately 6.9 billion barrels with an RLI of approximately 44 years as at year end 2023.
•Thermal in situ long life low decline production averaged 268,044 bbl/d in Q2/24, an increase of 12% from Q2/23 levels, primarily driven by strong results from Primrose, Kirby and Jackfish pad developments.
◦At Jackfish, the first of two Steam Assisted Gravity Drainage ("SAGD") pads drilled in 2023 reached full production capacity in Q2/24, slightly ahead of schedule. The second pad is currently producing at full production capacity also ahead of schedule, originally budgeted for Q4/24.
◦Planned turnarounds at Jackfish and Kirby North facilities were successfully completed ahead of schedule in Q2/24.
▪Canadian Natural has significant growth opportunities across its asset base, including sustainable production enhancements at its Oil Sands Mining and Upgrading operations.
•Near-term projects include the reliability enhancement project at Horizon, completed in Q2/24. Additionally, at the Scotford Upgrader, a debottlenecking project is targeted to be completed during the planned turnaround and targets to add incremental capacity at the Athabasca Oil Sands Project ("AOSP") of approximately 5,600 bbl/d net to Canadian Natural.
•Medium-term projects include the Naphtha Recovery Unit Tailings Treatment ("NRUTT") project at Horizon, which targets to add incremental production of approximately 6,300 bbl/d of SCO.
•Long-term projects at our Oil Sands operations include combining In-Pit Extraction Process ("IPEP") and Paraffinic Froth Treatment ("PFT") that have the potential to add approximately 195,000 bbl/d of additional annual bitumen production.
▪The Company's 2024 development plan has conventional activity strategically weighted to the second half of 2024 to align with increased market egress and improved crude oil pricing, maximizing value for our shareholders. The completion of construction and start-up of the TMX pipeline provides market optionality for all western Canadian crude oil products.
RETURNS TO SHAREHOLDERS
▪Canadian Natural achieved its $10 billion net debt level at year end 2023 and is returning 100% of free cash flow(1) in 2024 to shareholders, per the Company's free cash flow allocation policy. The Company will manage the allocation of free cash flow on a forward looking annual basis, while managing working capital and cash management as required.
•Returns to shareholders in Q2/24 were strong, totaling approximately $1.9 billion, comprised of $1.1 billion of dividends and $0.8 billion through the repurchase and cancellation of approximately 14.8 million common shares at a weighted average price of $51.66 per share, on a split-adjusted basis.
•In 2024, up to and including July 31, 2024, the Company has returned a total of approximately $4.9 billion directly to shareholders through $3.3 billion in dividends and $1.6 billion through the repurchase and cancellation of approximately 33.9 million common shares.
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| Canadian Natural Resources Limited | 3 | Three and six months ended June 30, 2024 |
▪Subsequent to quarter end, the Company declared a quarterly cash dividend on its common shares of $0.525 per common share. The quarterly dividend will be payable on October 4, 2024 to shareholders of record at the close of business on September 13, 2024.
•The Company has a leading track record of dividend increases, with 2024 being the 24th consecutive year of dividend increases with a compound annual growth rate ("CAGR") of 21% over that time. This demonstrates the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base.
(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the Company's MD&A for the three and six months ended June 30, 2024 dated July 31, 2024.
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| Canadian Natural Resources Limited | 4 | Three and six months ended June 30, 2024 |
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural’s production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and SCO (herein collectively referred to as "crude oil") and natural gas and NGLs. This balance provides optionality for capital investments, maximizing value for the Company’s shareholders.
Underpinning this asset base is the Company's long life low decline production, representing approximately 79% of total budgeted liquids production in 2024, the majority of which is zero decline high value SCO production from the Company's world class Oil Sands Mining and Upgrading assets. The remaining balance of the Company's long life low decline production comes from its top tier thermal in situ oil sands operations and Pelican Lake heavy crude oil assets. The combination of these long life low decline assets, low reserves replacement costs, and effective and efficient operations results in substantial and sustainable adjusted funds flow throughout the commodity price cycle.
In addition, Canadian Natural maintains a substantial inventory of low capital exposure projects within the Company's conventional asset base. These projects can be executed quickly and, in the right economic conditions, provide excellent returns and maximize value for our shareholders. Supporting these projects is the Company’s undeveloped land base which enables large, repeatable drilling programs that can be optimized over time. Additionally, Canadian Natural maximizes long-term value by maintaining high ownership and operatorship of its assets and has an extensive infrastructure network, allowing the Company to control the nature, timing and extent of development. Low capital exposure projects can be stopped or started relatively quickly depending upon success, market conditions or corporate needs.
Canadian Natural’s balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.
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| Drilling Activity | Six Months Ended |
| Jun 30, 2024 | Jun 30, 2023 |
| (number of wells) | Gross | Net | Gross | Net |
Crude oil (1) | 125 | | 124 | 141 | 135 |
| Natural gas | 49 | | 40 | 50 | 42 |
| Dry | 1 | | 1 | 2 | 2 |
| Subtotal | 175 | | 165 | 193 | 179 |
| Stratigraphic test / service wells | 457 | | 391 | 470 | 409 |
| Total | 632 | | 556 | 663 | 588 |
| Success rate (excluding stratigraphic test / service wells) | | 99% | | 99% |
(1)Includes bitumen wells.
▪Canadian Natural drilled a total of 165 net crude oil and natural gas producer wells in the first six months of 2024, consistent with the Company's strategic decision to focus on longer cycle development opportunities in the first half of 2024 and shorter cycle development opportunities in the second half of 2024.
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| Canadian Natural Resources Limited | 5 | Three and six months ended June 30, 2024 |
North America Exploration and Production
| | | | | | | | | | | | | | | | | |
| Crude oil and NGLs – excluding Thermal In Situ Oil Sands | | |
| Three Months Ended | Six Months Ended |
| Jun 30
2024 | Mar 31
2024 | Jun 30
2023 | Jun 30
2024 | Jun 30
2023 |
| Crude oil and NGLs production (bbl/d) | 231,592 | 237,481 | 226,202 | 234,537 | 230,310 |
| Net wells targeting crude oil | 33 | 38 | 29 | 71 | 89 |
| Net successful wells drilled | 33 | 38 | 29 | 71 | 87 |
| Success rate | 100% | 100% | 100% | 100% | 98% |
▪North America E&P liquids production, excluding thermal in situ, averaged 231,592 bbl/d in Q2/24, an increase of 2% compared to Q2/23 levels, primarily reflecting strong heavy crude oil production offset by natural field declines. As previously outlined in the 2024 budget, the Company has strategically allocated capital for its conventional assets to the latter part of 2024 to better align with incremental market egress, driving strong targeted 2024 exit rates.
•Primary heavy crude oil production averaged 79,141 bbl/d in Q2/24, an increase of 3% from Q2/23 levels, reflecting strong results from multilateral wells on the Company's extensive heavy oil landbase in the Mannville and Clearwater fairways, partially offset by natural field declines.
◦Operating costs(1) in the Company's primary heavy crude oil operations averaged $17.59/bbl (US$12.85/bbl) in Q2/24, a decrease of 12% from Q2/23 levels, primarily reflecting lower energy costs.
◦The Company holds the largest heavy oil landbase in Canada. We continue to maximize the value of this premium asset through our multilateral drilling program.
–Through continuous improvement, Canadian Natural has increased the average length by 16% of its multilateral heavy oil wells to approximately 9,900 meters in 2024 compared to an average budgeted well length of approximately 8,500 meters, lowering cost per meter and increasing reservoir capture.
–As a result of optimized longer well designs and the technical expertise of our teams, average initial peak rates of multilaterals onstream in the first half of 2024 have increased 30% to approximately 230 bbl/d per well compared to budget average initial peak rates of 175 bbl/d per well.
•Pelican Lake production averaged 44,839 bbl/d in Q2/24, a decrease of 5% from Q2/23 levels, reflecting low natural field declines from this long life low decline asset.
◦Operating costs at Pelican Lake averaged $8.92/bbl (US$6.52/bbl) in Q2/24, an increase of 4% compared to Q2/23 levels primarily due to lower production volumes partially offset by lower energy costs.
•North America light crude oil and NGLs production averaged 107,612 bbl/d in Q2/24, an increase of 5% from Q2/23 levels. The increase in Q2/24 was a result of strong drilling results and lower Q2/23 production due to wildfires and a third-party pipeline outage.
◦Operating costs in the Company's North America light crude oil and NGLs operations averaged $13.75/bbl (US$10.05/bbl) in Q2/24, a decrease of 24% from Q2/23 levels, reflecting increased production volumes and lower energy costs.
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| North America Natural Gas | | |
| Three Months Ended | Six Months Ended |
| Jun 30
2024 | Mar 31
2024 | Jun 30
2023 | Jun 30
2024 | Jun 30
2023 |
| Natural gas production (MMcf/d) | 2,099 | 2,135 | 2,072 | 2,117 | 2,100 |
| Net wells targeting natural gas | 25 | 16 | 21 | 41 | 42 |
| Net successful wells drilled | 24 | 16 | 21 | 40 | 42 |
| Success rate | 96% | 100% | 100% | 98% | 100% |
▪Canadian Natural's North America natural gas production averaged 2,099 MMcf/d in Q2/24, comparable to Q2/23 production, primarily reflecting strong results from our Montney and Deep Basin wells offset by natural field declines.
(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 | 6 | Three and six months ended June 30, 2024 |
•North America natural gas operating costs averaged $1.19/Mcf in Q2/24, a decrease of 12% from Q2/23 levels, primarily reflecting lower energy costs.
▪As previously disclosed, certain natural gas development activity in 2024 was shifted to higher-return multilateral heavy oil wells due to low natural gas prices during the first half of 2024. Concurrently approximately 20 wells of the Company’s remaining planned 2024 natural gas wells will be drilled and curtailed.
•The Company will maintain optionality to bring on production from these wells in late 2024 or early 2025, to align with improved natural gas prices, maximizing value for shareholders.
•Canadian Natural's 2024 corporate annual natural gas production guidance of 2,120 MMcf/d to 2,230 MMcf/d remains unchanged.
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| Thermal In Situ Oil Sands | | |
| Three Months Ended | Six Months Ended |
| Jun 30
2024 | Mar 31
2024 | Jun 30
2023 | Jun 30
2024 | Jun 30
2023 |
| Bitumen production (bbl/d) | 268,044 | 268,155 | 238,941 | 268,100 | 240,902 |
| Net wells targeting bitumen | 30 | 23 | 23 | 53 | 48 |
| Net successful wells drilled | 30 | 23 | 23 | 53 | 48 |
| Success rate | 100% | 100% | 100% | 100% | 100% |
▪Thermal in situ long life low decline production averaged 268,044 bbl/d in Q2/24, an increase of 12% from Q2/23 levels, primarily driven by strong results from Primrose, Kirby and Jackfish pad developments.
•Thermal in situ operating costs averaged $10.95/bbl (US$8.00/bbl) in Q2/24, a decrease of 25% from Q2/23 levels, reflecting higher production volumes and lower energy costs.
•Planned turnarounds at Jackfish and Kirby North facilities were successfully completed ahead of schedule in Q2/24.
▪Canadian Natural has decades of strong capital efficient growth opportunities on its long life low decline thermal in situ assets. As per our 2024 budget, we continue to develop these assets in a disciplined manner to deliver safe and reliable thermal in situ production with the following opportunities:
•At Jackfish, the first of two SAGD pads drilled in 2023 reached full production capacity in Q2/24, ahead of schedule. The second pad is currently producing at full production capacity also ahead of schedule, originally budgeted for Q4/24. Additionally, the Company is targeting to drill one SAGD pad at Jackfish in the second half of 2024, with production from this pad targeted to come on in Q3/25.
•At Primrose, the Company finished drilling one Cyclic Steam Stimulation ("CSS") pad which is targeted to come on production ahead of schedule in late Q4/24, originally targeted for Q2/25. The second pad is currently being drilled and is targeted to come on production in Q2/25. At Wolf Lake, the Company recently drilled one SAGD pad which is targeted to come on production in Q1/25.
▪Canadian Natural has been piloting solvent enhanced oil recovery technology on certain thermal in situ assets with an objective to increase bitumen production while reducing the Steam to Oil Ratio ("SOR") and optimizing solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
•At Kirby North, the Company began solvent injection in late June 2024. Currently all 8 wells at its commercial scale solvent SAGD pad are targeted to increase solvent injection with subsequent reduction in steam injection over the coming months as the project advances and we continue to monitor solvent recoveries and production trends.
•At Primrose, the Company is continuing to use its solvent enhanced oil recovery pilot in the steam flood area to optimize solvent efficiency and to further evaluate this commercial development opportunity.
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| Canadian Natural Resources Limited | 7 | Three and six months ended June 30, 2024 |
North America Oil Sands Mining and Upgrading
| | | | | | | | | | | | | | | | | |
| Three Months Ended | Six Months Ended |
| Jun 30
2024 | Mar 31
2024 | Jun 30
2023 | Jun 30
2024 | Jun 30
2023 |
Synthetic crude oil production (bbl/d) (1)(2) | 410,518 | 445,209 | 355,246 | 427,863 | 406,453 |
(1)SCO production before royalties and excludes production volumes consumed internally as diesel.
(2)Consists of heavy and light synthetic crude oil products.
▪The Company's world class Oil Sands Mining and Upgrading assets delivered average production of 410,518 bbl/d of high value SCO in Q2/24, an increase of 16% from Q2/23 levels. The increase in production reflected planned turnaround activities successfully completed ahead of schedule at Horizon, compared to Q2/23 which included planned turnarounds at both Horizon and the non-operated Scotford Upgrader.
•Oil Sands Mining and Upgrading operating costs are top tier, averaging $25.95/bbl (US$18.96/bbl) in Q2/24, a decrease of 17% from Q2/23 levels, primarily reflecting higher production volumes from reduced planned turnaround activity and lower energy costs.
▪During the planned turnaround at Horizon in June 2024, the Company successfully completed all tie-ins and commissioning of the reliability enhancement project components.
•The reliability enhancement project at Horizon targets to increase the two year average SCO capacity by approximately 14,000 bbl/d by extending the turnaround schedule to once every two years, with 2025 being the first year of operations without a planned turnaround.
▪Subsequent to quarter end, the Company achieved strong monthly SCO production of approximately 500,000 bbl/d in July 2024. This was primarily a result of high utilization and effective execution of tie-ins and commissioning associated with the Horizon reliability enhancement project completed in June 2024.
▪In July 2024, the Company achieved a milestone at Horizon with the production of the one billionth barrel of bitumen since operations began in 2009.
•Supporting this milestone is the Company's significant total proved SCO reserves at approximately 6.9 billion barrels with an RLI of approximately 44 years as at year end 2023.
▪At AOSP, due to schedule optimization at the Scotford Upgrader in Q2/24, the planned September 2024 turnaround is now targeted to last 39 days compared to the previous 49 day schedule. During the turnaround, the Scotford Upgrader is expected to run at reduced rates with the impact to annual production targeted to be approximately 9,000 bbl/d, a 2,000 bbl/d improvement compared to budget.
•At the Scotford Upgrader, a debottlenecking project is targeted to be completed during the planned turnaround and targets to add incremental capacity at AOSP of approximately 5,600 bbl/d net to Canadian Natural.
▪At Horizon, the Company is progressing the NRUTT project which targets to add incremental production of approximately 6,300 bbl/d of SCO following mechanical completion in Q3/27.
International Exploration and Production
| | | | | | | | | | | | | | | | | |
| Three Months Ended | Six Months Ended |
| Jun 30
2024 | Mar 31
2024 | Jun 30
2023 | Jun 30
2024 | Jun 30
2023 |
| Crude oil production (bbl/d) | 23,912 | 24,823 | 26,520 | 24,367 | | 26,923 | |
| Natural gas production (MMcf/d) | 11 | 12 | 13 | 12 | | 12 | |
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▪International E&P crude oil production volumes averaged 23,912 bbl/d in Q2/24, a decrease of 10% from Q2/23 levels, reflecting natural field declines.
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| Canadian Natural Resources Limited | 8 | Three and six months ended June 30, 2024 |
MARKETING
| | | | | | | | | | | | | | | | | |
| Three Months Ended | Six Months Ended |
| Jun 30
2024 | Mar 31
2024 | Jun 30
2023 | Jun 30
2024 | Jun 30
2023 |
| Benchmark Commodity Prices | | | | | |
WTI benchmark price (US$/bbl) (1) | $ | 80.55 | $ | 76.97 | $ | 73.75 | $ | 78.76 | $ | 74.92 |
WCS heavy differential (discount) to WTI (US$/bbl) (1) | $ | (13.54) | $ | (19.34) | $ | (15.07) | $ | (16.44) | $ | (19.87) |
WCS heavy differential as a percentage of WTI (%) (1) | 17% | 25% | 20% | 21% | 27% |
| Condensate benchmark price (US$/bbl) | $ | 77.11 | $ | 72.79 | $ | 72.28 | $ | 74.95 | $ | 76.03 |
SCO price (US$/bbl) (1) | $ | 83.33 | $ | 69.43 | $ | 76.67 | $ | 76.38 | $ | 77.42 |
SCO premium (discount) to WTI (US$/bbl) (1) | $ | 2.78 | $ | (7.54) | $ | 2.92 | $ | (2.38) | $ | 2.50 |
| AECO benchmark price (C$/GJ) | $ | 1.36 | $ | 1.94 | $ | 2.22 | $ | 1.65 | $ | 3.17 |
| Realized Prices | | | | | |
Exploration & Production liquids realized price (C$/bbl) (2)(3)(4)(5) | $ | 86.64 | $ | 70.01 | $ | 72.06 | $ | 78.43 | $ | 65.58 |
SCO realized price (C$/bbl) (1)(3)(4)(5) | $ | 108.81 | $ | 88.84 | $ | 95.08 | $ | 98.18 | $ | 95.64 |
Natural gas realized price (C$/Mcf) (4) | $ | 1.59 | $ | 2.55 | $ | 2.53 | $ | 2.07 | $ | 3.41 |
(1)West Texas Intermediate ("WTI"); Western Canadian Select ("WCS"); Synthetic Crude Oil ("SCO").
(2)Exploration & Production crude oil and NGLs average realized price excludes SCO.
(3)Pricing is net of blending costs.
(4)Excludes risk management activities.
(5)Non-GAAP ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and six months ended June 30, 2024 dated July 31, 2024.
▪Canadian Natural has a balanced and diverse product mix of natural gas, NGLs, heavy crude oil, light crude oil, bitumen and SCO.
▪WTI prices averaged US$80.55/bbl in Q2/24, an increase of US$6.80/bbl compared to Q2/23, due to continued supply quota management by OPEC+ and geopolitical concerns in the Middle East.
▪SCO pricing averaged US$83.33/bbl in Q2/24, representing a US$2.78/bbl price premium to WTI, compared to a US$2.92/bbl price premium to WTI in Q2/23.
▪The WCS differential to WTI averaged US$13.54/bbl, narrowing by US$1.53/bbl in Q2/24, compared to US$15.07/bbl in Q2/23, primarily reflecting the start-up of TMX in Q2/24 and stronger US Gulf Coast heavy oil pricing.
▪The North West Redwater ("NWR") refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 78,272 bbl/d in Q2/24.
▪AECO natural gas prices in Q2/24 were approximately 39% lower compared to Q2/23 reflecting lower NYMEX benchmark pricing, increased production in the WCSB and higher storage inventories resulting from mild winter weather.
•In 2024, the Company is targeting to use the equivalent of approximately 38% of its budgeted natural gas production in its operations, with approximately 25% targeted to be sold at AECO/Station 2 pricing, and approximately 37% targeted to be exported to other North American and international markets capturing higher natural gas prices, maximizing value from its diversified natural gas marketing portfolio.
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| Canadian Natural Resources Limited | 9 | Three and six months ended June 30, 2024 |
SUSTAINABILITY HIGHLIGHTS
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. Canadian Natural continues to invest in a range of technologies like 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 technologies across our assets, which will enhance the Company’s long-term sustainability.
In June 2024, the Canadian Government amended the Competition Act, resulting in changes to the law around environmental communications. As we look to communicate the important work we are doing to protect the environment or helping to address climate change, there is uncertainty on how this new legislation will be interpreted and applied on a go forward basis. We regret that we are unable to provide an environment and climate update at this time. This legislation does not change our commitment to the environment and to ensuring safe, reliable operations, only the way in which we are publicly communicating these aspects of our business. As we receive additional guidance, we intend to resume environmental and climate-related disclosure.
While we wait for clarity on this legislation, we are proud to share Canadian Natural’s performance in governance, workplace and process safety, and our contributions to people, community and partnerships. Today, Canadian Natural released its 2023 Stewardship Report to Stakeholders in conjunction with Q2/24 results, which is now available on the Company's website at www.cnrl.com. This report displays how Canadian Natural continues to focus on safe, reliable, effective and efficient operations while enhancing our world-class assets by innovating and leveraging technology, and driving continuous improvement across our teams. These efforts include building shared value with communities and Indigenous groups in our operating areas.
Highlights from the Company's 2023 report include:
▪50% reduction in total recordable injury frequency ("TRIF") and an 75% reduction in corporate lost time incident frequency ("LTI") from 2019 to 2023.
▪$502 million invested in research, technology development and deployment in 2023.
▪2.7 million tonnes of CO2e per year total carbon capture capacity.
▪$830 million in contracts secured with Indigenous businesses, a 21% increase from 2022.
▪Approximately $9 billion in payments to governments and local communities in 2023 through royalties, corporate taxes, property taxes and surface and mineral land leases.
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| Canadian Natural Resources Limited | 10 | Three and six months ended June 30, 2024 |
ADVISORY
Special Note Regarding Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "focus", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to the Company's strategy or strategic focus, capital budget, expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, abandonment expenditures, income tax expenses, and other targets provided throughout this document and the Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, including the strength of the Company's balance sheet, the sources and adequacy of the Company's liquidity, and the flexibility of the Company's capital structure, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects ("Primrose"), the Pelican Lake water and polymer flood projects ("Pelican Lake"), the Kirby thermal oil sands project ("Kirby"), the Jackfish thermal oil sands project ("Jackfish") and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market; the abandonment and decommissioning of certain assets and the timing thereof; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; the materiality of the impact of tax interpretations and litigation on the Company's results, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of armed conflicts in the Middle East, the impact of the Russian invasion of Ukraine, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the ability of the Company to prevent and recover from a cyberattack, other cyber-related crime and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the Company's ability to implement strategies and leverage technologies to meet climate change initiatives and emissions targets on the expected timelines; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company to complete capital programs; the Company's ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety, competition, environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.
The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state and local laws and regulations such as restrictions on production, 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
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| Canadian Natural Resources Limited | 11 | Three and six months ended June 30, 2024 |
respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this document or the Company's MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this document or the Company's MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company’s estimates or opinions change.
Special Note Regarding Common Share Split and Comparative Figures
At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a Special Resolution approving a two for one common share split effective for shareholders of record as of market close on June 3, 2024. On June 10, 2024, shareholders of record received one additional share for every one common share held, with common shares trading on a split-adjusted basis beginning June 11, 2024. Common share, per common share, dividend, and stock option amounts for periods prior to the two for one common share split have been updated to reflect the common share split.
Special Note Regarding Amendments to the Competition Act (Canada)
On June 20, 2024, amendments to the Competition Act (Canada) came into force with the adoption of Bill C-59, An Act to Implement Certain Provisions of the Fall Economic Statement which impact environmental and climate disclosures by businesses. As a result of these amendments, certain public representations by a business regarding the benefits of the work it is doing to protect or restore the environment or mitigate the environmental and ecological causes or effects of climate change may violate the Competition Act's deceptive marketing practices provisions. These amendments include substantial financial penalties and, effective June 20, 2025, a private right of action which will permit private parties to seek an order from the Competition Tribunal under the deceptive marketing practices provisions. Uncertainty surrounding the interpretation and enforcement of this legislation may expose the Company to increased litigation and financial penalties, the outcome and impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business, reputation, financial condition, and results.
Special Note Regarding Currency, Financial Information and Production
This document should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") and the Company's MD&A for the three and six months ended June 30, 2024, and audited consolidated financial statements for the year ended December 31, 2023. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company’s financial statements and MD&A for the three and six months ended June 30, 2024 have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").
Production volumes and per unit statistics are presented throughout this document on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this document, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.
Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2023, is available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. Information on the Company's website does not form part of and is not incorporated by reference in the Company's MD&A.
Special Note Regarding Non-GAAP and Other Financial Measures
This document includes references to non-GAAP measures, which include non-GAAP and other financial measures as defined in National Instrument 52-112 – Non-GAAP and Other Financial Measures Disclosure. These financial measures are used by the Company to evaluate its financial performance, financial position or cash flow and include non-GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial measure presented in the Company's financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company’s non-GAAP and other financial measures included in this document, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below as well as in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and six months ended June 30, 2024, dated July 31, 2024.
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| Canadian Natural Resources Limited | 12 | Three and six months ended June 30, 2024 |
Break-even WTI Price
The break-even WTI price is a supplementary financial measure that represents the equivalent US dollar WTI price per barrel where the Company's adjusted funds flow is equal to the sum of maintenance capital and dividends. The Company considers the break-even WTI price a key measure in evaluating its performance, as it demonstrates the efficiency and profitability of the Company's activities. The break-even WTI price incorporates the non-GAAP financial measure adjusted funds flow as reconciled in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. Maintenance capital is a supplementary financial measure that represents the capital required to maintain annual production at prior period levels.
Capital Budget
Capital budget is a forward looking non-GAAP financial measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for more details on net capital expenditures.
Capital Efficiency
Capital efficiency is a supplementary financial measure that represents the capital spent to add new or incremental production divided by the current rate of the new or incremental production. It is expressed as a dollar amount per flowing volume of a product ($/bbl/d or $/BOE/d). The Company considers capital efficiency a key measure in evaluating its performance, as it demonstrates the efficiency of the Company's capital investments.
Free Cash Flow Policy in 2023 and 2024
Free cash flow is a non-GAAP financial measure. The Company considers free cash flow a key measure in demonstrating the Company’s ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders and to repay or maintain net debt levels, pursuant to the free cash flow allocation policy.
The Company’s free cash flow is used to determine the target amount of shareholder returns after dividends. The calculation in determining free cash flow varies depending on the Company’s net debt position, and as a result of achieving $10 billion in net debt at the end of 2023, the Company's free cash flow calculation has changed in 2024, when compared to 2023 as follows:
▪Allocation of Free Cash Flow in 2024
As net debt of $10 billion was achieved at the end of 2023, commencing in 2024, the Company will target to return 100% of free cash flow to shareholders. Free cash flow is calculated as adjusted funds flow less dividends on common shares, net capital expenditures and abandonment expenditures. The Company targets to manage the allocation of free cash flow on a forward looking annual basis, while managing working capital and cash management as required.
The Company's free cash flow for the three and six months ended June 30, 2024 is shown below:
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| Three Months Ended | Six Months Ended |
| ($ millions) | Jun 30
2024 | Mar 31
2024 | Jun 30
2024 |
Adjusted funds flow (1) | $ | 3,614 | | $ | 3,138 | | $ | 6,752 | |
| Less: Dividends on common shares | 1,125 | | | 1,076 | | 2,201 | |
Net capital expenditures (2) | | 1,621 | | | 1,113 | | | 2,734 | |
| Abandonment expenditures | | 129 | | | 162 | | 291 | |
| Free cash flow | $ | 739 | | $ | 787 | | $ | 1,526 | |
(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 six months ended June 30, 2024, dated July 31, 2024.
(2)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three and six months ended June 30, 2024, dated July 31, 2024.
▪Allocation of Free Cash Flow in 2023
When net debt was between $10 billion and $15 billion, as was the case in 2023, approximately 50% of free cash flow was allocated to shareholder returns and 50% was allocated to the balance sheet, less strategic growth/acquisition opportunities. In 2023, free cash flow of $6.9 billion was calculated as adjusted funds flow of $15.3 billion less dividends on common shares of $3.9 billion, base capital expenditures of $4.0 million and abandonment expenditures of $0.5 billion.
Long-term Debt, net
Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents.
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| ($ millions) | Jun 30
2024 | Mar 31
2024 | Dec 31
2023 | Jun 30
2023 |
| Long-term debt | $ | 10,149 | | $ | 11,040 | | $ | 10,799 | | $ | 12,155 | |
| Less: cash and cash equivalents | 915 | | 767 | | 877 | | 122 | |
| Long-term debt, net | $ | 9,234 | | $ | 10,273 | | $ | 9,922 | | $ | 12,033 | |
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| Canadian Natural Resources Limited | 13 | Three and six months ended June 30, 2024 |
CONFERENCE CALL
Canadian Natural Resources Limited (TSX-CNQ / NYSE-CNQ) will be issuing its 2024 Second Quarter Earnings Results on Thursday, August 1, 2024 before market open.
A conference call will be held at 9:00 a.m. MDT / 11:00 a.m. EDT on Thursday, August 1, 2024.
Dial-in to the live event:
North America 1-800-717-1738 / International 001-289-514-5100.
Listen to the audio webcast:
Access the audio webcast on the home page of our website, www.cnrl.com.
Conference call playback:
North America 1-888-660-6264 / International 001-289-819-1325 (Passcode: 22190#)
Canadian Natural is a senior crude oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.
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CANADIAN NATURAL RESOURCES LIMITED T (403) 517-6700 F (403) 517-7350 E ir@cnrl.com 2100, 855 - 2 Street S.W. Calgary, Alberta, T2P 4J8 www.cnrl.com |
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SCOTT G. STAUTH President MARK A. STAINTHORPE Chief Financial Officer LANCE J. CASSON Manager, Investor Relations Trading Symbol - CNQ Toronto Stock Exchange New York Stock Exchange |
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| Canadian Natural Resources Limited | 14 | Three and six months ended June 30, 2024 |
CANADIAN NATURAL RESOURCES LIMITED
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MANAGEMENT'S DISCUSSION & ANALYSIS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2024 |
| JULY 31, 2024 |
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", "focus", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to the Company's strategy or strategic focus, capital budget, expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, abandonment expenditures, income tax expenses, and other targets provided throughout this Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, including the strength of the Company's balance sheet, the sources and adequacy of the Company's liquidity, and the flexibility of the Company's capital structure, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects ("Primrose"), the Pelican Lake water and polymer flood projects ("Pelican Lake"), the Kirby thermal oil sands project ("Kirby"), the Jackfish thermal oil sands project ("Jackfish") and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market; the abandonment and decommissioning of certain assets and the timing thereof; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; the materiality of the impact of tax interpretations and litigation on the Company's results, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of armed conflicts in the Middle East, the impact of the Russian invasion of Ukraine, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the ability of the Company to prevent and recover from a cyberattack, other cyber-related crime and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the Company's ability to implement strategies and leverage technologies to meet climate change initiatives and emissions targets on the expected timelines; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company to complete capital programs; the Company's ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety, competition, environmental laws and regulations, and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax and competition laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.
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| Canadian Natural Resources Limited | 1 | Three and six months ended June 30, 2024 |
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 Common Share Split and Comparative Figures
At the Company's Annual and Special Meeting held on May 2, 2024, shareholders passed a Special Resolution approving a two for one common share split effective for shareholders of record as of market close on June 3, 2024. On June 10, 2024, shareholders of record received one additional share for every one common share held, with common shares trading on a split-adjusted basis beginning June 11, 2024. Common share, per common share, dividend, and stock option amounts for periods prior to the two for one common share split have been updated to reflect the common share split.
Special Note Regarding Amendments to the Competition Act (Canada)
On June 20, 2024, amendments to the Competition Act (Canada) came into force with the adoption of Bill C-59, An Act to Implement Certain Provisions of the Fall Economic Statement which impact environmental and climate disclosures by businesses. As a result of these amendments, certain public representations by a business regarding the benefits of the work it is doing to protect or restore the environment or mitigate the environmental and ecological causes or effects of climate change may violate the Competition Act's deceptive marketing practices provisions. These amendments include substantial financial penalties and, effective June 20, 2025, a private right of action which will permit private parties to seek an order from the Competition Tribunal under the deceptive marketing practices provisions. Uncertainty surrounding the interpretation and enforcement of this legislation may expose the Company to increased litigation and financial penalties, the outcome and impacts of which can be difficult to assess or quantify and may have a material adverse effect on the Company's business, reputation, financial condition, and results.
Special Note Regarding Currency, Financial Information and Production
This MD&A should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") for the three and six months ended June 30, 2024, and the Company's MD&A and audited consolidated financial statements for the year ended December 31, 2023. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements for the three and six months ended June 30, 2024 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 six months ended June 30, 2024 in relation to the comparable periods in 2023 and the first quarter of 2024. 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, 2023, is available on SEDAR+ at www.sedarplus.ca, and on EDGAR at www.sec.gov. Information on the Company's website does not form part of and is not incorporated by reference in this MD&A. This MD&A is dated July 31, 2024.
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| Canadian Natural Resources Limited | 2 | Three and six months ended June 30, 2024 |
FINANCIAL HIGHLIGHTS(1)
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| | | Three Months Ended | | | Six Months Ended |
| ($ millions, except per common share amounts) | | Jun 30
2024 | | Mar 31
2024 | | Jun 30
2023 | | | Jun 30
2024 | | Jun 30
2023 |
Product sales (1) | | $ | 10,622 | | | $ | 9,422 | | | $ | 8,846 | | | | $ | 20,044 | | | $ | 18,394 | |
| Crude oil and NGLs | | $ | 10,084 | | | $ | 8,676 | | | $ | 8,115 | | | | $ | 18,760 | | | $ | 16,527 | |
| Natural gas | | | $ | 331 | | | $ | 529 | | | $ | 522 | | | | $ | 860 | | | $ | 1,373 | |
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| Net earnings | | $ | 1,715 | | | $ | 987 | | | $ | 1,463 | | | | $ | 2,702 | | | $ | 3,262 | |
| Per common share | – basic | | $ | 0.80 | | | $ | 0.46 | | | $ | 0.67 | | | | $ | 1.26 | | | $ | 1.49 | |
| – diluted | | $ | 0.80 | | | $ | 0.46 | | | $ | 0.66 | | | | $ | 1.25 | | | $ | 1.47 | |
Adjusted net earnings from operations (2) | | $ | 1,892 | | | $ | 1,474 | | | $ | 1,256 | | | | $ | 3,366 | | | $ | 3,137 | |
| Per common share | – basic (3) | | $ | 0.89 | | | $ | 0.69 | | | $ | 0.57 | | | | $ | 1.57 | | | $ | 1.43 | |
| – diluted (3) | | $ | 0.88 | | | $ | 0.68 | | | $ | 0.57 | | | | $ | 1.56 | | | $ | 1.41 | |
| Cash flows from operating activities | | $ | 4,084 | | | $ | 2,868 | | | $ | 2,745 | | | | $ | 6,952 | | | $ | 4,040 | |
Adjusted funds flow (2) | | $ | 3,614 | | | $ | 3,138 | | | $ | 2,742 | | | | $ | 6,752 | | | $ | 6,171 | |
| Per common share | – basic (3) | | $ | 1.69 | | | $ | 1.47 | | | $ | 1.25 | | | | $ | 3.16 | | | $ | 2.81 | |
| – diluted (3) | | $ | 1.68 | | | $ | 1.45 | | | $ | 1.24 | | | | $ | 3.13 | | | $ | 2.78 | |
| Cash flows used in investing activities | | $ | 1,015 | | | $ | 1,392 | | | $ | 1,560 | | | | $ | 2,407 | | | $ | 2,713 | |
Net capital expenditures (4) | | $ | 1,621 | | | $ | 1,113 | | | $ | 1,569 | | | | $ | 2,734 | | | $ | 2,826 | |
| Abandonment expenditures | | $ | 129 | | | $ | 162 | | | $ | 100 | | | | $ | 291 | | | $ | 237 | |
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(1)Further details related to product sales are disclosed in note 18 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.
(4)Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2023 and has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
SUMMARY OF FINANCIAL HIGHLIGHTS
Consolidated Net Earnings and Adjusted Net Earnings from Operations
Net earnings for the six months ended June 30, 2024 were $2,702 million compared with $3,262 million for the six months ended June 30, 2023. Net earnings for the six months ended June 30, 2024 included non-operating losses, net of tax, of $664 million compared with non-operating income of $125 million for the six months ended June 30, 2023 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on the repayment of US dollar debt securities, the gain from investments, and a recoverability charge related to the notice to withdraw from Block 11B/12B in South Africa. Excluding these items, adjusted net earnings from operations for the six months ended June 30, 2024 were $3,366 million compared with $3,137 million for the six months ended June 30, 2023.
Net earnings for the second quarter of 2024 were $1,715 million compared with $1,463 million for the second quarter of 2023 and $987 million for the first quarter of 2024. Net earnings for the second quarter of 2024 included non-operating losses, net of tax, of $177 million compared with non-operating income of $207 million for the second quarter of 2023 and non-operating losses of $487 million for the first quarter of 2024 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, realized foreign exchange on the repayment of US dollar debt securities, the loss (gain) from investments, and a recoverability charge related to the notice to withdraw from Block 11B/12B in South Africa. Excluding these items, adjusted net earnings from operations for the second quarter of 2024 were $1,892 million compared with $1,256 million for the second quarter of 2023 and $1,474 million for the first quarter of 2024.
(1)Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are disclosed in the Advisory section of this MD&A and in note 1 of the financial statements.
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| Canadian Natural Resources Limited | 3 | Three and six months ended June 30, 2024 |
The movements in net earnings and adjusted net earnings from operations for the three and six months ended June 30, 2024 from the three and six months ended June 30, 2023 primarily reflected:
▪higher crude oil and NGLs sales volumes and netbacks(1) in the North America Exploration and Production segment; and
▪higher realized SCO pricing(1) and sales volumes in the Oil Sands Mining and Upgrading segment;
partially offset by:
▪lower natural gas pricing in the North America Exploration and Production segment.
The increase in net earnings and adjusted net earnings from operations for the second quarter of 2024 from the first quarter of 2024 primarily reflected:
▪higher crude oil and NGLs pricing in the North America Exploration and Production segment; and
▪higher realized SCO sales pricing in the Oil Sands Mining and Upgrading segment;
partially offset by:
▪lower SCO sales volumes in the Oil Sands Mining and Upgrading segment; and
▪lower natural gas pricing in the North America Exploration and Production segment.
The impacts of share-based compensation, risk management activities, foreign exchange loss (gain), and the loss (gain) from investment 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 six months ended June 30, 2024 were $6,952 million compared with $4,040 million for the six months ended June 30, 2023. Cash flows from operating activities for the second quarter of 2024 were $4,084 million compared with $2,745 million for the second quarter of 2023 and $2,868 million for the first quarter of 2024. The increase 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 six months ended June 30, 2024 was $6,752 million compared with $6,171 million for the six months ended June 30, 2023. Adjusted funds flow for the second quarter of 2024 was $3,614 million compared with $2,742 million for the second quarter of 2023 and $3,138 million for the first quarter of 2024. The increase in adjusted funds flow from the comparable periods was 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, and movements in other long-term assets, including the unamortized cost of the share bonus program, accrued interest on the deferred Petroleum Revenue Tax ("PRT") recovery, and prepaid cost of service tolls.
Production Volumes
Crude oil and NGLs production before royalties for the second quarter of 2024 of 934,066 bbl/d increased 10% from 846,909 bbl/d for the second quarter of 2023, and decreased 4% from 975,668 bbl/d for the first quarter of 2024. Natural gas production before royalties for the second quarter of 2024 of 2,110 MMcf/d was comparable with 2,085 MMcf/d for the second quarter of 2023 and 2,147 MMcf/d for the first quarter of 2024. Total production before royalties for the second quarter of 2024 of 1,285,798 BOE/d increased 8% from 1,194,326 BOE/d for the second quarter of 2023, and decreased 4% from 1,333,502 BOE/d for the first quarter of 2024. Crude oil and NGLs and natural gas production volumes are discussed in detail in the "Daily Production, before royalties" section of this MD&A.
(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 | 4 | Three and six months ended June 30, 2024 |
Product Prices
In the Company's Exploration and Production segments, realized crude oil and NGLs prices(1) averaged $86.64 per bbl for the second quarter of 2024, an increase of 20% from $72.06 per bbl for the second quarter of 2023, and an increase of 24% from $70.01 per bbl for the first quarter of 2024. The realized natural gas price decreased 37% to average $1.59 per Mcf for the second quarter of 2024 from $2.53 per Mcf for the second quarter of 2023, and decreased 38% from $2.55 per Mcf for the first quarter of 2024. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price increased 14% to average $108.81 per bbl for the second quarter of 2024 from $95.08 per bbl for the second quarter of 2023, and increased 22% from $88.84 per bbl for the first quarter of 2024. 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.
Production Expense
In the Company's Exploration and Production segments, crude oil and NGLs production expense(2) averaged $14.54 per bbl for the second quarter of 2024, a decrease of 21% from $18.38 per bbl for the second quarter of 2023, and a decrease of 13% from $16.66 per bbl for the first quarter of 2024. Natural gas production expense(2) averaged $1.21 per Mcf for the second quarter of 2024, a decrease of 12% from $1.37 per Mcf for the second quarter of 2023, and a decrease of 7% from $1.30 per Mcf for the first quarter of 2024. In the Oil Sands Mining and Upgrading segment, production expense(2) averaged $25.95 per bbl for the second quarter of 2024, a decrease of 17% from $31.28 per bbl for the second quarter of 2023, and an increase of 4% from $24.85 per bbl for the first quarter of 2024. Crude oil and NGLs and natural gas production expense is discussed in detail in the "Production Expense – Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.
SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company's quarterly financial results for the eight most recently completed quarters:
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| ($ millions, except per common share amounts) | | Jun 30
2024 | | Mar 31
2024 | | Dec 31
2023 | | Sep 30
2023 |
Product sales (1) | | $ | 10,622 | | | $ | 9,422 | | | $ | 10,679 | | | $ | 11,762 | |
| Crude oil and NGLs | | $ | 10,084 | | | $ | 8,676 | | | $ | 9,829 | | | $ | 10,944 | |
| Natural gas | | $ | 331 | | | $ | 529 | | | $ | 603 | | | $ | 599 | |
| Net earnings | | $ | 1,715 | | | $ | 987 | | | $ | 2,627 | | | $ | 2,344 | |
Net earnings per common share (2) | | | | | | | | |
| – basic | | $ | 0.80 | | | $ | 0.46 | | | $ | 1.22 | | | $ | 1.08 | |
| – diluted | | $ | 0.80 | | | $ | 0.46 | | | $ | 1.21 | | | $ | 1.06 | |
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| ($ millions, except per common share amounts) | | Jun 30
2023 | | Mar 31
2023 | | Dec 31
2022 | | Sep 30
2022 |
Product sales (1) | | $ | 8,846 | | | $ | 9,548 | | | $ | 11,012 | | | $ | 12,574 | |
| Crude oil and NGLs | | $ | 8,115 | | | $ | 8,412 | | | $ | 9,508 | | | $ | 11,001 | |
| Natural gas | | $ | 522 | | | $ | 851 | | | $ | 1,287 | | | $ | 1,342 | |
| Net earnings | | $ | 1,463 | | | $ | 1,799 | | | $ | 1,520 | | | $ | 2,814 | |
Net earnings per common share (2) | | | | | | | | |
| – basic | | $ | 0.67 | | | $ | 0.82 | | | $ | 0.69 | | | $ | 1.26 | |
| – diluted | | $ | 0.66 | | | $ | 0.81 | | | $ | 0.68 | | | $ | 1.24 | |
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(1)Further details related to product sales for the three months ended June 30, 2024 and 2023 are disclosed in note 18 to the financial statements.
(2)Common share, per common share, dividend, and stock option amounts have been updated to reflect the two for one common share split. Further details are disclosed in the Advisory section of this MD&A and in note 1 of the financial statements.
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2)Calculated as respective production expense divided by respective sales volumes.
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| Canadian Natural Resources Limited | 5 | Three and six months ended June 30, 2024 |
Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to:
▪Crude oil pricing – Fluctuations in 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 the Russian invasion of Ukraine and conflict in the Middle East) on worldwide benchmark pricing, the impact of shale oil production in North America, the impact of the start-up of the Trans Mountain Expansion ("TMX") pipeline, 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 – Fluctuations in both the demand for natural gas and inventory storage levels, the impact of 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.
▪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 the North America Exploration and Production segment, natural field decline rates, the impact of turnarounds and pitstops in the Oil Sands Mining and Upgrading segment, wildfires and a third-party pipeline outage in 2023 in the North America Exploration and Production 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 the North America Exploration and Production segment, natural field decline rates, the impact of seasonal conditions, wildfires and a third-party pipeline outage in 2023 in the North America Exploration and Production 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, fluctuating energy costs, inflationary cost pressures, cost optimizations across all segments, 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, 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, a recoverability charge related to the notice to withdraw from Block 11B/12B in South Africa, a recoverability charge at December 31, 2023 relating to the increase in estimate of future abandonment costs for the planned decommissioning activities at the Ninian field in the North Sea, and a recoverability charge at December 31, 2022 relating to the de-booking of reserves at the Ninian field in the North Sea.
▪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 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.
▪Loss (gain) from investment – Fluctuations due to the loss (gain) from the investment in PrairieSky Royalty Ltd. shares.
BUSINESS ENVIRONMENT
Global crude oil benchmark pricing gained momentum in the second quarter of 2024 as a result of supply quota management by OPEC+ and continued geopolitical tensions in the Middle East. The start-up of TMX in the second quarter of 2024 also contributed to a narrowing of the WCS differential with corresponding benefits to realized pricing. 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.
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| Canadian Natural Resources Limited | 6 | Three and six months ended June 30, 2024 |
Liquidity
As at June 30, 2024, the Company had undrawn revolving bank credit facilities of $5,450 million. Including cash and cash equivalents, the Company had approximately $6,365 million in liquidity(1). The Company also has certain other dedicated credit facilities supporting letters of credit.
The Company remains committed to maintaining a strong balance sheet, adequate available liquidity, and a flexible capital structure. Refer to the "Liquidity and Capital Resources" section of this MD&A for further details.
Benchmark Commodity Prices
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| | Three Months Ended | | | Six Months Ended |
(Average for the period) | | Jun 30
2024 | | Mar 31
2024 | | Jun 30
2023 | | | Jun 30
2024 | | Jun 30
2023 |
| WTI benchmark price (US$/bbl) | | $ | 80.55 | | | $ | 76.97 | | | $ | 73.75 | | | | $ | 78.76 | | | $ | 74.92 | |
| Dated Brent benchmark price (US$/bbl) | | $ | 84.90 | | | $ | 83.23 | | | $ | 78.37 | | | | $ | 84.07 | | | $ | 79.79 | |
| WCS Heavy Differential from WTI (US$/bbl) | | $ | 13.54 | | | $ | 19.34 | | | $ | 15.07 | | | | $ | 16.44 | | | $ | 19.87 | |
SCO price (US$/bbl) | | $ | 83.33 | | | $ | 69.43 | | | $ | 76.67 | | | | $ | 76.38 | | | $ | 77.42 | |
| Condensate benchmark price (US$/bbl) | | $ | 77.11 | | | $ | 72.79 | | | $ | 72.28 | | | | $ | 74.95 | | | $ | 76.03 | |
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| NYMEX benchmark price (US$/MMBtu) | | $ | 1.89 | | | $ | 2.24 | | | $ | 2.10 | | | | $ | 2.06 | | | $ | 2.76 | |
| AECO benchmark price (C$/GJ) | | $ | 1.36 | | | $ | 1.94 | | | $ | 2.22 | | | | $ | 1.65 | | | $ | 3.17 | |
US/Canadian dollar average exchange rate (US$) | | $ | 0.7308 | | | $ | 0.7415 | | | $ | 0.7447 | | | | $ | 0.7360 | | | $ | 0.7420 | |
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 resulting in product revenues being impacted by changes in Canadian dollar sales prices relative to the US dollar benchmark prices.
Crude oil sales contracts in North America are typically based on WTI benchmark pricing. WTI averaged US$78.76 per bbl for the six months ended June 30, 2024, an increase of 5% from US$74.92 per bbl for the six months ended June 30, 2023. WTI averaged US$80.55 per bbl for the second quarter of 2024, an increase of 9% from US$73.75 per bbl for the second quarter of 2023, and an increase of 5% from US$76.97 per bbl for the first quarter of 2024.
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$84.07 per bbl for the six months ended June 30, 2024, an increase of 5% from US$79.79 per bbl for the six months ended June 30, 2023. Brent averaged US$84.90 per bbl for the second quarter of 2024, an increase of 8% from US$78.37 per bbl for the second quarter of 2023, and comparable with US$83.23 per bbl for the first quarter of 2024.
The increase in WTI and Brent benchmark pricing for the three and six months ended June 30, 2024 from the comparable periods in 2023 reflected continued supply quota management by OPEC+ and geopolitical concerns in the Middle East. The increase in WTI benchmark pricing for the second quarter of 2024 from the first quarter of 2024 reflected stronger seasonal demand outlooks.
The WCS Heavy Differential averaged US$16.44 per bbl for the six months ended June 30, 2024, compared with US$19.87 per bbl for the six months ended June 30, 2023. The WCS Heavy Differential averaged US$13.54 per bbl for the second quarter of 2024, compared with US$15.07 per bbl for the second quarter of 2023, and US$19.34 per bbl for the first quarter of 2024. The narrowing of the WCS Heavy Differential for the three and six months ended June 30, 2024 from the comparable periods in 2023 reflected the start-up of the TMX pipeline in the second quarter of 2024, combined with stronger US Gulf Coast heavy oil pricing. The narrowing of the WCS Heavy Differential for the second quarter of 2024 from the first quarter of 2024 reflected the start-up of the TMX pipeline as well as maintenance activities in the Western Canada Sedimentary Basin ("WCSB").
The SCO price averaged US$76.38 per bbl for the six months ended June 30, 2024, comparable with US$77.42 per bbl for the six months ended June 30, 2023. The SCO price averaged US$83.33 per bbl for the second quarter of 2024, an increase of 9% from US$76.67 per bbl for the second quarter of 2023, and an increase of 20% from US$69.43 per bbl for the first quarter of 2024. The increase in SCO pricing for the second quarter of 2024 from the second quarter of 2023 primarily reflected increased WTI benchmark pricing. The increase in SCO pricing for the second quarter of 2024 from the first quarter of 2024 reflected the SCO differential strengthening as a result of upgrader maintenance in the WCSB and the start-up of the TMX pipeline.
(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 | 7 | Three and six months ended June 30, 2024 |
NYMEX natural gas prices averaged US$2.06 per MMBtu for the six months ended June 30, 2024, a decrease of 25% from US$2.76 per MMBtu for the six months ended June 30, 2023. NYMEX natural gas prices averaged US$1.89 per MMBtu for the second quarter of 2024, a decrease of 10% from US$2.10 per MMBtu for the second quarter of 2023, and a decrease of 16% from US$2.24 per MMBtu for the first quarter of 2024. The decrease in NYMEX natural gas prices for three and six months ended June 30, 2024 from the comparable periods reflected mild winter weather that reduced heating demand and drove North American and European inventory levels above the five year average. Additionally, reduced Liquefied Natural Gas ("LNG") exports from the US Gulf Coast, as a result of maintenance, contributed to downward pressure on prices.
AECO natural gas prices averaged $1.65 per GJ for the six months ended June 30, 2024, a decrease of 48% from $3.17 per GJ for the six months ended June 30, 2023. AECO natural gas prices averaged $1.36 per GJ for the second quarter of 2024, a decrease of 39% from $2.22 per GJ for the second quarter of 2023, and a decrease of 30% from $1.94 per GJ for the first quarter of 2024. The decrease in AECO natural gas prices for three and six months ended June 30, 2024 from the comparable periods reflected decreased NYMEX benchmark pricing, increased production in the WCSB, and higher storage inventories resulting from mild winter weather in 2024.
DAILY PRODUCTION, before royalties
| | | | | | | | | | | | | | | | | |
| Three Months Ended | Six Months Ended |
| | Jun 30
2024 | Mar 31
2024 | Jun 30
2023 | Jun 30
2024 | Jun 30
2023 |
Crude oil and NGLs (bbl/d) | | | | | |
| North America – Exploration and Production | 499,636 | | 505,636 | | 465,143 | | 502,636 | | 471,212 | |
North America – Oil Sands Mining and Upgrading (1) | 410,518 | | 445,209 | | 355,246 | | 427,863 | | 406,453 | |
| International – Exploration and Production | | | | | |
| North Sea | 11,295 | | 12,433 | | 12,699 | | 11,864 | | 12,968 | |
| Offshore Africa | 12,617 | | 12,390 | | 13,821 | | 12,503 | | 13,955 | |
Total International (2) | 23,912 | | 24,823 | | 26,520 | | 24,367 | | 26,923 | |
| Total crude oil and NGLs | 934,066 | | 975,668 | | 846,909 | | 954,866 | | 904,588 | |
Natural gas (MMcf/d) (3) | | | | | |
| North America | 2,099 | | 2,135 | | 2,072 | | 2,117 | | 2,100 | |
| International | | | | | |
| North Sea | 2 | | 1 | | 2 | | 2 | | 2 | |
| Offshore Africa | 9 | | 11 | | 11 | | 10 | | 10 | |
| Total International | 11 | | 12 | | 13 | | 12 | | 12 | |
| Total Natural gas | 2,110 | | 2,147 | | 2,085 | | 2,129 | | 2,112 | |
| Total Barrels of oil equivalent (BOE/d) | 1,285,798 | | 1,333,502 | | 1,194,326 | | 1,309,649 | | 1,256,513 | |
| Product mix | | | | | |
Light and medium crude oil and NGLs | 10% | 11% | 11% | 10% | 11% |
| Pelican Lake heavy crude oil | 4% | 3% | 4% | 3% | 4% |
| Primary heavy crude oil | 6% | 6% | 6% | 6% | 6% |
| Bitumen (thermal oil) | 21% | 20% | 20% | 21% | 19% |
Synthetic crude oil (1) | 32% | 33% | 30% | 33% | 32% |
| Natural gas | 27% | 27% | 29% | 27% | 28% |
Percentage of product sales (1) (4) (5) | | | | | |
| Crude oil and NGLs | 97% | 94% | 93% | 95% | 91% |
| Natural gas | 3% | 6% | 7% | 5% | 9% |
(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 in this MD&A.
(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 six months ended June 30, 2024 |
DAILY PRODUCTION, net of royalties
| | | | | | | | | | | | | | | | | |
| Three Months Ended | Six Months Ended |
| | Jun 30
2024 | Mar 31
2024 | Jun 30
2023 | Jun 30
2024 | Jun 30
2023 |
Crude oil and NGLs (bbl/d) | | | | | |
| North America – Exploration and Production | 394,025 | | 413,752 | | 388,670 | | 403,888 | | 392,555 | |
North America – Oil Sands Mining and Upgrading (1) | 332,272 | | 370,837 | | 301,239 | | 351,554 | | 356,033 | |
| International – Exploration and Production | | | | | |
| North Sea | 11,270 | | 12,406 | | 12,654 | | 11,838 | | 12,945 | |
| Offshore Africa | 12,057 | | 11,755 | | 12,343 | | 11,906 | | 12,540 | |
| Total International | 23,327 | | 24,161 | | 24,997 | | 23,744 | | 25,485 | |
| Total Crude oil and NGLs | 749,624 | | 808,750 | | 714,906 | | 779,186 | | 774,073 | |
Natural gas (MMcf/d) | | | | | |
| North America | 2,077 | | 2,049 | | 2,014 | | 2,063 | | 2,001 | |
| International | | | | | |
| North Sea | 2 | | 1 | | 2 | | 2 | | 2 | |
| Offshore Africa | 9 | | 11 | | 10 | | 10 | | 10 | |
| Total International | 11 | | 12 | | 12 | | 12 | | 12 | |
| Total Natural gas | 2,088 | | 2,061 | | 2,026 | | 2,075 | | 2,013 | |
| Total Barrels of oil equivalent (BOE/d) | 1,097,693 | | 1,152,258 | | 1,052,602 | | 1,124,974 | | 1,109,635 | |
(1)SCO production net of royalties excludes SCO consumed internally as diesel.
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 six months ended June 30, 2024 averaged 954,866 bbl/d, an increase of 6% from 904,588 bbl/d for the six months ended June 30, 2023. Crude oil and NGLs production before royalties for the second quarter of 2024 averaged 934,066 bbl/d, an increase of 10% from 846,909 bbl/d for the second quarter of 2023, and a decrease of 4% from 975,668 bbl/d for the first quarter of 2024. The increase in crude oil and NGLs production for the three and six months ended June 30, 2024 from the comparable periods in 2023 reflected higher thermal oil production due to the cyclical nature of Primrose as well as pad additions in the North America Exploration and Production segment, partially offset by the planned turnaround at Horizon successfully completed in the second quarter of 2024 in the Oil Sands Mining and Upgrading segment. The increase in crude oil and NGLs production for the second quarter of 2024 from the second quarter of 2023 also reflected turnarounds at both Horizon and the non-operated Scotford Upgrader ("Scotford") in the second quarter of 2023. The decrease in crude oil and NGLs production for the second quarter of 2024 from the first quarter of 2024 primarily reflected lower production in the Oil Sands Mining and Upgrading segment due to the planned turnaround at Horizon.
Annual crude oil and NGLs production for 2024 is targeted to average between 977,000 bbl/d and 1,008,000 bbl/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.
Natural gas production before royalties for the six months ended June 30, 2024 averaged 2,129 MMcf/d, comparable with 2,112 MMcf/d for the six months ended June 30, 2023. Natural gas production before royalties for the second quarter of 2024 averaged 2,110 MMcf/d, comparable with 2,085 MMcf/d for the second quarter of 2023 and 2,147 MMcf/d for the first quarter of 2024. Natural gas production for the three and six months ended June 30, 2024 from the comparable periods in 2023 reflected the planned drilling program together with natural field declines in 2024, and the impact of wildfires and a third party pipeline outage in 2023.
Annual natural gas production for 2024 is targeted to average between 2,120 MMcf/d and 2,230 MMcf/d. Production targets constitute forward-looking statements. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.
| | | | | | | | |
| Canadian Natural Resources Limited | 9 | Three and six months ended June 30, 2024 |
North America – Exploration and Production
North America crude oil and NGLs production before royalties for the six months ended June 30, 2024 averaged 502,636 bbl/d, an increase of 7% from 471,212 bbl/d for the six months ended June 30, 2023. North America crude oil and NGLs production before royalties for the second quarter of 2024 of 499,636 bbl/d increased 7% from 465,143 bbl/d for the second quarter of 2023 and was comparable with 505,636 bbl/d for the first quarter of 2024. The increase in North America crude oil and NGLs production for the six months ended June 30, 2024 from the comparable period in 2023 primarily reflected pad additions in thermal in situ, partially offset by natural field declines. The increase in North America crude oil and NGLs production for the second quarter of 2024 from the second quarter of 2023 also reflected higher thermal oil production due to the cyclical nature of Primrose, and the impact of wildfires and a third party pipeline outage in the second quarter of 2023, partially offset by the planned turnarounds at Kirby and Jackfish successfully completed in the second quarter of 2024.
The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 268,044 bbl/d for the second quarter of 2024, an increase of 12% from 238,941 bbl/d for the second quarter of 2023, and comparable with 268,155 bbl/d for the first quarter of 2024. The increase in thermal in situ production in the second quarter of 2024 from the second quarter of 2023 primarily reflected higher production due to the cyclical nature of Primrose as well as pad additions, partially offset by the planned turnarounds at Kirby and Jackfish completed in the second quarter of 2024.
Pelican Lake heavy crude oil production before royalties for the second quarter of 2024 averaged 44,839 bbl/d, a decrease of 5% from 47,151 bbl/d for the second quarter of 2023, and comparable with 45,145 bbl/d for the first quarter of 2024, demonstrating Pelican Lake's long life low decline production.
North America natural gas production before royalties for the six months ended June 30, 2024 averaged 2,117 MMcf/d, comparable with 2,100 MMcf/d for the six months ended June 30, 2023. Natural gas production before royalties averaged 2,099 MMcf/d for the second quarter of 2024, comparable with 2,072 MMcf/d for the second quarter of 2023 and 2,135 MMcf/d for the first quarter of 2024. Natural gas production for the three and six months ended June 30, 2024 from the comparable periods in 2023 reflected the planned drilling program together with natural field declines in 2024, and the impact of wildfires and a third party pipeline outage in 2023.
North America – Oil Sands Mining and Upgrading
SCO production before royalties for the six months ended June 30, 2024 averaged 427,863 bbl/d, an increase of 5% from 406,453 bbl/d for the six months ended June 30, 2023. SCO production before royalties for the second quarter of 2024 averaged 410,518 bbl/d, an increase of 16% from 355,246 bbl/d for the second quarter of 2023, and a decrease of 8% from 445,209 bbl/d for the first quarter of 2024. SCO production for the three and six months ended June 30, 2024 reflected the successful completion of the planned turnaround at Horizon in the second quarter of 2024, as well as turnaround activities at both Horizon and Scotford in the second quarter of 2023.
International – Exploration and Production
International crude oil and NGLs production before royalties for the six months ended June 30, 2024 averaged 24,367 bbl/d, a decrease of 9% from 26,923 bbl/d for the six months ended June 30, 2023. International crude oil and NGLs production before royalties for the second quarter of 2024 averaged 23,912 bbl/d, a decrease of 10% from 26,520 bbl/d for the second quarter of 2023, and a decrease of 4% from 24,823 bbl/d for the first quarter of 2024. The decrease in International crude oil and NGLs production for the three and six months ended June 30, 2024 from the comparable periods primarily reflected natural field declines combined with the impact of maintenance activities in both comparable periods.
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 production held in various storage facilities or floating production storage and offloading vessels ("FPSOs"), as follows:
| | | | | | | | | | | |
| (bbl) | Jun 30
2024 | Mar 31
2024 | Jun 30
2023 |
| | | |
| | | |
| International | 1,145,760 | | 833,654 | | 816,475 | |
| | | | | | | | |
| Canadian Natural Resources Limited | 10 | Three and six months ended June 30, 2024 |
OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended |
| | | Jun 30
2024 | | Mar 31
2024 | | Jun 30
2023 | | | Jun 30
2024 | | Jun 30
2023 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
Realized price (2) | | $ | 86.64 | | | $ | 70.01 | | | $ | 72.06 | | | | $ | 78.43 | | | $ | 65.58 | |
Transportation (2) | | 5.98 | | | 4.63 | | | 4.57 | | | | 5.31 | | | 4.54 | |
Realized price, net of transportation (2) | | 80.66 | | | 65.38 | | | 67.49 | | | | 73.12 | | | 61.04 | |
Royalties (3) | | 17.45 | | | 12.09 | | | 11.09 | | | | 14.80 | | | 10.60 | |
Production expense (4) | | 14.54 | | | 16.66 | | | 18.38 | | | | 15.59 | | | 17.67 | |
Netback (2) | | $ | 48.67 | | | $ | 36.63 | | | $ | 38.02 | | | | $ | 42.73 | | | $ | 32.77 | |
Natural gas ($/Mcf) (1) | | | | | | | | | | | |
Realized price (5) | | $ | 1.59 | | | $ | 2.55 | | | $ | 2.53 | | | | $ | 2.07 | | | $ | 3.41 | |
Transportation (6) | | 0.63 | | | 0.64 | | | 0.58 | | | | 0.63 | | | 0.57 | |
| Realized price, net of transportation | | 0.96 | | | 1.91 | | | 1.95 | | | | 1.44 | | | 2.84 | |
Royalties (3) | | 0.02 | | | 0.10 | | | 0.07 | | | | 0.06 | | | 0.17 | |
Production expense (4) | | 1.21 | | | 1.30 | | | 1.37 | | | | 1.26 | | | 1.42 | |
| Netback | | $ | (0.27) | | | $ | 0.51 | | | $ | 0.51 | | | | $ | 0.12 | | | $ | 1.25 | |
Barrels of oil equivalent ($/BOE) (1) | | | | | | | | | | | |
Realized price (2) | | $ | 55.84 | | | $ | 47.60 | | | $ | 48.94 | | | | $ | 51.74 | | | $ | 46.98 | |
Transportation (2) | | 5.09 | | | 4.31 | | | 4.11 | | | | 4.71 | | | 4.08 | |
Realized price, net of transportation (2) | | 50.75 | | | 43.29 | | | 44.83 | | | | 47.03 | | | 42.90 | |
Royalties (3) | | 10.53 | | | 7.39 | | | 6.75 | | | | 8.97 | | | 6.65 | |
Production expense (4) | | 11.64 | | | 13.03 | | | 14.24 | | | | 12.33 | | | 13.88 | |
Netback (2) | | $ | 28.58 | | | $ | 22.87 | | | $ | 23.84 | | | | $ | 25.73 | | | $ | 22.37 | |
(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 six months ended June 30, 2024 |
REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended |
| | | Jun 30
2024 | | Mar 31
2024 | | Jun 30
2023 | | | Jun 30
2024 | | Jun 30
2023 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
North America (2) | | $ | 85.49 | | | $ | 68.14 | | | $ | 69.44 | | | | $ | 76.94 | | | $ | 63.66 | |
International average (3) | | $ | 115.27 | | | $ | 112.94 | | | $ | 103.64 | | | | $ | 114.08 | | | $ | 102.58 | |
North Sea (3) | | $ | 115.02 | | | $ | 113.75 | | | $ | 106.39 | | | | $ | 114.37 | | | $ | 106.39 | |
Offshore Africa (3) | | $ | 115.67 | | | $ | 111.59 | | | $ | 100.68 | | | | $ | 113.59 | | | $ | 99.94 | |
Crude oil and NGLs average (2) | | $ | 86.64 | | | $ | 70.01 | | | $ | 72.06 | | | | $ | 78.43 | | | $ | 65.58 | |
| | | | | | | | | | | |
Natural gas ($/Mcf) (1) (3) | | | | | | | | | | | |
| North America | | $ | 1.53 | | | $ | 2.50 | | | $ | 2.47 | | | | $ | 2.02 | | | $ | 3.35 | |
| International average | | $ | 11.87 | | | $ | 12.13 | | | $ | 13.16 | | | | $ | 12.01 | | | $ | 13.45 | |
| North Sea | | $ | 9.79 | | | $ | 11.48 | | | $ | 9.48 | | | | $ | 10.58 | | | $ | 10.88 | |
| Offshore Africa | | $ | 12.24 | | | $ | 12.22 | | | $ | 13.71 | | | | $ | 12.23 | | | $ | 13.97 | |
| Natural gas average | | $ | 1.59 | | | $ | 2.55 | | | $ | 2.53 | | | | $ | 2.07 | | | $ | 3.41 | |
| | | | | | | | | | | |
Average ($/BOE) (1) (2) | | $ | 55.84 | | | $ | 47.60 | | | $ | 48.94 | | | | $ | 51.74 | | | $ | 46.98 | |
(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 increased 21% to average $76.94 per bbl for the six months ended June 30, 2024 from $63.66 per bbl for the six months ended June 30, 2023. North America realized crude oil and NGLs prices averaged $85.49 per bbl for the second quarter of 2024, an increase of 23% from $69.44 per bbl for the second quarter of 2023, and an increase of 25% from $68.14 per bbl for the first quarter of 2024. The increase for the three and six months ended June 30, 2024 from the comparable periods primarily reflected the narrowing of the WCS Heavy Differential due to the start-up of the TMX pipeline and stronger US Gulf Coast heavy oil pricing. The Company continues to focus on its crude oil blending marketing strategy and in the second quarter of 2024 contributed approximately 222,000 bbl/d of heavy crude oil blends to the WCS stream.
North America realized natural gas prices decreased 40% to average $2.02 per Mcf for the six months ended June 30, 2024 from $3.35 per Mcf for the six months ended June 30, 2023. North America realized natural gas prices decreased 38% to average $1.53 per Mcf for the second quarter of 2024 from $2.47 per Mcf for the second quarter of 2023, and decreased 39% from $2.50 per Mcf for the first quarter of 2024. The decrease in North America realized natural gas prices for the three and six months ended June 30, 2024 from the comparable periods primarily reflected lower AECO benchmark and export pricing.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended |
| (Quarterly average) | | Jun 30
2024 | | Mar 31
2024 | | Jun 30
2023 |
Wellhead Price (1) | | | | | | |
| Light and medium crude oil and NGLs ($/bbl) | | $ | 74.90 | | | $ | 66.68 | | | $ | 68.11 | |
| Pelican Lake heavy crude oil ($/bbl) | | $ | 92.42 | | | $ | 74.69 | | | $ | 76.66 | |
| Primary heavy crude oil ($/bbl) | | $ | 91.27 | | | $ | 74.37 | | | $ | 76.20 | |
| Bitumen (thermal oil) ($/bbl) | | $ | 86.84 | | | $ | 65.83 | | | $ | 66.51 | |
| Natural gas ($/Mcf) | | $ | 1.53 | | | $ | 2.50 | | | $ | 2.47 | |
(1)Amounts expressed on a per unit basis are based on sales volumes of the respective product type.
| | | | | | | | |
| Canadian Natural Resources Limited | 12 | Three and six months ended June 30, 2024 |
International
International realized crude oil and NGLs prices increased 11% to average $114.08 per bbl for the six months ended June 30, 2024 from $102.58 per bbl for the six months ended June 30, 2023. International realized crude oil and NGLs prices increased 11% to average $115.27 per bbl for the second quarter of 2024 from $103.64 per bbl for the second quarter of 2023, and was comparable with $112.94 per bbl for the first quarter of 2024. Realized crude oil and NGLs prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The increase in realized crude oil and NGLs prices for the three and six months ended June 30, 2024 from the comparable periods in 2023 primarily reflected prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.
ROYALTIES – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended |
| | | Jun 30
2024 | | Mar 31
2024 | | Jun 30
2023 | | | Jun 30
2024 | | Jun 30
2023 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
| North America | | $ | 18.06 | | | $ | 12.52 | | | $ | 11.56 | | | | $ | 15.33 | | | $ | 10.83 | |
| International average | | $ | 2.11 | | | $ | 2.29 | | | $ | 5.38 | | | | $ | 2.20 | | | $ | 6.24 | |
| North Sea | | $ | 0.24 | | | $ | 0.24 | | | $ | 0.36 | | | | $ | 0.24 | | | $ | 0.36 | |
| Offshore Africa | | $ | 5.14 | | | $ | 5.72 | | | $ | 10.77 | | | | $ | 5.43 | | | $ | 10.30 | |
| Crude oil and NGLs average | | $ | 17.45 | | | $ | 12.09 | | | $ | 11.09 | | | | $ | 14.80 | | | $ | 10.60 | |
| | | | | | | | | | | |
Natural gas ($/Mcf) (1) | | | | | | | | | | | |
| North America | | $ | 0.02 | | | $ | 0.10 | | | $ | 0.07 | | | | $ | 0.06 | | | $ | 0.17 | |
| Offshore Africa | | $ | 0.56 | | | $ | 0.56 | | | $ | 0.65 | | | | $ | 0.56 | | | $ | 0.67 | |
| Natural gas average | | $ | 0.02 | | | $ | 0.10 | | | $ | 0.07 | | | | $ | 0.06 | | | $ | 0.17 | |
| | | | | | | | | | | |
Average ($/BOE) (1) | | $ | 10.53 | | | $ | 7.39 | | | $ | 6.75 | | | | $ | 8.97 | | | $ | 6.65 | |
(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 six months ended June 30, 2024 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 20% of product sales for the six months ended June 30, 2024 compared with 17% of product sales for the six months ended June 30, 2023. Crude oil and NGLs royalty rates averaged approximately 21% of product sales for the second quarter of 2024 compared with 17% for the second quarter of 2023, and 18% for the first quarter of 2024. The increase in royalty rates for the three and six months ended June 30, 2024 from the comparable periods was primarily due to prevailing benchmark pricing and fluctuations in the WCS differential.
Natural gas royalty rates averaged approximately 3% of product sales for the six months ended June 30, 2024 compared with 5% of product sales for the six months ended June 30, 2023. Natural gas royalty rates averaged approximately 1% of product sales for the second quarter of 2024 compared with 3% for the second quarter of 2023, and 4% for the first quarter of 2024. The decrease in royalty rates for the three and six months ended June 30, 2024 from the comparable periods was primarily due to lower benchmark prices.
(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 six months ended June 30, 2024 |
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 5% for the six months ended June 30, 2024 compared with 10% of product sales for the six months ended June 30, 2023. Royalty rates as a percentage of product sales averaged approximately 4% for the second quarter of 2024 compared with 10% of product sales for the second quarter of 2023, and 5% for the first quarter of 2024. 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 | | | Six Months Ended |
| | | Jun 30
2024 | | Mar 31
2024 | | Jun 30
2023 | | | Jun 30
2024 | | Jun 30
2023 |
Crude oil and NGLs ($/bbl) (1) | | | | | | | | | | | |
| North America | | $ | 12.44 | | | $ | 14.72 | | | $ | 15.64 | | | | $ | 13.56 | | | $ | 16.23 | |
| International average | | $ | 66.83 | | | $ | 61.32 | | | $ | 51.50 | | | | $ | 64.00 | | | $ | 45.27 | |
| North Sea | | $ | 96.07 | | | $ | 85.58 | | | $ | 81.32 | | | | $ | 90.67 | | | $ | 81.32 | |
| Offshore Africa | | $ | 19.28 | | | $ | 20.70 | | | $ | 19.44 | | | | $ | 20.00 | | | $ | 20.32 | |
| Crude oil and NGLs average | | $ | 14.54 | | | $ | 16.66 | | | $ | 18.38 | | | | $ | 15.59 | | | $ | 17.67 | |
| | | | | | | | | | | |
Natural gas ($/Mcf) (1) | | | | | | | | | | | |
| North America | | $ | 1.19 | | | $ | 1.27 | | | $ | 1.35 | | | | $ | 1.23 | | | $ | 1.39 | |
| International average | | $ | 6.51 | | | $ | 5.71 | | | $ | 4.83 | | | | $ | 6.08 | | | $ | 6.39 | |
| North Sea | | $ | 7.72 | | | $ | 8.66 | | | $ | 9.17 | | | | $ | 8.16 | | | $ | 10.15 | |
| Offshore Africa | | $ | 6.30 | | | $ | 5.33 | | | $ | 4.17 | | | | $ | 5.77 | | | $ | 5.63 | |
| Natural gas average | | $ | 1.21 | | | $ | 1.30 | | | $ | 1.37 | | | | $ | 1.26 | | | $ | 1.42 | |
| | | | | | | | | | | |
Average ($/BOE) (1) | | $ | 11.64 | | | $ | 13.03 | | | $ | 14.24 | | | | $ | 12.33 | | | $ | 13.88 | |
(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 six months ended June 30, 2024 averaged $13.56 per bbl, a decrease of 16% from $16.23 per bbl for the six months ended June 30, 2023. North America crude oil and NGLs production expense for the second quarter of 2024 of $12.44 per bbl decreased 20% from $15.64 per bbl for the second quarter of 2023, and decreased 15% from $14.72 per bbl for the first quarter of 2024. The decrease in crude oil and NGLs production expense per bbl for the three and six months ended June 30, 2024 from the comparable periods in 2023 primarily reflected lower energy costs combined with higher production volumes. The decrease in crude oil and NGLs production expense per bbl for the second quarter of 2024 from the first quarter of 2024 primarily reflected lower energy costs.
North America natural gas production expense for the six months ended June 30, 2024 averaged $1.23 per Mcf, a decrease of 12% from $1.39 per Mcf for the six months ended June 30, 2023. North America natural gas production expense for the second quarter of 2024 of $1.19 per Mcf decreased 12% from $1.35 per Mcf for the second quarter of 2023 and decreased 6% from $1.27 per Mcf for the first quarter of 2024. The decrease in natural gas production expense per Mcf for the three and six months ended June 30, 2024 from the comparable periods in 2023 primarily reflected lower energy costs. The decrease for the second quarter of 2024 from the first quarter of 2024 primarily reflected the impact of seasonality.
| | | | | | | | |
| Canadian Natural Resources Limited | 14 | Three and six months ended June 30, 2024 |
International
International crude oil and NGLs production expense for the six months ended June 30, 2024 averaged $64.00 per bbl, an increase of 41% from $45.27 per bbl for the six months ended June 30, 2023. International crude oil and NGLs production expense for the second quarter of 2024 of $66.83 per bbl increased 30% from $51.50 per bbl for the second quarter of 2023 and increased 9% from $61.32 per bbl for the first quarter of 2024. The increase in international crude oil and NGLs production expense per bbl for the three and six months ended June 30, 2024 from the comparable periods primarily reflected the timing of liftings from various fields that have different cost structures and fluctuations in foreign currency.
ADJUSTED DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended |
| ($ millions, except per BOE amounts) | | Jun 30
2024 | | Mar 31
2024 | | Jun 30
2023 | | | Jun 30
2024 | | Jun 30
2023 |
| North America | | $ | 956 | | | $ | 941 | | | $ | 871 | | | | $ | 1,897 | | | $ | 1,761 | |
| North Sea | | 24 | | | 17 | | | 15 | | | | 41 | | | 16 | |
| Offshore Africa | | 108 | | | 47 | | | 65 | | | | 155 | | | 100 | |
| Depletion, depreciation and amortization | | $ | 1,088 | | | $ | 1,005 | | | $ | 951 | | | | $ | 2,093 | | | $ | 1,877 | |
Less: Recoverability charge (1) | | 62 | | | — | | | — | | | | 62 | | | — | |
Adjusted depletion, depreciation and amortization (2) | | $ | 1,026 | | | $ | 1,005 | | | $ | 951 | | | | $ | 2,031 | | | $ | 1,877 | |
$/BOE (3) | | $ | 12.77 | | | $ | 12.64 | | | $ | 12.26 | | | | $ | 12.71 | | | $ | 12.20 | |
(1)In connection with the Company’s notice of withdrawal from Block 11B/12B in South Africa in the second quarter of 2024, the Company derecognized $62 million of exploration and evaluation assets through depletion, depreciation and amortization expense.
(2)This is a non-GAAP financial measure used to calculate depletion, depreciation and amortization, less the impact of charges that are not related to current period normal course depletion, depreciation and amortization expense such as asset recoverability charges that are not related to current period production. It 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 financial statements (depletion, depreciation and amortization expense), as an indication of the Company's performance.
(3)This is a non-GAAP ratio calculated as adjusted depletion, depreciation and amortization expense divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
Adjusted depletion, depreciation and amortization expense for the six months ended June 30, 2024 averaged $12.71 per BOE, an increase of 4% from $12.20 per BOE for the six months ended June 30, 2023. Adjusted depletion, depreciation and amortization expense for the second quarter of 2024 averaged $12.77 per BOE, an increase of 4% from $12.26 per BOE for the second quarter of 2023, and comparable with $12.64 per BOE for the first quarter of 2024. The increase in adjusted depletion, depreciation and amortization expense for the three and six months ended June 30, 2024 from the comparable periods in 2023 primarily reflected the impact of changes in North America depletion rates due to changes in reserve estimates at December 31, 2023.
Adjusted depletion, depreciation and amortization expense on an absolute and per BOE basis also reflects the impact of the timing of liftings from each field in the North Sea and Offshore Africa.
ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Six Months Ended |
| ($ millions, except per BOE amounts) | | Jun 30
2024 | | Mar 31
2024 | | Jun 30
2023 | | | Jun 30
2024 | | Jun 30
2023 |
| North America | | $ | 57 | | | $ | 58 | | | $ | 58 | | | | $ | 115 | | | $ | 117 | |
| North Sea | | 16 | | | 16 | | | 12 | | | | 32 | | | 23 | |
| Offshore Africa | | 2 | | | 2 | | | 2 | | | | 4 |