加拿大自然資源有限公司
管理層討論與分析 2024年9月30日結束的三個月和九個月 | ||
| 2024年10月30日 | ||
管理層討論和分析
注意事項
關於前瞻性聲明的特別說明
本文件中涉及加拿大自然資源有限公司（以下簡稱「公司」）的某些聲明構成前瞻性聲明或信息（統稱爲「前瞻性聲明」），依據適用證券立法。前瞻性聲明可通過「相信」、「預計」、「期待」、「計劃」、「估計」、「目標」、「關注」、「持續」、「可能」、「打算」、“或表達類似未來結果的詞語或對展望的描述，「目標」、「項目」、「預測」、「目標」、「指導」、「前景」、「努力」、「尋求」、「計劃」、「願景」等表達方式進行識別。揭示公司的策略或戰略重點、資本預算、預期未來商品定價、預測或預期生產量、特許權、生產成本、資本支出、棄置支出、所得稅支出以及本管理層討論和分析中提供的其他目標，包括公司財務狀況和業務結果的管理討論和分析（「MD&A」），包括公司資產負債表的強勁之處、公司流動性來源和充裕性，以及公司資本結構的靈活性，構成前瞻性聲明。有關協議以從雪佛龍加拿大有限公司或其附屬公司（統稱爲「雪佛龍」）處收購阿薩巴斯卡油砂項目（「AOSP」）20%權益、杜溫奈資產玩耍的70%運營權益以及其他一些非生產中的油砂租賃項目的更多權益的披露，以下簡稱「從雪佛龍收購資產協議」，包括預期的結束，包括此類收購對公司債務佔資本比率的影響，以及相關計劃和現有和未來發展的預期結果，包括但不限於以下內容： 好地方油砂項目（「地平線」）的公司資產，AOSP，普林鮑絲熱油項目（「普林鮑絲」），鵜鶘湖水和聚合物泛洪項目（「鵜鶘湖」），卡比熱油砂項目（「卡比」），傑克菲什熱油砂項目（「傑克菲什」）以及西北煤油精製工廠和煉油廠；第三方新建或擴建管道容量或其他運輸比特、原油、天然氣、天然氣液體（「NGL」）或合成原油（「SCO」）的施工，公司可能依賴這些來運輸其產品到市場；某些資產的棄置和退役以及其時間表；技術和技術創新的開發和部署；公司完成其增長項目的財政能力和負責任和可持續發展長期增長的重要性；以及對財務解釋和訴訟對公司業績的影響的重要性，也構成前瞻性聲明。這些前瞻性聲明基於年度預算和多年預測，並會根據年度預算和多年預測進行審查和修訂，以使其與目標的財務比率、項目回報率、產品定價預期和項目風險平衡以及時間段保持一致。這些聲明不是未來業績的保證，並且受到一定風險的影響。讀者不應過分依賴這些前瞻性聲明，因爲不能保證其基於的計劃、倡議或期望會發生。此外，與「儲量」有關的聲明被視爲前瞻性聲明，因爲它們涉及根據某些估計和假設進行的暗示評估，即所述儲量未來可以有益地生產。在估計已探明和已探明加上概率的原油、天然氣和NGL儲量以及預測未來生產率和開發支出方面存在許多不確定性。實際未來生產的數量或時間可能與儲量和生產估計大不相同。
前瞻性聲明基於對公司和公司所屬行業的當前期望、估計和預測，僅代表此類聲明或在該報告或文件中包含的日期可能製作的日期，並受已知和未知風險和不確定因素的影響，可能導致公司的實際結果、業績或成就與此類前瞻性聲明所暗示或表述的任何未來結果、業績或成就實質上不同。此類風險和不確定因素包括但不限於：一般經濟和業務狀況（包括由於石油輸出國家組織及其它國家的行動、中東衝突、俄羅斯入侵烏克蘭、通脹增加以及全球經濟衰退可能導致的經濟活動減少風險），這些可能影響公司產品的需求和供應以及市場價格，以及公司業務所需資源的可用性和成本；原油、天然氣和液化石油氣價格的波動和假設；貨幣和利率的波動；公司目前目標的假設基礎；公司經營的國家和地區的經濟狀況；政治不確定性，包括針對恐怖分子、叛亂團體或其他衝突（包括國家間衝突）的行動；公司防範和從網絡攻擊、其他網絡犯罪和其他網絡事件中恢復的能力；行業能力；公司實施業務策略的能力，包括勘探和開發活動；競爭的影響；公司對訴訟的抗辯；地震、鑽井和其他設備的可用性和成本；公司完成資本計劃的能力；公司爲其產品獲得足夠運輸的能力；礦產品的挖掘、提取或升級過程中的意外中斷或延遲；勘探或開發項目以及資本支出方面的潛在延遲或計劃更改的影響；公司吸引所需的勞動力來建設、維護和運營其熱力和油砂礦項目的能力；勘探和生產原油和天然氣以及挖掘、提取或升級公司石油產品所固有的操作風險和其他困難的困難；融資的可用性和成本；公司勘探和開發活動的成功以及替代和擴大原油和天然氣儲量的能力；公司實現目標生產水平的能力；收購公司和資產的業務和運營整合的時機和成功，包括從雪佛龍收購資產的協議；生產水平；儲量估計的不準確和目前未被分類爲證明的原油、天然氣和液化石油氣可回收數量的估計；政府機構的行動；政府法規及遵守這些法規所需的支出（特別是安全、競爭、環境法規，以及氣候變化舉措對資本支出和生產成本的影響）的解釋；適用稅法和競爭法律法規的解釋；資產退休義務；公司的流動性是否足夠以支持其增長戰略並在短期、中期和長期維持其運營；公司資產負債表的強度；公司資本結構的靈活性；公司提供稅款的充足性；公司所涉及的法律訴訟的影響；以及影響收入和支出的其他情況。
| Canadian Natural Resources Limited | 1 | Three and nine months ended September 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 nine months ended September 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 nine months ended September 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. Further, results from operations for the three and nine months ended September 30, 2024 and all guidance amounts presented in this MD&A exclude the impact of the agreement to acquire assets from Chevron.
The following discussion and analysis refers primarily to the Company's financial results for the three and nine months ended September 30, 2024 in relation to the comparable periods in 2023 and the second 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 in such Annual Information Form and 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 October 30, 2024.
| Canadian Natural Resources Limited | 2 | Three and nine months ended September 30, 2024 | ||||||
FINANCIAL HIGHLIGHTS(1)
| Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||||||||
| ($ millions, except per common share amounts) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | |||||||||||||||||||||||||||||||||
Product sales (1) | $ | 10,401 | $ | 10,622 | $ | 11,762 | $ | 30,445 | $ | 30,156 | ||||||||||||||||||||||||||||
| Crude oil and NGLs | $ | 9,943 | $ | 10,084 | $ | 10,944 | $ | 28,703 | $ | 27,471 | ||||||||||||||||||||||||||||
| Natural gas | $ | 257 | $ | 331 | $ | 599 | $ | 1,117 | $ | 1,972 | ||||||||||||||||||||||||||||
| Net earnings | $ | 2,266 | $ | 1,715 | $ | 2,344 | $ | 4,968 | $ | 5,606 | ||||||||||||||||||||||||||||
| Per common share | – basic | $ | 1.07 | $ | 0.80 | $ | 1.08 | $ | 2.33 | $ | 2.56 | |||||||||||||||||||||||||||
| – diluted | $ | 1.06 | $ | 0.80 | $ | 1.06 | $ | 2.31 | $ | 2.53 | ||||||||||||||||||||||||||||
Adjusted net earnings from operations (2) | $ | 2,071 | $ | 1,892 | $ | 2,850 | $ | 5,437 | $ | 5,987 | ||||||||||||||||||||||||||||
| Per common share | – basic (3) | $ | 0.98 | $ | 0.89 | $ | 1.31 | $ | 2.55 | $ | 2.73 | |||||||||||||||||||||||||||
– diluted (3) | $ | 0.97 | $ | 0.88 | $ | 1.30 | $ | 2.53 | $ | 2.71 | ||||||||||||||||||||||||||||
| Cash flows from operating activities | $ | 3,002 | $ | 4,084 | $ | 3,498 | $ | 9,954 | $ | 7,538 | ||||||||||||||||||||||||||||
Adjusted funds flow (2) | $ | 3,921 | $ | 3,614 | $ | 4,684 | $ | 10,673 | $ | 10,855 | ||||||||||||||||||||||||||||
| Per common share | – basic (3) | $ | 1.85 | $ | 1.69 | $ | 2.15 | $ | 5.01 | $ | 4.96 | |||||||||||||||||||||||||||
– diluted (3) | $ | 1.84 | $ | 1.68 | $ | 2.13 | $ | 4.97 | $ | 4.91 | ||||||||||||||||||||||||||||
| Cash flows used in investing activities | $ | 1,274 | $ | 1,015 | $ | 1,199 | $ | 3,681 | $ | 3,912 | ||||||||||||||||||||||||||||
Net capital expenditures (4) | $ | 1,349 | $ | 1,621 | $ | 1,108 | $ | 4,083 | $ | 3,934 | ||||||||||||||||||||||||||||
| Abandonment expenditures | $ | 204 | $ | 129 | $ | 123 | $ | 495 | $ | 360 | ||||||||||||||||||||||||||||
(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 nine months ended September 30, 2024 were $4,968 million compared with $5,606 million for the nine months ended September 30, 2023. Net earnings for the nine months ended September 30, 2024 included non-operating losses, net of tax, of $469 million compared with non-operating losses of $381 million for the nine months ended September 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 investment, 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 nine months ended September 30, 2024 were $5,437 million compared with $5,987 million for the nine months ended September 30, 2023.
Net earnings for the third quarter of 2024 were $2,266 million compared with $2,344 million for the third quarter of 2023 and $1,715 million for the second quarter of 2024. Net earnings for the third quarter of 2024 included non-operating income, net of tax, of $195 million compared with non-operating losses of $506 million for the third quarter of 2023 and non-operating losses of $177 million for the second 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 third quarter of 2024 were $2,071 million compared with $2,850 million for the third quarter of 2023 and $1,892 million for the second 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.
| Canadian Natural Resources Limited | 3 | Three and nine months ended September 30, 2024 | ||||||
The decrease in net earnings and adjusted net earnings from operations for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 primarily reflected:
▪lower natural gas pricing in the North America Exploration and Production segment;
partially offset by:
▪higher SCO sales volumes in the Oil Sands Mining and Upgrading segment; and
▪higher crude oil and NGLs sales volumes and netbacks(1) in the North America Exploration and Production segment.
The decrease in net earnings and adjusted net earnings from operations for the third quarter of 2024 from the third quarter of 2023 primarily reflected:
▪lower crude oil and NGLs sales volumes and netbacks in the North America Exploration and Production segment;
▪lower natural gas pricing in the North America Exploration and Production segment; and
▪lower realized SCO pricing(1) in the Oil Sands Mining and Upgrading segment.
The increase in net earnings and adjusted net earnings from operations for the third quarter of 2024 from the second quarter of 2024 primarily reflected:
▪higher SCO sales volumes in the Oil Sands Mining and Upgrading segment;
partially offset by:
▪lower crude oil and NGLs sales volumes and netbacks in the North America Exploration and Production segment; and
▪lower realized SCO pricing in the Oil Sands Mining and Upgrading segment.
The impacts of depletion, depreciation and amortization, share-based compensation, risk management activities, foreign exchange (gain) loss, 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 nine months ended September 30, 2024 were $9,954 million compared with $7,538 million for the nine months ended September 30, 2023. Cash flows from operating activities for the third quarter of 2024 were $3,002 million compared with $3,498 million for the third quarter of 2023 and $4,084 million for the second quarter of 2024. The fluctuations in cash flows from operating activities from the comparable periods was primarily due to the factors previously noted related to the fluctuations in adjusted net earnings from operations, together with the impact of net changes in non-cash working capital.
Adjusted funds flow for the nine months ended September 30, 2024 was $10,673 million compared with $10,855 million for the nine months ended September 30, 2023. Adjusted funds flow for the third quarter of 2024 was $3,921 million compared with $4,684 million for the third quarter of 2023 and $3,614 million for the second quarter of 2024. The fluctuations 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 third quarter of 2024 of 1,021,572 bbl/d was comparable with 1,035,153 bbl/d for the third quarter of 2023 and increased 9% from 934,066 bbl/d for the second quarter of 2024. Natural gas production before royalties for the third quarter of 2024 of 2,049 MMcf/d decreased 5% from 2,151 MMcf/d for the third quarter of 2023 and decreased 3% from 2,110 MMcf/d for the second quarter of 2024. Total production before royalties for the third quarter of 2024 of 1,363,086 BOE/d was comparable with 1,393,614 BOE/d for the third quarter of 2023 and increased 6% from 1,285,798 BOE/d for the second 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.
| Canadian Natural Resources Limited | 4 | Three and nine months ended September 30, 2024 | ||||||
Product Prices
In the Company's Exploration and Production segments, realized crude oil and NGLs prices(1) averaged $79.15 per bbl for the third quarter of 2024, a decrease of 10% from $87.83 per bbl for the third quarter of 2023, and a decrease of 9% from $86.64 per bbl for the second quarter of 2024. The realized natural gas price decreased 56% to average $1.25 per Mcf for the third quarter of 2024 from $2.81 per Mcf for the third quarter of 2023 and decreased 21% from $1.59 per Mcf for the second quarter of 2024. In the Oil Sands Mining and Upgrading segment, the Company's realized SCO sales price decreased 7% to average $100.93 per bbl for the third quarter of 2024 from $108.55 per bbl for the third quarter of 2023 and decreased 7% from $108.81 per bbl for the second 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 $14.65 per bbl for the third quarter of 2024, comparable with $14.40 per bbl for the third quarter of 2023 and $14.54 per bbl for the second quarter of 2024. Natural gas production expense(2) averaged $1.26 per Mcf for the third quarter of 2024, comparable with $1.25 per Mcf for the third quarter of 2023, and an increase of 4% from $1.21 per Mcf for the second quarter of 2024. In the Oil Sands Mining and Upgrading segment, production expense(2) averaged $20.67 per bbl for the third quarter of 2024, a decrease of 7% from $22.12 per bbl for the third quarter of 2023, and a decrease of 20% from $25.95 per bbl for the second quarter of 2024. Crude oil and NGLs and natural gas production expense is discussed in detail in the "Production Expense – Exploration and Production" and the "Oil Sands Mining and Upgrading" sections of this MD&A.
SUMMARY OF QUARTERLY FINANCIAL RESULTS
The following is a summary of the Company's quarterly financial results for the eight most recently completed quarters:
| ($ millions, except per common share amounts) | Sep 30 2024 | Jun 30 2024 | Mar 31 2024 | Dec 31 2023 | ||||||||||||||||||||||
Product sales (1) | $ | 10,401 | $ | 10,622 | $ | 9,422 | $ | 10,679 | ||||||||||||||||||
| Crude oil and NGLs | $ | 9,943 | $ | 10,084 | $ | 8,676 | $ | 9,829 | ||||||||||||||||||
| Natural gas | $ | 257 | $ | 331 | $ | 529 | $ | 603 | ||||||||||||||||||
| Net earnings | $ | 2,266 | $ | 1,715 | $ | 987 | $ | 2,627 | ||||||||||||||||||
Net earnings per common share (2) | ||||||||||||||||||||||||||
| – basic | $ | 1.07 | $ | 0.80 | $ | 0.46 | $ | 1.22 | ||||||||||||||||||
| – diluted | $ | 1.06 | $ | 0.80 | $ | 0.46 | $ | 1.21 | ||||||||||||||||||
| ($ millions, except per common share amounts) | Sep 30 2023 | Jun 30 2023 | Mar 31 2023 | Dec 31 2022 | ||||||||||||||||||||||
Product sales (1) | $ | 11,762 | $ | 8,846 | $ | 9,548 | $ | 11,012 | ||||||||||||||||||
| Crude oil and NGLs | $ | 10,944 | $ | 8,115 | $ | 8,412 | $ | 9,508 | ||||||||||||||||||
| Natural gas | $ | 599 | $ | 522 | $ | 851 | $ | 1,287 | ||||||||||||||||||
| Net earnings | $ | 2,344 | $ | 1,463 | $ | 1,799 | $ | 1,520 | ||||||||||||||||||
Net earnings per common share (2) | ||||||||||||||||||||||||||
| – basic | $ | 1.08 | $ | 0.67 | $ | 0.82 | $ | 0.69 | ||||||||||||||||||
| – diluted | $ | 1.06 | $ | 0.66 | $ | 0.81 | $ | 0.68 | ||||||||||||||||||
(1)Further details related to product sales for the three months ended September 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.
| Canadian Natural Resources Limited | 5 | Three and nine months ended September 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 Kirby and Jackfish, fluctuations in production due to the cyclic nature of Primrose, 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 at June 30, 2024 relating 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.
▪Loss (gain) from investment – Fluctuations due to the loss (gain) from the Company's investment in PrairieSky Royalty Ltd. shares.
| Canadian Natural Resources Limited | 6 | Three and nine months ended September 30, 2024 | ||||||
BUSINESS ENVIRONMENT
Global crude oil benchmark pricing declined in the third quarter of 2024 as a result of weaker global demand growth. Additionally, supply quota management by OPEC+ and geopolitical tensions in the Middle East led to continued volatility in pricing. The start-up of the TMX pipeline in the second quarter of 2024 contributed to a narrowing of the WCS differential with benefit to the Company's realized product pricing in 2024. Natural gas prices continued to decline as a result of high storage levels in 2024. Although inflationary pressures are easing, the Company has experienced and may continue to experience inflationary pressures on its operating and capital expenditures in addition to higher than normal fluctuations in commodity prices and interest rates.
Liquidity
As at September 30, 2024, the Company had undrawn revolving bank credit facilities of $5,450 million. Including cash and cash equivalents, the Company had approximately $6,171 million in liquidity(1). The Company also has certain other dedicated credit facilities supporting letters of credit.
The Company remains committed to maintaining a strong balance sheet, adequate available liquidity, and a flexible capital structure. Refer to the "Liquidity and Capital Resources" section of this MD&A for further details.
Benchmark Commodity Prices
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
(Average for the period) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| WTI benchmark price (US$/bbl) | $ | 75.16 | $ | 80.55 | $ | 82.18 | $ | 77.55 | $ | 77.37 | |||||||||||||||||||||||||
| Dated Brent benchmark price (US$/bbl) | $ | 80.25 | $ | 84.90 | $ | 86.68 | $ | 82.78 | $ | 82.11 | |||||||||||||||||||||||||
| WCS Heavy Differential from WTI (US$/bbl) | $ | 13.51 | $ | 13.54 | $ | 12.86 | $ | 15.46 | $ | 17.51 | |||||||||||||||||||||||||
SCO price (US$/bbl) | $ | 76.51 | $ | 83.33 | $ | 84.99 | $ | 76.42 | $ | 79.97 | |||||||||||||||||||||||||
| Condensate benchmark price (US$/bbl) | $ | 71.24 | $ | 77.11 | $ | 77.91 | $ | 73.71 | $ | 76.66 | |||||||||||||||||||||||||
| NYMEX benchmark price (US$/MMBtu) | $ | 2.16 | $ | 1.89 | $ | 2.55 | $ | 2.10 | $ | 2.69 | |||||||||||||||||||||||||
| AECO benchmark price (C$/GJ) | $ | 0.77 | $ | 1.36 | $ | 2.26 | $ | 1.35 | $ | 2.86 | |||||||||||||||||||||||||
US/Canadian dollar average exchange rate (US$) | $ | 0.7332 | $ | 0.7308 | $ | 0.7456 | $ | 0.7351 | $ | 0.7432 | |||||||||||||||||||||||||
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$77.55 per bbl for the nine months ended September 30, 2024, comparable with US$77.37 per bbl for the nine months ended September 30, 2023. WTI averaged US$75.16 per bbl for the third quarter of 2024, a decrease of 9% from US$82.18 per bbl for the third quarter of 2023, and a decrease of 7% from US$80.55 per bbl for the second 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$82.78 per bbl for the nine months ended September 30, 2024, comparable with US$82.11 per bbl for the nine months ended September 30, 2023. Brent averaged US$80.25 per bbl for the third quarter of 2024, a decrease of 7% from US$86.68 per bbl for the third quarter of 2023, and a decrease of 5% from US$84.90 per bbl for the second quarter of 2024.
The decrease in WTI and Brent benchmark pricing for the third quarter of 2024 from the comparable periods primarily reflected weaker global demand growth. Additionally, supply quota management by OPEC+, and geopolitical tensions in the Middle East led to continued volatility in the third quarter of 2024.
(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
| Canadian Natural Resources Limited | 7 | Three and nine months ended September 30, 2024 | ||||||
The WCS Heavy Differential averaged US$15.46 per bbl for the nine months ended September 30, 2024, compared with US$17.51 per bbl for the nine months ended September 30, 2023. The WCS Heavy Differential averaged US$13.51 per bbl for the third quarter of 2024, compared with US$12.86 per bbl for the third quarter of 2023, and US$13.54 per bbl for the second quarter of 2024. The narrowing of the WCS Heavy Differential for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 primarily reflected the start-up of the TMX pipeline in the second quarter of 2024, combined with stronger US Gulf Coast heavy oil pricing. The widening of the WCS Heavy Differential for the third quarter of 2024 from the third quarter of 2023 primarily reflected planned and unplanned refinery outages in the US Midwest as well as weakening US Gulf Coast heavy oil pricing.
The SCO price averaged US$76.42 per bbl for the nine months ended September 30, 2024, a decrease of 4% from US$79.97 per bbl for the nine months ended September 30, 2023. The SCO price averaged US$76.51 per bbl for the third quarter of 2024, a decrease of 10% from US$84.99 per bbl for the third quarter of 2023, and a decrease of 8% from US$83.33 per bbl for the second quarter of 2024. The decrease in SCO pricing for the three and nine months ended September 30, 2024 from the comparable periods primarily reflected WTI benchmark pricing and weaker diesel pricing.
NYMEX natural gas prices averaged US$2.10 per MMBtu for the nine months ended September 30, 2024, a decrease of 22% from US$2.69 per MMBtu for the nine months ended September 30, 2023. NYMEX natural gas prices averaged US$2.16 per MMBtu for the third quarter of 2024, a decrease of 15% from US$2.55 per MMBtu for the third quarter of 2023, and an increase of 14% from US$1.89 per MMBtu for the second quarter of 2024. The decrease in NYMEX natural gas prices for the three and nine months ended September 30, 2024 from the comparable periods in 2023 primarily reflected high North American and European inventory levels following mild winter weather in 2024. The increase in NYMEX natural gas pricing for the third quarter of 2024 from the second quarter of 2024 reflected seasonal demand factors with warm third quarter temperatures and lower US production levels.
AECO natural gas prices averaged $1.35 per GJ for the nine months ended September 30, 2024, a decrease of 53% from $2.86 per GJ for the nine months ended September 30, 2023. AECO natural gas prices averaged $0.77 per GJ for the third quarter of 2024, a decrease of 66% from $2.26 per GJ for the third quarter of 2023, and a decrease of 43% from $1.36 per GJ for the second quarter of 2024. The decrease in AECO natural gas prices for the three and nine months ended September 30, 2024 from the comparable periods in 2023 reflected NYMEX benchmark pricing, combined with high storage inventories resulting from weaker demand and increased production levels in the Western Canadian Sedimentary Basin. Similarly, the decrease for the third quarter of 2024 from the second quarter of 2024 primarily reflected high inventory levels resulting from weaker seasonal demand.
| Canadian Natural Resources Limited | 8 | Three and nine months ended September 30, 2024 | ||||||
DAILY PRODUCTION, before royalties
| Three Months Ended | Nine Months Ended | ||||||||||||||||
| Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | |||||||||||||
Crude oil and NGLs (bbl/d) | |||||||||||||||||
| North America – Exploration and Production | 499,772 | 499,636 | 519,581 | 501,674 | 487,512 | ||||||||||||
North America – Oil Sands Mining and Upgrading (1) | 497,656 | 410,518 | 490,853 | 451,298 | 434,895 | ||||||||||||
| International – Exploration and Production | |||||||||||||||||
| North Sea | 10,958 | 11,295 | 12,016 | 11,560 | 12,647 | ||||||||||||
| Offshore Africa | 13,186 | 12,617 | 12,703 | 12,733 | 13,533 | ||||||||||||
Total International (2) | 24,144 | 23,912 | 24,719 | 24,293 | 26,180 | ||||||||||||
| Total Crude oil and NGLs | 1,021,572 | 934,066 | 1,035,153 | 977,265 | 948,587 | ||||||||||||
Natural gas (MMcf/d) (3) | |||||||||||||||||
| North America | 2,039 | 2,099 | 2,139 | 2,091 | 2,113 | ||||||||||||
| International | |||||||||||||||||
| North Sea | 1 | 2 | 1 | 1 | 2 | ||||||||||||
| Offshore Africa | 9 | 9 | 11 | 10 | 10 | ||||||||||||
| Total International | 10 | 11 | 12 | 11 | 12 | ||||||||||||
| Total Natural gas | 2,049 | 2,110 | 2,151 | 2,102 | 2,125 | ||||||||||||
| Total Barrels of oil equivalent (BOE/d) | 1,363,086 | 1,285,798 | 1,393,614 | 1,327,593 | 1,302,715 | ||||||||||||
| Product mix | |||||||||||||||||
Light and medium crude oil and NGLs | 9% | 10% | 10% | 10% | 10% | ||||||||||||
| Pelican Lake heavy crude oil | 3% | 4% | 3% | 3% | 4% | ||||||||||||
| Primary heavy crude oil | 6% | 6% | 5% | 6% | 6% | ||||||||||||
| Bitumen (thermal oil) | 20% | 21% | 21% | 20% | 20% | ||||||||||||
Synthetic crude oil (1) | 37% | 32% | 35% | 34% | 33% | ||||||||||||
| Natural gas | 25% | 27% | 26% | 27% | 27% | ||||||||||||
Percentage of product sales (1) (4) (5) | |||||||||||||||||
| Crude oil and NGLs | 97% | 97% | 95% | 96% | 93% | ||||||||||||
| Natural gas | 3% | 3% | 5% | 4% | 7% | ||||||||||||
(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 | 9 | Three and nine months ended September 30, 2024 | ||||||
DAILY PRODUCTION, net of royalties
| Three Months Ended | Nine Months Ended | ||||||||||||||||
| Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | |||||||||||||
Crude oil and NGLs (bbl/d) | |||||||||||||||||
| North America – Exploration and Production | 399,397 | 394,025 | 409,479 | 402,381 | 398,258 | ||||||||||||
North America – Oil Sands Mining and Upgrading (1) | 408,120 | 332,272 | 387,407 | 370,547 | 366,606 | ||||||||||||
| International – Exploration and Production | |||||||||||||||||
| North Sea | 10,925 | 11,270 | 11,968 | 11,531 | 12,616 | ||||||||||||
| Offshore Africa | 12,496 | 12,057 | 11,746 | 12,104 | 12,273 | ||||||||||||
| Total International | 23,421 | 23,327 | 23,714 | 23,635 | 24,889 | ||||||||||||
| Total Crude oil and NGLs | 830,938 | 749,624 | 820,600 | 796,563 | 789,753 | ||||||||||||
Natural gas (MMcf/d) | |||||||||||||||||
| North America | 2,016 | 2,077 | 2,068 | 2,047 | 2,024 | ||||||||||||
| International | |||||||||||||||||
| North Sea | 1 | 2 | 1 | 1 | 2 | ||||||||||||
| Offshore Africa | 9 | 9 | 10 | 10 | 10 | ||||||||||||
| Total International | 10 | 11 | 11 | 11 | 12 | ||||||||||||
| Total Natural gas | 2,026 | 2,088 | 2,079 | 2,058 | 2,036 | ||||||||||||
| Total Barrels of oil equivalent (BOE/d) | 1,168,599 | 1,097,693 | 1,167,139 | 1,139,622 | 1,129,014 | ||||||||||||
(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 nine months ended September 30, 2024 averaged 977,265 bbl/d, an increase of 3% from 948,587 bbl/d for the nine months ended September 30, 2023. Crude oil and NGLs production before royalties for the third quarter of 2024 averaged 1,021,572 bbl/d, comparable with 1,035,153 bbl/d for the third quarter of 2023, and an increase of 9% from 934,066 bbl/d for the second quarter of 2024. The increase in crude oil and NGLs production for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 primarily reflected strong performance and utilization in the Oil Sands Mining and Upgrading segment and higher thermal oil production due to pad additions in the North America Exploration and Production segment. The increase in crude oil and NGLs production for the third quarter of 2024 from the second quarter of 2024 reflected strong production at Horizon following the completion of the planned turnaround including all tie-ins and commissioning of the reliability enhancement project in the second quarter of 2024, partially offset by the planned turnaround at the non-operated Scotford Upgrader ("Scotford") which commenced late in the third quarter of 2024.
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 nine months ended September 30, 2024 averaged 2,102 MMcf/d, comparable with 2,125 MMcf/d for the nine months ended September 30, 2023. Natural gas production before royalties for the third quarter of 2024 averaged 2,049 MMcf/d, a decrease of 5% from 2,151 MMcf/d for the third quarter of 2023 and a decrease of 3% from 2,110 MMcf/d for the second quarter of 2024. The decrease in natural gas production for the third quarter of 2024 from the comparable periods reflected previously announced deferrals of budgeted natural gas well onstream timing in response to natural gas pricing, together with natural field declines. The decrease in natural gas production for the third quarter of 2024 from the second quarter of 2024 also reflected the impact of heat and wildfire conditions in the third quarter of 2024.
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 | 10 | Three and nine months ended September 30, 2024 | ||||||
North America – Exploration and Production
North America crude oil and NGLs production before royalties for the nine months ended September 30, 2024 averaged 501,674 bbl/d, an increase of 3% from 487,512 bbl/d for the nine months ended September 30, 2023. North America crude oil and NGLs production before royalties for the third quarter of 2024 of 499,772 bbl/d decreased 4% from 519,581 bbl/d for the third quarter of 2023 and was comparable with 499,636 bbl/d for the second quarter of 2024. The increase in North America crude oil and NGLs production for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 reflected higher thermal oil production due to pad additions, partially offset by natural field declines. The decrease in North America crude oil and NGLs production for the third quarter of 2024 from the third quarter of 2023 reflected the cyclical nature of Primrose and natural field declines, partially offset by thermal pad additions at Jackfish and Kirby.
The Company's thermal in situ assets continued to demonstrate long life low decline production before royalties, averaging 271,551 bbl/d for the third quarter of 2024, a decrease of 5% from 287,085 bbl/d for the third quarter of 2023, and comparable with 268,044 bbl/d for the second quarter of 2024. The decrease in thermal in situ production in the third quarter of 2024 from the third quarter of 2023 primarily reflected the cyclical nature of Primrose and natural field declines, partially offset by thermal pad additions at Jackfish and Kirby.
Pelican Lake heavy crude oil production before royalties for the third quarter of 2024 averaged 45,101 bbl/d, a decrease of 4% from 46,897 bbl/d for the third quarter of 2023 and comparable with 44,839 bbl/d for the second quarter of 2024, reflecting Pelican Lake's long life low decline production, partially offset by drilling completed in the first half of 2024.
North America natural gas production before royalties for the nine months ended September 30, 2024 averaged 2,091 MMcf/d, comparable with 2,113 MMcf/d for the nine months ended September 30, 2023. Natural gas production before royalties averaged 2,039 MMcf/d for the third quarter of 2024, a decrease of 5% from 2,139 MMcf/d for the third quarter of 2023 and a decrease of 3% from 2,099 MMcf/d for the second quarter of 2024. The decrease in natural gas production for the third quarter of 2024 from the comparable periods reflected previously announced deferrals of budgeted natural gas well onstream timing in response to natural gas pricing, together with natural field declines. The decrease in natural gas production for the third quarter of 2024 from the second quarter of 2024 also reflected the impact of heat and wildfire conditions in the third quarter of 2024.
North America – Oil Sands Mining and Upgrading
SCO production before royalties for the nine months ended September 30, 2024 averaged 451,298 bbl/d, an increase of 4% from 434,895 bbl/d for the nine months ended September 30, 2023. SCO production before royalties for the third quarter of 2024 averaged 497,656 bbl/d, comparable with 490,853 bbl/d for the third quarter of 2023, and an increase of 21% from 410,518 bbl/d for the second quarter of 2024. The increase in SCO production for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 reflected strong performance and utilization at both Horizon and AOSP. The increase in SCO production for the third quarter of 2024 from the second quarter of 2024 primarily reflected the completion of the planned turnaround at Horizon including final tie-ins and commissioning of the reliability enhancement project in the second quarter of 2024, partially offset by the planned turnaround at Scotford, which commenced late in the third quarter of 2024.
International – Exploration and Production
International crude oil and NGLs production before royalties for the nine months ended September 30, 2024 averaged 24,293 bbl/d, a decrease of 7% from 26,180 bbl/d for the nine months ended September 30, 2023. International crude oil and NGLs production before royalties for the third quarter of 2024 averaged 24,144 bbl/d, comparable with 24,719 bbl/d for the third quarter of 2023 and 23,912 bbl/d for the second quarter of 2024. The decrease in International crude oil and NGLs production for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 reflected natural field declines.
International Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when control of the product passes to the customer and delivery has taken place. Revenue has not been recognized in the International segments on crude oil production held in various storage facilities or floating production storage and offloading vessels ("FPSOs"), as follows:
| (bbl) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | ||||||||
| International | 655,729 | 1,145,760 | 1,167,250 | ||||||||
| Canadian Natural Resources Limited | 11 | Three and nine months ended September 30, 2024 | ||||||
OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | |||||||||||||||||||||||||||||||
Crude oil and NGLs ($/bbl) (1) | |||||||||||||||||||||||||||||||||||
Realized price (2) | $ | 79.15 | $ | 86.64 | $ | 87.83 | $ | 78.67 | $ | 73.45 | |||||||||||||||||||||||||
Transportation (2) | 5.26 | 5.98 | 4.07 | 5.30 | 4.37 | ||||||||||||||||||||||||||||||
Realized price, net of transportation (2) | 73.89 | 80.66 | 83.76 | 73.37 | 69.08 | ||||||||||||||||||||||||||||||
Royalties (3) | 15.05 | 17.45 | 17.32 | 14.88 | 12.98 | ||||||||||||||||||||||||||||||
Production expense (4) | 14.65 | 14.54 | 14.40 | 15.28 | 16.51 | ||||||||||||||||||||||||||||||
Netback (2) | $ | 44.19 | $ | 48.67 | $ | 52.04 | $ | 43.21 | $ | 39.59 | |||||||||||||||||||||||||
Natural gas ($/Mcf) (1) | |||||||||||||||||||||||||||||||||||
Realized price (5) | $ | 1.25 | $ | 1.59 | $ | 2.81 | $ | 1.80 | $ | 3.20 | |||||||||||||||||||||||||
Transportation (6) | 0.63 | 0.63 | 0.56 | 0.62 | 0.56 | ||||||||||||||||||||||||||||||
| Realized price, net of transportation | 0.62 | 0.96 | 2.25 | 1.18 | 2.64 | ||||||||||||||||||||||||||||||
Royalties (3) | 0.02 | 0.02 | 0.09 | 0.05 | 0.15 | ||||||||||||||||||||||||||||||
Production expense (4) | 1.26 | 1.21 | 1.25 | 1.26 | 1.36 | ||||||||||||||||||||||||||||||
Netback (7) | $ | (0.66) | $ | (0.27) | $ | 0.91 | $ | (0.13) | $ | 1.13 | |||||||||||||||||||||||||
Barrels of oil equivalent ($/BOE) (1) | |||||||||||||||||||||||||||||||||||
Realized price (2) | $ | 50.36 | $ | 55.84 | $ | 59.40 | $ | 51.29 | $ | 51.31 | |||||||||||||||||||||||||
Transportation (2) | 4.67 | 5.09 | 3.78 | 4.70 | 3.97 | ||||||||||||||||||||||||||||||
Realized price, net of transportation (2) | 45.69 | 50.75 | 55.62 | 46.59 | 47.34 | ||||||||||||||||||||||||||||||
Royalties (3) | 9.05 | 10.53 | 10.61 | 8.99 | 8.03 | ||||||||||||||||||||||||||||||
Production expense (4) | 11.81 | 11.64 | 11.64 | 12.16 | 13.10 | ||||||||||||||||||||||||||||||
Netback (2) | $ | 24.83 | $ | 28.58 | $ | 33.37 | $ | 25.44 | $ | 26.21 | |||||||||||||||||||||||||
(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.
(7)Natural gas netbacks exclude NGLs netbacks derived from the Company's liquids rich natural gas plays.
| Canadian Natural Resources Limited | 12 | Three and nine months ended September 30, 2024 | ||||||
REALIZED PRODUCT PRICES – EXPLORATION AND PRODUCTION
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | |||||||||||||||||||||||||||||||
Crude oil and NGLs ($/bbl) (1) | |||||||||||||||||||||||||||||||||||
North America (2) | $ | 77.29 | $ | 85.49 | $ | 86.77 | $ | 77.06 | $ | 71.90 | |||||||||||||||||||||||||
International average (3) | $ | 109.41 | $ | 115.27 | $ | 113.59 | $ | 112.14 | $ | 105.20 | |||||||||||||||||||||||||
North Sea (3) | $ | 112.54 | $ | 115.02 | $ | 108.22 | $ | 113.90 | $ | 106.91 | |||||||||||||||||||||||||
Offshore Africa (3) | $ | 108.04 | $ | 115.67 | $ | 118.09 | $ | 110.45 | $ | 105.55 | |||||||||||||||||||||||||
Crude oil and NGLs average (2) | $ | 79.15 | $ | 86.64 | $ | 87.83 | $ | 78.67 | $ | 73.45 | |||||||||||||||||||||||||
Natural gas ($/Mcf) (1) (3) | |||||||||||||||||||||||||||||||||||
| North America | $ | 1.19 | $ | 1.53 | $ | 2.76 | $ | 1.75 | $ | 3.15 | |||||||||||||||||||||||||
| International average | $ | 12.67 | $ | 11.87 | $ | 12.21 | $ | 12.22 | $ | 13.04 | |||||||||||||||||||||||||
| North Sea | $ | 11.28 | $ | 9.79 | $ | 9.99 | $ | 10.79 | $ | 10.70 | |||||||||||||||||||||||||
| Offshore Africa | $ | 12.87 | $ | 12.24 | $ | 12.44 | $ | 12.43 | $ | 13.44 | |||||||||||||||||||||||||
| Natural gas average | $ | 1.25 | $ | 1.59 | $ | 2.81 | $ | 1.80 | $ | 3.20 | |||||||||||||||||||||||||
Average ($/BOE) (1) (2) | $ | 50.36 | $ | 55.84 | $ | 59.40 | $ | 51.29 | $ | 51.31 | |||||||||||||||||||||||||
(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 7% to average $77.06 per bbl for the nine months ended September 30, 2024 from $71.90 per bbl for the nine months ended September 30, 2023. North America realized crude oil and NGLs prices averaged $77.29 per bbl for the third quarter of 2024, a decrease of 11% from $86.77 per bbl for the third quarter of 2023, and a decrease of 10% from $85.49 per bbl for the second quarter of 2024. The increase in North America realized crude oil and NGLs prices for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 primarily reflected the narrowing of the WCS Heavy Differential due to the start-up of the TMX pipeline in the second quarter of 2024, combined with stronger US Gulf Coast heavy oil pricing. The decrease in North America realized crude oil and NGLs prices for the third quarter of 2024 from the comparable periods reflected lower WTI benchmark pricing. The decrease for the third quarter of 2024 from the third quarter of 2023 also reflected the widening of the WCS Heavy Differential. The Company continues to focus on its crude oil blending marketing strategy and in the third quarter of 2024 contributed approximately 199,000 bbl/d of heavy crude oil blends to the WCS stream.
North America realized natural gas prices decreased 44% to average $1.75 per Mcf for the nine months ended September 30, 2024 from $3.15 per Mcf for the nine months ended September 30, 2023. North America realized natural gas prices decreased 57% to average $1.19 per Mcf for the third quarter of 2024 from $2.76 per Mcf for the third quarter of 2023 and decreased 22% from $1.53 per Mcf for the second quarter of 2024. The decrease in North America realized natural gas prices for the three and nine months ended September 30, 2024 from the comparable periods primarily reflected lower AECO benchmark pricing together with volatility in export pricing.
| Canadian Natural Resources Limited | 13 | Three and nine months ended September 30, 2024 | ||||||
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
| Three Months Ended | ||||||||||||||||||||
| (Quarterly average) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | |||||||||||||||||
Wellhead Price (1) | ||||||||||||||||||||
| Light and medium crude oil and NGLs ($/bbl) | $ | 67.58 | $ | 74.90 | $ | 72.07 | ||||||||||||||
| Pelican Lake heavy crude oil ($/bbl) | $ | 84.02 | $ | 92.42 | $ | 93.19 | ||||||||||||||
| Primary heavy crude oil ($/bbl) | $ | 83.56 | $ | 91.27 | $ | 93.80 | ||||||||||||||
| Bitumen (thermal oil) ($/bbl) | $ | 78.26 | $ | 86.84 | $ | 89.50 | ||||||||||||||
| Natural gas ($/Mcf) | $ | 1.19 | $ | 1.53 | $ | 2.76 | ||||||||||||||
(1)Amounts expressed on a per unit basis are based on sales volumes of the respective product type.
International
International realized crude oil and NGLs prices increased 7% to average $112.14 per bbl for the nine months ended September 30, 2024 from $105.20 per bbl for the nine months ended September 30, 2023. International realized crude oil and NGLs prices decreased 4% to average $109.41 per bbl for the third quarter of 2024 from $113.59 per bbl for the third quarter of 2023 and decreased 5% from $115.27 per bbl for the second quarter of 2024. Realized crude oil and NGLs prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings from each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The fluctuations in realized crude oil and NGLs prices for the three and nine months ended September 30, 2024 from the comparable periods primarily reflected prevailing Brent benchmark pricing at the time of liftings, together with the impact of movements in the Canadian dollar.
ROYALTIES – EXPLORATION AND PRODUCTION
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | |||||||||||||||||||||||||||||||
Crude oil and NGLs ($/bbl) (1) | |||||||||||||||||||||||||||||||||||
| North America | $ | 15.72 | $ | 18.06 | $ | 17.79 | $ | 15.46 | $ | 13.31 | |||||||||||||||||||||||||
| International average | $ | 4.02 | $ | 2.11 | $ | 5.67 | $ | 2.96 | $ | 6.07 | |||||||||||||||||||||||||
| North Sea | $ | 0.33 | $ | 0.24 | $ | 0.42 | $ | 0.27 | $ | 0.38 | |||||||||||||||||||||||||
| Offshore Africa | $ | 5.65 | $ | 5.14 | $ | 8.90 | $ | 5.56 | $ | 9.87 | |||||||||||||||||||||||||
| Crude oil and NGLs average | $ | 15.05 | $ | 17.45 | $ | 17.32 | $ | 14.88 | $ | 12.98 | |||||||||||||||||||||||||
Natural gas ($/Mcf) (1) | |||||||||||||||||||||||||||||||||||
| North America | $ | 0.01 | $ | 0.02 | $ | 0.09 | $ | 0.04 | $ | 0.14 | |||||||||||||||||||||||||
| Offshore Africa | $ | 0.59 | $ | 0.56 | $ | 0.59 | $ | 0.57 | $ | 0.64 | |||||||||||||||||||||||||
| Natural gas average | $ | 0.02 | $ | 0.02 | $ | 0.09 | $ | 0.05 | $ | 0.15 | |||||||||||||||||||||||||
Average ($/BOE) (1) | $ | 9.05 | $ | 10.53 | $ | 10.61 | $ | 8.99 | $ | 8.03 | |||||||||||||||||||||||||
(1)Calculated as royalties divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
North America crude oil and NGLs and natural gas royalties for the three and nine months ended September 30, 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.
| Canadian Natural Resources Limited | 14 | Three and nine months ended September 30, 2024 | ||||||
Crude oil and NGLs royalty rates(1) averaged approximately 20% of product sales for the nine months ended September 30, 2024 compared with 19% of product sales for the nine months ended September 30, 2023. Crude oil and NGLs royalty rates averaged approximately 20% of product sales for the third quarter of 2024 compared with 21% for the third quarter of 2023 and 21% for the second quarter of 2024. The fluctuations in royalty rates for the three and nine months ended September 30, 2024 from the comparable periods was primarily due to prevailing benchmark pricing and fluctuations in the WCS Heavy Differential.
Natural gas royalty rates averaged approximately 2% of product sales for the nine months ended September 30, 2024 compared with 5% of product sales for the nine months ended September 30, 2023. Natural gas royalty rates averaged approximately 1% of product sales for the third quarter of 2024 compared with 3% for the third quarter of 2023 and 1% for the second quarter of 2024. The decrease in royalty rates for the three and nine months ended September 30, 2024 from the comparable periods was primarily due to lower benchmark prices.
Offshore Africa
Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital expenditures and production expenses, the status of payouts, and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 5% for the nine months ended September 30, 2024 compared with 9% of product sales for the nine months ended September 30, 2023. Royalty rates as a percentage of product sales averaged approximately 5% for the third quarter of 2024 compared with 7% of product sales for the third quarter of 2023 and 4% for the second 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 | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | |||||||||||||||||||||||||||||||
Crude oil and NGLs ($/bbl) (1) | |||||||||||||||||||||||||||||||||||
| North America | $ | 12.36 | $ | 12.44 | $ | 13.21 | $ | 13.17 | $ | 15.16 | |||||||||||||||||||||||||
| International average | $ | 52.04 | $ | 66.83 | $ | 44.16 | $ | 59.04 | $ | 44.94 | |||||||||||||||||||||||||
| North Sea | $ | 120.92 | $ | 96.07 | $ | 83.44 | $ | 98.49 | $ | 81.92 | |||||||||||||||||||||||||
| Offshore Africa | $ | 21.67 | $ | 19.28 | $ | 20.04 | $ | 20.94 | $ | 20.23 | |||||||||||||||||||||||||
| Crude oil and NGLs average | $ | 14.65 | $ | 14.54 | $ | 14.40 | $ | 15.28 | $ | 16.51 | |||||||||||||||||||||||||
Natural gas ($/Mcf) (1) | |||||||||||||||||||||||||||||||||||
| North America | $ | 1.23 | $ | 1.19 | $ | 1.22 | $ | 1.23 | $ | 1.33 | |||||||||||||||||||||||||
| International average | $ | 6.24 | $ | 6.51 | $ | 7.40 | $ | 6.13 | $ | 6.72 | |||||||||||||||||||||||||
| North Sea | $ | 9.61 | $ | 7.72 | $ | 9.19 | $ | 8.60 | $ | 9.95 | |||||||||||||||||||||||||
| Offshore Africa | $ | 5.75 | $ | 6.30 | $ | 7.21 | $ | 5.77 | $ | 6.17 | |||||||||||||||||||||||||
| Natural gas average | $ | 1.26 | $ | 1.21 | $ | 1.25 | $ | 1.26 | $ | 1.36 | |||||||||||||||||||||||||
Average ($/BOE) (1) | $ | 11.81 | $ | 11.64 | $ | 11.64 | $ | 12.16 | $ | 13.10 | |||||||||||||||||||||||||
(1)Calculated as production expense divided by respective sales volumes. For crude oil and NGLs and BOE sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A. For natural gas sales volumes, refer to the "Daily Production, before royalties" section of this MD&A.
North America
North America crude oil and NGLs production expense for the nine months ended September 30, 2024 averaged $13.17 per bbl, a decrease of 13% from $15.16 per bbl for the nine months ended September 30, 2023. North America crude oil and NGLs production expense for the third quarter of 2024 of $12.36 per bbl decreased 6% from $13.21 per bbl for the third quarter of 2023 and was comparable with $12.44 per bbl for the second quarter of 2024. The decrease in crude oil and NGLs production expense per bbl for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 reflected lower energy costs combined with higher production volumes. The decrease in crude oil and NGLs production expense per bbl for the third quarter of 2024 from the third quarter of 2023 primarily reflected lower energy costs, partially offset by lower production volumes in the third quarter of 2024.
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
| Canadian Natural Resources Limited | 15 | Three and nine months ended September 30, 2024 | ||||||
North America natural gas production expense for the nine months ended September 30, 2024 averaged $1.23 per Mcf, a decrease of 8% from $1.33 per Mcf for the nine months ended September 30, 2023. North America natural gas production expense for the third quarter of 2024 of $1.23 per Mcf was comparable with $1.22 per Mcf for the third quarter of 2023 and increased 3% from $1.19 per Mcf for the second quarter of 2024. The decrease in natural gas production expense per Mcf for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 reflected lower energy costs. The increase in natural gas production expense for the third quarter of 2024 from the second quarter of 2024 primarily reflected lower production volumes in the third quarter of 2024.
International
International crude oil and NGLs production expense for the nine months ended September 30, 2024 averaged $59.04 per bbl, an increase of 31% from $44.94 per bbl for the nine months ended September 30, 2023. International crude oil and NGLs production expense for the third quarter of 2024 of $52.04 per bbl increased 18% from $44.16 per bbl for the third quarter of 2023 and decreased 22% from $66.83 per bbl for the second quarter of 2024. Fluctuations in crude oil and NGLs production expense for the three and nine months ended September 30, 2024 from the comparable periods reflected the timing of liftings from various fields that have different cost structures and the impact of foreign exchange.
ADJUSTED DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except per BOE amounts) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| North America | $ | 924 | $ | 956 | $ | 947 | $ | 2,821 | $ | 2,708 | |||||||||||||||||||||||||
| North Sea | 17 | 24 | 12 | 58 | 28 | ||||||||||||||||||||||||||||||
| Offshore Africa | 96 | 108 | 47 | 251 | 147 | ||||||||||||||||||||||||||||||
| Depletion, depreciation and amortization | $ | 1,037 | $ | 1,088 | $ | 1,006 | $ | 3,130 | $ | 2,883 | |||||||||||||||||||||||||
Less: Recoverability charge (1) | — | 62 | — | 62 | — | ||||||||||||||||||||||||||||||
Adjusted depletion, depreciation and amortization (2) | $ | 1,037 | $ | 1,026 | $ | 1,006 | $ | 3,068 | $ | 2,883 | |||||||||||||||||||||||||
$/BOE (3) | $ | 13.27 | $ | 12.77 | $ | 12.22 | $ | 12.89 | $ | 12.21 | |||||||||||||||||||||||||
(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 nine months ended September 30, 2024 averaged $12.89 per BOE, an increase of 6% from $12.21 per BOE for the nine months ended September 30, 2023. Adjusted depletion, depreciation and amortization expense for the third quarter of 2024 averaged $13.27 per BOE, an increase of 9% from $12.22 per BOE for the third quarter of 2023, and an increase of 4% from $12.77 per BOE for the second quarter of 2024. The increase in adjusted depletion, depreciation and amortization expense per BOE for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 primarily reflected the impact of changes in North America depletion rates due to changes in reserve estimates at December 31, 2023. The increase in adjusted depletion, depreciation and amortization expense per BOE for the three months ended September 30, 2024 from the comparable periods reflected lower sales volumes in North America.
Adjusted depletion, depreciation and amortization expense on an absolute and per BOE basis also reflects the impact of the timing of liftings from each field in the North Sea and Offshore Africa.
| Canadian Natural Resources Limited | 16 | Three and nine months ended September 30, 2024 | ||||||
ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except per BOE amounts) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| North America | $ | 58 | $ | 57 | $ | 59 | $ | 173 | $ | 176 | |||||||||||||||||||||||||
| North Sea | 16 | 16 | 11 | 48 | 34 | ||||||||||||||||||||||||||||||
| Offshore Africa | 2 | 2 | 2 | 6 | 6 | ||||||||||||||||||||||||||||||
| Asset retirement obligation accretion | $ | 76 | $ | 75 | $ | 72 | $ | 227 | $ | 216 | |||||||||||||||||||||||||
$/BOE (1) | $ | 0.97 | $ | 0.95 | $ | 0.87 | $ | 0.96 | $ | 0.91 | |||||||||||||||||||||||||
(1)Calculated as asset retirement obligation accretion divided by sales volumes. For sales volumes, refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time.
Asset retirement obligation accretion expense for the nine months ended September 30, 2024 averaged $0.96 per BOE, an increase of 5% from $0.91 per BOE for the nine months ended September 30, 2023. Asset retirement obligation accretion expense for the third quarter of 2024 averaged $0.97 per BOE, an increase of 11% from $0.87 per BOE for the third quarter of 2023, and comparable with $0.95 per BOE for the second quarter of 2024. The increase in asset retirement obligation accretion expense per BOE for the three and nine months ended September 30, 2024 from the comparable periods in 2023 primarily reflected the Company's estimate for future abandonment costs for the Ninian field in the North Sea at December 31, 2023.
OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING
The Company continues to focus on safe, reliable, and efficient operations, leveraging its technical expertise across the Horizon and AOSP sites. SCO production averaged 497,656 bbl/d in the third quarter of 2024, reflecting record quarterly SCO production at Horizon resulting from strong production and utilization.
The Company incurred production expense of $935 million for the third quarter of 2024, a decrease of 7% from $1,003 million for the third quarter of 2023, and comparable with $941 million for the second quarter of 2024. The decrease in production expense for the third quarter of 2024 from the third quarter of 2023 primarily reflected lower energy costs. The Company continues to focus on cost control and driving efficiencies across the Oil Sands Mining and Upgrading segment.
REALIZED PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($/bbl) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
Realized SCO sales price (1) | $ | 100.93 | $ | 108.81 | $ | 108.55 | $ | 99.19 | $ | 100.57 | |||||||||||||||||||||||||
Bitumen value for royalty purposes (2) | $ | 76.16 | $ | 82.08 | $ | 84.66 | $ | 73.93 | $ | 66.85 | |||||||||||||||||||||||||
Bitumen royalties (3) | $ | 17.71 | $ | 20.01 | $ | 21.90 | $ | 17.24 | $ | 15.52 | |||||||||||||||||||||||||
Transportation (1) | $ | 3.34 | $ | 2.81 | $ | 2.18 | $ | 2.62 | $ | 1.91 | |||||||||||||||||||||||||
(1)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(2)Calculated as the quarterly average of the bitumen methodology price.
(3)Calculated as royalties divided by sales volumes.
The realized SCO sales price averaged $99.19 per bbl for the nine months ended September 30, 2024, comparable with $100.57 per bbl for the nine months ended September 30, 2023. The realized SCO sales price averaged $100.93 per bbl for the third quarter of 2024, a decrease of 7% from $108.55 per bbl for the third quarter of 2023, and a decrease of 7% from $108.81 per bbl for the second quarter of 2024. The decrease in realized SCO sales price for the third quarter of 2024 from the comparable periods primarily reflected the decrease in WTI benchmark pricing combined with weaker diesel pricing.
The fluctuations in bitumen royalties per bbl for the three and nine months ended September 30, 2024 from the comparable periods reflected prevailing bitumen pricing for royalty purposes, and the impact of sliding scale royalty rates.
| Canadian Natural Resources Limited | 17 | Three and nine months ended September 30, 2024 | ||||||
Transportation expense averaged $2.62 per bbl for the nine months ended September 30, 2024, an increase of 37% from $1.91 per bbl for the nine months ended September 30, 2023. Transportation expense averaged $3.34 per bbl for the third quarter of 2024, an increase of 53% from $2.18 per bbl for the third quarter of 2023, and an increase of 19% from $2.81 per bbl for the second quarter of 2024. The increase in transportation expense per bbl for the three and nine months ended September 30, 2024 from the comparable periods primarily reflected higher volumes shipped to the US Gulf Coast and on the TMX pipeline.
PRODUCTION EXPENSE – OIL SANDS MINING AND UPGRADING
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Production expense, excluding natural gas costs | $ | 917 | $ | 917 | $ | 962 | $ | 2,810 | $ | 2,890 | |||||||||||||||||||||||||
| Natural gas costs | 18 | 24 | 41 | 92 | 152 | ||||||||||||||||||||||||||||||
| Production expense | $ | 935 | $ | 941 | $ | 1,003 | $ | 2,902 | $ | 3,042 | |||||||||||||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($/bbl) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
Production expense, excluding natural gas costs (1) | $ | 20.27 | $ | 25.29 | $ | 21.22 | $ | 22.89 | $ | 24.33 | |||||||||||||||||||||||||
Natural gas costs (2) | 0.40 | 0.66 | 0.90 | 0.75 | 1.28 | ||||||||||||||||||||||||||||||
Production expense (3) | $ | 20.67 | $ | 25.95 | $ | 22.12 | $ | 23.64 | $ | 25.61 | |||||||||||||||||||||||||
| Sales volumes (bbl/d) | 491,635 | 398,528 | 492,926 | 448,145 | 435,109 | ||||||||||||||||||||||||||||||
(1)Calculated as production expense, excluding natural gas costs divided by sales volumes.
(2)Calculated as natural gas costs divided by sales volumes.
(3)Calculated as production expense divided by sales volumes.
Production expense for the nine months ended September 30, 2024 averaged $23.64 per bbl, a decrease of 8% from $25.61 per bbl for the nine months ended September 30, 2023. Production expense for the third quarter of 2024 averaged $20.67 per bbl, a decrease of 7% from $22.12 per bbl for the third quarter of 2023, and a decrease of 20% from $25.95 per bbl for the second quarter of 2024. The decrease in production expense per bbl for the three and nine months ended September 30, 2024 from the comparable periods in 2023 reflected lower energy costs and higher production volumes. The decrease in production expense per bbl for the third quarter of 2024 from the second quarter of 2024 primarily reflected higher production volumes following the planned turnaround at Horizon including final tie-ins and commissioning of the reliability enhancement project in the second quarter of 2024.
DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except per bbl amounts) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Depletion, depreciation and amortization | $ | 556 | $ | 557 | $ | 527 | $ | 1,637 | $ | 1,457 | |||||||||||||||||||||||||
$/bbl (1) | $ | 12.27 | $ | 15.37 | $ | 11.62 | $ | 13.33 | $ | 12.27 | |||||||||||||||||||||||||
(1)Calculated as depletion, depreciation and amortization divided by sales volumes.
Depletion, depreciation and amortization expense for the nine months ended September 30, 2024 averaged $13.33 per bbl, an increase of 9% from $12.27 per bbl for the nine months ended September 30, 2023. Depletion, depreciation and amortization expense for the third quarter of 2024 of $12.27 per bbl increased 6% from $11.62 per bbl for the third quarter of 2023 and decreased 20% from $15.37 per bbl for the second quarter of 2024. The increase in depletion, depreciation and amortization expense per bbl for the nine months ended September 30, 2024 from the nine months ended September 30, 2023 primarily reflected derecognitions related to the turnaround in the second quarter of 2024 and higher sales volumes at Horizon in 2024. The increase in depletion, depreciation and amortization expense per bbl for the third quarter of 2024 from the third quarter of 2023 primarily reflected the impact of a higher depletable base due to asset additions combined with higher sales volumes at Horizon. The decrease in depletion, depreciation and amortization expense per bbl for the third quarter of 2024 from the second quarter of 2024 primarily reflected the impact of higher sales volumes in the third quarter of 2024.
| Canadian Natural Resources Limited | 18 | Three and nine months ended September 30, 2024 | ||||||
ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except per bbl amounts) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Asset retirement obligation accretion | $ | 21 | $ | 22 | $ | 20 | $ | 64 | $ | 59 | |||||||||||||||||||||||||
$/bbl (1) | $ | 0.46 | $ | 0.58 | $ | 0.43 | $ | 0.51 | $ | 0.50 | |||||||||||||||||||||||||
(1)Calculated as asset retirement obligation accretion divided by sales volumes.
Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time.
Asset retirement obligation accretion expense for the nine months ended September 30, 2024 of $0.51 per bbl was comparable with $0.50 per bbl for the nine months ended September 30, 2023. Asset retirement obligation accretion expense for the third quarter of 2024 of $0.46 per bbl increased 7% from $0.43 per bbl for the third quarter of 2023 and decreased 21% from $0.58 per bbl for the second quarter of 2024. The increase in asset retirement obligation accretion expense per bbl for the third quarter of 2024 from the third quarter of 2023 primarily reflected the net impact of changes in estimates related to cost, timing and discount rates at December 31, 2023, combined with slightly lower sales volumes in the third quarter of 2024. The decrease in asset retirement obligation accretion expense per bbl for the third quarter of 2024 from the second quarter of 2024 reflected the impact of higher sales volumes in the third quarter of 2024.
MIDSTREAM AND REFINING
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Product sales | |||||||||||||||||||||||||||||||||||
| Midstream activities | $ | 20 | $ | 21 | $ | 20 | $ | 61 | $ | 56 | |||||||||||||||||||||||||
| NWRP, refined product sales and other | 191 | 215 | 237 | 620 | 690 | ||||||||||||||||||||||||||||||
| Segmented revenue | 211 | 236 | 257 | 681 | 746 | ||||||||||||||||||||||||||||||
| Less: | |||||||||||||||||||||||||||||||||||
| NWRP, refining toll | 75 | 81 | 66 | 230 | 221 | ||||||||||||||||||||||||||||||
| Midstream activities | 3 | 7 | 8 | 15 | 22 | ||||||||||||||||||||||||||||||
| Production expense | 78 | 88 | 74 | 245 | 243 | ||||||||||||||||||||||||||||||
| NWRP, transportation and feedstock costs | 169 | 194 | 183 | 521 | 498 | ||||||||||||||||||||||||||||||
| Depreciation | 5 | 4 | 4 | 13 | 12 | ||||||||||||||||||||||||||||||
| Segmented loss | $ | (41) | $ | (50) | $ | (4) | $ | (98) | $ | (7) | |||||||||||||||||||||||||
The Company's Midstream and Refining assets consist of two crude oil pipeline systems, a 50% working interest in an 84-megawatt cogeneration plant at Primrose and the Company's 50% equity investment in North West Redwater Partnership ("NWRP").
NWRP operates a 50,000 bbl/d bitumen upgrader and refinery that processes approximately 12,500 bbl/d of bitumen feedstock for the Company (25% toll payer) and 37,500 bbl/d of bitumen feedstock for the Alberta Petroleum Marketing Commission ("APMC") (75% toll payer), an agent of the Government of Alberta. The Company is unconditionally obligated to pay its 25% pro rata share of the debt component of the monthly fee-for-service toll over the 40-year tolling period until 2058. Sales of diesel and refined products and associated refining tolls are recognized in the Midstream and Refining segment. For the third quarter of 2024, production of ultra-low sulphur diesel and other refined products averaged 72,109 BOE/d (18,027 BOE/d to the Company) (three months ended June 30, 2024 – 78,272 BOE/d; 19,568 BOE/d to the Company; three months ended September 30, 2023 – 78,376 BOE/d; 19,594 BOE/d to the Company), reflecting the 25% toll payer commitment.
During the third quarter of 2024, NWRP repaid $500 million of 3.20% series A bonds.
| Canadian Natural Resources Limited | 19 | Three and nine months ended September 30, 2024 | ||||||
During the second quarter of 2024, NWRP issued $700 million of 4.85% series P bonds due June 1, 2034 and $600 million of 5.08% series Q bonds due June 1, 2054. Additionally, NWRP extended its revolving credit facility originally maturing June 2025 to June 2027, and reduced the capacity from $2,175 million to $1,900 million. NWRP also repaid $440 million on its non-revolving credit facility maturing June 2025, reducing the amount outstanding to $500 million.
As at September 30, 2024, the Company's cumulative unrecognized share of the equity loss and partnership distributions from NWRP was $510 million (December 31, 2023 – $555 million). For the three months ended September 30, 2024, the Company's recovery of its share of unrecognized equity losses was $6 million (nine months ended September 30, 2024 – recovery of unrecognized equity losses of $45 million; three months ended September 30, 2023 – recovery of unrecognized equity losses of $18 million; nine months ended September 30, 2023 – recovery of unrecognized equity losses of $1 million).
ADMINISTRATION EXPENSE
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except per BOE amounts) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Administration expense | $ | 126 | $ | 124 | $ | 108 | $ | 376 | $ | 333 | |||||||||||||||||||||||||
$/BOE (1) | $ | 1.02 | $ | 1.06 | $ | 0.84 | $ | 1.04 | $ | 0.94 | |||||||||||||||||||||||||
Sales volumes (BOE/d) (2) | 1,342,508 | 1,280,416 | 1,388,033 | 1,316,989 | 1,300,390 | ||||||||||||||||||||||||||||||
(1)Calculated as administration expense divided by sales volumes.
(2)Total Company sales volumes.
Administration expense for the nine months ended September 30, 2024 of $1.04 per BOE increased 11% from $0.94 per BOE for the nine months ended September 30, 2023. Administration expense for the third quarter of 2024 of $1.02 per BOE increased 21% from $0.84 per BOE for the third quarter of 2023 and decreased 4% from $1.06 per BOE for the second quarter of 2024. The increase in administration expense per BOE for the three and nine months ended September 30, 2024 from the comparable periods in 2023 primarily reflected higher personnel and corporate costs, partially offset by higher overhead recoveries. The decrease in administration expense per BOE for the third quarter of 2024 from the second quarter of 2024 reflected higher sales volumes, partially offset by higher personnel costs.
SHARE-BASED COMPENSATION
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Share-based compensation (recovery) expense | $ | (46) | $ | (13) | $ | 298 | $ | 235 | $ | 434 | |||||||||||||||||||||||||
The Company's Stock Option Plan provides employees with the right to receive common shares or a cash payment in exchange for stock options surrendered. The Performance Share Unit ("PSU") plan provides certain executive employees of the Company with the right to receive a cash payment; the amount of which is determined with reference to the value of the Company's shares, and by individual employee performance and the extent to which certain other performance measures are met.
The Company recognized $235 million of share-based compensation expense for the nine months ended September 30, 2024, primarily as a result of the measurement of the fair value of outstanding stock options related to the impact of normal course graded vesting of stock options granted in prior periods, the impact of vested stock options exercised or surrendered during the period, and changes in the Company's share price.
| Canadian Natural Resources Limited | 20 | Three and nine months ended September 30, 2024 | ||||||
INTEREST AND OTHER FINANCING EXPENSE
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except effective interest rate) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Interest and other financing expense | $ | 154 | $ | 158 | $ | 187 | $ | 450 | $ | 519 | |||||||||||||||||||||||||
Less: Interest (income) and other expense (1) | (5) | (7) | 4 | (34) | (2) | ||||||||||||||||||||||||||||||
Interest expense on long-term debt and lease liabilities (1) | $ | 159 | $ | 165 | $ | 183 | $ | 484 | $ | 521 | |||||||||||||||||||||||||
Average current and long-term debt (2) | $ | 11,130 | $ | 11,568 | $ | 13,393 | $ | 11,431 | $ | 12,882 | |||||||||||||||||||||||||
Average lease liabilities (2) | 1,511 | 1,525 | 1,490 | 1,526 | 1,505 | ||||||||||||||||||||||||||||||
Average long-term debt and lease liabilities (2) | $ | 12,641 | $ | 13,093 | $ | 14,883 | $ | 12,957 | $ | 14,387 | |||||||||||||||||||||||||
Average effective interest rate (3) (4) | 4.9% | 4.9% | 4.8% | 4.9% | 4.8% | ||||||||||||||||||||||||||||||
Interest and other financing expense per $/BOE (5) | $ | 1.24 | $ | 1.35 | $ | 1.46 | $ | 1.25 | $ | 1.46 | |||||||||||||||||||||||||
Sales volumes (BOE/d) (6) | 1,342,508 | 1,280,416 | 1,388,033 | 1,316,989 | 1,300,390 | ||||||||||||||||||||||||||||||
(1)Item is a component of interest and other financing expense.
(2)The average of current and long-term debt and lease liabilities outstanding during the respective period.
(3)This is a non-GAAP ratio and 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, as applicable, as an indication of the Company's performance.
(4)Calculated as the average interest expense on long-term debt and lease liabilities divided by the average long-term debt and lease liabilities balance. The Company presents its average effective interest rate for financial statement users to evaluate the Company’s average cost of debt borrowings.
(5)Calculated as interest and other financing expense divided by sales volumes.
(6)Total Company sales volumes.
Interest and other financing expense per BOE for the nine months ended September 30, 2024 decreased 14% to $1.25 per BOE from $1.46 per BOE for the nine months ended September 30, 2023. Interest and other financing expense per BOE for the third quarter of 2024 decreased 15% to $1.24 per BOE from $1.46 per BOE for the third quarter of 2023 and decreased 8% from $1.35 per BOE for the second quarter of 2024. The decrease in interest and other financing expense per BOE for the three and nine months ended September 30, 2024 from the comparable periods in 2023 primarily reflected lower average debt levels in the third quarter of 2024. The decrease in interest and other financing expense per BOE for the third quarter of 2024 from the second quarter of 2024 primarily reflected lower average debt levels and higher sales volumes in the third quarter of 2024.
The Company's average effective interest rate for the three and nine months ended September 30, 2024 of 4.9% increased from the comparable periods in 2023, primarily reflecting higher prevailing interest rates on floating rate long-term debt held during 2024.
| Canadian Natural Resources Limited | 21 | Three and nine months ended September 30, 2024 | ||||||
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These derivative financial instruments are not intended for trading or speculative purposes.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Foreign currency contracts | $ | (27) | $ | 12 | $ | 30 | $ | 11 | $ | (2) | |||||||||||||||||||||||||
Natural gas financial instruments (1) (2) | 6 | 6 | (1) | 11 | 5 | ||||||||||||||||||||||||||||||
| Net realized (gain) loss | (21) | 18 | 29 | 22 | 3 | ||||||||||||||||||||||||||||||
| Foreign currency contracts | 5 | 3 | 2 | 17 | 7 | ||||||||||||||||||||||||||||||
Natural gas financial instruments (1) (2) | (5) | (3) | 1 | (4) | 12 | ||||||||||||||||||||||||||||||
| Net unrealized loss | — | — | 3 | 13 | 19 | ||||||||||||||||||||||||||||||
| Net (gain) loss | $ | (21) | $ | 18 | $ | 32 | $ | 35 | $ | 22 | |||||||||||||||||||||||||
(1)Certain commodity financial instruments were assumed in the acquisition of Painted Pony Energy Ltd. in the fourth quarter of 2020.
(2)In the fourth quarter of 2023, the Company entered into 50,000 MMBtu/d of US$1.82 AECO fixed price financial contracts for the period of January to December 2024.
During the nine months ended September 30, 2024 net realized risk management losses were related to the settlement of foreign currency contracts and natural gas financial instruments. The Company recorded a net unrealized loss of $13 million ($13 million after tax of $nil) on its risk management activities for the nine months ended September 30, 2024 (nine months ended September 30, 2023 – unrealized loss of $19 million ($16 million after tax of $3 million)).
Further details related to outstanding derivative financial instruments as at September 30, 2024 are disclosed in note 16 to the financial statements.
FOREIGN EXCHANGE
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Net realized loss (gain) | $ | 30 | $ | 118 | $ | (48) | $ | 129 | $ | (30) | |||||||||||||||||||||||||
| Net unrealized (gain) loss | (148) | (15) | 250 | 106 | 16 | ||||||||||||||||||||||||||||||
Net (gain) loss (1) | $ | (118) | $ | 103 | $ | 202 | $ | 235 | $ | (14) | |||||||||||||||||||||||||
(1)Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange loss for the nine months ended September 30, 2024 was primarily related to the repayment of the US dollar debt in the second quarter of 2024. The net unrealized foreign exchange loss for the nine months ended September 30, 2024 was primarily related to the translation of outstanding US dollar debt, partially offset by the repayment of the US dollar debt. The US/Canadian dollar exchange rate as at September 30, 2024 was US$0.7405 (June 30, 2024 – US$0.7306, September 30, 2023 – US$0.7387).
| Canadian Natural Resources Limited | 22 | Three and nine months ended September 30, 2024 | ||||||
INCOME TAXES
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except effective tax rates) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
North America (1) | $ | 433 | $ | 548 | $ | 587 | $ | 1,393 | $ | 1,366 | |||||||||||||||||||||||||
| North Sea | (12) | (13) | (11) | (30) | (9) | ||||||||||||||||||||||||||||||
| Offshore Africa | 12 | 5 | 23 | 22 | 53 | ||||||||||||||||||||||||||||||
| Current PRT – North Sea | (47) | (6) | — | (67) | (45) | ||||||||||||||||||||||||||||||
| Other taxes | 3 | (14) | 3 | (8) | 9 | ||||||||||||||||||||||||||||||
| Current income tax | 389 | 520 | 602 | 1,310 | 1,374 | ||||||||||||||||||||||||||||||
| Deferred corporate income tax | 120 | 14 | 195 | 148 | 203 | ||||||||||||||||||||||||||||||
| Deferred PRT – North Sea | 34 | 7 | 6 | 47 | 24 | ||||||||||||||||||||||||||||||
| Deferred income tax | 154 | 21 | 201 | 195 | 227 | ||||||||||||||||||||||||||||||
| Income tax | $ | 543 | $ | 541 | $ | 803 | $ | 1,505 | $ | 1,601 | |||||||||||||||||||||||||
| Earnings before taxes | $ | 2,809 | $ | 2,256 | $ | 3,147 | $ | 6,473 | $ | 7,207 | |||||||||||||||||||||||||
Effective tax rate on net earnings (2) | 19% | 24% | 26% | 23% | 22% | ||||||||||||||||||||||||||||||
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except effective tax rates) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Income tax | $ | 543 | $ | 541 | $ | 803 | $ | 1,505 | $ | 1,601 | |||||||||||||||||||||||||
Tax effect on non-operating items (3) | 1 | 17 | 4 | 32 | 14 | ||||||||||||||||||||||||||||||
| Current PRT – North Sea | 47 | 6 | — | 67 | 45 | ||||||||||||||||||||||||||||||
| Deferred PRT – North Sea | (34) | (7) | (6) | (47) | (24) | ||||||||||||||||||||||||||||||
| Other taxes | (3) | 14 | (3) | 8 | (9) | ||||||||||||||||||||||||||||||
| Effective tax on adjusted net earnings | $ | 554 | $ | 571 | $ | 798 | $ | 1,565 | $ | 1,627 | |||||||||||||||||||||||||
Adjusted net earnings from operations (4) | $ | 2,071 | $ | 1,892 | $ | 2,850 | $ | 5,437 | $ | 5,987 | |||||||||||||||||||||||||
| Adjusted net earnings from operations, before taxes | $ | 2,625 | $ | 2,463 | $ | 3,648 | $ | 7,002 | $ | 7,614 | |||||||||||||||||||||||||
Effective tax rate on adjusted net earnings from operations (5) (6) | 21% | 23% | 22% | 22% | 21% | ||||||||||||||||||||||||||||||
(1)Includes North America Exploration and Production, Oil Sands Mining and Upgrading, and Midstream and Refining segments.
(2)Calculated as total of current and deferred income tax divided by earnings before taxes.
(3)Includes the net income tax effect on PSUs, certain stock options, unrealized risk management, and a recoverability charge related to the notice to withdraw from Block 11B/12B in South Africa.
(4)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
(5)This is a non-GAAP ratio and 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, as applicable, as an indication of the Company's performance.
(6)Calculated as effective tax on adjusted net earnings divided by adjusted net earnings from operations, before taxes. The Company presents its effective tax rate on adjusted net earnings from operations for financial statement users to evaluate the Company's effective tax rate on its core business activities.
The effective tax rate on net earnings and adjusted net earnings from operations for the three and nine months ended September 30, 2024 and the comparable periods included the impact of non-taxable items in North America and the North Sea and the impact of differences in jurisdictional income and tax rates in the countries in which the Company operates, in relation to net earnings.
The current and deferred corporate income tax and the current and deferred PRT in the North Sea for the three and nine months ended September 30, 2024 and the comparable periods included the impact of carrybacks of abandonment expenditures related to the decommissioning activities at the Company's platforms in the North Sea.
| Canadian Natural Resources Limited | 23 | Three and nine months ended September 30, 2024 | ||||||
The Company files income tax returns in the various jurisdictions in which it operates. These tax returns are subject to periodic examinations in the normal course by the applicable tax authorities. The tax returns as prepared may include filing positions that could be subject to differing interpretations of applicable tax laws and regulations, which may take several years to resolve. The Company does not believe the ultimate resolution of these matters will have a material impact upon the Company's reported results of operations, financial position or liquidity.
NET CAPITAL EXPENDITURES(1) (2)
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Exploration and Production | |||||||||||||||||||||||||||||||||||
| Exploration and Evaluation Assets | |||||||||||||||||||||||||||||||||||
| Net expenditures | $ | 8 | $ | (4) | $ | (2) | $ | 73 | $ | 35 | |||||||||||||||||||||||||
| Net property dispositions | — | — | (1) | — | (3) | ||||||||||||||||||||||||||||||
| Total Exploration and Evaluation Assets | 8 | (4) | (3) | 73 | 32 | ||||||||||||||||||||||||||||||
| Property, Plant and Equipment | |||||||||||||||||||||||||||||||||||
| Net property acquisitions | 88 | 4 | 8 | 89 | 25 | ||||||||||||||||||||||||||||||
| Well drilling, completion and equipping | 469 | 478 | 352 | 1,360 | 1,305 | ||||||||||||||||||||||||||||||
| Production and related facilities | 387 | 353 | 301 | 995 | 1,016 | ||||||||||||||||||||||||||||||
| Other | 14 | 13 | 18 | 39 | 48 | ||||||||||||||||||||||||||||||
| Total Property, Plant and Equipment | 958 | 848 | 679 | 2,483 | 2,394 | ||||||||||||||||||||||||||||||
| Total Exploration and Production | 966 | 844 | 676 | 2,556 | 2,426 | ||||||||||||||||||||||||||||||
| Oil Sands Mining and Upgrading | |||||||||||||||||||||||||||||||||||
| Project costs | 55 | 123 | 112 | 240 | 270 | ||||||||||||||||||||||||||||||
| Sustaining capital | 302 | 526 | 286 | 1,109 | 1,027 | ||||||||||||||||||||||||||||||
| Turnaround costs | 12 | 114 | 18 | 137 | 172 | ||||||||||||||||||||||||||||||
| Net property acquisitions (dispositions) | — | — | 6 | (2) | 6 | ||||||||||||||||||||||||||||||
| Other | 3 | 1 | 2 | 5 | 4 | ||||||||||||||||||||||||||||||
| Total Oil Sands Mining and Upgrading | 372 | 764 | 424 | 1,489 | 1,479 | ||||||||||||||||||||||||||||||
| Midstream and Refining | 3 | 3 | 1 | 10 | 6 | ||||||||||||||||||||||||||||||
| Head Office | 8 | 10 | 7 | 28 | 23 | ||||||||||||||||||||||||||||||
| Net capital expenditures | $ | 1,349 | $ | 1,621 | $ | 1,108 | $ | 4,083 | $ | 3,934 | |||||||||||||||||||||||||
| Abandonment expenditures | $ | 204 | $ | 129 | $ | 123 | $ | 495 | $ | 360 | |||||||||||||||||||||||||
| By Segment | |||||||||||||||||||||||||||||||||||
| North America | $ | 896 | $ | 804 | $ | 629 | $ | 2,401 | $ | 2,291 | |||||||||||||||||||||||||
| North Sea | 29 | 3 | 14 | 36 | 22 | ||||||||||||||||||||||||||||||
| Offshore Africa | 41 | 37 | 33 | 119 | 113 | ||||||||||||||||||||||||||||||
| Oil Sands Mining and Upgrading | 372 | 764 | 424 | 1,489 | 1,479 | ||||||||||||||||||||||||||||||
| Midstream and Refining | 3 | 3 | 1 | 10 | 6 | ||||||||||||||||||||||||||||||
| Head Office | 8 | 10 | 7 | 28 | 23 | ||||||||||||||||||||||||||||||
| Net capital expenditures | $ | 1,349 | $ | 1,621 | $ | 1,108 | $ | 4,083 | $ | 3,934 | |||||||||||||||||||||||||
(1)Net capital expenditures exclude the impact of lease assets, fair value and revaluation adjustments.
(2)Non-GAAP Financial Measure. The composition of this measure has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of this MD&A.
The Company's strategy is focused on building a diversified asset base that is balanced among various products. In order to facilitate efficient operations, the Company concentrates its activities in core areas. The Company focuses on maintaining its land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production expenses.
| Canadian Natural Resources Limited | 24 | Three and nine months ended September 30, 2024 | ||||||
Net capital expenditures were $4,083 million for the nine months ended September 30, 2024, compared with $3,934 million for the nine months ended September 30, 2023. Net capital expenditures were $1,349 million for the third quarter of 2024, compared with $1,108 million for the third quarter of 2023 and $1,621 million for the second quarter of 2024.
In addition, the Company reported abandonment expenditures of $495 million for the nine months ended September 30, 2024, compared with $360 million for the nine months ended September 30, 2023. Abandonment expenditures were $204 million for the third quarter of 2024, compared with $123 million for the third quarter of 2023 and $129 million for the second quarter of 2024. The increase in abandonment expenditures in the third quarter of 2024 from the comparable periods primarily relates to abandonment activities in the North Sea.
2024 Capital Budget
On December 14, 2023, the Company announced its 2024 capital budget targeted at approximately $5,420 million, and targeting to provide near-term production growth in 2024 and mid- and long-term production and capacity growth in 2025 and beyond. Production for 2024 is targeted between 1,330,000 BOE/d and 1,380,000 BOE/d. In addition, the Company targets $635 million in abandonment expenditures for 2024.
The 2024 capital budget constitutes forward-looking statements and is based on net capital expenditures (Non-GAAP Financial Measure) excluding net acquisition costs. Refer to the "Advisory" section of this MD&A for further details on forward-looking statements.
Agreement to Acquire Assets from Chevron Canada Limited
On October 7, 2024, the Company announced that it had entered into an agreement to acquire, subject to regulatory approvals, from Chevron, its 20% interest in AOSP and its 70% operated working interest in light crude oil and liquids rich assets in the Duvernay play in Alberta for total cash consideration of US$6.5 billion, before closing adjustments. The agreement also includes the acquisition of additional working interests in a number of other non-producing oil sands leases. The acquisitions are targeted to close in the fourth quarter of 2024.
The information in this MD&A relates to the Company's operations for the three and nine months ended September 30, 2024 and does not reflect closing of the acquisitions.
Drilling Activity(1) (2)
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| (number of net wells) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
Net successful crude oil wells (3) | 83 | 63 | 44 | 207 | 179 | ||||||||||||||||||||||||||||||
| Net successful natural gas wells | 24 | 24 | 10 | 64 | 52 | ||||||||||||||||||||||||||||||
| Dry wells | 1 | 1 | — | 2 | 2 | ||||||||||||||||||||||||||||||
| Total | 108 | 88 | 54 | 273 | 233 | ||||||||||||||||||||||||||||||
| Success rate | 99% | 99% | 100% | 99% | 99% | ||||||||||||||||||||||||||||||
(1)Includes drilling activity for North America and International segments.
(2)Excludes stratigraphic and service wells.
(3)Includes bitumen wells.
North America
During the third quarter of 2024, the Company drilled 24 net natural gas wells, 48 net primary heavy crude oil wells, 25 net bitumen (thermal oil) wells and 11 net light crude oil wells.
| Canadian Natural Resources Limited | 25 | Three and nine months ended September 30, 2024 | ||||||
LIQUIDITY AND CAPITAL RESOURCES
| ($ millions, except ratios) | Sep 30 2024 | Jun 30 2024 | Dec 31 2023 | Sep 30 2023 | ||||||||||||||||||||||
Adjusted working capital (1) | $ | 365 | $ | (194) | $ | 712 | $ | 866 | ||||||||||||||||||
Long-term debt, net (2) | $ | 9,308 | $ | 9,234 | $ | 9,922 | $ | 11,519 | ||||||||||||||||||
| Shareholders' equity | $ | 39,897 | $ | 39,469 | $ | 39,832 | $ | 39,634 | ||||||||||||||||||
Debt to book capitalization (2) | 18.9% | 19.0% | 19.9% | 22.5% | ||||||||||||||||||||||
After-tax return on average capital employed (3) | 15.9% | 16.1% | 17.2% | 15.0% | ||||||||||||||||||||||
(1)Calculated as current assets less current liabilities, excluding the current portion of long-term debt.
(2)Capital Management 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.
As at September 30, 2024, the Company's capital resources consisted primarily of cash flows from operating activities, available bank credit facilities and access to debt capital markets. Cash flows from operating activities and the Company's ability to renew existing bank credit facilities and raise new debt are dependent on factors discussed in the "Business Environment" section of this MD&A and in the "Risks and Uncertainties" section of the Company's annual MD&A for the year ended December 31, 2023. In addition, the Company's ability to renew existing bank credit facilities and raise new debt reflects current credit ratings as determined by independent rating agencies, and market conditions. The Company continues to believe its internally generated cash flows from operating activities supported by its ongoing hedge policy, the flexibility of its capital expenditure programs and multi-year financial plans, its existing bank credit facilities, and its ability to raise new debt on commercially acceptable terms will provide sufficient liquidity to sustain its operations in the short-, medium-, and long-term and support its growth strategy.
On an ongoing basis the Company continues to focus on its balance sheet strength and available liquidity by:
▪Monitoring cash flows from operating activities, which is the primary source of funds;
▪Monitoring exposure to individual customers, contractors, suppliers, and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place, and as applicable, taking other mitigating actions to minimize the impact in the event of a default;
▪Actively managing the allocation of capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. The Company continues to exercise its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments and long-term debt;
▪Monitoring the Company's ability to fulfill financial obligations as they become due or the ability to monetize assets in a timely manner at a reasonable price;
▪Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages; and
▪Reviewing the Company's borrowing capacity:
•Borrowings under the Company's credit facilities may be made by way of pricing referenced to CORRA, SOFR, US base rate or Canadian prime rate.
•The Company's borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million.
•During the second quarter of 2024, the Company repaid $320 million of 3.55% medium-term notes.
•In July 2023, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to $3,000 million of medium-term notes in Canada, which expires in August 2025. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.
•During the second quarter of 2024, the Company repaid US$500 million of 3.80% US dollar debt securities.
•In July 2023, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to US$3,000 million of debt securities in the United States, which expires in August 2025. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.
| Canadian Natural Resources Limited | 26 | Three and nine months ended September 30, 2024 | ||||||
•Subsequent to September 30, 2024, the Company extended its revolving syndicated credit facility originally maturing June 2025 to June 2028.
•Subsequent to September 30, 2024 and in connection with the agreement to acquire assets from Chevron, the Company obtained a fully committed $4,000 million non-revolving term loan facility.
As at September 30, 2024, the Company had undrawn revolving bank credit facilities of $5,450 million. Including cash and cash equivalents, the Company had approximately $6,171 million in liquidity. The Company also has certain other dedicated credit facilities supporting letters of credit. At September 30, 2024, the Company had no commercial paper drawn under its commercial paper program, and reserves capacity under its revolving bank credit facilities for amounts outstanding under this program.
Long-term debt, net was $9,308 million as at September 30, 2024 (December 31, 2023 – $9,922 million), resulting in a debt to book capitalization ratio of 18.9% (December 31, 2023 – 19.9%); this ratio was below the 25% to 45% internal range utilized by management. The ratio may fall below or exceed the targeted range depending on the execution of the Company's capital program, commodity price and foreign currency volatility, and the timing of acquisitions. The debt to book capitalization ratio is targeted to be within the internally targeted range upon close of the agreement to acquire assets from Chevron. The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital structure. Further details related to the Company's long-term debt as at September 30, 2024 are discussed in note 9 to the financial statements.
The Company is subject to a financial covenant that requires debt to book capitalization as defined in its credit facility agreements to not exceed 65%. As at September 30, 2024, the Company was in compliance with this covenant.
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 Company periodically utilizes commodity derivative financial instruments under its commodity hedge policy to reduce the risk of volatility in commodity prices and to support the Company's cash flow for its capital expenditure programs. This policy currently allows for the hedging of up to 60% of the near 12 months budgeted production and up to 40% of the following 13 to 24 months estimated production. For the purpose of this policy, the purchase of put options is in addition to the above parameters.
As at September 30, 2024, the maturity dates of certain financial liabilities, including long-term debt and other long-term liabilities and related interest payments, were as follows:
| Less than 1 year | 1 to less than 2 years | 2 to less than 5 years | Thereafter | ||||||||||||||||||||
Long-term debt (1) | $ | 1,618 | $ | — | $ | 2,355 | $ | 6,108 | |||||||||||||||
Other long-term liabilities (2) | $ | 267 | $ | 196 | $ | 395 | $ | 638 | |||||||||||||||
Interest and other financing expense (3) | $ | 540 | $ | 493 | $ | 1,246 | $ | 3,116 | |||||||||||||||
(1)Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs.
(2)Lease payments included within other long-term liabilities reflect principal payments only and are as follows; less than one year, $259 million; one to less than two years, $196 million; two to less than five years, $395 million; and thereafter, $638 million.
(3)Includes interest and other financing expense on long-term debt and other long-term liabilities. Payments were estimated based upon applicable interest and foreign exchange rates as at September 30, 2024.
| Canadian Natural Resources Limited | 27 | Three and nine months ended September 30, 2024 | ||||||
Share Capital(1)
As at September 30, 2024, there were 2,113,135,000 common shares outstanding (December 31, 2023 – 2,144,815,000 common shares) and 52,315,000 stock options outstanding (December 31, 2023 – 52,410,000 stock options). As at October 29, 2024, the Company had 2,109,858,000 common shares outstanding and 51,637,000 stock options outstanding.
On October 7, 2024, the Board of Directors approved a 7% increase in the quarterly dividend to $0.5625 per common share, beginning with the dividend payable on January 3, 2025. On February 28, 2024, the Board of Directors approved a 5% increase in the quarterly dividend to $0.525 per common share.
On November 1, 2023, the Board of Directors approved an 11% increase in the quarterly dividend to $0.50 per common share. On March 1, 2023, the Board of Directors approved a 6% increase in the quarterly dividend to $0.45 per common share.
On March 8, 2024, the Company's application was approved for a Normal Course Issuer Bid to purchase through the facilities of the Toronto Stock Exchange ("TSX"), alternative Canadian trading platforms, and the New York Stock Exchange, up to 180,462,858 common shares, representing 10% of the public float, over a 12-month period commencing March 13, 2024 and ending March 12, 2025.
For the nine months ended September 30, 2024, the Company purchased 43,650,000 common shares at a weighted average price of $48.33 per common share for a total cost, including tax, of $2,140 million. Retained earnings were reduced by $1,915 million, representing the excess of the purchase price of common shares over their average carrying value. Subsequent to September 30, 2024, up to and including October 29, 2024, the Company purchased 3,780,000 common shares at a weighted average price of $48.92 per common share for a total cost, including tax, of $188 million.
COMMITMENTS AND CONTINGENCIES
In the normal course of business, the Company has committed to certain payments. The following table summarizes the Company's commitments as at September 30, 2024:
| ($ millions) | Remaining 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | |||||||||||||||||||||||||||||
Product transportation, purchases and processing (1) (2) | $ | 480 | $ | 2,079 | $ | 1,995 | $ | 1,907 | $ | 1,805 | $ | 20,064 | |||||||||||||||||||||||
North West Redwater Partnership service toll (3) | $ | 37 | $ | 144 | $ | 125 | $ | 109 | $ | 111 | $ | 4,500 | |||||||||||||||||||||||
| Offshore vessels and equipment | $ | 11 | $ | 35 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||
| Field equipment and power | $ | 18 | $ | 25 | $ | 23 | $ | 23 | $ | 23 | $ | 193 | |||||||||||||||||||||||
| Other | $ | 34 | $ | 111 | $ | 111 | $ | 21 | $ | 22 | $ | 268 | |||||||||||||||||||||||
(1)The Company's commitment for the 20-year product transportation agreement on the TMX pipeline reflects interim tolls approved by the Canada Energy Regulator in the fourth quarter of 2023, and is subject to change pending the approval of final tolls.
(2)During the third quarter of 2024, the Company increased its commitment on the TMX pipeline by an incremental 75,000 bbl/d over a 20-year period.
(3)Pursuant to the processing agreements, the Company pays its 25% pro rata share of the debt component of the monthly fee-for-service toll. Included in the toll is $2,416 million of interest payable over the 40-year tolling period, ending in 2058.
In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and construction of its various development projects. These contracts can be cancelled by the Company upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation.
(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.
| Canadian Natural Resources Limited | 28 | Three and nine months ended September 30, 2024 | ||||||
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition, the Company is subject to certain contractor construction claims. The Company believes that any liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the application of IFRS that have a significant impact on the financial results of the Company. Actual results may differ from estimated amounts, and those differences may be material. A comprehensive discussion of the Company's significant accounting estimates is contained in the Company's annual MD&A and audited consolidated financial statements for the year ended December 31, 2023.
CONTROL ENVIRONMENT
There have been no changes to internal control over financial reporting ("ICFR") during the nine months ended September 30, 2024 that have materially affected, or are reasonably likely to materially affect the Company's internal control over financial reporting. Due to inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
| Canadian Natural Resources Limited | 29 | Three and nine months ended September 30, 2024 | ||||||
NON-GAAP AND OTHER FINANCIAL MEASURES
This MD&A includes references to non-GAAP and other financial measures as defined in NI 52-112. These financial measures are used by the Company to evaluate its financial performance, financial position and cash flow and include non-GAAP financial measures, non-GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial measure presented in the 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 MD&A, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below.
Adjusted Net Earnings from Operations
Adjusted net earnings from operations is a non-GAAP financial measure that adjusts net earnings as presented in the Company's consolidated Statements of Earnings, for non-operating items, net of tax impacts. The Company considers adjusted net earnings from operations a key measure in evaluating its performance, as it demonstrates the Company's ability to generate after-tax operating earnings from its core business areas. A reconciliation for adjusted net earnings from operations is presented below.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Net earnings | $ | 2,266 | $ | 1,715 | $ | 2,344 | $ | 4,968 | $ | 5,606 | |||||||||||||||||||||||||
Share-based compensation, net of tax (1) | (48) | (15) | 295 | 218 | 423 | ||||||||||||||||||||||||||||||
Unrealized risk management loss, net of tax (2) | 1 | — | 2 | 13 | 16 | ||||||||||||||||||||||||||||||
Unrealized foreign exchange (gain) loss, net of tax (3) | (148) | (15) | 250 | 106 | 16 | ||||||||||||||||||||||||||||||
Realized foreign exchange loss on repayment of US dollar debt securities, net of tax (4) | — | 135 | — | 135 | — | ||||||||||||||||||||||||||||||
Loss (gain) from investment, net of tax (5) | — | 25 | (41) | (50) | (74) | ||||||||||||||||||||||||||||||
Recoverability charge, net of tax (6) | — | 47 | — | 47 | — | ||||||||||||||||||||||||||||||
| Non-operating items, net of tax | (195) | 177 | 506 | 469 | 381 | ||||||||||||||||||||||||||||||
| Adjusted net earnings from operations | $ | 2,071 | $ | 1,892 | $ | 2,850 | $ | 5,437 | $ | 5,987 | |||||||||||||||||||||||||
(1)Share-based compensation includes costs incurred under the Company's Stock Option Plan and PSU plan. The fair value of the share-based compensation is recognized as a liability on the Company's balance sheets and periodic changes in the fair value are recognized in net earnings. Pre-tax share-based compensation for the three months ended September 30, 2024 was a recovery of $46 million (three months ended June 30, 2024 – $13 million recovery, three months ended September 30, 2023 – $298 million expense; nine months ended September 30, 2024 – $235 million expense; nine months ended September 30, 2023 – $434 million expense).
(2)Derivative financial instruments are recognized at fair value on the Company's balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than those amounts reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil, natural gas and foreign exchange. Pre-tax unrealized risk management loss (gain) for the three months ended September 30, 2024 was $nil (three months ended June 30, 2024 – $nil, three months ended September 30, 2023 – $3 million loss; nine months ended September 30, 2024 – $13 million loss; nine months ended September 30, 2023 – $19 million loss).
(3)Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates and are recognized in net earnings. Pre- and after-tax amounts for these unrealized foreign exchange gains and losses are the same.
(4)During the second quarter of 2024, the Company repaid US$500 million of 3.80% debt securities due April 2024, resulting in a pre- and after-tax foreign exchange loss of $135 million.
(5)The Company's investments have been accounted for at fair value through profit and loss and are measured each period with gains and losses recognized in net earnings. 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. There is a $nil net tax impact on the sale as the Company has sufficient capital losses to offset the capital gain on the sale.
(6)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 ($47 million after-tax) of exploration and evaluation assets through depletion, depreciation and amortization expense.
| Canadian Natural Resources Limited | 30 | Three and nine months ended September 30, 2024 | ||||||
Adjusted Funds Flow
Adjusted funds flow is a non-GAAP financial measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, abandonment expenditures, and movements in other long-term assets. The Company considers adjusted funds flow a key measure in evaluating its performance, as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment, repay debt, and provide returns to shareholders through dividends and share buybacks. A reconciliation for adjusted funds flow, from cash flows from operating activities is presented below.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Cash flows from operating activities | $ | 3,002 | $ | 4,084 | $ | 3,498 | $ | 9,954 | $ | 7,538 | |||||||||||||||||||||||||
| Net change in non-cash working capital | 680 | (515) | 1,088 | 180 | 2,979 | ||||||||||||||||||||||||||||||
| Abandonment expenditures | 204 | 129 | 123 | 495 | 360 | ||||||||||||||||||||||||||||||
Movements in other long-term assets (1) | 35 | (84) | (25) | 44 | (22) | ||||||||||||||||||||||||||||||
| Adjusted funds flow | $ | 3,921 | $ | 3,614 | $ | 4,684 | $ | 10,673 | $ | 10,855 | |||||||||||||||||||||||||
(1)Includes the unamortized cost of the share bonus program, the accrued interest on the deferred PRT recovery, and prepaid cost of service tolls.
Adjusted Net Earnings from Operations and Adjusted Funds Flow, Per Common Share (Basic and Diluted)
Adjusted net earnings from operations and adjusted funds flow, per common share (basic and diluted), are non-GAAP ratios that represent those non-GAAP measures divided by the weighted average number of basic and diluted common shares outstanding for the period, respectively, as presented in note 15 to the financial statements. These non-GAAP measures, disclosed on a per share basis, enable a comparison to the per share amounts disclosed in the Company's financial statements prepared in accordance with IFRS.
Netback
Netback is a non-GAAP ratio that represents net cash flows provided from core activities after the impact of all costs associated with bringing a product to market, on a per unit basis. The Company considers netback a key measure in evaluating its performance, as it demonstrates the efficiency and profitability of the Company's activities. Refer to the "Operating Highlights – Exploration and Production" section of this MD&A for the netback calculations on a per unit basis for crude oil and NGLs and on a total barrels of oil equivalent basis.
The netback calculations include the non-GAAP financial measures: realized price and transportation, reconciled below to their respective line item in note 18 to the financial statements.
| Canadian Natural Resources Limited | 31 | Three and nine months ended September 30, 2024 | ||||||
Realized Price ($/bbl and $/BOE) – Exploration and Production
Realized price ($/bbl and $/BOE) is a non-GAAP ratio calculated as realized crude oil and NGLs sales and total realized BOE sales (non-GAAP financial measures) divided by respective sales volumes. Realized crude oil and NGLs sales and total realized BOE sales exclude the impact of blending and feedstock costs and other by-product sales. The Company considers realized price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit the Company obtained on the market for its crude oil and NGLs sales volumes and BOE sales volumes.
Reconciliations for Exploration and Production realized crude oil and NGLs sales and BOE sales and the calculations for realized price are presented below.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except bbl/d and $/bbl) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
Crude oil and NGLs (bbl/d) | |||||||||||||||||||||||||||||||||||
| North America | 479,889 | 509,674 | 516,038 | 494,674 | 487,917 | ||||||||||||||||||||||||||||||
| International | |||||||||||||||||||||||||||||||||||
| North Sea | 9,020 | 12,682 | 7,839 | 11,713 | 9,305 | ||||||||||||||||||||||||||||||
| Offshore Africa | 20,450 | 7,800 | 12,769 | 12,129 | 13,931 | ||||||||||||||||||||||||||||||
| Total International | 29,470 | 20,482 | 20,608 | 23,842 | 23,236 | ||||||||||||||||||||||||||||||
| Total sales volumes | 509,359 | 530,156 | 536,646 | 518,516 | 511,153 | ||||||||||||||||||||||||||||||
Crude oil and NGLs sales (1) | $ | 4,653 | $ | 5,484 | $ | 5,351 | $ | 14,642 | $ | 13,597 | |||||||||||||||||||||||||
Less: Blending and feedstock costs (2) | 946 | 1,303 | 1,014 | 3,466 | 3,346 | ||||||||||||||||||||||||||||||
| Realized crude oil and NGLs sales | $ | 3,707 | $ | 4,181 | $ | 4,337 | $ | 11,176 | $ | 10,251 | |||||||||||||||||||||||||
| Realized price ($/bbl) | $ | 79.15 | $ | 86.64 | $ | 87.83 | $ | 78.67 | $ | 73.45 | |||||||||||||||||||||||||
(1)Crude oil and NGLs sales in note 18 to the financial statements.
(2)Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration and Production" section.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except BOE/d and $/BOE) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
Barrels of oil equivalent (BOE/d) | |||||||||||||||||||||||||||||||||||
| North America | 819,606 | 859,536 | 872,555 | 843,074 | 840,032 | ||||||||||||||||||||||||||||||
| International | |||||||||||||||||||||||||||||||||||
| North Sea | 9,246 | 12,959 | 8,022 | 11,961 | 9,598 | ||||||||||||||||||||||||||||||
| Offshore Africa | 22,021 | 9,393 | 14,530 | 13,809 | 15,651 | ||||||||||||||||||||||||||||||
| Total International | 31,267 | 22,352 | 22,552 | 25,770 | 25,249 | ||||||||||||||||||||||||||||||
| Total sales volumes | 850,873 | 881,888 | 895,107 | 868,844 | 865,281 | ||||||||||||||||||||||||||||||
Barrels of oil equivalent sales (1) | $ | 4,889 | $ | 5,788 | $ | 5,908 | $ | 15,681 | $ | 15,455 | |||||||||||||||||||||||||
Less: Blending and feedstock costs (2) | 946 | 1,303 | 1,014 | 3,466 | 3,346 | ||||||||||||||||||||||||||||||
| Less: Sulphur expense (income) | 2 | 3 | 1 | 6 | (12) | ||||||||||||||||||||||||||||||
| Realized barrels of oil equivalent sales | $ | 3,941 | $ | 4,482 | $ | 4,893 | $ | 12,209 | $ | 12,121 | |||||||||||||||||||||||||
| Realized price ($/BOE) | $ | 50.36 | $ | 55.84 | $ | 59.40 | $ | 51.29 | $ | 51.31 | |||||||||||||||||||||||||
(1)Barrels of oil equivalent sales includes crude oil and NGLs sales and natural gas sales in note 18 to the financial statements.
(2)Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled below in the "Transportation – Exploration and Production" section.
| Canadian Natural Resources Limited | 32 | Three and nine months ended September 30, 2024 | ||||||
Transportation – Exploration and Production
Transportation ($/BOE, $/bbl and $/Mcf) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure) divided by the respective sales volumes. The Company calculates transportation to demonstrate its cost to deliver products to the market excluding the impact of blending costs. A reconciliation for Exploration and Production transportation and the calculations for transportation on a per unit basis are presented below.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except $ per unit amounts) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
Transportation, blending and feedstock (1) | $ | 1,312 | $ | 1,712 | $ | 1,326 | $ | 4,584 | $ | 4,285 | |||||||||||||||||||||||||
| Less: Blending and feedstock costs | 946 | 1,303 | 1,014 | 3,466 | 3,346 | ||||||||||||||||||||||||||||||
| Transportation | $ | 366 | $ | 409 | $ | 312 | $ | 1,118 | $ | 939 | |||||||||||||||||||||||||
| Transportation ($/BOE) | $ | 4.67 | $ | 5.09 | $ | 3.78 | $ | 4.70 | $ | 3.97 | |||||||||||||||||||||||||
| Amounts attributed to crude oil and NGLs | $ | 246 | $ | 289 | $ | 200 | $ | 752 | $ | 610 | |||||||||||||||||||||||||
| Transportation ($/bbl) | $ | 5.26 | $ | 5.98 | $ | 4.07 | $ | 5.30 | $ | 4.37 | |||||||||||||||||||||||||
| Amounts attributed to natural gas | $ | 120 | $ | 120 | $ | 112 | $ | 366 | $ | 329 | |||||||||||||||||||||||||
| Transportation ($/Mcf) | $ | 0.63 | $ | 0.63 | $ | 0.56 | $ | 0.62 | $ | 0.56 | |||||||||||||||||||||||||
(1)Transportation, blending and feedstock in note 18 to the financial statements.
North America – Realized Product Prices and Royalties
Realized crude oil and NGLs price ($/bbl) is a non-GAAP ratio calculated as realized crude oil and NGLs sales (non-GAAP financial measure) divided by sales volumes. Realized crude oil and NGLs sales exclude the impact of blending costs. The Company considers the realized crude oil and NGLs price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its crude oil and NGLs sales volumes.
Crude oil and NGLs royalty rate is a non-GAAP ratio that is calculated as crude oil and NGLs royalties divided by realized crude oil and NGLs sales. The Company considers crude oil and NGLs royalty rate a key measure in evaluating its performance, as it describes the Company's royalties for crude oil and NGLs sales volumes on a per unit basis.
A reconciliation for North America realized crude oil and NGLs sales and the calculations for realized crude oil and NGLs prices and the royalty rates are presented below.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except $/bbl and royalty rates) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
Crude oil and NGLs sales (1) | $ | 4,357 | $ | 5,269 | $ | 5,135 | $ | 13,910 | $ | 12,924 | |||||||||||||||||||||||||
Less: Blending and feedstock costs (2) | 946 | 1,303 | 1,014 | 3,466 | 3,346 | ||||||||||||||||||||||||||||||
| Realized crude oil and NGLs sales | $ | 3,411 | $ | 3,966 | $ | 4,121 | $ | 10,444 | $ | 9,578 | |||||||||||||||||||||||||
| Realized crude oil and NGLs prices ($/bbl) | $ | 77.29 | $ | 85.49 | $ | 86.77 | $ | 77.06 | $ | 71.90 | |||||||||||||||||||||||||
Crude oil and NGLs royalties (3) | $ | 694 | $ | 838 | $ | 845 | $ | 2,095 | $ | 1,773 | |||||||||||||||||||||||||
| Crude oil and NGLs royalty rates | 20% | 21% | 21% | 20% | 19% | ||||||||||||||||||||||||||||||
(1)Crude oil and NGLs sales in note 18 to the financial statements.
(2)Blending and feedstock costs are a component of transportation, blending and feedstock expense as reconciled above in the "Transportation – Exploration and Production" section.
(3)Item is a component of royalties in note 18 to the financial statements.
| Canadian Natural Resources Limited | 33 | Three and nine months ended September 30, 2024 | ||||||
Realized Product Prices and Transportation – Oil Sands Mining and Upgrading
Realized SCO sales price ($/bbl) is a non-GAAP ratio calculated as realized SCO sales (non-GAAP financial measure) excluding the impact of blending and feedstock costs, divided by SCO sales volumes. The Company considers realized SCO sales price a key measure in evaluating its performance, as it demonstrates the realized pricing per unit that the Company obtained on the market for its SCO sales volumes.
Transportation ($/bbl) is a non-GAAP ratio calculated as transportation (a non-GAAP financial measure) divided by SCO sales volumes. The Company calculates transportation to demonstrate its cost to deliver product to the market excluding the impact of blending and feedstock costs.
Reconciliations for Oil Sands Mining and Upgrading realized SCO sales and transportation and the calculations for realized SCO sales price and transportation on a per unit basis are presented below.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions, except for bbl/d and $/bbl) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| SCO sales volumes (bbl/d) | 491,635 | 398,528 | 492,926 | 448,145 | 435,109 | ||||||||||||||||||||||||||||||
Crude oil and NGLs sales (1) | $ | 5,208 | $ | 4,525 | $ | 5,591 | $ | 13,901 | $ | 13,619 | |||||||||||||||||||||||||
| Less: Blending and feedstock costs | 643 | 579 | 670 | 1,721 | 1,674 | ||||||||||||||||||||||||||||||
| Realized SCO sales | $ | 4,565 | $ | 3,946 | $ | 4,921 | $ | 12,180 | $ | 11,945 | |||||||||||||||||||||||||
| Realized SCO sales price ($/bbl) | $ | 100.93 | $ | 108.81 | $ | 108.55 | $ | 99.19 | $ | 100.57 | |||||||||||||||||||||||||
Transportation, blending and feedstock (2) | $ | 794 | $ | 682 | $ | 768 | $ | 2,044 | $ | 1,900 | |||||||||||||||||||||||||
| Less: Blending and feedstock costs | 643 | 579 | 670 | 1,721 | 1,674 | ||||||||||||||||||||||||||||||
| Transportation | $ | 151 | $ | 103 | $ | 98 | $ | 323 | $ | 226 | |||||||||||||||||||||||||
| Transportation ($/bbl) | $ | 3.34 | $ | 2.81 | $ | 2.18 | $ | 2.62 | $ | 1.91 | |||||||||||||||||||||||||
(1)Crude oil and NGLs sales in note 18 to the financial statements.
(2)Transportation, blending and feedstock in note 18 to the financial statements.
Change in Composition of Non-GAAP Financial Measure
During the fourth quarter of 2023, the Company revised the composition of its Net Capital Expenditures non-GAAP financial measure to exclude expenditures related to the Company's abandonment program. The revision was made during Management's assessment of its annual capital budgeting process, and will provide users a better representation of the Company's performance and the composition of its capital budget. The composition of this measure has been updated for all periods presented.
Net Capital Expenditures
Net capital expenditures is a non-GAAP financial measure that represents cash flows used in investing activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, and cash flows from investing activities not included in the Company's capital budget. The Company includes acquisition and disposition capital in net capital expenditures at close of the transactions. The Company considers net capital expenditures a key measure in evaluating its performance, as it provides an understanding of the Company's capital spending activities in comparison to the Company's annual capital budget. A reconciliation of net capital expenditures is presented below.
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||||||||
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Sep 30 2023 | Sep 30 2024 | Sep 30 2023 | ||||||||||||||||||||||||||||||
| Cash flows used in investing activities | $ | 1,274 | $ | 1,015 | $ | 1,199 | $ | 3,681 | $ | 3,912 | |||||||||||||||||||||||||
| Net proceeds from investment | — | 575 | — | 575 | — | ||||||||||||||||||||||||||||||
| Net change in non-cash working capital | 75 | 31 | (91) | (173) | 22 | ||||||||||||||||||||||||||||||
| Net capital expenditures | 1,349 | 1,621 | 1,108 | 4,083 | 3,934 | ||||||||||||||||||||||||||||||
| Abandonment expenditures | 204 | 129 | 123 | 495 | 360 | ||||||||||||||||||||||||||||||
| Capital and abandonment expenditures | $ | 1,553 | $ | 1,750 | $ | 1,231 | $ | 4,578 | $ | 4,294 | |||||||||||||||||||||||||
| Canadian Natural Resources Limited | 34 | Three and nine months ended September 30, 2024 | ||||||
Liquidity
Liquidity is a non-GAAP financial measure that represents the availability of readily available undrawn bank credit facilities, cash and cash equivalents, and other highly liquid assets to meet short-term funding requirements and to assist in assessing the Company's financial position. The Company's calculation of liquidity is presented below.
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Dec 31 2023 | Sep 30 2023 | ||||||||||||||||||||||
| Undrawn bank credit facilities | $ | 5,450 | $ | 5,450 | $ | 5,450 | $ | 5,450 | ||||||||||||||||||
| Cash and cash equivalents | 721 | 915 | 877 | 125 | ||||||||||||||||||||||
Investments (1) | — | — | 525 | 565 | ||||||||||||||||||||||
| Liquidity | $ | 6,171 | $ | 6,365 | $ | 6,852 | $ | 6,140 | ||||||||||||||||||
(1)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 $575 million.
Long-term Debt, net
Long-term debt, net, is a capital management measure that represents long-term debt, including the current portion of long-term debt, less cash and cash equivalents, as disclosed in note 14 to the financial statements. A reconciliation of long-term debt, net is presented below.
| ($ millions) | Sep 30 2024 | Jun 30 2024 | Dec 31 2023 | Sep 30 2023 | ||||||||||||||||||||||
| Long-term debt | $ | 10,029 | $ | 10,149 | $ | 10,799 | $ | 11,644 | ||||||||||||||||||
| Less: cash and cash equivalents | 721 | 915 | 877 | 125 | ||||||||||||||||||||||
| Long-term debt, net | $ | 9,308 | $ | 9,234 | $ | 9,922 | $ | 11,519 | ||||||||||||||||||
Debt to Book Capitalization
Debt to book capitalization is a capital management measure intended to enable financial statement users to evaluate the Company's capital structure, as disclosed in note 14 to the financial statements.
After-Tax Return on Average Capital Employed
After-tax return on average capital employed as defined by the Company is a non-GAAP ratio. The ratio is calculated as net earnings plus after-tax interest and other financing expense for the twelve month trailing period; as a percentage of average capital employed (defined as current and long-term debt plus shareholders' equity) for the twelve month trailing period. The Company considers this ratio a key measure in evaluating the Company's ability to generate profit and the efficiency with which it employs capital. A reconciliation of the Company's after-tax return on average capital employed is presented below.
| ($ millions, except ratios) | Sep 30 2024 | Jun 30 2024 | Dec 31 2023 | Sep 30 2023 | ||||||||||||||||||||||
| Interest adjusted after-tax return: | ||||||||||||||||||||||||||
| Net earnings, 12 months trailing | $ | 7,595 | $ | 7,673 | $ | 8,233 | $ | 7,126 | ||||||||||||||||||
Interest and other financing expense, net of tax, 12 months trailing (1) | 435 | 461 | 490 | 459 | ||||||||||||||||||||||
| Interest adjusted after-tax return | $ | 8,030 | $ | 8,134 | $ | 8,723 | $ | 7,585 | ||||||||||||||||||
12 months average current portion long-term debt (2) | $ | 1,366 | $ | 1,506 | $ | 1,259 | $ | 1,337 | ||||||||||||||||||
12 months average long-term debt (2) | 9,366 | 9,651 | 10,354 | 10,706 | ||||||||||||||||||||||
12 months average common shareholders' equity (2) | 39,668 | 39,418 | 38,974 | 38,635 | ||||||||||||||||||||||
| 12 months average capital employed | $ | 50,400 | $ | 50,575 | $ | 50,587 | $ | 50,678 | ||||||||||||||||||
| After-tax return on average capital employed | 15.9% | 16.1% | 17.2% | 15.0% | ||||||||||||||||||||||
(1)The blended tax rate on interest was 23% for each of the periods presented.
(2)For the purpose of this non-GAAP ratio, the measurement of average current and long-term debt and common shareholders' equity are determined on a consistent basis, as an average of the opening and quarterly period end values for the 12 month trailing period for each of the periods presented.
| Canadian Natural Resources Limited | 35 | Three and nine months ended September 30, 2024 | ||||||